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x
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934.
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o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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Delaware
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51-0337383
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(State or other jurisdiction of
incorporation or organization)
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(I.R.S. Employer
Identification No.)
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Title of each class
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Name of exchange on which registered
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Common Stock ($.01 par value)
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New York Stock Exchange
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Preferred Share Purchase Rights
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New York Stock Exchange
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TABLE OF CONTENTS
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Page
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PART I
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ITEM 1.
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Business
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ITEM 1A.
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Risk Factors
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ITEM 1B.
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Unresolved Staff Comments
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ITEM 2.
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Properties
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ITEM 3.
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Legal Proceedings
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ITEM 4.
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Mine Safety and Health Administration Safety Data
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PART II
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ITEM 5.
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Market for Registrant's Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities
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ITEM 6.
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Selected Financial Data
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ITEM 7.
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Management's Discussion and Analysis of Financial Condition and Results of Operations
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ITEM 7A.
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Quantitative and Qualitative Disclosures About Market Risk
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ITEM 8.
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Financial Statements and Supplementary Data
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ITEM 9.
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Changes in and Disagreements with Accountants on Accounting and Financial Disclosures
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ITEM 9A.
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Controls and Procedures
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ITEM 9B.
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Other Information
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PART III
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ITEM 10.
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Directors and Executive Officers of the Registrant
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ITEM 11.
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Executive Compensation
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ITEM 12.
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Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
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ITEM 13.
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Certain Relationships and Related Transactions and Director Independence
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ITEM 14.
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Principal Accounting Fees and Services
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PART IV
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ITEM 15.
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Exhibits and Financial Statement Schedules
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SIGNATURES
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•
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deterioration in global economic conditions in any of the industries in which our customers operate, or sustained uncertainty in financial markets cause conditions we cannot predict;
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•
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an extended decline in demand for or prices we receive for our natural gas and coal affecting our operating results and cash flows;
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•
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our customers extending existing contracts or entering into new long-term contracts for coal;
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•
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our reliance on major customers;
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•
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our inability to collect payments from customers if their creditworthiness declines;
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•
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the disruption of rail, barge, gathering, processing and transportation facilities and other systems that deliver our natural gas and coal to market;
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•
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a loss of our competitive position because of the competitive nature of the natural gas and coal industries, or a loss of our competitive position because of overcapacity in these industries impairing our profitability;
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•
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coal users switching to other fuels in order to comply with various environmental standards related to coal combustion emissions;
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•
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the impact of potential, as well as any adopted regulations relating to greenhouse gas emissions on the demand for natural gas and coal;
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•
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foreign currency fluctuations could adversely affect the competitiveness of our coal abroad;
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•
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the risks inherent in natural gas and coal operations being subject to unexpected disruptions, including geological conditions, equipment failure, timing of completion of significant construction or repair of equipment, fires, explosions, accidents and weather conditions which could impact financial results;
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•
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decreases in the availability of, or increases in, the price of commodities or capital equipment used in our mining operations;
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•
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decreases in the availability of, an increase in the prices charged by third party contractors or, failure of third party contractors to provide quality services to us in a timely manner could impact our profitability;
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•
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obtaining and renewing governmental permits and approvals for our natural gas and coal operations;
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•
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the effects of government regulation on the discharge into the water or air, and the disposal and clean-up of, hazardous substances and wastes generated during our natural gas and coal operations;
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•
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our ability to find adequate water sources for our use in gas drilling, or our ability to dispose of water used or removed from strata in connection with our gas operations at a reasonable cost and within applicable environmental rules;
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•
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the effects of stringent federal and state employee health and safety regulations, including the ability of regulators to shut down a natural gas well or a mine;
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•
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the potential for liabilities arising from environmental contamination or alleged environmental contamination in connection with our past or current gas and coal operations;
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•
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the effects of mine closing, reclamation, gas well closing and certain other liabilities;
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•
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uncertainties in estimating our economically recoverable gas and coal reserves;
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•
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defects may exist in our chain of title and we may incur additional costs associated with perfecting title for gas or coal rights on some of our properties or failing to acquire these additional rights may result in a reduction of our estimated reserves;
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•
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the impacts of various asbestos litigation claims;
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•
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the outcomes of various legal proceedings, which are more fully described in our reports filed under the Securities Exchange Act of 1934;
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•
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increased exposure to employee-related long-term liabilities;
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•
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lump sum payments made to retiring salaried employees pursuant to our defined benefit pension plan exceeding total service and interest cost in a plan year;
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•
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acquisitions that we recently have completed or may make in the future including the accuracy of our assessment of the acquired businesses and their risks, achieving any anticipated synergies, integrating the acquisitions and unanticipated changes that could affect assumptions we may have made and divestitures we anticipate may not occur or produce anticipated proceeds;
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•
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the terms of our existing joint ventures restrict our flexibility, actions taken by the other party in our gas joint ventures may impact our financial position and various circumstances could cause us not to realize the benefits we anticipate receiving from these joint ventures;
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•
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risks associated with our debt;
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•
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replacing our natural gas reserves, which if not replaced, will cause our gas reserves and gas production to decline;
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•
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our hedging activities may prevent us from benefiting from price increases and may expose us to other risks;
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•
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changes in federal or state income tax laws, particularly in the area of percentage depletion and intangible drilling costs, could cause our financial position and profitability to deteriorate;
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•
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failure to appropriately allocate capital and other resources among our strategic opportunities may adversely affect our financial condition;
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•
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failure by Murray Energy to satisfy liabilities it acquired from us, or failure to perform its obligations under various arrangements, which we guaranteed, could materially or adversely affect our results of operations, financial position, and cash flows; and
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•
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other factors discussed in this 2013 Form 10-K under “Risk Factors,” as updated by any subsequent Form 10-Qs, which are on file at the Securities and Exchange Commission.
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ITEM 1.
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Business
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•
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Total production of 472,274 Mcfe per day, an increase of 10% over 2012;
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•
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98% Natural Gas, 2% Liquids; and
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•
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34% Marcellus, 48% coalbed methane, 16% shallow oil & gas, 2% other.
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•
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5.7 Tcfe of proved reserves;
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•
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97.5% natural gas;
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•
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43.9% proved developed;
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•
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85.7% operated; and
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•
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A reserve life ratio of 33.25 years (based on fourth quarter 2013 production);
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•
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Underground mining complexes are among the safest in the United States of America;
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•
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Production of 28.5 million tons of coal from continuing operations;
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•
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Coal reserve holdings of 3.0 billion tons;
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•
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30% of sales delivered to export markets;
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•
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59% of sales to domestic utilities; and
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•
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New BMX Mine in southwest Pennsylvania scheduled to come on-line in March 2014, as planned.
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•
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Safety,
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•
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Compliance, and
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•
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Continuous Improvement.
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Capex ($MM)
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Natural Gas Operations:
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Land and Permitting:
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$
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70
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Liquids-rich drilling and completions:
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Marcellus
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410
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Utica
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105
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Dry-gas drilling and completions:
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Marcellus/Upper Devonian
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415
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Utica
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10
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CBM/Shallow Gas
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40
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Midstream:
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Marcellus Gathering
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60
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Total Natural Gas Operations
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$
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1,110
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Coal Operations:
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BMX Mine
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$
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200
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Maintenance of Production
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130
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Land/Safety/Water/Terminal
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60
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Total Coal Operations
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$
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390
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Total Company
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$
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1,500
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•
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26 wells in Southwestern Pennsylvania,
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•
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10 wells in Central Pennsylvania,
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•
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10 wells in Northern West Virginia, and
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•
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71 wells drilled by Noble Energy in the wet gas area of the play.
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Shallow Oil
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|||||
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CBM
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and Gas
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Marcellus
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Other Gas
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Segment
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Segment
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Segment
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Segment
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Total
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|||||
Estimated Net Proved Reserves (MMcfe)
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1,544,970
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582,846
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3,373,093
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230,305
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5,731,214
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Percent Developed
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73
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%
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100
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%
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21
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%
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34
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%
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44
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%
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Net Producing Wells (including gob wells)
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4,310
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8,324
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132
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108
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12,874
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Net Acreage Position
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|||||
Net Proved Developed Acres
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258,601
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248,318
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11,527
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9,247
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527,693
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Net Proved Undeveloped Acres
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9,986
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—
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44,396
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4,964
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59,346
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Net Unproved Acres(1)
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2,193,699
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625,706
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380,964
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1,011,661
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4,212,030
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Total Net Acres(2)
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2,462,286
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874,024
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436,887
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1,025,872
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4,799,069
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(1)
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Net acres include acreage attributable to our working interests in the properties. Additional adjustments (either increases or decreases) may be required as we further develop title to and further confirm our rights with respect to our various properties in anticipation of development. We believe that our assumptions and methodology in this regard are reasonable. See Risk Factors in Section 1A. of this Form 10-K.
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(2)
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Acreage amounts are shown under the target strata CONSOL Energy expects to produce, although the reported acres may include rights to multiple gas seams (CBM, Shallow Oil and Gas, Marcellus, etc.). We have reviewed our drilling plans, our acreage rights and used our best judgment to reflect the acres in the strata we expect to produce. As more information is obtained or circumstances change, the acreage classification may change.
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Gross
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Net(1)
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Producing Wells (including gob wells)
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15,063
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12,874
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Net Acreage Position
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Proved Developed Acreage
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542,388
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527,693
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Proved Undeveloped Acreage
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105,019
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59,346
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Unproven Acreage
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5,396,659
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4,212,030
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Total Acreage
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6,044,066
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4,799,069
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(1)
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Net acres include acreage attributable to our working interests in the properties. Additional adjustments (either increases or decreases) may be required as we further develop title to and further confirm our rights with respect to our various
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For the Year
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|||||||
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Ended December 31,
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|||||||
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2013
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2012
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2011
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|||||
CBM segment
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63.8
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42.5
|
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221.4
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Shallow Oil and Gas segment
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5.0
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2.0
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4.0
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Marcellus segment
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56.0
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44.0
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17.5
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(A)
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Other Gas segment
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15.0
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7.0
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12.0
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Total Development Wells
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139.8
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95.5
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|
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254.9
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For the Year Ended December 31,
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|||||||||||||||||||||||||
|
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2013
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2012
|
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2011
|
|||||||||||||||||||||
|
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Producing
|
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Dry
|
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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
|
|
|
1.0
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Marcellus segment
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0.5
|
|
|
—
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|
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2.0
|
|
|
0.5
|
|
|
—
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|
|
0.5
|
|
|
47.5
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|
|
1.0
|
|
|
—
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Other Gas segment (1)
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|
—
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|
|
—
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|
|
3.0
|
|
|
1.0
|
|
|
0.5
|
|
|
4.5
|
|
|
5.5
|
|
|
—
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1.5
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Total
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0.5
|
|
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—
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|
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5.0
|
|
|
5.5
|
|
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7.5
|
|
|
9.0
|
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65.0
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|
|
2.0
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|
|
2.5
|
|
|
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Net Reserves
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|||||||
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(Million cubic feet equivalent)
|
|||||||
|
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as of December 31,
|
|||||||
|
|
2013
|
|
2012
|
|
2011
|
|||
Proved developed reserves
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2,514,294
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|
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2,165,483
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2,135,805
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Proved undeveloped reserves
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3,216,920
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|
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1,827,975
|
|
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1,344,222
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Total proved developed and undeveloped reserves(a)
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5,731,214
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3,993,458
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|
|
3,480,027
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(a)
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For additional information on our reserves, see “Other Supplemental Information–Supplemental Gas Data (unaudited) to the Consolidated Financial Statements in Item 8 of this Form 10-K.
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|
|
Discounted Future
|
||||||||||
|
|
Net Cash Flows
|
||||||||||
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(Dollars in millions)
|
||||||||||
|
|
2013
|
|
2012
|
|
2011
|
||||||
Future net cash flows
|
|
$
|
6,568
|
|
|
$
|
2,792
|
|
|
$
|
4,877
|
|
Total PV-10 measure of pre-tax discounted future net cash flows (1)
|
|
$
|
2,780
|
|
|
$
|
1,242
|
|
|
$
|
2,861
|
|
Total 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-Generally Accepted Accounting Principle (GAAP) financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes estimated to be paid, the use of a pre-tax measure is valuable when comparing companies based on reserves. PV-10 is not a measure of the financial or operating performance under GAAP. PV-10 should not be considered as an alternative to the standardized measure as defined under GAAP. We have included a reconciliation of the most directly comparable GAAP measure-after-tax discounted future net cash flows.
|
|
|
As of December 31,
|
||||||||||
|
|
2013
|
|
2012
|
|
2011
|
||||||
|
|
(Dollars in millions)
|
||||||||||
Future cash inflows
|
|
$
|
21,603
|
|
|
$
|
11,778
|
|
|
$
|
14,804
|
|
Future 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
|
|
|
7,866
|
|
|||
10% discount factor
|
|
(7,814
|
)
|
|
(3,261
|
)
|
|
(5,005
|
)
|
|||
PV-10 (Non-GAAP measure)
|
|
2,780
|
|
|
1,242
|
|
|
2,861
|
|
|||
Undiscounted income taxes
|
|
(4,026
|
)
|
|
(1,711
|
)
|
|
(2,989
|
)
|
|||
10% discount factor
|
|
2,927
|
|
|
1,205
|
|
|
1,875
|
|
|||
Discounted income taxes
|
|
(1,099
|
)
|
|
(506
|
)
|
|
(1,114
|
)
|
|||
Standardized GAAP measure
|
|
$
|
1,681
|
|
|
$
|
736
|
|
|
$
|
1,747
|
|
|
|
For the Year
|
|||||||
|
|
Ended December 31,
|
|||||||
|
|
2013
|
|
2012
|
|
2011
|
|||
GAS
|
|
|
|
|
|
|
|||
Marcellus Sales Volumes (MMcf)
|
|
55,048
|
|
|
35,853
|
|
|
26,863
|
|
CBM Sales Volumes (MMcf)
|
|
82,867
|
|
|
88,149
|
|
|
92,360
|
|
Shallow Oil and Gas Sales Volumes (MMcf)
|
|
27,457
|
|
|
28,684
|
|
|
31,731
|
|
Other Sales Volumes (MMcf)
|
|
3,365
|
|
|
2,366
|
|
|
1,987
|
|
LIQUIDS*
|
|
|
|
|
|
|
|||
NGLs Sales Volumes (MMcfe)
|
|
2,628
|
|
|
610
|
|
|
—
|
|
Oil Sales Volumes (MMcfe)
|
|
634
|
|
|
600
|
|
|
563
|
|
Condensate Sales Volumes (MMcfe)
|
|
381
|
|
|
63
|
|
|
—
|
|
TOTAL (MMcfe)
|
|
172,380
|
|
|
156,325
|
|
|
153,504
|
|
|
|
For the Year
|
||||||||||
|
|
Ended December 31,
|
||||||||||
|
|
2013
|
|
2012
|
|
2011
|
||||||
Total Average Gas Sales Price Before Effects of Financial Settlements (per Mcfe)
|
|
$
|
3.85
|
|
|
$
|
3.00
|
|
|
$
|
4.27
|
|
Average Effects of Financial Settlements (per Mcfe)
|
|
$
|
0.45
|
|
|
$
|
1.22
|
|
|
$
|
0.63
|
|
Total Average Gas Sales Price Including Effects of Financial Settlements (per Mcfe)
|
|
$
|
4.30
|
|
|
$
|
4.22
|
|
|
$
|
4.90
|
|
Average Lifting Costs excluding ad valorem and severance taxes (per Mcfe)
|
|
$
|
0.56
|
|
|
$
|
0.58
|
|
|
$
|
0.69
|
|
CONSOL ENERGY MINING COMPLEXES
|
||||||||||||||||||||||
Proven 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
|
|
Millions
|
||||||
Mine/Reserve
|
|
Location
|
|
Class
|
|
Seam
|
|
(feet)
|
|
Typical
|
|
Range
|
|
(%)
|
|
(%)
|
|
12/31/2013
|
|
12/31/2012
|
||
ASSIGNED–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
|
|
|
232.8
|
|
Bailey (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
|
|
|
303.0
|
|
Amvest-Fola Complex (3)
|
|
Bickmore, WV
|
|
Assigned
|
|
Multiple
|
|
4.6
|
|
12,380
|
|
12,250 – 12,550
|
|
86%
|
|
14%
|
|
73.4
|
|
|
73.4
|
|
Miller 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
|
|
|
46.3
|
|
Amonate 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
|
|
|
6.6
|
|
Total Assigned Operating and Accessible
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
872.0
|
|
|
869.4
|
|
(1)
|
The heat value shown for Assigned Operating reserves is based on the quality of coal mined and processed during the year ended
December 31, 2013
. The heat value shown for accessible reserves are based on as received, dry values obtained from drill hole analysis prorated by the associated Assigned Operating reserve values to account for similar mining and processing methods.
|
(2)
|
Recoverable reserves are calculated based on the area in which mineable coal exists, coal seam thickness and average density determined by laboratory testing of drill core samples. This calculation is adjusted to account for coal that will not be recovered during mining and for losses that occur if the coal is processed after mining. Reserve calculations do not include adjustments for moisture that may be added during mining or processing, nor do the calculations include adjustments for dilution from rock lying above or below the coal seam. Reserves are reported only for those coal seams that are controlled by ownership or leases.
|
(3)
|
A portion of these reserves contain metallurgical qualities and are currently being sold on the metallurgical market.
|
(4)
|
The table excludes 57 million tons of recoverable reserves which represents CONSOL Energy's portion of tonnage held by two equity affiliates. CONSOL Energy owns a 49% interest in both of these affiliates.
|
(1)
|
The heat value estimates for Northern Appalachian and Central Appalachian Unassigned coal reserves include adjustments for moisture that may be added during mining or processing as well as for dilution by rock lying above or below the coal seam. The mining and processing methods currently in use are used for these estimates. The heat value estimates for the Illinois Basin, unassigned reserves are based primarily on exploration drill core data that may not include adjustments for moisture added during mining or processing or for dilution by rock lying above or below the coal seam.
|
(2)
|
Recoverable reserves are calculated based on the area in which mineable coal exists, coal seam thickness, and average density determined by laboratory testing of drill core samples. This calculation is adjusted to account for coal that will not be recovered during mining and for losses that occur if the coal is processed after mining. Reserve calculations do not include adjustment for moisture that may be added during mining or processing, nor do the calculations include adjustments for dilution from rock lying above or below the coal seam. Reserves are only reported for those coal seams that are controlled by ownership or leases.
|
CONSOL Energy Proven and Probable Recoverable Coal Reserves
|
||||||||||||||||||||||||||||||||||
By 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 By
|
|||||||||||
By Region
|
|
Btu
|
|
Btu
|
|
Btu
|
|
Btu
|
|
Btu
|
|
Btu
|
|
Btu
|
|
Btu
|
|
Btu
|
|
Total
|
|
Product
|
||||||||||||
Metallurgical(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
|
%
|
|
|
|
|
Total
|
|
Total
|
|
Total
|
|
|
Royalty
|
|
Coal
|
|
Royalty
|
|
|
Tonnage
|
|
Acreage
|
|
Income
|
Year
|
|
(in thousands)
|
|
Leased
|
|
(in thousands)
|
2013
|
|
8,335
|
|
271,755
|
|
$16,906
|
2012
|
|
8,326
|
|
271,760
|
|
$16,853
|
2011
|
|
8,488
|
|
289,833
|
|
$17,969
|
|
|
|
|
|
|
|
|
|
|
Tons Produced
|
|
Year
|
|||||||
|
|
|
|
Mine
|
|
Mining
|
|
|
|
(in millions)
|
|
Established
|
|||||||
Mine
|
|
Location
|
|
Type
|
|
Equipment
|
|
Transportation
|
|
2013
|
|
|
2012
|
|
|
2011
|
|
|
or Acquired
|
Thermal
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||
Bailey (3)
|
|
Enon, PA
|
|
U
|
|
LW/CM
|
|
R R/B
|
|
10.1
|
|
|
8.6
|
|
|
8.6
|
|
|
1984
|
Enlow Fork (3)
|
|
Enon, PA
|
|
U
|
|
LW/CM
|
|
R R/B
|
|
8.9
|
|
|
8.0
|
|
|
8.3
|
|
|
1990
|
Miller Creek Complex(2)
|
|
Delbarton, WV
|
|
U/S
|
|
CM/S/L
|
|
R T
|
|
2.2
|
|
|
2.9
|
|
|
2.8
|
|
|
2004
|
AMVEST-Fola Complex(1)(2)
|
|
Bickmore, WV
|
|
U/S
|
|
A/S/L/CM
|
|
R T
|
|
—
|
|
|
0.8
|
|
|
2.1
|
|
|
2007
|
High Volatile Metallurgical
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Bailey-Met (3)
|
|
Enon, PA
|
|
U
|
|
LW/CM
|
|
R R/B
|
|
1.3
|
|
|
1.5
|
|
|
2.1
|
|
|
1984
|
Enlow Fork-Met (3)
|
|
Enon, PA
|
|
U
|
|
LW/CM
|
|
R R/B
|
|
1.2
|
|
|
1.5
|
|
|
1.8
|
|
|
1990
|
AMVEST-Fola Complex(1)(2)-Met
|
|
Bickmore, WV
|
|
U/S
|
|
A/S/L/CM
|
|
R T
|
|
—
|
|
|
0.3
|
|
|
0.1
|
|
|
2007
|
AMVEST-Terry Eagle Complex(1)(2)-Met
|
|
Jodie, WV
|
|
U/S
|
|
CM/A/S/L
|
|
R T
|
|
—
|
|
|
—
|
|
|
0.1
|
|
|
2007
|
Low Volatile Metallurgical
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Buchanan(1)
|
|
Mavisdale, VA
|
|
U
|
|
LW/CM
|
|
R T
|
|
4.8
|
|
|
3.5
|
|
|
5.7
|
|
|
1983
|
Amonate (1)(2)
|
|
Amonate, VA
|
|
U/S
|
|
A/S/CM
|
|
R T
|
|
—
|
|
|
0.1
|
|
|
—
|
|
|
2012
|
Total
|
|
|
|
|
|
|
|
|
|
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
|
|
|
2007
|
Western Allegheny-Knob Creek(2)(4)
|
|
Young Township, PA
|
|
U
|
|
CM
|
|
R T
|
|
0.3
|
|
|
0.1
|
|
|
0.1
|
|
|
2010
|
Total CONSOL Energy Portion of Equity Affiliates
|
|
|
|
|
|
|
|
|
|
0.7
|
|
|
0.5
|
|
|
0.5
|
|
|
|
A
|
–
|
Auger
|
S
|
–
|
Surface
|
U
|
–
|
Underground
|
LW
|
–
|
Longwall
|
CM
|
–
|
Continuous Miner
|
S/L
|
–
|
Stripping Shovel and Front End Loaders
|
R
|
–
|
Rail
|
B
|
–
|
Barge
|
R/B
|
–
|
Rail to Barge
|
T
|
–
|
Truck
|
CB
|
–
|
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 include facilities 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 at a reduced capacity.
|
(4)
|
–
|
Production amounts represent CONSOL Energy's 49% ownership interest.
|
|
|
Years Ended December 31,
|
||||||||||
|
|
2013
|
|
2012
|
|
2011
|
||||||
Average Sales Price Per Ton Sold– Thermal Coal
|
|
$
|
64.78
|
|
|
$
|
69.08
|
|
|
$
|
66.84
|
|
Average Sales Price Per Ton Sold– High Volatile Met Coal
|
|
$
|
63.44
|
|
|
$
|
63.93
|
|
|
$
|
78.57
|
|
Average Sales Price Per Ton Sold– Low Volatile Met Coal
|
|
$
|
92.64
|
|
|
$
|
140.11
|
|
|
$
|
191.81
|
|
Average Sales Price Per Ton Sold– Total Company
|
|
$
|
69.34
|
|
|
$
|
77.75
|
|
|
$
|
90.10
|
|
|
|
Tons
|
|
Percent of
|
||
|
|
Sold
|
|
Total
|
||
Thermal
|
|
21.4
|
|
|
74
|
%
|
High Volatile Metallurgical
|
|
2.5
|
|
|
9
|
%
|
Low Volatile Metallurgical
|
|
4.9
|
|
|
17
|
%
|
Total tons sold
|
|
28.8
|
|
|
100
|
%
|
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
|
|
|
•
|
Fixed price contracts with pre-established prices;
|
•
|
Periodically negotiated prices that reflect market conditions at the time;
|
•
|
Price restricted to an agreed-upon percentage increase or decrease; or
|
•
|
Base-price-plus-escalation methods which allow for periodic price adjustments based on inflation indices, or other negotiated indices.
|
•
|
the price of competing coal and alternative fuel supplies, including nuclear, natural gas, oil and
|
•
|
environmental and government regulation;
|
•
|
coal quality;
|
•
|
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.
|
•
|
the caching of additional supplies of self-contained self-rescuer (SCSR) devices underground;
|
•
|
the purchase and installation of electronic communication and personal tracking devices underground;
|
•
|
the placement of refuge chambers, which are structures designed to provide refuge for groups of miners during a mine emergency when evacuation from the mine is not possible, which will provide breathable air for 96 hours;
|
•
|
the replacement of existing seals in worked-out areas of mines with stronger seals;
|
•
|
the purchase of new fire resistant conveyor belting underground;
|
•
|
additional training and testing that creates the need to hire additional employees; and
|
•
|
more stringent rock dusting requirements.
|
•
|
current and former coal miners totally disabled from black lung disease;
|
•
|
certain survivors of a miner who dies from black lung disease or pneumoconiosis; and
|
•
|
a trust fund for the payment of benefits and medical expenses to claimants whose last mine employment was before January 1, 1970, where no responsible coal mine operator has been identified for claims (where a miner's last coal employment was after December 31, 1969), or where the responsible coal mine operator has defaulted on the payment of such benefits. The trust fund is funded by an excise tax on U.S. production of up to $1.10 per ton for deep mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price.
|
ITEM 1A.
|
Risk Factors
|
•
|
demand for natural gas and electricity in the United States is impacted by industrial production, which if weakened would negatively impact the revenues, margins and profitability of our natural gas and thermal coal business;
|
•
|
demand for metallurgical coal depends on steel demand in the United States and globally, which if weakened would negatively impact the revenues, margins and profitability of our metallurgical coal business including our ability to sell our thermal coal as higher-priced high volatile metallurgical coal;
|
•
|
the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect our trade receivables and the amount of receivables eligible for sale pursuant to our accounts receivable securitization facility may decline;
|
•
|
our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital for our business including for exploration and/or development of our gas or coal reserves; and
|
•
|
our commodity hedging arrangements could become ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection.
|
•
|
the overall domestic supply of natural gas;
|
•
|
the supply of natural gas in our market;
|
•
|
changes in the consumption pattern of industrial consumers, electricity generators and residential users;
|
•
|
weather conditions;
|
•
|
proximity and capacity of gas pipelines and other transportation facilities;
|
•
|
overall domestic and global economic conditions;
|
•
|
the price and availability of alternative fuels, especially thermal coal; and
|
•
|
the price and supply of imported liquefied natural gas.
|
•
|
overall domestic and global economic conditions, technological advances affecting energy consumption, price and availability of foreign coal, and domestic and foreign government regulations;
|
•
|
the consumption pattern of industrial consumers, electricity generators and residential users;
|
•
|
weather can impact thermal coal demand (for example, the unusually warm 2011 - 2012 winter left utilities with large coal stockpiles and depressed the demand for thermal coal);
|
•
|
the price and availability of alternative fuels for electricity generation, especially natural gas (for example, abundant natural gas supplies at prices averaging less than $3/MMbtu during 2012 depressed the demand for thermal coal as natural gas fired electricity generation market share increased from approximately 25% in 2011 to 30% in 2012 and coal-fired generation declined from approximately 42% in 2011 to 37% in 2012); and
|
•
|
increased utilization by the steel industry of electric arc furnaces or pulverized coal processes to make steel which do not use furnace coke, an intermediate product produced from metallurgical coal, decreases the demand for metallurgical coal.
|
•
|
unexpected drilling conditions;
|
•
|
title problems;
|
•
|
pressure or irregularities in geologic formations;
|
•
|
equipment failures or repairs;
|
•
|
fires, explosions or other accidents;
|
•
|
adverse weather conditions;
|
•
|
reductions in natural gas prices;
|
•
|
security breaches or terroristic acts;
|
•
|
pipeline ruptures;
|
•
|
lack of adequate capacity for treatment or disposal of waste water generated in drilling, completion and production operations;
|
•
|
environmental contamination from surface spillage of fluids used in well drilling, completion or operation including fracturing fluids used in hydraulic fracturing of wells, or other contamination of groundwater or the environment resulting from our use of such fluids; and
|
•
|
unavailability or high cost of drilling rigs, other field services and equipment.
|
•
|
variations in thickness of the layer, or seam, of coal;
|
•
|
amounts of rock and other natural materials intruding into the coal seam and other geological conditions that could affect the stability of the roof and the side walls of the mine;
|
•
|
equipment failures or repairs;
|
•
|
fires, explosions or other accidents;
|
•
|
weather conditions; and
|
•
|
security breaches or terroristic acts.
|
•
|
geological conditions;
|
•
|
changes in governmental regulations and taxation;
|
•
|
the amount and timing of actual production;
|
•
|
assumptions governing future prices;
|
•
|
future operating costs; and
|
•
|
capital costs of drilling, completion and gathering assets.
|
•
|
geological conditions;
|
•
|
historical production from the area compared with production from other producing areas;
|
•
|
the assumed effects of regulations and taxes by governmental agencies;
|
•
|
assumptions governing future prices; and
|
•
|
future operating costs, including the cost of materials.
|
•
|
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).
|
•
|
uncertainties in assessing the value, strengths, and potential profitability of, and identifying the extent of all weaknesses, risks, contingent and other liabilities (including environmental liabilities) of expansion and acquisition opportunities;
|
•
|
the potential loss of key customers, management and employees of an acquired business;
|
•
|
the ability to achieve identified operating and financial synergies anticipated to result from an expansion or an acquisition opportunity;
|
•
|
the potential revision of assumptions regarding gas reserves as we acquire more knowledge by operating an acquired gas business;
|
•
|
problems that could arise from the integration of the acquired business;
|
•
|
unanticipated changes in business, industry or general economic conditions that affect the assumptions underlying our rationale for pursuing the expansion or the acquisition opportunity; and
|
•
|
we may have to assume cleanup or reclamation obligations or other unanticipated liabilities in connection with these acquisitions.
|
•
|
The development of these properties is subject to the terms of our joint development agreements with these parties and we no longer have the flexibility to control the development of these properties. For example, the joint development agreements for each of these joint ventures sets forth required capital expenditure programs that each party must participate in unless the parties mutually agree to change such programs or, in certain limited circumstances in the case of the Noble Energy joint development agreement, a party elects to exercise a non-consent right with respect to an entire year. If we do not timely meet our financial commitments under the respective joint venture agreements, our rights to participate in such joint ventures will be adversely affected and the other parties to the joint ventures may have a right to acquire a share of our interest in such joint ventures proportionate to, and in satisfaction of, our unmet financial obligations. In addition, each joint venture party has the right to elect to participate in all acreage and other acquisitions in certain defined areas of mutual interest.
|
•
|
Each joint development agreement assigns to each party designated areas over which that party will manage and control operations. We could incur liability as a result of action taken by one of our joint venture partners.
|
•
|
Approximately $1.9 billion of consideration that we expect to receive from Noble Energy depends upon Noble Energy paying a portion of our share of drilling and development costs for new wells, which we call “carried costs.” We entered into a similar transaction with Hess Ohio Developments, LLC (Hess) in which approximately $335 million of consideration that we expect to receive from Hess is dependent upon Hess paying carried costs. Thus, the benefits we anticipate receiving in the joint ventures depend in part upon the rate at which new wells are drilled and developed in each joint venture, which could fluctuate significantly from period to period. Moreover, the performance of these third party obligations is outside our control. The inability or failure of a joint venturer to pay its portion of development costs, including our carried costs during the carry period, could increase our costs of operations or result in reduced drilling and production of oil and gas or loss of rights to develop the oil and gas properties held by that joint venture.
|
•
|
Noble Energy's obligation to pay carried costs is suspended if average Henry Hub natural gas prices fall and remain below $4.00 per million British thermal units or “MMbtu” in any three consecutive month period and will remain suspended until average natural gas prices are above $4.00/MMbtu for three consecutive months. As a result of this provision, Noble Energy's obligation to pay carried costs was suspended beginning on December 1, 2011. We cannot predict when this suspension will be lifted and Noble Energy's obligation to pay the carried costs will resume. This suspension has the effect of requiring us to incur our entire 50 percent share of the drilling and completion costs for new wells during the suspension period and delaying receipt of a portion of the value we expect to receive in the transaction.
|
•
|
The Noble Energy joint development agreement prohibits prior to March 31, 2014, unless Noble Energy consents in its sole discretion, any transfer of our interests in the Noble Energy joint venture assets or our selling or otherwise transferring control of CNX Gas Company. The Hess joint development agreement prohibits prior to October 21, 2014, unless Hess consents in its sole discretion, any transfer of our interests in the Hess joint venture assets. These restrictions may preclude transactions which could be beneficial to our shareholders.
|
•
|
Disputes between us and our joint venture partners may result in litigation or arbitration that would increase our expenses, delay or terminate projects and distract our officers and directors from focusing their time and effort on our business.
|
•
|
increasing our vulnerability to general adverse economic and industry conditions;
|
•
|
limiting our ability to obtain additional financing to fund future working capital, capital expenditures, acquisitions, development of our gas and coal reserves or other general corporate requirements;
|
•
|
limiting our flexibility in planning for, or reacting to, changes in our business and in the coal and gas industries; and
|
•
|
placing us at a competitive disadvantage compared to less leveraged competitors.
|
•
|
our production is less than expected;
|
•
|
the counterparties to our contracts fail to perform the contracts; or
|
•
|
the creditworthiness of our counterparties or their guarantors is substantially impaired.
|
ITEM 1B.
|
Unresolved Staff Comments
|
ITEM 2.
|
Properties
|
ITEM 3.
|
Legal Proceedings
|
ITEM 4.
|
Mine Safety and Health Administration Safety Data
|
ITEM 5.
|
Market for Registrant's Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities
|
|
|
|
High
|
|
Low
|
|
Dividends
|
||||||
Year 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
|
|
|
$
|
0.125
|
|
Year 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
|
|
|
$
|
0.250
|
|
|
|
2008
|
|
2009
|
|
2010
|
|
2011
|
|
2012
|
|
2013
|
||||||
CONSOL Energy Inc.
|
|
100.0
|
|
|
175.6
|
|
|
173.3
|
|
|
132.1
|
|
|
117.8
|
|
|
141.0
|
|
Peer Group
|
|
100.0
|
|
|
149.0
|
|
|
167.3
|
|
|
140.2
|
|
|
131.4
|
|
|
151.2
|
|
S&P 500 Stock Index
|
|
100.0
|
|
|
63.4
|
|
|
79.8
|
|
|
91.7
|
|
|
104.0
|
|
|
134.8
|
|
ITEM 6.
|
Selected Financial Data
|
|
|
For the Years Ended December 31,
|
||||||||||||||||||
|
|
2013
|
|
2012
|
|
2011
|
|
2010
|
|
2009
|
||||||||||
Operating revenues from Continuing Operations
|
|
$
|
3,120,722
|
|
|
$
|
3,282,350
|
|
|
$
|
4,237,913
|
|
|
$
|
3,559,511
|
|
|
$
|
3,202,549
|
|
Income from Continuing Operations
|
|
$
|
79,264
|
|
|
$
|
317,959
|
|
|
$
|
681,675
|
|
|
$
|
315,240
|
|
|
$
|
515,700
|
|
Net Income Attributable to CONSOL Energy Inc. Shareholders
|
|
$
|
660,442
|
|
|
$
|
388,470
|
|
|
$
|
632,497
|
|
|
$
|
346,779
|
|
|
$
|
539,717
|
|
Earnings per share:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Income from Continuing Operations
|
|
$
|
0.35
|
|
|
$
|
1.40
|
|
|
$
|
3.01
|
|
|
$
|
1.41
|
|
|
$
|
2.70
|
|
Income from Discontinued Operations
|
|
2.54
|
|
|
0.31
|
|
|
(0.22
|
)
|
|
0.20
|
|
|
0.29
|
|
|||||
Net Income
|
|
$
|
2.89
|
|
|
$
|
1.71
|
|
|
$
|
2.79
|
|
|
$
|
1.61
|
|
|
$
|
2.99
|
|
Dilutive:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Income from Continuing Operations
|
|
$
|
.35
|
|
|
$
|
1.39
|
|
|
$
|
2.98
|
|
|
$
|
1.40
|
|
|
$
|
2.67
|
|
Income from Discontinued Operations
|
|
2.52
|
|
|
0.31
|
|
|
(0.22
|
)
|
|
0.20
|
|
|
0.28
|
|
|||||
Net 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
|
|
|
$
|
5,281,010
|
|
Assets from Discontinued Operations
|
|
—
|
|
|
2,614,251
|
|
|
2,573,623
|
|
|
2,527,153
|
|
|
2,494,391
|
|
|||||
Total assets
|
|
$
|
11,393,667
|
|
|
$
|
12,997,594
|
|
|
$
|
12,525,700
|
|
|
$
|
12,070,610
|
|
|
$
|
7,775,401
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Long-term debt from Continuing Operations (including current portion)
|
|
$
|
3,175,014
|
|
|
$
|
3,185,497
|
|
|
$
|
3,196,455
|
|
|
$
|
3,209,101
|
|
|
$
|
465,975
|
|
Long-term debt from Discontinued Operations (including current portion)
|
|
—
|
|
|
2,574
|
|
|
1,659
|
|
|
1,820
|
|
|
2,327
|
|
|||||
Total Long-term debt (including current portion)
|
|
$
|
3,175,014
|
|
|
$
|
3,188,071
|
|
|
$
|
3,198,114
|
|
|
$
|
3,210,921
|
|
|
$
|
468,302
|
|
Cash dividends declared per share of common stock
|
|
$
|
0.375
|
|
|
$
|
0.625
|
|
|
$
|
0.425
|
|
|
$
|
0.400
|
|
|
$
|
0.400
|
|
|
|
Years Ended December 31,
|
||||||||||||||||||
|
|
2013
|
|
2012
|
|
2011
|
|
2010
|
|
2009
|
||||||||||
Gas:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net sales volumes produced (in billion cubic feet)
|
|
172.4
|
|
|
156.3
|
|
|
153.5
|
|
|
127.9
|
|
|
94.4
|
|
|||||
Average sales price ($ per Mcfe)(A)
|
|
$
|
4.30
|
|
|
$
|
4.22
|
|
|
$
|
4.90
|
|
|
$
|
5.83
|
|
|
$
|
6.68
|
|
Average cost ($ per Mcfe)
|
|
$
|
3.51
|
|
|
$
|
3.37
|
|
|
$
|
3.53
|
|
|
$
|
3.54
|
|
|
$
|
3.15
|
|
Proved 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
|
|
|
32,185
|
|
|||||
Tons produced from continuing operations (in thousands)
|
|
28,476
|
|
|
27,178
|
|
|
31,721
|
|
|
31,895
|
|
|
32,987
|
|
|||||
Average sales price of tons produced ($ per ton produced)
|
|
$
|
69.34
|
|
|
$
|
77.75
|
|
|
$
|
90.10
|
|
|
$
|
73.31
|
|
|
$
|
66.71
|
|
Average Cost of Goods Sold ($ per ton produced)
|
|
$
|
50.78
|
|
|
$
|
53.98
|
|
|
$
|
51.88
|
|
|
$
|
44.37
|
|
|
$
|
41.76
|
|
Recoverable coal reserves (tons in millions)(D)
|
|
3,032
|
|
|
4,229
|
|
|
4,314
|
|
|
4,229
|
|
|
4,350
|
|
|||||
Number 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 following amount from third parties: 0.6 million tons, 0.5 million tons, 0.6 million tons, 0.2 million tons, and 0.3 million tons for the years ended
December 31, 2013
,
2012
,
2011
,
2010
and
2009
, respectively.
|
(D)
|
Represents proven and probable coal reserves at period end, excluding equity affiliates.
|
ITEM 7.
|
Management's Discussion and Analysis of Financial Condition and Results of Operations
|
•
|
Record total gas production of 172.4 Bcfe in 2013, 10% higher than 2012.
|
•
|
Record Marcellus Shale production of 57.8 Bcfe in 2013, 58% higher than 2012.
|
•
|
Completed a lease with the Allegheny County Airport Authority, which operates the Pittsburgh International Airport and the Allegheny County Airport, for the oil and gas rights on approximately 9.3 thousand acres. A majority of these contiguous acres are in the liquids area of the Marcellus Shale play. An up-front bonus payment of $46.3 million was paid at closing. Noble Energy, our joint venture partner, acquired 50% of the acres and accordingly, reimbursed CONSOL Energy for 50% of the associated costs. Approximately 7.6% of the bonus payment was placed into escrow while negotiations continue for a portion of the acres associated with the Allegheny County Airport and other acres that have potentially defective title. To date, less than 1% of this amount has been released from escrow. We must spud a well by February 21, 2015 and proceed with due diligence to complete the well or the lease terminates and the bonus is foregone.
|
•
|
Entered into a farm-in agreement for approximately 90 thousand additional Marcellus Shale acres in West Virginia. Consideration of up to $190 million will be paid by CONSOL Energy in two installments: (i) 50% was paid at closing and (ii) the balance due over time as the acres are drilled. Closing occurred on December 5, 2013. Noble Energy, our Marcellus Shale joint venture partner, acquired a 50% interest in the acres and accordingly, will reimburse CONSOL Energy for 50% of the associated costs.
|
•
|
Completed the sale of Consolidation Coal Company (CCC) and certain of its subsidiaries, which contains all five of CONSOL Energy's longwall coal mines in West Virginia, to a subsidiary of Murray Energy Corporation (Murray Energy). The CCC mines sold were McElroy Mine, Shoemaker Mine, Robinson Run Mine, Loveridge Mine, and Blacksville No. 2 Mine. Collectively, these mines produced 26.7 million tons of thermal coal in 2013 and 28.8 million tons of thermal coal in 2012. Murray Energy acquired approximately 1.1 billion tons of Pittsburgh No. 8 seam reserves. CONSOL Energy’s River and Dock Operations were included in the transaction. CONSOL Energy received $850 million in cash as a result of the transaction. CONSOL Energy retained an overriding royalty interest in certain reserves sold in the transaction that included minimum royalty payments of $42 million. Additionally, Murray Energy acquired approximately $1.9 billion of other postretirement benefit plan liabilities, $100 million of workers compensation liabilities, $50 million of coal workers’ pneumoconiosis liabilities, $10 million of long term disability liabilities, $155 million of environmental liabilities and CONSOL Energy’s UMWA 1974 Pension Trust Obligations. The pre-tax financial gain resulting from the transaction was $1,035 million.
|
•
|
In conjunction with the sale of CCC and certain of its subsidiaries, CONSOL Energy realigned its dividend policy to reflect the company’s increased emphasis on growth. CONSOL Energy intends to pay a regular quarterly rate of $0.0625 per common share, or a 2014 annual rate of $0.25 per share, beginning with the first quarter of 2014.
|
•
|
Our 2014 annual gas production is expected to be between 215 - 235 Bcfe with annual production growth of 30% for 2015 and 2016.
|
•
|
Our 2014 gas capital investment is expected to be $1,110 million.
|
•
|
Our 2014 coal production is expected to be between 30.1 - 32.1 million tons.
|
•
|
Our 2014 coal capital investment is expected to be $390 million.
|
•
|
Pension settlement accounting may occur in 2014 related to staff reduction that occured in relation to the sale of CCC and certain subsidiaries.
|
•
|
BMX Mine is expected to begin longwall mining during the first quarter of 2014.
|
•
|
In August 2013, CONSOL Energy completed the sale of its 50% interest in the CONSOL Energy/Devon Energy joint venture in Alberta, Canada. The properties and coal leases included were those related to Grassy Mountain, Bellevue, Adanac, and Lynx Creek (Crowsnest Pass). Cash proceeds for the sale were $24.7 million. The transaction resulted in a $15.3 million pre-tax gain on the sale of assets.
|
•
|
On June 24, 2013, CONSOL Energy closed the sale of the Potomac coal reserves located in Grant and Tucker Counties in West Virginia. Cash proceeds from the sale were $25.0 million. The transaction resulted in a $24.7 million pre-tax gain on the sale of assets.
|
•
|
Pension settlement accounting required the acceleration of previously unrecognized actuarial losses due to lump sum payments from the Company's qualified and non-qualified salary retirement pension plans exceeding the annual projected service and interest costs of the plans. The pension settlement resulted in a $39.5 million pre-tax expense adjustment. Many of the lump sum payments in the year ended December 31, 2013 were paid to employees who elected to retire under the 2012 Voluntary Severance Incentive Plan.
|
•
|
A review of certain titles in the Company's Marcellus Shale acreage, continued throughout the year ended December 31, 2013. As a result of the Company's review of the title defects, asserted by its joint venture partner Noble Energy, and working in collaboration with Noble, CONSOL Energy has conceded defects on acreage with a value of $23.1 million. See Note 11- Property, Plant and Equipment, in the Notes to the Audited Consolidated Financial Statements included in this Form 10-K for additional details.
|
•
|
In the year ended December 31, 2013, an agreement was reached for resolution of the class actions brought by shareholders of CNX Gas alleging that the price paid by CONSOL Energy to acquire all the shares of CNX Gas common stock that CONSOL Energy did not already own for $38.25 per share in May 2010 was not fair. The total settlement provided for a payment to the plaintiffs of $42.7 million, of which the CONSOL Energy’s portion was $19.2 million. See Note 24 - Commitments and Contingencies, in the Notes to the Audited Consolidated Financial Statements included in this Form 10-K for additional details.
|
•
|
On March 12, 2013, smoke was detected exiting the Orndoff shaft at CONSOL Energy's Blacksville No. 2 Mine near Wayne in Greene County, Pennsylvania. All day shift underground employees were safely evacuated and no one sustained injuries. The location of the fire was identified and containment and extinguishment procedures were followed. The fire was successfully extinguished and the longwall restarted May 20, 2013. This event resulted in a pre-tax expense of $34.3 million in the year ended December 31, 2013.
|
•
|
Severance and related costs of $9.5 million pre-tax expense related to the change in control of the 5 coal mines and the reduction of supporting administrative staff was reflected in the 2013 financial results.
|
•
|
Settlement and curtailment gains totaling $1.6 billion were recognized related to the company’s obligations under the Other Postretirement Benefits, Workers’ Compensation, Pension, Coal Workers’ Pneumoconiosis, and Long-Term Disability plans as a result of the sale to Murray Energy.
|
|
|
For the Years Ended December 31,
|
|||||||||||||
in thousands (unless noted)
|
|
2013
|
|
2012
|
|
Variance
|
|
Percent
Change |
|||||||
LIQUIDS
|
|
|
|
|
|
|
|
|
|
|
|||||
NGLs:
|
|
|
|
|
|
|
|
|
|
|
|||||
Sales Volume (MMcfe)
|
|
2,628
|
|
|
610
|
|
|
2,018
|
|
|
330.8
|
%
|
|||
Sales Volume (Mbbls)
|
|
438
|
|
|
102
|
|
|
336
|
|
|
329.4
|
%
|
|||
Gross Price ($/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
|
%
|
•
|
Gathering costs increased in the period-to-period comparison due to a $0.04 per Mcfe increase in processing fees associated with natural gas liquids and a $0.10 per Mcfe increase in firm transportation costs.
|
•
|
Depreciation, depletion and amortization rates increased due to higher units-of-production for producing properties in the period to period comparison offset, in part, by additional volumes.
|
•
|
These increases were offset, in part, by higher volumes in the period-to-period comparison due to the on-going Marcellus drilling program. Fixed costs are allocated over increased volumes, resulting in lower unit costs.
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2013
|
|
2012
|
|
Variance
|
|
Percent
Change
|
|||||||
Average Sales Price per ton sold
|
$
|
69.34
|
|
|
$
|
77.75
|
|
|
$
|
(8.41
|
)
|
|
(10.8
|
)%
|
Average Costs of Goods Sold per ton
|
50.78
|
|
|
53.98
|
|
|
(3.20
|
)
|
|
(5.9
|
)%
|
|||
Margin
|
$
|
18.56
|
|
|
$
|
23.77
|
|
|
$
|
(5.21
|
)
|
|
(21.9
|
)%
|
•
|
Average cost of goods sold decreased due to an increase in tons sold. Fixed costs are allocated over more sales tons, resulting in lower unit costs.
|
•
|
On July 27, 2012, a structural failure occurred at the Bailey Preparation Plant in Southwestern Pennsylvania. The belt system conveys coal from both the Bailey and Enlow Fork Mines to the Bailey Preparation Plant. The incident caused a total of four longwalls to be idled for approximately three weeks, and production to be at approximately 60% for the third quarter of 2012. The mines operated at full capacity for the entire 2013 period, which resulted in lower direct operating costs per ton produced.
|
•
|
The Fola Mining Complex was idled in August 2012 which resulted in lower direct operating costs per ton produced in the period-to-period comparison. The mine, which was idled for market reasons, was a higher cost mining operation which when removed reduced the overall average direct operating costs per ton produced.
|
•
|
Direct services to operations are improved primarily due to a reduction in subsidence expenses related to the timing and nature of properties and streams undermined as well as a reduction in direct administration employees as a result of the 2012 Voluntary Severance Incentive Plan discussed below under general and administrative costs.
|
•
|
Depreciation, depletion and amortization was improved primarily due to the idling of operations at the Fola Mining Complex in August 2012. The improvements were offset, in part, by higher costs in the 2013 period related to Bailey, Enlow Fork, and Buchanan Mines running for the full year in 2013 compared to being idled at various times throughout 2012.
|
•
|
Average direct operating costs were impaired due to CONSOL Energy entering into a new longwall lease in 2013 at our Bailey Mine.
|
•
|
Costs were impaired in the current period due to the idling of the Buchanan Mine for various months throughout 2012. Although idled at times during 2012, the Buchanan Mine ran the continuous miners and worked on various projects which increased overall 2012 unit costs.
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2013
|
|
2012
|
|
Variance
|
|
Percent
Change
|
|||||||
Contributions
|
$
|
7
|
|
|
$
|
9
|
|
|
$
|
(2
|
)
|
|
(22.2
|
)%
|
Employee Wages and Related Expenses
|
33
|
|
|
35
|
|
|
(2
|
)
|
|
(5.7
|
)%
|
|||
Advertising and Promotion
|
4
|
|
|
4
|
|
|
—
|
|
|
—
|
%
|
|||
Consulting and Professional Services
|
21
|
|
|
14
|
|
|
7
|
|
|
50.0
|
%
|
|||
Miscellaneous
|
17
|
|
|
17
|
|
|
—
|
|
|
—
|
%
|
|||
Total Company General and Administrative Expenses
|
$
|
82
|
|
|
$
|
79
|
|
|
$
|
3
|
|
|
3.8
|
%
|
•
|
Contributions decreased $
2
million related to various transactions that occurred throughout both periods, none of which were individually material.
|
•
|
Employee wages and related expenses decreased $
2
million primarily attributable to fewer employees as a result of the 2012 Voluntary Severance Incentive Plan, as previously discussed. There was also lower salary other post-employment benefit (OPEB) expenses in the period-to-period comparison related to changes in the discount rates and other assumptions.
|
•
|
Advertising and promotion remained consistent in the period-to-period comparison.
|
•
|
Consulting and professional services increased $
7
million in the period-to-period comparison. Various legal proceedings accounted for $3 million of the increase and an additional $2 million was related to tax advisory services. The remaining increase was due to various other corporate initiatives, none of which were individually significant.
|
•
|
Miscellaneous general and administrative expenses remained consistent in the period-to-period comparison.
|
|
For the Year Ended
|
|
Difference to Year Ended
|
||||||||||||||||||||||||||||||||||||
|
December 31, 2013
|
|
December 31, 2012
|
||||||||||||||||||||||||||||||||||||
|
Marcellus
|
|
CBM
|
|
Shallow Oil and Gas
|
|
Other
Gas
|
|
Total
Gas
|
|
Marcellus
|
|
CBM
|
|
Shallow Oil and Gas
|
|
Other
Gas
|
|
Total
Gas
|
||||||||||||||||||||
Sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||
Produced
|
$
|
252
|
|
|
$
|
336
|
|
|
$
|
131
|
|
|
$
|
19
|
|
|
$
|
738
|
|
|
$
|
118
|
|
|
$
|
(42
|
)
|
|
$
|
(4
|
)
|
|
$
|
9
|
|
|
$
|
81
|
|
Related Party
|
—
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
||||||||||
Total Outside Sales
|
252
|
|
|
339
|
|
|
131
|
|
|
19
|
|
|
741
|
|
|
118
|
|
|
(41
|
)
|
|
(4
|
)
|
|
9
|
|
|
82
|
|
||||||||||
Gas Royalty Interest
|
—
|
|
|
—
|
|
|
—
|
|
|
63
|
|
|
63
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
13
|
|
|
13
|
|
||||||||||
Purchased Gas
|
—
|
|
|
—
|
|
|
—
|
|
|
7
|
|
|
7
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
4
|
|
||||||||||
Other Income
|
—
|
|
|
—
|
|
|
—
|
|
|
58
|
|
|
58
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
1
|
|
||||||||||
Total Revenue and Other Income
|
252
|
|
|
339
|
|
|
131
|
|
|
147
|
|
|
869
|
|
|
118
|
|
|
(41
|
)
|
|
(4
|
)
|
|
27
|
|
|
100
|
|
||||||||||
Lifting
|
20
|
|
|
37
|
|
|
35
|
|
|
5
|
|
|
97
|
|
|
8
|
|
|
—
|
|
|
(5
|
)
|
|
3
|
|
|
6
|
|
||||||||||
Ad Valorem, Severance, and Other Taxes
|
9
|
|
|
9
|
|
|
10
|
|
|
1
|
|
|
29
|
|
|
5
|
|
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
|
3
|
|
||||||||||
Gathering
|
50
|
|
|
114
|
|
|
34
|
|
|
3
|
|
|
201
|
|
|
26
|
|
|
8
|
|
|
8
|
|
|
(2
|
)
|
|
40
|
|
||||||||||
Gas Direct Administrative, Selling & Other
|
26
|
|
|
8
|
|
|
10
|
|
|
5
|
|
|
49
|
|
|
9
|
|
|
(6
|
)
|
|
(3
|
)
|
|
2
|
|
|
2
|
|
||||||||||
Depreciation, Depletion and Amortization
|
67
|
|
|
90
|
|
|
60
|
|
|
13
|
|
|
230
|
|
|
20
|
|
|
3
|
|
|
1
|
|
|
4
|
|
|
28
|
|
||||||||||
General & Administration
|
—
|
|
|
—
|
|
|
—
|
|
|
45
|
|
|
45
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|
5
|
|
||||||||||
Gas Royalty Interest
|
—
|
|
|
—
|
|
|
—
|
|
|
53
|
|
|
53
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
14
|
|
|
14
|
|
||||||||||
Purchased Gas
|
—
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
2
|
|
||||||||||
Exploration and Other Costs
|
—
|
|
|
—
|
|
|
—
|
|
|
61
|
|
|
61
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
22
|
|
|
22
|
|
||||||||||
Other Corporate Expenses
|
—
|
|
|
—
|
|
|
—
|
|
|
92
|
|
|
92
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
15
|
|
|
15
|
|
||||||||||
Interest Expense
|
—
|
|
|
—
|
|
|
—
|
|
|
9
|
|
|
9
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
4
|
|
||||||||||
Total Cost
|
172
|
|
|
258
|
|
|
149
|
|
|
292
|
|
|
871
|
|
|
68
|
|
|
4
|
|
|
1
|
|
|
68
|
|
|
141
|
|
||||||||||
Earnings (Loss) Before Income Tax
|
80
|
|
|
81
|
|
|
(18
|
)
|
|
(145
|
)
|
|
(2
|
)
|
|
50
|
|
|
(45
|
)
|
|
(5
|
)
|
|
(41
|
)
|
|
(41
|
)
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2013
|
|
2012
|
|
Variance
|
|
Percent
Change
|
|||||||
Marcellus 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
|
%
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2013
|
|
2012
|
|
Variance
|
|
Percent
Change
|
|||||||
CBM 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
|
)%
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2013
|
|
2012
|
|
Variance
|
|
Percent
Change
|
|||||||
Shallow 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 (per Mcfe)
|
$
|
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
|
%
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2013
|
|
2012
|
|
Variance
|
|
Percent
Change
|
|||||||
Gas 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
|
%
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2013
|
|
2012
|
|
Variance
|
|
Percent
Change
|
|||||||
Purchased 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
|
%
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2013
|
|
2012
|
|
Variance
|
|
Percent
Change
|
|||||||
Gas 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
|
%
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2013
|
|
2012
|
|
Variance
|
|
Percent
Change
|
|||||||
Purchased Gas Sales Volumes (Bcf)
|
1.6
|
|
|
1.1
|
|
|
0.5
|
|
|
45.5
|
%
|
|||
Average Cost (per Mcf)
|
$
|
3.05
|
|
|
$
|
2.44
|
|
|
$
|
0.61
|
|
|
25.0
|
%
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2013
|
|
2012
|
|
Variance
|
|
Percent
Change
|
|||||||
Marcellus Title Defects
|
$
|
23
|
|
|
$
|
4
|
|
|
$
|
19
|
|
|
475.0
|
%
|
Dry Hole Costs
|
8
|
|
|
3
|
|
|
5
|
|
|
166.7
|
%
|
|||
Exploration Costs
|
20
|
|
|
18
|
|
|
2
|
|
|
11.1
|
%
|
|||
Lease Expiration Costs
|
10
|
|
|
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 title defects on acreage which had a carrying value to CONSOL Energy of
$23
million for the year ended
December 31, 2013
compared to
$4
million for the year ended
December 31, 2012
.
|
•
|
Dry hole costs increased $
5
million due to various transactions that occurred throughout both periods, none of which were individually material.
|
•
|
Exploration expense increased
$2
million due to increased exploratory expenses associated primarily with the Utica operating areas and various transactions that occurred throughout both periods, none of which were individually material.
|
•
|
Lease expiration costs relate to locations where CONSOL Energy allowed the primary term lease to expire because of unfavorable drilling economics. The
$4
million decrease is due to fewer lease expirations in the current period when compared with the prior period.
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2013
|
|
2012
|
|
Variance
|
|
Percent
Change
|
|||||||
Unutilized firm transportation
|
$
|
35
|
|
|
$
|
16
|
|
|
$
|
19
|
|
|
118.8
|
%
|
Stock-based compensation
|
24
|
|
|
18
|
|
|
6
|
|
|
33.3
|
%
|
|||
Bank fees
|
7
|
|
|
7
|
|
|
—
|
|
|
—
|
%
|
|||
Short-term incentive compensation
|
20
|
|
|
26
|
|
|
(6
|
)
|
|
(23.1
|
)%
|
|||
PA Impact fees
|
—
|
|
|
4
|
|
|
(4
|
)
|
|
(100.0
|
)%
|
|||
Other
|
6
|
|
|
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 flow uninterrupted as sales volumes increase, as well as additional processing capacity for natural gas liquids. The
$19
million increase is due to increased firm transportation capacity which has not been utilized by active operations.
|
•
|
Stock-based compensation was $
6
million higher in the period-to-period comparison primarily due to additional non-cash expense and accelerated non-cash expense for retiree-eligible employees who received awards under the new CONSOL Share Unit (CSU) program, when compared to the prior year. The new program replaces several previously provided long-term executive compensation award programs. The compensation expense of the CSU program will not be materially different from the total expense of the previous programs over the three-year performance period.
|
•
|
Bank Fees remained consistent in the period-to-period comparison.
|
•
|
The short-term incentive compensation program is designed to increase compensation to eligible employees when CNX Gas reaches predetermined targets for safety, production and unit costs. Short-term incentive compensation expense decreased $
6
million due to lower projected payouts in the 2013 period.
|
•
|
PA impact fees are related to legislation in the state of Pennsylvania (Act 13 of 2012, House Bill 1950) which was signed into law during the first quarter of 2012. This legislation permits Pennsylvania counties to impose annual fees on unconventional gas wells located within their borders. As part of the legislation, all unconventional wells which were drilled prior to January 1, 2012 were assessed an initial fee related to periods prior to 2012. The
$4
million represents this one-time initial assessment on wells drilled prior to January 1, 2012. Ongoing PA impact fees, which relate to wells drilled in the applicable period, are included as part of ad valorem, severance and other taxes in the Marcellus gas segment.
|
•
|
Other corporate related expense remained consistent in the period-to-period comparison.
|
|
For the Year Ended
|
|
Increase (Decrease) from Year Ended
|
||||||||||||||||||||||||||||||||||||
|
December 31, 2013
|
|
December 31, 2012
|
||||||||||||||||||||||||||||||||||||
|
Thermal Coal
|
|
High
Vol
Met
Coal
|
|
Low
Vol
Met
Coal
|
|
Other
Coal
|
|
Total
Coal
|
|
Thermal
Coal
|
|
High
Vol
Met
Coal
|
|
Low
Vol
Met
Coal
|
|
Other
Coal
|
|
Total
Coal
|
||||||||||||||||||||
Sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||
Produced Coal
|
$
|
1,388
|
|
|
$
|
160
|
|
|
$
|
447
|
|
|
$
|
—
|
|
|
$
|
1,995
|
|
|
$
|
(43
|
)
|
|
$
|
(50
|
)
|
|
$
|
(59
|
)
|
|
$
|
(5
|
)
|
|
$
|
(157
|
)
|
Purchased Coal
|
—
|
|
|
—
|
|
|
—
|
|
|
23
|
|
|
23
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6
|
|
|
6
|
|
||||||||||
Total Outside Sales
|
1,388
|
|
|
160
|
|
|
447
|
|
|
23
|
|
|
2,018
|
|
|
(43
|
)
|
|
(50
|
)
|
|
(59
|
)
|
|
1
|
|
|
(151
|
)
|
||||||||||
Freight Revenue
|
—
|
|
|
—
|
|
|
—
|
|
|
35
|
|
|
35
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(72
|
)
|
|
(72
|
)
|
||||||||||
Other Income
|
2
|
|
|
2
|
|
|
—
|
|
|
98
|
|
|
102
|
|
|
—
|
|
|
(4
|
)
|
|
—
|
|
|
(226
|
)
|
|
(230
|
)
|
||||||||||
Total Revenue and Other Income
|
1,390
|
|
|
162
|
|
|
447
|
|
|
156
|
|
|
2,155
|
|
|
(43
|
)
|
|
(54
|
)
|
|
(59
|
)
|
|
(297
|
)
|
|
(453
|
)
|
||||||||||
Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||
Beginning inventory costs
|
33
|
|
|
—
|
|
|
21
|
|
|
—
|
|
|
54
|
|
|
(34
|
)
|
|
(2
|
)
|
|
5
|
|
|
—
|
|
|
(31
|
)
|
||||||||||
Total direct costs
|
626
|
|
|
79
|
|
|
196
|
|
|
101
|
|
|
1,002
|
|
|
33
|
|
|
(16
|
)
|
|
12
|
|
|
(44
|
)
|
|
(15
|
)
|
||||||||||
Total royalty/production taxes
|
68
|
|
|
5
|
|
|
26
|
|
|
2
|
|
|
101
|
|
|
(6
|
)
|
|
(4
|
)
|
|
(4
|
)
|
|
(1
|
)
|
|
(15
|
)
|
||||||||||
Total direct services to operations
|
134
|
|
|
15
|
|
|
27
|
|
|
163
|
|
|
339
|
|
|
(20
|
)
|
|
(6
|
)
|
|
5
|
|
|
(54
|
)
|
|
(75
|
)
|
||||||||||
Total retirement and disability
|
58
|
|
|
7
|
|
|
25
|
|
|
10
|
|
|
100
|
|
|
(3
|
)
|
|
(3
|
)
|
|
(3
|
)
|
|
(10
|
)
|
|
(19
|
)
|
||||||||||
Depreciation, depletion and amortization
|
116
|
|
|
15
|
|
|
41
|
|
|
46
|
|
|
218
|
|
|
(4
|
)
|
|
(7
|
)
|
|
4
|
|
|
13
|
|
|
6
|
|
||||||||||
Ending inventory costs
|
(21
|
)
|
|
—
|
|
|
(10
|
)
|
|
—
|
|
|
(31
|
)
|
|
12
|
|
|
—
|
|
|
11
|
|
|
—
|
|
|
23
|
|
||||||||||
Total Costs and Expenses
|
1,014
|
|
|
121
|
|
|
326
|
|
|
322
|
|
|
1,783
|
|
|
(22
|
)
|
|
(38
|
)
|
|
30
|
|
|
(96
|
)
|
|
(126
|
)
|
||||||||||
Freight Expense
|
—
|
|
|
—
|
|
|
—
|
|
|
35
|
|
|
35
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(72
|
)
|
|
(72
|
)
|
||||||||||
Total Costs of Goods Sold
|
1,014
|
|
|
121
|
|
|
326
|
|
|
357
|
|
|
1,818
|
|
|
(22
|
)
|
|
(38
|
)
|
|
30
|
|
|
(168
|
)
|
|
(198
|
)
|
||||||||||
Earnings (Loss) Before Income Taxes
|
$
|
376
|
|
|
$
|
41
|
|
|
$
|
121
|
|
|
$
|
(201
|
)
|
|
$
|
337
|
|
|
$
|
(21
|
)
|
|
$
|
(16
|
)
|
|
$
|
(89
|
)
|
|
$
|
(129
|
)
|
|
$
|
(255
|
)
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2013
|
|
2012
|
|
Variance
|
|
Percent
Change
|
|||||||
Company 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 Produced
|
3.22
|
|
|
3.65
|
|
|
(0.43
|
)
|
|
(11.8
|
%)
|
|||
Total Direct Services to Operations Per Thermal Ton Produced
|
6.31
|
|
|
7.61
|
|
|
(1.30
|
)
|
|
(17.1
|
%)
|
|||
Total Retirement and Disability Per Thermal Ton Produced
|
2.76
|
|
|
3.01
|
|
|
(0.25
|
)
|
|
(8.3
|
%)
|
|||
Total Depreciation, Depletion and Amortization Costs Per Thermal Ton Produced
|
5.45
|
|
|
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
|
%)
|
•
|
In 2013, CONSOL Energy entered into a new longwall lease at Bailey Mine which resulted in higher cost per ton produced in the period-to-period comparison.
|
•
|
Project expense increased in the 2013 period due to a longwall overhaul and a waterline extension project at Bailey Mine.
|
•
|
Power expense increased in the 2013 period due to an increase in rates in the current year.
|
•
|
Average cost of goods sold decreased due to an increase in tons sold. Fixed costs are allocated over more sales tons, resulting in lower unit costs.
|
•
|
On July 27, 2012, a structural failure occurred at the Bailey Preparation Plant in Southwestern Pennsylvania. The belt system conveys coal from both the Bailey and Enlow Fork Mines to the Bailey Preparation Plant. The incident caused a total of four longwalls to be idled for approximately three weeks, and production to be at approximately 60% for the third quarter of 2012. The mines operated at full capacity for the entire 2013 period, which resulted in lower direct operating costs per ton produced.
|
•
|
The Fola Mining Complex was idled in August 2012 which resulted in lower direct operating costs per ton produced in the period-to-period comparison. The mine, which was idled for market reasons, was a higher cost mining operation which when removed reduced the overall average direct operating costs per ton produced.
|
•
|
Average direct service costs to operations were improved due to a reduction in subsidence expense. The reduction was the result of the timing and nature of properties undermined in the period-to-period comparison.
|
•
|
Average direct service costs to operations were also improved due to a reduction in direct administrative employees as a result of the 2012 Voluntary Severance Incentive Plan, as discussed previously.
|
•
|
Unit costs decreased due to the increase in production volumes since fixed costs are spread over more tons.
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2013
|
|
2012
|
|
Increase (Decrease)
|
|
Percent
Change
|
|||||||
Company 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 Produced
|
1.82
|
|
|
2.72
|
|
|
(0.90
|
)
|
|
(33.1
|
%)
|
|||
Total Direct Services to Operations Per High Vol Met Ton Produced
|
5.96
|
|
|
6.22
|
|
|
(0.26
|
)
|
|
(4.2
|
%)
|
|||
Total Retirement and Disability Per High Vol Met Ton Produced
|
2.94
|
|
|
3.10
|
|
|
(0.16
|
)
|
|
(5.2
|
%)
|
|||
Total Depreciation, Depletion and Amortization Costs Per High Vol Met Ton Produced
|
5.96
|
|
|
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
|
%)
|
•
|
Average direct service costs to operations were improved due to a reduction in subsidence expense. The reduction was the result of the timing and nature of properties undermined in the period-to-period comparison. The decrease in unit costs was offset, in part, by the reduction in production tons.
|
•
|
Average direct service costs to operations were also improved due to a reduction in direct administrative employees as a result of the 2012 Voluntary Severance Incentive Plan, as discussed previously. The decrease in unit costs was also offset, in part, by the reduction in production tons.
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2013
|
|
2012
|
|
Variance
|
|
Percent
Change
|
|||||||
Company 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 Produced
|
5.54
|
|
|
8.33
|
|
|
(2.79
|
)
|
|
(33.5
|
%)
|
|||
Total Direct Services to Operations Per Low Vol Met Ton Produced
|
5.66
|
|
|
6.03
|
|
|
(0.37
|
)
|
|
(6.1
|
%)
|
|||
Total Retirement and Disability Per Low Vol Met Ton Produced
|
5.28
|
|
|
7.63
|
|
|
(2.35
|
)
|
|
(30.8
|
%)
|
|||
Total Depreciation, Depletion and Amortization Costs Per Low Vol Met Ton Produced
|
8.69
|
|
|
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
|
%)
|
•
|
Gain on sale of assets attributable to the Other Coal segment was $46 million in the year ended
December 31, 2013
compared to $271 million in the year ended
December 31, 2012
. The decrease of $225 million was primarily related to 2012 sales of non-producing assets in the Northern Powder River Basin that resulted in a gain on sale of $151 million, as well as coal and surface lands in Illinois and West Virginia that resulted in a gain on sale of $112 million. This is offset by the 2013 sale of Potomac coal reserves that resulted in a gain on sale of $25 million and the sale of 50% interest in a joint venture in Alberta, Canada that resulted in a gain on sale of $15 million. See Note 3—Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form
|
•
|
In the year ended
December 31, 2013
, $5 million of business interruption insurance proceeds were received related to the 2012 Bailey Belt Conveyor accident. There is no assurance that additional proceeds from the incident will be received.
|
•
|
The remaining $6 million decrease in other income is due to various items, none of which were individually material.
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2013
|
|
2012
|
|
Variance
|
||||||
Freight 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
|
|
|
2
|
|
|||
Stock-based Compensation
|
|
33
|
|
|
23
|
|
|
10
|
|
|||
Other
|
|
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 the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is the amount billed to customers for transportation costs incurred. Freight expense is offset by freight revenue. The $
72
million decrease in freight expense was due to decreased shipments under contracts which CONSOL Energy contractually provides transportation services.
|
•
|
Bailey Belt Incident costs represent expenses during the belt-reconstruction period. The mine was idled during this period but there was continued advancement of the mine and on-going projects which resulted in $
42
million of expense.
|
•
|
Closed and idle mine costs decreased approximately $
27
million for the year ended
December 31, 2013
compared to the year ended
December 31, 2012
. Closed and idle mine costs decreased $16 million due to the decision to shutdown the Fola Mining Complex in August 2012 and $18 million due to the decision to idle operations at Buchanan Mine for three months in 2012. These decrease were offset, in part, by an increase of $8 million in costs incurred primarily by the Amonate Complex. Other changes in the operational status of various other mines, between idled and operating throughout both periods, none of which were individually material resulted in an additional $1 million decrease.
|
•
|
Litigation Contingencies decreased $
17
million in the year-to-year comparison due to various items. See Note 24- Commitments and Contingent Liabilities in the Notes to Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details related to total Company expense.
|
•
|
In November 2012, CONSOL Energy offered a voluntary severance incentive program (VSIP) to active salaried corporate and operation support employees with 30 years of service, or more. Under this program, eligible employees who accepted the offer received a severance payment equal to one year's salary. Approximately 100 employees volunteered for the program. Severance pay was approximately $
13
million.
|
•
|
General and Administrative Expense decreased $
2
million due to various items that occurred in both periods, none of which were individually material.
|
•
|
Purchased coal costs increased $
2
million due to higher amounts of coal that was purchased to fulfill various contracts.
|
•
|
Stock-based compensation was $
10
million higher in the period-to-period comparison primarily due to additional non-cash expense and accelerated non-cash expense for retiree-eligible employees who received awards under the new CONSOL Share Unit (CSU) program. The new program replaces several previously provided long-term executive compensation award programs. The compensation expense of the CSU program will not be materially different from the total expense of the previous programs over the three-year performance period.
|
•
|
Other expenses related to the coal segment decreased $
7
million due to various transactions that occurred throughout both periods, none of which were individually material.
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2013
|
|
2012
|
|
Variance
|
|
Percent
Change
|
|||||||
Sales—Outside
|
$
|
260
|
|
|
$
|
294
|
|
|
$
|
(34
|
)
|
|
(11.6
|
)%
|
Other Income
|
19
|
|
|
6
|
|
|
13
|
|
|
216.7
|
%
|
|||
Total Revenue
|
279
|
|
|
300
|
|
|
(21
|
)
|
|
(7.0
|
)%
|
|||
Cost of Goods Sold and Other Charges
|
332
|
|
|
292
|
|
|
40
|
|
|
13.7
|
%
|
|||
Depreciation, Depletion & Amortization
|
13
|
|
|
12
|
|
|
1
|
|
|
8.3
|
%
|
|||
Taxes Other Than Income Tax
|
11
|
|
|
5
|
|
|
6
|
|
|
120.0
|
%
|
|||
Interest Expense
|
211
|
|
|
215
|
|
|
(4
|
)
|
|
(1.9
|
)%
|
|||
Total Costs
|
567
|
|
|
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
|
%
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2013
|
|
2012
|
|
Variance
|
||||||
Pennsylvania Turnpike Settlement
|
|
$
|
9
|
|
|
$
|
—
|
|
|
$
|
9
|
|
Equity in Earnings of Affiliates
|
|
1
|
|
|
—
|
|
|
1
|
|
|||
Towing Income
|
|
1
|
|
|
1
|
|
|
—
|
|
|||
Other
|
|
3
|
|
|
3
|
|
|
—
|
|
|||
|
|
$
|
14
|
|
|
$
|
4
|
|
|
$
|
10
|
|
•
|
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.
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2013
|
|
2012
|
|
Variance
|
||||||
Pension Settlement
|
|
$
|
39
|
|
|
$
|
—
|
|
|
$
|
39
|
|
CNX Gas Shareholder Settlement
|
|
19
|
|
|
—
|
|
|
19
|
|
|||
Corporate Initiative Fees and Other Legal Charges
|
|
15
|
|
|
4
|
|
|
11
|
|
|||
Accelerated Bank Fees
|
|
3
|
|
|
—
|
|
|
3
|
|
|||
Bank Fees
|
|
15
|
|
|
13
|
|
|
2
|
|
|||
Interest 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 interest costs for the 2013 plan year.
|
•
|
The CNX Gas shareholder settlement is the result of an agreement in principle for resolution of the class actions brought by shareholders of CNX Gas challenging the tender offer by CONSOL Energy to acquire all of the shares of CNX Gas common stock that CONSOL Energy did not already own for $38.25 per share in May 2010. The total settlement provides for a payment to the plaintiffs of $43 million, of which the Company paid $19 million.
|
•
|
Corporate initiative fees and other legal charges reflect various charges for services related to corporate initiatives to evaluate various asset sales. These fees also include legal charges related to land title issues raised by our joint venture partners and the CNX Gas Shareholder case. See Note 11 - Property, Plant and Equipment and Note 24 - Commitments and Contingent Liabilities of the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
|
•
|
Accelerated Bank Fees represents accelerated amortization of the previously deferred fees in relation to the capacity reduction in CONSOL Energy's revolving credit facility from $1.5 billion to $1.0 billion.
|
•
|
Bank fees increased $
2
million mainly due to higher borrowings on the CNX Gas revolving credit facilities in the period-to-period comparison.
|
•
|
Interest Expense decreased $
4
million primarily due to a reduction in capitalized interest due to lower capital expenditures for major construction projects in the current period.
|
•
|
Other corporate items decreased $
2
million due to various transactions that occurred throughout both periods, none of which were individually material.
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2013
|
|
2012
|
|
Variance
|
|
Percent
Change
|
|||||||
Total 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
|
)%
|
|
|
|
|
For the Years Ended December 31,
|
|||||||||||||
in thousands (unless noted)
|
|
2012
|
|
2011
|
|
Variance
|
|
Percent
Change |
|||||||
LIQUIDS
|
|
|
|
|
|
|
|
|
|||||||
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
|
)%
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2012
|
|
2011
|
|
Variance
|
|
Percent
Change
|
|||||||
Average 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
|
)%
|
•
|
Higher volumes in the period-to-period comparison due to the on-going drilling program, offset, in part, by 10.7 billion cubic feet divested in the 2011 Noble and the 2011 Antero transactions resulted in lower average costs per Mcfe sold. Fixed costs are allocated over increased volumes, resulting in lower unit costs.
|
•
|
Lower units-of-production depreciation, depletion and amortization rates for producing properties. These rates were generally calculated using the net book value of assets divided by either proved or proved developed reserve additions. Increased proved and proved developed reserves relative to the net book value of the producing assets as compared with the prior year resulted in a lower units-of-production rate.
|
•
|
Lower direct administrative, selling and other costs per Mcfe sold due to increased sales volumes and decreased actual dollars as a result of lower direct administrative labor and other costs.
|
•
|
Gathering costs increased in the period-to-period comparison due to higher transportation charges.
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2012
|
|
2011
|
|
Variance
|
|
Percent
Change
|
|||||||
Average Sales Price per ton sold
|
$
|
77.75
|
|
|
$
|
90.10
|
|
|
$
|
(12.35
|
)
|
|
(13.7
|
)%
|
Average Costs of Goods Sold per ton
|
53.98
|
|
|
51.88
|
|
|
2.10
|
|
|
4.0
|
%
|
|||
Margin
|
$
|
23.77
|
|
|
$
|
38.22
|
|
|
$
|
(14.45
|
)
|
|
(37.8
|
)%
|
•
|
Average cost of goods sold per ton increased due to fewer tons sold. Fixed costs are allocated over fewer sales tons, resulting in higher unit costs.
|
•
|
The idled longwall at Buchanan Mine during portions of 2012 resulted in an increase in unit costs as the fixed costs were allocated over fewer tons.
|
•
|
Average depreciation, depletion and amortization increased due to additional assets placed into service after the 2011 period.
|
•
|
Average operating supplies and maintenance costs per ton increased due to additional equipment maintenance, timing of major equipment overhaul costs, increased fuel and lubricants and use of pumpable cribs for roof support.
|
•
|
Average retirement and disability cost per ton decreased due to the improvement in other postretirement benefits discussed in the long-term liabilities section below.
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2012
|
|
2011
|
|
Variance
|
|
Percent
Change
|
|||||||
Employee Wages and Related Expenses
|
$
|
35
|
|
|
$
|
44
|
|
|
$
|
(9
|
)
|
|
(20.5
|
)%
|
Advertising and Promotion
|
4
|
|
|
7
|
|
|
(3
|
)
|
|
(42.9
|
)%
|
|||
Consulting and Professional Services
|
14
|
|
|
17
|
|
|
(3
|
)
|
|
(17.6
|
)%
|
|||
Contributions
|
9
|
|
|
10
|
|
|
(1
|
)
|
|
(10.0
|
)%
|
|||
Miscellaneous
|
17
|
|
|
19
|
|
|
(2
|
)
|
|
(10.5
|
)%
|
|||
Total Company General and Administrative Expenses
|
$
|
79
|
|
|
$
|
97
|
|
|
$
|
(18
|
)
|
|
(18.6
|
)%
|
•
|
Employee wages and related expenses decreased
$9
million primarily attributable to lower salary OPEB expenses in the period-to-period comparison. The lower expenses relate to changes in the discount rates and other assumptions, and a modification of the salaried other post-employment benefit plan. See Note 16—Pension and Other Postretirement Benefit Plans and Note 17—Coal Workers' Pneumoconiosis (CWP) and Workers' Compensation in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details related to total Company expense increases
|
•
|
Advertising and promotion decreased $
3
million in the period-to-period comparison due to a reduction in CONSOL Energy's advertising and promotion campaign.
|
•
|
Consulting and professional services decreased
$3
million in the period-to-period comparison due to various legal proceedings and corporate initiatives, none of which were individually significant.
|
•
|
Contributions decreased $1 million in the period-to-period comparison due to various transactions, none of which were individually material.
|
•
|
Miscellaneous general and administrative expenses decreased
$2
million in the period-to-period comparison due to various transactions throughout both periods, none of which were individually material.
|
|
For the Year Ended
|
|
Difference to Year Ended
|
||||||||||||||||||||||||||||||||||||
|
December 31, 2012
|
|
December 31, 2011
|
||||||||||||||||||||||||||||||||||||
|
Marcellus
|
|
CBM
|
|
Shallow Oil and Gas
|
|
Other
Gas
|
|
Total
Gas
|
|
Marcellus
|
|
CBM
|
|
Shallow Oil and Gas
|
|
Other
Gas
|
|
Total
Gas
|
||||||||||||||||||||
Sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||
Produced
|
$
|
134
|
|
|
$
|
378
|
|
|
$
|
135
|
|
|
$
|
10
|
|
|
$
|
657
|
|
|
$
|
15
|
|
|
$
|
(83
|
)
|
|
$
|
(20
|
)
|
|
$
|
(2
|
)
|
|
$
|
(90
|
)
|
Related Party
|
—
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
(3
|
)
|
||||||||||
Total Outside Sales
|
134
|
|
|
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 Other Income
|
134
|
|
|
380
|
|
|
135
|
|
|
120
|
|
|
769
|
|
|
15
|
|
|
(86
|
)
|
|
(20
|
)
|
|
(22
|
)
|
|
(113
|
)
|
||||||||||
Lifting
|
12
|
|
|
37
|
|
|
40
|
|
|
2
|
|
|
91
|
|
|
(3
|
)
|
|
(3
|
)
|
|
(9
|
)
|
|
1
|
|
|
(14
|
)
|
||||||||||
Ad Valorem, Severance, and Other Taxes
|
4
|
|
|
10
|
|
|
10
|
|
|
2
|
|
|
26
|
|
|
3
|
|
|
(2
|
)
|
|
(2
|
)
|
|
1
|
|
|
—
|
|
||||||||||
Gathering
|
24
|
|
|
106
|
|
|
26
|
|
|
5
|
|
|
161
|
|
|
9
|
|
|
8
|
|
|
(1
|
)
|
|
3
|
|
|
19
|
|
||||||||||
Gas Direct Administrative, Selling & Other
|
17
|
|
|
14
|
|
|
13
|
|
|
3
|
|
|
47
|
|
|
6
|
|
|
(15
|
)
|
|
(8
|
)
|
|
3
|
|
|
(14
|
)
|
||||||||||
Depreciation, Depletion and Amortization
|
47
|
|
|
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 Other Costs
|
—
|
|
|
—
|
|
|
—
|
|
|
39
|
|
|
39
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
21
|
|
|
21
|
|
||||||||||
Other Corporate Expenses
|
—
|
|
|
—
|
|
|
—
|
|
|
77
|
|
|
77
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
12
|
|
|
12
|
|
||||||||||
Interest Expense
|
—
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|
5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(5
|
)
|
|
(5
|
)
|
||||||||||
Total Cost
|
104
|
|
|
254
|
|
|
148
|
|
|
224
|
|
|
730
|
|
|
27
|
|
|
(26
|
)
|
|
(22
|
)
|
|
3
|
|
|
(18
|
)
|
||||||||||
Earnings Before Noncontrolling Interest and Income Tax
|
30
|
|
|
126
|
|
|
(13
|
)
|
|
(104
|
)
|
|
39
|
|
|
(12
|
)
|
|
(60
|
)
|
|
2
|
|
|
(25
|
)
|
|
(95
|
)
|
||||||||||
Noncontrolling Interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
|
(4
|
)
|
||||||||||
Earnings (Loss) Before Income Tax
|
$
|
30
|
|
|
$
|
126
|
|
|
$
|
(13
|
)
|
|
$
|
(104
|
)
|
|
$
|
39
|
|
|
$
|
(12
|
)
|
|
$
|
(60
|
)
|
|
$
|
2
|
|
|
$
|
(21
|
)
|
|
$
|
(91
|
)
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2012
|
|
2011
|
|
Variance
|
|
Percent
Change
|
|||||||
Marcellus 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
|
)%
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2012
|
|
2011
|
|
Variance
|
|
Percent
Change
|
|||||||
CBM 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 (per Mcf)
|
$
|
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
|
)%
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2012
|
|
2011
|
|
Variance
|
|
Percent
Change
|
|||||||
Shallow 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 (per Mcfe)
|
$
|
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
|
%
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2012
|
|
2011
|
|
Variance
|
|
Percent
Change
|
|||||||
Purchased 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
|
)%
|
•
|
Gain on sale of assets decreased $30 million due to gains on the Hess transaction and Antero overriding royalty interest of $53 million and $41 million respectively, both of which occurred in 2011. Additionally, CONSOL Energy incurred a $64 million loss on the Noble transaction during 2011.
|
•
|
Interest income increased $20 million due to the notes receivable which were part of the Noble joint venture transaction.
|
•
|
Revenue from equity affiliates increased $5 million due to the formation of CONE, a 50% owned affiliate. CONE was formed in relation to the Noble joint venture transaction.
|
•
|
The remaining $3 million increase relates to various transactions that occurred throughout both periods, none of which were individually material.
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2012
|
|
2011
|
|
Variance
|
|
Percent
Change
|
|||||||
Purchased Gas Volumes (Bcf)
|
1.1
|
|
|
1.2
|
|
|
(0.1
|
)
|
|
(8.3
|
)%
|
|||
Average Sales Price (per Mcf)
|
$
|
2.44
|
|
|
$
|
3.07
|
|
|
$
|
(0.63
|
)
|
|
(20.5
|
)%
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2012
|
|
2011
|
|
Variance
|
|
Percent
Change
|
|||||||
Lease Expiration Costs
|
$
|
18
|
|
|
$
|
6
|
|
|
$
|
12
|
|
|
200.0
|
%
|
Marcellus Title Defects
|
4
|
|
|
—
|
|
|
$
|
4
|
|
|
100.0
|
%
|
||
Exploration Costs
|
14
|
|
|
7
|
|
|
7
|
|
|
100.0
|
%
|
|||
Dry Hole Costs
|
3
|
|
|
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 which had a carrying value to CONSOL Energy of $4 million for the year ended
December 31, 2012
.
|
•
|
Exploration expense increased $
7
million due to higher exploratory expenses associated with the Utica operating area and various other transactions that occurred throughout both periods, none of which were individually material.
|
•
|
Dry Hole Costs decreased $2 million due to various transactions that occurred throughout both periods, none of which were individually material.
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2012
|
|
2011
|
|
Variance
|
|
Percent
Change
|
|||||||
Legal Fees
|
$
|
5
|
|
|
$
|
—
|
|
|
$
|
5
|
|
|
100.0
|
%
|
PA Impact Fees
|
4
|
|
|
—
|
|
|
4
|
|
|
100.0
|
%
|
|||
Unused FT Commitments
|
16
|
|
|
14
|
|
|
2
|
|
|
14.3
|
%
|
|||
Short-term incentive compensation
|
26
|
|
|
25
|
|
|
1
|
|
|
4.0
|
%
|
|||
Stock-based compensation
|
18
|
|
|
18
|
|
|
—
|
|
|
—
|
%
|
|||
Bank fees
|
7
|
|
|
7
|
|
|
—
|
|
|
—
|
%
|
|||
Other
|
1
|
|
|
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 first quarter of 2012. This legislation permits Pennsylvania counties to impose annual fees on unconventional gas wells located within their borders. As part of the legislation, all unconventional wells which were drilled prior to January 1, 2012 were assessed an initial fee related to periods prior to 2012. The
$4
million represents the one-time initial assessment on wells drilled prior to January 1, 2012. Ongoing PA impact fees, which relate to current year wells drilled, are included as part of ad valorem, severance and other taxes in the Marcellus gas segment.
|
•
|
Unutilized firm transportation represents pipeline transportation capacity that the gas segment has obtained to enable gas production to flow uninterrupted as the gas operations continue to increase sales volumes.
|
•
|
The short-term incentive compensation program is designed to increase compensation to eligible employees when CNX Gas reaches predetermined targets for safety, production and unit costs. Short-term incentive compensation increased in the period-to-period comparison as the result of exceeding the targets in the 2012 period and an increased allocation of expense from CONSOL Energy as a result of exceeding corporate targets.
|
•
|
Stock-based compensation remained consistent in the period-to-period comparison. Stock-based compensation costs are allocated to the gas segment based on revenue and capital expenditure projections between coal and gas.
|
•
|
Bank fees remained consistent in the period-to-period comparison.
|
•
|
Other corporate related expense remained consistent in the period-to-period comparison.
|
|
For the Year Ended
|
|
Difference to Year Ended
|
||||||||||||||||||||||||||||||||||||
|
December 31, 2012
|
|
December 31, 2011
|
||||||||||||||||||||||||||||||||||||
|
Thermal Coal
|
|
High
Vol
Met
Coal
|
|
Low
Vol
Met
Coal
|
|
Other
Coal
|
|
Total
Coal
|
|
Thermal
Coal
|
|
High
Vol
Met
Coal
|
|
Low
Vol
Met
Coal
|
|
Other
Coal
|
|
Total
Coal
|
||||||||||||||||||||
Sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||
Produced Coal
|
$
|
1,431
|
|
|
$
|
210
|
|
|
$
|
506
|
|
|
$
|
5
|
|
|
$
|
2,152
|
|
|
$
|
(65
|
)
|
|
$
|
(114
|
)
|
|
$
|
(566
|
)
|
|
$
|
(22
|
)
|
|
$
|
(767
|
)
|
Purchased Coal
|
—
|
|
|
—
|
|
|
—
|
|
|
17
|
|
|
17
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(23
|
)
|
|
(23
|
)
|
||||||||||
Total Outside Sales
|
1,431
|
|
|
210
|
|
|
506
|
|
|
22
|
|
|
2,169
|
|
|
(65
|
)
|
|
(114
|
)
|
|
(566
|
)
|
|
(45
|
)
|
|
(790
|
)
|
||||||||||
Freight Revenue
|
—
|
|
|
—
|
|
|
—
|
|
|
107
|
|
|
107
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(69
|
)
|
|
(69
|
)
|
||||||||||
Other Income
|
2
|
|
|
6
|
|
|
—
|
|
|
324
|
|
|
332
|
|
|
(4
|
)
|
|
(5
|
)
|
|
—
|
|
|
269
|
|
|
260
|
|
||||||||||
Total Revenue and Other Income
|
1,433
|
|
|
216
|
|
|
506
|
|
|
453
|
|
|
2,608
|
|
|
(69
|
)
|
|
(119
|
)
|
|
(566
|
)
|
|
155
|
|
|
(599
|
)
|
||||||||||
Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||
Beginning inventory costs
|
67
|
|
|
2
|
|
|
16
|
|
|
—
|
|
|
85
|
|
|
(17
|
)
|
|
2
|
|
|
6
|
|
|
—
|
|
|
(9
|
)
|
||||||||||
Total direct costs
|
593
|
|
|
95
|
|
|
184
|
|
|
145
|
|
|
1,017
|
|
|
37
|
|
|
(14
|
)
|
|
(14
|
)
|
|
16
|
|
|
25
|
|
||||||||||
Total royalty/production taxes
|
74
|
|
|
9
|
|
|
30
|
|
|
3
|
|
|
116
|
|
|
(10
|
)
|
|
(3
|
)
|
|
(37
|
)
|
|
(5
|
)
|
|
(55
|
)
|
||||||||||
Total direct services to operations
|
154
|
|
|
21
|
|
|
22
|
|
|
217
|
|
|
414
|
|
|
(71
|
)
|
|
(21
|
)
|
|
(24
|
)
|
|
57
|
|
|
(59
|
)
|
||||||||||
Total retirement and disability
|
61
|
|
|
10
|
|
|
28
|
|
|
20
|
|
|
119
|
|
|
(11
|
)
|
|
(6
|
)
|
|
(10
|
)
|
|
6
|
|
|
(21
|
)
|
||||||||||
Depreciation, depletion and amortization
|
120
|
|
|
22
|
|
|
37
|
|
|
33
|
|
|
212
|
|
|
(7
|
)
|
|
(5
|
)
|
|
—
|
|
|
12
|
|
|
—
|
|
||||||||||
Ending inventory costs
|
(33
|
)
|
|
—
|
|
|
(21
|
)
|
|
—
|
|
|
(54
|
)
|
|
35
|
|
|
—
|
|
|
(5
|
)
|
|
—
|
|
|
30
|
|
||||||||||
Total Costs and Expenses
|
1,036
|
|
|
159
|
|
|
296
|
|
|
418
|
|
|
1,909
|
|
|
(44
|
)
|
|
(47
|
)
|
|
(84
|
)
|
|
86
|
|
|
(89
|
)
|
||||||||||
Freight Expense
|
—
|
|
|
—
|
|
|
—
|
|
|
107
|
|
|
107
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(69
|
)
|
|
(69
|
)
|
||||||||||
Total Costs
|
1,036
|
|
|
159
|
|
|
296
|
|
|
525
|
|
|
2,016
|
|
|
(44
|
)
|
|
(47
|
)
|
|
(84
|
)
|
|
17
|
|
|
(158
|
)
|
||||||||||
Earnings (Loss) Before Income Taxes
|
$
|
397
|
|
|
$
|
57
|
|
|
$
|
210
|
|
|
$
|
(72
|
)
|
|
$
|
592
|
|
|
$
|
(25
|
)
|
|
$
|
(72
|
)
|
|
$
|
(482
|
)
|
|
$
|
138
|
|
|
$
|
(441
|
)
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2012
|
|
2011
|
|
Variance
|
|
Percent
Change
|
|||||||
Company 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 Produced
|
3.65
|
|
|
3.82
|
|
|
(0.17
|
)
|
|
(4.5
|
%)
|
|||
Total Direct Services to Operations Per Thermal Ton Produced
|
7.61
|
|
|
10.25
|
|
|
(2.64
|
)
|
|
(25.8
|
%)
|
|||
Total Retirement and Disability Per Thermal Ton Produced
|
3.01
|
|
|
3.28
|
|
|
(0.27
|
)
|
|
(8.2
|
%)
|
|||
Total Depreciation, Depletion and Amortization Costs Per Thermal Ton Produced
|
5.93
|
|
|
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
|
%
|
•
|
Average operating costs per thermal ton produced increased due to fewer tons produced. Thermal mines produced 20.3 million tons in 2012 compared to 21.9 million tons in 2011. Fixed costs are allocated over less tons, resulting in higher unit costs.
|
•
|
Average operating supplies and maintenance costs per ton increased due to additional maintenance and equipment overhaul costs and additional contractor labor, combined with lower tons produced. Additional maintenance and equipment overhaul costs are related to additional equipment being serviced in the current year. Additional contractor
|
•
|
The Fola Mining Complex was idled in August 2012 which resulted in lower direct operating costs per ton produced in the period-to-period comparison. The mine, which was idled for market reasons, was a higher cost mining operation which when removed reduced the overall average direct operating costs per ton produced.
|
•
|
There were no significant changes in various other unit costs individually or in total.
|
•
|
Average direct service costs to operations were impaired due to lower tons produced in the year-to-year comparison.
|
•
|
Permitting and compliance costs have increased due to increased stream monitoring expenses, increased compliance work related to ponds and ditches, and additional permits for water discharge pipelines.
|
•
|
Selling expense decreased in the year-to-year comparison due to fewer tons being sold under contracts that require commissions.
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2012
|
|
2011
|
|
Variance
|
|
Percent
Change
|
|||||||
Company 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 Produced
|
2.72
|
|
|
2.86
|
|
|
(0.14
|
)
|
|
(4.9
|
%)
|
|||
Total Direct Services to Operations Per High Vol Met Ton Produced
|
6.22
|
|
|
10.23
|
|
|
(4.01
|
)
|
|
(39.2
|
%)
|
|||
Total Retirement and Disability Per High Vol Met Ton Produced
|
3.10
|
|
|
3.87
|
|
|
(0.77
|
)
|
|
(19.9
|
%)
|
|||
Total Depreciation, Depletion and Amortization Costs Per High Vol Met Ton Produced
|
6.63
|
|
|
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
|
%)
|
•
|
Labor and related benefits average costs per high volatile metallurgical ton produced decreased due to less overtime worked, offset, in part, by lower tons produced and higher hourly wage rates.
|
•
|
Mine maintenance and supplies per ton produced decreased due to the mix of mines producing tons that were shipped as high volatile metallurgical coal. Mines with lower cost structures produced a larger portion of the high volatile metallurgical coal shipped in the current year compared to the prior year.
|
•
|
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.
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2012
|
|
2011
|
|
Variance
|
|
Percent
Change
|
|||||||
Company 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 Produced
|
8.33
|
|
|
11.74
|
|
|
(3.41
|
)
|
|
(29.0
|
%)
|
|||
Total Direct Services to Operations Per Low Vol Met Ton Produced
|
6.03
|
|
|
8.15
|
|
|
(2.12
|
)
|
|
(26.0
|
%)
|
|||
Total Retirement and Disability Per Low Vol Met Ton Produced
|
7.63
|
|
|
6.71
|
|
|
0.92
|
|
|
13.7
|
%
|
|||
Total Depreciation, Depletion and Amortization Costs Per Low Vol Met Ton Produced
|
10.23
|
|
|
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
|
%)
|
•
|
The Buchanan longwall was idled during the months of March, April and October of 2012 which resulted in higher direct operating costs produced. The mine continued to run the continuous miners and perform mine maintenance during the months when the longwall was idled. This negatively impacted unit costs.
|
•
|
Low volatile metallurgical coal production was 3.7 million tons for the year ended December 31, 2012 compared to 5.7 million tons for the year ended December 31, 2011. Production was significantly lower in the year-to-year comparison due to the Buchanan Mine being idled for portions of 2012. The mine was idled in response to weak market demand for low volatile metallurgical coal. Late in 2012, a five day work week instead of the normal seven
|
•
|
Gain on sale of assets attributable to the Other Coal segment were $271 million for the year ended December 31, 2012 compared to $5 million for the year ended December 31, 2011. The change was primarily related to sales of non-producing assets in the Northern Powder River Basin that resulted in income of $151 million, as well as coal and surface lands in Western Canada, Illinois and West Virginia that resulted in income of $112 million. See Note 3—
|
•
|
For the year ended December 31, 2012, $12 million of income was recognized related to contracts from certain thermal coal customers that were unable to take delivery of previously contracted coal tonnage. These customers agreed to buy out their contracts in order to be released from the requirements of taking delivery of previously committed tons. No such transactions were entered into in the year ended December 31, 2011.
|
•
|
Gain on issuances of pipeline right-of-ways to third parties decreased $8 million in the year-to-year comparison, primarily due to a $10 million pipeline right-of-way to a third party issued in the year ended December 31, 2011.
|
•
|
The remaining $1 million decrease in a year-to-year comparison is due to several transactions, none of which are individually material.
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2012
|
|
2011
|
|
Variance
|
||||||
Closed and idle mines
|
|
$
|
134
|
|
|
$
|
73
|
|
|
$
|
61
|
|
Bailey Belt Incident
|
|
42
|
|
|
—
|
|
|
42
|
|
|||
Voluntary Incentive Separation Program
|
|
13
|
|
|
—
|
|
|
13
|
|
|||
Litigation Contingencies
|
|
17
|
|
|
12
|
|
|
5
|
|
|||
General 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 Fola Complex for the year ended December 31, 2012. Closed and idle mine costs increased $20 million as the result of a 2012 decision to temporarily idle Buchanan Mine in 2012. Closed and idle mine costs increased $11 million due to other changes in the operational status of various other mines, between idled and operating throughout both periods, none of which were individually material.
|
•
|
Bailey Belt incident costs represents expenses related to continued advancement of the mines and on-going projects at the mines that took place during the idled phase when belt reconstruction was occurring.
|
•
|
In November 2012, CONSOL Energy offered a voluntary severance incentive program (VSIP) to active salaried corporate and operation support employees with 30 years of service, or more. Under this program, eligible employees who accepted the offer will receive a severance payment equal to one year's salary and the 2013 accrued vacation earned as of December 31, 2012. Approximately 100 employees volunteered for the program. Severance and vacation pay was approximately $13 million and was recognized for the year ended December 31, 2012. This was paid in January 2013.
|
•
|
Litigation contingencies increased $
5
million in the year-to-year comparison due to various items. See Note 24-Commitments and Contingent Liabilities in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details related to total Company expense.
|
•
|
General and Administrative Expense related to the other coal segment decreased by $
21
million primarily due to a reduction of wages and related expenses.
|
•
|
Purchased coal costs decreased approximately $
22
million in the year-to-year comparison primarily due to differences in the quality of coal purchased, decreases in the market price of coal purchased, and an increase in the volumes of coal purchased in the period-to-period comparison.
|
•
|
Freight expense is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. rail, barge, truck, etc.) used by the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is the amount billed to customers for transportation costs incurred. Freight expense is almost completely offset in freight revenue. The $
68
million decrease in freight revenue was due to decreased shipments which CONSOL Energy contractually provides transportation services.
|
•
|
Other costs related to the coal segment increased $
7
million due to various other transactions that occurred throughout both periods, none of which are individually material.
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2012
|
|
2011
|
|
Variance
|
|
Percent
Change
|
|||||||
Sales—Outside
|
$
|
294
|
|
|
$
|
285
|
|
|
$
|
9
|
|
|
3.2
|
%
|
Other Income
|
6
|
|
|
8
|
|
|
(2
|
)
|
|
(25.0
|
)%
|
|||
Total Revenue
|
300
|
|
|
293
|
|
|
7
|
|
|
2.4
|
%
|
|||
Cost of Goods Sold and Other Charges
|
289
|
|
|
320
|
|
|
(31
|
)
|
|
(9.7
|
)%
|
|||
Depreciation, Depletion & Amortization
|
15
|
|
|
12
|
|
|
3
|
|
|
25.0
|
%
|
|||
Taxes Other Than Income Tax
|
5
|
|
|
11
|
|
|
(6
|
)
|
|
(54.5
|
)%
|
|||
Interest Expense
|
215
|
|
|
239
|
|
|
(24
|
)
|
|
(10.0
|
)%
|
|||
Total Costs
|
524
|
|
|
582
|
|
|
(58
|
)
|
|
(10.0
|
)%
|
|||
Loss Before Income Tax
|
(224
|
)
|
|
(289
|
)
|
|
65
|
|
|
22.5
|
%
|
|||
Income Tax
|
89
|
|
|
191
|
|
|
(102
|
)
|
|
(53.4
|
)%
|
|||
Net Loss
|
$
|
(313
|
)
|
|
$
|
(480
|
)
|
|
$
|
167
|
|
|
34.8
|
%
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2012
|
|
2011
|
|
Variance
|
||||||
Interest 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 related to higher capital expenditures for major construction projects in the current period. Capital expenditures for coal activities increased $310 million in the period-to-period comparison.
|
•
|
On April 11, 2011, CONSOL Energy redeemed all of its outstanding $250 million, 7.875% senior secured notes due March 1, 2012 in accordance with the terms of the indenture governing these notes.
|
•
|
The loss on extinguishment of debt was $16 million, which primarily represented the interest that would have been paid on these notes if held to maturity.
|
•
|
Transaction and financing fees of $
15
million incurred in the year ended December 31, 2011 related to the solicitation of consents of the long-term bonds needed in order to clarify the indentures that relate to joint arrangements with respect to its oil and gas properties.
|
•
|
Bank fees decreased $
5
million mainly due to lower borrowings on the revolving credit facilities in the period-to-period comparison and also due to the refinancing and extension of the credit facility on April 12, 2011.
|
•
|
Evaluation fees for non-core asset dispositions and other legal charges decreased $
2
million in the period-to-period comparison due to various corporate initiatives.
|
•
|
Various other corporate expenses decreased $
7
million due to various transactions that occurred throughout both periods, none of which were individually material.
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2012
|
|
2011
|
|
Variance
|
|
Percent
Change
|
|||||||
Total Company Earnings Before Income Tax
|
$
|
407
|
|
|
$
|
873
|
|
|
$
|
(466
|
)
|
|
(53.4
|
)%
|
Income Tax Expense
|
$
|
89
|
|
|
$
|
191
|
|
|
$
|
(102
|
)
|
|
(53.3
|
)%
|
Effective Income Tax Rate
|
21.8
|
%
|
|
21.9
|
%
|
|
(0.1
|
)%
|
|
|
•
|
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.
|
•
|
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.
|
|
For the Years Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
Change
|
||||||
Cash flows from operating activities
|
$
|
659
|
|
|
$
|
728
|
|
|
$
|
(69
|
)
|
Cash used in investing activities
|
$
|
(202
|
)
|
|
$
|
(1,000
|
)
|
|
$
|
798
|
|
Cash used in financing activities
|
$
|
(151
|
)
|
|
$
|
(82
|
)
|
|
$
|
(69
|
)
|
•
|
Net income increased $271 million in the period-to-period comparison;
|
•
|
Discontinued operations changes decreased $675 million primarily as a result of the gain on sale of CCC and certain subsidiaries to Murray Energy Corporation in December 2013;
|
•
|
Operating cash flows increased $214 million in the period-to-period comparison due to changes in the gain on the sale of assets. See Note 3 - Acquisitions and Dispositions in the Notes to Audited Financial Statements in Item 8 of this Form 10-K for more information; and
|
•
|
Other changes in operating assets, operating liabilities, other assets and other liabilities which occurred throughout both periods also contributed to the increase in operating cash flows.
|
•
|
Capital expenditures increased $251 million due to:
|
•
|
Gas segment capital expenditures increased $441 million. The increase was comprised of increased drilling costs in the Marcellus and Utica plays, CONSOL Energy's agreement to lease oil and gas rights from the Allegheny County Airport Authority, land acquisitions in Monroe and Noble Counties in Ohio, additional gas drilling rights acquired from Dominion Transmission in West Virginia and various other individually insignificant projects;
|
•
|
Coal segment capital expenditures decreased $196 million. The decrease was comprised of a $27 million decrease in Bailey Mine Expansion projects. Longwall shield projects decreased $71 million as well as an additional $98 million decrease in various miscellaneous transactions that occurred throughout both periods, none of which were individually material; and
|
•
|
Other capital expenditures increased $6 million due to various miscellaneous transactions that occurred throughout both periods, none of which were individually material.
|
•
|
Proceeds from sale of assets decreased $161 million due to various items that occurred throughout both periods. See Note 3 - Acquisitions and Dispositions, in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information.
|
•
|
Discontinued operations changes increased $1,106 million primarily as a result of the gain on the sale of CCC and certain subsidiaries to Murray Energy Corporation in December 2013.
|
•
|
Distributions from/investments in equity affiliates decreased $12 million due to various miscellaneous transactions that occurred throughout both periods, none of which were individually material.
|
•
|
Restricted cash increased $116 million due to the release of $69 million of restricted cash of which $48 million is associated with the Ram River & Scurry Canadian asset proceeds received during December 2012 and $21 million is associated with the Ryerson Dam Settlement. See Note 3 - Acquisitions and Dispositions, in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for more information.
|
•
|
In 2013, CONSOL Energy repaid $32 million of borrowings related to miscellaneous borrowings. In 2012, CONSOL Energy received $16 million of borrowings.
|
•
|
The accelerated declaration and payment of the regular quarterly dividend in the fourth quarter of 2012 resulted in no dividends paid in the first quarter of 2013. Total dividends paid in the year ended December 31, 2013 were $86 million as compared to $142 million in dividends paid in the period ended December 31, 2012.
|
•
|
In 2013, CONSOL Energy repaid $38 million of borrowings under its Securitization Facility. In 2012, CONSOL Energy had proceeds of $38 million from the Securitization Facility.
|
•
|
The remaining change is due to various other transactions that occurred throughout both periods, none of which were individually material.
|
|
Payments due by Year
|
||||||||||||||||||
|
Less Than
1 Year
|
|
1-3 Years
|
|
3-5 Years
|
|
More Than
5 Years
|
|
Total
|
||||||||||
Purchase Order Firm Commitments
|
167,658
|
|
|
125,505
|
|
|
61,768
|
|
|
14,637
|
|
|
369,568
|
|
|||||
Gas Firm Transportation
|
73,212
|
|
|
134,713
|
|
|
137,376
|
|
|
568,696
|
|
|
913,997
|
|
|||||
Long-Term Debt
|
3,489
|
|
|
6,553
|
|
|
1,503,562
|
|
|
1,605,316
|
|
|
3,118,920
|
|
|||||
Interest on Long-Term Debt
|
245,385
|
|
|
490,600
|
|
|
310,280
|
|
|
240,117
|
|
|
1,286,382
|
|
|||||
Capital (Finance) Lease Obligations
|
8,498
|
|
|
15,334
|
|
|
13,096
|
|
|
19,166
|
|
|
56,094
|
|
|||||
Interest on Capital (Finance) Lease Obligations
|
3,557
|
|
|
5,493
|
|
|
3,790
|
|
|
2,110
|
|
|
14,950
|
|
|||||
Operating Lease Obligations
|
102,454
|
|
|
177,781
|
|
|
119,230
|
|
|
95,669
|
|
|
495,134
|
|
|||||
Long-Term Liabilities—Employee Related (a)
|
87,751
|
|
|
181,311
|
|
|
188,171
|
|
|
791,444
|
|
|
1,248,677
|
|
|||||
Other Long-Term Liabilities (b)
|
298,584
|
|
|
211,363
|
|
|
97,815
|
|
|
318,321
|
|
|
926,083
|
|
|||||
Total 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 retirement contributions required to meet minimum funding standards under ERISA are excluded from the pay-out table due to the uncertainty regarding amounts to be contributed. Estimated 2014 contributions are expected to approximate
$
25
million to
$35
million.
|
(b)
|
Other long-term liabilities include mine reclamation and closure and other long-term liability costs.
|
(c)
|
The significant obligation table does not include obligations to taxing authorities due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations.
|
•
|
An aggregate principal amount of $
1.50
billion
of
8.00%
senior unsecured notes due in April 2017. Interest on the notes is payable April 1 and October 1 of each year. Payment of the principal and interest on the notes are guaranteed by most of CONSOL Energy’s subsidiaries.
|
•
|
An aggregate principal amount of $
1.25
billion
of
8.25%
senior unsecured notes due in April 2020. Interest on the notes is payable April 1 and October 1 of each year. Payment of the principal and interest on the notes are guaranteed by most of CONSOL Energy’s subsidiaries.
|
•
|
An aggregate principal amount of $
250
million
of
6.375%
notes due in March 2021. Interest on the notes is payable March 1 and September 1 of each year. Payment of the principal and interest on the notes are guaranteed by most of CONSOL Energy's subsidiaries.
|
•
|
An aggregate principal amount of $
103
million
of industrial revenue bonds which were issued to finance the Baltimore port facility and bear interest at
5.75%
per annum and mature in September 2025. Interest on the industrial revenue bonds is payable March 1 and September 1 of each year. Payment of the principal and interest on the notes are guaranteed by CONSOL Energy.
|
•
|
Advance royalty commitments of $
11
million
with an average interest rate of
7.93%
per annum.
|
•
|
An aggregate principal amount of $
5
million
on other various rate notes maturing through June 2031.
|
•
|
An aggregate principal amount of $
56
million
of capital leases with a weighted average interest rate of
6.19%
per annum.
|
Declaration Date
|
|
Amount Per Share
|
|
Record Date
|
|
Payment Date
|
February 3, 2014
|
|
$0.0625
|
|
February 14, 2014
|
|
February 28, 2014
|
November 1, 2013
|
|
$0.125
|
|
November 15, 2013
|
|
December 4, 2013
|
July 26, 2013
|
|
$0.125
|
|
August 9, 2013
|
|
August 23, 2013
|
April 26, 2013
|
|
$0.125
|
|
May 10, 2013
|
|
May 24, 2013
|
ITEM 7A.
|
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
|
|
For the Three Months Ended
|
|
|
||||||||||||||||
|
March 31,
|
|
June 30,
|
|
September 30,
|
|
December 31,
|
|
Total Year
|
||||||||||
2014 Fixed Price Volumes
|
|
|
|
|
|
|
|
|
|
||||||||||
Hedged Bcf
|
31.9
|
|
|
32.2
|
|
|
32.6
|
|
|
32.6
|
|
|
129.3
|
|
|||||
Weighted Average Hedge Price/Mcf
|
$
|
4.61
|
|
|
$
|
4.61
|
|
|
$
|
4.61
|
|
|
$
|
4.61
|
|
|
$
|
4.61
|
|
2015 Fixed Price Volumes
|
|
|
|
|
|
|
|
|
|
||||||||||
Hedged Bcf
|
19.4
|
|
|
19.6
|
|
|
19.8
|
|
|
19.8
|
|
|
78.6
|
|
|||||
Weighted Average Hedge Price/Mcf
|
$
|
4.10
|
|
|
$
|
4.10
|
|
|
$
|
4.10
|
|
|
$
|
4.10
|
|
|
$
|
4.10
|
|
2016 Fixed Price Volumes
|
|
|
|
|
|
|
|
|
|
||||||||||
Hedged Bcf
|
17.7
|
|
|
17.8
|
|
|
17.9
|
|
|
17.9
|
|
|
71.3
|
|
|||||
Weighted Average Hedge Price/Mcf
|
$
|
4.20
|
|
|
$
|
4.20
|
|
|
$
|
4.20
|
|
|
$
|
4.20
|
|
|
$
|
4.20
|
|
ITEM 8.
|
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
|
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
|
||
|
|
Page
|
Report of Independent Registered Public Accounting Firm
|
||
Consolidated Statements of Income for the Years Ended December 31, 2013, 2012 and 2011
|
||
Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2013, 2012 and 2011
|
||
Consolidated Statements of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011
|
||
Notes to the Audited Consolidated Financial Statements
|
|
For the Years Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Sales—Outside
|
$
|
3,015,551
|
|
|
$
|
3,122,550
|
|
|
$
|
3,991,007
|
|
Sales—Gas Royalty Interests
|
63,202
|
|
|
49,405
|
|
|
66,929
|
|
|||
Sales—Purchased Gas
|
6,531
|
|
|
3,316
|
|
|
4,344
|
|
|||
Freight—Outside
|
35,438
|
|
|
107,079
|
|
|
175,633
|
|
|||
Other Income (Note 4)
|
178,963
|
|
|
395,176
|
|
|
139,132
|
|
|||
Total Revenue and Other Income
|
3,299,685
|
|
|
3,677,526
|
|
|
4,377,045
|
|
|||
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)
|
2,228,952
|
|
|
2,221,859
|
|
|
2,266,560
|
|
|||
Gas Royalty Interests Costs
|
53,028
|
|
|
38,867
|
|
|
59,331
|
|
|||
Purchased Gas Costs
|
4,837
|
|
|
2,711
|
|
|
3,831
|
|
|||
Freight Expense
|
35,438
|
|
|
107,079
|
|
|
175,444
|
|
|||
Selling, General and Administrative Expenses
|
90,408
|
|
|
90,740
|
|
|
114,643
|
|
|||
Depreciation, Depletion and Amortization
|
461,122
|
|
|
427,115
|
|
|
430,577
|
|
|||
Interest Expense (Note 5)
|
219,198
|
|
|
220,042
|
|
|
248,344
|
|
|||
Taxes Other Than Income (Note 6)
|
160,627
|
|
|
162,426
|
|
|
174,392
|
|
|||
Loss on Debt Extinguishment (Note 14)
|
—
|
|
|
—
|
|
|
16,090
|
|
|||
Transaction and Financing Fees (Note 14)
|
—
|
|
|
—
|
|
|
14,907
|
|
|||
Total Costs
|
3,253,610
|
|
|
3,270,839
|
|
|
3,504,119
|
|
|||
Earnings Before Income Taxes
|
46,075
|
|
|
406,687
|
|
|
872,926
|
|
|||
Income Taxes (Note 7)
|
(33,189
|
)
|
|
88,728
|
|
|
191,251
|
|
|||
Income from Continuing Operations
|
79,264
|
|
|
317,959
|
|
|
681,675
|
|
|||
Income (Loss) from Discontinued Operations, net of tax (Note 2)
|
579,792
|
|
|
70,114
|
|
|
(49,178
|
)
|
|||
Net Income
|
659,056
|
|
|
388,073
|
|
|
632,497
|
|
|||
Less: Net Loss Attributable to Noncontrolling Interest
|
1,386
|
|
|
397
|
|
|
—
|
|
|||
Net Income Attributable to CONSOL Energy Inc. Shareholders
|
$
|
660,442
|
|
|
$
|
388,470
|
|
|
$
|
632,497
|
|
Earnings Per Share (Note 1):
|
|
|
|
|
|
||||||
Basic:
|
|
|
|
|
|
||||||
Income from Continuing Operations
|
$
|
0.35
|
|
|
$
|
1.40
|
|
|
$
|
3.01
|
|
Income (Loss) from Discontinued Operations
|
2.54
|
|
|
0.31
|
|
|
(0.22
|
)
|
|||
Net Income
|
$
|
2.89
|
|
|
$
|
1.71
|
|
|
$
|
2.79
|
|
Dilutive:
|
|
|
|
|
|
||||||
Income from Continuing Operations
|
$
|
0.35
|
|
|
$
|
1.39
|
|
|
$
|
2.98
|
|
Income (Loss) from Discontinued Operations
|
2.52
|
|
|
0.31
|
|
|
(0.22
|
)
|
|||
Net Income
|
$
|
2.87
|
|
|
$
|
1.70
|
|
|
$
|
2.76
|
|
Weighted Average Number of Common Shares Outstanding (Note 1):
|
|
|
|
|
|
||||||
Basic
|
228,728,628
|
|
|
227,593,524
|
|
|
226,680,369
|
|
|||
Dilutive
|
230,077,942
|
|
|
229,141,767
|
|
|
229,003,599
|
|
|||
Dividends Paid Per Share
|
$
|
0.375
|
|
|
$
|
0.625
|
|
|
$
|
0.425
|
|
|
|
|
|
|
|
||||||
|
For the Years Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Net Income
|
$
|
659,056
|
|
|
$
|
388,073
|
|
|
$
|
632,497
|
|
Other Comprehensive Income:
|
|
|
|
|
|
||||||
Treasury Rate Lock (Net of tax: $-, $-, $59)
|
—
|
|
|
—
|
|
|
(96
|
)
|
|||
Actuarially Determined Long-Term Liability Adjustments (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 of tax: ($29,407), ($73,593), ($129,235))
|
45,631
|
|
|
114,240
|
|
|
200,700
|
|
|||
Reclassification of Cash Flow Hedges from Other Comprehensive Income to Earnings (Net of tax: $53,990, $121,484, $60,925)
|
(79,899
|
)
|
|
(189,259
|
)
|
|
(95,007
|
)
|
|||
|
|
|
|
|
|
||||||
Other Comprehensive Income
|
422,225
|
|
|
54,212
|
|
|
72,784
|
|
|||
|
|
|
|
|
|
||||||
Comprehensive Income
|
1,081,281
|
|
|
442,285
|
|
|
705,281
|
|
|||
|
|
|
|
|
|
||||||
Less: Comprehensive Loss Attributable to Noncontrolling Interest
|
1,386
|
|
|
397
|
|
|
—
|
|
|||
|
|
|
|
|
|
||||||
Comprehensive Income Attributable to CONSOL Energy Inc. Shareholders
|
$
|
1,082,667
|
|
|
$
|
442,682
|
|
|
$
|
705,281
|
|
|
|
|
|
||||
|
December 31,
2013 |
|
December 31,
2012 |
||||
ASSETS
|
|
|
|
||||
Current Assets:
|
|
|
|
||||
Cash and Cash Equivalents
|
$
|
327,420
|
|
|
$
|
21,862
|
|
Accounts and Notes Receivable:
|
|
|
|
||||
Trade
|
332,574
|
|
|
428,328
|
|
||
Notes Receivable
|
25,861
|
|
|
318,387
|
|
||
Other Receivables
|
243,973
|
|
|
131,131
|
|
||
Accounts Receivable—Securitized (Note 10)
|
—
|
|
|
37,846
|
|
||
Inventories (Note 9)
|
157,914
|
|
|
170,808
|
|
||
Deferred Income Taxes (Note 7)
|
211,303
|
|
|
84,777
|
|
||
Recoverable Income Taxes
|
10,705
|
|
|
—
|
|
||
Restricted Cash (Note 1)
|
—
|
|
|
48,294
|
|
||
Prepaid Expenses
|
135,842
|
|
|
148,431
|
|
||
Current Assets of Discontinued Operations (Note 2)
|
—
|
|
|
149,230
|
|
||
Total Current Assets
|
1,445,592
|
|
|
1,539,094
|
|
||
Property, Plant and Equipment (Note 11):
|
|
|
|
||||
Property, Plant and Equipment
|
13,578,509
|
|
|
12,121,557
|
|
||
Less—Accumulated Depreciation, Depletion and Amortization
|
4,136,247
|
|
|
3,613,499
|
|
||
Property, Plant and Equipment of Discontinued Operations, Net (Note 2)
|
—
|
|
|
1,682,909
|
|
||
Total Property, Plant and Equipment—Net
|
9,442,262
|
|
|
10,190,967
|
|
||
Other Assets:
|
|
|
|
||||
Restricted Cash (Note 1)
|
—
|
|
|
20,379
|
|
||
Investment in Affiliates
|
291,675
|
|
|
222,830
|
|
||
Notes Receivable
|
125
|
|
|
25,977
|
|
||
Other
|
214,013
|
|
|
216,235
|
|
||
Other Assets of Discontinued Operations (Note 2)
|
—
|
|
|
782,112
|
|
||
Total Other Assets
|
505,813
|
|
|
1,267,533
|
|
||
|
|
|
|
||||
TOTAL ASSETS
|
$
|
11,393,667
|
|
|
$
|
12,997,594
|
|
|
December 31,
2013 |
|
December 31,
2012 |
||||
LIABILITIES AND EQUITY
|
|
|
|
||||
Current Liabilities:
|
|
|
|
||||
Accounts Payable
|
$
|
514,580
|
|
|
$
|
498,515
|
|
Current Portion of Long-Term Debt (Note 14 and Note 15)
|
11,455
|
|
|
12,484
|
|
||
Short-Term Notes Payable (Note 12)
|
—
|
|
|
25,073
|
|
||
Accrued Income Taxes
|
—
|
|
|
34,219
|
|
||
Borrowings Under Securitization Facility (Note 10)
|
—
|
|
|
37,846
|
|
||
Other Accrued Liabilities (Note 13)
|
565,697
|
|
|
545,748
|
|
||
Current Liabilities of Discontinued Operations (Note 2)
|
28,239
|
|
|
233,214
|
|
||
Total Current Liabilities
|
1,119,971
|
|
|
1,387,099
|
|
||
Long-Term Debt:
|
|
|
|
||||
Long-Term Debt (Note 14)
|
3,115,963
|
|
|
3,123,600
|
|
||
Capital Lease Obligations (Note 15)
|
47,596
|
|
|
49,413
|
|
||
Long-Term Debt of Discontinued Operations (Note 2)
|
—
|
|
|
1,573
|
|
||
Total Long-Term Debt
|
3,163,559
|
|
|
3,174,586
|
|
||
Deferred Credits and Other Liabilities:
|
|
|
|
||||
Deferred Income Taxes (Note 7)
|
242,643
|
|
|
326,685
|
|
||
Postretirement Benefits Other Than Pensions (Note 16)
|
961,127
|
|
|
882,600
|
|
||
Pneumoconiosis Benefits (Note 17)
|
111,971
|
|
|
114,136
|
|
||
Mine Closing (Note 8)
|
320,723
|
|
|
289,818
|
|
||
Gas Well Closing (Note 8)
|
175,603
|
|
|
146,002
|
|
||
Workers’ Compensation (Note 17)
|
71,468
|
|
|
60,396
|
|
||
Salary Retirement (Note 16)
|
48,252
|
|
|
218,004
|
|
||
Reclamation (Note 8)
|
40,706
|
|
|
47,965
|
|
||
Other
|
131,355
|
|
|
118,307
|
|
||
Deferred Credits and Other Liabilities of Discontinued Operations (Note 2)
|
—
|
|
|
2,278,251
|
|
||
Total Deferred Credits and Other Liabilities
|
2,103,848
|
|
|
4,482,164
|
|
||
TOTAL LIABILITIES
|
6,387,378
|
|
|
9,043,849
|
|
||
Stockholders’ Equity:
|
|
|
|
||||
Common Stock, $.01 Par Value; 500,000,000 Shares Authorized, 229,145,736 Issued and Outstanding at December 31, 2013; 228,129,467 Issued and 228,094,712 Outstanding at December 31, 2012
|
2,294
|
|
|
2,284
|
|
||
Capital in Excess of Par Value
|
2,364,592
|
|
|
2,296,908
|
|
||
Preferred Stock, 15,000,000 Shares Authorized, None Issued and Outstanding
|
—
|
|
|
—
|
|
||
Retained Earnings
|
2,964,520
|
|
|
2,402,551
|
|
||
Accumulated 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’ Equity
|
5,006,289
|
|
|
3,953,792
|
|
||
Noncontrolling Interest
|
—
|
|
|
(47
|
)
|
||
TOTAL EQUITY
|
5,006,289
|
|
|
3,953,745
|
|
||
|
|
|
|
||||
TOTAL LIABILITIES AND EQUITY
|
$
|
11,393,667
|
|
|
$
|
12,997,594
|
|
|
Common
Stock
|
|
Capital in
Excess
of Par
Value
|
|
Retained
Earnings
(Deficit)
|
|
Accumulated
Other
Comprehensive
Income
(Loss)
|
|
Common
Stock in
Treasury
|
|
Total
CONSOL
Energy Inc.
Stockholders’
Equity
|
|
Non-
Controlling
Interest
|
|
Total
Equity
|
||||||||||||||||
Balance at December 31, 2010
|
$
|
2,273
|
|
|
$
|
2,178,604
|
|
|
$
|
1,680,597
|
|
|
$
|
(874,338
|
)
|
|
$
|
(42,659
|
)
|
|
$
|
2,944,477
|
|
|
$
|
(8,464
|
)
|
|
$
|
2,936,013
|
|
Net Income
|
—
|
|
|
—
|
|
|
632,497
|
|
|
—
|
|
|
—
|
|
|
632,497
|
|
|
—
|
|
|
632,497
|
|
||||||||
Treasury Rate Lock (Net of $59 Tax)
|
—
|
|
|
—
|
|
|
—
|
|
|
(96
|
)
|
|
—
|
|
|
(96
|
)
|
|
—
|
|
|
(96
|
)
|
||||||||
Gas Cash Flow Hedge (Net of ($68,310) Tax)
|
—
|
|
|
—
|
|
|
—
|
|
|
105,693
|
|
|
—
|
|
|
105,693
|
|
|
—
|
|
|
105,693
|
|
||||||||
Actuarially Determined Long-Term Liability Adjustments (Net of $20,259 Tax)
|
—
|
|
|
—
|
|
|
—
|
|
|
(32,813
|
)
|
|
—
|
|
|
(32,813
|
)
|
|
—
|
|
|
(32,813
|
)
|
||||||||
Comprehensive Income (Loss)
|
—
|
|
|
—
|
|
|
632,497
|
|
|
72,784
|
|
|
—
|
|
|
705,281
|
|
|
—
|
|
|
705,281
|
|
||||||||
Issuance of Treasury Stock
|
—
|
|
|
—
|
|
|
(32,001
|
)
|
|
—
|
|
|
33,313
|
|
|
1,312
|
|
|
—
|
|
|
1,312
|
|
||||||||
Tax Benefit from Stock-Based Compensation
|
—
|
|
|
7,329
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
7,329
|
|
|
—
|
|
|
7,329
|
|
||||||||
Amortization of Stock-Based Compensation Awards
|
—
|
|
|
48,842
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
48,842
|
|
|
—
|
|
|
48,842
|
|
||||||||
Net Change in Noncontrolling Interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8,464
|
|
|
8,464
|
|
||||||||
Dividends ($0.425 per share)
|
—
|
|
|
—
|
|
|
(96,356
|
)
|
|
—
|
|
|
—
|
|
|
(96,356
|
)
|
|
—
|
|
|
(96,356
|
)
|
||||||||
Balance at December 31, 2011
|
2,273
|
|
|
2,234,775
|
|
|
2,184,737
|
|
|
(801,554
|
)
|
|
(9,346
|
)
|
|
3,610,885
|
|
|
—
|
|
|
3,610,885
|
|
||||||||
Net Income
|
—
|
|
|
—
|
|
|
388,470
|
|
|
—
|
|
|
—
|
|
|
388,470
|
|
|
(397
|
)
|
|
388,073
|
|
||||||||
Gas Cash Flow Hedge (Net of $47,891 Tax)
|
—
|
|
|
—
|
|
|
—
|
|
|
(75,019
|
)
|
|
—
|
|
|
(75,019
|
)
|
|
—
|
|
|
(75,019
|
)
|
||||||||
Actuarially Determined Long-Term Liability Adjustments (Net of ($77,871) Tax)
|
—
|
|
|
—
|
|
|
—
|
|
|
129,231
|
|
|
—
|
|
|
129,231
|
|
|
—
|
|
|
129,231
|
|
||||||||
Comprehensive Income (Loss)
|
—
|
|
|
—
|
|
|
388,470
|
|
|
54,212
|
|
|
—
|
|
|
442,682
|
|
|
(397
|
)
|
|
442,285
|
|
||||||||
Issuance of Treasury Stock
|
—
|
|
|
—
|
|
|
(28,378
|
)
|
|
—
|
|
|
8,737
|
|
|
(19,641
|
)
|
|
—
|
|
|
(19,641
|
)
|
||||||||
Issuance of Common Stock
|
11
|
|
|
8,267
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8,278
|
|
|
—
|
|
|
8,278
|
|
||||||||
Tax Benefit from Stock-Based Compensation
|
—
|
|
|
6,028
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6,028
|
|
|
—
|
|
|
6,028
|
|
||||||||
Amortization of Stock-Based Compensation Awards
|
—
|
|
|
47,838
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
47,838
|
|
|
—
|
|
|
47,838
|
|
||||||||
Net Change in Noncontrolling Interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
350
|
|
|
350
|
|
||||||||
Dividends ($0.625 per share)
|
—
|
|
|
—
|
|
|
(142,278
|
)
|
|
—
|
|
|
—
|
|
|
(142,278
|
)
|
|
—
|
|
|
(142,278
|
)
|
||||||||
Balance at December 31, 2012
|
2,284
|
|
|
2,296,908
|
|
|
2,402,551
|
|
|
(747,342
|
)
|
|
(609
|
)
|
|
3,953,792
|
|
|
(47
|
)
|
|
3,953,745
|
|
||||||||
Net Income
|
—
|
|
|
—
|
|
|
660,442
|
|
|
—
|
|
|
—
|
|
|
660,442
|
|
|
(1,386
|
)
|
|
659,056
|
|
||||||||
Gas Cash Flow Hedge (Net of $24,583 Tax)
|
—
|
|
|
—
|
|
|
—
|
|
|
(34,268
|
)
|
|
—
|
|
|
(34,268
|
)
|
|
—
|
|
|
(34,268
|
)
|
||||||||
Actuarially Determined Long-Term Liability Adjustments (Net of ($276,928) Tax)
|
—
|
|
|
—
|
|
|
—
|
|
|
456,493
|
|
|
—
|
|
|
456,493
|
|
|
—
|
|
|
456,493
|
|
||||||||
Comprehensive Income (Loss)
|
—
|
|
|
—
|
|
|
660,442
|
|
|
422,225
|
|
|
—
|
|
|
1,082,667
|
|
|
(1,386
|
)
|
|
1,081,281
|
|
||||||||
Issuance of Treasury Stock
|
—
|
|
|
—
|
|
|
(12,641
|
)
|
|
—
|
|
|
609
|
|
|
(12,032
|
)
|
|
—
|
|
|
(12,032
|
)
|
||||||||
Issuance of Common Stock
|
10
|
|
|
3,717
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,727
|
|
|
—
|
|
|
3,727
|
|
||||||||
Tax Cost from Stock-Based Compensation
|
—
|
|
|
(2,075
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,075
|
)
|
|
—
|
|
|
(2,075
|
)
|
||||||||
Amortization of Stock-Based Compensation Awards
|
—
|
|
|
66,042
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
66,042
|
|
|
—
|
|
|
66,042
|
|
||||||||
Net Change in Noncontrolling Interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,433
|
|
|
1,433
|
|
||||||||
Dividends ($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
|
|
|
$
|
—
|
|
|
$
|
5,006,289
|
|
(Dollars in thousands)
|
For the Years Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Cash Flows from Operating Activities:
|
|
|
|
|
|
||||||
Net Income
|
$
|
659,056
|
|
|
$
|
388,073
|
|
|
$
|
632,497
|
|
Adjustments to Reconcile Net Income to Net Cash Provided By Continuing Operating Activities:
|
|
|
|
|
|
||||||
Net (Loss) Income from Discontinued Operations
|
(579,792
|
)
|
|
(70,114
|
)
|
|
49,178
|
|
|||
Depreciation, Depletion and Amortization
|
461,122
|
|
|
427,115
|
|
|
430,577
|
|
|||
Stock-Based Compensation
|
56,987
|
|
|
41,127
|
|
|
42,131
|
|
|||
Gain on Sale of Assets
|
(67,480
|
)
|
|
(282,006
|
)
|
|
(45,673
|
)
|
|||
Loss on Debt Extinguishment
|
—
|
|
|
—
|
|
|
16,090
|
|
|||
Deferred 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 Receivable
|
135,970
|
|
|
(20,218
|
)
|
|
(83,770
|
)
|
|||
Inventories
|
12,894
|
|
|
21,166
|
|
|
5,509
|
|
|||
Prepaid Expenses
|
(3,219
|
)
|
|
12,435
|
|
|
3,047
|
|
|||
Changes in Other Assets
|
31,146
|
|
|
(7,041
|
)
|
|
23,534
|
|
|||
Changes in Operating Liabilities:
|
|
|
|
|
|
||||||
Accounts Payable
|
(99,944
|
)
|
|
(23,918
|
)
|
|
142,843
|
|
|||
Other Operating Liabilities
|
(31,701
|
)
|
|
(50,790
|
)
|
|
78,530
|
|
|||
Changes in Other Liabilities
|
5,844
|
|
|
12,876
|
|
|
38,413
|
|
|||
Other
|
42,597
|
|
|
24,786
|
|
|
23,001
|
|
|||
Net Cash Provided by Continuing Operations
|
553,570
|
|
|
457,342
|
|
|
1,328,871
|
|
|||
Net Cash Provided by Discontinued Operating Activities
|
105,206
|
|
|
270,771
|
|
|
198,735
|
|
|||
Net Cash Provided by Operating Activities
|
658,776
|
|
|
728,113
|
|
|
1,527,606
|
|
|||
Cash Flows from Investing Activities:
|
|
|
|
|
|
||||||
Capital Expenditures
|
(1,496,056
|
)
|
|
(1,245,497
|
)
|
|
(1,178,375
|
)
|
|||
Change in Restricted Cash
|
68,673
|
|
|
(48,294
|
)
|
|
—
|
|
|||
Proceeds from Sales of Assets
|
483,969
|
|
|
645,621
|
|
|
747,285
|
|
|||
(Investments in) Distributions from Equity Affiliates
|
(35,712
|
)
|
|
(23,451
|
)
|
|
55,876
|
|
|||
Net Cash Used in Continuing Operations
|
(979,126
|
)
|
|
(671,621
|
)
|
|
(375,214
|
)
|
|||
Net Cash Provided by (Used In) Discontinued Investing Activities
|
777,145
|
|
|
(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
|
—
|
|
|
—
|
|
|
250,000
|
|
|||
Tax Benefit from Stock-Based Compensation
|
2,929
|
|
|
8,678
|
|
|
8,281
|
|
|||
Dividends Paid
|
(85,832
|
)
|
|
(142,278
|
)
|
|
(96,356
|
)
|
|||
Proceeds from Issuance of Common Stock
|
3,727
|
|
|
8,278
|
|
|
—
|
|
|||
(Purchases) Issuance of Treasury Stock
|
(2,151
|
)
|
|
(9,485
|
)
|
|
9,033
|
|
|||
Debt 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 Equivalents
|
305,558
|
|
|
(353,874
|
)
|
|
342,942
|
|
|||
Cash and Cash Equivalents at Beginning of Period
|
21,862
|
|
|
375,736
|
|
|
32,794
|
|
|||
Cash and Cash Equivalents at End of Period
|
$
|
327,420
|
|
|
$
|
21,862
|
|
|
$
|
375,736
|
|
|
|
Years
|
Buildings and improvements
|
|
10 to 45
|
Machinery and equipment
|
|
3 to 25
|
Leasehold improvements
|
|
Life of Lease
|
|
For the Years Ended
|
|||||||
|
December 31,
|
|||||||
|
2013
|
|
2012
|
|
2011
|
|||
Anti-Dilutive Options
|
1,976,549
|
|
|
2,411,963
|
|
|
1,156,018
|
|
Anti-Dilutive Restricted Stock Units
|
282,230
|
|
|
8,822
|
|
|
—
|
|
Anti-Dilutive Performance Share Units
|
—
|
|
|
445,847
|
|
|
—
|
|
Anti-Dilutive Performance Share Options
|
802,804
|
|
|
501,744
|
|
|
—
|
|
|
3,061,583
|
|
|
3,368,376
|
|
|
1,156,018
|
|
|
For the Years Ended
|
||||||||||
|
December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Income from Continuing Operations
|
79,264
|
|
|
317,959
|
|
|
681,675
|
|
|||
Income (Loss) from Discontinuing Operations
|
579,792
|
|
|
70,114
|
|
|
(49,178
|
)
|
|||
Less: Net Loss Attributable to Noncontrolling Interest
|
1,386
|
|
|
397
|
|
|
—
|
|
|||
Net income attributable to CONSOL Energy Inc. shareholders
|
$
|
660,442
|
|
|
$
|
388,470
|
|
|
$
|
632,497
|
|
Weighted average shares of common stock outstanding:
|
|
|
|
|
|
||||||
Basic
|
228,728,628
|
|
|
227,593,524
|
|
|
226,680,369
|
|
|||
Effect of stock-based compensation awards
|
1,349,314
|
|
|
1,548,243
|
|
|
2,323,230
|
|
|||
Dilutive
|
230,077,942
|
|
|
229,141,767
|
|
|
229,003,599
|
|
|||
Earnings per share:
|
|
|
|
|
|
||||||
Basic (Continuing Operations)
|
$
|
0.35
|
|
|
$
|
1.40
|
|
|
$
|
3.01
|
|
Basic (Discontinuing Operations)
|
2.54
|
|
|
0.31
|
|
|
(0.22
|
)
|
|||
Total Basic
|
$
|
2.89
|
|
|
$
|
1.71
|
|
|
$
|
2.79
|
|
|
|
|
|
|
|
||||||
Dilutive (Continuing Operations)
|
$
|
0.35
|
|
|
$
|
1.39
|
|
|
$
|
2.98
|
|
Dilutive (Discontinuing Operations)
|
2.52
|
|
|
0.31
|
|
|
(0.22
|
)
|
|||
Total Dilutive
|
$
|
2.87
|
|
|
$
|
1.70
|
|
|
$
|
2.76
|
|
|
|
2013
|
|
2012
|
|
2011
|
|||
Balance, beginning of year
|
|
228,094,712
|
|
|
227,056,212
|
|
|
226,162,133
|
|
Issuance related to Stock-Based Compensation(1)
|
|
1,051,024
|
|
|
1,038,500
|
|
|
894,079
|
|
Balance, end of year
|
|
229,145,736
|
|
|
228,094,712
|
|
|
227,056,212
|
|
|
Gains and Losses on Cash Flow Hedges
|
|
Postretirement Benefits
|
|
Total
|
||||||||||||
Balance at December 31, 2012
|
$
|
76,761
|
|
|
$
|
(824,103
|
)
|
|
$
|
(747,342
|
)
|
||||||
Other comprehensive income before reclassifications
|
45,631
|
|
|
140,250
|
|
|
185,881
|
|
|||||||||
Amounts reclassified from accumulated other comprehensive 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
|
)
|
|
For the Years Ended December 31,
|
||||||||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||||||||
Derivative Instruments (Note 23)
|
|
|
|
|
|
||||||||||||
Natural gas price swaps
|
$
|
(133,889
|
)
|
|
$
|
(310,743
|
)
|
|
$
|
(155,932
|
)
|
||||||
Tax benefit
|
53,990
|
|
|
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 loss
|
86,481
|
|
|
106,299
|
|
|
119,262
|
|
|||||||||
Settlement loss
|
39,482
|
|
|
—
|
|
|
—
|
|
|||||||||
Total
|
93,799
|
|
|
52,446
|
|
|
71,470
|
|
|||||||||
Tax expense
|
(35,806
|
)
|
|
(19,720
|
)
|
|
(27,416
|
)
|
|||||||||
Net of tax
|
$
|
57,993
|
|
|
$
|
32,726
|
|
|
$
|
44,054
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2013
|
|
2012
|
|
2011
|
||||||
Sales
|
|
$
|
2,598,875
|
|
|
$
|
1,717,926
|
|
|
$
|
1,740,196
|
|
Income (Loss) from operations before income taxes
|
|
$
|
969,685
|
|
|
$
|
90,587
|
|
|
$
|
(84,972
|
)
|
Income taxes (expense) benefit
|
|
(389,893
|
)
|
|
(20,473
|
)
|
|
35,794
|
|
|||
Income (loss) from discontinued operations
|
|
$
|
579,792
|
|
|
$
|
70,114
|
|
|
$
|
(49,178
|
)
|
|
|
December 31, 2013
|
|
December 31, 2012
|
||||
Assets:
|
|
|
|
|
||||
Inventory
|
|
$
|
—
|
|
|
$
|
76,958
|
|
Current Deferred Income Tax Asset
|
|
—
|
|
|
63,327
|
|
||
Other Current Assets
|
|
—
|
|
|
8,945
|
|
||
Properties, plants, and equipment
|
|
—
|
|
|
1,682,909
|
|
||
Deferred Income Tax Asset
|
|
—
|
|
|
771,270
|
|
||
Other assets
|
|
—
|
|
|
10,842
|
|
||
Assets of discontinued operations
|
|
$
|
—
|
|
|
$
|
2,614,251
|
|
Liabilities:
|
|
|
|
|
||||
Current Liabilities
|
|
$
|
28,239
|
|
|
$
|
233,214
|
|
Long Term Debt
|
|
—
|
|
|
1,573
|
|
||
Postretirement Benefits Other Than Pensions
|
|
—
|
|
|
1,949,801
|
|
||
Pneumoconiosis Benefits
|
|
—
|
|
|
60,645
|
|
||
Workers' Compensation
|
|
—
|
|
|
95,252
|
|
||
Mine Closing
|
|
—
|
|
|
156,909
|
|
||
Other liabilities
|
|
—
|
|
|
15,644
|
|
||
Liabilities of discontinued operations
|
|
$
|
28,239
|
|
|
$
|
2,513,038
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2013
|
|
2012
|
|
2011
|
||||||
Gain on disposition of assets (a)
|
|
$
|
67,480
|
|
|
$
|
282,006
|
|
|
$
|
45,673
|
|
Equity in earnings of affiliates
|
|
33,133
|
|
|
27,048
|
|
|
24,663
|
|
|||
Royalty income
|
|
16,906
|
|
|
16,853
|
|
|
17,969
|
|
|||
Interest income
|
|
15,889
|
|
|
28,937
|
|
|
8,919
|
|
|||
Pennsylvania Turnpike Settlement
|
|
9,000
|
|
|
—
|
|
|
—
|
|
|||
Right-of-way issuance
|
|
4,536
|
|
|
3,966
|
|
|
12,157
|
|
|||
Other
|
|
32,019
|
|
|
36,366
|
|
|
29,751
|
|
|||
Total Other Income
|
|
$
|
178,963
|
|
|
$
|
395,176
|
|
|
$
|
139,132
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2013
|
|
2012
|
|
2011
|
||||||
Interest on debt
|
|
$
|
260,233
|
|
|
$
|
256,800
|
|
|
$
|
264,080
|
|
Interest on other payables
|
|
2,682
|
|
|
1,296
|
|
|
(189
|
)
|
|||
Interest capitalized
|
|
(43,717
|
)
|
|
(38,054
|
)
|
|
(15,547
|
)
|
|||
Total Interest Expense
|
|
$
|
219,198
|
|
|
$
|
220,042
|
|
|
$
|
248,344
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2013
|
|
2012
|
|
2011
|
||||||
Production taxes
|
|
$
|
84,984
|
|
|
$
|
77,629
|
|
|
$
|
99,442
|
|
Property taxes
|
|
36,338
|
|
|
43,679
|
|
|
35,495
|
|
|||
Payroll taxes
|
|
32,779
|
|
|
32,478
|
|
|
33,155
|
|
|||
Capital stock & franchise tax
|
|
6,833
|
|
|
9,013
|
|
|
3,670
|
|
|||
Virginia 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
|
|
|
$
|
174,392
|
|
|
For The Years Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Current:
|
|
|
|
|
|
||||||
U.S. Federal
|
$
|
6,728
|
|
|
$
|
44,727
|
|
|
$
|
161,474
|
|
U.S. State
|
(10,903
|
)
|
|
1,508
|
|
|
32,150
|
|
|||
Non-U.S
|
7,763
|
|
|
31,594
|
|
|
—
|
|
|||
|
3,588
|
|
|
77,829
|
|
|
193,624
|
|
|||
Deferred:
|
|
|
|
|
|
||||||
U.S. Federal
|
(32,125
|
)
|
|
23,300
|
|
|
30,034
|
|
|||
U.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
|
|
|
$
|
191,251
|
|
|
December 31,
|
||||||
|
2013
|
|
2012
|
||||
Deferred Tax Assets:
|
|
|
|
||||
Postretirement benefits other than pensions
|
$
|
337,836
|
|
|
$
|
347,584
|
|
Mine closing
|
37,306
|
|
|
57,370
|
|
||
Alternative minimum tax
|
159,933
|
|
|
54,609
|
|
||
Pneumoconiosis benefits
|
44,580
|
|
|
46,164
|
|
||
Workers' compensation
|
31,008
|
|
|
25,191
|
|
||
Salary retirement
|
14,330
|
|
|
83,077
|
|
||
Net operating loss
|
168,658
|
|
|
27,277
|
|
||
Mine subsidence
|
35,655
|
|
|
20,804
|
|
||
Reclamation
|
20,978
|
|
|
26,716
|
|
||
Capital lease
|
22,489
|
|
|
23,103
|
|
||
Other
|
160,567
|
|
|
149,435
|
|
||
Total Deferred Tax Assets
|
1,033,340
|
|
|
861,330
|
|
||
Valuation Allowance**
|
(7,532
|
)
|
|
(4,500
|
)
|
||
Net Deferred Tax Assets
|
1,025,808
|
|
|
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
|
)
|
|
For the Years Ended December 31,
|
|||||||||||||||||||
|
2013
|
|
2012
|
|
2011
|
|||||||||||||||
|
Amount
|
|
Percent
|
|
Amount
|
|
Percent
|
|
Amount
|
|
Percent
|
|||||||||
Statutory 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, improvement and modernization act of 2003
|
2,112
|
|
|
4.6
|
|
|
2,112
|
|
|
0.5
|
|
|
2,112
|
|
|
0.2
|
|
|||
Effect of domestic production activities
|
5,680
|
|
|
12.3
|
|
|
(7,215
|
)
|
|
(1.8
|
)
|
|
(21,938
|
)
|
|
(2.5
|
)
|
|||
Federal and state tax accrual to tax return reconciliation
|
(1,406
|
)
|
|
(3.1
|
)
|
|
6,004
|
|
|
1.5
|
|
|
2,257
|
|
|
0.3
|
|
|||
IRS and state tax examination settlements
|
3
|
|
|
—
|
|
|
(925
|
)
|
|
(0.2
|
)
|
|
(5,188
|
)
|
|
(0.6
|
)
|
|||
Net effect of state income taxes
|
(2,399
|
)
|
|
(5.2
|
)
|
|
(8,737
|
)
|
|
(2.1
|
)
|
|
2,926
|
|
|
0.3
|
|
|||
Effect of releasing valuation allowance
|
(4,659
|
)
|
|
(10.1
|
)
|
|
—
|
|
|
—
|
|
|
(22,618
|
)
|
|
(2.6
|
)
|
|||
Effect of foreign tax
|
—
|
|
|
—
|
|
|
1,765
|
|
|
0.4
|
|
|
(1,822
|
)
|
|
(0.2
|
)
|
|||
Other
|
2,458
|
|
|
5.3
|
|
|
2,956
|
|
|
0.7
|
|
|
2,575
|
|
|
0.3
|
|
|||
Income Tax Expense / Effective Rate
|
$
|
(33,189
|
)
|
|
(72.1
|
)%
|
|
$
|
88,728
|
|
|
21.8
|
%
|
|
$
|
191,251
|
|
|
21.9
|
%
|
|
For the Years Ended
|
||||||
|
December 31,
|
||||||
|
2013
|
|
2012
|
||||
Balance at beginning of period
|
$
|
34,786
|
|
|
$
|
37,586
|
|
Increase 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
|
|
|
$
|
34,786
|
|
|
|
As of December 31,
|
||||||
|
|
2013
|
|
2012
|
||||
Balance at beginning of period
|
|
$
|
539,177
|
|
|
$
|
500,648
|
|
Accretion expense
|
|
41,909
|
|
|
37,922
|
|
||
Payments
|
|
(38,198
|
)
|
|
(36,086
|
)
|
||
Revisions in estimated cash flows
|
|
42,558
|
|
|
40,832
|
|
||
Other
|
|
15,429
|
|
|
(4,139
|
)
|
||
Balance at end of period
|
|
$
|
600,875
|
|
|
$
|
539,177
|
|
|
December 31,
|
||||||
|
2013
|
|
2012
|
||||
Coal
|
$
|
31,944
|
|
|
$
|
53,452
|
|
Merchandise for resale
|
38,263
|
|
|
35,363
|
|
||
Supplies
|
87,707
|
|
|
81,993
|
|
||
Total Inventories
|
$
|
157,914
|
|
|
$
|
170,808
|
|
|
December 31,
|
||||||
|
2013
|
|
2012
|
||||
Coal & Other Plant and Equipment
|
$
|
3,681,051
|
|
|
$
|
3,414,940
|
|
Intangible Drilling Cost
|
1,937,336
|
|
|
1,550,297
|
|
||
Proven Properties
|
1,670,404
|
|
|
1,596,838
|
|
||
Unproven Properties
|
1,463,406
|
|
|
1,266,017
|
|
||
Coal Properties and Surface Lands
|
1,404,056
|
|
|
1,164,107
|
|
||
Gathering Equipment
|
1,058,008
|
|
|
1,006,882
|
|
||
Wells and Related Equipment
|
688,548
|
|
|
492,364
|
|
||
Airshafts
|
397,466
|
|
|
366,054
|
|
||
Leased Coal Lands
|
393,372
|
|
|
529,758
|
|
||
Coal Advance Mining Royalties
|
381,348
|
|
|
381,343
|
|
||
Mine Development
|
354,607
|
|
|
262,511
|
|
||
Other Gas Assets
|
126,239
|
|
|
82,217
|
|
||
Gas Advance Royalties
|
22,668
|
|
|
8,229
|
|
||
Total Property, Plant and Equipment
|
13,578,509
|
|
|
12,121,557
|
|
||
Less Accumulated Depreciation, Depletion and Amortization
|
4,136,247
|
|
|
3,613,499
|
|
||
Total Net Property, Plant and Equipment
|
$
|
9,442,262
|
|
|
$
|
8,508,058
|
|
|
|
December 31,
|
||||||
|
|
2013
|
|
2012
|
||||
Unproven gas properties
|
|
$
|
1,487,166
|
|
|
$
|
1,266,017
|
|
Coal properties
|
|
273,242
|
|
|
317,676
|
|
||
Mine Development
|
|
238,356
|
|
|
145,940
|
|
||
Leased coal lands
|
|
99,506
|
|
|
118,697
|
|
||
Coal advance mining royalties
|
|
48,043
|
|
|
55,749
|
|
||
Airshafts
|
|
38,794
|
|
|
21,866
|
|
||
Gas advance royalties
|
|
22,668
|
|
|
8,229
|
|
||
Total
|
|
$
|
2,207,775
|
|
|
$
|
1,934,174
|
|
|
|
Year Ended
|
||
|
|
December 31,
|
||
|
|
2011
|
||
Total Revenue and Other Income
|
|
$
|
6,073,904
|
|
Earnings Before Income Taxes
|
|
$
|
775,807
|
|
Net Income Attributable to CONSOL Energy Inc. Shareholders
|
|
$
|
623,114
|
|
Basic Earnings Per Share
|
|
$
|
2.75
|
|
Dilutive Earnings Per Share
|
|
$
|
2.72
|
|
|
|
Industry
|
|
Industry
|
|
|
||
|
|
Participation
|
|
Participation
|
|
Drilling
|
||
Shale
|
|
Agreement
|
|
Agreement
|
|
Carries
|
||
Play
|
|
Partner
|
|
Date
|
|
Remaining
|
||
Marcellus
|
|
Noble
|
|
September 30, 2011
|
|
$
|
1,873,785
|
|
Utica
|
|
Hess
|
|
October 21, 2011
|
|
$
|
230,353
|
|
|
|
December 31,
|
||||||
|
|
2013
|
|
2012
|
||||
Subsidence liability
|
|
$
|
98,573
|
|
|
$
|
88,939
|
|
Accrued interest
|
|
63,600
|
|
|
63,687
|
|
||
Accrued payroll and benefits
|
|
38,953
|
|
|
39,172
|
|
||
Short-term incentive compensation
|
|
30,371
|
|
|
28,744
|
|
||
Uncertain income tax positions
|
|
28,530
|
|
|
2,100
|
|
||
Accrued other taxes
|
|
26,305
|
|
|
35,943
|
|
||
Other
|
|
122,902
|
|
|
144,352
|
|
||
Current portion of long-term liabilities:
|
|
|
|
|
||||
Postretirement benefits other than pensions
|
|
60,847
|
|
|
58,452
|
|
||
Mine closing
|
|
30,320
|
|
|
25,081
|
|
||
Gas well closing
|
|
23,971
|
|
|
9,729
|
|
||
Workers' compensation
|
|
13,628
|
|
|
9,176
|
|
||
Reclamation
|
|
9,552
|
|
|
20,582
|
|
||
Pneumoconiosis benefits
|
|
9,212
|
|
|
8,838
|
|
||
Salary retirement
|
|
4,593
|
|
|
6,937
|
|
||
Long-term disability
|
|
4,340
|
|
|
4,016
|
|
||
Total Other Accrued Liabilities
|
|
$
|
565,697
|
|
|
$
|
545,748
|
|
|
December 31,
|
||||||
|
2013
|
|
2012
|
||||
Debt:
|
|
|
|
||||
Senior notes due April 2017 at 8.00%, issued at par value
|
$
|
1,500,000
|
|
|
$
|
1,500,000
|
|
Senior notes due April 2020 at 8.25%, issued at par value
|
1,250,000
|
|
|
1,250,000
|
|
||
Senior notes due March 2021 at 6.375%, issued at par value
|
250,000
|
|
|
250,000
|
|
||
MEDCO revenue bonds in series due September 2025 at 5.75%
|
102,865
|
|
|
102,865
|
|
||
Advance royalty commitments (7.93% and 7.43% weighted average interest rate for December 31, 2013 and 2012, respectively)
|
11,182
|
|
|
19,103
|
|
||
Other long-term notes maturing at various dates through 2031 (total value of $5,923 and $7,300 less unamortized discount of $1,050 and $1,542 at December 31, 2013 and December 31,2012, respectively).
|
4,873
|
|
|
5,758
|
|
||
|
3,118,920
|
|
|
3,127,726
|
|
||
Less amounts due in one year *
|
2,957
|
|
|
4,126
|
|
||
Long-Term Debt
|
$
|
3,115,963
|
|
|
$
|
3,123,600
|
|
Year ended December 31,
|
Amount
|
||
2014
|
$
|
3,364
|
|
2015
|
4,276
|
|
|
2016
|
3,457
|
|
|
2017
|
1,502,484
|
|
|
2018
|
1,403
|
|
|
Thereafter
|
1,609,159
|
|
|
Total Long-Term Debt Maturities
|
$
|
3,124,143
|
|
|
|
Capital
|
|
Operating
|
||||
|
|
Leases
|
|
Leases
|
||||
Year Ended December 31,
|
|
|
|
|
||||
2014
|
|
$
|
12,059
|
|
|
$
|
90,565
|
|
2015
|
|
10,984
|
|
|
85,225
|
|
||
2016
|
|
9,842
|
|
|
73,158
|
|
||
2017
|
|
8,758
|
|
|
66,536
|
|
||
2018
|
|
8,128
|
|
|
41,221
|
|
||
Thereafter
|
|
21,272
|
|
|
81,321
|
|
||
Total minimum lease payments
|
|
$
|
71,043
|
|
|
$
|
438,026
|
|
Less 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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
2014
|
|
2015
|
|
2016
|
|
2017
|
|
2018
|
|
Thereafter
|
|
Total
|
|||||||||||||||||||||
$
|
33,084
|
|
|
|
$
|
33,084
|
|
|
|
$
|
33,084
|
|
|
|
$
|
26,685
|
|
|
|
$
|
26,685
|
|
|
|
$
|
13,343
|
|
|
|
$
|
165,965
|
|
|
2014
|
2015
|
|
2016
|
|
2017
|
|
2018
|
|
Thereafter
|
|
Total
|
|||||||||||||||||||||
$
|
8,561
|
|
|
$
|
8,561
|
|
|
|
$
|
7,637
|
|
|
|
$
|
4,496
|
|
|
|
$
|
2,992
|
|
|
|
$
|
2,328
|
|
|
|
$
|
34,575
|
|
|
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
||||||||||||
|
|
at December 31,
|
|
at December 31,
|
||||||||||||
|
|
2013
|
|
2012
|
|
2013
|
|
2012
|
||||||||
Change in benefit obligation:
|
|
|
|
|
|
|
|
|
||||||||
Benefit obligation at beginning of period
|
|
$
|
953,102
|
|
|
$
|
857,352
|
|
|
$
|
3,018,172
|
|
|
$
|
3,242,200
|
|
Service cost
|
|
20,865
|
|
|
20,466
|
|
|
18,680
|
|
|
18,817
|
|
||||
Interest cost
|
|
36,829
|
|
|
37,586
|
|
|
111,687
|
|
|
135,695
|
|
||||
Actuarial 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
|
|
|
5,651
|
|
||||
Benefits 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
|
|
|
166,820
|
|
||||
Participant contributions
|
|
—
|
|
|
—
|
|
|
6,150
|
|
|
5,651
|
|
||||
Benefits 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 comprehensive income consist of:
|
|
|
|
|
|
|
|
|
||||||||
Net actuarial loss
|
|
$
|
286,637
|
|
|
$
|
495,511
|
|
|
$
|
433,073
|
|
|
$
|
1,116,051
|
|
Prior service credit
|
|
(4,629
|
)
|
|
(6,614
|
)
|
|
(34,086
|
)
|
|
(104,288
|
)
|
||||
Net amount recognized (before tax effect)
|
|
$
|
282,008
|
|
|
$
|
488,897
|
|
|
$
|
398,987
|
|
|
$
|
1,011,763
|
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
||||||||||||||||||||
|
For the Years Ended December 31,
|
|
For the Years Ended December 31,
|
||||||||||||||||||||
|
2013
|
|
2012
|
|
2011
|
|
2013
|
|
2012
|
|
2011
|
||||||||||||
Components of net periodic benefit cost:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Service cost
|
$
|
20,865
|
|
|
$
|
20,466
|
|
|
$
|
17,457
|
|
|
$
|
18,680
|
|
|
$
|
18,817
|
|
|
$
|
13,677
|
|
Interest cost
|
36,829
|
|
|
37,586
|
|
|
37,744
|
|
|
111,687
|
|
|
135,695
|
|
|
179,739
|
|
||||||
Expected 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 loss
|
37,853
|
|
|
47,834
|
|
|
38,102
|
|
|
66,417
|
|
|
80,875
|
|
|
105,364
|
|
||||||
Curtailment 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
|
|
|
$
|
252,383
|
|
|
|
|
|
Other
|
||||
|
|
Pension
|
|
Postretirement
|
||||
|
|
Benefits
|
|
Benefits
|
||||
Prior Service (credit) recognition
|
|
$
|
(1,384
|
)
|
|
$
|
(8,784
|
)
|
Actuarial loss recognition
|
|
$
|
23,564
|
|
|
$
|
25,474
|
|
|
|
As of December 31,
|
||||||
|
|
2013
|
|
2012
|
||||
Projected benefit obligation
|
|
$
|
52,845
|
|
|
$
|
953,102
|
|
Accumulated benefit obligation
|
|
$
|
50,820
|
|
|
$
|
895,493
|
|
Fair value of plan assets
|
|
$
|
—
|
|
|
$
|
728,161
|
|
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
||||||||
|
|
For the Year Ended
|
|
For the Year Ended
|
||||||||
|
|
December 31,
|
|
December 31,
|
||||||||
|
|
2013
|
|
2012
|
|
2013
|
|
2012
|
||||
Discount rate
|
|
4.87
|
%
|
|
4.00
|
%
|
|
4.88
|
%
|
|
4.05
|
%
|
Rate of compensation increase
|
|
4.23
|
%
|
|
3.77
|
%
|
|
—
|
|
|
—
|
|
|
|
Pension Benefits at
|
|
Other Postretirement Benefits at
|
||||||||||||||
|
|
December 31,
|
|
December 31,
|
||||||||||||||
|
|
2013
|
|
2012
|
|
2011
|
|
2013
|
|
2012
|
|
2011
|
||||||
Discount 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
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
At December 31,
|
|||||||
|
|
2013
|
|
2012
|
|
2011
|
|||
Health 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
|
|
|
2026
|
|
|
|
1-Percentage
|
|
1-Percentage
|
||||
|
|
Point Increase
|
|
Point Decrease
|
||||
Effect on total of service and interest cost components
|
|
$
|
17,296
|
|
|
$
|
(14,297
|
)
|
Effect on accumulated postretirement benefit obligation
|
|
$
|
123,355
|
|
|
$
|
(103,788
|
)
|
|
|
0.25 Percentage
|
|
0.25 Percentage
|
||||
|
|
Point Increase
|
|
Point Decrease
|
||||
Pension benefit costs (decrease) increase
|
|
$
|
(1,797
|
)
|
|
$
|
1,798
|
|
Other postemployment benefits costs (decrease) increase
|
|
$
|
(3,690
|
)
|
|
$
|
3,830
|
|
|
|
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 Grade Fixed 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 Fixed Income (n)
|
|
34,108
|
|
|
—
|
|
|
34,108
|
|
|
—
|
|
|
29,483
|
|
|
—
|
|
|
29,483
|
|
|
—
|
|
||||||||
US Ultra Long Duration Fixed Income (o)
|
|
7,656
|
|
|
—
|
|
|
7,656
|
|
|
—
|
|
|
34,595
|
|
|
—
|
|
|
34,595
|
|
|
—
|
|
||||||||
US Active Long Corporate Investment (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.
|
(b)
|
This category invests primarily in common stock of large cap companies in the U.S. with above average earnings growth and revenue expectations. It targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by Mercer’s investment management team. The strategy is benchmarked to the Russell 1000 Growth Index.
|
(c)
|
This category invests primarily in U.S. large cap companies that appear to be undervalued relative to their intrinsic value. It targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by Mercer’s investment management team. The strategy is benchmarked to the Russell 1000 Value Index.
|
(d)
|
This category invests in small to mid-sized U.S. companies with above average earnings growth and revenue expectations. It targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by Mercer’s investment management team. The smaller cap orientation of the strategy requires the investment team to be cognizant of liquidity and capital constraints, which are monitored on an ongoing basis. The strategy is benchmarked to the Russell 2500 Growth Index.
|
(e)
|
This category invests in small to mid-sized U.S. companies that appear to be undervalued relative to their intrinsic value. It targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by Mercer’s investment management team. The smaller cap orientation of the strategy requires the investment team to be cognizant of liquidity and capital constraints, which are monitored on an ongoing basis. The strategy is benchmarked to the Russell 2500 Value Index.
|
(f)
|
This category invests primarily in U.S. dollar-denominated investment grade and government securities. It may also invest opportunistically in out-of-benchmark positions including U.S. high yield, non-U.S. bonds, and Treasury Inflation-Protected Securities (TIPs). The strategy seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics, and total portfolio duration is targeted to be within 20% of the benchmark’s duration. Total exposure to high yield issues is typically less than 10%, inclusive of direct investment in high yield and exposure through other core fixed income funds. Fund selection and allocations within the portfolio are implemented by Mercer’s investment management team. The strategy is benchmarked to the Barclays Capital Aggregate Index.
|
(g)
|
This category invests in all cap companies primarily operating in developed non-US markets, with some exposure to emerging markets. The strategy targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Total exposure to emerging markets is typically 10-15%, inclusive of direct investment in emerging markets and exposure through other non-U.S. equity funds. Fund selection and allocations within the portfolio are implemented by Mercer’s investment management team. The strategy is benchmarked to the MSCI EAFE Index.
|
(h)
|
This category invests in companies operating in non-US emerging markets. The strategy targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by Mercer’s investment management team. The strategy is benchmarked to the MSCI Emerging Markets Index.
|
(i)
|
This category invests in companies operating in developed markets, globally. The strategy targets a diversified portfolio of equity securities issued by companies which the investment managers believe will exhibit less volatility in their price performance relative to the broad equity market as described by the MSCI World Index. The strategy is benchmarked to the MSCI World Index.
|
(j)
|
This category invests in a passively managed U.S. long duration corporate investment grade portfolio at a 90% weight and a passively managed U.S. Long Treasury portfolio at a 10% weight. It seeks to provide broad exposure to U.S. long duration investment grade credit while allowing for short term liquidity through a strategic allocation to US Treasuries. The strategy is benchmarked 90% to the Barclays Capital U.S. Long Credit Index and 10% to the Barclays Capital Long Treasury.
|
(k)
|
This category invests primarily in U.S. dollar denominated investment grade bonds and government securities with durations between 9 and 11 years. It may also invest opportunistically in out-of-benchmark positions including U.S. high yield, non-U.S. bonds, municipal bonds, and TIPs. The strategy seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by Mercer’s investment management team. The strategy is benchmarked to the Barclays Capital U.S. Long Government/Credit Index.
|
(l)
|
This category invests in common stock of U.S. large cap companies. The strategy is benchmarked to the S&P 500 Index.
|
(m)
|
This category invests primarily in U.S. dollar-denominated investment grade bonds and government securities. The strategy and its underlying passive investments are benchmarked to the Barclays Capital Aggregate Index.
|
(n)
|
This category invests primarily in U.S. dollar-denominated investment grade bonds and government securities with durations between 9 and 11 years. The strategy and its underlying passive investments are benchmarked to the Barclays Capital Long Government/Credit Index.
|
(o)
|
This category seeks to reduce the volatility of the plan’s funded status and extend the duration of the assets by investing in a series of ultra long duration portfolios with target durations of up to 35 years. Each underlying portfolio is managed by a sub-advisor and consists of five interest rate swaps with sequential target or maturity dates, with the longest dated portfolio maturing in 2045. The interest rate swaps are fully collateralized, resulting in no leverage. The cash collateral is invested by the sub-advisor in an actively managed cash strategy that seeks to provide a return in excess of 3 month LIBOR. The ultra long duration strategy is used in conjunction with liability driven investing solutions, which seek to align the duration of the assets to the plan’s liabilities. The Strategy is benchmarked to a Custom Liability Benchmark Portfolio.
|
(p)
|
This category invests in a U.S. long duration corporate investment grade portfolio at a 90% weight and a U.S. long treasury portfolio at a 10% weight. It seeks to provide broad exposure to U.S. long duration investment grade corporate bonds with an emphasis on reducing default risk through active management while allowing for short term liquidity through a strategic allocation to U.S. Treasuries. The strategy is benchmarked 90% to the Barclays Capital U.S. Long Corporate Index and 10% to the Barclay’s Capital Long Treasury.
|
(q)
|
This category invests primarily in long dated US Treasury STRIPS often with maturities greater than 20 years. The strategy and its underlying passive investments are benchmarked to the Barclays Capital U.S. 20+ Year STRIPS Index.
|
(r)
|
This category invests primarily in fixed income securities from issuers either located in developing/emerging markets or those rated below investment grade (high yield), globally, The strategy is benchmarked to a blended index of 50% JP Morgan Government Bond Index Emerging Markets Global Diversified and 50% Bank of America/Merrill Lynch Global High Yield Index.
|
|
|
|
|
Other
|
|||||
|
|
Pension
|
|
Postretirement
|
|||||
|
|
Benefits
|
|
Benefits
|
|||||
2014
|
|
|
$
|
90,347
|
|
|
$
|
60,847
|
|
2015
|
|
|
$
|
50,080
|
|
|
$
|
62,914
|
|
2016
|
|
|
$
|
48,952
|
|
|
$
|
65,493
|
|
2017
|
|
|
$
|
49,415
|
|
|
$
|
67,623
|
|
2018
|
|
|
$
|
50,741
|
|
|
$
|
68,395
|
|
Year 2019-2023
|
|
|
$
|
262,986
|
|
|
$
|
338,544
|
|
|
|
CWP
|
|
Workers' Compensation
|
||||||||||||
|
|
at December 31,
|
|
at December 31,
|
||||||||||||
|
|
2013
|
|
2012
|
|
2013
|
|
2012
|
||||||||
Change in benefit obligation:
|
|
|
|
|
|
|
|
|
||||||||
Benefit obligation at beginning of period
|
|
$
|
184,079
|
|
|
$
|
183,580
|
|
|
$
|
179,589
|
|
|
$
|
174,069
|
|
State administrative fees and insurance bond premiums
|
|
—
|
|
|
—
|
|
|
5,324
|
|
|
6,727
|
|
||||
Service, legal and administrative cost
|
|
8,168
|
|
|
7,711
|
|
|
15,943
|
|
|
17,126
|
|
||||
Interest cost
|
|
7,031
|
|
|
7,964
|
|
|
6,401
|
|
|
7,113
|
|
||||
Actuarial (gain) loss
|
|
(18,020
|
)
|
|
(3,919
|
)
|
|
11,806
|
|
|
6,754
|
|
||||
Benefits 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 comprehensive income 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
|
)
|
|
CWP
|
|
Workers’ Compensation
|
||||||||||||||||||||
|
For the Years Ended
|
|
For the Years Ended
|
||||||||||||||||||||
|
December 31,
|
|
December 31,
|
||||||||||||||||||||
|
2013
|
|
2012
|
|
2011
|
|
2013
|
|
2012
|
|
2011
|
||||||||||||
Service cost
|
$
|
8,168
|
|
|
$
|
7,711
|
|
|
$
|
7,620
|
|
|
$
|
15,943
|
|
|
$
|
17,126
|
|
|
$
|
20,015
|
|
Interest cost
|
7,031
|
|
|
7,964
|
|
|
9,330
|
|
|
6,401
|
|
|
7,113
|
|
|
8,238
|
|
||||||
Amortization 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 bond premiums
|
—
|
|
|
—
|
|
|
—
|
|
|
5,324
|
|
|
6,727
|
|
|
7,035
|
|
||||||
Settlement gain
|
(119,881
|
)
|
|
—
|
|
|
—
|
|
|
(121,838
|
)
|
|
—
|
|
|
—
|
|
||||||
Net periodic cost (credit)
|
$
|
(121,066
|
)
|
|
$
|
(4,058
|
)
|
|
$
|
(4,960
|
)
|
|
$
|
(96,800
|
)
|
|
$
|
27,022
|
|
|
$
|
31,381
|
|
|
|
|
|
Workers'
|
||||
|
|
CWP
|
|
Compensation
|
||||
|
|
Benefits
|
|
Benefits
|
||||
Prior Service benefit recognition
|
|
$
|
—
|
|
|
$
|
—
|
|
Actuarial gain recognition
|
|
$
|
(6,196
|
)
|
|
$
|
(382
|
)
|
|
|
CWP
|
|
Workers' Compensation
|
||||||||||||||
|
|
For the Years Ended
|
|
For the Years Ended
|
||||||||||||||
|
|
December 31,
|
|
December 31,
|
||||||||||||||
|
|
2013
|
|
|
2012
|
|
|
2011
|
|
|
2013
|
|
|
2012
|
|
|
2011
|
|
Benefit 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
|
%
|
|
|
0.25 Percentage
|
|
0.25 Percentage
|
||||
|
|
Point Increase
|
|
Point Decrease
|
||||
CWP benefit increase (decrease)
|
|
$
|
585
|
|
|
$
|
(530
|
)
|
Workers' Compensation costs (decrease) increase
|
|
$
|
(379
|
)
|
|
$
|
398
|
|
|
|
|
|
Workers' Compensation
|
|||||||||||||
|
|
CWP
|
|
Total
|
|
Actuarial
|
|
Other
|
|||||||||
|
|
Benefits
|
|
Benefits
|
|
Benefits
|
|
Benefits
|
|||||||||
2014
|
|
|
$
|
9,211
|
|
|
$
|
18,635
|
|
|
$
|
13,628
|
|
|
$
|
5,007
|
|
2015
|
|
|
$
|
9,204
|
|
|
$
|
18,479
|
|
|
$
|
13,347
|
|
|
$
|
5,132
|
|
2016
|
|
|
$
|
9,185
|
|
|
$
|
18,602
|
|
|
$
|
13,341
|
|
|
$
|
5,261
|
|
2017
|
|
|
$
|
9,163
|
|
|
$
|
18,815
|
|
|
$
|
13,423
|
|
|
$
|
5,392
|
|
2018
|
|
|
$
|
9,156
|
|
|
$
|
19,000
|
|
|
$
|
13,473
|
|
|
$
|
5,527
|
|
Year 2019-2023
|
|
|
$
|
45,090
|
|
|
$
|
99,249
|
|
|
$
|
69,471
|
|
|
$
|
29,778
|
|
|
|
For the Years Ended
|
||||||||||
|
|
December 31,
|
||||||||||
|
|
2013
|
|
2012
|
|
2011
|
||||||
Benefit (Credit) Cost
|
|
$
|
(687
|
)
|
|
$
|
6,122
|
|
|
$
|
6,439
|
|
Discount rate assumption used to determine net periodic benefit costs
|
|
3.04
|
%
|
|
3.62
|
%
|
|
4.04
|
%
|
|
|
December 31,
|
||||||
|
|
2012
|
|
2011
|
||||
Weighted average fair value of grants
|
|
$
|
14.58
|
|
|
$
|
20.47
|
|
Risk-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
|
|
|
4.26
|
|
|
|
|
|
|
|
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
|
|
|
$
|
28,398
|
|
Vested and expected to vest
|
|
4,765,963
|
|
|
$
|
38.13
|
|
|
4.19
|
|
|
$
|
28,398
|
|
Exercisable at December 31, 2013
|
|
4,344,749
|
|
|
$
|
38.45
|
|
|
3.76
|
|
|
$
|
28,839
|
|
|
|
Number of
|
|
Weighted Average
|
|
|
|
Shares
|
|
Grant Date Fair Value
|
|
Nonvested at December 31, 2012
|
|
1,326,953
|
|
|
$40.39
|
Granted
|
|
654,656
|
|
|
$31.60
|
Vested
|
|
(930,390
|
)
|
|
$39.77
|
Forfeited
|
|
(169,649
|
)
|
|
$32.93
|
Nonvested at December 31, 2013
|
|
881,570
|
|
|
$35.95
|
|
|
Number of
|
|
Weighted Average
|
|
|
|
Shares
|
|
Grant Date Fair Value
|
|
Nonvested at December 31, 2012
|
|
702,194
|
|
|
$50.76
|
Granted
|
|
40,514
|
|
|
$31.35
|
Vested
|
|
(159,228
|
)
|
|
$68.45
|
Nonvested at December 31, 2013
|
|
583,480
|
|
|
$38.19
|
|
|
Number of
|
|
Weighted Average
|
|
|
|
Shares
|
|
Grant Date Fair Value
|
|
Nonvested at December 31, 2012
|
|
401,392
|
|
|
$16.44
|
Vested
|
|
(100,349
|
)
|
|
$16.44
|
Nonvested at December 31, 2013
|
|
301,063
|
|
|
$16.44
|
|
|
Number of
|
|
Weighted Average
|
|
|
|
Shares
|
|
Grant Date Fair Value
|
|
Nonvested at December 31, 2012
|
|
—
|
|
|
—
|
Granted
|
|
842,167
|
|
|
$33.70
|
Forfeited
|
|
(8,614
|
)
|
|
$33.39
|
Nonvested at December 31, 2013
|
|
833,553
|
|
|
$33.70
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2013
|
|
2012
|
|
2011
|
||||||
Interest (Net of Amounts Capitalized)
|
|
$
|
209,580
|
|
|
$
|
212,364
|
|
|
$
|
242,587
|
|
Income Taxes
|
|
$
|
35,079
|
|
|
$
|
121,245
|
|
|
$
|
144,405
|
|
|
|
December 31,
|
||||||
|
|
2013
|
|
2012
|
||||
Thermal coal utilities
|
|
$
|
154,738
|
|
|
$
|
247,955
|
|
Steel and coke producers
|
|
10,963
|
|
|
47,203
|
|
||
Coal brokers and distributors
|
|
52,233
|
|
|
65,057
|
|
||
Gas wholesalers
|
|
71,441
|
|
|
51,718
|
|
||
Various other
|
|
43,199
|
|
|
16,395
|
|
||
Total Accounts Receivable Trade (including Accounts Receivable—Securitized)
|
|
$
|
332,574
|
|
|
$
|
428,328
|
|
|
Fair Value Measurements at December 31, 2013
|
|
Fair Value Measurements at December 31, 2012
|
||||||||||||||||||||
Description
|
Quoted Prices in
Active Markets
for Identical
Liabilities
(Level 1)
|
|
Significant
Other
Observable
Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
|
Quoted Prices in
Active Markets
for Identical
Liabilities
(Level 1)
|
|
Significant
Other
Observable
Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
||||||||||||
Gas Cash Flow Hedges (Note 23)
|
$
|
—
|
|
|
$
|
65,449
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
128,945
|
|
|
$
|
—
|
|
|
December 31, 2013
|
|
December 31, 2012
|
||||||||||||
|
Carrying
Amount
|
|
Fair
Value
|
|
Carrying
Amount
|
|
Fair
Value
|
||||||||
Cash and cash equivalents
|
$
|
327,420
|
|
|
$
|
327,420
|
|
|
$
|
21,862
|
|
|
$
|
21,862
|
|
Restricted cash (a)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
68,673
|
|
|
$
|
68,673
|
|
Short-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
|
)
|
|
|
|
Year Ended December 31,
|
||||||||
|
2013
|
2012
|
2011
|
||||||||
Natural Gas Price Swaps
|
|
|
|
||||||||
Beginning Balance – Accumulated OCI
|
$
|
76,761
|
|
$
|
151,780
|
|
$
|
46,087
|
|
||
Gain recognized in Accumulated OCI
|
$
|
45,631
|
|
$
|
114,240
|
|
$
|
200,700
|
|
||
Less: Gain reclassified from Accumulated OCI into Outside Sales
|
$
|
79,899
|
|
$
|
189,259
|
|
$
|
95,007
|
|
||
Ending Balance – Accumulated OCI
|
$
|
42,493
|
|
$
|
76,761
|
|
$
|
151,780
|
|
||
Gain recognized in Outside Sales for ineffectiveness
|
$
|
(4,645
|
)
|
$
|
579
|
|
$
|
1,034
|
|
|
Amount of Commitment Expiration Per Period
|
||||||||||||||||||
|
Total
Amounts
Committed
|
|
Less Than
1 Year
|
|
1-3 Years
|
|
3-5 Years
|
|
Beyond
5 Years
|
||||||||||
Letters of Credit:
|
|
|
|
|
|
|
|
|
|
||||||||||
Employee-Related
|
$
|
190,358
|
|
|
$
|
164,852
|
|
|
$
|
25,506
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Environmental
|
56,293
|
|
|
23,075
|
|
|
33,218
|
|
|
—
|
|
|
—
|
|
|||||
Other
|
114,106
|
|
|
76,460
|
|
|
37,646
|
|
|
—
|
|
|
—
|
|
|||||
Total Letters of Credit
|
360,757
|
|
|
264,387
|
|
|
96,370
|
|
|
—
|
|
|
—
|
|
|||||
Surety Bonds:
|
|
|
|
|
|
|
|
|
|
||||||||||
Employee-Related
|
204,884
|
|
|
204,884
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Environmental
|
610,209
|
|
|
610,209
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Other
|
32,492
|
|
|
32,481
|
|
|
10
|
|
|
—
|
|
|
1
|
|
|||||
Total Surety Bonds
|
847,585
|
|
|
847,574
|
|
|
10
|
|
|
—
|
|
|
1
|
|
|||||
Gurantees:
|
|
|
|
|
|
|
|
|
|
||||||||||
Coal
|
333,460
|
|
|
200,400
|
|
|
133,060
|
|
|
—
|
|
|
—
|
|
|||||
Other
|
70,523
|
|
35,611
|
|
10,846
|
|
9,718
|
|
14,348
|
||||||||||
Total Guarantees
|
403,983
|
|
|
236,011
|
|
|
143,906
|
|
|
9,718
|
|
|
14,348
|
|
|||||
Total Commitments
|
$
|
1,612,325
|
|
|
$
|
1,347,972
|
|
|
$
|
240,286
|
|
|
$
|
9,718
|
|
|
$
|
14,349
|
|
Obligations Due
|
Amount
|
||
Less than 1 year
|
$
|
240,870
|
|
1 - 3 years
|
260,218
|
|
|
3 - 5 years
|
199,144
|
|
|
More than 5 years
|
583,333
|
|
|
Total Purchase Obligations
|
$
|
1,283,565
|
|
|
For The Years Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Gas drilling obligations
|
$
|
109,609
|
|
|
$
|
110,975
|
|
|
$
|
108,167
|
|
Firm transportation expense
|
126,766
|
|
|
78,475
|
|
|
59,606
|
|
|||
Major equipment purchases
|
12,668
|
|
|
101,367
|
|
|
34,219
|
|
|||
Other
|
—
|
|
|
492
|
|
|
891
|
|
|||
Total costs related to purchase obligations
|
$
|
249,043
|
|
|
$
|
291,309
|
|
|
$
|
202,883
|
|
|
Marcellus
Shale
|
|
Coalbed
Methane
|
|
Shallow Oil and Gas
|
|
Other
Gas
|
|
Total
Gas
|
|
Thermal
|
|
Low Volatile
Metallurgical
|
|
High Volatile
Metallurgical
|
|
Other
Coal
|
|
Total Coal
|
|
All
Other
|
|
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 Income Taxes
|
$
|
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 and amortization
|
|
|
|
|
|
|
|
|
$
|
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.
|
|
Marcellus
Shale
|
|
Coalbed
Methane
|
|
Shallow Oil and Gas
|
|
Other
Gas
|
|
Total
Gas |
|
Thermal
|
|
Low Volatile
Metallurgical
|
|
High Volatile
Metallurgical
|
|
Other
Coal
|
|
Total Coal
|
|
All
Other
|
|
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) Before Income 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, depletion and 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.
|
|
Marcellus
Shale
|
|
Coalbed
Methane
|
|
Shallow Oil and Gas
|
|
Other
Gas
|
|
Total
Gas
|
|
Thermal
|
|
Low Volatile
Metallurgical
|
|
High Volatile
Metallurgical
|
|
Other
Coal
|
|
Total Coal
|
|
All
Other
|
|
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—purchased gas
|
—
|
|
|
—
|
|
|
—
|
|
|
4,344
|
|
|
4,344
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,344
|
|
|
|||||||||||||
Sales—gas royalty interests
|
—
|
|
|
—
|
|
|
—
|
|
|
66,929
|
|
|
66,929
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
66,929
|
|
|
|||||||||||||
Freight—outside
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
175,633
|
|
|
175,633
|
|
|
—
|
|
|
—
|
|
|
175,633
|
|
|
|||||||||||||
Intersegment transfers
|
—
|
|
|
—
|
|
|
—
|
|
|
3,303
|
|
|
3,303
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
194,857
|
|
|
(198,160
|
)
|
|
—
|
|
|
|||||||||||||
Total Sales and Freight
|
$
|
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) Before Income Taxes
|
$
|
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, depletion and amortization
|
|
|
|
|
|
|
|
|
$
|
206,821
|
|
|
|
|
|
|
|
|
|
|
$
|
214,285
|
|
|
$
|
9,471
|
|
|
$
|
—
|
|
|
$
|
430,577
|
|
|
||||||||||||||||
Capital expenditures
|
|
|
|
|
|
|
|
|
$
|
664,612
|
|
|
|
|
|
|
|
|
|
|
$
|
472,591
|
|
|
$
|
41,172
|
|
|
$
|
—
|
|
|
$
|
1,178,375
|
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2013
|
|
2012
|
|
2011
|
||||||
Total segment sales and freight from external customers
|
|
$
|
3,120,722
|
|
|
$
|
3,282,350
|
|
|
$
|
4,237,913
|
|
Other income not allocated to segments (Note 4)
|
|
178,963
|
|
|
395,176
|
|
|
139,132
|
|
|||
Total Consolidated Revenue and Other Income
|
|
$
|
3,299,685
|
|
|
$
|
3,677,526
|
|
|
$
|
4,377,045
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2013
|
|
2012
|
|
2011
|
||||||
Segment Earnings Before Income Taxes for total reportable business segments
|
|
$
|
334,910
|
|
|
$
|
631,078
|
|
|
$
|
1,162,481
|
|
Segment Earnings Before Income Taxes for all other businesses
|
|
(47,468
|
)
|
|
10,997
|
|
|
3,408
|
|
|||
Interest 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
|
|
—
|
|
|
—
|
|
|
2,122
|
|
|||
Earnings Before Income Taxes
|
|
$
|
46,075
|
|
|
$
|
406,687
|
|
|
$
|
872,926
|
|
Total Assets:
|
|
December 31,
|
||||||
|
2013
|
|
2012
|
|||||
Segment assets for total reportable business segments
|
|
$
|
10,521,753
|
|
|
$
|
9,873,863
|
|
Segment assets for all other businesses
|
|
293,486
|
|
|
363,676
|
|
||
Items excluded from segment assets:
|
|
|
|
|
||||
Cash and other investments (I)
|
|
321,992
|
|
|
19,252
|
|
||
Recoverable income taxes
|
|
10,705
|
|
|
—
|
|
||
Deferred tax assets
|
|
211,303
|
|
|
84,777
|
|
||
Bond issuance costs
|
|
34,428
|
|
|
41,775
|
|
||
Discontinued Operations
|
|
—
|
|
|
2,614,251
|
|
||
Total Consolidated Assets
|
|
$
|
11,393,667
|
|
|
$
|
12,997,594
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2013
|
|
2012
|
|
2011
|
||||||
United States (K)
|
|
$
|
2,999,674
|
|
|
$
|
2,898,341
|
|
|
$
|
3,460,871
|
|
Europe
|
|
83,878
|
|
|
187,313
|
|
|
366,384
|
|
|||
South America
|
|
29,787
|
|
|
169,591
|
|
|
400,307
|
|
|||
Canada
|
|
3,575
|
|
|
5,692
|
|
|
10,351
|
|
|||
Other
|
|
3,808
|
|
|
21,413
|
|
|
—
|
|
|||
Total Revenues and Freight from External Customers (K)
|
|
$
|
3,120,722
|
|
|
$
|
3,282,350
|
|
|
$
|
4,237,913
|
|
|
|
December 31,
|
||||||
|
|
2013
|
|
2012
|
||||
United States
|
|
$
|
9,431,238
|
|
|
$
|
8,487,614
|
|
Canada
|
|
11,024
|
|
|
20,444
|
|
||
Discontinued Operations
|
|
—
|
|
|
1,682,909
|
|
||
Total Property, Plant and Equipment, net
|
|
$
|
9,442,262
|
|
|
$
|
10,190,967
|
|
|
Parent
Issuer
|
|
CNX Gas
Guarantor
|
|
Other
Subsidiary
Guarantors
|
|
Non-
Guarantors
|
|
Elimination
|
|
Consolidated
|
||||||||||||
Sales—Outside
|
$
|
—
|
|
|
$
|
740,869
|
|
|
$
|
2,061,652
|
|
|
$
|
216,419
|
|
|
$
|
(3,389
|
)
|
|
$
|
3,015,551
|
|
Sales—Gas Royalty Interests
|
—
|
|
|
63,202
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
63,202
|
|
||||||
Sales—Purchased Gas
|
—
|
|
|
6,531
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6,531
|
|
||||||
Freight—Outside
|
—
|
|
|
—
|
|
|
35,438
|
|
|
—
|
|
|
—
|
|
|
35,438
|
|
||||||
Other Income
|
930,481
|
|
|
57,592
|
|
|
100,757
|
|
|
20,614
|
|
|
(930,481
|
)
|
|
178,963
|
|
||||||
Total Revenue and Other Income
|
930,481
|
|
|
868,194
|
|
|
2,197,847
|
|
|
237,033
|
|
|
(933,870
|
)
|
|
3,299,685
|
|
||||||
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)
|
170,702
|
|
|
493,416
|
|
|
1,313,601
|
|
|
219,450
|
|
|
31,783
|
|
|
2,228,952
|
|
||||||
Gas Royalty Interests Costs
|
—
|
|
|
53,069
|
|
|
—
|
|
|
—
|
|
|
(41
|
)
|
|
53,028
|
|
||||||
Purchased Gas Costs
|
—
|
|
|
4,837
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,837
|
|
||||||
Related Party Activity
|
35,678
|
|
|
—
|
|
|
(112,626
|
)
|
|
1,767
|
|
|
75,181
|
|
|
—
|
|
||||||
Freight Expense
|
—
|
|
|
—
|
|
|
35,438
|
|
|
—
|
|
|
—
|
|
|
35,438
|
|
||||||
Selling, General and Administrative Expenses
|
—
|
|
|
44,733
|
|
|
44,357
|
|
|
1,318
|
|
|
—
|
|
|
90,408
|
|
||||||
Depreciation, Depletion and Amortization
|
12,857
|
|
|
229,562
|
|
|
216,726
|
|
|
1,977
|
|
|
—
|
|
|
461,122
|
|
||||||
Interest Expense
|
211,449
|
|
|
8,605
|
|
|
(423
|
)
|
|
47
|
|
|
(480
|
)
|
|
219,198
|
|
||||||
Taxes Other Than Income
|
3,669
|
|
|
35,176
|
|
|
118,675
|
|
|
3,107
|
|
|
—
|
|
|
160,627
|
|
||||||
Total Costs
|
434,355
|
|
|
869,398
|
|
|
1,615,748
|
|
|
227,666
|
|
|
106,443
|
|
|
3,253,610
|
|
||||||
Earnings (Loss) Before Income Taxes
|
496,126
|
|
|
(1,204
|
)
|
|
582,099
|
|
|
9,367
|
|
|
(1,040,313
|
)
|
|
46,075
|
|
||||||
Income Tax (Benefit) Expense
|
(164,316
|
)
|
|
1,420
|
|
|
126,164
|
|
|
3,543
|
|
|
—
|
|
|
(33,189
|
)
|
||||||
Income (Loss) from Continuing Operations
|
660,442
|
|
|
(2,624
|
)
|
|
455,935
|
|
|
5,824
|
|
|
(1,040,313
|
)
|
|
79,264
|
|
||||||
Income from Discontinued Operations, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
579,792
|
|
|
—
|
|
|
579,792
|
|
||||||
Net Income (Loss)
|
660,442
|
|
|
(2,624
|
)
|
|
455,935
|
|
|
585,616
|
|
|
(1,040,313
|
)
|
|
659,056
|
|
||||||
Less: Net Loss Attributable to Noncontrolling Interest
|
—
|
|
|
1,386
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,386
|
|
||||||
Net Income (Loss) Attributable to CONSOL Energy Inc. Shareholders
|
$
|
660,442
|
|
|
$
|
(1,238
|
)
|
|
$
|
455,935
|
|
|
$
|
585,616
|
|
|
$
|
(1,040,313
|
)
|
|
$
|
660,442
|
|
|
Parent
Issuer
|
|
CNX Gas
Guarantor
|
|
Other
Subsidiary
Guarantors
|
|
Non-
Guarantors
|
|
Elimination
|
|
Consolidated
|
||||||||||||
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Current Assets:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Cash and Cash Equivalents
|
$
|
320,473
|
|
|
$
|
6,238
|
|
|
$
|
—
|
|
|
$
|
709
|
|
|
$
|
—
|
|
|
$
|
327,420
|
|
Accounts and Notes Receivable:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Trade
|
—
|
|
|
71,911
|
|
|
—
|
|
|
260,663
|
|
|
—
|
|
|
332,574
|
|
||||||
Notes Receivable
|
1,238
|
|
|
—
|
|
|
24,623
|
|
|
—
|
|
|
—
|
|
|
25,861
|
|
||||||
Other Receivables
|
17,657
|
|
|
207,128
|
|
|
14,969
|
|
|
4,219
|
|
|
—
|
|
|
243,973
|
|
||||||
Inventories
|
—
|
|
|
15,185
|
|
|
99,320
|
|
|
43,409
|
|
|
—
|
|
|
157,914
|
|
||||||
Deferred Income Taxes
|
219,566
|
|
|
(8,263
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
211,303
|
|
||||||
Recoverable Income Taxes
|
(16,262
|
)
|
|
26,967
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10,705
|
|
||||||
Prepaid Expenses
|
43,698
|
|
|
65,701
|
|
|
24,915
|
|
|
1,528
|
|
|
—
|
|
|
135,842
|
|
||||||
Total Current Assets
|
586,370
|
|
|
384,867
|
|
|
163,827
|
|
|
310,528
|
|
|
—
|
|
|
1,445,592
|
|
||||||
Property, Plant and Equipment:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Property, Plant and Equipment
|
220,355
|
|
|
6,919,972
|
|
|
6,412,378
|
|
|
25,804
|
|
|
—
|
|
|
13,578,509
|
|
||||||
Less-Accumulated Depreciation, Depletion and Amortization
|
145,754
|
|
|
1,188,464
|
|
|
2,783,043
|
|
|
18,986
|
|
|
—
|
|
|
4,136,247
|
|
||||||
Total Property, Plant and Equipment-Net
|
74,601
|
|
|
5,731,508
|
|
|
3,629,335
|
|
|
6,818
|
|
|
—
|
|
|
9,442,262
|
|
||||||
Other Assets:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Investment in Affiliates
|
11,965,054
|
|
|
206,060
|
|
|
70,222
|
|
|
—
|
|
|
(11,949,661
|
)
|
|
291,675
|
|
||||||
Notes Receivable
|
125
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
125
|
|
||||||
Other
|
145,401
|
|
|
30,728
|
|
|
28,831
|
|
|
9,053
|
|
|
—
|
|
|
214,013
|
|
||||||
Total Other Assets
|
12,110,580
|
|
|
236,788
|
|
|
99,053
|
|
|
9,053
|
|
|
(11,949,661
|
)
|
|
505,813
|
|
||||||
Total Assets
|
$
|
12,771,551
|
|
|
$
|
6,353,163
|
|
|
$
|
3,892,215
|
|
|
$
|
326,399
|
|
|
$
|
(11,949,661
|
)
|
|
$
|
11,393,667
|
|
Liabilities and Equity:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Current Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Accounts Payable
|
$
|
180,261
|
|
|
$
|
324,226
|
|
|
$
|
493
|
|
|
$
|
9,600
|
|
|
$
|
—
|
|
|
$
|
514,580
|
|
Accounts Payable (Recoverable)—Related Parties
|
4,563,327
|
|
|
23,287
|
|
|
(5,055,923
|
)
|
|
136,822
|
|
|
332,487
|
|
|
—
|
|
||||||
Current Portion Long-Term Debt
|
1,029
|
|
|
6,258
|
|
|
3,372
|
|
|
796
|
|
|
—
|
|
|
11,455
|
|
||||||
Short-Term Notes Payable
|
—
|
|
|
332,487
|
|
|
—
|
|
|
—
|
|
|
(332,487
|
)
|
|
—
|
|
||||||
Other Accrued Liabilities
|
144,612
|
|
|
89,080
|
|
|
322,606
|
|
|
9,399
|
|
|
—
|
|
|
565,697
|
|
||||||
Current Liabilities of Discontinued Operations
|
—
|
|
|
—
|
|
|
—
|
|
|
28,239
|
|
|
—
|
|
|
28,239
|
|
||||||
Total Current Liabilities
|
4,889,229
|
|
|
775,338
|
|
|
(4,729,452
|
)
|
|
184,856
|
|
|
—
|
|
|
1,119,971
|
|
||||||
Long-Term Debt:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Long-Term Debt
|
3,004,213
|
|
|
—
|
|
|
111,750
|
|
|
—
|
|
|
—
|
|
|
3,115,963
|
|
||||||
Capital Lease Obligations
|
1,245
|
|
|
42,852
|
|
|
1,724
|
|
|
1,775
|
|
|
—
|
|
|
47,596
|
|
||||||
Total Long-Term Debt
|
3,005,458
|
|
|
42,852
|
|
|
113,474
|
|
|
1,775
|
|
|
—
|
|
|
3,163,559
|
|
||||||
Deferred Credits and Other Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Deferred Income Taxes
|
(232,904
|
)
|
|
475,547
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
242,643
|
|
||||||
Postretirement Benefits Other Than Pensions
|
—
|
|
|
—
|
|
|
961,127
|
|
|
—
|
|
|
—
|
|
|
961,127
|
|
||||||
Pneumoconiosis Benefits
|
—
|
|
|
—
|
|
|
111,971
|
|
|
—
|
|
|
—
|
|
|
111,971
|
|
||||||
Mine Closing
|
—
|
|
|
—
|
|
|
320,723
|
|
|
—
|
|
|
—
|
|
|
320,723
|
|
||||||
Gas Well Closing
|
—
|
|
|
119,429
|
|
|
56,174
|
|
|
—
|
|
|
—
|
|
|
175,603
|
|
||||||
Workers’ Compensation
|
—
|
|
|
—
|
|
|
71,136
|
|
|
332
|
|
|
—
|
|
|
71,468
|
|
||||||
Salary Retirement
|
48,252
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
48,252
|
|
||||||
Reclamation
|
—
|
|
|
—
|
|
|
40,706
|
|
|
—
|
|
|
—
|
|
|
40,706
|
|
||||||
Other
|
55,227
|
|
|
61,190
|
|
|
14,938
|
|
|
—
|
|
|
—
|
|
|
131,355
|
|
||||||
Total Deferred Credits and Other Liabilities
|
(129,425
|
)
|
|
656,166
|
|
|
1,576,775
|
|
|
332
|
|
|
—
|
|
|
2,103,848
|
|
||||||
Total CONSOL Energy Inc. Stockholders’ Equity
|
5,006,289
|
|
|
4,878,807
|
|
|
6,931,418
|
|
|
139,436
|
|
|
(11,949,661
|
)
|
|
5,006,289
|
|
||||||
Total Liabilities and Equity
|
$
|
12,771,551
|
|
|
$
|
6,353,163
|
|
|
$
|
3,892,215
|
|
|
$
|
326,399
|
|
|
$
|
(11,949,661
|
)
|
|
$
|
11,393,667
|
|
|
Parent
|
|
CNX Gas
Guarantor
|
|
Other Subsidiary Guarantors
|
|
Non-
Guarantors
|
|
Elimination
|
|
Consolidated
|
||||||||||||
Net Cash Provided by (Used in) Continuing Operations
|
$
|
51,093
|
|
|
$
|
440,763
|
|
|
$
|
572,683
|
|
|
$
|
(843,456
|
)
|
|
$
|
332,487
|
|
|
$
|
553,570
|
|
Net Cash Provided by Discontinued Operating Activities
|
—
|
|
|
—
|
|
|
—
|
|
|
105,206
|
|
|
—
|
|
|
105,206
|
|
||||||
Net Cash Provided by (Used in) Operating Activities
|
$
|
51,093
|
|
|
$
|
440,763
|
|
|
$
|
572,683
|
|
|
$
|
(738,250
|
)
|
|
$
|
332,487
|
|
|
$
|
658,776
|
|
Cash Flows from Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Capital Expenditures
|
$
|
(68,796
|
)
|
|
$
|
(968,607
|
)
|
|
$
|
(458,653
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(1,496,056
|
)
|
Change in Restricted Cash
|
—
|
|
|
—
|
|
|
68,673
|
|
|
—
|
|
|
—
|
|
|
68,673
|
|
||||||
Proceeds From Sales of Assets
|
327,964
|
|
|
350,975
|
|
|
(195,082
|
)
|
|
112
|
|
|
—
|
|
|
483,969
|
|
||||||
(Investments in), net of Distributions from, Equity Affiliates
|
—
|
|
|
(47,500
|
)
|
|
11,788
|
|
|
—
|
|
|
—
|
|
|
(35,712
|
)
|
||||||
Net Cash (Used in) Provided by Continuing Operations
|
259,168
|
|
|
(665,132
|
)
|
|
(573,274
|
)
|
|
112
|
|
|
—
|
|
|
(979,126
|
)
|
||||||
Net Cash Provided by Discontinued Investing Activities
|
—
|
|
|
—
|
|
|
—
|
|
|
777,145
|
|
|
—
|
|
|
777,145
|
|
||||||
Net Cash (Used in) Provided by Investing Activities
|
$
|
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 Stock
|
3,727
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,727
|
|
||||||
Other Financing Activities
|
778
|
|
|
(5,232
|
)
|
|
5,232
|
|
|
—
|
|
|
—
|
|
|
778
|
|
||||||
Net Cash (Used in) Provided by Continuing Operations
|
(7,279
|
)
|
|
227,255
|
|
|
432
|
|
|
(38,638
|
)
|
|
(332,487
|
)
|
|
(150,717
|
)
|
||||||
Net Cash Used in Discontinued Financing Activities
|
—
|
|
|
—
|
|
|
—
|
|
|
(520
|
)
|
|
—
|
|
|
(520
|
)
|
||||||
Net Cash (Used in) Provided by Financing Activities
|
$
|
(7,279
|
)
|
|
$
|
227,255
|
|
|
$
|
432
|
|
|
$
|
(39,158
|
)
|
|
$
|
(332,487
|
)
|
|
$
|
(151,237
|
)
|
|
Parent
Issuer
|
|
CNX Gas
Guarantor
|
|
Other
Subsidiary
Guarantors
|
|
Non-
Guarantors
|
|
Elimination
|
|
Consolidated
|
||||||||||||
Sales—Outside
|
$
|
—
|
|
|
$
|
660,442
|
|
|
$
|
2,221,421
|
|
|
$
|
243,059
|
|
|
$
|
(2,372
|
)
|
|
$
|
3,122,550
|
|
Sales—Gas Royalty Interests
|
—
|
|
|
49,405
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
49,405
|
|
||||||
Sales—Purchased Gas
|
—
|
|
|
3,316
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,316
|
|
||||||
Freight—Outside
|
—
|
|
|
—
|
|
|
107,079
|
|
|
—
|
|
|
—
|
|
|
107,079
|
|
||||||
Other Income
|
613,340
|
|
|
56,946
|
|
|
316,592
|
|
|
21,639
|
|
|
(613,341
|
)
|
|
395,176
|
|
||||||
Total Revenue and Other Income
|
613,340
|
|
|
770,109
|
|
|
2,645,092
|
|
|
264,698
|
|
|
(615,713
|
)
|
|
3,677,526
|
|
||||||
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)
|
127,372
|
|
|
407,045
|
|
|
1,417,519
|
|
|
239,502
|
|
|
30,421
|
|
|
2,221,859
|
|
||||||
Gas Royalty Interests Costs
|
—
|
|
|
38,922
|
|
|
—
|
|
|
—
|
|
|
(55
|
)
|
|
38,867
|
|
||||||
Purchased Gas Costs
|
—
|
|
|
2,711
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,711
|
|
||||||
Related Party Activity
|
12,865
|
|
|
—
|
|
|
(22,466
|
)
|
|
1,814
|
|
|
7,787
|
|
|
—
|
|
||||||
Freight Expense
|
—
|
|
|
—
|
|
|
107,079
|
|
|
—
|
|
|
—
|
|
|
107,079
|
|
||||||
Selling, General and Administrative Expenses
|
—
|
|
|
40,101
|
|
|
49,222
|
|
|
1,417
|
|
|
—
|
|
|
90,740
|
|
||||||
Depreciation, Depletion and Amortization
|
12,172
|
|
|
202,956
|
|
|
209,923
|
|
|
2,064
|
|
|
—
|
|
|
427,115
|
|
||||||
Interest Expense
|
208,894
|
|
|
5,098
|
|
|
6,470
|
|
|
44
|
|
|
(464
|
)
|
|
220,042
|
|
||||||
Taxes Other Than Income
|
401
|
|
|
33,892
|
|
|
125,288
|
|
|
2,845
|
|
|
—
|
|
|
162,426
|
|
||||||
Total Costs
|
361,704
|
|
|
730,725
|
|
|
1,893,035
|
|
|
247,686
|
|
|
37,689
|
|
|
3,270,839
|
|
||||||
Earnings (Loss) Before Income Taxes
|
251,636
|
|
|
39,384
|
|
|
752,057
|
|
|
17,012
|
|
|
(653,402
|
)
|
|
406,687
|
|
||||||
Income Tax Expense (Benefit)
|
(136,834
|
)
|
|
15,021
|
|
|
204,105
|
|
|
6,436
|
|
|
—
|
|
|
88,728
|
|
||||||
Income (Loss) from Continuing Operations
|
388,470
|
|
|
24,363
|
|
|
547,952
|
|
|
10,576
|
|
|
(653,402
|
)
|
|
317,959
|
|
||||||
Income from Discontinued Operations, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
70,114
|
|
|
—
|
|
|
70,114
|
|
||||||
Net Income (Loss)
|
388,470
|
|
|
24,363
|
|
|
547,952
|
|
|
80,690
|
|
|
(653,402
|
)
|
|
388,073
|
|
||||||
Less: Net Loss Attributable to Noncontrolling Interest
|
—
|
|
|
397
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
397
|
|
||||||
Net Income (Loss) Attributable to CONSOL Energy Inc. Shareholders
|
$
|
388,470
|
|
|
$
|
24,760
|
|
|
$
|
547,952
|
|
|
$
|
80,690
|
|
|
$
|
(653,402
|
)
|
|
$
|
388,470
|
|
|
Parent
Issuer
|
|
CNX Gas
Guarantor
|
|
Other
Subsidiary
Guarantors
|
|
Non-
Guarantors
|
|
Elimination
|
|
Consolidated
|
||||||||||||
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Current Assets:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Cash and Cash Equivalents
|
$
|
17,491
|
|
|
$
|
3,352
|
|
|
$
|
159
|
|
|
$
|
860
|
|
|
$
|
—
|
|
|
$
|
21,862
|
|
Accounts and Notes Receivable:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Trade
|
—
|
|
|
58,126
|
|
|
—
|
|
|
370,202
|
|
|
—
|
|
|
428,328
|
|
||||||
Securitized
|
—
|
|
|
—
|
|
|
—
|
|
|
37,846
|
|
|
—
|
|
|
37,846
|
|
||||||
Notes Receivable
|
154
|
|
|
315,730
|
|
|
2,503
|
|
|
—
|
|
|
—
|
|
|
318,387
|
|
||||||
Other Receivables
|
6,335
|
|
|
214,748
|
|
|
33,289
|
|
|
5,159
|
|
|
(128,400
|
)
|
|
131,131
|
|
||||||
Inventories
|
—
|
|
|
14,133
|
|
|
121,311
|
|
|
35,364
|
|
|
—
|
|
|
170,808
|
|
||||||
Deferred Income Taxes
|
174,176
|
|
|
(26,072
|
)
|
|
(63,327
|
)
|
|
—
|
|
|
—
|
|
|
84,777
|
|
||||||
Restricted Cash
|
—
|
|
|
—
|
|
|
48,294
|
|
|
—
|
|
|
—
|
|
|
48,294
|
|
||||||
Prepaid Expenses
|
29,589
|
|
|
86,186
|
|
|
31,286
|
|
|
1,370
|
|
|
—
|
|
|
148,431
|
|
||||||
Current Assets of Discontinued Operations
|
—
|
|
|
—
|
|
|
—
|
|
|
149,230
|
|
|
—
|
|
|
149,230
|
|
||||||
Total Current Assets
|
227,745
|
|
|
666,203
|
|
|
173,515
|
|
|
600,031
|
|
|
(128,400
|
)
|
|
1,539,094
|
|
||||||
Property, Plant and Equipment:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Property, Plant and Equipment
|
216,448
|
|
|
5,956,207
|
|
|
5,923,723
|
|
|
25,179
|
|
|
—
|
|
|
12,121,557
|
|
||||||
Less-Accumulated Depreciation, Depletion and Amortization
|
126,048
|
|
|
960,613
|
|
|
2,508,769
|
|
|
18,069
|
|
|
—
|
|
|
3,613,499
|
|
||||||
Property, Plant and Equipment of Discontinued Operations, net
|
—
|
|
|
—
|
|
|
—
|
|
|
1,682,909
|
|
|
—
|
|
|
1,682,909
|
|
||||||
Total Property, Plant and Equipment-Net
|
90,400
|
|
|
4,995,594
|
|
|
3,414,954
|
|
|
1,690,019
|
|
|
—
|
|
|
10,190,967
|
|
||||||
Other Assets:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Restricted Cash
|
—
|
|
|
—
|
|
|
20,379
|
|
|
—
|
|
|
—
|
|
|
20,379
|
|
||||||
Investment in Affiliates
|
9,917,050
|
|
|
143,876
|
|
|
769,058
|
|
|
—
|
|
|
(10,607,154
|
)
|
|
222,830
|
|
||||||
Notes Receivable
|
239
|
|
|
—
|
|
|
25,738
|
|
|
—
|
|
|
—
|
|
|
25,977
|
|
||||||
Other
|
118,938
|
|
|
65,935
|
|
|
21,174
|
|
|
10,188
|
|
|
—
|
|
|
216,235
|
|
||||||
Other Assets of Discontinued Operations
|
—
|
|
|
—
|
|
|
—
|
|
|
782,112
|
|
|
—
|
|
|
782,112
|
|
||||||
Total Other Assets
|
10,036,227
|
|
|
209,811
|
|
|
836,349
|
|
|
792,300
|
|
|
(10,607,154
|
)
|
|
1,267,533
|
|
||||||
Total Assets
|
$
|
10,354,372
|
|
|
$
|
5,871,608
|
|
|
$
|
4,424,818
|
|
|
$
|
3,082,350
|
|
|
$
|
(10,735,554
|
)
|
|
$
|
12,997,594
|
|
|
Parent
Issuer
|
|
CNX Gas
Guarantor
|
|
Other
Subsidiary
Guarantors
|
|
Non-
Guarantors
|
|
Elimination
|
|
Consolidated
|
||||||||||||
Liabilities and Equity:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Current Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Accounts Payable
|
$
|
177,734
|
|
|
$
|
166,182
|
|
|
$
|
145,469
|
|
|
$
|
9,130
|
|
|
$
|
—
|
|
|
$
|
498,515
|
|
Accounts Payable (Recoverable)-Related Parties
|
3,599,216
|
|
|
23,981
|
|
|
(3,749,584
|
)
|
|
254,787
|
|
|
(128,400
|
)
|
|
—
|
|
||||||
Short-Term Notes Payable
|
25,073
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
25,073
|
|
||||||
Current Portion of Long-Term Debt
|
1,554
|
|
|
5,953
|
|
|
4,221
|
|
|
756
|
|
|
—
|
|
|
12,484
|
|
||||||
Accrued Income Taxes
|
20,488
|
|
|
13,731
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
34,219
|
|
||||||
Borrowings under Securitization Facility
|
—
|
|
|
—
|
|
|
—
|
|
|
37,846
|
|
|
—
|
|
|
37,846
|
|
||||||
Other Accrued Liabilities
|
135,407
|
|
|
57,074
|
|
|
343,739
|
|
|
9,528
|
|
|
—
|
|
|
545,748
|
|
||||||
Current Liabilities of Discontinued Operations
|
—
|
|
|
—
|
|
|
—
|
|
|
233,214
|
|
|
—
|
|
|
233,214
|
|
||||||
Total Current Liabilities
|
3,959,472
|
|
|
266,921
|
|
|
(3,256,155
|
)
|
|
545,261
|
|
|
(128,400
|
)
|
|
1,387,099
|
|
||||||
Long-Term Debt:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Long-Term Debt
|
3,004,798
|
|
|
—
|
|
|
118,802
|
|
|
—
|
|
|
—
|
|
|
3,123,600
|
|
||||||
Capital Lease Obligations
|
717
|
|
|
46,081
|
|
|
1,148
|
|
|
1,467
|
|
|
—
|
|
|
49,413
|
|
||||||
Long-Term Debt of Discontinued Operations
|
—
|
|
|
—
|
|
|
—
|
|
|
1,573
|
|
|
—
|
|
|
1,573
|
|
||||||
Total Long-Term Debt
|
3,005,515
|
|
|
46,081
|
|
|
119,950
|
|
|
3,040
|
|
|
—
|
|
|
3,174,586
|
|
||||||
Deferred Credits and Other Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Deferred Income Taxes
|
(884,310
|
)
|
|
439,725
|
|
|
771,270
|
|
|
—
|
|
|
—
|
|
|
326,685
|
|
||||||
Postretirement Benefits Other Than Pensions
|
—
|
|
|
—
|
|
|
882,600
|
|
|
—
|
|
|
—
|
|
|
882,600
|
|
||||||
Pneumoconiosis Benefits
|
—
|
|
|
—
|
|
|
114,136
|
|
|
—
|
|
|
—
|
|
|
114,136
|
|
||||||
Mine Closing
|
—
|
|
|
—
|
|
|
289,818
|
|
|
—
|
|
|
—
|
|
|
289,818
|
|
||||||
Gas Well Closing
|
—
|
|
|
80,097
|
|
|
65,905
|
|
|
—
|
|
|
—
|
|
|
146,002
|
|
||||||
Workers’ Compensation
|
—
|
|
|
—
|
|
|
60,090
|
|
|
306
|
|
|
—
|
|
|
60,396
|
|
||||||
Salary Retirement
|
218,004
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
218,004
|
|
||||||
Reclamation
|
—
|
|
|
—
|
|
|
47,965
|
|
|
—
|
|
|
—
|
|
|
47,965
|
|
||||||
Other
|
101,899
|
|
|
24,518
|
|
|
(8,110
|
)
|
|
—
|
|
|
—
|
|
|
118,307
|
|
||||||
Deferred Credits and Other Liabilities of Discontinued Operations
|
—
|
|
|
—
|
|
|
—
|
|
|
2,278,251
|
|
|
—
|
|
|
2,278,251
|
|
||||||
Total Deferred Credits and Other Liabilities
|
(564,407
|
)
|
|
544,340
|
|
|
2,223,674
|
|
|
2,278,557
|
|
|
—
|
|
|
4,482,164
|
|
||||||
Total CONSOL Energy Inc. Stockholders’ Equity
|
3,953,792
|
|
|
5,014,313
|
|
|
5,337,349
|
|
|
255,492
|
|
|
(10,607,154
|
)
|
|
3,953,792
|
|
||||||
Noncontrolling Interest
|
—
|
|
|
(47
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(47
|
)
|
||||||
Total Liabilities and Equity
|
$
|
10,354,372
|
|
|
$
|
5,871,608
|
|
|
$
|
4,424,818
|
|
|
$
|
3,082,350
|
|
|
$
|
(10,735,554
|
)
|
|
$
|
12,997,594
|
|
|
Parent
|
|
CNX Gas
Guarantor
|
|
Other Subsidiary Guarantors
|
|
Non-
Guarantors
|
|
Elimination
|
|
Consolidated
|
||||||||||||
Net Cash Provided by (Used in) Continuing Operations
|
$
|
(58,410
|
)
|
|
$
|
82,036
|
|
|
$
|
412,293
|
|
|
$
|
21,423
|
|
|
$
|
—
|
|
|
$
|
457,342
|
|
Net Cash Provided by Discontinued Operating Activities
|
—
|
|
|
—
|
|
|
—
|
|
|
270,771
|
|
|
—
|
|
|
270,771
|
|
||||||
Net Cash Provided by (Used in) Operating Activities
|
$
|
(58,410
|
)
|
|
$
|
82,036
|
|
|
$
|
412,293
|
|
|
$
|
292,194
|
|
|
$
|
—
|
|
|
$
|
728,113
|
|
Cash 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, Equity Affiliates
|
200,000
|
|
|
(37,400
|
)
|
|
13,949
|
|
|
—
|
|
|
(200,000
|
)
|
|
(23,451
|
)
|
||||||
Net Cash (Used in) Provided by Continuning Operations
|
$
|
150,027
|
|
|
$
|
(209,907
|
)
|
|
$
|
(411,995
|
)
|
|
$
|
254
|
|
|
$
|
(200,000
|
)
|
|
$
|
(671,621
|
)
|
Net Cash Used in Discontinued Investing Activities
|
—
|
|
|
—
|
|
|
—
|
|
|
(328,789
|
)
|
|
—
|
|
|
(328,789
|
)
|
||||||
Net Cash (Used in) Provided by Investing Activities
|
$
|
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 Stock
|
8,278
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8,278
|
|
||||||
Other Financing Activities
|
22,532
|
|
|
(5,504
|
)
|
|
(1,408
|
)
|
|
37,404
|
|
|
—
|
|
|
53,024
|
|
||||||
Net Cash (Used in) Provided by Continuing Operations
|
$
|
(111,468
|
)
|
|
$
|
(205,504
|
)
|
|
$
|
(1,408
|
)
|
|
$
|
37,404
|
|
|
$
|
200,000
|
|
|
$
|
(80,976
|
)
|
Net Cash Used in Discontinued Financing Activities
|
—
|
|
|
—
|
|
|
—
|
|
|
(601
|
)
|
|
—
|
|
|
(601
|
)
|
||||||
Net Cash (Used in) Provided by Financing Activities
|
$
|
(111,468
|
)
|
|
$
|
(205,504
|
)
|
|
$
|
(1,408
|
)
|
|
$
|
36,803
|
|
|
$
|
200,000
|
|
|
$
|
(81,577
|
)
|
|
Parent
Issuer
|
|
CNX Gas
Guarantor
|
|
Other
Subsidiary
Guarantors
|
|
Non-
Guarantors
|
|
Elimination
|
|
Consolidated
|
||||||||||||
Sales—Outside
|
$
|
—
|
|
|
$
|
751,767
|
|
|
$
|
3,009,104
|
|
|
$
|
234,998
|
|
|
$
|
(4,862
|
)
|
|
$
|
3,991,007
|
|
Sales—Gas Royalty Interests
|
—
|
|
|
66,929
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
66,929
|
|
||||||
Sales—Purchased Gas
|
$
|
—
|
|
|
$
|
4,344
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
4,344
|
|
Freight—Outside
|
—
|
|
|
—
|
|
|
175,633
|
|
|
—
|
|
|
—
|
|
|
175,633
|
|
||||||
Other Income
|
876,233
|
|
|
58,923
|
|
|
48,673
|
|
|
26,309
|
|
|
(871,006
|
)
|
|
139,132
|
|
||||||
Total Revenue and Other Income
|
876,233
|
|
|
881,963
|
|
|
3,233,410
|
|
|
261,307
|
|
|
(875,868
|
)
|
|
4,377,045
|
|
||||||
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion, and amortization shown below)
|
108,681
|
|
|
388,507
|
|
|
1,443,472
|
|
|
228,291
|
|
|
97,609
|
|
|
2,266,560
|
|
||||||
Gas Royalty Interests Costs
|
—
|
|
|
59,377
|
|
|
—
|
|
|
—
|
|
|
(46
|
)
|
|
59,331
|
|
||||||
Purchased Gas Costs
|
—
|
|
|
3,831
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,831
|
|
||||||
Related Party Activity
|
4,767
|
|
|
—
|
|
|
(25,720
|
)
|
|
1,986
|
|
|
18,967
|
|
|
—
|
|
||||||
Freight Expense
|
—
|
|
|
—
|
|
|
175,444
|
|
|
—
|
|
|
—
|
|
|
175,444
|
|
||||||
Selling, General and Administrative Expenses
|
—
|
|
|
50,429
|
|
|
62,729
|
|
|
1,485
|
|
|
—
|
|
|
114,643
|
|
||||||
Depreciation, Depletion and Amortization
|
12,194
|
|
|
206,821
|
|
|
209,159
|
|
|
2,403
|
|
|
—
|
|
|
430,577
|
|
||||||
Interest Expense
|
235,370
|
|
|
9,398
|
|
|
3,911
|
|
|
53
|
|
|
(388
|
)
|
|
248,344
|
|
||||||
Taxes Other Than Income
|
950
|
|
|
34,023
|
|
|
136,382
|
|
|
3,037
|
|
|
—
|
|
|
174,392
|
|
||||||
Transaction and Financing Fees
|
14,907
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
14,907
|
|
||||||
Loss on Debt Extinguishment
|
16,090
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
16,090
|
|
||||||
Total Costs
|
392,959
|
|
|
752,386
|
|
|
2,005,377
|
|
|
237,255
|
|
|
116,142
|
|
|
3,504,119
|
|
||||||
Earnings (Loss) Before Income Taxes
|
483,274
|
|
|
129,577
|
|
|
1,228,033
|
|
|
24,052
|
|
|
(992,010
|
)
|
|
872,926
|
|
||||||
Income Tax Expense (Benefit)
|
(149,223
|
)
|
|
51,876
|
|
|
279,500
|
|
|
9,098
|
|
|
—
|
|
|
191,251
|
|
||||||
Income (Loss) from Continuing Operations
|
632,497
|
|
|
77,701
|
|
|
948,533
|
|
|
14,954
|
|
|
(992,010
|
)
|
|
681,675
|
|
||||||
Loss from Discontinued Operations, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
(49,178
|
)
|
|
—
|
|
|
(49,178
|
)
|
||||||
Net Income (Loss) Attributable to CONSOL Energy Inc. Shareholders
|
$
|
632,497
|
|
|
$
|
77,701
|
|
|
$
|
948,533
|
|
|
$
|
(34,224
|
)
|
|
$
|
(992,010
|
)
|
|
$
|
632,497
|
|
|
Parent
|
|
CNX Gas
Guarantor
|
|
Other Subsidiary Guarantors
|
|
Non-
Guarantors
|
|
Elimination
|
|
Consolidated
|
||||||||||||
Net Cash Provided by (Used in) Continuing Operations
|
$
|
530,444
|
|
|
$
|
329,360
|
|
|
$
|
465,847
|
|
|
$
|
3,220
|
|
|
$
|
—
|
|
|
$
|
1,328,871
|
|
Net Cash Provided by Discontinued Operating Activities
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
198,735
|
|
|
$
|
—
|
|
|
198,735
|
|
|
Net Cash Provided by (Used in) Operating Activities
|
$
|
530,444
|
|
|
$
|
329,360
|
|
|
$
|
465,847
|
|
|
$
|
201,955
|
|
|
$
|
—
|
|
|
$
|
1,527,606
|
|
Cash Flows from Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Capital Expenditures
|
$
|
(41,172
|
)
|
|
$
|
(664,612
|
)
|
|
$
|
(472,591
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(1,178,375
|
)
|
Proceeds From Sales of Assets
|
10
|
|
|
746,956
|
|
|
(1,155
|
)
|
|
1,474
|
|
|
—
|
|
|
747,285
|
|
||||||
Distributions from, net of Investments in, Equity Affiliates
|
—
|
|
|
50,626
|
|
|
5,250
|
|
|
—
|
|
|
—
|
|
|
55,876
|
|
||||||
Net Cash (Used in) Provided by Continuing Operations
|
$
|
(41,162
|
)
|
|
$
|
132,970
|
|
|
$
|
(468,496
|
)
|
|
$
|
1,474
|
|
|
$
|
—
|
|
|
$
|
(375,214
|
)
|
Net Cash Used in Discontinued Investing Activities
|
—
|
|
|
—
|
|
|
—
|
|
|
(203,310
|
)
|
|
—
|
|
|
(203,310
|
)
|
||||||
Net Cash (Used in) Provided by Investing Activities
|
$
|
(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 Notes
|
250,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
250,000
|
|
||||||
Payments on Long Term Notes, including Redemption Premium
|
(265,785
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(265,785
|
)
|
||||||
Other Financing Activities
|
5,749
|
|
|
(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 Financing Activities
|
—
|
|
|
—
|
|
|
—
|
|
|
(547
|
)
|
|
—
|
|
|
(547
|
)
|
||||||
Net Cash Used in Financing Activities
|
$
|
(461,392
|
)
|
|
$
|
(142,162
|
)
|
|
$
|
(1,246
|
)
|
|
$
|
(1,340
|
)
|
|
$
|
—
|
|
|
$
|
(606,140
|
)
|
|
Parent
|
|
CNX Gas
Guarantor
|
|
Other
Subsidiary
Guarantors
|
|
Non-
Guarantors
|
|
Elimination
|
|
Consolidated
|
||||||||||||
Net Income (Loss)
|
$
|
660,442
|
|
|
$
|
(2,624
|
)
|
|
$
|
455,935
|
|
|
$
|
585,616
|
|
|
$
|
(1,040,313
|
)
|
|
$
|
659,056
|
|
Other Comprehensive Income (Loss):
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Actuarially Determined Long-Term Liability Adjustments
|
456,493
|
|
|
—
|
|
|
456,493
|
|
|
—
|
|
|
(456,493
|
)
|
|
456,493
|
|
||||||
Net Increase (Decrease) in the Value of Cash Flow Hedge
|
45,631
|
|
|
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
|
)
|
|
$
|
422,225
|
|
Comprehensive Income (Loss)
|
1,082,667
|
|
|
(36,892
|
)
|
|
912,428
|
|
|
585,616
|
|
|
(1,462,538
|
)
|
|
1,081,281
|
|
||||||
Less: Comprehensive Loss Attributable to Noncontrolling Interest
|
—
|
|
|
1,386
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,386
|
|
||||||
Comprehensive Income (Loss) Attributable to CONSOL Energy Inc. Shareholders
|
$
|
1,082,667
|
|
|
$
|
(35,506
|
)
|
|
$
|
912,428
|
|
|
$
|
585,616
|
|
|
$
|
(1,462,538
|
)
|
|
$
|
1,082,667
|
|
|
Parent
|
|
CNX Gas
Guarantor
|
|
Other
Subsidiary
Guarantors
|
|
Non-Guarantors
|
|
Elimination
|
|
Consolidated
|
||||||||||||
Net Income (Loss)
|
$
|
388,470
|
|
|
$
|
24,363
|
|
|
$
|
547,952
|
|
|
$
|
80,690
|
|
|
$
|
(653,402
|
)
|
|
$
|
388,073
|
|
Other Comprehensive Income (Loss):
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Actuarially Determined Long-Term Liability Adjustments
|
129,231
|
|
|
—
|
|
|
129,231
|
|
|
—
|
|
|
(129,231
|
)
|
|
129,231
|
|
||||||
Net Increase (Decrease) in the Value of Cash Flow Hedge
|
114,240
|
|
|
114,240
|
|
|
—
|
|
|
—
|
|
|
(114,240
|
)
|
|
114,240
|
|
||||||
Reclassification of Cash Flow Hedge from OCI to Earnings
|
(189,259
|
)
|
|
(189,259
|
)
|
|
—
|
|
|
—
|
|
|
189,259
|
|
|
(189,259
|
)
|
||||||
Other Comprehensive Income (Loss):
|
$
|
54,212
|
|
|
$
|
(75,019
|
)
|
|
$
|
129,231
|
|
|
$
|
—
|
|
|
$
|
(54,212
|
)
|
|
$
|
54,212
|
|
Comprehensive Income (Loss)
|
$
|
442,682
|
|
|
$
|
(50,656
|
)
|
|
$
|
677,183
|
|
|
$
|
80,690
|
|
|
$
|
(707,614
|
)
|
|
$
|
442,285
|
|
Less: Comprehensive Income Attributable to Noncontrolling Interest
|
—
|
|
|
397
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
397
|
|
||||||
Comprehensive Income (Loss) Attributable to CONSOL Energy Inc. Shareholders
|
$
|
442,682
|
|
|
$
|
(50,259
|
)
|
|
$
|
677,183
|
|
|
$
|
80,690
|
|
|
$
|
(707,614
|
)
|
|
$
|
442,682
|
|
|
Parent
|
|
CNX Gas
Guarantor
|
|
Other
Subsidiary
Guarantors
|
|
Non-
Guarantors
|
|
Elimination
|
|
Consolidated
|
||||||||||||
Net Income (Loss)
|
$
|
632,497
|
|
|
$
|
77,701
|
|
|
$
|
948,533
|
|
|
$
|
(34,224
|
)
|
|
$
|
(992,010
|
)
|
|
$
|
632,497
|
|
Other 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 Hedge
|
200,700
|
|
|
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
|
)
|
|
$
|
72,784
|
|
Comprehensive Income (Loss) Attributable to CONSOL Energy Inc. Shareholders
|
$
|
705,281
|
|
|
$
|
183,394
|
|
|
$
|
915,720
|
|
|
$
|
(34,224
|
)
|
|
$
|
(1,064,890
|
)
|
|
$
|
705,281
|
|
|
December 31,
|
|
December 31,
|
|
|
||||
|
2013
|
|
2012
|
|
Location on Balance Sheet
|
||||
Reimbursement for CONE Expenses
|
$
|
(2,168
|
)
|
|
$
|
(1,336
|
)
|
|
Accounts Receivable–Other
|
Reimbursement for Services Provided to CONE
|
(265
|
)
|
|
(341
|
)
|
|
Accounts Receivable–Other
|
||
CONE Gathering Capital Reimbursement
|
—
|
|
|
(18
|
)
|
|
Accounts Receivable–Other
|
||
CONE Gathering Fee Payable
|
7,881
|
|
|
4,837
|
|
|
Accounts Payable
|
||
Net Payable due CONE
|
$
|
5,448
|
|
|
$
|
3,142
|
|
|
|
|
|
As of December 31,
|
||||||
|
|
2013
|
|
2012
|
||||
Proven properties
|
|
$
|
1,670,404
|
|
|
$
|
1,596,838
|
|
Unproven properties
|
|
1,463,406
|
|
|
1,266,017
|
|
||
Intangible drilling costs
|
|
1,937,336
|
|
|
1,550,297
|
|
||
Wells and related equipment
|
|
688,548
|
|
|
492,364
|
|
||
Gathering assets
|
|
1,058,008
|
|
|
1,006,882
|
|
||
Gas Well Plugging
|
|
113,481
|
|
|
70,753
|
|
||
Total Property, Plant and Equipment
|
|
6,931,183
|
|
|
5,983,151
|
|
||
Accumulated Depreciation, Depletion and Amortization
|
|
(1,187,409
|
)
|
|
(959,291
|
)
|
||
Net Capitalized Costs
|
|
$
|
5,743,774
|
|
|
$
|
5,023,860
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2013
|
|
2012
|
|
2011
|
||||||
Property acquisitions
|
|
|
|
|
|
|
||||||
Proven properties
|
|
$
|
—
|
|
|
$
|
50,005
|
|
|
$
|
6,673
|
|
Unproven properties
|
|
260,477
|
|
|
28,634
|
|
|
58,731
|
|
|||
Development
|
|
629,100
|
|
|
339,608
|
|
|
463,401
|
|
|||
Exploration
|
|
95,413
|
|
|
130,312
|
|
|
131,419
|
|
|||
Total
|
|
$
|
984,990
|
|
|
$
|
548,559
|
|
|
$
|
660,224
|
|
(*)
|
Includes costs incurred whether capitalized or expensed.
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2013
|
|
2012
|
|
2011
|
||||||
Production Revenue
|
|
$
|
740,869
|
|
|
$
|
660,442
|
|
|
$
|
751,767
|
|
Royalty Interest Gas Revenue
|
|
63,202
|
|
|
49,405
|
|
|
66,929
|
|
|||
Purchased Gas Revenue
|
|
6,531
|
|
|
3,316
|
|
|
4,344
|
|
|||
Total Revenue
|
|
810,602
|
|
|
713,163
|
|
|
823,040
|
|
|||
Lifting Costs
|
|
96,600
|
|
|
90,835
|
|
|
106,477
|
|
|||
Ad Valorem, Severance & Other Taxes
|
|
28,677
|
|
|
26,145
|
|
|
26,261
|
|
|||
Gathering Costs
|
|
201,023
|
|
|
160,575
|
|
|
142,339
|
|
|||
Royalty Interest Gas Costs
|
|
53,069
|
|
|
38,922
|
|
|
59,377
|
|
|||
Direct Administrative, Selling & Other Costs
|
|
49,092
|
|
|
47,567
|
|
|
60,355
|
|
|||
Other Costs
|
|
61,119
|
|
|
39,029
|
|
|
18,095
|
|
|||
Purchased Gas Costs
|
|
4,837
|
|
|
2,711
|
|
|
3,831
|
|
|||
DD&A
|
|
229,562
|
|
|
202,956
|
|
|
206,821
|
|
|||
Total Costs
|
|
723,979
|
|
|
608,740
|
|
|
623,556
|
|
|||
Pre-tax Operating Income
|
|
86,623
|
|
|
104,423
|
|
|
199,484
|
|
|||
Income Taxes
|
|
32,917
|
|
|
39,827
|
|
|
79,873
|
|
|||
Results of Operations for Producing Activities excluding Corporate and Interest Costs
|
|
$
|
53,706
|
|
|
$
|
64,596
|
|
|
$
|
119,611
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2013
|
|
2012
|
|
2011
|
||||||
Production (MMcfe)
|
|
172,380
|
|
|
156,325
|
|
|
153,504
|
|
|||
Average gas sales price before effects of financial settlements (per Mcf)
|
|
$
|
3.85
|
|
|
$
|
3.00
|
|
|
$
|
4.27
|
|
Average effects of financial settlements (per Mcf)
|
|
$
|
0.45
|
|
|
$
|
1.22
|
|
|
$
|
0.63
|
|
Average gas sales price including effects of financial settlements (per Mcf)
|
|
$
|
4.30
|
|
|
$
|
4.22
|
|
|
$
|
4.90
|
|
Average lifting costs, excluding ad valorem and severance taxes (per Mcf)
|
|
$
|
0.56
|
|
|
$
|
0.58
|
|
|
$
|
0.68
|
|
|
|
Gross
|
|
Net(1)
|
||
Producing Wells (including gob wells)
|
|
15,063
|
|
|
12,874
|
|
Proved Developed Acreage
|
|
542,388
|
|
|
527,693
|
|
Proved Undeveloped Acreage
|
|
105,019
|
|
|
59,346
|
|
Unproved 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 as we further develop title to and further confirm our rights with respect to our various properties in anticipation of development. We believe that our assumptions and methodology in this regard are reasonable.
|
|
|
|
|
|
|
Condensate
|
|
Consolidated
|
||||
|
|
Natural Gas
|
|
NGLs
|
|
& Crude Oil
|
|
Operations
|
||||
|
|
(MMcfe)
|
|
(Mbbls)
|
|
(Mbbls)
|
|
(MMcfe)
|
||||
Balance December 31, 2010
|
|
3,724,361
|
|
|
—
|
|
|
1,206
|
|
|
3,731,597
|
|
Revisions (a)
|
|
(76,486
|
)
|
|
25
|
|
|
416
|
|
|
(73,837
|
)
|
Price Changes
|
|
(9,976
|
)
|
|
—
|
|
|
—
|
|
|
(9,976
|
)
|
Extensions and Discoveries (c)
|
|
517,023
|
|
|
—
|
|
|
27
|
|
|
517,178
|
|
Production
|
|
(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
|
|
|
3,480,027
|
|
Revisions (b)
|
|
243,442
|
|
|
469
|
|
|
(710
|
)
|
|
241,989
|
|
Price Changes
|
|
(526,608
|
)
|
|
—
|
|
|
(1
|
)
|
|
(526,611
|
)
|
Extensions and Discoveries (c)
|
|
873,104
|
|
|
12,992
|
|
|
553
|
|
|
954,378
|
|
Production
|
|
(155,052
|
)
|
|
(111
|
)
|
|
(100
|
)
|
|
(156,325
|
)
|
Sales of Reserves In-Place
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Balance December 31, 2012 (d)
|
|
3,905,437
|
|
|
13,375
|
|
|
1,297
|
|
|
3,993,458
|
|
Revisions (b)
|
|
176,045
|
|
|
(1,017
|
)
|
|
336
|
|
|
171,953
|
|
Price Changes
|
|
104,728
|
|
|
4
|
|
|
1
|
|
|
104,757
|
|
Extensions and Discoveries (c)
|
|
1,567,634
|
|
|
9,623
|
|
|
1,343
|
|
|
1,633,426
|
|
Production
|
|
(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
|
|
|
2,135,805
|
|
December 31, 2012
|
|
2,149,912
|
|
|
1,717
|
|
|
878
|
|
|
2,165,483
|
|
December 31, 2013
|
|
2,470,412
|
|
|
5,939
|
|
|
1,375
|
|
|
2,514,294
|
|
|
|
|
|
|
|
|
|
|
||||
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
||||
December 31, 2011
|
|
1,344,222
|
|
|
—
|
|
|
—
|
|
|
1,344,222
|
|
December 31, 2012
|
|
1,755,525
|
|
|
12,075
|
|
|
—
|
|
|
1,827,975
|
|
December 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 and reservoirs. These changes were partially offset by upward revisions attributable to efficiencies in operations and well performance and had the total affect of a negative revision for 2011.
|
(b)
|
Revisions are primarily due to corporate planning changes that affect the number of wells (5-Years) forecasted to be drilled in our various areas and reservoirs. These changes along with upward revisions attributable to efficiencies in operations and well performance and had the total affect of the positive revisions for 2013 and 2012.
|
(c)
|
Extensions and Discoveries are primarily due to the addition of wells on our Marcellus Shale acreage more than one offset location away with reliable technology.
|
(d)
|
Proved developed and proved undeveloped gas reserves are defined by SEC Rule 4.10(a) of Regulation S-X. Generally, these reserves would be commercially recovered under current economic conditions, operating methods and government regulations. CONSOL Energy cautions that there are many inherent uncertainties in estimating proved reserve quantities, projecting future production rates and timing of development expenditures. Proved oil and gas reserves are estimated quantities of natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions and government regulations. Proved developed reserves are those reserves expected to be recovered through existing wells, with existing equipment and operating methods.
|
|
|
For the Year
|
|
|
|
Ended
|
|
|
|
December 31,
|
|
|
|
2013
|
|
Proved Undeveloped Reserves (MMcfe)
|
|
|
|
Beginning proved undeveloped reserves
|
|
1,827,975
|
|
Undeveloped reserves transferred to developed(a)
|
|
(230,333
|
)
|
Price Changes
|
|
11,410
|
|
Plan and other revisions (b)
|
|
88,187
|
|
Extension and discoveries (c)
|
|
1,519,681
|
|
Ending 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 year ended December 31, 2013 related to undeveloped reserves that were transferred to developed.
|
(c)
|
Extensions and discoveries include approximately 683 Bcfe which were initially classified as unproved related to the DTI and Airport lease acquisitions. These reserves were subsequently reclassified to proved undeveloped reserves utilizing reliable technologies which include wire line open hole log data, performance data, log cross sections, core data, and statistical analysis. The statistical method utilized production performance from Consol Energy's and competitors' wells. Geophysical data include data from Consol's wells, published documents, state data-sites and were used to confirm continuity of the formation.
|
(d)
|
Included in proved undeveloped reserves at December 31, 2013 are approximately 226,063 MMcfe of reserves that have been reported for more than five years. These reserves specifically relate to CONSOL Energy's Buchanan Mine, more specifically, to GOB (a rubble zone formed in the cavity created by the extraction of coal) production due to a complex fracture being generated in the overburden strata above the mined seam. Mining operations take a significant amount of time and our GOB forecasts are consistent with the future plans of the Buchanan Mine. Evidence also exists that supports the continual operation of the mine beyond the current plan, unless there was an extreme circumstance which resulted from an external factor. These reasons constitute that specific circumstances exist to continue recognizing these reserves for CONSOL Energy.
|
|
|
December 31,
|
||||||||||
|
|
2013
|
|
2012
|
|
2011
|
||||||
Costs reclassified to wells, equipment and facilities based on the determination of proved reserves
|
|
$
|
12,140
|
|
|
$
|
14,447
|
|
|
$
|
189
|
|
Costs expensed due to determination of dry hole or abandonment of project
|
|
$
|
8,596
|
|
|
$
|
3,320
|
|
|
$
|
5,108
|
|
|
|
December 31,
|
||||||||||
|
|
2013
|
|
2012
|
|
2011
|
||||||
Future Cash Flows:
|
|
|
|
|
|
|
||||||
Revenues
|
|
$
|
21,602,594
|
|
|
$
|
11,777,550
|
|
|
$
|
14,804,398
|
|
Production 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
|
|
|
4,877,499
|
|
|||
Discounted 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
|
|
|
$
|
1,747,181
|
|
|
|
December 31,
|
||||||||||
|
|
2013
|
|
2012
|
|
2011
|
||||||
Balance at beginning of period
|
|
$
|
736,206
|
|
|
$
|
1,747,181
|
|
|
$
|
1,660,821
|
|
Net 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
|
|
|
324,755
|
|
|||
Net change due to (divestiture) acquisition
|
|
—
|
|
|
—
|
|
|
(559,132
|
)
|
|||
Development costs incurred during the period
|
|
625,824
|
|
|
333,640
|
|
|
463,401
|
|
|||
Difference in previously estimated development costs compared to actual costs incurred during the period
|
|
(123,976
|
)
|
|
(96,749
|
)
|
|
154,137
|
|
|||
Changes in estimated future development costs
|
|
(486,518
|
)
|
|
(153,104
|
)
|
|
155,619
|
|
|||
Net change in future income taxes
|
|
(578,951
|
)
|
|
619,045
|
|
|
130,746
|
|
|||
Accretion of discount and other
|
|
61,539
|
|
|
(39,203
|
)
|
|
56,698
|
|
|||
Total discounted cash flow at end of period
|
|
$
|
1,680,811
|
|
|
$
|
736,206
|
|
|
$
|
1,747,181
|
|
|
|
Millions of Tons
|
|||||||||||||
|
|
For the Year Ended December 31,
|
|||||||||||||
|
|
2013
|
|
|
2012
|
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
Proved and probable reserves at beginning of period
|
|
4,229
|
|
|
4,314
|
|
|
4,229
|
|
|
4,350
|
|
|
4,372
|
|
Purchased reserves
|
|
1
|
|
|
—
|
|
|
6
|
|
|
4
|
|
|
5
|
|
Reserves sold in place
|
|
(1,199
|
)
|
|
(155
|
)
|
|
—
|
|
|
(41
|
)
|
|
(3
|
)
|
Production
|
|
(55
|
)
|
|
(55
|
)
|
|
(62
|
)
|
|
(62
|
)
|
|
(58
|
)
|
Revisions and other changes
|
|
56
|
|
|
125
|
|
|
141
|
|
|
(22
|
)
|
|
34
|
|
Consolidated 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
|
|
|
|
Three Months Ended
|
||||||||||||||
|
|
March 31,
|
|
June 30,
|
|
September 30,
|
|
December 31,
|
||||||||
|
|
2013
|
|
2013
|
|
2013
|
|
2013
|
||||||||
Sales
|
|
$
|
799,997
|
|
|
$
|
759,948
|
|
|
$
|
753,080
|
|
|
$
|
772,258
|
|
Freight Revenue
|
|
$
|
14,061
|
|
|
$
|
10,125
|
|
|
$
|
11,563
|
|
|
$
|
3,946
|
|
Cost of Goods Sold and Other Operating Charges (including Gas Royalty Interests' Costs and Purchased Gas Costs)
|
|
$
|
612,000
|
|
|
$
|
552,126
|
|
|
$
|
560,247
|
|
|
$
|
562,386
|
|
Freight Expense
|
|
$
|
14,061
|
|
|
$
|
10,125
|
|
|
$
|
11,563
|
|
|
$
|
3,946
|
|
(Loss) Income from Continuing Operations
|
|
$
|
(3,725
|
)
|
|
$
|
8,562
|
|
|
$
|
(72,169
|
)
|
|
$
|
146,595
|
|
Income (Loss) from Discontinued Operations
|
|
$
|
1,904
|
|
|
$
|
(21,375
|
)
|
|
$
|
8,120
|
|
|
$
|
591,144
|
|
Net (Loss) Income Attributable to CONSOL Energy Inc Shareholders
|
|
$
|
(1,564
|
)
|
|
$
|
(12,526
|
)
|
|
$
|
(63,651
|
)
|
|
$
|
738,183
|
|
Earnings Per Share
|
|
|
|
|
|
|
|
|
||||||||
Basic:
|
|
|
|
|
|
|
|
|
||||||||
(Loss) Income from Continuing Operations
|
|
$
|
(0.02
|
)
|
|
$
|
0.04
|
|
|
$
|
(0.31
|
)
|
|
$
|
0.64
|
|
Income (Loss) from Discontinued Operations
|
|
$
|
0.01
|
|
|
$
|
(0.09
|
)
|
|
$
|
0.03
|
|
|
$
|
2.58
|
|
Net (Loss) Income
|
|
$
|
(0.01
|
)
|
|
$
|
(0.05
|
)
|
|
$
|
(0.28
|
)
|
|
$
|
3.22
|
|
Dilutive:
|
|
|
|
|
|
|
|
|
||||||||
(Loss) Income from Continuing Operations
|
|
$
|
(0.02
|
)
|
|
$
|
0.04
|
|
|
$
|
(0.31
|
)
|
|
$
|
0.64
|
|
Income (Loss) from Discontinued Operations
|
|
$
|
0.01
|
|
|
$
|
(0.09
|
)
|
|
$
|
0.03
|
|
|
$
|
2.56
|
|
Net (Loss) Income
|
|
$
|
(0.01
|
)
|
|
$
|
(0.05
|
)
|
|
$
|
(0.28
|
)
|
|
$
|
3.20
|
|
|
|
Three Months Ended
|
||||||||||||||
|
|
March 31,
|
|
June 30,
|
|
September 30,
|
|
December 31,
|
||||||||
|
|
2012
|
|
2012
|
|
2012
|
|
2012
|
||||||||
Sales
|
|
$
|
878,118
|
|
|
$
|
807,198
|
|
|
$
|
681,717
|
|
|
$
|
808,238
|
|
Freight Revenue
|
|
$
|
49,293
|
|
|
$
|
49,472
|
|
|
$
|
27,430
|
|
|
$
|
13,426
|
|
Cost of Goods Sold and Other Operating Charges (including Gas Royalty Interests' Costs and Purchased Gas Costs)
|
|
$
|
601,723
|
|
|
$
|
565,601
|
|
|
$
|
543,158
|
|
|
$
|
557,094
|
|
Freight Expense
|
|
$
|
49,293
|
|
|
$
|
49,472
|
|
|
$
|
27,430
|
|
|
$
|
13,426
|
|
Income (Loss) from Continuing Operations
|
|
$
|
80,906
|
|
|
$
|
155,789
|
|
|
$
|
(26,316
|
)
|
|
$
|
107,580
|
|
Income (Loss) from Discontinued Operations
|
|
$
|
16,290
|
|
|
$
|
(3,050
|
)
|
|
$
|
14,814
|
|
|
$
|
42,060
|
|
Net Income (Loss) Attributable to CONSOL Energy Inc Shareholders
|
|
$
|
97,196
|
|
|
$
|
152,739
|
|
|
$
|
(11,368
|
)
|
|
$
|
149,903
|
|
Earnings Per Share
|
|
|
|
|
|
|
|
|
||||||||
Basic:
|
|
|
|
|
|
|
|
|
||||||||
Income (Loss) from Continuing Operations
|
|
$
|
0.36
|
|
|
$
|
0.68
|
|
|
$
|
(0.12
|
)
|
|
$
|
0.47
|
|
Income (Loss) from Discontinued Operations
|
|
$
|
0.07
|
|
|
$
|
(0.01
|
)
|
|
$
|
0.07
|
|
|
$
|
0.19
|
|
Net Income (Loss)
|
|
$
|
0.43
|
|
|
$
|
0.67
|
|
|
$
|
(0.05
|
)
|
|
$
|
0.66
|
|
Dilutive:
|
|
|
|
|
|
|
|
|
||||||||
Income (Loss) from Continuing Operations
|
|
$
|
0.35
|
|
|
$
|
0.68
|
|
|
$
|
(0.12
|
)
|
|
$
|
0.47
|
|
Income (Loss) from Discontinued Operations
|
|
$
|
0.07
|
|
|
$
|
(0.01
|
)
|
|
$
|
0.07
|
|
|
$
|
0.18
|
|
Net Income (Loss)
|
|
$
|
0.42
|
|
|
$
|
0.67
|
|
|
$
|
(0.05
|
)
|
|
$
|
0.65
|
|
ITEM 9.
|
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES
|
ITEM 9A.
|
CONTROLS AND PROCEDURES
|
ITEM 9B.
|
OTHER INFORMATION
|
ITEM 10.
|
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
|
Name
|
|
Age
|
|
Position
|
J. Brett Harvey
|
|
63
|
|
Chairman of the Board and Chief Executive Officer
|
Nicholas J. DeIuliis
|
|
45
|
|
President
|
Stephen W. Johnson
|
|
55
|
|
Executive Vice President - Chief Legal and Corporate Affairs Officer
|
David M. Khani
|
|
50
|
|
Executive Vice President and Chief Financial Officer
|
James C. Grech
|
|
52
|
|
Executive Vice President and Chief Commercial Officer
|
ITEM 11.
|
EXECUTIVE COMPENSATION
|
ITEM 12.
|
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
|
ITEM 13.
|
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
|
ITEM 14.
|
PRINCIPAL ACCOUNTING FEES AND SERVICES
|
ITEM 15.
|
EXHIBIT INDEX
|
(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 to Exhibit 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 by reference 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 (file no. 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 on May 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 Scotia Trust 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., Dominion Coalbed Methane, Inc., Dominion Appalachian Development, LLC, Dominion Appalachian Development Properties, LLC, CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee, with respect to the 8.00% Senior Notes due 2017, incorporated by reference 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 Gas Corporation, Coalfield Pipeline Company, Knox Energy, LLC, MOB Corporation, CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company 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., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust 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 August 29, 2011.
|
4.50
|
|
Indenture, dated as of April 1, 2010, among CONSOL Energy, Inc., the Subsidiary Guarantors named therein and The Bank of Nova Scotia Trust 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., Dominion Coalbed Methane, Inc., Dominion Appalachian Development, LLC, Dominion Appalachian Development Properties, LLC, CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee, with respect to the 8.25% Senior Notes due 2020, incorporated by reference 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 Gas Corporation, Coalfield Pipeline Company, Knox Energy, LLC, MOB Corporation, CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company 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., certain subsidiaries 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 Trust Company 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 (file no. 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., certain subsidiaries 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 attached thereto 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 attached thereto and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as Representative of the Initial Purchasers, incorporated by reference to Exhibit 4.2 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 Scotia Trust 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 Scotia Trust 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 Scotia Trust 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 (file no. 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 of CONSOL Energy Inc. signatory thereto, Wells Fargo Bank, National Association, as Successor Trustee to The Bank of Nova Scotia Trust Company of New York, and The Bank of Nova Scotia Trust Company of New York, as Resigning Trustee (related to the Indenture dated as of April 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 Notes due 2020, and the Indenture dated as of March 9, 2011 with respect to the 6.375% Senior Notes due 2021), incorporated by reference to Exhibit 4.4 of Form 10-Q (file no. 001-14901) filed on November 1, 2013.
|
10.1
|
|
Purchase and Sale Agreement, dated as of April 30, 2003, by and among CONSOL Energy Inc., CONSOL Sales Company, CONSOL of Kentucky 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 Marine Terminals Inc. and CNX Funding Corporation, incorporated by reference to Exhibit 10.30 to Form 10-Q (file no. 001-14901) for the quarter ended 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 Energy Sales Company, CONSOL of Kentucky 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 and CNX Marine Terminals Inc., each an “Originator” and CNX Funding Corporation, incorporated by reference to Exhibit 10.31 to Form 10-K for the year 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. (“CONSOL Energy”), CONSOL Energy Sales Company, CONSOL of Kentucky Inc., Consol Pennsylvania Coal Company LLC, Consolidation Coal Company, Island Creek Coal Company, McElroy Coal Company, Keystone Coal Mining Corporation, Eighty-Four Mining Company and CNX Marine Terminals Inc. (each an “Existing Originator”) and collectively the “Existing Originators”), Fola Coal Company, LLC., Little Eagle Coal Company, LLC., Mon River Towing, Inc., Terry Eagle Coal Company, LLC., Tri-River Fleeting Harbor Service, Inc., and Twin Rivers Towing 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 Energy Inc., CONSOL Energy Sales Company, CONSOL of Kentucky Inc., CONSOL Pennsylvania Coal Company LLC, Consolidated Coal Company, 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 Rivers Towing Company and CNX Funding Corporation, incorporated by reference to Exhibit 10.6 to Form 8-K (file no. 001-14901) filed on March 16, 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 and its subsidiaries) and (b) CNX Gas Corporation and its subsidiaries, incorporated by reference to Exhibit 99(D)(11) of the Schedule TO filed on April 28, 2010.
|
10.6
|
|
Amended and Restated Receivable Purchase Agreement, dated as of April 30, 2007, by and among CNX Funding Corporation, CONSOL Energy Inc., CONSOL Energy Sales Company, CONSOL of Kentucky 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 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 Funding Corporation, CONSOL Energy Inc., as the initial Servicer, the Conduit Purchasers listed on the 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 10.34 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 Funding Corporation, CONSOL Energy Inc., as the initial Servicer (in such capacity, the “Servicer”), the Conduit Purchasers listed on the 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 10.35 to Form 10-K for the year ended December 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 CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer, the various new sub-servicers listed on the signature pages thereto, the Conduit Purchasers listed on the 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 10.36 to 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 on the signature pages thereto, the Purchaser Agents listed on the signature pages thereto, the LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator and as LC Bank, incorporated by reference to Exhibit 10.4 to Form 8-K (file no. 001-14901) filed on March 16, 2010.
|
10.11
|
|
Fifth Amendment to Amended and Restated Receivables Purchase Agreement and Waiver, dated as of March 12, 2010, 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 on the 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 10.5 to Form 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 Conduit Purchasers listed on the signature pages of the Amendment, the Purchaser Agents listed on the signature pages of the Amendment, the LC 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 10.13 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 Funding Corporation, CONSOL Energy Inc., as the initial Servicer, the various Sub-Servicers listed on the signature pages of the Amendment, the Conduit Purchasers listed on the signature pages of the Amendment, the Purchaser Agents listed on the signature pages of the Amendment, the LC 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, National Association 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., incorporated by 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, the Lenders Party thereto, PNC Bank, National Association, as the Administrative Agent, Bank of America, N.A., as the Syndication Agent, The Bank of Nova Scotia, The Royal Bank of Scotland PLC and Sovereign Bank, as the Co-Documentation Agents, and PNC Capital Markets LLC 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 Designated Subsidiaries, Wilmington Trust Company, as Corporate Trustee and David A. Vanaskey, as Individual Trustee, incorporated by reference to Exhibit 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 pages thereto and each other persons and entities that become bound thereto from time to time by joinder, assumption, or otherwise and Wilmington Trust 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 the signature pages thereto and each other persons and entities that become bound thereto from time to time by joinder, assumption, or otherwise and Wilmington 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 signature pages thereto and each of the other persons and entities that become bound thereby from time to time by joinder, assumption, or otherwise and Wilmington 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 among each of the pledgors listed on the signature pages thereto and each other persons and entities that become bound thereto from time to time by joinder, 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 assignor and PNC Bank, National Association as assignee, incorporated by reference to Exhibit 2.1 to Form 8-K (file no. 001-14901) filed on April 18, 2011.
|
10.24
|
|
Guaranty and Suretyship Agreement, dated as of April 30, 2003, by CONSOL Energy Inc., as guarantor in favor of CNX Funding Corporation, 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 the undersigned thereto and each of the other persons which become Guarantors thereunder from time to time in favor of PNC Bank, National Association, 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 on February 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 its subsidiaries, 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 existing agents, PNC Bank, National Association as Collateral Trustee and CONSOL Energy Inc. and certain of its subsidiaries, incorporated by reference 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, the Lenders Party thereto, PNC Bank, National Association, as the Administrative Agent, Bank of America, N.A., as the Syndication Agent, The Bank of Nova Scotia, The Royal Bank of Scotland PLC and Wells Fargo Bank, N.A., as the Co-Documentation Agents, and PNC Capital Markets LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as Bookrunners and Joint Lead Arrangers, incorporated by reference to Exhibit 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 party thereto and PNC Bank, National Association, as Administrative Agent, incorporated by reference to Exhibit 10.29 to Form 10-K for the year ended 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 Trust Company, as Corporate Trustee and David A. Vanaskey, as Individual Trustee, incorporated by reference to Exhibit 2.1 to the CNX Gas Corporation 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 and entities that become bound thereby from time to time by joinder, assumption or otherwise and Wilmington Trust Company, as Collateral Trustee, 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 the other persons and entities that become bound thereby from time to time by joinder, assumption or otherwise and Wilmington Trust Company, as Collateral 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 and certain 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 and certain 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 to Exhibit 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 reference to 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 thereto and PNC Bank, National Association, as administrative agent, incorporated by reference to Exhibit 10.1 of Form 10-Q (file no. 001-14901) for the 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 James R. Gummel, on their own behalf and on behalf of the Class (as defined therein) and (ii) defendants CNX Gas Corporation, CONSOL Energy Inc. and certain individual defendants, incorporated by reference to Exhibit 10.1 of Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2013, filed on August 5, 2013.
|
10.39
|
|
Amendment No. 1, dated April 19, 2013, to the Asset Acquisition Agreement, dated August 17, 2011, between CNX Gas Company LLC and Noble 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 on August 5, 2013.
|
10.40
|
|
Ninth Amendment to Amended and Restated Receivables Purchase Agreement, dated September 23, 2013, by and among CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer, the Sub-Servicers listed on the signature pages thereto, the Conduit Purchasers listed on 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, incorporated by 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 administrative agent, 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 10.14 to 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 to Exhibit 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 Exhibit 10.1 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 Exhibit 10.1 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 Form 8-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-K for the year ended December 31, 2008 (file no. 001-14901), filed on February 17, 2009.
|
10.49
|
|
Change in Control Agreement by and between CONSOL Energy Inc. and William J. Lyons, incorporated by reference to Exhibit 10.4 to Form 10-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 Form 10-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 to Exhibit 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 on May 4, 2010.
|
10.54
|
|
Form of Indemnification Agreement for Directors and Executive Officers of CONSOL Energy Inc., incorporated by reference to Exhibit 10.6 to Form 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 to Form 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 ended March 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.
|
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 ended March 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) filed on 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 Statement on 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 10.28 to 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 Form S-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 Amendment No. 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 Form S-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 quarter ended 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 quarter ended 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 Exhibit 10.53 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 Form 10-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 on May 8, 2006.
|
10.75
|
|
Trust Agreement (Amended and Restated on March 20, 2008) (1999 Directors Deferred Compensation Plan), incorporated by reference to Exhibit 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 to Form 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 year ended 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 on September 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 to Form 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 (file no. 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 Exhibit 10.3 of Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2013, filed on May 7, 2013.
|
10.84
|
|
Retirement and Consulting Agreement, dated February 28, 2013, by and between CONSOL Energy Inc. and William J. Lyons, incorporated by reference 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 by reference 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 LLP
|
23.2
|
|
Consent of Netherland Sewell & Associates, Inc.
|
31.1
|
|
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
|
31.2
|
|
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
|
32.1
|
|
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
|
32.2
|
|
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
|
95
|
|
Mine Safety Disclosure Exhibit
|
99
|
|
Engineers' Audit Letter
|
101
|
|
Interactive Data File (Form 10-K for the year ended December 31, 2013 furnished in XBRL).
|
|
CONSOL ENERGY INC.
|
||
|
|
|
|
|
By:
|
|
/
S
/ J. B
RETT
H
ARVEY
|
|
|
|
J. Brett Harvey
|
|
|
|
Chairman of the Board and Chief Executive Officer
|
Signature
|
|
Title
|
|
|
|
/
S
/ J. B
RETT
H
ARVEY
|
|
Chairman of the Board and Chief Executive Officer
|
J. Brett Harvey
|
|
(Duly Authorized Officer and Principal Executive Officer)
|
|
|
|
/s/ D
AVID
M. K
HANI
|
|
Chief Financial Officer and Executive Vice President
|
David M. Khani
|
|
(Duly Authorized Officer and Principal Financial Officer)
|
|
|
|
/s/ L
ORRAINE
L. R
ITTER
|
|
Controller and Vice President
|
Lorraine L. Ritter
|
|
(Duly Authorized Officer and Principal Accounting Officer)
|
|
|
|
/
S
/ P
HILIP
W. B
AXTER
|
|
Lead Independent Director
|
Philip W. Baxter
|
|
|
|
|
|
/
S
/ J
AMES
E. A
LTMEYER,
S
R.
|
|
Director
|
James E. Altmeyer, Sr.
|
|
|
|
|
|
/s/ A
LVIN
R. C
ARPENTER
|
|
Director
|
Alvin R. Carpenter
|
|
|
|
|
|
/
S
/ W
ILLIAM
E. D
AVIS
|
|
Director
|
William E. Davis
|
|
|
|
|
|
/
S
/ R
AJ
K. G
UPTA
|
|
Director
|
Raj K. Gupta
|
|
|
|
|
|
/
S
/ D
AVID
C. H
ARDESTY,
J
R.
|
|
Director
|
David C. Hardesty, Jr.
|
|
|
|
|
|
/s/ M
AUREEN
E. L
ALLY
-G
REEN
|
|
Director
|
Maureen E. Lally-Green
|
|
|
|
|
|
/
S
/ J
OHN
T. M
ILLS
|
|
Director
|
John T. Mills
|
|
|
|
|
|
/s/ W
ILLIAM
P. P
OWELL
|
|
Director
|
William P. Powell
|
|
|
|
|
|
/
S
/ J
OSEPH
T. W
ILLIAMS
|
|
Director
|
Joseph T. Williams
|
|
|
|
|
|
|
Additions
|
|
Deductions
|
|
|
||||||||||||
|
|
Balance at
|
|
|
|
Release of
|
|
|
|
Balance at
|
||||||||||
|
|
Beginning
|
|
Charged to
|
|
Valuation
|
|
Charged to
|
|
End
|
||||||||||
|
|
of Period
|
|
Expense
|
|
Allowance
|
|
Expense
|
|
of Period
|
||||||||||
Year 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
|
)
|
|
$
|
—
|
|
|
$
|
7,873
|
|
|
|
|
|
|
|
|
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)
|
|
||||||||||||||||||||
|
|
Twelve Months Ended December 31,
|
||||||||||||||||||
|
|
2013
|
|
|
2012
|
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|||||
Earnings:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
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
|
|
|
18,283
|
|
|||||
Total Fixed Charges
|
|
$
|
292,958
|
|
|
$
|
285,784
|
|
|
$
|
289,123
|
|
|
$
|
240,177
|
|
|
$
|
61,573
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Ratio of Earnings to Fixed Charges
|
|
1.05
|
|
|
2.33
|
|
|
3.93
|
|
|
2.66
|
|
|
12.27
|
|
AMVEST Coal & Rail, LLC (a Virginia limited liability company)
|
|
CONSOL of Central Pennsylvania LLC (a Pennsylvania limited
|
AMVEST 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 Consol
|
AMVEST Minerals Company, LLC (a Virginia limited liability
|
|
Pennsylvania Coal Company) (a Delaware limited liability
|
company)
|
|
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 Penn
|
liability 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 West
|
Cardinal States Gathering Company (a Virginia general partnership)
|
|
Virginia limited liability company)
|
CNX Funding Corporation (a Delaware corporation)
|
|
Glamorgan Coal Company, LLC (a Virginia limited liability
|
CNX 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 liability
|
Virginia 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 liability
|
CONSOL Financial Inc. (a Delaware corporation)
|
|
company)
|
CONSOL Mining Company LLC (a Delaware limited liability
|
|
Terry Eagle Limited Partnership (a West Virginia limited
|
company)
|
|
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)
|
NETHERLAND, SEWELL & ASSOCIATES, INC.
|
|
|
|
By:
|
/s/ DANNY D. SIMMONS, P.E.
|
|
Danny D. Simmons, P.E.
|
|
President and Chief Operating Officer
|
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 the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial 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 in Exchange 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 our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others 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 our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external 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 the effectiveness 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 most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant'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 are reasonably 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 internal control 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)
|
|
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 the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial 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 in Exchange 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 our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others 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 our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external 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 the effectiveness 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 most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
|
5.
|
The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant'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 are reasonably 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 internal control over financial reporting.
|
Date:
|
February 7, 2014
|
|
|
|
|
/s/ David M. Khani
|
|
|
David M. Khani
|
|
|
Chief Financial Officer and Executive Vice President
(Principal Financial Officer )
|
|
(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 the Registrant.
|
Date:
|
February 7, 2014
|
|
|
|
|
/s/ J. Brett Harvey
|
|
|
J. Brett Harvey
|
|
|
Chairman of the Board and Chief Executive Officer
|
|
|
(Principal Executive Officer)
|
|
(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 the Registrant.
|
Date:
|
February 7, 2014
|
|
|
|
|
/s/ David M. Khani
|
|
|
David M. Khani
|
|
|
Chief Financial Officer and Executive Vice President
(Principal Financial Officer)
|
|
|
|
Net Reserves
|
|
Future Net Revenue (M$)
|
|||||||||||
|
|
Oil
|
|
NGL
|
|
Gas
|
|
|
|
Present Worth
|
|||||
Category
|
|
(MBBL)
|
|
(MBBL)
|
|
(MMCF)
|
|
Total
|
|
at 10%
|
|||||
Proved Developed Producing
|
|
1,320.444
|
|
|
4,774.494
|
|
|
2,316,099.000
|
|
|
4,774,610.352
|
|
|
2,112,931.219
|
|
Proved Developed Non-Producing
|
|
54.407
|
|
|
1,164.379
|
|
|
154,312.984
|
|
|
433,154.688
|
|
|
150,869.703
|
|
Proved Undeveloped
(1)
|
|
1,430.883
|
|
|
15,606.579
|
|
|
3,114,694.750
|
|
|
5,385,994.000
|
|
|
516,093.094
|
|
Total Proved
|
|
2,805.734
|
|
|
21,545.469
|
|
|
5,585,107.000
|
|
|
10,593,759.000
|
|
|
2,779,893.750
|
|
|
|
|
NETHERLAND, SEWELL & ASSOCIATES, INC.
|
|
|
|
|
Texas Registered Engineering Firm F-2699
|
|
|
|
|
|
|
|
|
|
By:
|
/s/ C.H. (Scott) Rees III
|
|
|
|
|
C.H. (Scott) Rees III, P.E.
|
|
|
|
|
Chairman and Chief Executive Officer
|
|
|
|
|
|
By:
|
/s/ Richard B. Talley, Jr.
|
|
By:
|
/s/ David E. Nice
|
|
Richard B. Talley, Jr., P.E. 102425
|
|
|
David E. Nice, P.G. 346
|
|
Vice President
|
|
|
Vice President
|
|
|
|
|
|
Date Signed: February 5, 2014
|
|
Date Signed: February 5, 2014
|
||
|
|
|
|
|
RBT:DEG
|
|
|
|
SUMMARY OF NET RESERVES AND FUTURE REVENUE
|
|||||||||||||||||||||||||||
CONSOL ENERGY INC. INTEREST
|
|||||||||||||||||||||||||||
AS OF DECEMBER 31, 2013
|
|||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
|
|
|
|
|
|||||||||
|
|
Net Reserves
|
|
Future
|
|
Operating
|
|
|
|
Including
|
|
Future Net Revenue (M$)
|
|||||||||||||||
|
|
Oil
|
|
NGL
|
|
Gas
|
|
Gross Revenue
|
|
Expense
|
|
Taxes
|
|
Abandonment
|
|
|
|
Discounted
|
|||||||||
Category
|
|
(MBBL)
|
|
(MBBL)
|
|
(MMCF)
|
|
(M$)
|
|
(M$)
|
|
(M$)
|
|
(M$)
|
|
Total
|
|
At 10%
|
|||||||||
Proved Developed Producing
|
|
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
|
|
|
2,026,466.500
|
|
Other Revenue and Costs
(1)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
141,340.750
|
|
|
57,811.406
|
|
|
—
|
|
|
—
|
|
|
83,529.352
|
|
|
86,464.719
|
|
Total Proved Developed Producing
|
|
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
|
|
|
2,779,893.750
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
Actions
|
|||||||||||
Mine or Operating
|
|
104
|
|
Section
|
|
Citations
|
|
Section
|
|
Section
|
|
Assessments
|
|
Mining
|
|
Under
|
|
Under
|
|
Last
|
|
Initiated
|
|
Resolved
|
|||||||||||||
Name/MSHA
|
|
S&S
|
|
104(b)
|
|
and
|
|
110(b)(2)
|
|
107(a)
|
|
Proposed (in
|
|
Related
|
|
Section
|
|
Section
|
|
Day of
|
|
During
|
|
During
|
|||||||||||||
Identification Number
|
|
Citations
|
|
Orders
|
|
Orders
|
|
Violations
|
|
Orders
|
|
thousands)
|
|
Fatalities
|
|
104(e)
|
|
104(e)
|
|
Period (1)
|
|
Period
|
|
Period
|
|||||||||||||
Active Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Alma No. 1 Mine
|
|
46-09277
|
|
7
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
6,104
|
|
|
—
|
|
|
No
|
|
No
|
|
—
|
|
|
—
|
|
|
—
|
|
Bailey
|
|
36-07230
|
|
77
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
185,163
|
|
|
—
|
|
|
No
|
|
No
|
|
12
|
|
|
2
|
|
|
1
|
|
Buchanan
|
|
44-04856
|
|
67
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
363,835
|
|
|
—
|
|
|
No
|
|
No
|
|
34
|
|
|
2
|
|
|
2
|
|
Enlow Fork
|
|
36-07416
|
|
68
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
$
|
145,446
|
|
|
—
|
|
|
No
|
|
No
|
|
9
|
|
|
3
|
|
|
1
|
|
Miller Creek PP #1
|
|
46-05890
|
|
11
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
7,024
|
|
|
—
|
|
|
No
|
|
No
|
|
—
|
|
|
—
|
|
|
1
|
|
Twin 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 Block Mine)
|
|
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
|
|
—
|
|
|
—
|
|
|
—
|
|
Peach Orchard Prep Plant
|
|
46-08376
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
200
|
|
|
—
|
|
|
No
|
|
No
|
|
—
|
|
|
—
|
|
|
—
|
|
Powellton/Bridge Fork
|
|
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
|
|
—
|
|
|
—
|
|
|
—
|
|
Wiley Surface(MT34/Peg Fork)
|
|
46-09035
|
|
3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
3,624
|
|
|
—
|
|
|
No
|
|
No
|
|
—
|
|
|
—
|
|
|
—
|
|
Winoc Prep Plant
|
|
46-08172
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
No
|
|
No
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
237
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
$
|
727,920
|
|
|
—
|
|
|
|
|
|
|
56
|
|
|
7
|
|
|
5
|
|
Mine or Operating Name/MSHA Identification Number
|
|
Contests of Citations, Orders
(as of 12.31.13)
(a)
|
|
Contests of Proposed Penalties
(as of 12.31.13)
(b)
|
|
Complaints for Compensation
(as of 12.31.13)
(c)
|
|
Complaints of Discharge, Discrimination or Interference
(as of 12.31.13)
(d)
|
|
Applications for Temporary Relief
(as of 12.31.13)
(e)
|
|
Appeals of Judges' Decisions or Order
(as of 12.31.13)
(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
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
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
|
|
|
—
|
|
|
—
|
|