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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 coal and natural gas 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 coal and natural gas to market;
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•
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a loss of our competitive position because of the competitive nature of the coal and natural gas industries, or a loss of our competitive position because of overcapacity in these industries impairing our profitability;
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•
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our inability to maintain satisfactory labor relations;
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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 coal and natural gas;
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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 coal and natural gas operations being subject to unexpected disruptions, including geological conditions, equipment failure, timing of completion of significant construction or repair of equipment, fires, explosions, accidents and weather conditions which could impact financial results;
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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 coal and gas 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 coal and natural gas 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 mine or natural gas well;
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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 coal and gas 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 coal and gas 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 coal or gas rights on some of our properties or failing to acquire these additional rights may result in a reduction of our estimated reserves;
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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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exposure to multi-employer pension plan liabilities;
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•
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minimum funding requirements by the Pension Protection Act of 2006 (the Pension Act) coupled with the significant investment and plan asset losses suffered during the recent economic decline has exposed us to making additional required cash contributions to fund the pension benefit plans which we sponsor and the multi-employer pension benefit plans in which we participate;
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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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the anti-takeover effects of our rights plan could prevent a change of control;
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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; and
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•
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other factors discussed in this 2012 Form 10-K under “Risk Factors,” as updated by any subsequent Form 10-Qs, which are on file at the Securities and Exchange Commission.
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ITEM 1.
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Business
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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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U.S. ELECTRIC SUPPLY by ENERGY SOURCE
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||||||||
In percent of total
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||||||||
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Actuals
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Preliminary
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Projected
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2010
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2011
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2012
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2013
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Coal
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44.8%
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42.3%
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37.5%
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39.0%
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Natural Gas
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23.9%
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24.7%
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30.3%
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27.9%
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Nuclear
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19.6%
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19.3%
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18.9%
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19.2%
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Conventional Hydro
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6.3%
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7.8%
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6.8%
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6.9%
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Renewables
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3.9%
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4.6%
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5.3%
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5.8%
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Others
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1.5%
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1.3%
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1.2%
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1.2%
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2012
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Forecasted 2013
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Actual Capital
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Expenditures
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|||||||
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Expenditures
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Low
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High
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(in millions)
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Coal and Other Operations
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$
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921
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$
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410
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$
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520
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Gas Operations
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528
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835
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935
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Water Operations
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126
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45
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50
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Total Capital Expenditures
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$
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1,575
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$
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1,290
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$
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1,505
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Less: Asset Sale Proceeds
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(647
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)
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(455
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)
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(640
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)
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Net Investments
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$
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928
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$
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835
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$
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865
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•
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We produce one of the largest amounts of coal east of the Mississippi River;
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•
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We control one of the largest amounts of recoverable coal reserves east of the Mississippi River;
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•
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We control the fourth largest amount of recoverable coal reserves among United States coal producers; and
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•
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We are one of the largest United States producers of coal from underground mines.
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MAJOR U.S. UNDERGROUND COAL MINES–2011
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In millions of tons
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||||
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Mine Name
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Operating Company
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Production
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Bailey
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CONSOL Energy
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10.8
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Enlow Fork
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CONSOL Energy
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10.2
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McElroy
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CONSOL Energy
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9.3
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River View
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River View Coal, LLC (Alliance)
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7.6
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Twentymile
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Peabody Energy
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7.5
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Mach No. 1
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Williamson Energy, LLC (Foresight Energy)
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7.2
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Century
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American Energy Corp. (Murray)
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7.1
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Powhatan No. 6
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The Ohio Valley Coal Company (Murray)
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6.3
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Cumberland
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Cumberland Coal Resources (Alpha)
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6.2
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SUFCO
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Arch Coal
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6.1
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Robinson Run
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CONSOL Energy
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6.0
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West Elk
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Arch Coal
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5.7
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Buchanan
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CONSOL Energy
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5.7
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Loveridge
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CONSOL Energy
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5.6
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Warrior
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Warrior Coal LLC (Alliance)
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5.4
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Shoemaker
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CONSOL Energy
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5.1
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Bull Mountain
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Signal Peak Energy LLC
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5.1
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New Era
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American Energy Corp. (Murray)
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5.0
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Blackville No. 2
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CONSOL Energy
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4.3
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San Juan
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BHP Billiton-New Mexico Coal
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4.0
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•
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We are one of the largest natural gas producers in Appalachia with approximately 15,000 total gross wells in Appalachia comprising 8% of all Appalachian wells based on 2011 U.S. Energy Information Administration data, the latest year for which statistics are available.
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•
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We are one of the largest CBM producers, with production equal to approximately 40% of total Appalachian CBM production and 75% of Northern Appalachian production (excluding Alabama) based on 2011 U.S. Energy Information Administration data, the latest year for which statistics are available.
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•
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We gather essentially all of our own production independently or through company operated joint ventures, and we operate one of the largest gas gathering networks in Appalachia. We also own or operate over 4,500 miles of gathering pipelines.
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•
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We have been a pioneer in the exploration of unconventional gas including coalbed methane, Marcellus, Utica, Chattanooga, Huron and New Albany Shales.
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•
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the price of competing coal and alternative fuel supplies, including nuclear, natural gas, oil and
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•
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environmental and government regulation;
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•
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coal quality;
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•
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transportation costs from the mine to the customer;
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•
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the reliability of fuel supply;
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•
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worldwide demand for steel;
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•
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natural/weather disasters; and
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•
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political changes in international governments.
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CONSOL ENERGY MINING COMPLEXES
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||||||||||||||||||||||
Proven and Probable Assigned and Accessible Coal Reserves as of December 31, 2012 and 2011
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Recoverable
|
||||||||||
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Average
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As Received Heat
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Reserves(2)
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Seam
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Value(1)
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Tons in
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||||||
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Reserve
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Coal
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Thickness
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(Btu/lb)
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Owned
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Leased
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Millions
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||||||
Mine/Reserve
|
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Location
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Class
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Seam
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(feet)
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Typical
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Range
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(%)
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(%)
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|
12/31/2012
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12/31/2011
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ASSIGNED–OPERATING
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(4)
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Thermal Reserves
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|
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||
Enlow Fork (3)
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Enon, PA
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Assigned
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Pittsburgh
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|
5.4
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|
12,940
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|
12,860 – 13,060
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100%
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—%
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27.0
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28.5
|
|
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Accessible
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Pittsburgh
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5.3
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13,040
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12,850 – 13,120
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79%
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21%
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232.8
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204.5
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Bailey (3)
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Enon, PA
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Assigned
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Pittsburgh
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5.5
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12,950
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12,860 – 13,060
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46%
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54%
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92.2
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|
|
101.6
|
|
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|
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Accessible
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Pittsburgh
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5.7
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|
12,930
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12,770 – 13,090
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89%
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|
11%
|
|
303.0
|
|
|
334.4
|
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McElroy
|
|
Glen Easton, WV
|
|
Assigned
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Pittsburgh
|
|
5.7
|
|
12,570
|
|
12,450 – 12,650
|
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94%
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6%
|
|
101.8
|
|
|
105.7
|
|
|
|
|
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Accessible
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Pittsburgh
|
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5.9
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|
12,650
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12,490 – 12,700
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96%
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4%
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86.9
|
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|
90.0
|
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Shoemaker
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Moundsville, WV
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Assigned
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Pittsburgh
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5.6
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12,300
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11,800 – 12,400
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100%
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—%
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62.5
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68.3
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Loveridge
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Metz, WV
|
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Assigned
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Pittsburgh
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7.5
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|
13,050
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12,850 – 13,150
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78%
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|
22%
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|
21.5
|
|
|
26.4
|
|
|
|
|
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Accessible
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Pittsburgh
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7.6
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|
13,010
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13,010 – 13,010
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95%
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|
5%
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16.5
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|
|
13.6
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Robinson Run
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Shinnston, WV
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Assigned
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Pittsburgh
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|
7.5
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12,950
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|
12,600 – 13,300
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84%
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16%
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45.1
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|
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46.7
|
|
|
|
|
|
Accessible
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Pittsburgh
|
|
6.6
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|
12,900
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|
12,850 – 12,950
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74%
|
|
26%
|
|
269.3
|
|
|
156.7
|
|
Blacksville #2 (3)
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Wana, WV
|
|
Assigned
|
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Pittsburgh
|
|
6.7
|
|
13,000
|
|
12,800 – 13,150
|
|
83%
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|
17%
|
|
17.7
|
|
|
20.3
|
|
|
|
|
|
Accessible
|
|
Pittsburgh
|
|
6.9
|
|
12,950
|
|
12,950 – 12,950
|
|
99%
|
|
1%
|
|
16.3
|
|
|
16.5
|
|
Amvest-Fola Complex (3)
|
|
Bickmore, WV
|
|
Assigned
|
|
Multiple
|
|
4.6
|
|
12,380
|
|
12,250 – 12,550
|
|
86%
|
|
14%
|
|
73.4
|
|
|
92.2
|
|
Miller Creek Complex
|
|
Delbarton, WV
|
|
Assigned
|
|
Multiple
|
|
4.1
|
|
12,000
|
|
11,600 – 12,650
|
|
—%
|
|
100%
|
|
13.4
|
|
|
5.6
|
|
|
|
|
|
Accessible
|
|
Multiple
|
|
3.7
|
|
12,440
|
|
12,440 – 12,440
|
|
4%
|
|
96%
|
|
8.2
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
Metallurgical Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
Buchanan
|
|
Mavisdale, VA
|
|
Assigned
|
|
Pocahontas 3
|
|
6.2
|
|
13,650
|
|
13,400 – 14,000
|
|
19%
|
|
81%
|
|
51.7
|
|
|
58.0
|
|
|
|
|
|
Accessible
|
|
Pocahontas 3
|
|
5.9
|
|
13,630
|
|
13,540 – 13,780
|
|
14%
|
|
86%
|
|
46.3
|
|
|
37.0
|
|
Amonate Complex
|
|
Amonate, VA
|
|
Assigned
|
|
Multiple
|
|
4.3
|
|
13,150
|
|
12,850 – 13,350
|
|
52%
|
|
48%
|
|
14.8
|
|
|
4.9
|
|
|
|
|
|
Accessible
|
|
Multiple
|
|
5.2
|
|
13,110
|
|
13,110 – 13,110
|
|
100%
|
|
—%
|
|
6.6
|
|
|
—
|
|
Total Assigned Operating and Accessible
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,507.0
|
|
|
1,410.9
|
|
(1)
|
The heat value shown for Assigned Operating reserves is based on the quality of coal mined and processed during the year ended December 31, 2012. The heat value shown for accessible reserves are based on as received, dry values obtained from drill hole analysis prorated by the associated Assigned Operating reserve values to account for similar mining and processing methods.
|
(2)
|
Recoverable reserves are calculated based on the area in which mineable coal exists, coal seam thickness and average density determined by laboratory testing of drill core samples. This calculation is adjusted to account for coal that will not be recovered during mining and for losses that occur if the coal is processed after mining. Reserve calculations do not include adjustments for moisture that may be added during mining or processing, nor do the calculations include adjustments for dilution from rock lying above or below the coal seam. Reserves are reported only for those coal seams that are controlled by ownership or leases.
|
(3)
|
A portion of these reserves contain metallurgical qualities and are currently being sold on the metallurgical market.
|
(4)
|
The table excludes 11 million tons of recoverable reserves which represents CONSOL Energy's portion of tonnage held by two equity affiliates. CONSOL Energy owns a 49% interest in both of these affiliates. Also, excluded from the table above are approximately 209.3 million tons of reserves at December 31, 2012 that are assigned to projects that have not produced coal in 2012. These assigned reserves are in the Northern Appalachia (northern West Virginia and Pennsylvania), Central Appalachia (Virginia and eastern Kentucky), the Western U.S. (Utah) and Illinois Basin (Illinois) regions. These reserves are approximately 64% owned and 36% leased.
|
CONSOL Energy UNASSIGNED Recoverable Coal Reserves as of December 31, 2012 and 2011
|
||||||||||||
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||
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|
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Recoverable
|
||
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|
|
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Recoverable Reserves(2)
|
|
Reserves
|
||||||
|
|
|
|
|
|
|
|
Tons in
|
|
(tons in
|
||
|
|
As Received Heat
|
|
Owned
|
|
Leased
|
|
Millions
|
|
Millions)
|
||
Coal Producing Region
|
|
Value(1) (Btu/lb)
|
|
(%)
|
|
(%)
|
|
12/31/2012
|
|
12/31/2011
|
||
Northern Appalachia (Pennsylvania, Ohio, Northern West Virginia)
|
|
11,400 – 13,600
|
|
72%
|
|
28%
|
|
1,424.0
|
|
|
1,448.1
|
|
Central Appalachia (Virginia, Southern West Virginia, Eastern Kentucky)
|
|
11,400 – 14,100
|
|
53%
|
|
47%
|
|
354.7
|
|
|
421.3
|
|
Illinois Basin (Illinois, Western Kentucky, Indiana)
|
|
11,600 – 12,000
|
|
45%
|
|
55%
|
|
733.6
|
|
|
750.7
|
|
Total
|
|
|
|
60%
|
|
40%
|
|
2,512.3
|
|
|
2,620.1
|
|
(1)
|
The heat value estimates for Northern Appalachian and Central Appalachian Unassigned coal reserves include adjustments for moisture that may be added during mining or processing as well as for dilution by rock lying above or below the coal seam. The mining and processing methods currently in use are used for these estimates. The heat value estimates for the Illinois Basin, and the Western U.S. Unassigned reserves are based primarily on exploration drill core data that may not include adjustments for moisture added during mining or processing or for dilution by rock lying above or below the coal seam.
|
(2)
|
Recoverable reserves are calculated based on the area in which mineable coal exists, coal seam thickness, and average density determined by laboratory testing of drill core samples. This calculation is adjusted to account for coal that will not be recovered during mining and for losses that occur if the coal is processed after mining. Reserve calculations do not include adjustment for moisture that may be added during mining or processing, nor do the calculations include adjustments for dilution from rock lying above or below the coal seam. Reserves are only reported for those coal seams that are controlled by ownership or leases.
|
CONSOL Energy Proven and Probable Recoverable Coal Reserves
|
||||||||||||||||||||||||||||||||||
By Producing Region and Product (In Millions of Tons) As of December 31, 2012
|
||||||||||||||||||||||||||||||||||
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|
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|
|||||||||||
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|
|
≤ 1.20 lbs.
|
|
> 1.20 ≤ 2.50 lbs.
|
|
> 2.50 lbs.
|
|
|
|
|
|||||||||||||||||||||||
|
|
|
S02/MMBtu
|
|
S02/MMBtu
|
|
S02/MMBtu
|
|
|
|
Percent
|
|||||||||||||||||||||||
|
|
|
Low
|
|
Med
|
|
High
|
|
Low
|
|
Med
|
|
High
|
|
Low
|
|
Med
|
|
High
|
|
|
|
By
|
|||||||||||
By Region
|
|
Btu
|
|
Btu
|
|
Btu
|
|
Btu
|
|
Btu
|
|
Btu
|
|
Btu
|
|
Btu
|
|
Btu
|
|
Total
|
|
Region
|
||||||||||||
Northern Appalachia:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Metallurgical(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
|
High Vol A Bituminous
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
162.3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
162.3
|
|
|
3.8
|
%
|
Thermal(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
|
High Vol A Bituminous
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
103.5
|
|
|
57.6
|
|
|
109.7
|
|
|
2,305.8
|
|
|
2,576.6
|
|
|
61.0
|
%
|
|
Low Vol Bituminous
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
33.6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
33.6
|
|
|
0.8
|
%
|
|
Region Total
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
299.4
|
|
|
57.6
|
|
|
109.7
|
|
|
2,305.8
|
|
|
2,772.5
|
|
|
65.6
|
%
|
Central Appalachia:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Metallurgical:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
|
High Vol A Bituminous
|
|
—
|
|
|
—
|
|
|
6.2
|
|
|
—
|
|
|
—
|
|
|
46.5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
52.7
|
|
|
1.2
|
%
|
|
Med Vol Bituminous
|
|
—
|
|
|
3.0
|
|
|
55.9
|
|
|
—
|
|
|
—
|
|
|
2.9
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
61.8
|
|
|
1.5
|
%
|
|
Low Vol Bituminous
|
|
—
|
|
|
—
|
|
|
188.9
|
|
|
—
|
|
|
—
|
|
|
55.2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
244.1
|
|
|
5.8
|
%
|
Thermal:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
|
High Vol A Bituminous
|
|
33.6
|
|
|
80.4
|
|
|
2.8
|
|
|
42.0
|
|
|
116.9
|
|
|
2.1
|
|
|
9.4
|
|
|
15.0
|
|
|
8.2
|
|
|
310.4
|
|
|
7.3
|
%
|
|
Region Total
|
|
33.6
|
|
|
83.4
|
|
|
253.8
|
|
|
42.0
|
|
|
116.9
|
|
|
106.7
|
|
|
9.4
|
|
|
15.0
|
|
|
8.2
|
|
|
669.0
|
|
|
15.8
|
%
|
Midwest-Illinois Basin:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Thermal:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
|
High Vol B Bituminous
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
63.6
|
|
|
—
|
|
|
—
|
|
|
425.5
|
|
|
—
|
|
|
489.1
|
|
|
11.6
|
%
|
|
High Vol C Bituminous
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
159.5
|
|
|
—
|
|
|
108.3
|
|
|
—
|
|
|
—
|
|
|
267.8
|
|
|
6.3
|
%
|
|
Region Total
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
223.1
|
|
|
—
|
|
|
108.3
|
|
|
425.5
|
|
|
—
|
|
|
756.9
|
|
|
17.9
|
%
|
Utah-Emery Field:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Thermal:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
|
High Vol B Bituminous
|
|
—
|
|
|
17.9
|
|
|
—
|
|
|
—
|
|
|
12.3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
30.2
|
|
|
0.7
|
%
|
|
Region Total
|
|
—
|
|
|
17.9
|
|
|
—
|
|
|
—
|
|
|
12.3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
30.2
|
|
|
0.7
|
%
|
|
Total Company
|
|
33.6
|
|
|
101.3
|
|
|
253.8
|
|
|
42.0
|
|
|
352.3
|
|
|
406.1
|
|
|
175.3
|
|
|
550.2
|
|
|
2,314.0
|
|
|
4,228.6
|
|
|
100.0
|
%
|
|
Percent of Total
|
|
0.8
|
%
|
|
2.4
|
%
|
|
6.0
|
%
|
|
1.0
|
%
|
|
8.3
|
%
|
|
9.6
|
%
|
|
4.1
|
%
|
|
13.0
|
%
|
|
54.8
|
%
|
|
100.0
|
%
|
|
|
CONSOL Energy Proven and Probable Recoverable Coal Reserves
|
||||||||||||||||||||||||||||||||||
By Product (In Millions of Tons) As of December 31, 2012
|
||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
|
|
|
≤ 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
|
|
|
—
|
|
|
—
|
|
|
208.8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
215.0
|
|
|
5.1
|
%
|
|
Med Vol Bituminous
|
|
—
|
|
|
3.0
|
|
|
55.9
|
|
|
—
|
|
|
—
|
|
|
2.9
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
61.8
|
|
|
1.5
|
%
|
|
Low Vol Bituminous
|
|
—
|
|
|
—
|
|
|
188.9
|
|
|
—
|
|
|
—
|
|
|
55.2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
244.1
|
|
|
5.7
|
%
|
|
Total Metallurgical
|
|
—
|
|
|
3.0
|
|
|
251.0
|
|
|
—
|
|
|
—
|
|
|
266.9
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
520.9
|
|
|
12.3
|
%
|
Thermal(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
|
High Vol A Bituminous
|
|
33.6
|
|
|
80.4
|
|
|
2.8
|
|
|
42.0
|
|
|
116.9
|
|
|
105.6
|
|
|
67.0
|
|
|
124.7
|
|
|
2,314.0
|
|
|
2,887.0
|
|
|
68.3
|
%
|
|
High Vol B Bituminous
|
|
—
|
|
|
17.9
|
|
|
—
|
|
|
—
|
|
|
75.9
|
|
|
—
|
|
|
—
|
|
|
425.5
|
|
|
—
|
|
|
519.3
|
|
|
12.3
|
%
|
|
High Vol C Bituminous
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
159.5
|
|
|
—
|
|
|
108.3
|
|
|
—
|
|
|
—
|
|
|
267.8
|
|
|
6.3
|
%
|
|
Low Vol Bituminous
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
33.6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
33.6
|
|
|
0.8
|
%
|
|
Total Thermal
|
|
33.6
|
|
|
98.3
|
|
|
2.8
|
|
|
42.0
|
|
|
352.3
|
|
|
139.2
|
|
|
175.3
|
|
|
550.2
|
|
|
2,314.0
|
|
|
3,707.7
|
|
|
87.7
|
%
|
|
Total
|
|
33.6
|
|
|
101.3
|
|
|
253.8
|
|
|
42.0
|
|
|
352.3
|
|
|
406.1
|
|
|
175.3
|
|
|
550.2
|
|
|
2,314.0
|
|
|
4,228.6
|
|
|
100.0
|
%
|
|
Percent of Total
|
|
0.8
|
%
|
|
2.4
|
%
|
|
6.0
|
%
|
|
1.0
|
%
|
|
8.3
|
%
|
|
9.6
|
%
|
|
4.1
|
%
|
|
13.0
|
%
|
|
54.8
|
%
|
|
100.0
|
%
|
|
|
Region
|
|
Low
|
|
Medium
|
|
High
|
Northern, Central Appalachia and Canada (1)
|
|
< 12,500
|
|
12,500 – 13,000
|
|
> 13,000
|
Midwest Appalachia
|
|
< 11,600
|
|
11,600 – 12,000
|
|
> 12,000
|
Northern Powder River Basin
|
|
< 8,400
|
|
8,400 – 8,800
|
|
> 8,800
|
Colorado and Utah
|
|
< 11,000
|
|
11,000 – 12,000
|
|
> 12,000
|
|
|
Total
|
|
Total
|
|
Total
|
|
|
Royalty
|
|
Coal
|
|
Royalty
|
|
|
Tonnage
|
|
Acreage
|
|
Income
|
Year
|
|
(in thousands)
|
|
Leased
|
|
(in thousands)
|
2012
|
|
8,326
|
|
271,760
|
|
$16,479
|
2011
|
|
8,488
|
|
289,833
|
|
$17,998
|
2010
|
|
8,606
|
|
226,524
|
|
$14,073
|
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, Jones Fork Complex, Amonate Complex and Western Allegheny–Knob Creek include facilities operated by independent contractors.
|
(3)
|
–
|
Mine was idle for three weeks 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,
|
||||||||||
|
|
2012
|
|
2011
|
|
2010
|
||||||
Average Sales Price Per Ton Sold– Thermal Coal
|
|
$
|
61.99
|
|
|
$
|
58.87
|
|
|
$
|
53.76
|
|
Average Sales Price Per Ton Sold– High Volatile Met Coal
|
|
$
|
63.76
|
|
|
$
|
78.06
|
|
|
$
|
72.89
|
|
Average Sales Price Per Ton Sold– Low Volatile Met Coal
|
|
$
|
140.11
|
|
|
$
|
191.81
|
|
|
$
|
146.32
|
|
Average Sales Price Per Ton Sold– Total Company
|
|
$
|
67.11
|
|
|
$
|
72.25
|
|
|
$
|
61.33
|
|
|
|
Tons
|
|
Percent of
|
||
|
|
Sold
|
|
Total
|
||
Thermal
|
|
49.1
|
|
|
88
|
%
|
High Volatile Metallurgical
|
|
3.6
|
|
|
6
|
%
|
Low Volatile Metallurgical
|
|
3.6
|
|
|
6
|
%
|
Total tons sold
|
|
56.3
|
|
|
100
|
%
|
COAL DIVISION GUIDANCE
|
||||||||||||
(Tons in millions)
|
||||||||||||
|
|
|
|
|
|
|
|
|
||||
|
|
Q1 2013
|
|
2013
|
|
2014
|
|
2015
|
||||
Estimated Coal Production
|
|
14.0
|
|
|
56.3
|
|
|
61.6
|
|
|
63.8
|
|
Estimated Low-Vol Met Sales
|
|
0.9
|
|
|
3.9
|
|
|
5.0
|
|
|
5.1
|
|
Tonnage - Firm
|
|
0.8
|
|
|
1.5
|
|
|
—
|
|
|
—
|
|
Average Price - Sold (firm)
|
|
$121.48
|
|
$115.63
|
|
—
|
|
|
—
|
|
||
Estimated High-Vol Met Sales
|
|
1.1
|
|
|
1.8
|
|
|
4.8
|
|
|
6.3
|
|
Tonnage - Firm
|
|
1.1
|
|
|
1.4
|
|
|
0.2
|
|
|
0.2
|
|
Average Price - Sold (firm)
|
|
$64.24
|
|
$62.95
|
|
$75.53
|
|
$74.74
|
||||
Estimated Thermal Sales
|
|
11.9
|
|
|
50.1
|
|
|
51.1
|
|
|
51.7
|
|
Tonnage - Firm
|
|
11.5
|
|
|
48.7
|
|
|
23.7
|
|
|
15.0
|
|
Average Price - Sold (firm)
|
|
$58.76
|
|
$59.06
|
|
$59.92
|
|
$61.42
|
•
|
Fixed price contracts with pre-established prices; or
|
•
|
Periodically negotiated prices that reflect market conditions at the time; or
|
•
|
Price restricted to an agreed-upon percentage increase or decrease; or
|
•
|
Base-price-plus-escalation methods which allow for periodic price adjustments based on inflation indices, or other negotiated indices.
|
|
|
|
|
Shallow Oil
|
|
|
|
|
|
|
|||||
|
|
CBM
|
|
and Gas
|
|
Marcellus
|
|
Other Gas
|
|
|
|||||
|
|
Segment
|
|
Segment
|
|
Segment
|
|
Segment
|
|
Total
|
|||||
Estimated Net Proved Reserves (million cubic feet equivalent)
|
|
1,485,464
|
|
|
583,611
|
|
|
1,805,149
|
|
|
119,234
|
|
|
3,993,458
|
|
Percent Developed
|
|
75
|
%
|
|
100
|
%
|
|
24
|
%
|
|
40
|
%
|
|
54
|
%
|
Net Producing Wells (including gob wells)
|
|
4,287
|
|
|
8,341
|
|
|
92
|
|
|
99
|
|
|
12,819
|
|
Net Proved Developed Acres
|
|
248,425
|
|
|
203,747
|
|
|
5,162
|
|
|
8,058
|
|
|
465,392
|
|
Net Proved Undeveloped Acres
|
|
54,799
|
|
|
—
|
|
|
18,710
|
|
|
10,065
|
|
|
83,574
|
|
Net Unproved Acres(1)
|
|
2,229,564
|
|
|
444,722
|
|
|
322,927
|
|
|
1,041,302
|
|
|
4,038,515
|
|
Total Net Acres(2)
|
|
2,532,788
|
|
|
648,469
|
|
|
346,799
|
|
|
1,059,425
|
|
|
4,587,481
|
|
(1)
|
Net acres include acreage attributable to our working interests in the properties. Additional adjustments (either increases or decreases) may be required as we further develop title to and further confirm our rights with respect to our various properties in anticipation of development. We believe that our assumptions and methodology in this regard are reasonable. See Risk Factors in Section 1A. of this Form 10-K.
|
(2)
|
Acreage amounts are shown under the target strata CONSOL Energy expects to produce, although the reported acre may include rights to multiple gas seams (CBM, Shallow Oil and Gas, Marcellus, etc.). We have reviewed our drilling plans, our acreage rights and used our best judgment to reflect the acre in the strata we expect to produce. As more information is obtained or circumstances change, the acreage classification may change.
|
|
|
Gross
|
|
Net(1)
|
||
Producing Wells (including gob wells)
|
|
14,906
|
|
|
12,819
|
|
Proved Developed Acreage
|
|
555,160
|
|
|
465,392
|
|
Proved Undeveloped Acreage
|
|
118,384
|
|
|
83,574
|
|
Unproven Acreage
|
|
4,930,181
|
|
|
4,038,515
|
|
Total Acreage
|
|
5,603,725
|
|
|
4,587,481
|
|
(1)
|
Net acres include acreage attributable to our working interests in the properties. Additional adjustments (either increases or decreases) may be required as we further develop title to and further confirm our rights with respect to our various properties in anticipation of development. We believe that our assumptions and methodology in this regard are reasonable. See Risk Factors in Section 1A. of this Form 10-K.
|
|
|
For the Year
|
|||||||
|
|
Ended December 31,
|
|||||||
|
|
2012
|
2011
|
|
2010
|
||||
CBM segment
|
|
42.5
|
|
|
221.4
|
|
|
184.0
|
|
Shallow Oil and Gas segment
|
|
2.0
|
|
|
4.0
|
|
|
107.0
|
|
Marcellus segment
|
|
44.0
|
|
|
17.5
|
|
|
24.0
|
|
Other Gas segment
|
|
7.0
|
|
|
12.0
|
|
|
2.0
|
|
Total Development Wells
|
|
95.5
|
|
|
254.9
|
|
|
317.0
|
|
|
|
For the Year Ended December 31,
|
|||||||||||||||||||||||||
|
|
2012
|
|
2011
|
|
2010
|
|||||||||||||||||||||
|
|
Producing
|
|
Dry
|
|
Still Eval.
|
|
Producing
|
|
Dry
|
|
Still Eval.
|
|
Producing
|
|
Dry
|
|
Still Eval.
|
|||||||||
CBM segment
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Shallow Oil and Gas segment
|
|
4.0
|
|
|
7.0
|
|
|
4.0
|
|
|
12.0
|
|
|
1.0
|
|
|
1.0
|
|
|
2.0
|
|
|
—
|
|
|
3.0
|
|
Marcellus segment
|
|
—
|
|
|
—
|
|
|
0.5
|
|
|
47.5
|
|
|
1.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Other Gas segment (1)
|
|
0.5
|
|
|
—
|
|
|
5.5
|
|
|
5.5
|
|
|
—
|
|
|
1.5
|
|
|
18.0
|
|
|
2.0
|
|
|
13.0
|
|
Total
|
|
4.5
|
|
|
7.0
|
|
|
10.0
|
|
|
65.0
|
|
|
2.0
|
|
|
2.5
|
|
|
20.0
|
|
|
2.0
|
|
|
16.0
|
|
|
|
Net Reserves
|
|||||||
|
|
(Million cubic feet equivalent)
|
|||||||
|
|
as of December 31,
|
|||||||
|
|
2012
|
|
2011
|
|
2010
|
|||
Proved developed reserves
|
|
2,165,483
|
|
|
2,135,805
|
|
|
1,931,272
|
|
Proved undeveloped reserves
|
|
1,827,975
|
|
|
1,344,222
|
|
|
1,800,325
|
|
Total proved developed and undeveloped reserves(a)
|
|
3,993,458
|
|
|
3,480,027
|
|
|
3,731,597
|
|
(a)
|
For additional information on our reserves, see “Other Supplemental Information–Supplemental Gas Data (unaudited) to the Consolidated Financial Statements in Item 8 of this Form 10-K.
|
|
|
Discounted Future
|
||||||||||
|
|
Net Cash Flows
|
||||||||||
|
|
(Dollars in millions)
|
||||||||||
|
|
2012
|
|
2011
|
|
2010
|
||||||
Future net cash flows
|
|
$
|
2,792
|
|
|
$
|
4,877
|
|
|
$
|
5,474
|
|
Total PV-10 measure of pre-tax discounted future net cash flows (1)
|
|
$
|
1,242
|
|
|
$
|
2,861
|
|
|
$
|
2,780
|
|
Total standardized measure of after tax discounted future net cash flows
|
|
$
|
736
|
|
|
$
|
1,747
|
|
|
$
|
1,661
|
|
(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,
|
||||||||||
|
|
2012
|
|
2011
|
|
2010
|
||||||
|
|
(Dollars in millions)
|
||||||||||
Future cash inflows
|
|
$
|
11,778
|
|
|
$
|
14,804
|
|
|
$
|
16,724
|
|
Future production costs
|
|
(4,824
|
)
|
|
(5,263
|
)
|
|
(5,176
|
)
|
|||
Future development costs (including abandonments)
|
|
(2,451
|
)
|
|
(1,675
|
)
|
|
(2,720
|
)
|
|||
Future net cash flows (pre-tax)
|
|
4,503
|
|
|
7,866
|
|
|
8,828
|
|
|||
10% discount factor
|
|
(3,261
|
)
|
|
(5,005
|
)
|
|
(6,048
|
)
|
|||
PV-10 (Non-GAAP measure)
|
|
1,242
|
|
|
2,861
|
|
|
2,780
|
|
|||
Undiscounted income taxes
|
|
(1,711
|
)
|
|
(2,989
|
)
|
|
(3,354
|
)
|
|||
10% discount factor
|
|
1,205
|
|
|
1,875
|
|
|
2,235
|
|
|||
Discounted income taxes
|
|
(506
|
)
|
|
(1,114
|
)
|
|
(1,119
|
)
|
|||
Standardized GAAP measure
|
|
$
|
736
|
|
|
$
|
1,747
|
|
|
$
|
1,661
|
|
|
|
For the Year
|
|||||||
|
|
Ended December 31,
|
|||||||
|
|
2012
|
|
2011
|
|
2010
|
|||
|
|
(in million cubic feet)
|
|||||||
CBM segment
|
|
88,149
|
|
|
92,360
|
|
|
91,351
|
|
Shallow Oil and Gas segment
|
|
29,204
|
|
|
32,168
|
|
|
24,646
|
|
Marcellus segment
|
|
36,476
|
|
|
26,873
|
|
|
10,408
|
|
Other Gas segment
|
|
2,495
|
|
|
2,103
|
|
|
1,470
|
|
Total Produced
|
|
156,324
|
|
|
153,504
|
|
|
127,875
|
|
|
|
For the Year
|
||||||||||
|
|
Ended December 31,
|
||||||||||
|
|
2012
|
|
2011
|
|
2010
|
||||||
Average Gas Sales Price Before Effects of Financial Settlements (per thousand cubic feet)
|
|
$
|
3.01
|
|
|
$
|
4.27
|
|
|
$
|
4.53
|
|
Average Effects of Financial Settlements (per thousand cubic feet)
|
|
$
|
1.21
|
|
|
$
|
0.63
|
|
|
$
|
1.30
|
|
Average Gas Sales Price Including Effects of Financial Settlements (per thousand cubic feet)
|
|
$
|
4.22
|
|
|
$
|
4.90
|
|
|
$
|
5.83
|
|
Average Lifting Costs excluding ad valorem and severance taxes (per thousand cubic feet)
|
|
$
|
0.58
|
|
|
$
|
0.68
|
|
|
$
|
0.50
|
|
a.
|
A wage increase of $1.00 per hour effective July 1, 2011, and an additional $1.00 per hour increase each January 1
st
throughout the contract term.
|
b.
|
Contributions to the 1974 Pension Plan, a multi-employer plan, will continue at the current rate of $5.50 per hour throughout the contract term. New inexperienced miners hired after December 31, 2011 do not participate in the 1974 Pension Plan, but receive a $1.00 per hour contribution (increasing to $1.50 per hour in 2014-2016) to the UMWA Cash Deferred Savings Plan (CDSP), which is a 401(k) Plan. UMWA represented employees with over 20 years of credited service under the 1974 Pension Plan receive a $1.00 per hour contribution (increasing to $1.50 per hour in 2014-2016) to the CDSP beginning January 1, 2012. Also beginning January 1, 2012, UMWA represented employees have the right to elect to opt-out of future participation in the 1974 Pension Plan and upon such election, receive a $1.00 per hour contribution (increasing to $1.50 per hour in 2014 - 2016) to the CDSP.
|
c.
|
A $1.50 per hour contribution starting January 1, 2012 to a new defined contribution plan to provide retiree bonus payments to eligible retirees in 2014, 2015 and 2016.
|
d.
|
An increased contribution from $0.50 per hour to $1.10 per hour effective January 1, 2012 to the 1993 Benefit Plan, which is a defined contribution plan providing health benefits to certain retirees.
|
e.
|
Various other changes related to absenteeism, contributions to various UMWA benefit funds, and eligibility for various vacation days and sick days.
|
•
|
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.
|
•
|
the Surface Mining Control and Reclamation Act of 1977,
|
•
|
the Clean Air Act,
|
•
|
the Clean Water Act,
|
•
|
the Endangered Species Act,
|
•
|
the Resource Conservation and Recovery Act,
|
•
|
the Comprehensive Environmental Response, Compensation and Liability Act,
|
•
|
the Toxic Substances Control Act, and
|
•
|
the Emergency Planning and Community Right to Know Act,
|
ITEM 1A.
|
Risk Factors
|
•
|
demand for natural gas and electricity in the United States is impacted by industrial production, which if weakened would negatively impact the revenues, margins and profitability of our natural gas and thermal coal business;
|
•
|
demand for metallurgical coal depends on steel demand in the United States and globally, which if weakened would negatively impact the revenues, margins and profitability of our metallurgical coal business including our ability to sell our high volatile steam coal as higher-priced metallurgical coal;
|
•
|
the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect our trade receivables and the amount of receivables eligible for sale pursuant to our accounts receivable securitization facility may decline;
|
•
|
our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital for our business including for exploration and/or development of our coal or gas reserves; and
|
•
|
our commodity hedging arrangements could become ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection.
|
•
|
overall domestic and global economic conditions, technological advances affecting energy consumption, price and availability of foreign coal, and domestic and foreign government regulations;
|
•
|
the consumption pattern of industrial consumers, electricity generators and residential users as well as weather can impact thermal coal (for example, the unusually warm 2011 - 2012 winter left utilities with large coal stockpiles and depressed the demand for thermal coal);
|
•
|
the price and availability of alternative fuels for electricity generation, especially natural gas (for example, abundant natural gas supplies at prices averaging less than $3/MMBtu during 2012 depressed the demand for thermal coal as natural gas fired electricity generation market share increased from approximately 27% in 2011 to 30% in 2012 and coal-fired generation declined from approximately 46% in 2011 to 37.5% in 2012); and
|
•
|
increased utilization by the steel industry of electric arc furnaces or pulverized coal processes to make steel which do not use furnace coke, an intermediate product produced from metallurgical coal, decreases the demand for metallurgical coal.
|
•
|
the domestic supply of natural gas;
|
•
|
the consumption pattern of industrial consumers, electricity generators and residential users and weather conditions;
|
•
|
proximity and capacity of gas pipelines and other transportation facilities;
|
•
|
overall domestic and global economic conditions;
|
•
|
the price and availability of alternative fuels, especially thermal coal; and
|
•
|
the price and supply of imported liquefied natural gas.
|
•
|
variations in thickness of the layer, or seam, of coal;
|
•
|
amounts of rock and other natural materials intruding into the coal seam and other geological conditions that could affect the stability of the roof and the side walls of the mine;
|
•
|
equipment failures or repairs;
|
•
|
fires, explosions or other accidents;
|
•
|
weather conditions; and
|
•
|
security breaches or terroristic acts.
|
•
|
unexpected drilling conditions;
|
•
|
title problems;
|
•
|
pressure or irregularities in geologic formations;
|
•
|
equipment failures or repairs;
|
•
|
fires, explosions or other accidents;
|
•
|
adverse weather conditions;
|
•
|
reductions in natural gas prices;
|
•
|
security breaches or terroristic acts;
|
•
|
pipeline ruptures;
|
•
|
lack of adequate capacity for treatment or disposal of waste water generated in drilling, completion and production operations;
|
•
|
environmental contamination from surface spillage of fluids used in well drilling, completion or operation including fracturing fluids used in hydraulic fracturing of wells, or other contamination of groundwater or the environment resulting from our use of such fluids; and
|
•
|
unavailability or high cost of drilling rigs, other field services and equipment.
|
•
|
geological conditions;
|
•
|
historical production from the area compared with production from other producing areas;
|
•
|
the assumed effects of regulations and taxes by governmental agencies;
|
•
|
assumptions governing future prices; and
|
•
|
future operating costs, including the cost of materials.
|
•
|
geological conditions;
|
•
|
changes in governmental regulations and taxation;
|
•
|
the amount and timing of actual production;
|
•
|
assumptions governing future prices;
|
•
|
future operating costs; and
|
•
|
capital costs of drilling new wells.
|
•
|
postretirement medical and life insurance ($3.0 billion);
|
•
|
coal workers' black lung benefits ($184.1 million);
|
•
|
salaried retirement benefits ($224.9 million); and
|
•
|
workers' compensation ($179.6 million).
|
•
|
uncertainties in assessing the value, strengths, and potential profitability of, and identifying the extent of all weaknesses, risks, contingent and other liabilities (including environmental liabilities) of expansion and acquisition opportunities;
|
•
|
the potential loss of key customers, management and employees of an acquired business;
|
•
|
the ability to achieve identified operating and financial synergies anticipated to result from an expansion or an acquisition opportunity;
|
•
|
the potential revision of assumptions regarding gas reserves as we acquire more knowledge by operating an acquired gas business;
|
•
|
problems that could arise from the integration of the acquired business;
|
•
|
unanticipated changes in business, industry or general economic conditions that affect the assumptions underlying our rationale for pursuing the expansion or the acquisition opportunity; and
|
•
|
we may have to assume cleanup or reclamation obligations or other unanticipated liabilities in connection with these acquisitions.
|
•
|
The development of these properties is subject to the terms of our joint development agreements with these parties and we no longer have the flexibility to control the development of these properties. For example, the joint development agreements for each of these joint ventures sets forth required capital expenditure programs that each party must participate in unless the parties mutually agree to change such programs or, in certain limited circumstances in the case of the Noble Energy joint development agreement, a party elects to exercise a non-consent right with respect to an entire year. If we do not timely meet our financial commitments under the respective joint venture agreements, our rights to participate in such joint ventures will be adversely affected and the other parties to the joint ventures may have a right to acquire a share of our interest in such joint ventures proportionate to, and in satisfaction of, our unmet financial obligations. In addition, each joint venture party has the right to elect to participate in all acreage and other acquisitions in certain defined areas of mutual interest.
|
•
|
Each joint development agreement assigns to each party designated areas over which that party will manage and control operations. We could incur liability as a result of action taken by one of our joint venture partners.
|
•
|
Of the approximately $3.3 billion we anticipate receiving from Noble Energy, approximately $2.1 billion depends upon Noble Energy paying a portion of our share of drilling and development costs for new wells, which we call “carried costs.” We entered into a similar transaction with Hess Ohio Developments, LLC (Hess) in which approximately $534 million of the total anticipated consideration of $594 million is dependent upon Hess paying carried costs. Thus, the benefits we anticipate receiving in the joint ventures depend in part upon the rate at which new wells are drilled and developed in each joint venture, which could fluctuate significantly from period to period. Moreover, the performance of these third party obligations is outside our control. The inability or failure of a joint venturer to pay its portion of development costs, including our carried costs during the carry period, could increase our costs of operations or result in reduced drilling and production of oil and gas or loss of rights to develop the oil and gas properties held by that joint venture.
|
•
|
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
|
•
|
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.
|
•
|
Under our joint venture agreements with Noble Energy and Hess, each of them has the right to perform due diligence on the title to the oil and gas interests which we conveyed to them and to assert that title to the acreage is defective. CONSOL Energy then can review and respond to the asserted title defects, or cure them, and ultimately, if the claim is not resolved, either party can submit the defect to an arbitrator for resolution. CONSOL Energy also has the right to require the defected acreage to be reassigned in certain circumstances. We are currently engaged in this title review process with Noble and Hess. If they establish any title defects which are not resolved in favor of CONSOL Energy or if the subject acreage is reassigned to us at our request, then subject to certain deductibles, Noble's and Hess's respective aggregate carried cost obligation under the joint venture agreements will be reduced by the value the parties previously allocated to the affected acreage in the transaction. If a significant percentage of the oil and gas interests we contributed have title defects, the carried costs could be materially reduced and our aggregate share of the drilling and completion costs for wells in these joint ventures could materially increase. To date, Noble has asserted formal title defects with respect to approximately 30,171 gross deal acres, which have an aggregate transaction value of $196 million. We believe that we will resolve most of those defects favorably to CONSOL Energy. To date, we have conceded defects to Noble which have an aggregate value equal to less than the applicable deductibles and the impact of these conceded defects on the Company's financial statements has not been material. In the case of our Ohio Utica Shale joint venture with Hess, based on title work performed by Hess, we believe that there are chain of title issues with respect to approximately 36,000 of the joint venture acres, most of which likely cannot be cured. Hess's 50% interest in these 36,000 acres has an allocated transaction value of approximately $146 million and may result in a corresponding reduction of the associated carried interest. The loss of these Utica Shale acres itself will not have a material impact on the Company's financial statements. After accounting for these defective acres, there are approximately 161,000 acres in our Ohio Utica Shale joint venture with Hess.
|
•
|
increasing our vulnerability to general adverse economic and industry conditions;
|
•
|
limiting our ability to obtain additional financing to fund future working capital, capital expenditures, acquisitions, development of our coal and gas reserves or other general corporate requirements;
|
•
|
limiting our flexibility in planning for, or reacting to, changes in our business and in the coal and gas industries; and
|
•
|
placing us at a competitive disadvantage compared to less leveraged competitors.
|
•
|
our production is less than expected;
|
•
|
the counterparties to our contracts fail to perform the contracts; or
|
•
|
the creditworthiness of our counterparties or their guarantors is substantially impaired.
|
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, 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
|
|
Year Period Ended December 31, 2011
|
|
|
|
|
|
|
|||||||
|
Quarter Ended March 31, 2011
|
|
$
|
55.49
|
|
|
$
|
45.49
|
|
|
$
|
0.100
|
|
|
Quarter Ended June 30, 2011
|
|
$
|
54.17
|
|
|
$
|
45.86
|
|
|
$
|
0.100
|
|
|
Quarter Ended September 30, 2011
|
|
$
|
54.82
|
|
|
$
|
33.93
|
|
|
$
|
0.100
|
|
|
Quarter Ended December 31, 2011
|
|
$
|
46.75
|
|
|
$
|
31.70
|
|
|
$
|
0.125
|
|
|
|
2007
|
|
2008
|
|
2009
|
|
2010
|
|
2011
|
|
2012
|
||||||
CONSOL Energy Inc.
|
|
100.0
|
|
|
40.5
|
|
|
71.1
|
|
|
70.2
|
|
|
53.5
|
|
|
47.7
|
|
Peer Group
|
|
100.0
|
|
|
60.3
|
|
|
89.5
|
|
|
101.9
|
|
|
85.3
|
|
|
80.1
|
|
S&P 500 Stock Index
|
|
100.0
|
|
|
63.4
|
|
|
79.8
|
|
|
91.7
|
|
|
91.7
|
|
|
104.0
|
|
ITEM 6.
|
Selected Financial Data
|
|
|
For the Years Ended December 31,
|
||||||||||||||||||
|
|
2012
|
|
2011
|
|
2010
|
|
2009
|
|
2008
|
||||||||||
Sales–Outside(A)
|
|
$
|
4,825,946
|
|
|
$
|
5,660,813
|
|
|
$
|
4,938,703
|
|
|
$
|
4,311,791
|
|
|
$
|
4,181,569
|
|
Sales–Gas Royalty Interest(A)
|
|
49,405
|
|
|
66,929
|
|
|
62,869
|
|
|
40,951
|
|
|
79,302
|
|
|||||
Sales–Purchased Gas(A)
|
|
3,316
|
|
|
4,344
|
|
|
11,227
|
|
|
7,040
|
|
|
8,464
|
|
|||||
Freight–Outside(A)
|
|
141,936
|
|
|
231,536
|
|
|
125,715
|
|
|
148,907
|
|
|
216,968
|
|
|||||
Other Income
|
|
409,704
|
|
|
153,620
|
|
|
97,507
|
|
|
113,186
|
|
|
166,142
|
|
|||||
Total Revenue and Other Income
|
|
5,430,307
|
|
|
6,117,242
|
|
|
5,236,021
|
|
|
4,621,875
|
|
|
4,652,445
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)
|
|
3,421,953
|
|
|
3,501,298
|
|
|
3,262,327
|
|
|
2,757,052
|
|
|
2,843,203
|
|
|||||
Gas Royalty Interests' Costs
|
|
38,867
|
|
|
59,331
|
|
|
53,775
|
|
|
32,376
|
|
|
73,962
|
|
|||||
Purchased Gas Costs
|
|
2,711
|
|
|
3,831
|
|
|
9,736
|
|
|
6,442
|
|
|
8,175
|
|
|||||
Freight Expense
|
|
141,936
|
|
|
231,347
|
|
|
125,544
|
|
|
148,907
|
|
|
216,968
|
|
|||||
Selling, General and Administrative Expenses
|
|
148,071
|
|
|
175,467
|
|
|
150,210
|
|
|
130,704
|
|
|
124,543
|
|
|||||
Depreciation, Depletion and Amortization
|
|
622,780
|
|
|
618,397
|
|
|
567,663
|
|
|
437,417
|
|
|
389,621
|
|
|||||
Interest Expense
|
|
220,060
|
|
|
248,344
|
|
|
205,032
|
|
|
31,419
|
|
|
36,183
|
|
|||||
Taxes Other Than Income
|
|
336,655
|
|
|
344,460
|
|
|
328,458
|
|
|
289,941
|
|
|
289,990
|
|
|||||
Abandonment of Long-Lived Assets
|
|
—
|
|
|
115,817
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Loss on Debt Extinguishment
|
|
—
|
|
|
16,090
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Transaction and Financing Fees
|
|
—
|
|
|
14,907
|
|
|
65,363
|
|
|
—
|
|
|
—
|
|
|||||
Black Lung Excise Tax Refund
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(728
|
)
|
|
(55,795
|
)
|
|||||
Total Costs
|
|
4,933,033
|
|
|
5,329,289
|
|
|
4,768,108
|
|
|
3,833,530
|
|
|
3,926,850
|
|
|||||
Earnings Before Income Taxes
|
|
497,274
|
|
|
787,953
|
|
|
467,913
|
|
|
788,345
|
|
|
725,595
|
|
|||||
Income Taxes
|
|
109,201
|
|
|
155,456
|
|
|
109,287
|
|
|
221,203
|
|
|
239,934
|
|
|||||
Net Income
|
|
388,073
|
|
|
632,497
|
|
|
358,626
|
|
|
567,142
|
|
|
485,661
|
|
|||||
Less: Net Loss (Income) Attributable to Noncontrolling Interest
|
|
397
|
|
|
—
|
|
|
(11,845
|
)
|
|
(27,425
|
)
|
|
(43,191
|
)
|
|||||
Net Income Attributable to CONSOL Energy Inc. Shareholders
|
|
$
|
388,470
|
|
|
$
|
632,497
|
|
|
$
|
346,781
|
|
|
$
|
539,717
|
|
|
$
|
442,470
|
|
Earnings Per Share:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic(B)
|
|
$
|
1.71
|
|
|
$
|
2.79
|
|
|
$
|
1.61
|
|
|
$
|
2.99
|
|
|
$
|
2.43
|
|
Dilutive(B)
|
|
$
|
1.70
|
|
|
$
|
2.76
|
|
|
$
|
1.60
|
|
|
$
|
2.95
|
|
|
$
|
2.40
|
|
Weighted Average Number of Common Shares Outstanding:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
|
227,593,524
|
|
|
226,680,369
|
|
|
214,920,561
|
|
|
180,693,243
|
|
|
182,386,011
|
|
|||||
Dilutive
|
|
229,141,767
|
|
|
229,003,599
|
|
|
217,037,804
|
|
|
182,821,136
|
|
|
184,679,592
|
|
|||||
Dividends Paid Per Share
|
|
$
|
0.625
|
|
|
$
|
0.425
|
|
|
$
|
0.400
|
|
|
$
|
0.400
|
|
|
$
|
0.400
|
|
|
|
December 31,
|
||||||||||||||||||
|
|
2012
|
|
2011
|
|
2010
|
|
2009
|
|
2008
|
||||||||||
Working capital (deficiency)
|
|
$
|
151,995
|
|
|
$
|
509,580
|
|
|
$
|
(549,779
|
)
|
|
$
|
(487,550
|
)
|
|
$
|
(527,926
|
)
|
Total assets
|
|
$
|
12,670,909
|
|
|
$
|
12,525,700
|
|
|
$
|
12,070,610
|
|
|
$
|
7,775,401
|
|
|
$
|
7,535,458
|
|
Short-term debt
|
|
$
|
62,919
|
|
|
$
|
—
|
|
|
$
|
484,000
|
|
|
$
|
522,850
|
|
|
$
|
722,700
|
|
Long-term debt (including current portion)
|
|
$
|
3,188,071
|
|
|
$
|
3,198,114
|
|
|
$
|
3,210,921
|
|
|
$
|
468,302
|
|
|
$
|
490,752
|
|
Total deferred credits and other liabilities
|
|
$
|
4,155,479
|
|
|
$
|
4,348,995
|
|
|
$
|
4,283,674
|
|
|
$
|
3,849,428
|
|
|
$
|
3,716,021
|
|
CONSOL Energy Inc. Stockholders' equity
|
|
$
|
3,953,792
|
|
|
$
|
3,610,885
|
|
|
$
|
2,944,477
|
|
|
$
|
1,785,548
|
|
|
$
|
1,462,187
|
|
|
|
Years Ended December 31,
|
||||||||||||||||||
|
|
2012
|
|
2011
|
|
2010
|
|
2009
|
|
2008
|
||||||||||
Coal:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Tons sold (in thousands)(C)
|
|
56,909
|
|
|
63,278
|
|
|
63,297
|
|
|
57,771
|
|
|
66,017
|
|
|||||
Tons produced (in thousands)
|
|
55,987
|
|
|
62,048
|
|
|
61,733
|
|
|
59,038
|
|
|
64,858
|
|
|||||
Average sales price of tons produced ($ per ton produced)
|
|
$
|
67.11
|
|
|
$
|
72.25
|
|
|
$
|
61.33
|
|
|
$
|
58.70
|
|
|
$
|
47.59
|
|
Average Cost of Goods Sold ($ per ton produced)
|
|
$
|
52.42
|
|
|
$
|
50.82
|
|
|
$
|
45.49
|
|
|
$
|
43.36
|
|
|
$
|
39.89
|
|
Recoverable coal reserves (tons in millions)(D)
|
|
4,270
|
|
|
4,459
|
|
|
4,401
|
|
|
4,520
|
|
|
4,543
|
|
|||||
Number of active mining complexes (at end of period)
|
|
11
|
|
|
12
|
|
|
12
|
|
|
11
|
|
|
17
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Gas:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net sales volumes produced (in billion cubic feet)
|
|
156.3
|
|
|
153.5
|
|
|
127.9
|
|
|
94.4
|
|
|
76.6
|
|
|||||
Average sales price ($ per mcf)(E)
|
|
$
|
4.22
|
|
|
$
|
4.90
|
|
|
$
|
5.83
|
|
|
$
|
6.68
|
|
|
$
|
8.99
|
|
Average cost ($ per mcf)
|
|
$
|
3.37
|
|
|
$
|
3.53
|
|
|
$
|
3.54
|
|
|
$
|
3.15
|
|
|
$
|
3.25
|
|
Proved reserves (in billion cubic feet)(F)
|
|
3,993
|
|
|
3,480
|
|
|
3,732
|
|
|
1,911
|
|
|
1,422
|
|
|
|
For the Years Ended December 31,
|
||||||||||||||||||
|
|
2012
|
|
2011
|
|
2010
|
|
2009
|
|
2008
|
||||||||||
Net cash provided by operating activities
|
|
$
|
728,129
|
|
|
$
|
1,527,606
|
|
|
$
|
1,131,312
|
|
|
$
|
1,060,451
|
|
|
$
|
989,864
|
|
Net cash used in investing activities(G)
|
|
$
|
(1,000,410
|
)
|
|
$
|
(578,524
|
)
|
|
$
|
(5,543,974
|
)
|
|
$
|
(845,341
|
)
|
|
$
|
(1,098,856
|
)
|
Net cash provided by (used in) financing activities
|
|
$
|
(81,577
|
)
|
|
$
|
(606,140
|
)
|
|
$
|
4,379,849
|
|
|
$
|
(288,015
|
)
|
|
$
|
205,853
|
|
|
|
For the Years Ended December 31,
|
||||||||||||||||||
|
|
2012
|
|
2011
|
|
2010
|
|
2009
|
|
2008
|
||||||||||
Capital expenditures
|
|
$
|
1,575,230
|
|
|
$
|
1,382,371
|
|
|
$
|
1,154,024
|
|
|
$
|
920,080
|
|
|
$
|
1,061,669
|
|
Adjusted EBIT(H)
|
|
$
|
688,794
|
|
|
$
|
1,159,285
|
|
|
$
|
653,458
|
|
|
$
|
786,520
|
|
|
$
|
685,574
|
|
Adjusted EBITDA(H)
|
|
$
|
1,311,574
|
|
|
$
|
1,777,682
|
|
|
$
|
1,221,121
|
|
|
$
|
1,223,937
|
|
|
$
|
1,075,195
|
|
Ratio of earnings to fixed charges(I)
|
|
2.58
|
|
|
3.53
|
|
|
2.74
|
|
|
11.76
|
|
|
10.67
|
|
(A)
|
See Note 24–Segment Information in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for sales and freight by operating segment.
|
(B)
|
Basic earnings per share are computed using weighted average shares outstanding. Differences in the weighted average number of shares outstanding for purposes of computing dilutive earnings per share are due to the inclusion of the weighted average dilutive effect of employee and non-employee share-based compensation granted, totaling 1,548,243 shares, 2,323,230 shares, 2,117,243 shares, 2,127,893 shares, and 2,293,581 shares for the year ended
December 31, 2012
,
2011
,
2010
,
2009
, and
2008
, respectively.
|
(C)
|
Includes sales of coal produced by CONSOL Energy and purchased from third parties. Of the tons sold, CONSOL Energy purchased the following amount from third parties: 0.5 million tons, 0.6 million tons, 0.3 million tons, 0.3 million tons, and 1.7 million tons for the years ended
December 31, 2012
,
2011
,
2010
,
2009
and
2008
, respectively.
|
(D)
|
Represents proven and probable coal reserves at period end.
|
(E)
|
Represents average net sales price including the effect of derivative transactions.
|
(F)
|
Represents proved developed and undeveloped gas reserves at period end.
|
(G)
|
Net cash used in investing activities includes $327,964 for collection of Noble Note Receivable related to the 2011 agreement, $169,500 related to the disposition of the Northern Powder River Basin assets, $51,869 related to the disposition of the Ram River & Scurry Ram assets, $26,000 related to the disposition of the Elk Creek property, and $13,023 related to the disposition of the Burning Star No. 4 property in the year ended December 31, 2012. The year ended December 31, 2011 includes $485,464 related to the Noble transaction, $190,381 related to the Antero Transaction, and $54,099 related to the Hess Transaction. The year ended December 31, 2010 includes $3,470,212 and $991,034 related to the Dominion Acquisition and the purchase of CNX Gas Non-Controlling Interest, respectively.
|
(H)
|
Adjusted EBIT is defined as earnings before deducting net interest expense (interest expense less interest income), income taxes, loss on debt extinguishment, and abandonment of long-lived assets. Adjusted EBITDA is defined as earnings before deducting net interest expense (interest expense less interest income), income taxes and depreciation, depletion and amortization. Although adjusted EBIT and adjusted EBITDA are not measures of performance calculated in accordance with generally accepted accounting principles, management believes that they are useful to an investor in evaluating CONSOL Energy because they are widely used in the coal industry as measures to evaluate a company's operating performance before debt expense and cash flow. Financial covenants in our credit facility include ratios based on adjusted EBITDA. Adjusted EBIT and adjusted EBITDA do not purport to represent cash generated by operating activities and should not be considered in isolation or as a substitute for measures of performance in accordance with generally accepted accounting principles. In addition, because adjusted EBIT and adjusted EBITDA are not calculated identically by all companies, the presentation here may not be comparable to other similarly titled measures of other companies. Management's discretionary use of funds depicted by adjusted EBIT and adjusted EBITDA may be limited by working capital, debt service and capital expenditure requirements, and by restrictions related to legal requirements, commitments and uncertainties. A reconcilement of adjusted EBIT and adjusted EBITDA to financial net income is as follows:
|
|
|
For the Years Ended December 31,
|
||||||||||||||||||
|
|
2012
|
|
2011
|
|
2010
|
|
2009
|
|
2008
|
||||||||||
Net Income
|
|
$
|
388,470
|
|
|
$
|
632,497
|
|
|
$
|
346,781
|
|
|
$
|
539,717
|
|
|
$
|
442,470
|
|
Add: Interest expense
|
|
220,060
|
|
|
248,344
|
|
|
205,032
|
|
|
31,419
|
|
|
36,183
|
|
|||||
Less: Interest income
|
|
(28,937
|
)
|
|
(8,919
|
)
|
|
(7,642
|
)
|
|
(5,052
|
)
|
|
(2,363
|
)
|
|||||
Less: Interest income included in black lung excise tax refund
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(767
|
)
|
|
(30,650
|
)
|
|||||
Add: Income tax expense
|
|
109,201
|
|
|
155,456
|
|
|
109,287
|
|
|
221,203
|
|
|
239,934
|
|
|||||
Add: Loss on Debt Extinguishment
|
|
—
|
|
|
16,090
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Add: Abandonment of Long-Lived Assets
|
|
—
|
|
|
115,817
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Adjusted Earnings before interest and taxes (Adjusted EBIT)
|
|
688,794
|
|
|
1,159,285
|
|
|
653,458
|
|
|
786,520
|
|
|
685,574
|
|
|||||
Add: Depreciation, depletion and amortization
|
|
622,780
|
|
|
618,397
|
|
|
567,663
|
|
|
437,417
|
|
|
389,621
|
|
|||||
Adjusted Earnings before interest, taxes and depreciation, depletion and amortization (Adjusted EBITDA)
|
|
$
|
1,311,574
|
|
|
$
|
1,777,682
|
|
|
$
|
1,221,121
|
|
|
$
|
1,223,937
|
|
|
$
|
1,075,195
|
|
(I)
|
For purposes of computing the ratio of earnings to fixed charges, earnings represent income before income taxes plus fixed charges. Fixed charges include (a) interest on indebtedness (whether expensed or capitalized), (b) amortization of debt discounts and premiums and capitalized expenses related to indebtedness and (c) the portion of rent expense we believe to be representative of interest.
|
ITEM 7.
|
Management's Discussion and Analysis of Financial Condition and Results of Operations
|
•
|
In April 2012, CONSOL Energy sold its non-producing Elk Creek reserves in southern West Virginia. The transaction resulted in cash proceeds of $26 million and a gain on sale of assets of $11 million.
|
•
|
In February 2012, CONSOL Energy sold it's non-producing Burning Star #4 reserves in Illinois. The transaction resulted in cash proceeds of $13 million and a gain on sale of assets of $11 million.
|
•
|
In June 2012, CONSOL Energy sold its non-producing Northern Powder River Basin assets in southern Montana and northern Wyoming for $170 million in cash to Cloud Peak Energy. Additionally, CONSOL Energy retained an 8% production royalty interest on approximately 200 million tons of permitted fee coal. This transaction resulted in a pre-tax gain of $151 million.
|
•
|
In June 2012, CONSOL Energy expanded an existing mining joint venture with a privately-held company in Central Pennsylvania. The joint venture will self-fund, through retained earnings, a $54 million (gross) expansion in 2012 and 2013. The expansion will enable CONSOL Energy's share of high-vol and mid-vol forecasted coal production to increase from 150,000 tons in 2012 to 900,000 tons in 2015.
|
•
|
In December 2012, CONSOL Energy sold non-producing western Canadian coal assets for $103 million. Ram River Coal Corp., a private Ontario company created by Forbes & Manhattan Inc. (F&M) (a private merchant bank headquartered in Toronto, Canada) acquired 100% of CONSOL Energy's Ram River and Scurry Ram coal properties for aggregate consideration of $105 million ($102.5 million payable to CONSOL Energy). On closing, Ram River Coal Corp. made an aggregate cash payment of $55.0 million ($52.5 million payable to CONSOL Energy) and under the terms of the asset purchase agreement provides for additional payments to CONSOL Energy of $25.5 million on or before June 21, 2013 and $24.5 million on or before June 21, 2014. The transaction resulted in an after-tax gain of $60.7 million.
|
•
|
In December 2012, CONSOL Energy agreed to sell its interest in other coal assets, subject to certain conditions, in Alberta, for $24 million. The buyer is Riversdale Resources, headquartered in Sydney, Australia. The primary asset is Grassy Mountain Surface Mine. The sale is anticipated to close during the second quarter of 2013, and as such, no gain has been recognized as of December 31, 2012.
|
•
|
CONSOL Energy continues to explore potential sales of assets.
|
•
|
In November 2012, CONSOL Energy offered a voluntary severance incentive program (VSIP) to active salaried corporate and operation support employees with 30 years of service, or more. Under this program, eligible employees who accepted the offer will receive a severance payment equal to one year's salary and the 2013 accrued vacation earned as of December 31, 2012. Approximately 100 employees volunteered for the program. Severance and vacation pay was approximately $13.3 million and was recognized in other accrued liabilities at December 31, 2012. These enhanced benefits were paid in January 2013.
|
•
|
On July 27, 2012 a structural failure occurred at CONSOL Energy's newly installed above-ground conveyor system at the Bailey Preparation Plant in Southwestern Pennsylvania. The belt system conveys coal from the Bailey and Enlow Fork mines to the Bailey Preparation Plant. This incident caused a total of four longwalls to be idled for approximately three weeks, at which point one rebuilt conveyor belt was re-started. Production from these mines was at approximately 60% of normal for most of the remainder of the third quarter. The company's net income would have been an estimated $53 million higher, had the conveyor belt incident not occurred. This impact is before the receipt of any insurance proceeds and any other proceeds under the indemnity provisions of the construction contract. CONSOL Energy has received $2.3 million of business interruption insurance proceeds related to this incident, included in its 2012 results of operations. Although CONSOL Energy's insurance claim is higher than the proceeds received to date, there is no guarantee that additional monies will be received.
|
•
|
In June 2012, CONSOL Energy announced that it acquired a non-controlling interest in Epiphany Solar Water Systems, a privately-held company founded in New Castle, PA in 2009. Epiphany Solar Water Systems is testing what is believed to be the world's first concentrated solar powered water purification system. Under the agreement, CONSOL Energy has made an initial investment of $0.5 million and one of its Marcellus gas well locations in Greene County served as the site to pilot test this solar powered water purification system. Initial testing of the Epiphany unit demonstrated the efficacy of the approach. Based on results of the pilot test, system improvements and upgrades are being implemented. Additional testing is ongoing and will be used to evaluate system enhancements in the coming months.
|
•
|
In April 2012, CONSOL Energy announced certain changes to the salaried other post-retirement benefit plan that current retirees and current active employees will receive as of January 1, 2014. The change provides a fixed annual retiree medical contribution into a Health Reimbursement Account for eligible employees. The money in the account can be used to help pay for a commercial medical plan, Medicare Part B and Part D premiums and other qualified expenses. Employees who work or worked in corporate or operational support positions at retirement and who are age 50 or older at December 31, 2013 will receive the revised benefit in lieu of the current retiree medical and prescription drug coverage. Employees who work or worked in corporate or operations support positions who are under age 50 at December 31, 2013 will receive no retiree medical or prescription drug benefit. CONSOL Energy remeasured the salaried other postretirement plan as of March 31, 2012 to recognize these changes. The remeasurement reflects the reduction in benefits and the change in discount rate from 4.51% at December 31, 2011 to 4.57% at March 31, 2012. The remeasurement resulted in a reduction of approximately $80.6 million of Other Post-Retirement Benefits (OPEB) liability with a corresponding offset to Other Comprehensive Income, net of applicable deferred taxes. The change resulted in a $9.4 million reduction in OPEB expense compared to what was originally expected to be recognized for the year ended December 31, 2012. The change was made to align CONSOL Energy's corporate and operational support compensation package more closely with our peer group.
|
•
|
Pennsylvania enacted Act 13 of 2012, which provides for the comprehensive regulation of Marcellus Shale development in Pennsylvania. Among other things, Act 13 requires an impact fee be paid annually on all nonconventional gas wells drilled in the state. The annual fee is based on annual average sales price and is modified annually for a 15-year period for each well. The impact fee also required the first year fee be paid on all applicable wells drilled before January 1, 2012 with subsequent annual fees to apply each year thereafter. CONSOL Energy's retroactive impact fee related to wells drilled prior to January 1, 2012 was approximately $4 million. This amount was paid in September 2012.
|
•
|
On December 10, 2012, CONSOL Energy's board of directors accelerated the declaration and payment of the regular quarterly dividend of $0.125 per share, payable on December 28, 2012, to shareholders of record on December 21, 2012.
|
•
|
Challenges in the overall environment in which we operate create increased risks that we must continuously monitor and manage. These risks include (i) increased prices for commodities such as diesel fuel, synthetic rubber and steel that we use in our operations (although prices for some of these commodities declined during the year from previous years), (ii) increased scrutiny of existing safety regulations and the development of new safety regulations and (iii) additional environmental restrictions.
|
•
|
Federal and state environmental regulators are reviewing our operations more closely and are more strictly interpreting and enforcing existing environmental laws and regulations, resulting in increased costs and delays. For example, we entered into a consent decree with the EPA and the West Virginia Department of Environmental Protection pursuant to which we agreed to construct an advanced technology mine water treatment plant and related facilities to reduce high levels of chlorides in water discharges from certain of our mines in Northern West Virginia, at a total estimated cost of approximately $200 million. The new facility must be placed into service no later than May 2013.
|
•
|
Federal and state regulators have proposed regulations which, if adopted, would adversely impact our business. These proposed regulations could require significant changes in the manner in which we operate and/or would increase the cost of our operations. For example, the Department of Interior, Office of Surface Mining Reclamation and Enforcement (OSM) is currently preparing an environmental impact statement relating to OSM's consideration of five alternatives for amending its coal mining stream protection rules. All of the alternatives, except the no action alternative, could make it more costly to mine our coal and/or could eliminate the ability to mine some of our coal. Other examples are the Mercury and Air Toxic Standards (MATS) (remanded by the court and reproposed by the EPA in November 2012) and the Utility Maximum Achievable Control Technology (Utility MACTS) rules issued by the EPA. These new regulations set mercury and air toxic standards for new and existing coal and oil fired electric utility steam generating units and include more stringent new source performance standards (NSPS) for particulate matter (PM), SO2 and NOx. Although the EPA intends to reconsider certain aspects of these new rules, some older coal fired
|
•
|
In April 2012, the EPA published its proposed New Source Performance Standards (NSPS) for carbon dioxide emissions from coal powered electric generating units. The proposed rules will apply to new power plants and to existing plants that make major modifications. If the rules are adopted as proposed, the only new coal fired power plants that will be able to meet the proposed emission limits will be coal fired plants with carbon dioxide capture and storage (CCS). Commercial scale CCS is not likely to be available in the near future, and if available, it may make coal fired electric generation units uneconomical compared to new gas fired electric generation units. Thus, if finalized the proposed rules could seriously threaten the construction of new coal fired electric generating units.
|
•
|
In May 2012, CONSOL Energy received a citizens' Notice of Intent to Sue from the Sierra Club, the Ohio Valley Environmental Coalition and the West Virginia Highlands Conservancy alleging violations of the Clean Water Act relating to selenium at its Fola mining complex in central West Virginia. On June 5, 2012, the West Virginia Department of Environmental Protection issued an Administrative Order to Fola. Fola is complying with the Administrative Order. On September 4, 2012, the citizens group filed a complaint against Fola in the U.S District Court for the Southern District of West Virginia covering the same matters addressed in the State Administrative Order.
|
•
|
In late June 2012, CONSOL Energy received informal notification from the Pennsylvania Department of Environmental Protection of the Department's intent pursuant to a Technical Guidance Document entitled “Surface Water Protection-Underground Bituminous Coal Mining” to require a change in the mine plan of a pending application for a permit for expansion of the Company's Bailey longwall mine. If ultimately required, this change in mine plan could have a material effect on CONSOL Energy's forecasted production for 2015. Although CONSOL Energy does not agree that a modification of its mining plan is necessary to comply with applicable regulatory performance standards, CONSOL Energy is currently reviewing the notification and any modifications that would be required if CONSOL Energy is compelled to modify its application.
|
•
|
Under our joint venture agreements with Noble Energy and Hess, each of them has the right to perform due diligence on the title to the oil and gas interests which we conveyed to them and to assert that title to the acreage is defective. If they establish any title defects which are not resolved in favor of CONSOL Energy or if the subject acreage is reassigned to us at our request, then subject to certain deductibles, Noble's and Hess's respective aggregate carried cost obligation under the joint venture agreements will be reduced by the value the parties previously allocated to the affected acreage in the transaction. If a significant percentage of the oil and gas interests we contributed have title defects, the carried costs could be materially reduced and our aggregate share of the drilling and completion costs for wells in these joint ventures could materially increase. To date, Noble has asserted formal title defects with respect to approximately 30,171 gross deal acres, which have an aggregate transaction value of $196 million. We believe that we will resolve most of those defects favorably to CONSOL Energy. To date, we have conceded defects to Noble which have an aggregate value equal to less than the applicable deductibles and the impact of these conceded defects on the Company's financial statements has not been material. In the case of our Ohio Utica Shale joint venture with Hess, based on title work performed by Hess, we believe that there are chain of title issues with respect to approximately 36,000 of the joint venture acres, most of which likely cannot be cured. Hess's 50% interest in these 36,000 acres has an allocated transaction value of approximately $146 million and may result in a corresponding reduction of the associated carried interest. The loss of these Utica Shale acres itself will not have a material impact on the Company's financial statements. After accounting for these defective acres, there are approximately 161,000 acres in our Ohio Utica Shale joint venture with Hess.
|
•
|
A pension settlement charge is reasonably possible to occur in 2013. When lump sum payments from the pension plan exceed the service and interest expense, pension settlement accounting requires unamortized actuarial gains and loss related to the lump sum payouts be amortized immediately. The 2013 threshold for pension settlement recognition is $55 million. If the threshold for pension settlement is reached, the pension settlement charge could be material to the financial results of CONSOL Energy. Also, pension settlement would require the pension plan to be remeasured using updated assumptions. The updated assumptions would include resetting the discount rate used in the actuarial calculation.
|
•
|
CONSOL is also in negotiations with the authority that operates the Pittsburgh International Airport for the lease of the oil and gas rights on approximately 8,800 acres surrounding the airport. These are contiguous acres which are in the liquids area of the Marcellus Shale play.
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2012
|
|
2011
|
|
Variance
|
|
Percent
Change
|
|||||||
Average Sales Price per ton sold
|
$
|
67.11
|
|
|
$
|
72.25
|
|
|
$
|
(5.14
|
)
|
|
(7.1
|
)%
|
Average Costs of Goods Sold per ton
|
52.56
|
|
|
50.69
|
|
|
1.87
|
|
|
3.7
|
%
|
|||
Margin
|
$
|
14.55
|
|
|
$
|
21.56
|
|
|
$
|
(7.01
|
)
|
|
(32.5
|
)%
|
•
|
Average cost of goods sold per ton increased due to fewer tons sold. Fixed costs are allocated over fewer sales tons, resulting in higher unit costs.
|
•
|
The idle longwalls at the Blacksville Mine and the Buchanan Mine during March and April 2012 resulted in an increase in unit costs of approximately $2.16 per ton as the fixed costs were allocated over fewer tons.
|
•
|
Average depreciation, depletion and amortization increased due to additional assets placed into service after the 2011 period.
|
•
|
Average operating supplies and maintenance costs per ton increased due to additional equipment maintenance, timing of major equipment overhaul costs, increased fuel and lubricants and use of pumpable cribs for roof support.
|
•
|
Average labor and labor related expenses increased primarily as result of the impact of the UMWA contract wage increases, offset, in part, by lower overtime hours worked.
|
•
|
Average retirement and disability cost per ton decreased due to the improvement in other postretirement benefits discussed in the long-term liabilities section below.
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2012
|
|
2011
|
|
Variance
|
|
Percent
Change
|
|||||||
Average Sales Price per thousand cubic feet sold
|
$
|
4.22
|
|
|
$
|
4.90
|
|
|
$
|
(0.68
|
)
|
|
(13.9
|
)%
|
Average Costs per thousand cubic feet sold
|
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 thousand cubic feet 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 thousand cubic feet sold due to increased sales volumes and decreased actual dollars as a result of lower direct administrative labor and other costs.
|
•
|
Gathering costs increased in the period-to-period comparison due to higher transportation charges.
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2012
|
|
2011
|
|
Variance
|
|
Percent
Change
|
|||||||
Employee wages and related expenses
|
$
|
60
|
|
|
$
|
68
|
|
|
$
|
(8
|
)
|
|
(11.8
|
)%
|
Consulting and professional services
|
32
|
|
|
37
|
|
|
(5
|
)
|
|
(13.5
|
)%
|
|||
Contributions
|
16
|
|
|
15
|
|
|
1
|
|
|
6.7
|
%
|
|||
Miscellaneous
|
28
|
|
|
32
|
|
|
(4
|
)
|
|
(12.5
|
)%
|
|||
Total Company General and Administrative Expenses
|
$
|
136
|
|
|
$
|
152
|
|
|
$
|
(16
|
)
|
|
(10.5
|
)%
|
•
|
Employee wages and related expenses decreased $8 million primarily attributable to lower salary OPEB expenses in the period-to-period comparison. The lower expenses relate to changes in the discount rates and other assumptions, and a modification to the benefit plan for certain salaried employees.
|
•
|
Consulting and professional services decreased $5 million in the period-to-period comparison due to a reduction in CONSOL Energy's advertising and promotion campaign.
|
•
|
Contributions increased $1 million in the period-to-period comparison due to various transactions, none of which were individually material.
|
•
|
Miscellaneous general and administrative expenses decreased $4 million in the period-to-period comparison due to various transactions throughout both periods, none of which were individually material.
|
|
For the Year Ended
|
|
Increase (Decrease) from 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
|
$
|
3,046
|
|
|
$
|
229
|
|
|
$
|
506
|
|
|
$
|
6
|
|
|
$
|
3,787
|
|
|
$
|
(12
|
)
|
|
$
|
(139
|
)
|
|
$
|
(566
|
)
|
|
$
|
(21
|
)
|
|
$
|
(738
|
)
|
Purchased Coal
|
—
|
|
|
—
|
|
|
—
|
|
|
19
|
|
|
19
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(23
|
)
|
|
(23
|
)
|
||||||||||
Total Outside Sales
|
3,046
|
|
|
229
|
|
|
506
|
|
|
25
|
|
|
3,806
|
|
|
(12
|
)
|
|
(139
|
)
|
|
(566
|
)
|
|
(44
|
)
|
|
(761
|
)
|
||||||||||
Freight Revenue
|
—
|
|
|
—
|
|
|
—
|
|
|
142
|
|
|
142
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(90
|
)
|
|
(90
|
)
|
||||||||||
Other Income
|
1
|
|
|
6
|
|
|
—
|
|
|
323
|
|
|
330
|
|
|
(5
|
)
|
|
(5
|
)
|
|
—
|
|
|
261
|
|
|
251
|
|
||||||||||
Total Revenue and Other Income
|
3,047
|
|
|
235
|
|
|
506
|
|
|
490
|
|
|
4,278
|
|
|
(17
|
)
|
|
(144
|
)
|
|
(566
|
)
|
|
127
|
|
|
(600
|
)
|
||||||||||
Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||
Beginning inventory costs
|
89
|
|
|
2
|
|
|
16
|
|
|
—
|
|
|
107
|
|
|
(9
|
)
|
|
2
|
|
|
6
|
|
|
—
|
|
|
(1
|
)
|
||||||||||
Total direct costs
|
1,539
|
|
|
105
|
|
|
185
|
|
|
172
|
|
|
2,001
|
|
|
(4
|
)
|
|
(37
|
)
|
|
(34
|
)
|
|
20
|
|
|
(55
|
)
|
||||||||||
Total royalty/production taxes
|
201
|
|
|
10
|
|
|
31
|
|
|
3
|
|
|
245
|
|
|
(5
|
)
|
|
(4
|
)
|
|
(36
|
)
|
|
(5
|
)
|
|
(50
|
)
|
||||||||||
Total direct services to operations
|
239
|
|
|
22
|
|
|
21
|
|
|
290
|
|
|
572
|
|
|
(9
|
)
|
|
(8
|
)
|
|
(1
|
)
|
|
39
|
|
|
21
|
|
||||||||||
Total retirement and disability
|
179
|
|
|
12
|
|
|
27
|
|
|
20
|
|
|
238
|
|
|
(53
|
)
|
|
(8
|
)
|
|
(14
|
)
|
|
4
|
|
|
(71
|
)
|
||||||||||
Depreciation, depletion and amortization
|
301
|
|
|
24
|
|
|
37
|
|
|
34
|
|
|
396
|
|
|
(1
|
)
|
|
(7
|
)
|
|
—
|
|
|
(96
|
)
|
|
(104
|
)
|
||||||||||
Ending inventory costs
|
(58
|
)
|
|
—
|
|
|
(21
|
)
|
|
—
|
|
|
(79
|
)
|
|
32
|
|
|
—
|
|
|
(5
|
)
|
|
—
|
|
|
27
|
|
||||||||||
Total Costs and Expenses
|
2,490
|
|
|
175
|
|
|
296
|
|
|
519
|
|
|
3,480
|
|
|
(49
|
)
|
|
(62
|
)
|
|
(84
|
)
|
|
(38
|
)
|
|
(233
|
)
|
||||||||||
Freight Expense
|
—
|
|
|
—
|
|
|
—
|
|
|
142
|
|
|
142
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(90
|
)
|
|
(90
|
)
|
||||||||||
Total Costs of Goods Sold
|
2,490
|
|
|
175
|
|
|
296
|
|
|
661
|
|
|
3,622
|
|
|
(49
|
)
|
|
(62
|
)
|
|
(84
|
)
|
|
(128
|
)
|
|
(323
|
)
|
||||||||||
Earnings (Loss) Before Income Taxes
|
$
|
557
|
|
|
$
|
60
|
|
|
$
|
210
|
|
|
$
|
(171
|
)
|
|
$
|
656
|
|
|
$
|
32
|
|
|
$
|
(82
|
)
|
|
$
|
(482
|
)
|
|
$
|
255
|
|
|
$
|
(277
|
)
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2012
|
|
2011
|
|
Variance
|
|
Percent
Change
|
|||||||
Company Produced Thermal Tons Sold (in millions)
|
49.1
|
|
|
52.0
|
|
|
(2.9
|
)
|
|
(5.6
|
%)
|
|||
Average Sales Price Per Thermal Ton Sold
|
$
|
61.99
|
|
|
$
|
58.87
|
|
|
$
|
3.12
|
|
|
5.3
|
%
|
|
|
|
|
|
|
|
|
|||||||
Beginning Inventory Costs Per Thermal Ton
|
$
|
58.32
|
|
|
$
|
51.73
|
|
|
$
|
6.59
|
|
|
12.7
|
%
|
|
|
|
|
|
|
|
|
|||||||
Total Direct Operating Costs Per Thermal Ton Produced
|
$
|
31.56
|
|
|
$
|
29.86
|
|
|
$
|
1.70
|
|
|
5.7
|
%
|
Total Royalty/Production Taxes Per Thermal Ton Produced
|
4.14
|
|
|
4.00
|
|
|
0.14
|
|
|
3.5
|
%
|
|||
Total Direct Services to Operations Per Thermal Ton Produced
|
4.90
|
|
|
4.81
|
|
|
0.09
|
|
|
1.9
|
%
|
|||
Total Retirement and Disability Per Thermal Ton Produced
|
3.68
|
|
|
4.48
|
|
|
(0.80
|
)
|
|
(17.9
|
%)
|
|||
Total Depreciation, Depletion and Amortization Costs Per Thermal Ton Produced
|
6.19
|
|
|
5.84
|
|
|
0.35
|
|
|
6.0
|
%
|
|||
Total Production Costs Per Thermal Ton Produced
|
$
|
50.47
|
|
|
$
|
48.99
|
|
|
$
|
1.48
|
|
|
3.0
|
%
|
|
|
|
|
|
|
|
|
|||||||
Ending Inventory Costs Per Thermal Ton
|
$
|
(50.94
|
)
|
|
$
|
(58.32
|
)
|
|
$
|
(7.38
|
)
|
|
(12.7
|
%)
|
|
|
|
|
|
|
|
|
|||||||
Total Costs of Goods Sold Per Thermal Ton Sold
|
$
|
50.68
|
|
|
$
|
48.88
|
|
|
$
|
1.80
|
|
|
3.7
|
%
|
Average Margin Per Thermal Ton Sold
|
$
|
11.31
|
|
|
$
|
9.98
|
|
|
$
|
1.33
|
|
|
13.3
|
%
|
•
|
Average operating costs per thermal ton produced increased due to fewer tons produced. Thermal mines produced 48.8 million tons in 2012 compared to 51.7 million tons in 2011. Fixed costs are allocated over less tons, resulting in higher unit costs.
|
•
|
The Blacksville No. 2 longwall idling resulted in higher direct operating costs per ton produced. The mine continued to run the continuous miners and perform mine maintenance during the months of March and April when the longwall was idled for market reasons, which negatively impacted unit costs.
|
•
|
Labor and related benefits average costs per thermal ton produced increased. This was primarily due to the impact of the wage increases per hour worked related to the United Mine Workers of America (UMWA) collective bargaining agreement in the year-to-year comparison, offset, in part, by fewer overtime hours worked.
|
•
|
Average operating supplies and maintenance costs per ton increased due to additional maintenance and equipment overhaul costs and additional contractor labor, combined with lower tons produced. Additional maintenance and equipment overhaul costs are related to additional equipment being serviced in the current year. Additional contractor labor costs resulted from additional underground hourly contractors utilized as well as additional security contractor costs in the current year.
|
•
|
There were no significant changes in various other unit costs individually or in total.
|
•
|
Average direct service costs to operations were impaired due to lower tons produced in the year-to-year comparison.
|
•
|
Permitting and compliance costs have increased due to increased stream monitoring expenses, increased compliance work related to ponds and ditches, and additional permits for water discharge pipelines.
|
•
|
Selling expense decreased in the year-to-year comparison due to fewer tons being sold under contracts that require commissions.
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2012
|
|
2011
|
|
Increase (Decrease)
|
|
Percent
Change
|
|||||||
Company Produced High Vol Met Tons Sold (in millions)
|
3.6
|
|
|
4.7
|
|
|
(1.1
|
)
|
|
(23.4
|
%)
|
|||
Average Sales Price Per High Vol Met Ton Sold
|
$
|
63.76
|
|
|
$
|
78.06
|
|
|
$
|
(14.30
|
)
|
|
(18.3
|
%)
|
|
|
|
|
|
|
|
|
|||||||
Beginning Inventory Costs Per High Vol Met Ton
|
$
|
63.50
|
|
|
$
|
—
|
|
|
$
|
63.50
|
|
|
—
|
%
|
|
|
|
|
|
|
|
|
|||||||
Total Direct Operating Costs Per High Vol Met Ton Produced
|
$
|
29.30
|
|
|
$
|
30.15
|
|
|
$
|
(0.85
|
)
|
|
(2.8
|
%)
|
Total Royalty/Production Taxes Per High Vol Met Ton Produced
|
2.83
|
|
|
3.01
|
|
|
(0.18
|
)
|
|
(6.0
|
%)
|
|||
Total Direct Services to Operations Per High Vol Met Ton Produced
|
6.15
|
|
|
6.26
|
|
|
(0.11
|
)
|
|
(1.8
|
%)
|
|||
Total Retirement and Disability Per High Vol Met Ton Produced
|
3.24
|
|
|
4.28
|
|
|
(1.04
|
)
|
|
(24.3
|
%)
|
|||
Total Depreciation, Depletion and Amortization Costs Per High Vol Met Ton Produced
|
6.62
|
|
|
6.50
|
|
|
0.12
|
|
|
1.8
|
%
|
|||
Total Production Costs Per High Vol Met Ton Produced
|
$
|
48.14
|
|
|
$
|
50.20
|
|
|
$
|
(2.06
|
)
|
|
(4.1
|
%)
|
|
|
|
|
|
|
|
|
|||||||
Ending Inventory Costs Per High Vol Met Ton
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
—
|
%
|
|
|
|
|
|
|
|
|
|||||||
Total Costs Per High Vol Met Ton Sold
|
$
|
48.85
|
|
|
$
|
50.20
|
|
|
$
|
(1.35
|
)
|
|
(2.7
|
%)
|
Margin Per High Vol Met Ton Sold
|
$
|
14.91
|
|
|
$
|
27.86
|
|
|
$
|
(12.95
|
)
|
|
(46.5
|
%)
|
•
|
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.
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2012
|
|
2011
|
|
Variance
|
|
Percent
Change
|
|||||||
Company Produced Low Vol Met Tons Sold (in millions)
|
3.7
|
|
|
5.6
|
|
|
(1.9
|
)
|
|
(33.9
|
%)
|
|||
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
|
$
|
50.98
|
|
|
$
|
38.71
|
|
|
$
|
12.27
|
|
|
31.7
|
%
|
Total Royalty/Production Taxes Per Low Vol Met Ton Produced
|
8.32
|
|
|
11.74
|
|
|
(3.42
|
)
|
|
(29.1
|
%)
|
|||
Total Direct Services to Operations Per Low Vol Met Ton Produced
|
5.93
|
|
|
3.77
|
|
|
2.16
|
|
|
57.3
|
%
|
|||
Total Retirement and Disability Per Low Vol Met Ton Produced
|
7.63
|
|
|
7.28
|
|
|
0.35
|
|
|
4.8
|
%
|
|||
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
|
$
|
83.09
|
|
|
$
|
68.04
|
|
|
$
|
15.05
|
|
|
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 and April which resulted in $18.53 per ton higher direct operating costs produced. The mine continued to run the continuous miners and perform mine maintenance during the month when the longwall was idled. This negatively impacted unit costs.
|
•
|
Low volatile metallurgical coal production was 3.7 million tons for the year ended December 31, 2012 compared to 5.7 million tons for the year ended December 31, 2011. Production was significantly lower in the year-to-year comparison due to the Buchanan Mine being idled in early September 2012. The mine was idled in response to weak market demand for low volatile metallurgical coal. Production resumed in early November 2012 with a five day work week instead of the normal seven day work week. Fixed costs were then spread over fewer tons produced which increased all costs on a per unit basis. Buchanan Mine was also idled in March and April 2012 which impacted production.
|
•
|
Gain on sale of assets attributable to the Other Coal segment were $271 million for the year ended December 31, 2012 compared to $5 million for the year ended December 31, 2011. The change was primarily related to sales of non-producing assets in the Northern Powder River Basin that resulted in income of $151 million, as well as coal and surface lands in Western Canada, Illinois and West Virginia that resulted in income of $112 million. See Note 2—Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional detail of these sales. The remaining $3 million change was related to various transactions that occurred throughout both periods, none of which were individually material.
|
•
|
For the year ended December 31, 2012, $12 million of income was recognized related to contracts from certain thermal coal customers that were unable to take delivery of previously contracted coal tonnage. These customers agreed to buy out their contracts in order to be released from the requirements of taking delivery of previously committed tons. No such transactions were entered into in the year ended December 31, 2011.
|
•
|
Gain on issuances of pipeline right-of-ways to third parties decreased $8 million in the year-to-year comparison, primarily due to a $10 million pipeline right-of-way to a third party issued in the year ended December 31, 2011.
|
•
|
The remaining $9 million decrease in a year-to-year comparison is due to several transactions, none of which are individually material.
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2012
|
|
2011
|
|
Variance
|
||||||
Abandonment of long-lived assets
|
|
$
|
—
|
|
|
$
|
116
|
|
|
$
|
(116
|
)
|
Freight expense
|
|
142
|
|
|
231
|
|
|
(89
|
)
|
|||
Purchased Coal
|
|
47
|
|
|
71
|
|
|
(24
|
)
|
|||
General and Administrative Expense
|
|
91
|
|
|
98
|
|
|
(7
|
)
|
|||
Litigation Contingencies
|
|
18
|
|
|
8
|
|
|
10
|
|
|||
Voluntary Incentive Separation Program
|
|
13
|
|
|
—
|
|
|
13
|
|
|||
Bailey Belt Incident
|
|
41
|
|
|
—
|
|
|
41
|
|
|||
Closed and idle mines
|
|
153
|
|
|
107
|
|
|
46
|
|
|||
Other
|
|
156
|
|
|
158
|
|
|
(2
|
)
|
|||
Total other coal segment costs
|
|
$
|
661
|
|
|
$
|
789
|
|
|
$
|
(128
|
)
|
•
|
Abandonment of long-lived assets was $116 million for the year ended December 31, 2011 as a result of permanently idling Mine 84.
|
•
|
Freight expense is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. rail, barge, truck, etc.) used by the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is the amount billed to customers for transportation costs incurred. Freight expense is almost completely offset in freight revenue. The $89 million decrease in freight revenue was due to decreased shipments which CONSOL Energy contractually provides transportation services.
|
•
|
Purchased coal costs decreased approximately $24 million in the year-to-year comparison primarily due to differences in the quality of coal purchased, decreases in the market price of coal purchased, and an increase in the volumes of coal purchased in the period-to-period comparison.
|
•
|
General and Administrative Expense related to the other coal segment decreased by $7 million primarily due to a reduction of wages and related expenses.
|
•
|
Litigation contingencies increased $10 million in the year-to-year comparison due to various items. See Note 23-Commitments and Contingent Liabilities in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional details related to total Company expense.
|
•
|
In November 2012, CONSOL Energy offered a voluntary severance incentive program (VSIP) to active salaried corporate and operation support employees with 30 years of service, or more. Under this program, eligible employees who accepted the offer will receive a severance payment equal to one year's salary and the 2013 accrued vacation earned as of December 31, 2012. Approximately 100 employees volunteered for the program. Severance and vacation pay was approximately $13 million and was recognized for the year ended December 31, 2012. This was paid in January 2013.
|
•
|
Bailey Belt incident costs represents expenses related to continued advancement of the mines and on-going projects at the mines that took place during the idled phase when belt reconstruction was occurring.
|
•
|
Closed and idle mine costs increased approximately $46 million for the year ended December 31, 2012 compared to the year ended December 31, 2011. The increase was the result of $30 million additional costs related to reclamation liabilities and on-going idling costs incurred at the Fola Complex for the year ended December 31, 2012. Closed and idle mine costs increased $20 million as the result of a 2012 decision to temporarily idle Buchanan Mine in 2012. Closed and idle mine costs decreased $4 million due to other changes in the operational status of various other mines, between idled and operating throughout both periods, none of which were individually material.
|
•
|
Other costs related to the coal segment decreased $2 million due to various other transactions that occurred throughout both periods, none of which are individually material.
|
|
For the Year Ended
|
|
Difference to Year Ended
|
||||||||||||||||||||||||||||||||||||
|
December 31, 2012
|
|
December 31, 2011
|
||||||||||||||||||||||||||||||||||||
|
CBM
|
|
Shallow Oil and Gas
|
|
Marcellus
|
|
Other
Gas
|
|
Total
Gas
|
|
CBM
|
|
Shallow Oil and Gas
|
|
Marcellus
|
|
Other
Gas
|
|
Total
Gas
|
||||||||||||||||||||
Sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||
Produced
|
$
|
379
|
|
|
$
|
135
|
|
|
$
|
134
|
|
|
$
|
10
|
|
|
$
|
658
|
|
|
$
|
(82
|
)
|
|
$
|
(20
|
)
|
|
$
|
15
|
|
|
$
|
(2
|
)
|
|
$
|
(89
|
)
|
Related Party
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3
|
)
|
||||||||||
Total Outside Sales
|
381
|
|
|
135
|
|
|
134
|
|
|
10
|
|
|
660
|
|
|
(85
|
)
|
|
(20
|
)
|
|
15
|
|
|
(2
|
)
|
|
(92
|
)
|
||||||||||
Gas Royalty Interest
|
—
|
|
|
—
|
|
|
—
|
|
|
50
|
|
|
50
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(17
|
)
|
|
(17
|
)
|
||||||||||
Purchased Gas
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
(1
|
)
|
||||||||||
Other Income
|
—
|
|
|
—
|
|
|
—
|
|
|
57
|
|
|
57
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2
|
)
|
|
(2
|
)
|
||||||||||
Total Revenue and Other Income
|
381
|
|
|
135
|
|
|
134
|
|
|
120
|
|
|
770
|
|
|
(85
|
)
|
|
(20
|
)
|
|
15
|
|
|
(22
|
)
|
|
(112
|
)
|
||||||||||
Lifting
|
37
|
|
|
40
|
|
|
12
|
|
|
2
|
|
|
91
|
|
|
(3
|
)
|
|
(9
|
)
|
|
(3
|
)
|
|
1
|
|
|
(14
|
)
|
||||||||||
Ad Valorem, Severance, and Other Taxes
|
10
|
|
|
10
|
|
|
4
|
|
|
2
|
|
|
26
|
|
|
(2
|
)
|
|
(2
|
)
|
|
3
|
|
|
1
|
|
|
—
|
|
||||||||||
Gathering
|
106
|
|
|
26
|
|
|
24
|
|
|
5
|
|
|
161
|
|
|
8
|
|
|
(1
|
)
|
|
9
|
|
|
3
|
|
|
19
|
|
||||||||||
Gas Direct Administrative, Selling & Other
|
14
|
|
|
13
|
|
|
17
|
|
|
3
|
|
|
47
|
|
|
(15
|
)
|
|
(8
|
)
|
|
6
|
|
|
3
|
|
|
(14
|
)
|
||||||||||
Depreciation, Depletion and Amortization
|
88
|
|
|
59
|
|
|
47
|
|
|
9
|
|
|
203
|
|
|
(13
|
)
|
|
(2
|
)
|
|
12
|
|
|
(1
|
)
|
|
(4
|
)
|
||||||||||
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
|
255
|
|
|
148
|
|
|
104
|
|
|
224
|
|
|
731
|
|
|
(25
|
)
|
|
(22
|
)
|
|
27
|
|
|
3
|
|
|
(17
|
)
|
||||||||||
Earnings Before Noncontrolling Interest and Income Tax
|
126
|
|
|
(13
|
)
|
|
30
|
|
|
(104
|
)
|
|
39
|
|
|
(60
|
)
|
|
2
|
|
|
(12
|
)
|
|
(25
|
)
|
|
(95
|
)
|
||||||||||
Noncontrolling Interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4
|
)
|
|
(4
|
)
|
||||||||||
Earnings Before Income Tax
|
$
|
126
|
|
|
$
|
(13
|
)
|
|
$
|
30
|
|
|
$
|
(104
|
)
|
|
$
|
39
|
|
|
$
|
(60
|
)
|
|
$
|
2
|
|
|
$
|
(12
|
)
|
|
$
|
(21
|
)
|
|
$
|
(91
|
)
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2012
|
|
2011
|
|
Variance
|
|
Percent
Change
|
|||||||
Produced gas CBM sales volumes (in billion cubic feet)
|
88.2
|
|
|
92.4
|
|
|
(4.2
|
)
|
|
(4.5
|
)%
|
|||
Average CBM sales price per thousand cubic feet sold
|
$
|
4.32
|
|
|
$
|
5.05
|
|
|
$
|
(0.73
|
)
|
|
(14.5
|
)%
|
Average CBM lifting costs per thousand cubic feet sold
|
$
|
0.42
|
|
|
$
|
0.43
|
|
|
$
|
(0.01
|
)
|
|
(2.3
|
)%
|
Average CBM ad valorem, severance, and other taxes per thousand cubic feet sold
|
$
|
0.12
|
|
|
$
|
0.13
|
|
|
$
|
(0.01
|
)
|
|
(7.7
|
)%
|
Average CBM gathering costs per thousand cubic feet sold
|
$
|
1.21
|
|
|
$
|
1.06
|
|
|
$
|
0.15
|
|
|
14.2
|
%
|
Average CBM direct administrative, selling & other costs per thousand cubic feet sold
|
$
|
0.16
|
|
|
$
|
0.31
|
|
|
$
|
(0.15
|
)
|
|
(48.4
|
)%
|
Average CBM depreciation, depletion and amortization costs per thousand cubic feet sold
|
$
|
0.98
|
|
|
$
|
1.10
|
|
|
$
|
(0.12
|
)
|
|
(10.9
|
)%
|
Total Average CBM costs per thousand cubic feet sold
|
$
|
2.89
|
|
|
$
|
3.03
|
|
|
$
|
(0.14
|
)
|
|
(4.6
|
)%
|
Average Margin for CBM
|
$
|
1.43
|
|
|
$
|
2.02
|
|
|
$
|
(0.59
|
)
|
|
(29.2
|
)%
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2012
|
|
2011
|
|
Variance
|
|
Percent
Change
|
|||||||
Produced gas Shallow Oil and Gas sales volumes (in billion cubic feet)
|
29.2
|
|
|
32.2
|
|
|
(3.0
|
)
|
|
(9.3
|
)%
|
|||
Average Shallow Oil and Gas sales price per thousand cubic feet sold
|
$
|
4.64
|
|
|
$
|
4.83
|
|
|
$
|
(0.19
|
)
|
|
(3.9
|
)%
|
Average Shallow Oil and Gas lifting costs per thousand cubic feet sold
|
$
|
1.37
|
|
|
$
|
1.52
|
|
|
$
|
(0.15
|
)
|
|
(9.9
|
)%
|
Average Shallow Oil and Gas ad valorem, Severance, and other taxes per thousand cubic feet sold
|
$
|
0.35
|
|
|
$
|
0.37
|
|
|
$
|
(0.02
|
)
|
|
(5.4
|
)%
|
Average Shallow Oil and Gas gathering costs per thousand cubic feet sold
|
$
|
0.92
|
|
|
$
|
0.83
|
|
|
$
|
0.09
|
|
|
10.8
|
%
|
Average Shallow Oil and Gas direct administrative, selling & other costs per thousand cubic feet sold
|
$
|
0.45
|
|
|
$
|
0.67
|
|
|
$
|
(0.22
|
)
|
|
(32.8
|
)%
|
Average Shallow Oil and Gas depreciation, depletion and amortization costs per thousand cubic feet sold
|
$
|
2.02
|
|
|
$
|
1.90
|
|
|
$
|
0.12
|
|
|
6.3
|
%
|
Total Average Shallow Oil and Gas costs per thousand cubic feet sold
|
$
|
5.11
|
|
|
$
|
5.29
|
|
|
$
|
(0.18
|
)
|
|
(3.4
|
)%
|
Average Margin for Shallow Oil and Gas
|
$
|
(0.47
|
)
|
|
$
|
(0.46
|
)
|
|
$
|
(0.01
|
)
|
|
2.2
|
%
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2012
|
|
2011
|
|
Variance
|
|
Percent
Change
|
|||||||
Produced gas Marcellus sales volumes (in billion cubic feet)
|
36.5
|
|
|
26.9
|
|
|
9.6
|
|
|
35.7
|
%
|
|||
Average Marcellus sales price per thousand cubic feet sold
|
$
|
3.68
|
|
|
$
|
4.43
|
|
|
$
|
(0.75
|
)
|
|
(16.9
|
)%
|
Average Marcellus lifting costs per thousand cubic feet sold
|
$
|
0.34
|
|
|
$
|
0.56
|
|
|
$
|
(0.22
|
)
|
|
(39.3
|
)%
|
Average Marcellus ad valorem, severance, and other taxes per thousand cubic feet sold
|
$
|
0.12
|
|
|
$
|
0.05
|
|
|
$
|
0.07
|
|
|
140.0
|
%
|
Average Marcellus gathering costs per thousand cubic feet sold
|
$
|
0.67
|
|
|
$
|
0.54
|
|
|
$
|
0.13
|
|
|
24.1
|
%
|
Average Marcellus direct administrative, selling & costs per thousand cubic feet sold
|
$
|
0.46
|
|
|
$
|
0.41
|
|
|
$
|
0.05
|
|
|
12.2
|
%
|
Average Marcellus depreciation, depletion and amortization costs per thousand cubic feet sold
|
$
|
1.30
|
|
|
$
|
1.33
|
|
|
$
|
(0.03
|
)
|
|
(2.3
|
)%
|
Total Average Marcellus costs per thousand cubic feet sold
|
$
|
2.89
|
|
|
$
|
2.89
|
|
|
$
|
—
|
|
|
—
|
%
|
Average Margin for Marcellus
|
$
|
0.79
|
|
|
$
|
1.54
|
|
|
$
|
(0.75
|
)
|
|
(48.7
|
)%
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2012
|
|
2011
|
|
Variance
|
|
Percent
Change
|
|||||||
Gas Royalty Interest Sales Volumes (in billion cubic feet)
|
18.0
|
|
|
16.4
|
|
|
1.6
|
|
|
9.8
|
%
|
|||
Average Sales Price Per thousand cubic feet
|
$
|
2.74
|
|
|
$
|
4.07
|
|
|
$
|
(1.33
|
)
|
|
(32.7
|
)%
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2012
|
|
2011
|
|
Variance
|
|
Percent
Change
|
|||||||
Purchased Gas Sales Volumes (in billion cubic feet)
|
1.1
|
|
|
1.0
|
|
|
0.1
|
|
|
10.0
|
%
|
|||
Average Sales Price Per thousand cubic feet
|
$
|
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. See Note 2 - Acquisitions and Dispositions, in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
|
•
|
Revenue from equity affiliates increased $5 million due to the formation of CONE, a 50% affiliate. CONE was formed in relation to the Noble joint venture transaction. See Note 2 - Acquisitions and Dispositions, in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
|
•
|
The remaining $3 million increase relates to various transactions that occurred throughout both periods, none of which were individually material.
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2012
|
|
2011
|
|
Variance
|
|
Percent
Change
|
|||||||
Gas Royalty Interest Sales Volumes (in billion cubic feet)
|
18.0
|
|
|
16.4
|
|
|
1.6
|
|
|
9.8
|
%
|
|||
Average Cost Per thousand cubic feet sold
|
$
|
2.16
|
|
|
$
|
3.61
|
|
|
$
|
(1.45
|
)
|
|
(40.2
|
)%
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2012
|
|
2011
|
|
Variance
|
|
Percent
Change
|
|||||||
Purchased Gas Volumes (in billion cubic feet)
|
1.1
|
|
|
1.2
|
|
|
(0.1
|
)
|
|
(8.3
|
)%
|
|||
Average Cost Per thousand cubic feet sold
|
$
|
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
|
%
|
Exploration
|
18
|
|
|
7
|
|
|
11
|
|
|
157.1
|
%
|
|||
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 relating to locations where CONSOL Energy allowed primary lease terms to expire. Additionally, the increase also relates to various title defect issues identified as part of the Noble transaction. See Note 2 - Acquisitions and Dispositions, in the Notes to the Audited Consolidated Financial Statements in Item 8 of this form 10-K for additional information.
|
•
|
Exploration expenses increased $11 million due to increased exploratory expenses associated with the Utica operating area and various other transaction that occurred throughout both periods, none of which were individually material.
|
•
|
Dry Hole Costs decreased $2 million due to various transactions that occurred throughout both periods, none of which were individually material.
|
|
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
|
|
|
—
|
|
|
—
|
%
|
|||
Other
|
8
|
|
|
8
|
|
|
—
|
|
|
—
|
%
|
|||
Total Other Corporate Expenses
|
$
|
77
|
|
|
$
|
65
|
|
|
$
|
12
|
|
|
18.5
|
%
|
•
|
Legal fees were related to CNX Gas royalty litigation and title defect work. See Note 23 - Commitments and Contingencies in the Notes to the Audited Consolidated Financial Statements in Item 8 of this form 10-K for additional information.
|
•
|
PA impact fees are related to legislation in the state of Pennsylvania (Act 13 of 2012, House Bill 1950) which was signed into law during the first quarter of 2012. This legislation permits Pennsylvania counties to impose annual fees on unconventional gas wells located within their borders. As part of the legislation, all unconventional wells which were drilled prior to January 1, 2012 were assessed an initial fee related to periods prior to 2012. The $4 million represents this one-time initial assessment on wells drilled prior to January 1, 2012. On-going PA impact fees which relate to current year wells drilled are included as part of ad valorem, severance and other taxes in the Marcellus gas segment.
|
•
|
Unutilized firm transportation represents pipeline transportation capacity that the gas segment has obtained to enable gas production to flow uninterrupted as the gas operations continue to increase sales volumes.
|
•
|
The short-term incentive compensation program is designed to increase compensation to eligible employees when CNX Gas reaches predetermined targets for safety compliance, production and unit costs. Short-term incentive compensation increased in the period-to-period comparison as the result of exceeding the targets in the 2012 period and an increased allocation of expense from CONSOL Energy as the result of exceeding corporate targets.
|
•
|
Stock-based compensation remained consistent in the period-to-period comparison. Stock-based compensation costs are allocated to the gas segment based on revenue and capital expenditure projections between coal and gas.
|
•
|
Other corporate related expense remained consistent in the period-to-period comparison.
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2012
|
|
2011
|
|
Variance
|
|
Percent
Change
|
|||||||
Sales—Outside
|
$
|
361
|
|
|
$
|
346
|
|
|
$
|
15
|
|
|
4.3
|
%
|
Other Income
|
20
|
|
|
16
|
|
|
4
|
|
|
25.0
|
%
|
|||
Total Revenue
|
381
|
|
|
362
|
|
|
19
|
|
|
5.2
|
%
|
|||
Cost of Goods Sold and Other Charges
|
329
|
|
|
368
|
|
|
(39
|
)
|
|
(10.6
|
)%
|
|||
Depreciation, Depletion & Amortization
|
24
|
|
|
19
|
|
|
5
|
|
|
26.3
|
%
|
|||
Taxes Other Than Income Tax
|
11
|
|
|
11
|
|
|
—
|
|
|
—
|
%
|
|||
Interest Expense
|
215
|
|
|
239
|
|
|
(24
|
)
|
|
(10.0
|
)%
|
|||
Total Costs
|
579
|
|
|
637
|
|
|
(58
|
)
|
|
(9.1
|
)%
|
|||
Loss Before Income Tax
|
(198
|
)
|
|
(275
|
)
|
|
77
|
|
|
28.0
|
%
|
|||
Income Tax
|
109
|
|
|
155
|
|
|
(46
|
)
|
|
(29.7
|
)%
|
|||
Net Loss
|
$
|
(307
|
)
|
|
$
|
(430
|
)
|
|
$
|
123
|
|
|
28.6
|
%
|
|
|
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 and other legal charges
|
|
4
|
|
|
6
|
|
|
(2
|
)
|
|||
Other
|
|
19
|
|
|
19
|
|
|
—
|
|
|||
|
|
$
|
251
|
|
|
$
|
313
|
|
|
$
|
(62
|
)
|
•
|
Interest Expense decreased $24 million in the period-to-period comparison. Interest expense decreased due to an increase in capitalized interest related to higher capital expenditures for major construction projects in the current period. Capital expenditures for coal activities increased $310 million in the period-to-period comparison.
|
•
|
On April 11, 2011, CONSOL Energy redeemed all of its outstanding $250 million, 7.875% senior secured notes due March 1, 2012 in accordance with the terms of the indenture governing these notes. The loss on extinguishment of debt was $16 million, which primarily represented the interest that would have been paid on these notes if held to maturity.
|
•
|
Transaction and financing fees of $15 million incurred in the year ended December 31, 2011 related to the solicitation of consents of the long-term bonds needed in order to clarify the indentures that relate to joint arrangements with respect to its oil and gas properties.
|
•
|
Bank fees decreased $5 million mainly due to lower borrowings on the revolving credit facilities in the period-to-period comparison and also due to the refinancing and extension of the credit facility on April 12, 2011.
|
•
|
Evaluation fees for non-core asset dispositions and other legal charges decreased $2 million in the period-to-period comparison due to various corporate initiatives.
|
•
|
Various other corporate expenses remained constant in the period-to-period comparison.
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2012
|
|
2011
|
|
Variance
|
|
Percent
Change
|
|||||||
Total Company Earnings Before Income Tax
|
$
|
497
|
|
|
$
|
788
|
|
|
$
|
(291
|
)
|
|
(36.9
|
)%
|
Income Tax Expense
|
$
|
109
|
|
|
$
|
155
|
|
|
$
|
(46
|
)
|
|
(29.7
|
)%
|
Effective Income Tax Rate
|
22.0
|
%
|
|
19.7
|
%
|
|
2.3
|
%
|
|
|
|
For the Years Ended December 31,
|
|||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||
Average Sales Price per ton sold
|
$
|
72.25
|
|
|
61.33
|
|
$
|
10.92
|
|
|
17.8
|
%
|
Average Cost of Goods Sold per ton
|
50.69
|
|
|
45.74
|
|
4.95
|
|
|
10.8
|
%
|
||
Margin
|
$
|
21.56
|
|
|
15.59
|
|
$
|
5.97
|
|
|
38.3
|
%
|
•
|
Average operating supplies and maintenance costs per ton sold were higher due to increased equipment overhauls, additional roof control and additional equipment maintenance.
|
•
|
Depreciation, depletion and amortization increased due to additional assets placed into service after the 2010 period.
|
•
|
Labor and labor related charges increased as a result of additional employees, increased overtime hours worked and the impact of the $1.50 per hour worked UMWA contract wage increases, $0.50 per hour worked related to the prior UMWA contract and $1.00 per hour worked related to the July 2011 UMWA contract.
|
•
|
Average retirement and disability costs per ton increased primarily due to changes in discount rates, employees retiring sooner than originally anticipated and higher average claim costs.
|
•
|
Royalties and production taxes increased due to a higher average sales price per ton sold.
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Average Sales Price per thousand cubic feet sold
|
$
|
4.90
|
|
|
$
|
5.83
|
|
|
$
|
(0.93
|
)
|
|
(16.0
|
)%
|
Average Costs per thousand cubic feet sold
|
3.53
|
|
|
3.54
|
|
|
(0.01
|
)
|
|
(0.3
|
)%
|
|||
Margin
|
$
|
1.37
|
|
|
$
|
2.29
|
|
|
$
|
(0.92
|
)
|
|
(40.2
|
)%
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Employee wages and related expenses
|
$
|
68
|
|
|
$
|
60
|
|
|
$
|
8
|
|
|
13.3
|
%
|
Contributions
|
15
|
|
|
11
|
|
|
4
|
|
|
36.4
|
%
|
|||
Consulting and professional services
|
37
|
|
|
33
|
|
|
4
|
|
|
12.1
|
%
|
|||
Miscellaneous
|
32
|
|
|
31
|
|
|
1
|
|
|
3.2
|
%
|
|||
Total Company General and Administrative Expenses
|
$
|
152
|
|
|
$
|
135
|
|
|
$
|
17
|
|
|
12.6
|
%
|
•
|
Employee wages and related expenses increased $8 million which was primarily attributable to the support staff retained in the Dominion Acquisition and additional hiring of support staff in the period-to-period comparison.
|
•
|
Contributions expense increased $4 million due to various transactions that occurred throughout both periods, none of which were individually material.
|
•
|
Consulting and professional services increased $4 million due to various transactions that occurred throughout both periods, none of which were individually material.
|
•
|
Miscellaneous general and administrative expenses increased $1 million due to various transactions that occurred throughout both periods, none of which were individually material.
|
|
For the Year Ended
|
|
Difference to Year Ended
|
||||||||||||||||||||||||||||||||||||
|
December 31, 2011
|
|
December 31, 2010
|
||||||||||||||||||||||||||||||||||||
|
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
|
$
|
3,058
|
|
|
$
|
368
|
|
|
$
|
1,072
|
|
|
$
|
27
|
|
|
$
|
4,525
|
|
|
$
|
57
|
|
|
$
|
196
|
|
|
$
|
392
|
|
|
$
|
15
|
|
|
$
|
660
|
|
Purchased Coal
|
—
|
|
|
—
|
|
|
—
|
|
|
42
|
|
|
42
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8
|
|
|
8
|
|
||||||||||
Total Outside Sales
|
3,058
|
|
|
368
|
|
|
1,072
|
|
|
69
|
|
|
4,567
|
|
|
57
|
|
|
196
|
|
|
392
|
|
|
23
|
|
|
668
|
|
||||||||||
Freight Revenue
|
—
|
|
|
—
|
|
|
—
|
|
|
232
|
|
|
232
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
106
|
|
|
106
|
|
||||||||||
Other Income
|
6
|
|
|
11
|
|
|
—
|
|
|
62
|
|
|
79
|
|
|
(2
|
)
|
|
4
|
|
|
—
|
|
|
14
|
|
|
16
|
|
||||||||||
Total Revenue and Other Income
|
3,064
|
|
|
379
|
|
|
1,072
|
|
|
363
|
|
|
4,878
|
|
|
55
|
|
|
200
|
|
|
392
|
|
|
143
|
|
|
790
|
|
||||||||||
Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||
Beginning inventory costs
|
98
|
|
|
—
|
|
|
10
|
|
|
—
|
|
|
108
|
|
|
(56
|
)
|
|
—
|
|
|
(10
|
)
|
|
—
|
|
|
(66
|
)
|
||||||||||
Total direct costs
|
1,543
|
|
|
142
|
|
|
219
|
|
|
152
|
|
|
2,056
|
|
|
25
|
|
|
88
|
|
|
45
|
|
|
46
|
|
|
204
|
|
||||||||||
Total royalty/production taxes
|
206
|
|
|
14
|
|
|
67
|
|
|
8
|
|
|
295
|
|
|
3
|
|
|
8
|
|
|
27
|
|
|
(80
|
)
|
|
(42
|
)
|
||||||||||
Total direct services to operations
|
248
|
|
|
30
|
|
|
22
|
|
|
251
|
|
|
551
|
|
|
13
|
|
|
18
|
|
|
5
|
|
|
(31
|
)
|
|
5
|
|
||||||||||
Total retirement and disability
|
232
|
|
|
20
|
|
|
41
|
|
|
16
|
|
|
309
|
|
|
23
|
|
|
13
|
|
|
12
|
|
|
(8
|
)
|
|
40
|
|
||||||||||
Depreciation, depletion and amortization
|
302
|
|
|
31
|
|
|
37
|
|
|
130
|
|
|
500
|
|
|
30
|
|
|
20
|
|
|
16
|
|
|
78
|
|
|
144
|
|
||||||||||
Ending inventory costs
|
(90
|
)
|
|
—
|
|
|
(16
|
)
|
|
—
|
|
|
(106
|
)
|
|
8
|
|
|
—
|
|
|
(6
|
)
|
|
—
|
|
|
2
|
|
||||||||||
Total Costs and Expenses
|
2,539
|
|
|
237
|
|
|
380
|
|
|
557
|
|
|
3,713
|
|
|
46
|
|
|
147
|
|
|
89
|
|
|
5
|
|
|
287
|
|
||||||||||
Freight Expense
|
—
|
|
|
—
|
|
|
—
|
|
|
232
|
|
|
232
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
106
|
|
|
106
|
|
||||||||||
Total Costs
|
2,539
|
|
|
237
|
|
|
380
|
|
|
789
|
|
|
3,945
|
|
|
46
|
|
|
147
|
|
|
89
|
|
|
111
|
|
|
393
|
|
||||||||||
Earnings (Loss) Before Income Taxes
|
$
|
525
|
|
|
$
|
142
|
|
|
$
|
692
|
|
|
$
|
(426
|
)
|
|
$
|
933
|
|
|
$
|
9
|
|
|
$
|
53
|
|
|
$
|
303
|
|
|
$
|
32
|
|
|
$
|
397
|
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Company Produced Thermal Tons Sold (in millions)
|
52.0
|
|
|
55.8
|
|
|
(3.8
|
)
|
|
(6.8
|
%)
|
|||
Average Sales Price Per Thermal Ton Sold
|
$
|
58.87
|
|
|
$
|
53.76
|
|
|
$
|
5.11
|
|
|
9.5
|
%
|
|
|
|
|
|
|
|
|
|||||||
Beginning Inventory Costs Per Thermal Ton
|
$
|
51.73
|
|
|
$
|
53.24
|
|
|
$
|
(1.51
|
)
|
|
(2.8
|
%)
|
|
|
|
|
|
|
|
|
|||||||
Total Direct Operating Costs Per Thermal Ton Produced
|
$
|
29.86
|
|
|
$
|
27.62
|
|
|
$
|
2.24
|
|
|
8.1
|
%
|
Total Royalty/Production Taxes Per Thermal Ton Produced
|
4.00
|
|
|
3.70
|
|
|
0.30
|
|
|
8.1
|
%
|
|||
Total Direct Services to Operations Per Thermal Ton Produced
|
4.81
|
|
|
4.28
|
|
|
0.53
|
|
|
12.4
|
%
|
|||
Total Retirement and Disability Per Thermal Ton Produced
|
4.48
|
|
|
3.80
|
|
|
0.68
|
|
|
17.9
|
%
|
|||
Total Depreciation, Depletion and Amortization Costs Per Thermal Ton Produced
|
5.84
|
|
|
4.96
|
|
|
0.88
|
|
|
17.7
|
%
|
|||
Total Production Costs Per Thermal Ton Produced
|
$
|
48.99
|
|
|
$
|
44.36
|
|
|
$
|
4.63
|
|
|
10.4
|
%
|
|
|
|
|
|
|
|
|
|||||||
Ending Inventory Costs Per Thermal Ton
|
$
|
(58.32
|
)
|
|
$
|
(51.73
|
)
|
|
$
|
6.59
|
|
|
12.7
|
%
|
|
|
|
|
|
|
|
|
|||||||
Total Costs Per Thermal Ton Sold
|
$
|
48.88
|
|
|
$
|
44.65
|
|
|
$
|
4.23
|
|
|
9.5
|
%
|
Average Margin Per Thermal Ton Sold
|
$
|
9.98
|
|
|
$
|
9.11
|
|
|
$
|
0.87
|
|
|
9.5
|
%
|
•
|
Average operating supplies and maintenance costs per thermal ton produced increased due to additional maintenance and equipment overhaul costs, additional roof control costs, and increased fuel and lubricants. Additional maintenance and equipment overhaul costs are related to additional equipment being serviced in the current period. Additional roof
|
•
|
Labor and related benefits were impaired on a cost per thermal ton sold basis due to higher costs and lower volumes sold. Higher benefit costs were due primarily to contributions made to the 1974 Pension Trust (the Trust), which is a multiemployer pension plan. Contributions to the Trust were negotiated under the National Bituminous Coal Wage Agreement and are based on a rate per hour worked by members of the United Mine Workers of America (UMWA). The contribution rate increased $0.50 per hour worked in the 2011 period compared to the 2010 period. Non-represented benefit rates for active employees also increased as a result of continued increases in healthcare costs. Labor and related benefits also increased due to additional employees and the impact of the wage increases of $1.50 per hour worked, $0.50 per hour worked effective January 1, 2011 under the previous collective bargaining agreement and $1.00 per hour worked effective July 1, 2011 related to the July 2011 collective bargaining agreement. These increases were offset, in part, as a result of the Tax Relief and Health Care Act of 2006 authorizing general fund revenues and expanding transfers of interest from the Abandoned Mine Land trust fund to cover orphan retirees which remain in the Combined Fund, the 1992 Benefit Plan and the 1993 Plan. The additional federal funding eliminated the 2011 funding of orphan retirees by participating active employers of the plans, resulting in lower expense in the period-to-period comparison. The additional federal funding does not impact the amount of contributions required to be paid for our assigned retirees. Also, we may be required to make additional payments in the future to these plans in the event the federal contributions are not sufficient to cover the benefits.
|
•
|
Average operating costs per thermal ton sold increased due to lower tons sold resulting in fixed costs being allocated over less tons resulting in higher unit costs.
|
•
|
Average direct service costs to operations were impaired due to lower tons produced in the period-to-period comparison which negatively impacted unit costs.
|
•
|
Permitting and compliance costs have increased due to increased stream monitoring expenses, increased compliance work related to ponds and ditches, and additional permits for water discharge pipelines.
|
•
|
Unit costs were also impaired due to various other items, none of which were individually material.
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Company Produced High Vol Met Tons Sold (in millions)
|
4.7
|
|
|
2.4
|
|
|
2.3
|
|
|
95.8
|
%
|
|||
Average Sales Price Per High Vol Met Ton Sold
|
$
|
78.06
|
|
|
$
|
72.89
|
|
|
$
|
5.17
|
|
|
7.1
|
%
|
|
|
|
|
|
|
|
|
|||||||
Beginning Inventory Costs Per High Vol Met Ton
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
—
|
%
|
|
|
|
|
|
|
|
|
|||||||
Total Direct Operating Costs Per High Vol Met Ton Produced
|
$
|
30.15
|
|
|
$
|
23.07
|
|
|
$
|
7.08
|
|
|
30.7
|
%
|
Total Royalty/Production Taxes Per High Vol Met Ton Produced
|
3.01
|
|
|
2.40
|
|
|
0.61
|
|
|
25.4
|
%
|
|||
Total Direct Services to Operations Per High Vol Met Ton Produced
|
6.26
|
|
|
5.19
|
|
|
1.07
|
|
|
20.6
|
%
|
|||
Total Retirement and Disability Per High Vol Met Ton Produced
|
4.28
|
|
|
3.15
|
|
|
1.13
|
|
|
35.9
|
%
|
|||
Total Depreciation, Depletion and Amortization Costs Per High Vol Met Ton Produced
|
6.50
|
|
|
4.60
|
|
|
1.90
|
|
|
41.3
|
%
|
|||
Total Production Costs Per High Vol Met Ton Produced
|
$
|
50.20
|
|
|
$
|
38.41
|
|
|
$
|
11.79
|
|
|
30.7
|
%
|
|
|
|
|
|
|
|
|
|||||||
Ending Inventory Costs Per High Vol Met Ton
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
—
|
%
|
|
|
|
|
|
|
|
|
|||||||
Total Costs Per High Vol Met Ton Sold
|
$
|
50.20
|
|
|
$
|
38.41
|
|
|
$
|
11.79
|
|
|
30.7
|
%
|
Margin Per High Vol Met Ton Sold
|
$
|
27.86
|
|
|
$
|
34.48
|
|
|
$
|
(6.62
|
)
|
|
(19.2
|
%)
|
•
|
Average operating costs per high volatile metallurgical ton produced increased due to the mix of mines selling coal on the high volatile metallurgical coal market. As higher cost structure mines sell coal in the high volatile metallurgical
|
•
|
Labor and related benefits increased due to higher employee counts, higher non-represented benefit rates and higher contributions per hour worked to the 1974 Pension Trust (Trust). Labor and related benefits increased due to additional employees in the period-to-period comparison. Higher labor and related costs were also due to higher non-represented benefit rates for active employees related to the continued increase in healthcare costs. Higher contributions made to the Trust were discussed in the thermal coal segment. Labor and related benefits also increased due to the impact of the wage increases of $1.50 per hour worked, $0.50 per hour worked effective January 1, 2011 under the previous collective bargaining agreement and $1.00 per hour worked effective July 1, 2011 related to the July 2011 collective bargaining agreement, in the period-to-period comparison. These increases were offset by lower overall contributions to certain multiemployer benefit plans such as the 1992 Fund, the 1993 Fund and the Combined Fund, which were also discussed in the thermal coal segment. Increased labor and related benefit costs per unit sold were also offset, in part, by additional volumes of high volatile metallurgical tons sold in the period-to-period comparison.
|
•
|
Average operating supplies and maintenance costs per high volatile metallurgical ton produced increased due to additional maintenance and equipment overhaul costs, additional roof control costs, and increased fuel and lubricants. Additional maintenance and equipment overhaul costs are related to additional equipment being serviced in the current period. Additional roof control costs resulted from changes in roof support strategy, such as using longer roof bolts and additional types of roof support, in order to improve the safety of our mines and to provide a more reliable source of production for our customers.
|
•
|
Average coal preparation costs per high volatile metallurgical ton produced increased due to additional maintenance projects that have been completed at our preparation plants in the period-to-period comparison.
|
•
|
In-transit charges average cost per high volatile metallurgical ton produced increased primarily due to the increased cost of moving coal from the mine to the preparation plant for processing. This increase is primarily related to the mix of mines now shipping high volatile metallurgical coal.
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Company Produced Low Vol Met Tons Sold (in millions)
|
5.6
|
|
|
4.6
|
|
|
1.0
|
|
|
21.7
|
%
|
|||
Average Sales Price Per Low Vol Met Ton Sold
|
$
|
191.81
|
|
|
$
|
146.32
|
|
|
$
|
45.49
|
|
|
31.1
|
%
|
|
|
|
|
|
|
|
|
|||||||
Beginning Inventory Costs Per Low Vol Met Ton
|
$
|
62.51
|
|
|
$
|
55.22
|
|
|
$
|
7.29
|
|
|
13.2
|
%
|
|
|
|
|
|
|
|
|
|||||||
Total Direct Operating Costs Per Low Vol Met Ton Produced
|
$
|
38.71
|
|
|
$
|
39.13
|
|
|
$
|
(0.42
|
)
|
|
(1.1
|
%)
|
Total Royalty/Production Taxes Per Low Vol Met Ton Produced
|
11.74
|
|
|
9.03
|
|
|
2.71
|
|
|
30.0
|
%
|
|||
Total Direct Services to Operations Per Low Vol Met Ton Produced
|
3.77
|
|
|
3.74
|
|
|
0.03
|
|
|
0.8
|
%
|
|||
Total Retirement and Disability Per Low Vol Met Ton Produced
|
7.28
|
|
|
6.46
|
|
|
0.82
|
|
|
12.7
|
%
|
|||
Total Depreciation, Depletion and Amortization Costs Per Low Vol Met Ton Produced
|
6.54
|
|
|
4.78
|
|
|
1.76
|
|
|
36.8
|
%
|
|||
Total Production Costs Per Low Vol Met Ton Produced
|
$
|
68.04
|
|
|
$
|
63.14
|
|
|
$
|
4.90
|
|
|
7.8
|
%
|
|
|
|
|
|
|
|
|
|||||||
Ending Inventory Costs Per Low Vol Met Ton
|
$
|
(67.60
|
)
|
|
$
|
(62.51
|
)
|
|
$
|
(5.09
|
)
|
|
8.1
|
%
|
|
|
|
|
|
|
|
|
|||||||
Total Costs Per Low Vol Met Ton Sold
|
$
|
67.90
|
|
|
$
|
62.55
|
|
|
$
|
5.35
|
|
|
8.6
|
%
|
Margin Per Low Vol Met Ton Sold
|
$
|
123.91
|
|
|
$
|
83.77
|
|
|
$
|
40.14
|
|
|
47.9
|
%
|
•
|
Average operating supplies and maintenance costs per low volatile metallurgical ton produced increased due to additional roof control costs, additional ventilation costs of coalbed methane gas, additional equipment overhaul costs and increased rock dusting. Additional roof control costs resulted from changes in roof support strategy, such as types of roof support used and quantity of supports put into place. The roof control strategy was changed to improve the safety of the mine and to provide a more reliable source of production for our customers. Roof control costs also
|
•
|
These increases in costs were partially offset by a decrease in the power costs per low volatile metallurgical ton produced which were improved due to utility rate reductions that became effective in the 2011 period.
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2011
|
|
2010
|
|
Variance
|
||||||
Abandonment of long-lived assets
|
|
$
|
116
|
|
|
$
|
—
|
|
|
$
|
116
|
|
Freight expense
|
|
231
|
|
|
126
|
|
|
105
|
|
|||
Purchased Coal
|
|
71
|
|
|
40
|
|
|
31
|
|
|||
General and Administrative Expense
|
|
98
|
|
|
83
|
|
|
15
|
|
|||
Litigation Contingencies
|
|
8
|
|
|
55
|
|
|
(47
|
)
|
|||
Closed and idle mines
|
|
107
|
|
|
222
|
|
|
(115
|
)
|
|||
Other
|
|
158
|
|
|
152
|
|
|
6
|
|
|||
Total other coal segment costs
|
|
$
|
789
|
|
|
$
|
678
|
|
|
$
|
111
|
|
•
|
Abandonment of long-lived assets was $116 million for the year ended December 31, 2011 as a result of permanently idling Mine 84.
|
•
|
Freight expense is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. rail, barge, truck, etc.) used by the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is the amount billed to customers for transportation costs incurred. Freight expense is almost completely offset in freight revenue. The increase was primarily due to the 3.6 million ton increase in export tons in the period-to-period comparison.
|
•
|
Purchased coal costs increased approximately $31 million in the period-to-period comparison primarily due to differences in the quality of coal purchased, increases in the market price of coal purchased, and an increase in the volumes of coal purchased in the period-to-period comparison.
|
•
|
General and Administrative Expense related to the other coal segment increased by $15 million primarily due to an increase of wages and related expenses and professional services.
|
•
|
Litigation expense of $25 million was recognized in the year ended December 31, 2010 related to a legal settlement related to water discharge from our Buchanan Mine being stored in mine voids of adjacent properties which were leased by CONSOL Energy subsidiaries. Litigation expense was also recognized in the year ended December 31, 2010 related to a settlement that included the sale of Jones Fork which resulted in a loss of $10 million. Litigation expense related to various other potential legal settlements decreased $12 million in the period-to-period comparison. None of these items were individually material.
|
•
|
General and Administrative Expense related to the other coal segment increased by $15 million primarily due to an increase of wages and related expenses.
|
•
|
Closed and idle mine costs decreased approximately $115 million in the year ended December 31, 2011 compared to the year ended December 31, 2010. In the 2010 period, as a result of market conditions, permitting issues, new regulatory requirements and the resulting changes in mining plans, the reclamation liability associated with the Fola mining operations in West Virginia increased $82 million. Also in the 2010 period, closed and idle mine costs increased approximately $14 million as the result of the change in mine plan at Mine 84. As a result of the mine plan change, a portion of the previously developed area of the mine was abandoned. Closed and idle mine costs decreased $9 million as a result of the decision to permanently abandon Mine 84. Closed and idle mine costs for the 2010 period also included $6 million related to various asset abandonments that occurred, none of which were individually material. In addition, $9 million of reduced expenses were recognized in closed and idle mine costs for various changes in the operational status of other mines, between idled and operating, throughout both periods, none of which
|
•
|
Other costs related to the coal segment increased $6 million due to various other transactions that occurred throughout both periods, none of which are individually material.
|
|
For the Year Ended
|
|
Difference to Year Ended
|
||||||||||||||||||||||||||||||||||||
|
December 31, 2011
|
|
December 31, 2010
|
||||||||||||||||||||||||||||||||||||
|
CBM
|
|
Shallow Oil and Gas
|
|
Marcellus
|
|
Other
Gas
|
|
Total
Gas
|
|
CBM
|
|
Shallow Oil and Gas
|
|
Marcellus
|
|
Other
Gas
|
|
Total
Gas
|
||||||||||||||||||||
Sales:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||
Produced
|
$
|
461
|
|
|
$
|
155
|
|
|
$
|
119
|
|
|
$
|
12
|
|
|
$
|
747
|
|
|
$
|
(106
|
)
|
|
$
|
39
|
|
|
$
|
70
|
|
|
$
|
4
|
|
|
$
|
7
|
|
Related Party
|
5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
||||||||||
Total Outside Sales
|
466
|
|
|
155
|
|
|
119
|
|
|
12
|
|
|
752
|
|
|
(107
|
)
|
|
39
|
|
|
70
|
|
|
4
|
|
|
6
|
|
||||||||||
Gas Royalty Interest
|
—
|
|
|
—
|
|
|
—
|
|
|
67
|
|
|
67
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
4
|
|
||||||||||
Purchased Gas
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(7
|
)
|
|
(7
|
)
|
||||||||||
Other Income
|
—
|
|
|
—
|
|
|
—
|
|
|
59
|
|
|
59
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
54
|
|
|
54
|
|
||||||||||
Total Revenue and Other Income
|
466
|
|
|
155
|
|
|
119
|
|
|
142
|
|
|
882
|
|
|
(107
|
)
|
|
39
|
|
|
70
|
|
|
55
|
|
|
57
|
|
||||||||||
Lifting
|
40
|
|
|
49
|
|
|
15
|
|
|
1
|
|
|
105
|
|
|
2
|
|
|
28
|
|
|
10
|
|
|
—
|
|
|
40
|
|
||||||||||
Ad Valorem, Severance, and Other Taxes
|
12
|
|
|
12
|
|
|
1
|
|
|
1
|
|
|
26
|
|
|
(1
|
)
|
|
2
|
|
|
—
|
|
|
1
|
|
|
2
|
|
||||||||||
Gathering
|
98
|
|
|
27
|
|
|
15
|
|
|
2
|
|
|
142
|
|
|
1
|
|
|
9
|
|
|
5
|
|
|
(1
|
)
|
|
14
|
|
||||||||||
Gas Direct Administrative, Selling & Other
|
29
|
|
|
21
|
|
|
11
|
|
|
—
|
|
|
61
|
|
|
(2
|
)
|
|
9
|
|
|
8
|
|
|
—
|
|
|
15
|
|
||||||||||
Depreciation, Depletion and Amortization
|
101
|
|
|
61
|
|
|
35
|
|
|
10
|
|
|
207
|
|
|
(12
|
)
|
|
11
|
|
|
15
|
|
|
3
|
|
|
17
|
|
||||||||||
General & Administration
|
—
|
|
|
—
|
|
|
—
|
|
|
51
|
|
|
51
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6
|
|
|
6
|
|
||||||||||
Gas Royalty Interest
|
—
|
|
|
—
|
|
|
—
|
|
|
59
|
|
|
59
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|
5
|
|
||||||||||
Purchased Gas
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6
|
)
|
|
(6
|
)
|
||||||||||
Exploration and Other Costs
|
—
|
|
|
—
|
|
|
—
|
|
|
18
|
|
|
18
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(7
|
)
|
|
(7
|
)
|
||||||||||
Other Corporate Expenses
|
—
|
|
|
—
|
|
|
—
|
|
|
65
|
|
|
65
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9
|
|
|
9
|
|
||||||||||
Interest Expense
|
—
|
|
|
—
|
|
|
—
|
|
|
10
|
|
|
10
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
3
|
|
||||||||||
Total Cost
|
280
|
|
|
170
|
|
|
77
|
|
|
221
|
|
|
748
|
|
|
(12
|
)
|
|
59
|
|
|
38
|
|
|
13
|
|
|
98
|
|
||||||||||
Earnings Before Noncontrolling Interest and Income Tax
|
186
|
|
|
(15
|
)
|
|
42
|
|
|
(79
|
)
|
|
134
|
|
|
(95
|
)
|
|
(20
|
)
|
|
32
|
|
|
42
|
|
|
(41
|
)
|
||||||||||
Noncontrolling Interest
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9
|
|
|
9
|
|
||||||||||
Earnings Before Income Tax
|
$
|
186
|
|
|
$
|
(15
|
)
|
|
$
|
42
|
|
|
$
|
(83
|
)
|
|
$
|
130
|
|
|
$
|
(95
|
)
|
|
$
|
(20
|
)
|
|
$
|
32
|
|
|
$
|
33
|
|
|
$
|
(50
|
)
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Produced gas CBM sales volumes (in billion cubic feet)
|
92.4
|
|
|
91.4
|
|
|
1.0
|
|
|
1.1
|
%
|
|||
Average CBM sales price per thousand cubic feet sold
|
$
|
5.05
|
|
|
$
|
6.27
|
|
|
$
|
(1.22
|
)
|
|
(19.5
|
)%
|
Average CBM lifting costs per thousand cubic feet sold
|
$
|
0.43
|
|
|
$
|
0.42
|
|
|
$
|
0.01
|
|
|
2.4
|
%
|
Average CBM ad valorem, severance, and other taxes per thousand cubic feet sold
|
$
|
0.13
|
|
|
$
|
0.14
|
|
|
$
|
(0.01
|
)
|
|
(7.1
|
)%
|
Average CBM gathering costs per thousand cubic feet sold
|
$
|
1.06
|
|
|
$
|
1.06
|
|
|
$
|
—
|
|
|
—
|
%
|
Average CBM direct administrative, selling, & other costs per thousand cubic feet sold
|
$
|
0.31
|
|
|
$
|
0.34
|
|
|
$
|
(0.03
|
)
|
|
(8.8
|
)%
|
Average CBM depreciation, depletion and amortization costs per thousand cubic feet sold
|
$
|
1.10
|
|
|
$
|
1.24
|
|
|
$
|
(0.14
|
)
|
|
(11.3
|
)%
|
Total Average CBM costs per thousand cubic feet sold
|
$
|
3.03
|
|
|
$
|
3.20
|
|
|
$
|
(0.17
|
)
|
|
(5.3
|
)%
|
Average Margin for CBM
|
$
|
2.02
|
|
|
$
|
3.07
|
|
|
$
|
(1.05
|
)
|
|
(34.2
|
)%
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Produced gas Shallow Oil and Gas sales volumes (in billion cubic feet)
|
32.2
|
|
|
24.7
|
|
|
7.5
|
|
|
30.4
|
%
|
|||
Average Shallow Oil and Gas sales price per thousand cubic feet sold
|
$
|
4.83
|
|
|
$
|
4.73
|
|
|
$
|
0.10
|
|
|
2.1
|
%
|
Average Shallow Oil and Gas lifting costs per thousand cubic feet sold
|
$
|
1.52
|
|
|
$
|
0.86
|
|
|
$
|
0.66
|
|
|
76.7
|
%
|
Average Shallow Oil and Gas ad valorem, severance, and other taxes per thousand cubic feet sold
|
$
|
0.37
|
|
|
$
|
0.40
|
|
|
$
|
(0.03
|
)
|
|
(7.5
|
)%
|
Average Shallow Oil and Gas gathering costs per thousand cubic feet sold
|
$
|
0.83
|
|
|
$
|
0.75
|
|
|
$
|
0.08
|
|
|
10.7
|
%
|
Average Shallow Oil and Gas direct administrative, selling, & other costs per thousand cubic feet sold
|
$
|
0.67
|
|
|
$
|
0.49
|
|
|
$
|
0.18
|
|
|
36.7
|
%
|
Average Shallow Oil and Gas depreciation, depletion and amortization costs per thousand cubic feet sold
|
$
|
1.90
|
|
|
$
|
2.04
|
|
|
$
|
(0.14
|
)
|
|
(6.9
|
)%
|
Total Average Shallow Oil and Gas costs per thousand cubic feet sold
|
$
|
5.29
|
|
|
$
|
4.54
|
|
|
$
|
0.75
|
|
|
16.5
|
%
|
Average Margin for Shallow Oil and Gas
|
$
|
(0.46
|
)
|
|
$
|
0.19
|
|
|
$
|
(0.65
|
)
|
|
(342.1
|
)%
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Produced gas Marcellus sales volumes (in billion cubic feet)
|
26.9
|
|
|
10.4
|
|
|
16.5
|
|
|
158.7
|
%
|
|||
Average Marcellus sales price per thousand cubic feet sold
|
$
|
4.43
|
|
|
$
|
4.69
|
|
|
$
|
(0.26
|
)
|
|
(5.5
|
)%
|
Average Marcellus lifting costs per thousand cubic feet sold
|
$
|
0.56
|
|
|
$
|
0.45
|
|
|
$
|
0.11
|
|
|
24.4
|
%
|
Average Marcellus ad valorem, severance, and other taxes per thousand cubic feet sold
|
$
|
0.05
|
|
|
$
|
0.05
|
|
|
$
|
—
|
|
|
—
|
%
|
Average Marcellus gathering costs per thousand cubic feet sold
|
$
|
0.54
|
|
|
$
|
0.99
|
|
|
$
|
(0.45
|
)
|
|
(45.5
|
)%
|
Average Marcellus direct administrative, selling & other costs per thousand cubic feet sold
|
$
|
0.41
|
|
|
$
|
0.37
|
|
|
$
|
0.04
|
|
|
10.8
|
%
|
Average Marcellus depreciation, depletion and amortization costs per thousand cubic feet sold
|
$
|
1.33
|
|
|
$
|
1.90
|
|
|
$
|
(0.57
|
)
|
|
(30.0
|
)%
|
Total Average Marcellus costs per thousand cubic feet sold
|
$
|
2.89
|
|
|
$
|
3.76
|
|
|
$
|
(0.87
|
)
|
|
(23.1
|
)%
|
Average Margin for Marcellus
|
$
|
1.54
|
|
|
$
|
0.93
|
|
|
$
|
0.61
|
|
|
65.6
|
%
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Gas Royalty Interest Sales Volumes (in billion cubic feet)
|
16.4
|
|
|
14.2
|
|
|
2.2
|
|
|
15.5
|
%
|
|||
Average Sales Price Per thousand cubic feet
|
$
|
4.07
|
|
|
$
|
4.41
|
|
|
$
|
(0.34
|
)
|
|
(7.7
|
)%
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Purchased Gas Sales Volumes (in billion cubic feet)
|
1.0
|
|
|
2.0
|
|
|
(1.0
|
)
|
|
(50.0
|
)%
|
|||
Average Sales Price Per thousand cubic feet
|
$
|
4.28
|
|
|
$
|
5.48
|
|
|
$
|
(1.20
|
)
|
|
(21.9
|
)%
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Gas Royalty Interest Sales Volumes (in billion cubic feet)
|
16.4
|
|
|
14.2
|
|
|
2.2
|
|
|
15.5
|
%
|
|||
Average Cost Per thousand cubic feet sold
|
$
|
3.61
|
|
|
$
|
3.78
|
|
|
$
|
(0.17
|
)
|
|
(4.5
|
)%
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Purchased Gas Volumes (in billion cubic feet)
|
1.2
|
|
|
1.9
|
|
|
(0.7
|
)
|
|
(36.8
|
)%
|
|||
Average Cost Per thousand cubic feet sold
|
$
|
3.07
|
|
|
$
|
5.14
|
|
|
$
|
(2.07
|
)
|
|
(40.3
|
)%
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Dry hole and lease expiration costs
|
$
|
11
|
|
|
$
|
21
|
|
|
$
|
(10
|
)
|
|
(47.6
|
)%
|
Exploration
|
7
|
|
|
4
|
|
|
3
|
|
|
75.0
|
%
|
|||
Total Exploration and Other Costs
|
$
|
18
|
|
|
$
|
25
|
|
|
$
|
(7
|
)
|
|
(28.0
|
)%
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Unutilized firm transportation
|
$
|
14
|
|
|
$
|
3
|
|
|
$
|
11
|
|
|
366.7
|
%
|
Contract buyout
|
3
|
|
|
—
|
|
|
3
|
|
|
100.0
|
%
|
|||
Bank fees
|
7
|
|
|
4
|
|
|
3
|
|
|
75.0
|
%
|
|||
Stock-based compensation
|
18
|
|
|
16
|
|
|
2
|
|
|
12.5
|
%
|
|||
Short-term incentive compensation
|
25
|
|
|
24
|
|
|
1
|
|
|
4.2
|
%
|
|||
Variable interest earnings
|
(4
|
)
|
|
4
|
|
|
(8
|
)
|
|
(200.0
|
)%
|
|||
Legal fees
|
—
|
|
|
3
|
|
|
(3
|
)
|
|
(100.0
|
)%
|
|||
Other
|
2
|
|
|
2
|
|
|
—
|
|
|
—
|
%
|
|||
Total Other Corporate Expenses
|
$
|
65
|
|
|
$
|
56
|
|
|
$
|
9
|
|
|
16.1
|
%
|
•
|
Unutilized firm transportation represents pipeline transportation capacity that the gas segment has obtained to enable gas production to flow uninterrupted as the gas operations continue to increase sales volumes.
|
•
|
Contract buyout represents the cancellation of a drilling arrangement with a third party well driller.
|
•
|
Bank fees were higher in the period-to-period comparison due to amending and extending the revolving credit facility related to the gas segment. In April 2011, the facility was amended to allow $1 billion of borrowings and was extended to April 12, 2016.
|
•
|
Stock-based compensation was higher in the period-to-period comparison primarily due to the increased allocation from CONSOL Energy as a result of the Dominion Acquisition as well as an increase in total CONSOL Energy stock-based compensation expense. Stock-based compensation costs are allocated to the gas segment based on revenue and capital expenditure projections between coal and gas.
|
•
|
The short-term incentive compensation program is designed to increase compensation to eligible employees when CNX Gas reaches predetermined targets for safety, production and unit costs. Short-term incentive compensation increased in the period-to-period comparison as the result of exceeding the targets in the 2011 period, increased number of employees, and an increased allocation of expense from CONSOL Energy as the result of exceeding corporate targets.
|
•
|
Variable interest earnings are related to various adjustments a third party entity has reflected in its financial statements. CONSOL Energy holds no ownership interest and during the 2011 period de-consolidated the impact of this third party due to the cancellation of the drilling arrangement. Based on analysis, during the time CONSOL Energy guaranteed the bank loans the entity held, it was determined that CONSOL Energy was the primary beneficiary. Therefore, the entity was fully consolidated and the earnings impact was fully reversed in the non-controlling interest line discussed below.
|
•
|
Legal fees for the 2010 period were related to the special committee formed during the CNX Gas take-in transaction and also represent legal fees related to the shareholder litigation related to this transaction.
|
•
|
Other corporate related expense remained consistent in the period-to-period comparison.
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Sales—Outside
|
$
|
346
|
|
|
$
|
297
|
|
|
$
|
49
|
|
|
16.5
|
%
|
Other Income
|
16
|
|
|
29
|
|
|
(13
|
)
|
|
(44.8
|
)%
|
|||
Total Revenue
|
362
|
|
|
326
|
|
|
36
|
|
|
11.0
|
%
|
|||
Cost of Goods Sold and Other Charges
|
368
|
|
|
349
|
|
|
19
|
|
|
5.4
|
%
|
|||
Depreciation, Depletion & Amortization
|
19
|
|
|
18
|
|
|
1
|
|
|
5.6
|
%
|
|||
Taxes Other Than Income Tax
|
11
|
|
|
10
|
|
|
1
|
|
|
10.0
|
%
|
|||
Interest Expense
|
239
|
|
|
198
|
|
|
41
|
|
|
20.7
|
%
|
|||
Total Costs
|
637
|
|
|
575
|
|
|
62
|
|
|
10.8
|
%
|
|||
Loss Before Income Tax
|
(275
|
)
|
|
(249
|
)
|
|
(26
|
)
|
|
(10.4
|
)%
|
|||
Income Tax
|
155
|
|
|
109
|
|
|
46
|
|
|
42.2
|
%
|
|||
Net Loss
|
$
|
(430
|
)
|
|
$
|
(358
|
)
|
|
$
|
(72
|
)
|
|
(20.1
|
)%
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2011
|
|
2010
|
|
Variance
|
||||||
Interest expense
|
|
$
|
239
|
|
|
$
|
198
|
|
|
$
|
41
|
|
Loss on extinguishment of debt
|
|
16
|
|
|
—
|
|
|
16
|
|
|||
Evaluation fees for non-core asset dispositions
|
|
6
|
|
|
2
|
|
|
4
|
|
|||
Bank fees
|
|
18
|
|
|
16
|
|
|
2
|
|
|||
Transaction and financing fees
|
|
15
|
|
|
61
|
|
|
(46
|
)
|
|||
Other
|
|
19
|
|
|
20
|
|
|
(1
|
)
|
|||
|
|
$
|
313
|
|
|
$
|
297
|
|
|
$
|
16
|
|
•
|
Interest expense increased $41 million primarily due to interest expense on the long-term bonds that were issued in conjunction with the Dominion Acquisition in April 2010.
|
•
|
On April 11, 2011, CONSOL Energy redeemed all of its outstanding $250 million, 7.875% senior secured notes due March 1, 2012 in accordance with the terms of the indenture governing these notes. The redemption price included principal of $250 million, a make-whole premium of $16 million and accrued interest of $2 million for a total redemption cost of $268 million. The loss on extinguishment of debt was $16 million, which primarily represented the interest that would have been paid on these notes if held to maturity.
|
•
|
Evaluation fees for non-core asset dispositions increased $4 million in the period-to-period comparison due to various corporate initiatives that began in the 2010 period.
|
•
|
Bank fees increased $2 million in the period-to-period comparison due to the refinancing and extension of the previous $1.0 billion credit facility to $1.5 billion on April 12, 2011.
|
•
|
Transaction and financing fees of $15 million were incurred in the year ended December 31, 2011 related to the solicitation of consents of the long-term bonds needed in order to clarify the indentures that relate to joint arrangements with respect to CONSOL Energy's oil and gas properties. Transaction and financing fees of $61 million were incurred in the year ended December 31, 2010 primarily related to the Dominion Acquisition, as well as the equity and debt issuance that raised approximately $4.6 billion.
|
•
|
Various other corporate expenses were $19 million in the year ended December 31, 2011 compared to $20 million in the year ended December 31, 2010. The decrease of $1 million was due to various transactions that occurred throughout both periods, none of which were individually material.
|
|
For the Years Ended December 31,
|
|||||||||||||
|
2011
|
|
2010
|
|
Variance
|
|
Percent
Change
|
|||||||
Total Company Earnings Before Income Tax
|
$
|
788
|
|
|
$
|
468
|
|
|
$
|
320
|
|
|
68.4
|
%
|
Income Tax Expense
|
$
|
155
|
|
|
$
|
109
|
|
|
$
|
46
|
|
|
42.2
|
%
|
Effective Income Tax Rate
|
19.7
|
%
|
|
23.4
|
%
|
|
(3.7
|
)%
|
|
|
•
|
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,
|
||||||||||
|
2012
|
|
2011
|
|
Change
|
||||||
Cash flows from operating activities
|
$
|
728
|
|
|
$
|
1,528
|
|
|
$
|
(800
|
)
|
Cash used in investing activities
|
$
|
(1,000
|
)
|
|
$
|
(579
|
)
|
|
$
|
(421
|
)
|
Cash used in financing activities
|
$
|
(82
|
)
|
|
$
|
(606
|
)
|
|
$
|
524
|
|
•
|
Net income decreased $244 million in the period-to-period comparison; and
|
•
|
The remaining $556 million decrease in operating cash flows was due to various other changes in operating assets, operating liabilities, other assets and other liabilities which occurred through both years, none of which were individually material.
|
•
|
Capital expenditures increased $193 million due to:
|
•
|
Coal segment increased capital expenditures $310 million in the period-to-period comparison. The increase was comprised of an additional $169 million in longwall shield projects, an additional $70 million for the Northern West Virginia RO system, an additional $37 million for an overland conveyor, an additional $30 million for the ongoing development of the BMX Mine (scheduled to begin production in early 2014) and an additional $34 million in various other individually insignificant projects, offset, in part, by a decrease of $30 million for a longwall face extension;
|
•
|
Gas segment capital expenditures decreased $134 million due to management's decision to decrease CBM and conventional drilling during 2012 in response to low gas prices;
|
•
|
Mineral lease expenditures associated with our advance mining royalties and leased coal assets increased $7 million in 2012; and
|
•
|
Other capital expenditures increased $10 million related to various miscellaneous items, none of which were individually material.
|
•
|
Proceeds from sale of assets decreased $101 million due to:
|
•
|
Proceeds of an additional $158 million received in 2011 related to the Noble transaction;
|
•
|
Proceeds of $190 million received in 2011 related to the sale of the Antero overriding royalty interest;
|
•
|
Proceeds of $170 million received in 2012 related to the sale of non-producing Northern Powder River Basin (PRB) assets;
|
•
|
Proceeds of $52 million received in 2012 from the Ram River & Scurry Canadian asset sale;
|
•
|
Proceeds increased $25 million due to various other transactions that occurred throughout both periods, none of which were individually material.
|
•
|
Distributions from/investments in equity affiliates decreased $79 million due to:
|
•
|
Contributions of $42 million to CONE in order to meet the operating and capital expenditure;
|
•
|
A cash distribution of $67 million from CONE Gathering LLC; and
|
•
|
Net contributions of $30 million from various equity affiliates, none of which were individually significant.
|
•
|
Restricted cash receipts of $48 million associated with the Ram River & Scurry Canadian asset sale.
|
•
|
A make-whole provision of $266 million in 2011 to redeem 7.875% notes due in March 2012;
|
•
|
Payments of $284 million in 2011 on short term borrowing under the revolving credit facility;
|
•
|
Proceeds of $250 million in 2011 from the issuance of 6.375% senior unsecured notes due in March 2021;
|
•
|
Payments of $200 million in 2011 under the accounts receivable securitization program;
|
•
|
Proceeds of $25 million in 2012 from an interim funding agreement for the Bailey longwall shields;
|
•
|
Proceeds of $38 million in 2012 from the accounts receivable securitization program;
|
•
|
Increased dividend payments of $46 million in 2012 due to an additional dividend payment in 2012 associated with the acceleration of the fourth quarter dividend and the increase of the quarterly dividend for the entire year; and
|
•
|
An increase of $7 million due to various transactions throughout both period, none of which were individually material.
|
|
Payments due by Year
|
||||||||||||||||||
|
Less Than
1 Year
|
|
1-3 Years
|
|
3-5 Years
|
|
More Than
5 Years
|
|
Total
|
||||||||||
Short-term Notes Payable
|
$
|
25,073
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
25,073
|
|
Borrowings Under Securitization Facility
|
37,846
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
37,846
|
|
|||||
Purchase Order Firm Commitments
|
189,102
|
|
|
172,763
|
|
|
—
|
|
|
—
|
|
|
361,865
|
|
|||||
Gas Firm Transportation
|
80,359
|
|
|
148,502
|
|
|
130,919
|
|
|
435,384
|
|
|
795,164
|
|
|||||
Long-Term Debt
|
4,544
|
|
|
8,395
|
|
|
1,505,451
|
|
|
1,610,627
|
|
|
3,129,017
|
|
|||||
Interest on Long-Term Debt
|
244,977
|
|
|
490,664
|
|
|
430,800
|
|
|
369,842
|
|
|
1,536,283
|
|
|||||
Capital (Finance) Lease Obligations
|
8,941
|
|
|
14,464
|
|
|
10,932
|
|
|
24,717
|
|
|
59,054
|
|
|||||
Interest on Capital (Finance) Lease Obligations
|
3,895
|
|
|
6,118
|
|
|
4,455
|
|
|
3,692
|
|
|
18,160
|
|
|||||
Operating Lease Obligations
|
88,997
|
|
|
139,557
|
|
|
78,478
|
|
|
132,637
|
|
|
439,669
|
|
|||||
Long-Term Liabilities—Employee Related (a)
|
225,562
|
|
|
441,819
|
|
|
441,252
|
|
|
2,312,604
|
|
|
3,421,237
|
|
|||||
Other Long-Term Liabilities (b)
|
321,729
|
|
|
132,148
|
|
|
88,873
|
|
|
480,857
|
|
|
1,023,607
|
|
|||||
Total Contractual Obligations (c)
|
$
|
1,231,025
|
|
|
$
|
1,554,430
|
|
|
$
|
2,691,160
|
|
|
$
|
5,370,360
|
|
|
$
|
10,846,975
|
|
(a)
|
Long-term liabilities—employee related include other post-employment benefits, work-related injuries and illnesses. Estimated salaried retirement contributions required to meet minimum funding standards under ERISA are excluded from the pay-out table due to the uncertainty regarding amounts to be contributed. Estimated 2013 contributions are expected to approximate $
50
million to
$75
million.
|
(b)
|
Other long-term liabilities include mine reclamation and closure and other long-term liability costs.
|
(c)
|
The significant obligation table does not include obligations to taxing authorities due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations.
|
•
|
An aggregate principal amount of $
1.50
billion
of
8.00%
senior unsecured notes due in April 2017. Interest on the notes is payable April 1 and October 1 of each year. Payment of the principal and interest on the notes are guaranteed by most of CONSOL Energy’s subsidiaries.
|
•
|
An aggregate principal amount of $
1.25
billion
of
8.25%
senior unsecured notes due in April 2020. Interest on the notes is payable April 1 and October 1 of each year. Payment of the principal and interest on the notes are guaranteed by most of CONSOL Energy’s subsidiaries.
|
•
|
An aggregate principal amount of $
250
million
of
6.375%
notes due in March 2021. Interest on the notes is payable March 1 and September 1 of each year. Payment of the principal and interest on the notes are guaranteed by most of CONSOL Energy's subsidiaries.
|
•
|
An aggregate principal amount of $
103
million
of industrial revenue bonds which were issued to finance the Baltimore port facility and bear interest at
5.75%
per annum and mature in September 2025. Interest on the industrial revenue bonds is payable March 1 and September 1 of each year.
|
•
|
Advance royalty commitments of $
20
million
with an average interest rate of
7.43%
per annum.
|
•
|
An aggregate principal amount of $
6
million
on other various rate notes maturing through June 2031.
|
•
|
An aggregate principal amount of $
59
million
of capital leases with a weighted average interest rate of
6.38%
per annum.
|
Declaration Date
|
|
Amount Per Share
|
|
Record Date
|
|
Payment Date
|
December 10, 2012
|
|
$0.125
|
|
December 21, 2012
|
|
December 28, 2012
|
October 26, 2012
|
|
$0.125
|
|
November 9, 2012
|
|
November 23, 2012
|
July 27, 2012
|
|
$0.125
|
|
August 10, 2012
|
|
August 24, 2012
|
April 27, 2012
|
|
$0.125
|
|
May 11, 2012
|
|
May 25, 2012
|
January 27, 2012
|
|
$0.125
|
|
February 7, 2012
|
|
February 21, 2012
|
ITEM 7A.
|
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
|
|
For the Three Months Ended
|
|
|
||||||||||||||||
|
March 31,
|
|
June 30,
|
|
September 30,
|
|
December 31,
|
|
Total Year
|
||||||||||
2013 Fixed Price Volumes
|
|
|
|
|
|
|
|
|
|
||||||||||
Hedged Mcf
|
17,042,684
|
|
|
17,232,047
|
|
|
17,421,410
|
|
|
17,421,410
|
|
|
69,117,551
|
|
|||||
Weighted Average Hedge Price/Mcf
|
$
|
4.66
|
|
|
$
|
4.66
|
|
|
$
|
4.66
|
|
|
$
|
4.66
|
|
|
$
|
4.66
|
|
2014 Fixed Price Volumes
|
|
|
|
|
|
|
|
|
|
||||||||||
Hedged Mcf
|
14,487,673
|
|
|
14,648,647
|
|
|
14,809,621
|
|
|
14,809,621
|
|
|
58,755,562
|
|
|||||
Weighted Average Hedge Price/Mcf
|
$
|
4.87
|
|
|
$
|
4.87
|
|
|
$
|
4.87
|
|
|
$
|
4.87
|
|
|
$
|
4.87
|
|
2015 Fixed Price Volumes
|
|
|
|
|
|
|
|
|
|
||||||||||
Hedged Mcf
|
10,022,456
|
|
|
10,133,816
|
|
|
10,245,177
|
|
|
10,245,177
|
|
|
40,646,626
|
|
|||||
Weighted Average Hedge Price/Mcf
|
$
|
4.10
|
|
|
$
|
4.10
|
|
|
$
|
4.10
|
|
|
$
|
4.10
|
|
|
$
|
4.10
|
|
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, 2012, 2011 and 2010
|
||
Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2012, 2011 and 2010
|
||
Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010
|
||
Notes to the Audited Consolidated Financial Statements
|
|
|
|
|
|
|
||||||
|
For the Years Ended December 31,
|
||||||||||
|
2012
|
|
2011
|
|
2010
|
||||||
Sales—Outside
|
$
|
4,825,946
|
|
|
$
|
5,660,813
|
|
|
$
|
4,938,703
|
|
Sales—Gas Royalty Interests
|
49,405
|
|
|
66,929
|
|
|
62,869
|
|
|||
Sales—Purchased Gas
|
3,316
|
|
|
4,344
|
|
|
11,227
|
|
|||
Freight—Outside
|
141,936
|
|
|
231,536
|
|
|
125,715
|
|
|||
Other Income (Note 3)
|
409,704
|
|
|
153,620
|
|
|
97,507
|
|
|||
Total Revenue and Other Income
|
5,430,307
|
|
|
6,117,242
|
|
|
5,236,021
|
|
|||
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)
|
3,421,953
|
|
|
3,501,298
|
|
|
3,262,327
|
|
|||
Gas Royalty Interests Costs
|
38,867
|
|
|
59,331
|
|
|
53,775
|
|
|||
Purchased Gas Costs
|
2,711
|
|
|
3,831
|
|
|
9,736
|
|
|||
Freight Expense
|
141,936
|
|
|
231,347
|
|
|
125,544
|
|
|||
Selling, General and Administrative Expenses
|
148,071
|
|
|
175,467
|
|
|
150,210
|
|
|||
Depreciation, Depletion and Amortization
|
622,780
|
|
|
618,397
|
|
|
567,663
|
|
|||
Interest Expense (Note 4)
|
220,060
|
|
|
248,344
|
|
|
205,032
|
|
|||
Taxes Other Than Income (Note 5)
|
336,655
|
|
|
344,460
|
|
|
328,458
|
|
|||
Abandonment of Long-Lived Assets (Note 10)
|
—
|
|
|
115,817
|
|
|
—
|
|
|||
Loss on Debt Extinguishment (Note 13)
|
—
|
|
|
16,090
|
|
|
—
|
|
|||
Transaction and Financing Fees (Note 13)
|
—
|
|
|
14,907
|
|
|
65,363
|
|
|||
Total Costs
|
4,933,033
|
|
|
5,329,289
|
|
|
4,768,108
|
|
|||
Earnings Before Income Taxes
|
497,274
|
|
|
787,953
|
|
|
467,913
|
|
|||
Income Taxes (Note 6)
|
109,201
|
|
|
155,456
|
|
|
109,287
|
|
|||
Net Income
|
388,073
|
|
|
632,497
|
|
|
358,626
|
|
|||
Less: Net Loss (Income) Attributable to Noncontrolling Interest
|
397
|
|
|
—
|
|
|
(11,845
|
)
|
|||
Net Income Attributable to CONSOL Energy Inc. Shareholders
|
$
|
388,470
|
|
|
$
|
632,497
|
|
|
$
|
346,781
|
|
Earnings Per Share (Note 1):
|
|
|
|
|
|
||||||
Basic
|
$
|
1.71
|
|
|
$
|
2.79
|
|
|
$
|
1.61
|
|
Dilutive
|
$
|
1.70
|
|
|
$
|
2.76
|
|
|
$
|
1.60
|
|
Weighted Average Number of Common Shares Outstanding (Note 1):
|
|
|
|
|
|
||||||
Basic
|
227,593,524
|
|
|
226,680,369
|
|
|
214,920,561
|
|
|||
Dilutive
|
229,141,767
|
|
|
229,003,599
|
|
|
217,037,804
|
|
|||
Dividends Paid Per Share
|
$
|
0.625
|
|
|
$
|
0.425
|
|
|
$
|
0.400
|
|
|
|
|
|
|
|
||||||
|
For the Years Ended December 31,
|
||||||||||
|
2012
|
|
2011
|
|
2010
|
||||||
Net Income
|
$
|
388,073
|
|
|
$
|
632,497
|
|
|
$
|
358,626
|
|
Other Comprehensive Income:
|
|
|
|
|
|
||||||
Treasury Rate Lock (Net of tax: $-, $59, $49)
|
—
|
|
|
(96
|
)
|
|
(84
|
)
|
|||
Actuarially Determined Long-Term Liability Adjustments (Net of tax: ($77,871), $1,583, $154,773)
|
129,231
|
|
|
(32,813
|
)
|
|
(221,228
|
)
|
|||
Net Increase in the Value of Cash Flow Hedge (Net of tax: ($73,593), ($129,235), ($92,048))
|
114,240
|
|
|
200,700
|
|
|
140,985
|
|
|||
Reclassification of Cash Flow Hedges from Other Comprehensive Income to Earnings (Net of tax: $121,484, $60,925, $108,031)
|
(189,259
|
)
|
|
(95,007
|
)
|
|
(166,276
|
)
|
|||
Purchase of CNX Gas Noncontrolling Interest
|
—
|
|
|
—
|
|
|
18,026
|
|
|||
|
|
|
|
|
|
||||||
Other Comprehensive Income (Loss)
|
54,212
|
|
|
72,784
|
|
|
(228,577
|
)
|
|||
|
|
|
|
|
|
||||||
Comprehensive Income
|
442,285
|
|
|
705,281
|
|
|
130,049
|
|
|||
|
|
|
|
|
|
||||||
Less: Comprehensive Loss (Income) Attributable to Noncontrolling Interest
|
397
|
|
|
—
|
|
|
(17,102
|
)
|
|||
|
|
|
|
|
|
||||||
Comprehensive Income Attributable to CONSOL Energy Inc. Shareholders
|
$
|
442,682
|
|
|
$
|
705,281
|
|
|
$
|
112,947
|
|
|
|
|
|
||||
|
December 31,
2012 |
|
December 31,
2011 |
||||
ASSETS
|
|
|
|
||||
Current Assets:
|
|
|
|
||||
Cash and Cash Equivalents
|
$
|
21,878
|
|
|
$
|
375,736
|
|
Accounts and Notes Receivable:
|
|
|
|
||||
Trade
|
428,328
|
|
|
462,812
|
|
||
Notes Receivable
|
318,387
|
|
|
314,950
|
|
||
Other Receivables
|
131,131
|
|
|
105,708
|
|
||
Accounts Receivable—Securitized (Note 9)
|
37,846
|
|
|
—
|
|
||
Inventories (Note 8)
|
247,766
|
|
|
258,335
|
|
||
Deferred Income Taxes (Note 6)
|
148,104
|
|
|
141,083
|
|
||
Restricted Cash (Note 1)
|
48,294
|
|
|
—
|
|
||
Prepaid Expenses
|
157,360
|
|
|
239,353
|
|
||
Total Current Assets
|
1,539,094
|
|
|
1,897,977
|
|
||
Property, Plant and Equipment (Note 10):
|
|
|
|
||||
Property, Plant and Equipment
|
15,545,204
|
|
|
14,087,319
|
|
||
Less—Accumulated Depreciation, Depletion and Amortization
|
5,354,237
|
|
|
4,760,903
|
|
||
Total Property, Plant and Equipment—Net
|
10,190,967
|
|
|
9,326,416
|
|
||
Other Assets:
|
|
|
|
||||
Deferred Income Taxes (Note 6)
|
444,585
|
|
|
507,724
|
|
||
Restricted Cash (Note 1)
|
20,379
|
|
|
22,148
|
|
||
Investment in Affiliates
|
222,830
|
|
|
182,036
|
|
||
Notes Receivable
|
25,977
|
|
|
300,492
|
|
||
Other
|
227,077
|
|
|
288,907
|
|
||
Total Other Assets
|
940,848
|
|
|
1,301,307
|
|
||
TOTAL ASSETS
|
$
|
12,670,909
|
|
|
$
|
12,525,700
|
|
|
|
|
|
||||
|
December 31,
2012 |
|
December 31,
2011 |
||||
LIABILITIES AND EQUITY
|
|
|
|
||||
Current Liabilities:
|
|
|
|
||||
Accounts Payable
|
$
|
507,982
|
|
|
$
|
522,003
|
|
Current Portion of Long-Term Debt (Note 13 and Note 14)
|
13,485
|
|
|
20,691
|
|
||
Short-Term Notes Payable (Note 11)
|
25,073
|
|
|
—
|
|
||
Accrued Income Taxes
|
34,219
|
|
|
75,633
|
|
||
Borrowings Under Securitization Facility (Note 9)
|
37,846
|
|
|
—
|
|
||
Other Accrued Liabilities (Note 12)
|
768,494
|
|
|
770,070
|
|
||
Total Current Liabilities
|
1,387,099
|
|
|
1,388,397
|
|
||
Long-Term Debt:
|
|
|
|
||||
Long-Term Debt (Note 13)
|
3,124,473
|
|
|
3,122,234
|
|
||
Capital Lease Obligations (Note 14)
|
50,113
|
|
|
55,189
|
|
||
Total Long-Term Debt
|
3,174,586
|
|
|
3,177,423
|
|
||
Deferred Credits and Other Liabilities:
|
|
|
|
||||
Postretirement Benefits Other Than Pensions (Note 15)
|
2,832,401
|
|
|
3,059,671
|
|
||
Pneumoconiosis Benefits (Note 16)
|
174,781
|
|
|
173,553
|
|
||
Mine Closing (Note 7)
|
446,727
|
|
|
406,712
|
|
||
Gas Well Closing (Note 7)
|
148,928
|
|
|
124,051
|
|
||
Workers’ Compensation (Note 16)
|
155,648
|
|
|
151,034
|
|
||
Salary Retirement (Note 15)
|
218,004
|
|
|
269,069
|
|
||
Reclamation (Note 7)
|
47,965
|
|
|
39,969
|
|
||
Other
|
131,025
|
|
|
124,936
|
|
||
Total Deferred Credits and Other Liabilities
|
4,155,479
|
|
|
4,348,995
|
|
||
TOTAL LIABILITIES
|
8,717,164
|
|
|
8,914,815
|
|
||
Stockholders’ Equity:
|
|
|
|
||||
Common Stock, $.01 Par Value; 500,000,000 Shares Authorized, 228,129,467 Issued and 228,094,712 Outstanding at December 31, 2012; 227,289,426 Issued and 227,056,212 Outstanding at December 31, 2011
|
2,284
|
|
|
2,273
|
|
||
Capital in Excess of Par Value
|
2,296,908
|
|
|
2,234,775
|
|
||
Preferred Stock, 15,000,000 Shares Authorized, None Issued and Outstanding
|
—
|
|
|
—
|
|
||
Retained Earnings
|
2,402,551
|
|
|
2,184,737
|
|
||
Accumulated Other Comprehensive Loss
|
(747,342
|
)
|
|
(801,554
|
)
|
||
Common Stock in Treasury, at Cost—34,755 Shares at December 31, 2012 and 233,214 Shares at December 31, 2011
|
(609
|
)
|
|
(9,346
|
)
|
||
Total CONSOL Energy Inc. Stockholders’ Equity
|
3,953,792
|
|
|
3,610,885
|
|
||
Noncontrolling Interest
|
(47
|
)
|
|
—
|
|
||
TOTAL EQUITY
|
3,953,745
|
|
|
3,610,885
|
|
||
TOTAL LIABILITIES AND EQUITY
|
$
|
12,670,909
|
|
|
$
|
12,525,700
|
|
|
|
|
|
|
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, 2009
|
$
|
1,830
|
|
|
$
|
1,033,616
|
|
|
$
|
1,456,898
|
|
|
$
|
(640,504
|
)
|
|
$
|
(66,292
|
)
|
|
$
|
1,785,548
|
|
|
$
|
238,931
|
|
|
$
|
2,024,479
|
|
Net Income
|
—
|
|
|
—
|
|
|
346,781
|
|
|
—
|
|
|
—
|
|
|
346,781
|
|
|
11,845
|
|
|
358,626
|
|
||||||||
Treasury Rate Lock (Net of $49 Tax)
|
—
|
|
|
—
|
|
|
—
|
|
|
(84
|
)
|
|
—
|
|
|
(84
|
)
|
|
—
|
|
|
(84
|
)
|
||||||||
Gas Cash Flow Hedge (Net of $15,983 Tax)
|
—
|
|
|
—
|
|
|
—
|
|
|
(30,543
|
)
|
|
—
|
|
|
(30,543
|
)
|
|
5,252
|
|
|
(25,291
|
)
|
||||||||
Actuarially Determined Long-Term Liability Adjustments (Net of $154,773 Tax)
|
—
|
|
|
—
|
|
|
—
|
|
|
(221,233
|
)
|
|
—
|
|
|
(221,233
|
)
|
|
5
|
|
|
(221,228
|
)
|
||||||||
Purchase of CNX Gas Noncontrolling Interest
|
—
|
|
|
—
|
|
|
—
|
|
|
18,026
|
|
|
—
|
|
|
18,026
|
|
|
—
|
|
|
18,026
|
|
||||||||
Comprehensive Income (Loss)
|
—
|
|
|
—
|
|
|
346,781
|
|
|
(233,834
|
)
|
|
—
|
|
|
112,947
|
|
|
17,102
|
|
|
130,049
|
|
||||||||
Issuance of Treasury Stock
|
—
|
|
|
—
|
|
|
(37,221
|
)
|
|
—
|
|
|
23,633
|
|
|
(13,588
|
)
|
|
—
|
|
|
(13,588
|
)
|
||||||||
Issuance of Common Stock
|
443
|
|
|
1,828,419
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,828,862
|
|
|
—
|
|
|
1,828,862
|
|
||||||||
Issuance of CNX Gas Stock
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,178
|
|
|
2,178
|
|
||||||||
Purchase of CNX Gas Noncontrolling Interest
|
—
|
|
|
(746,052
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(746,052
|
)
|
|
(263,008
|
)
|
|
(1,009,060
|
)
|
||||||||
Tax Benefit from Stock-Based Compensation
|
—
|
|
|
15,100
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
15,100
|
|
|
—
|
|
|
15,100
|
|
||||||||
Amortization of Stock-Based Compensation Awards
|
—
|
|
|
45,395
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
45,395
|
|
|
2,198
|
|
|
47,593
|
|
||||||||
Stock-Based Compensation Awards to CNX Gas Employees
|
—
|
|
|
2,126
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,126
|
|
|
(1,771
|
)
|
|
355
|
|
||||||||
Net Change in Noncontrolling Interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(4,094
|
)
|
|
(4,094
|
)
|
||||||||
Dividends ($0.40 per share)
|
—
|
|
|
—
|
|
|
(85,861
|
)
|
|
—
|
|
|
—
|
|
|
(85,861
|
)
|
|
—
|
|
|
(85,861
|
)
|
||||||||
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 $1,583 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
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2012
|
|
2011
|
|
2010
|
||||||
Cash Flows from Operating Activities:
|
|
|
|
|
|
||||||
Net Income
|
$
|
388,073
|
|
|
$
|
632,497
|
|
|
$
|
358,626
|
|
Adjustments to Reconcile Net Income to Net Cash Provided By Operating Activities:
|
|
|
|
|
|
||||||
Depreciation, Depletion and Amortization
|
622,780
|
|
|
618,397
|
|
|
567,663
|
|
|||
Abandonment of Long-Lived Assets
|
—
|
|
|
115,817
|
|
|
—
|
|
|||
Stock-Based Compensation
|
47,838
|
|
|
48,842
|
|
|
47,593
|
|
|||
Gain on Sale of Assets
|
(282,235
|
)
|
|
(46,497
|
)
|
|
(9,908
|
)
|
|||
Loss on Debt Extinguishment
|
—
|
|
|
16,090
|
|
|
—
|
|
|||
Amortization of Mineral Leases
|
4,658
|
|
|
7,608
|
|
|
4,160
|
|
|||
Deferred Income Taxes
|
(6,649
|
)
|
|
(53,011
|
)
|
|
17,029
|
|
|||
Equity in Earnings of Affiliates
|
(27,048
|
)
|
|
(24,663
|
)
|
|
(21,428
|
)
|
|||
Changes in Operating Assets:
|
|
|
|
|
|
||||||
Accounts and Notes Receivable
|
(20,218
|
)
|
|
(83,770
|
)
|
|
(96,245
|
)
|
|||
Inventories
|
10,569
|
|
|
(380
|
)
|
|
48,919
|
|
|||
Prepaid Expenses
|
8,095
|
|
|
4,431
|
|
|
(20,974
|
)
|
|||
Changes in Other Assets
|
(7,041
|
)
|
|
17,745
|
|
|
7,237
|
|
|||
Changes in Operating Liabilities:
|
|
|
|
|
|
||||||
Accounts Payable
|
(20,106
|
)
|
|
144,652
|
|
|
78,839
|
|
|||
Other Operating Liabilities
|
(12,634
|
)
|
|
84,146
|
|
|
129,230
|
|
|||
Changes in Other Liabilities
|
1,917
|
|
|
30,309
|
|
|
(15,443
|
)
|
|||
Other
|
20,130
|
|
|
15,393
|
|
|
36,014
|
|
|||
Net Cash Provided by Operating Activities
|
728,129
|
|
|
1,527,606
|
|
|
1,131,312
|
|
|||
Cash Flows from Investing Activities:
|
|
|
|
|
|
||||||
Capital Expenditures
|
(1,575,230
|
)
|
|
(1,382,371
|
)
|
|
(1,154,024
|
)
|
|||
Acquisition of Dominion Exploration and Production Business
|
—
|
|
|
—
|
|
|
(3,470,212
|
)
|
|||
Purchase of CNX Gas Noncontrolling Interest
|
—
|
|
|
—
|
|
|
(991,034
|
)
|
|||
Change in Restricted Cash
|
(48,294
|
)
|
|
—
|
|
|
—
|
|
|||
Proceeds from Sales of Assets
|
646,565
|
|
|
747,971
|
|
|
59,844
|
|
|||
Distributions From, net of (Investments In), Equity Affiliates
|
(23,451
|
)
|
|
55,876
|
|
|
11,452
|
|
|||
Net Cash Used in Investing Activities
|
(1,000,410
|
)
|
|
(578,524
|
)
|
|
(5,543,974
|
)
|
|||
Cash Flows from Financing Activities:
|
|
|
|
|
|
||||||
Payments on Short-Term Borrowings
|
—
|
|
|
(284,000
|
)
|
|
(188,850
|
)
|
|||
Proceeds from (Payments on) Miscellaneous Borrowings
|
15,594
|
|
|
(11,627
|
)
|
|
(11,412
|
)
|
|||
Proceeds from (Payments on) Securitization Facility
|
37,846
|
|
|
(200,000
|
)
|
|
150,000
|
|
|||
Payments on Long-Term Notes, Including Redemption Premium
|
—
|
|
|
(265,785
|
)
|
|
—
|
|
|||
Proceeds from Issuance of Long-Term Notes
|
—
|
|
|
250,000
|
|
|
2,750,000
|
|
|||
Tax Benefit from Stock-Based Compensation
|
8,678
|
|
|
8,281
|
|
|
15,365
|
|
|||
Dividends Paid
|
(142,278
|
)
|
|
(96,356
|
)
|
|
(85,861
|
)
|
|||
Proceeds from Issuance of Common Stock
|
8,278
|
|
|
—
|
|
|
1,828,862
|
|
|||
(Purchases) Issuance of Treasury Stock
|
(9,485
|
)
|
|
9,033
|
|
|
5,993
|
|
|||
Debt Issuance and Financing Fees
|
(210
|
)
|
|
(15,686
|
)
|
|
(84,248
|
)
|
|||
Net Cash (Used In) Provided By Financing Activities
|
(81,577
|
)
|
|
(606,140
|
)
|
|
4,379,849
|
|
|||
Net (Decrease) Increase in Cash and Cash Equivalents
|
(353,858
|
)
|
|
342,942
|
|
|
(32,813
|
)
|
|||
Cash and Cash Equivalents at Beginning of Period
|
375,736
|
|
|
32,794
|
|
|
65,607
|
|
|||
Cash and Cash Equivalents at End of Period
|
$
|
21,878
|
|
|
$
|
375,736
|
|
|
$
|
32,794
|
|
|
|
Years
|
Buildings and improvements
|
|
10 to 45
|
Machinery and equipment
|
|
3 to 25
|
Leasehold improvements
|
|
Life of Lease
|
|
For the Years Ended
|
|||||||
|
December 31,
|
|||||||
|
2012
|
|
2011
|
|
2010
|
|||
Anti-Dilutive Options
|
2,411,963
|
|
|
1,156,018
|
|
|
813,833
|
|
Anti-Dilutive Restricted Stock Units
|
8,822
|
|
|
—
|
|
|
1,960
|
|
Anti-Dilutive Performance Share Units
|
445,847
|
|
|
—
|
|
|
—
|
|
Anti-Dilutive Performance Share Options
|
501,744
|
|
|
—
|
|
|
—
|
|
|
3,368,376
|
|
|
1,156,018
|
|
|
815,793
|
|
|
For the Years Ended
|
||||||||||
|
December 31,
|
||||||||||
|
2012
|
|
2011
|
|
2010
|
||||||
Net income attributable to CONSOL Energy Inc. shareholders
|
$
|
388,470
|
|
|
$
|
632,497
|
|
|
$
|
346,781
|
|
Weighted average shares of common stock outstanding:
|
|
|
|
|
|
||||||
Basic
|
227,593,524
|
|
|
226,680,369
|
|
|
214,920,561
|
|
|||
Effect of stock-based compensation awards
|
1,548,243
|
|
|
2,323,230
|
|
|
2,117,243
|
|
|||
Dilutive
|
229,141,767
|
|
|
229,003,599
|
|
|
217,037,804
|
|
|||
Earnings per share:
|
|
|
|
|
|
||||||
Basic
|
$
|
1.71
|
|
|
$
|
2.79
|
|
|
$
|
1.61
|
|
Dilutive
|
$
|
1.70
|
|
|
$
|
2.76
|
|
|
$
|
1.60
|
|
|
|
2012
|
|
2011
|
|
2010
|
|||
Balance, beginning of year
|
|
227,056,212
|
|
|
226,162,133
|
|
|
181,086,267
|
|
Issuance related to Stock-Based Compensation(1)
|
|
1,038,500
|
|
|
894,079
|
|
|
800,866
|
|
Issuance of Common Stock(2)
|
|
—
|
|
|
—
|
|
|
44,275,000
|
|
Balance, end of year
|
|
228,094,712
|
|
|
227,056,212
|
|
|
226,162,133
|
|
|
|
Year Ended
|
||||||
|
|
December 31,
|
||||||
|
|
2011
|
|
2010
|
||||
Total Revenue and Other Income
|
|
$
|
6,073,904
|
|
|
$
|
5,212,597
|
|
Earnings Before Income Taxes
|
|
$
|
775,807
|
|
|
$
|
465,740
|
|
Net Income Attributable to CONSOL Energy Inc. Shareholders
|
|
$
|
623,114
|
|
|
$
|
345,169
|
|
Basic Earnings Per Share
|
|
$
|
2.75
|
|
|
$
|
1.60
|
|
Dilutive Earnings Per Share
|
|
$
|
2.72
|
|
|
$
|
1.59
|
|
|
|
Year
|
||
|
|
Ended
|
||
|
|
December 31,
|
||
|
|
2010
|
||
Total Revenue and Other Income
|
|
$
|
5,303,008
|
|
Earnings Before Income Taxes
|
|
$
|
414,205
|
|
Net Income Attributable to CONSOL Energy Inc. Shareholders
|
|
$
|
314,760
|
|
Basic Earnings Per Share
|
|
$
|
1.39
|
|
Dilutive Earnings Per Share
|
|
$
|
1.38
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2012
|
|
|
2011
|
|
|
2010
|
|
|||
Gain on disposition of assets (a)
|
|
$
|
282,235
|
|
|
$
|
46,497
|
|
|
$
|
9,908
|
|
Interest income
|
|
28,937
|
|
|
8,919
|
|
|
7,642
|
|
|||
Equity in earnings of affiliates
|
|
27,048
|
|
|
24,663
|
|
|
21,428
|
|
|||
Royalty income
|
|
16,865
|
|
|
18,491
|
|
|
14,688
|
|
|||
Service income
|
|
9,029
|
|
|
9,059
|
|
|
9,796
|
|
|||
Right-of-way issuance
|
|
5,030
|
|
|
13,519
|
|
|
122
|
|
|||
Other
|
|
40,560
|
|
|
32,472
|
|
|
33,923
|
|
|||
Total Other Income
|
|
$
|
409,704
|
|
|
$
|
153,620
|
|
|
$
|
97,507
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2012
|
|
|
2011
|
|
|
2010
|
|
|||
Interest on debt
|
|
$
|
256,800
|
|
|
$
|
264,080
|
|
|
$
|
213,832
|
|
Interest on other payables
|
|
1,314
|
|
|
(189
|
)
|
|
4,593
|
|
|||
Interest capitalized
|
|
(38,054
|
)
|
|
(15,547
|
)
|
|
(13,393
|
)
|
|||
Total Interest Expense
|
|
$
|
220,060
|
|
|
$
|
248,344
|
|
|
$
|
205,032
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2012
|
|
2011
|
|
2010
|
||||||
Production taxes
|
|
$
|
201,906
|
|
|
$
|
220,857
|
|
|
$
|
202,536
|
|
Property taxes
|
|
68,145
|
|
|
58,117
|
|
|
57,889
|
|
|||
Payroll taxes
|
|
58,286
|
|
|
59,186
|
|
|
54,631
|
|
|||
Capital stock & franchise tax
|
|
8,378
|
|
|
3,670
|
|
|
11,201
|
|
|||
Virginia employment enhancement tax credit
|
|
(4,311
|
)
|
|
(6,109
|
)
|
|
(4,777
|
)
|
|||
Other
|
|
4,251
|
|
|
8,739
|
|
|
6,978
|
|
|||
Total Taxes Other Than Income
|
|
$
|
336,655
|
|
|
$
|
344,460
|
|
|
$
|
328,458
|
|
|
For The Years Ended December 31,
|
||||||||||
|
2012
|
|
2011
|
|
2010
|
||||||
Current:
|
|
|
|
|
|
||||||
U.S. Federal
|
$
|
75,579
|
|
|
$
|
173,912
|
|
|
$
|
82,031
|
|
U.S. State
|
8,677
|
|
|
34,555
|
|
|
13,652
|
|
|||
Non-U.S
|
31,594
|
|
|
—
|
|
|
(3,425
|
)
|
|||
|
115,850
|
|
|
208,467
|
|
|
92,258
|
|
|||
Deferred:
|
|
|
|
|
|
||||||
U.S. Federal
|
(6,717
|
)
|
|
(35,487
|
)
|
|
8,463
|
|
|||
U.S. State
|
(1,697
|
)
|
|
(17,524
|
)
|
|
8,566
|
|
|||
Non-U.S.
|
1,765
|
|
|
—
|
|
|
—
|
|
|||
|
$
|
(6,649
|
)
|
|
$
|
(53,011
|
)
|
|
$
|
17,029
|
|
|
|
|
|
|
|
||||||
Total Income Taxes
|
$
|
109,201
|
|
|
$
|
155,456
|
|
|
$
|
109,287
|
|
|
December 31,
|
||||||
|
2012
|
|
2011
|
||||
Deferred Tax Assets:
|
|
|
|
||||
Postretirement benefits other than pensions
|
$
|
1,136,495
|
|
|
$
|
1,217,246
|
|
Mine closing
|
107,418
|
|
|
95,193
|
|
||
Alternative minimum tax
|
54,609
|
|
|
54,998
|
|
||
Pneumoconiosis benefits
|
70,141
|
|
|
69,915
|
|
||
Workers' compensation
|
68,339
|
|
|
65,266
|
|
||
Salary retirement
|
83,077
|
|
|
103,146
|
|
||
Net operating loss
|
59,797
|
|
|
57,669
|
|
||
Mine subsidence
|
35,332
|
|
|
41,453
|
|
||
Reclamation
|
26,716
|
|
|
23,738
|
|
||
Capital lease
|
23,103
|
|
|
24,763
|
|
||
Other
|
149,435
|
|
|
136,211
|
|
||
Total Deferred Tax Assets
|
1,814,462
|
|
|
1,889,598
|
|
||
Valuation Allowance**
|
(41,136
|
)
|
|
(41,016
|
)
|
||
Net Deferred Tax Assets
|
1,773,326
|
|
|
1,848,582
|
|
||
|
|
|
|
||||
Deferred Tax Liabilities:
|
|
|
|
||||
Property, plant and equipment
|
(1,084,246
|
)
|
|
(1,046,235
|
)
|
||
Gas hedge
|
(51,006
|
)
|
|
(98,539
|
)
|
||
Advance mining royalties
|
(33,950
|
)
|
|
(31,284
|
)
|
||
Other
|
(11,435
|
)
|
|
(23,717
|
)
|
||
Total Deferred Tax Liabilities
|
(1,180,637
|
)
|
|
(1,199,775
|
)
|
||
|
|
|
|
||||
Net Deferred Tax Assets
|
$
|
592,689
|
|
|
$
|
648,807
|
|
|
For the Years Ended December 31,
|
|||||||||||||||||||
|
2012
|
|
2011
|
|
2010
|
|||||||||||||||
|
Amount
|
|
Percent
|
|
Amount
|
|
Percent
|
|
Amount
|
|
Percent
|
|||||||||
Statutory U.S. federal income tax rate
|
$
|
174,047
|
|
|
35.0
|
%
|
|
$
|
275,784
|
|
|
35.0
|
%
|
|
$
|
163,770
|
|
|
35.0
|
%
|
Excess tax depletion
|
(72,028
|
)
|
|
(14.5
|
)
|
|
(91,470
|
)
|
|
(11.6
|
)
|
|
(70,812
|
)
|
|
(15.1
|
)
|
|||
Effect of medicare prescription drug, improvement and modernization act of 2003
|
2,112
|
|
|
0.4
|
|
|
2,112
|
|
|
0.3
|
|
|
2,113
|
|
|
0.4
|
|
|||
Effect of domestic production activities
|
(10,267
|
)
|
|
(2.0
|
)
|
|
(22,209
|
)
|
|
(2.8
|
)
|
|
(5,633
|
)
|
|
(1.2
|
)
|
|||
Federal and state tax accrual to tax return reconciliation
|
6,004
|
|
|
1.2
|
|
|
2,257
|
|
|
0.3
|
|
|
4,609
|
|
|
1.0
|
|
|||
IRS and state tax examination settlements
|
(925
|
)
|
|
(0.2
|
)
|
|
(5,188
|
)
|
|
(0.7
|
)
|
|
—
|
|
|
—
|
|
|||
Net effect of state income taxes
|
4,479
|
|
|
0.9
|
|
|
14,197
|
|
|
1.8
|
|
|
12,022
|
|
|
2.6
|
|
|||
Effect of releasing valuation allowance
|
—
|
|
|
—
|
|
|
(22,618
|
)
|
|
(2.9
|
)
|
|
—
|
|
|
—
|
|
|||
Effect of foreign tax
|
1,765
|
|
|
0.4
|
|
|
(1,822
|
)
|
|
(0.2
|
)
|
|
(3,424
|
)
|
|
(0.7
|
)
|
|||
Other
|
4,014
|
|
|
0.8
|
|
|
4,413
|
|
|
0.5
|
|
|
6,642
|
|
|
1.4
|
|
|||
Income Tax Expense / Effective Rate
|
$
|
109,201
|
|
|
22.0
|
%
|
|
$
|
155,456
|
|
|
19.7
|
%
|
|
$
|
109,287
|
|
|
23.4
|
%
|
|
For the Years Ended
|
||||||
|
December 31,
|
||||||
|
2012
|
|
2011
|
||||
Balance at beginning of period
|
$
|
37,586
|
|
|
$
|
91,349
|
|
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
|
)
|
|
(17,362
|
)
|
||
Reduction of unrecognized tax benefits as a result of a settlement with taxing authorities
|
—
|
|
|
(36,401
|
)
|
||
Balance at end of period
|
$
|
34,786
|
|
|
$
|
37,586
|
|
|
|
As of December 31,
|
||||||
|
|
2012
|
|
2011
|
||||
Balance at beginning of period
|
|
$
|
650,073
|
|
|
$
|
670,856
|
|
Accretion expense
|
|
49,332
|
|
|
48,120
|
|
||
Payments
|
|
(40,242
|
)
|
|
(57,584
|
)
|
||
Revisions in estimated cash flows
|
|
43,988
|
|
|
(4,621
|
)
|
||
Dispositions
|
|
(4,139
|
)
|
|
(6,698
|
)
|
||
Balance at end of period
|
|
$
|
699,012
|
|
|
$
|
650,073
|
|
|
December 31,
|
||||||
|
2012
|
|
2011
|
||||
Coal
|
$
|
78,825
|
|
|
$
|
105,378
|
|
Merchandise for resale
|
35,363
|
|
|
43,639
|
|
||
Supplies
|
133,578
|
|
|
109,318
|
|
||
Total Inventories
|
$
|
247,766
|
|
|
$
|
258,335
|
|
|
December 31,
|
||||||
|
2012
|
|
2011
|
||||
Coal & Other Plant and Equipment
|
$
|
6,022,404
|
|
|
$
|
5,160,759
|
|
Proven Properties
|
1,606,376
|
|
|
1,542,837
|
|
||
Intangible Drilling Cost
|
1,550,539
|
|
|
1,277,678
|
|
||
Coal Properties and Surface Lands
|
1,336,186
|
|
|
1,340,757
|
|
||
Unproven Gas Properties
|
1,266,444
|
|
|
1,258,027
|
|
||
Gas Gathering Equipment
|
1,006,882
|
|
|
963,494
|
|
||
Airshafts
|
706,388
|
|
|
659,736
|
|
||
Mine Development
|
537,939
|
|
|
457,179
|
|
||
Leased Coal Lands
|
529,758
|
|
|
540,817
|
|
||
Gas Wells and Related Equipment
|
492,112
|
|
|
408,814
|
|
||
Coal Advance Mining Royalties
|
391,501
|
|
|
393,340
|
|
||
Other Gas Assets
|
90,446
|
|
|
79,816
|
|
||
Gas Advance Royalties
|
8,229
|
|
|
4,065
|
|
||
Total property, plant and equipment
|
15,545,204
|
|
|
14,087,319
|
|
||
Less Accumulated depreciation, depletion and amortization
|
5,354,237
|
|
|
4,760,903
|
|
||
Total Net Property, Plant and Equipment
|
$
|
10,190,967
|
|
|
$
|
9,326,416
|
|
|
|
December 31,
|
||||||
|
|
2012
|
|
2011
|
||||
Unproven gas properties
|
|
$
|
1,266,444
|
|
|
$
|
1,258,027
|
|
Coal properties
|
|
387,294
|
|
|
386,402
|
|
||
Mine Development
|
|
146,138
|
|
|
78,990
|
|
||
Leased coal lands
|
|
126,085
|
|
|
178,988
|
|
||
Coal advance mining royalties
|
|
57,326
|
|
|
54,533
|
|
||
Airshafts
|
|
36,674
|
|
|
47,437
|
|
||
Gas advance royalties
|
|
8,229
|
|
|
3,884
|
|
||
Total
|
|
$
|
2,028,190
|
|
|
$
|
2,008,261
|
|
|
|
Industry
|
|
Industry
|
|
|
||
|
|
Participation
|
|
Participation
|
|
Drilling
|
||
Shale
|
|
Agreement
|
|
Agreement
|
|
Carries
|
||
Play
|
|
Partner
|
|
Date
|
|
Remaining*
|
||
Marcellus
|
|
Noble
|
|
September 30, 2011
|
|
$
|
2,089,790
|
|
Utica
|
|
Hess
|
|
October 21, 2011
|
|
$
|
505,851
|
|
|
|
December 31,
|
||||||
|
|
2012
|
|
2011
|
||||
Subsidence liability
|
|
$
|
126,078
|
|
|
$
|
108,094
|
|
Accrued payroll and benefits
|
|
64,000
|
|
|
65,775
|
|
||
Accrued interest
|
|
63,687
|
|
|
63,577
|
|
||
Accrued other taxes
|
|
36,172
|
|
|
50,869
|
|
||
Short-term incentive compensation
|
|
28,744
|
|
|
37,947
|
|
||
Voluntary severance incentive program
|
|
13,304
|
|
|
—
|
|
||
Other
|
|
147,067
|
|
|
135,067
|
|
||
Current portion of long-term liabilities:
|
|
|
|
|
||||
Postretirement benefits other than pensions
|
|
185,770
|
|
|
182,529
|
|
||
Workers' compensation
|
|
25,491
|
|
|
24,837
|
|
||
Mine closing
|
|
25,081
|
|
|
34,501
|
|
||
Reclamation
|
|
20,582
|
|
|
20,180
|
|
||
Gas well closing
|
|
9,729
|
|
|
24,660
|
|
||
Pneumoconiosis benefits
|
|
9,298
|
|
|
10,027
|
|
||
Salary retirement
|
|
6,938
|
|
|
5,713
|
|
||
Long-term disability
|
|
6,553
|
|
|
6,294
|
|
||
Total Other Accrued Liabilities
|
|
$
|
768,494
|
|
|
$
|
770,070
|
|
|
December 31,
|
||||||
|
2012
|
|
2011
|
||||
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 (7.43% and 6.73% weighted average interest rate for December 31, 2012 and 2011, respectively)
|
20,394
|
|
|
31,053
|
|
||
Other long-term notes maturing at various dates through 2031 (total value of $7,300 less unamortized discount of $1,542 at December 31, 2012)
|
5,758
|
|
|
75
|
|
||
|
3,129,017
|
|
|
3,133,993
|
|
||
Less amounts due in one year
|
4,544
|
|
|
11,759
|
|
||
Long-Term Debt
|
$
|
3,124,473
|
|
|
$
|
3,122,234
|
|
Year ended December 31,
|
Amount
|
||
2013
|
$
|
5,035
|
|
2014
|
4,965
|
|
|
2015
|
4,862
|
|
|
2016
|
3,334
|
|
|
2017
|
1,503,283
|
|
|
Thereafter
|
1,619,230
|
|
|
Total Long-Term Debt Maturities
|
$
|
3,140,709
|
|
|
|
Capital
|
|
Operating
|
||||
|
|
Leases
|
|
Leases
|
||||
Year Ended December 31,
|
|
|
|
|
||||
2013
|
|
$
|
12,836
|
|
|
$
|
88,997
|
|
2014
|
|
11,134
|
|
|
74,485
|
|
||
2015
|
|
9,448
|
|
|
65,072
|
|
||
2016
|
|
7,845
|
|
|
44,453
|
|
||
2017
|
|
7,542
|
|
|
34,025
|
|
||
Thereafter
|
|
28,409
|
|
|
132,637
|
|
||
Total minimum lease payments
|
|
$
|
77,214
|
|
|
$
|
439,669
|
|
Less amount representing interest (0.75% – 7.36%)
|
|
18,160
|
|
|
|
|||
Present value of minimum lease payments
|
|
59,054
|
|
|
|
|||
Less amount due in one year
|
|
8,941
|
|
|
|
|||
Total Long-Term Capital Lease Obligation
|
|
$
|
50,113
|
|
|
|
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
||||||||||||
|
|
at December 31,
|
|
at December 31,
|
||||||||||||
|
|
2012
|
|
2011
|
|
2012
|
|
2011
|
||||||||
Change in benefit obligation:
|
|
|
|
|
|
|
|
|
||||||||
Benefit obligation at beginning of period
|
|
$
|
857,352
|
|
|
$
|
701,152
|
|
|
$
|
3,242,200
|
|
|
$
|
3,257,199
|
|
Service cost
|
|
20,466
|
|
|
17,457
|
|
|
18,817
|
|
|
13,677
|
|
||||
Interest cost
|
|
37,586
|
|
|
37,744
|
|
|
135,695
|
|
|
179,739
|
|
||||
Actuarial loss (gain)
|
|
90,502
|
|
|
159,320
|
|
|
(131,150
|
)
|
|
(51,650
|
)
|
||||
Plan amendments
|
|
—
|
|
|
(7,186
|
)
|
|
(80,570
|
)
|
|
—
|
|
||||
Participant contributions
|
|
—
|
|
|
—
|
|
|
5,651
|
|
|
6,088
|
|
||||
Benefits and other payments
|
|
(52,804
|
)
|
|
(51,135
|
)
|
|
(172,471
|
)
|
|
(162,853
|
)
|
||||
Benefit obligation at end of period
|
|
$
|
953,102
|
|
|
$
|
857,352
|
|
|
$
|
3,018,172
|
|
|
$
|
3,242,200
|
|
|
|
|
|
|
|
|
|
|
||||||||
Change in plan assets:
|
|
|
|
|
|
|
|
|
||||||||
Fair value of plan assets at beginning of period
|
|
$
|
582,571
|
|
|
$
|
537,721
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Actual return on plan assets
|
|
87,935
|
|
|
23,791
|
|
|
—
|
|
|
—
|
|
||||
Company contributions
|
|
110,459
|
|
|
72,194
|
|
|
166,820
|
|
|
156,765
|
|
||||
Participant contributions
|
|
—
|
|
|
—
|
|
|
5,651
|
|
|
6,088
|
|
||||
Benefits and other payments
|
|
(52,804
|
)
|
|
(51,135
|
)
|
|
(172,471
|
)
|
|
(162,853
|
)
|
||||
Fair value of plan assets at end of period
|
|
$
|
728,161
|
|
|
$
|
582,571
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
||||||||
Funded status:
|
|
|
|
|
|
|
|
|
||||||||
Current liabilities
|
|
$
|
(6,938
|
)
|
|
$
|
(5,713
|
)
|
|
$
|
(185,770
|
)
|
|
$
|
(182,529
|
)
|
Noncurrent liabilities
|
|
(218,003
|
)
|
|
(269,068
|
)
|
|
(2,832,402
|
)
|
|
(3,059,671
|
)
|
||||
Net obligation recognized
|
|
$
|
(224,941
|
)
|
|
$
|
(274,781
|
)
|
|
$
|
(3,018,172
|
)
|
|
$
|
(3,242,200
|
)
|
|
|
|
|
|
|
|
|
|
||||||||
Amounts recognized in accumulated other comprehensive income consist of:
|
|
|
|
|
|
|
|
|
||||||||
Net actuarial loss
|
|
$
|
495,511
|
|
|
$
|
494,622
|
|
|
$
|
1,116,051
|
|
|
$
|
1,328,077
|
|
Prior service credit
|
|
(6,614
|
)
|
|
(8,244
|
)
|
|
(104,288
|
)
|
|
(75,546
|
)
|
||||
Net amount recognized (before tax effect)
|
|
$
|
488,897
|
|
|
$
|
486,378
|
|
|
$
|
1,011,763
|
|
|
$
|
1,252,531
|
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
||||||||||||||||||||
|
For the Years Ended December 31,
|
|
For the Years Ended December 31,
|
||||||||||||||||||||
|
2012
|
|
2011
|
|
2010
|
|
2012
|
|
2011
|
|
2010
|
||||||||||||
Components of net periodic benefit cost:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Service cost
|
$
|
20,466
|
|
|
$
|
17,457
|
|
|
$
|
14,485
|
|
|
$
|
18,817
|
|
|
$
|
13,677
|
|
|
$
|
13,147
|
|
Interest cost
|
37,586
|
|
|
37,744
|
|
|
37,150
|
|
|
135,695
|
|
|
179,739
|
|
|
162,815
|
|
||||||
Expected return on plan assets
|
(46,157
|
)
|
|
(38,522
|
)
|
|
(36,977
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Amortization of prior service (credits)
|
(1,630
|
)
|
|
(666
|
)
|
|
(735
|
)
|
|
(51,828
|
)
|
|
(46,397
|
)
|
|
(46,415
|
)
|
||||||
Recognized net actuarial loss
|
47,834
|
|
|
38,102
|
|
|
31,870
|
|
|
80,875
|
|
|
105,364
|
|
|
70,145
|
|
||||||
Benefit cost
|
$
|
58,099
|
|
|
$
|
54,115
|
|
|
$
|
45,793
|
|
|
$
|
183,559
|
|
|
$
|
252,383
|
|
|
$
|
199,692
|
|
|
|
|
|
Other
|
||||
|
|
Pension
|
|
Postretirement
|
||||
|
|
Benefits
|
|
Benefits
|
||||
Prior Service (credit) recognition
|
|
$
|
(1,630
|
)
|
|
$
|
(31,215
|
)
|
Actuarial loss recognition
|
|
$
|
48,701
|
|
|
$
|
70,379
|
|
|
|
As of December 31,
|
||||||
|
|
2012
|
|
2011
|
||||
Projected benefit obligation
|
|
$
|
953,102
|
|
|
$
|
857,352
|
|
Accumulated benefit obligation
|
|
$
|
895,493
|
|
|
$
|
782,820
|
|
Fair value of plan assets
|
|
$
|
728,161
|
|
|
$
|
582,571
|
|
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
||||||||
|
|
For the Year Ended
|
|
For the Year Ended
|
||||||||
|
|
December 31,
|
|
December 31,
|
||||||||
|
|
2012
|
|
2011
|
|
2012
|
|
2011
|
||||
Discount rate
|
|
4.00
|
%
|
|
4.50
|
%
|
|
4.05
|
%
|
|
4.51
|
%
|
Rate of compensation increase
|
|
3.77
|
%
|
|
3.77
|
%
|
|
—
|
|
|
—
|
|
|
|
Pension Benefits at
|
|
Other Postretirement Benefits at
|
||||||||||||||
|
|
December 31,
|
|
December 31,
|
||||||||||||||
|
|
2012
|
|
2011
|
|
2010
|
|
2012
|
|
2011
|
|
2010
|
||||||
Discount rate
|
|
4.50
|
%
|
|
5.30
|
%
|
|
5.79
|
%
|
|
4.51
|
%
|
|
5.33
|
%
|
|
5.87
|
%
|
Expected long-term return on plan assets
|
|
8.00
|
%
|
|
8.00
|
%
|
|
8.00
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
Rate of compensation increase
|
|
3.82
|
%
|
|
3.66
|
%
|
|
4.14
|
%
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
At December 31,
|
|||||||
|
|
2012
|
|
2011
|
|
2010
|
|||
Health care cost trend rate for next year
|
|
6.30
|
%
|
|
6.85
|
%
|
|
8.47
|
%
|
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
|
|
|
2023
|
|
|
|
1-Percentage
|
|
1-Percentage
|
||||
|
|
Point Increase
|
|
Point Decrease
|
||||
Effect on total of service and interest cost components
|
|
$
|
20,963
|
|
|
$
|
(17,393
|
)
|
Effect on accumulated postretirement benefit obligation
|
|
$
|
388,169
|
|
|
$
|
(323,329
|
)
|
|
|
0.25 Percentage
|
|
0.25 Percentage
|
||||
|
|
Point Increase
|
|
Point Decrease
|
||||
Pension benefit costs (decrease) increase
|
|
$
|
(2,449
|
)
|
|
$
|
2,480
|
|
Other postemployment benefits costs (decrease) increase
|
|
$
|
(4,532
|
)
|
|
$
|
5,292
|
|
|
|
Fair Value Measurements at December 31, 2012
|
|
Fair Value Measurements at December 31, 2011
|
||||||||||||||||||||||||||||
|
|
|
|
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
|
|
$
|
610
|
|
|
$
|
610
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
552
|
|
|
$
|
552
|
|
|
$
|
—
|
|
|
$
|
—
|
|
US Equities (a)
|
|
11
|
|
|
11
|
|
|
—
|
|
|
—
|
|
|
11
|
|
|
11
|
|
|
—
|
|
|
—
|
|
||||||||
MGI Collective Trusts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
US Large Cap Growth Equity (b)
|
|
63,726
|
|
|
—
|
|
|
63,726
|
|
|
—
|
|
|
46,670
|
|
|
—
|
|
|
46,670
|
|
|
—
|
|
||||||||
US Large Cap Value Equity (c)
|
|
64,381
|
|
|
—
|
|
|
64,381
|
|
|
—
|
|
|
48,115
|
|
|
—
|
|
|
48,115
|
|
|
—
|
|
||||||||
US Small/Mid Cap Growth Equity (d)
|
|
26,406
|
|
|
—
|
|
|
26,406
|
|
|
—
|
|
|
20,897
|
|
|
—
|
|
|
20,897
|
|
|
—
|
|
||||||||
US Small/Mid Cap Value Equity (e)
|
|
26,411
|
|
|
—
|
|
|
26,411
|
|
|
—
|
|
|
21,375
|
|
|
—
|
|
|
21,375
|
|
|
—
|
|
||||||||
US Core Fixed Income (f)
|
|
38,045
|
|
|
—
|
|
|
38,045
|
|
|
—
|
|
|
29,881
|
|
|
—
|
|
|
29,881
|
|
|
—
|
|
||||||||
Non-US Core Equity (g)
|
|
146,009
|
|
|
—
|
|
|
146,009
|
|
|
—
|
|
|
139,395
|
|
|
—
|
|
|
139,395
|
|
|
—
|
|
||||||||
Emerging Markets Equity (h)
|
|
33,541
|
|
|
—
|
|
|
33,541
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
US Long Duration Investment Grade Fixed Income (i)
|
|
39,925
|
|
|
—
|
|
|
39,925
|
|
|
—
|
|
|
35,709
|
|
|
—
|
|
|
35,709
|
|
|
—
|
|
||||||||
US Long Duration Fixed Income (j)
|
|
30,675
|
|
|
—
|
|
|
30,675
|
|
|
—
|
|
|
34,434
|
|
|
—
|
|
|
34,434
|
|
|
—
|
|
||||||||
US Large Cap Passive Equity (k)
|
|
81,067
|
|
|
—
|
|
|
81,067
|
|
|
—
|
|
|
71,786
|
|
|
—
|
|
|
71,786
|
|
|
—
|
|
||||||||
US Passive Fixed Income (l)
|
|
20,415
|
|
|
—
|
|
|
20,415
|
|
|
—
|
|
|
16,158
|
|
|
—
|
|
|
16,158
|
|
|
—
|
|
||||||||
US Long Duration Passive Fixed Income (m)
|
|
29,483
|
|
|
—
|
|
|
29,483
|
|
|
—
|
|
|
21,422
|
|
|
—
|
|
|
21,422
|
|
|
—
|
|
||||||||
US Ultra Long Duration Fixed Income (n)
|
|
34,595
|
|
|
—
|
|
|
34,595
|
|
|
—
|
|
|
33,466
|
|
|
—
|
|
|
33,466
|
|
|
—
|
|
||||||||
US Active Long Corporate Investment (o)
|
|
92,861
|
|
|
—
|
|
|
92,861
|
|
|
—
|
|
|
62,700
|
|
|
—
|
|
|
62,700
|
|
|
—
|
|
||||||||
Total
|
|
$
|
728,161
|
|
|
$
|
621
|
|
|
$
|
727,540
|
|
|
$
|
—
|
|
|
$
|
582,571
|
|
|
$
|
563
|
|
|
$
|
582,008
|
|
|
$
|
—
|
|
(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
|
(d)
|
This category invests in small to mid-sized U.S. companies with above average earnings growth and revenue expectations. It targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by Mercer's investment management team. The smaller cap orientation of the strategy requires the investment team to be cognizant of liquidity and capital constraints, which are monitored on an ongoing basis. The strategy is benchmarked to the Russell 2500 Growth Index.
|
(e)
|
This category invests in small to mid-sized U.S. companies that appear to be undervalued relative to their intrinsic value. It targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by Mercer's investment management team. The smaller cap orientation of the strategy requires the investment team to be cognizant of liquidity and capital constraints, which are monitored on an ongoing basis. The strategy is benchmarked to the Russell 2500 Value Index.
|
(f)
|
This category invests primarily in U.S. dollar-denominated investment grade and government securities. It may also invest opportunistically in out-of-benchmark positions including U.S. high yield, non-U.S. bonds, and Treasury Inflation-Protected Securities (TIPs). The strategy seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics, and total portfolio duration is targeted to be within 20% of the benchmark's duration. Total exposure to high yield issues is typically less than 10%, inclusive of direct investment in high yield and exposure through other core fixed income funds. Fund selection and allocations within the portfolio are implemented by Mercer's investment management team. The strategy is benchmarked to the Barclays Capital Aggregate Index.
|
(g)
|
This category invests in all cap companies primarily operating in developed non-US markets, with some exposure to emerging markets. The strategy targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Total exposure to emerging markets is typically 10-15%, inclusive of direct investment in emerging markets and exposure through other non-U.S. equity funds. Fund selection and allocations within the portfolio are implemented by Mercer's investment management team. The strategy is benchmarked to the MSCI EAFE Index.
|
(h)
|
This category invests in companies operating in non-US emerging markets. The strategy targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by Mercer's investment management team. The strategy is benchmarked to the MSCI Emerging Markets Index.
|
(i)
|
This category invests in a passively managed U.S. long duration corporate investment grade portfolio at a 90% weight and a passively managed U.S. Long Treasury portfolio at a 10% weight. It seeks to provide broad exposure to U.S. long duration investment grade credit while allowing for short term liquidity through a strategic allocation to US Treasuries. The strategy is benchmarked 90% to the Barclays Capital U.S. Long Credit Index and 10% to the Barclays Capital Long Treasury.
|
(j)
|
This category invests primarily in U.S. dollar denominated investment grade bonds and government securities with durations between 9 and 11 years. It may also invest opportunistically in out-of-benchmark positions including U.S. high yield, non-U.S. bonds, municipal bonds, and TIPs. The strategy seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by Mercer's investment management team. The strategy is benchmarked to the Barclays Capital U.S. Long Government/Credit Index.
|
(k)
|
This category invests in common stock of U.S. large cap companies. The strategy is benchmarked to the S&P 500 Index.
|
(l)
|
This category invests primarily in U.S. dollar-denominated investment grade bonds and government securities. The strategy and its underlying passive investments are benchmarked to the Barclays Capital Aggregate Index.
|
(m)
|
This category invests primarily in U.S. dollar-denominated investment grade bonds and government securities with durations between 9 and 11 years. The strategy and its underlying passive investments are benchmarked to the Barclays Capital Long Government/Credit Index.
|
(n)
|
This category seeks to reduce the volatility of the plan's funded status and extend the duration of the assets by investing in a series of ultra long duration portfolios with target durations of up to 35 years. Each underlying portfolio is managed by a sub-advisor and consists of five interest rate swaps with sequential target or maturity dates, with the longest dated portfolio maturing in 2045. The interest rate swaps are fully collateralized, resulting in no leverage. The cash collateral is invested by the sub-advisor in an actively managed cash strategy that seeks to provide a return in excess of 3 month LIBOR. The ultra long duration strategy is used in conjunction with liability driven investing solutions, which seek to align the duration of the assets to the plan's liabilities. The Strategy is benchmarked to a Custom Liability Benchmark Portfolio.
|
(o)
|
This category invests in a U.S. long duration corporate investment grade portfolio at a 90% weight and a U.S. long treasury portfolio at a 10% weight. It seeks to provide broad exposure to U.S. long duration investment grade corporate bonds
|
|
|
|
|
Other
|
|||||
|
|
Pension
|
|
Postretirement
|
|||||
|
|
Benefits
|
|
Benefits
|
|||||
2013
|
|
|
$
|
97,746
|
|
|
$
|
185,770
|
|
2014
|
|
|
$
|
54,290
|
|
|
$
|
181,857
|
|
2015
|
|
|
$
|
54,782
|
|
|
$
|
181,896
|
|
2016
|
|
|
$
|
55,220
|
|
|
$
|
184,283
|
|
2017
|
|
|
$
|
54,226
|
|
|
$
|
183,626
|
|
Year 2018-2022
|
|
|
$
|
282,331
|
|
|
$
|
890,936
|
|
|
|
CWP
|
|
Workers' Compensation
|
||||||||||||
|
|
at December 31,
|
|
at December 31,
|
||||||||||||
|
|
2012
|
|
2011
|
|
2012
|
|
2011
|
||||||||
Change in benefit obligation:
|
|
|
|
|
|
|
|
|
||||||||
Benefit obligation at beginning of period
|
|
$
|
183,580
|
|
|
$
|
184,531
|
|
|
$
|
174,069
|
|
|
$
|
174,456
|
|
State administrative fees and insurance bond premiums
|
|
—
|
|
|
—
|
|
|
6,727
|
|
|
7,035
|
|
||||
Service, legal and administrative cost
|
|
7,711
|
|
|
7,620
|
|
|
17,126
|
|
|
20,015
|
|
||||
Interest cost
|
|
7,964
|
|
|
9,330
|
|
|
7,113
|
|
|
8,238
|
|
||||
Actuarial (gain) loss
|
|
(3,919
|
)
|
|
(6,783
|
)
|
|
6,754
|
|
|
(2,783
|
)
|
||||
Benefits paid
|
|
(11,257
|
)
|
|
(11,118
|
)
|
|
(32,200
|
)
|
|
(32,892
|
)
|
||||
Benefit obligation at end of period
|
|
$
|
184,079
|
|
|
$
|
183,580
|
|
|
$
|
179,589
|
|
|
$
|
174,069
|
|
|
|
|
|
|
|
|
|
|
||||||||
Current liabilities
|
|
$
|
(9,298
|
)
|
|
$
|
(10,027
|
)
|
|
$
|
(23,941
|
)
|
|
$
|
(24,837
|
)
|
Noncurrent liabilities
|
|
(174,781
|
)
|
|
(173,553
|
)
|
|
(155,648
|
)
|
|
(149,232
|
)
|
||||
Net obligation recognized
|
|
$
|
(184,079
|
)
|
|
$
|
(183,580
|
)
|
|
$
|
(179,589
|
)
|
|
$
|
(174,069
|
)
|
|
|
|
|
|
|
|
|
|
||||||||
Amounts recognized in accumulated other comprehensive income consist of:
|
|
|
|
|
|
|
|
|
||||||||
Net actuarial gain
|
|
$
|
(148,955
|
)
|
|
$
|
(164,374
|
)
|
|
$
|
(44,535
|
)
|
|
$
|
(55,233
|
)
|
Prior service credit
|
|
—
|
|
|
(395
|
)
|
|
—
|
|
|
—
|
|
||||
Net amount recognized (before tax effect)
|
|
$
|
(148,955
|
)
|
|
$
|
(164,769
|
)
|
|
$
|
(44,535
|
)
|
|
$
|
(55,233
|
)
|
|
CWP
|
|
Workers’ Compensation
|
||||||||||||||||||||
|
For the Years Ended
|
|
For the Years Ended
|
||||||||||||||||||||
|
December 31,
|
|
December 31,
|
||||||||||||||||||||
|
2012
|
|
2011
|
|
2010
|
|
2012
|
|
2011
|
|
2010
|
||||||||||||
Service cost
|
$
|
7,711
|
|
|
$
|
4,620
|
|
|
$
|
5,067
|
|
|
$
|
14,536
|
|
|
$
|
17,872
|
|
|
$
|
27,015
|
|
Interest cost
|
7,964
|
|
|
9,330
|
|
|
10,789
|
|
|
7,113
|
|
|
8,238
|
|
|
9,156
|
|
||||||
Legal and administrative costs
|
—
|
|
|
3,000
|
|
|
3,000
|
|
|
2,590
|
|
|
2,143
|
|
|
3,384
|
|
||||||
Amortization of prior service cost
|
(395
|
)
|
|
(728
|
)
|
|
(728
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Recognized net actuarial gain
|
(19,338
|
)
|
|
(21,182
|
)
|
|
(21,585
|
)
|
|
(3,944
|
)
|
|
(3,907
|
)
|
|
(3,072
|
)
|
||||||
State administrative fees and insurance bond premiums
|
—
|
|
|
—
|
|
|
—
|
|
|
6,727
|
|
|
7,035
|
|
|
7,816
|
|
||||||
Net periodic cost (credit)
|
$
|
(4,058
|
)
|
|
$
|
(4,960
|
)
|
|
$
|
(3,457
|
)
|
|
$
|
27,022
|
|
|
$
|
31,381
|
|
|
$
|
44,299
|
|
|
|
|
|
Workers'
|
||||
|
|
CWP
|
|
Compensation
|
||||
|
|
Benefits
|
|
Benefits
|
||||
Prior Service benefit recognition
|
|
$
|
—
|
|
|
$
|
—
|
|
Actuarial gain recognition
|
|
$
|
(16,850
|
)
|
|
$
|
(2,797
|
)
|
|
|
CWP
|
|
Workers' Compensation
|
||||||||||||||
|
|
For the Years Ended
|
|
For the Years Ended
|
||||||||||||||
|
|
December 31,
|
|
December 31,
|
||||||||||||||
|
|
2012
|
|
|
2011
|
|
|
2010
|
|
|
2012
|
|
|
2011
|
|
|
2010
|
|
Benefit obligations
|
|
4.03
|
%
|
|
4.46
|
%
|
|
5.21
|
%
|
|
3.95
|
%
|
|
4.40
|
%
|
|
5.13
|
%
|
Net Periodic (benefit) costs
|
|
4.46
|
%
|
|
5.21
|
%
|
|
5.84
|
%
|
|
4.40
|
%
|
|
5.13
|
%
|
|
5.55
|
%
|
|
|
0.25 Percentage
|
|
0.25 Percentage
|
||||
|
|
Point Increase
|
|
Point Decrease
|
||||
CWP benefit increase (decrease)
|
|
$
|
1,067
|
|
|
$
|
(948
|
)
|
Workers' Compensation costs (decrease) increase
|
|
$
|
(424
|
)
|
|
$
|
444
|
|
|
|
|
|
Workers' Compensation
|
|||||||||||||
|
|
CWP
|
|
Total
|
|
Actuarial
|
|
Other
|
|||||||||
|
|
Benefits
|
|
Benefits
|
|
Benefits
|
|
Benefits
|
|||||||||
2013
|
|
|
$
|
9,298
|
|
|
$
|
30,501
|
|
|
$
|
23,941
|
|
|
$
|
6,560
|
|
2014
|
|
|
$
|
9,596
|
|
|
$
|
30,144
|
|
|
$
|
23,420
|
|
|
$
|
6,724
|
|
2015
|
|
|
$
|
9,824
|
|
|
$
|
29,407
|
|
|
$
|
22,515
|
|
|
$
|
6,892
|
|
2016
|
|
|
$
|
9,996
|
|
|
$
|
28,657
|
|
|
$
|
21,593
|
|
|
$
|
7,064
|
|
2017
|
|
|
$
|
10,126
|
|
|
$
|
27,874
|
|
|
$
|
20,633
|
|
|
$
|
7,241
|
|
Year 2018-2022
|
|
|
$
|
51,147
|
|
|
$
|
128,704
|
|
|
$
|
89,691
|
|
|
$
|
39,013
|
|
|
|
For the Years Ended
|
||||||||||
|
|
December 31,
|
||||||||||
|
|
2012
|
|
2011
|
|
2010
|
||||||
Benefit Costs
|
|
$
|
6,122
|
|
|
$
|
6,439
|
|
|
$
|
3,294
|
|
Discount rate assumption used to determine net periodic benefit costs
|
|
3.62
|
%
|
|
4.04
|
%
|
|
4.72
|
%
|
|
|
December 31,
|
||||||||||
|
|
2012
|
|
2011
|
|
2010
|
||||||
Weighted average fair value of grants
|
|
$
|
14.58
|
|
|
$
|
20.47
|
|
|
$
|
21.97
|
|
Risk-free interest rate
|
|
0.73
|
%
|
|
1.61
|
%
|
|
1.88
|
%
|
|||
Expected dividend yield
|
|
1.18
|
%
|
|
0.82
|
%
|
|
0.80
|
%
|
|||
Expected forfeiture rate
|
|
2.00
|
%
|
|
2.00
|
%
|
|
2.00
|
%
|
|||
Expected volatility
|
|
54.80
|
%
|
|
55.10
|
%
|
|
59.00
|
%
|
|||
Expected term in years
|
|
4.40
|
|
|
4.26
|
|
|
4.04
|
|
|
|
|
|
|
|
Weighted
|
|
|
||||||
|
|
|
|
|
|
Average
|
|
|
||||||
|
|
|
|
Weighted
|
|
Remaining
|
|
Aggregate
|
||||||
|
|
|
|
Average
|
|
Contractual
|
|
Intrinsic
|
||||||
|
|
|
|
Exercise
|
|
Term (in
|
|
Value (in
|
||||||
|
|
Shares
|
|
Price
|
|
years)
|
|
thousands)
|
||||||
Balance at December 31, 2011
|
|
5,335,510
|
|
|
$
|
32.79
|
|
|
|
|
|
|||
Granted
|
|
583,996
|
|
|
$
|
36.02
|
|
|
|
|
|
|||
Exercised
|
|
(787,502
|
)
|
|
$
|
10.65
|
|
|
|
|
|
|||
Forfeited
|
|
(20,790
|
)
|
|
$
|
40.08
|
|
|
|
|
|
|||
Balance at December 31, 2012
|
|
5,111,214
|
|
|
$
|
36.54
|
|
|
4.94
|
|
|
$
|
43,623
|
|
Vested and expected to vest
|
|
5,099,783
|
|
|
$
|
36.54
|
|
|
4.93
|
|
|
$
|
43,578
|
|
Exercisable at December 31, 2012
|
|
4,079,537
|
|
|
$
|
35.25
|
|
|
4.02
|
|
|
$
|
33,732
|
|
|
|
Number of
|
|
Weighted Average
|
|
|
|
Shares
|
|
Grant Date Fair Value
|
|
Nonvested at December 31, 2011
|
|
1,220,353
|
|
|
$42.83
|
Granted
|
|
735,678
|
|
|
$35.92
|
Vested
|
|
(577,857
|
)
|
|
$39.97
|
Forfeited
|
|
(51,221
|
)
|
|
$39.10
|
Nonvested at December 31, 2012
|
|
1,326,953
|
|
|
$40.39
|
|
|
Number of
|
|
Weighted Average
|
|
|
|
Shares
|
|
Grant Date Fair Value
|
|
Nonvested at December 31, 2011
|
|
509,004
|
|
|
$51.40
|
Granted
|
|
422,920
|
|
|
$39.71
|
Vested
|
|
(229,730
|
)
|
|
$31.83
|
Nonvested at December 31, 2012
|
|
702,194
|
|
|
$50.76
|
|
|
Number of
|
|
Weighted Average
|
|
|
|
Shares
|
|
Grant Date Fair Value
|
|
Nonvested at December 31, 2011
|
|
602,107
|
|
|
$16.44
|
Vested
|
|
(401,394
|
)
|
|
$16.44
|
Nonvested at December 31, 2012
|
|
200,713
|
|
|
$16.44
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2012
|
|
2011
|
|
2010
|
||||||
Interest (Net of Amounts Capitalized)
|
|
$
|
212,364
|
|
|
$
|
242,587
|
|
|
$
|
138,762
|
|
Income Taxes
|
|
$
|
121,245
|
|
|
$
|
144,405
|
|
|
$
|
118,550
|
|
|
|
December 31,
|
||||||
|
|
2012
|
|
2011
|
||||
Thermal coal utilities
|
|
$
|
247,955
|
|
|
$
|
210,164
|
|
Steel and coke producers
|
|
47,203
|
|
|
93,303
|
|
||
Coal brokers and distributors
|
|
65,057
|
|
|
38,033
|
|
||
Gas wholesalers
|
|
51,718
|
|
|
63,299
|
|
||
Various other
|
|
16,395
|
|
|
58,013
|
|
||
Total Accounts Receivable Trade (including Accounts Receivable—Securitized)
|
|
$
|
428,328
|
|
|
$
|
462,812
|
|
|
Fair Value Measurements at December 31, 2012
|
|
Fair Value Measurements at December 31, 2011
|
||||||||||||||||||||
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 22)
|
$
|
—
|
|
|
$
|
128,945
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
251,277
|
|
|
$
|
—
|
|
|
December 31, 2012
|
|
December 31, 2011
|
||||||||||||
|
Carrying
Amount
|
|
Fair
Value
|
|
Carrying
Amount
|
|
Fair
Value
|
||||||||
Cash and cash equivalents
|
$
|
21,878
|
|
|
$
|
21,878
|
|
|
$
|
375,736
|
|
|
$
|
375,736
|
|
Restricted cash (a)
|
$
|
68,673
|
|
|
$
|
68,673
|
|
|
$
|
22,148
|
|
|
$
|
22,148
|
|
Borrowings under securitization facility
|
$
|
37,846
|
|
|
$
|
37,846
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Long-term debt
|
$
|
(3,129,017
|
)
|
|
$
|
(3,378,058
|
)
|
|
$
|
(3,133,993
|
)
|
|
$
|
(3,442,452
|
)
|
|
|
|
Year Ended December 31,
|
||||||||
|
2012
|
2011
|
2010
|
||||||||
Natural Gas Price Swaps
|
|
|
|
||||||||
Beginning Balance – Accumulated OCI
|
$
|
151,780
|
|
$
|
46,087
|
|
$
|
71,378
|
|
||
Gain recognized in Accumulated OCI
|
$
|
114,240
|
|
$
|
200,700
|
|
$
|
140,985
|
|
||
Gain reclassified from Accumulated OCI into Outside Sales
|
$
|
189,259
|
|
$
|
95,007
|
|
$
|
166,276
|
|
||
Ending Balance – Accumulated OCI
|
$
|
76,761
|
|
$
|
151,780
|
|
$
|
46,087
|
|
||
Gain recognized in Outside Sales for ineffectiveness
|
$
|
579
|
|
$
|
1,034
|
|
$
|
31
|
|
|
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
|
$
|
193,031
|
|
|
$
|
120,729
|
|
|
$
|
72,302
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Environmental
|
56,293
|
|
|
23,075
|
|
|
33,218
|
|
|
—
|
|
|
—
|
|
|||||
Other
|
83,398
|
|
|
45,752
|
|
|
37,646
|
|
|
—
|
|
|
—
|
|
|||||
Total Letters of Credit
|
332,722
|
|
|
189,556
|
|
|
143,166
|
|
|
—
|
|
|
—
|
|
|||||
Surety Bonds:
|
|
|
|
|
|
|
|
|
|
||||||||||
Employee-Related
|
204,884
|
|
|
204,884
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Environmental
|
525,913
|
|
|
502,359
|
|
|
23,554
|
|
|
—
|
|
|
—
|
|
|||||
Other
|
29,342
|
|
|
29,331
|
|
|
10
|
|
|
—
|
|
|
1
|
|
|||||
Total Surety Bonds
|
760,139
|
|
|
736,574
|
|
|
23,564
|
|
|
—
|
|
|
1
|
|
|||||
Total Commitments
|
$
|
1,092,861
|
|
|
$
|
926,130
|
|
|
$
|
166,730
|
|
|
$
|
—
|
|
|
$
|
1
|
|
Obligations Due
|
Amount
|
||
Less than 1 year
|
$
|
269,461
|
|
1 - 3 years
|
321,265
|
|
|
3 - 5 years
|
130,919
|
|
|
More than 5 years
|
435,384
|
|
|
Total Purchase Obligations
|
$
|
1,157,029
|
|
|
|
|
|
||||||||
|
For The Years Ended December 31,
|
||||||||||
|
2012
|
|
2011
|
|
2010
|
||||||
Gas drilling obligations
|
$
|
110,975
|
|
|
$
|
108,167
|
|
|
$
|
28,641
|
|
Firm transportation expense
|
78,475
|
|
|
59,606
|
|
|
40,274
|
|
|||
Major equipment purchases
|
203,522
|
|
|
43,698
|
|
|
56,723
|
|
|||
Other
|
492
|
|
|
891
|
|
|
497
|
|
|||
Total costs related to purchase obligations
|
$
|
393,464
|
|
|
$
|
212,362
|
|
|
$
|
126,135
|
|
|
Thermal
|
|
Low Volatile
Metallurgical
|
|
High Volatile
Metallurgical
|
|
Other
Coal
|
|
Total Coal
|
|
Coalbed
Methane
|
|
Marcellus
Shale
|
|
Shallow Oil and Gas
|
|
Other
Gas
|
|
Total
Gas
|
|
All
Other
|
|
Corporate,
Adjustments
&
Eliminations
|
|
Consolidated
|
|
||||||||||||||||||||||||||
Sales—outside
|
$
|
3,046,448
|
|
|
$
|
505,670
|
|
|
$
|
228,859
|
|
|
$
|
25,291
|
|
|
$
|
3,806,268
|
|
|
$
|
379,595
|
|
|
$
|
134,080
|
|
|
$
|
135,412
|
|
|
$
|
9,733
|
|
|
$
|
658,820
|
|
|
$
|
360,858
|
|
|
$
|
—
|
|
|
$
|
4,825,946
|
|
(A)
|
Sales—purchased gas
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,316
|
|
|
3,316
|
|
|
—
|
|
|
—
|
|
|
3,316
|
|
|
|||||||||||||
Sales—gas royalty interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
49,405
|
|
|
49,405
|
|
|
—
|
|
|
—
|
|
|
49,405
|
|
|
|||||||||||||
Freight—outside
|
—
|
|
|
—
|
|
|
—
|
|
|
141,936
|
|
|
141,936
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
141,936
|
|
|
|||||||||||||
Intersegment transfers
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,622
|
|
|
1,622
|
|
|
142,014
|
|
|
(143,636
|
)
|
|
—
|
|
|
|||||||||||||
Total Sales and Freight
|
$
|
3,046,448
|
|
|
$
|
505,670
|
|
|
$
|
228,859
|
|
|
$
|
167,227
|
|
|
$
|
3,948,204
|
|
|
$
|
379,595
|
|
|
$
|
134,080
|
|
|
$
|
135,412
|
|
|
$
|
64,076
|
|
|
$
|
713,163
|
|
|
$
|
502,872
|
|
|
$
|
(143,636
|
)
|
|
$
|
5,020,603
|
|
|
Earnings (Loss) Before Income Taxes
|
$
|
557,480
|
|
|
$
|
210,133
|
|
|
$
|
59,730
|
|
|
$
|
(171,524
|
)
|
|
$
|
655,819
|
|
|
$
|
125,978
|
|
|
$
|
29,546
|
|
|
$
|
(13,388
|
)
|
|
$
|
(102,685
|
)
|
|
$
|
39,451
|
|
|
$
|
37,410
|
|
|
$
|
(235,406
|
)
|
|
$
|
497,274
|
|
(B)
|
Segment assets
|
|
|
|
|
|
|
|
|
$
|
5,884,620
|
|
|
|
|
|
|
|
|
|
|
$
|
5,768,882
|
|
|
$
|
363,675
|
|
|
$
|
653,732
|
|
|
$
|
12,670,909
|
|
(C)
|
||||||||||||||||
Depreciation, depletion and amortization
|
|
|
|
|
|
|
|
|
$
|
396,311
|
|
|
|
|
|
|
|
|
|
|
$
|
202,956
|
|
|
$
|
23,513
|
|
|
$
|
—
|
|
|
$
|
622,780
|
|
|
||||||||||||||||
Capital expenditures
|
|
|
|
|
|
|
|
|
$
|
992,621
|
|
|
|
|
|
|
|
|
|
|
$
|
532,636
|
|
|
$
|
49,973
|
|
|
$
|
—
|
|
|
$
|
1,575,230
|
|
|
(A)
|
Included in the Coal segment are sales of $
546,982
to First Energy and $
465,886
to Xcoal Energy & Resources each comprising over 10% of sales.
|
(B)
|
Includes equity in earnings of unconsolidated affiliates of
$7,355
,
$9,562
and
$10,131
for Coal, Gas and All Other, respectively.
|
(C)
|
Includes investments in unconsolidated equity affiliates of
$19,517
,
$143,876
and
$59,437
for Coal, Gas and All Other, respectively.
|
|
Thermal
|
|
Low Volatile
Metallurgical
|
|
High Volatile
Metallurgical
|
|
Other
Coal
|
|
Total Coal
|
|
Coalbed
Methane
|
|
Marcellus
Shale
|
|
Shallow Oil and Gas
|
|
Other
Gas
|
|
Total
Gas
|
|
All
Other
|
|
Corporate,
Adjustments
&
Eliminations
|
|
Consolidated
|
|
||||||||||||||||||||||||||
Sales—outside
|
$
|
3,058,193
|
|
|
$
|
1,071,570
|
|
|
$
|
368,221
|
|
|
$
|
68,864
|
|
|
$
|
4,566,848
|
|
|
$
|
462,677
|
|
|
$
|
118,973
|
|
|
$
|
155,444
|
|
|
$
|
11,370
|
|
|
$
|
748,464
|
|
|
$
|
345,501
|
|
|
$
|
—
|
|
|
$
|
5,660,813
|
|
(D)
|
Sales—purchased gas
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,344
|
|
|
4,344
|
|
|
—
|
|
|
—
|
|
|
4,344
|
|
|
|||||||||||||
Sales—gas royalty interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
66,929
|
|
|
66,929
|
|
|
—
|
|
|
—
|
|
|
66,929
|
|
|
|||||||||||||
Freight—outside
|
—
|
|
|
—
|
|
|
—
|
|
|
231,536
|
|
|
231,536
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
231,536
|
|
|
|||||||||||||
Intersegment transfers
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,303
|
|
|
3,303
|
|
|
194,857
|
|
|
(198,160
|
)
|
|
—
|
|
|
|||||||||||||
Total Sales and Freight
|
$
|
3,058,193
|
|
|
$
|
1,071,570
|
|
|
$
|
368,221
|
|
|
$
|
300,400
|
|
|
$
|
4,798,384
|
|
|
$
|
462,677
|
|
|
$
|
118,973
|
|
|
$
|
155,444
|
|
|
$
|
85,946
|
|
|
$
|
823,040
|
|
|
$
|
540,358
|
|
|
$
|
(198,160
|
)
|
|
$
|
5,963,622
|
|
|
Earnings (Loss) Before Income Taxes
|
$
|
524,340
|
|
|
$
|
692,249
|
|
|
$
|
142,095
|
|
|
$
|
(425,535
|
)
|
|
$
|
933,149
|
|
|
$
|
185,761
|
|
|
$
|
41,566
|
|
|
$
|
(14,732
|
)
|
|
$
|
(82,811
|
)
|
|
$
|
129,784
|
|
|
$
|
17,983
|
|
|
$
|
(292,963
|
)
|
|
$
|
787,953
|
|
(E)
|
Segment assets
|
|
|
|
|
|
|
|
|
$
|
5,253,226
|
|
|
|
|
|
|
|
|
|
|
$
|
6,183,582
|
|
|
$
|
351,370
|
|
|
$
|
737,522
|
|
|
$
|
12,525,700
|
|
(F)
|
||||||||||||||||
Depreciation, depletion and amortization
|
|
|
|
|
|
|
|
|
$
|
392,765
|
|
|
|
|
|
|
|
|
|
|
$
|
206,821
|
|
|
$
|
18,811
|
|
|
$
|
—
|
|
|
$
|
618,397
|
|
|
||||||||||||||||
Capital expenditures
|
|
|
|
|
|
|
|
|
$
|
676,587
|
|
|
|
|
|
|
|
|
|
|
$
|
664,612
|
|
|
$
|
41,172
|
|
|
$
|
—
|
|
|
$
|
1,382,371
|
|
|
(D)
|
Included in the Coal segment are sales of $
662,109
to Xcoal Energy & Resources comprising over 10% of sales.
|
(E)
|
Includes equity in earnings of unconsolidated affiliates of
$15,803
,
$4,231
and
$4,629
for Coal, Gas and All Other, respectively.
|
(F)
|
Includes investments in unconsolidated equity affiliates of
$34,316
,
$96,914
and
$50,806
for Coal, Gas and All Other, respectively.
|
|
Thermal
|
|
Low Volatile
Metallurgical
|
|
High Volatile
Metallurgical
|
|
Other
Coal
|
|
Total Coal
|
|
Coalbed
Methane
|
|
Marcellus
Shale
|
|
Shallow Oil and Gas
|
|
Other
Gas
|
|
Total
Gas
|
|
All
Other
|
|
Corporate,
Adjustments
&
Eliminations
|
|
Consolidated
|
|
||||||||||||||||||||||||||
Sales—outside
|
$
|
3,001,352
|
|
|
$
|
680,212
|
|
|
$
|
172,087
|
|
|
$
|
45,738
|
|
|
$
|
3,899,389
|
|
|
$
|
569,367
|
|
|
$
|
48,769
|
|
|
$
|
116,679
|
|
|
$
|
7,741
|
|
|
$
|
742,556
|
|
|
$
|
296,758
|
|
|
$
|
—
|
|
|
$
|
4,938,703
|
|
(G)
|
Sales—purchased gas
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
11,227
|
|
|
11,227
|
|
|
—
|
|
|
—
|
|
|
11,227
|
|
|
|||||||||||||
Sales—gas royalty interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
62,869
|
|
|
62,869
|
|
|
—
|
|
|
—
|
|
|
62,869
|
|
|
|||||||||||||
Freight—outside
|
—
|
|
|
—
|
|
|
—
|
|
|
125,715
|
|
|
125,715
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
125,715
|
|
|
|||||||||||||
Intersegment transfers
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,253
|
|
|
3,253
|
|
|
175,906
|
|
|
(179,159
|
)
|
|
—
|
|
|
|||||||||||||
Total Sales and Freight
|
$
|
3,001,352
|
|
|
$
|
680,212
|
|
|
$
|
172,087
|
|
|
$
|
171,453
|
|
|
$
|
4,025,104
|
|
|
$
|
569,367
|
|
|
$
|
48,769
|
|
|
$
|
116,679
|
|
|
$
|
85,090
|
|
|
$
|
819,905
|
|
|
$
|
472,664
|
|
|
$
|
(179,159
|
)
|
|
$
|
5,138,514
|
|
|
Earnings (Loss) Before Income Taxes
|
$
|
516,373
|
|
|
$
|
389,427
|
|
|
$
|
88,565
|
|
|
$
|
(457,871
|
)
|
|
$
|
536,494
|
|
|
$
|
280,528
|
|
|
$
|
9,684
|
|
|
$
|
4,744
|
|
|
$
|
(115,078
|
)
|
|
$
|
179,878
|
|
|
$
|
22,156
|
|
|
$
|
(270,615
|
)
|
|
$
|
467,913
|
|
(H)
|
Segment assets
|
|
|
|
|
|
|
|
|
$
|
5,056,583
|
|
|
|
|
|
|
|
|
|
|
$
|
5,916,093
|
|
|
$
|
337,855
|
|
|
$
|
760,079
|
|
|
$
|
12,070,610
|
|
(I)
|
||||||||||||||||
Depreciation, depletion and amortization
|
|
|
|
|
|
|
|
|
$
|
359,497
|
|
|
|
|
|
|
|
|
|
|
$
|
190,424
|
|
|
$
|
17,742
|
|
|
$
|
—
|
|
|
$
|
567,663
|
|
|
||||||||||||||||
Capital expenditures
|
|
|
|
|
|
|
|
|
$
|
707,473
|
|
|
|
|
|
|
|
|
|
|
$
|
3,891,640
|
|
|
$
|
25,123
|
|
|
$
|
—
|
|
|
$
|
4,624,236
|
|
(J)
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2012
|
|
2011
|
|
2010
|
||||||
Total segment sales and freight from external customers
|
|
$
|
5,020,603
|
|
|
$
|
5,963,622
|
|
|
$
|
5,138,514
|
|
Other income not allocated to segments (Note 3)
|
|
409,704
|
|
|
153,620
|
|
|
97,507
|
|
|||
Total Consolidated Revenue and Other Income
|
|
$
|
5,430,307
|
|
|
$
|
6,117,242
|
|
|
$
|
5,236,021
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2012
|
|
2011
|
|
2010
|
||||||
Segment Earnings Before Income Taxes for total reportable business segments
|
|
$
|
695,270
|
|
|
$
|
1,062,933
|
|
|
$
|
716,372
|
|
Segment Earnings Before Income Taxes for all other businesses
|
|
37,410
|
|
|
17,983
|
|
|
22,156
|
|
|||
Interest income (expense), net and other non-operating activity (K)
|
|
(228,822
|
)
|
|
(258,308
|
)
|
|
(208,893
|
)
|
|||
Transaction and Financing Fees (K)
|
|
—
|
|
|
(14,907
|
)
|
|
(62,033
|
)
|
|||
Evaluation fees for non-core asset dispositions (K)
|
|
(6,584
|
)
|
|
(5,780
|
)
|
|
(2,688
|
)
|
|||
Loss on debt extinguishment
|
|
—
|
|
|
(16,090
|
)
|
|
—
|
|
|||
Lease Settlement
|
|
—
|
|
|
2,122
|
|
|
2,999
|
|
|||
Earnings Before Income Taxes
|
|
$
|
497,274
|
|
|
$
|
787,953
|
|
|
$
|
467,913
|
|
Total Assets:
|
|
December 31,
|
||||||||||
|
2012
|
|
2011
|
|
2010
|
|||||||
Segment assets for total reportable business segments
|
|
$
|
11,653,502
|
|
|
$
|
11,436,808
|
|
|
$
|
10,972,676
|
|
Segment assets for all other businesses
|
|
363,675
|
|
|
351,370
|
|
|
337,855
|
|
|||
Items excluded from segment assets:
|
|
|
|
|
|
|
||||||
Cash and other investments (K)
|
|
19,268
|
|
|
39,655
|
|
|
16,836
|
|
|||
Recoverable income taxes
|
|
—
|
|
|
—
|
|
|
32,528
|
|
|||
Deferred tax assets
|
|
592,689
|
|
|
648,807
|
|
|
659,017
|
|
|||
Bond issuance costs
|
|
41,775
|
|
|
49,060
|
|
|
51,698
|
|
|||
Total Consolidated Assets
|
|
$
|
12,670,909
|
|
|
$
|
12,525,700
|
|
|
$
|
12,070,610
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2012
|
|
2011
|
|
2010
|
||||||
United States (M)
|
|
$
|
4,514,040
|
|
|
$
|
5,070,593
|
|
|
$
|
4,684,358
|
|
Europe
|
|
263,878
|
|
|
455,782
|
|
|
208,762
|
|
|||
South America
|
|
186,192
|
|
|
410,634
|
|
|
233,466
|
|
|||
Canada
|
|
15,094
|
|
|
26,613
|
|
|
3,251
|
|
|||
Other
|
|
41,399
|
|
|
—
|
|
|
8,677
|
|
|||
Total Revenues and Freight from External Customers (M)
|
|
$
|
5,020,603
|
|
|
$
|
5,963,622
|
|
|
$
|
5,138,514
|
|
|
|
December 31,
|
||||||||||
|
|
2012
|
|
2011
|
|
2010
|
||||||
United States
|
|
$
|
10,170,523
|
|
|
$
|
9,294,046
|
|
|
$
|
10,095,851
|
|
Canada
|
|
20,444
|
|
|
32,370
|
|
|
33,400
|
|
|||
Total Property, Plant and Equipment, net
|
|
$
|
10,190,967
|
|
|
$
|
9,326,416
|
|
|
$
|
10,129,251
|
|
|
Parent
Issuer
|
|
CNX Gas
Guarantor
|
|
Other
Subsidiary
Guarantors
|
|
Non-
Guarantors
|
|
Elimination
|
|
Consolidated
|
||||||||||||
Sales—Outside
|
$
|
—
|
|
|
$
|
660,442
|
|
|
$
|
3,924,817
|
|
|
$
|
243,059
|
|
|
$
|
(2,372
|
)
|
|
$
|
4,825,946
|
|
Sales—Gas Royalty Interests
|
—
|
|
|
49,405
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
49,405
|
|
||||||
Sales—Purchased Gas
|
—
|
|
|
3,316
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,316
|
|
||||||
Freight—Outside
|
—
|
|
|
—
|
|
|
141,936
|
|
|
—
|
|
|
—
|
|
|
141,936
|
|
||||||
Other Income
|
652,054
|
|
|
56,946
|
|
|
331,120
|
|
|
21,639
|
|
|
(652,055
|
)
|
|
409,704
|
|
||||||
Total Revenue and Other Income
|
652,054
|
|
|
770,109
|
|
|
4,397,873
|
|
|
264,698
|
|
|
(654,427
|
)
|
|
5,430,307
|
|
||||||
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)
|
127,372
|
|
|
407,045
|
|
|
2,617,613
|
|
|
239,502
|
|
|
30,421
|
|
|
3,421,953
|
|
||||||
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
|
—
|
|
|
—
|
|
|
141,936
|
|
|
—
|
|
|
—
|
|
|
141,936
|
|
||||||
Selling, General and Administrative Expenses
|
—
|
|
|
40,101
|
|
|
106,553
|
|
|
1,417
|
|
|
—
|
|
|
148,071
|
|
||||||
Depreciation, Depletion and Amortization
|
12,172
|
|
|
202,956
|
|
|
405,588
|
|
|
2,064
|
|
|
—
|
|
|
622,780
|
|
||||||
Interest Expense
|
208,894
|
|
|
5,098
|
|
|
6,488
|
|
|
44
|
|
|
(464
|
)
|
|
220,060
|
|
||||||
Taxes Other Than Income
|
401
|
|
|
33,892
|
|
|
299,517
|
|
|
2,845
|
|
|
—
|
|
|
336,655
|
|
||||||
Total Costs
|
361,704
|
|
|
730,725
|
|
|
3,555,229
|
|
|
247,686
|
|
|
37,689
|
|
|
4,933,033
|
|
||||||
Earnings (Loss) Before Income Taxes
|
290,350
|
|
|
39,384
|
|
|
842,644
|
|
|
17,012
|
|
|
(692,116
|
)
|
|
497,274
|
|
||||||
Income Tax Expense (Benefit)
|
(98,120
|
)
|
|
15,021
|
|
|
186,459
|
|
|
5,841
|
|
|
—
|
|
|
109,201
|
|
||||||
Net Income (Loss)
|
388,470
|
|
|
24,363
|
|
|
656,185
|
|
|
11,171
|
|
|
(692,116
|
)
|
|
388,073
|
|
||||||
Less: Net Loss Attributable to Noncontrolling Interest
|
—
|
|
|
397
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
397
|
|
||||||
Net Income (Loss) Attributable to CONSOL Energy Inc. Shareholders
|
$
|
388,470
|
|
|
$
|
24,760
|
|
|
$
|
656,185
|
|
|
$
|
11,171
|
|
|
$
|
(692,116
|
)
|
|
$
|
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
|
|
|
$
|
175
|
|
|
$
|
860
|
|
|
$
|
—
|
|
|
$
|
21,878
|
|
Accounts and Notes Receivable:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Trade
|
—
|
|
|
58,126
|
|
|
—
|
|
|
370,202
|
|
|
—
|
|
|
428,328
|
|
||||||
Notes Receivable
|
154
|
|
|
315,730
|
|
|
2,503
|
|
|
—
|
|
|
—
|
|
|
318,387
|
|
||||||
Other Receivables
|
6,335
|
|
|
214,748
|
|
|
33,289
|
|
|
5,159
|
|
|
(128,400
|
)
|
|
131,131
|
|
||||||
Accounts Receivable—Securitized
|
—
|
|
|
—
|
|
|
—
|
|
|
37,846
|
|
|
—
|
|
|
37,846
|
|
||||||
Inventories
|
—
|
|
|
14,133
|
|
|
198,269
|
|
|
35,364
|
|
|
—
|
|
|
247,766
|
|
||||||
Deferred Income Taxes
|
174,176
|
|
|
(26,072
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
148,104
|
|
||||||
Restricted Cash
|
—
|
|
|
—
|
|
|
48,294
|
|
|
—
|
|
|
—
|
|
|
48,294
|
|
||||||
Prepaid Expenses
|
29,589
|
|
|
86,186
|
|
|
40,215
|
|
|
1,370
|
|
|
—
|
|
|
157,360
|
|
||||||
Total Current Assets
|
227,745
|
|
|
666,203
|
|
|
322,745
|
|
|
450,801
|
|
|
(128,400
|
)
|
|
1,539,094
|
|
||||||
Property, Plant and Equipment:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Property, Plant and Equipment
|
216,448
|
|
|
5,956,207
|
|
|
9,347,370
|
|
|
25,179
|
|
|
—
|
|
|
15,545,204
|
|
||||||
Less-Accumulated Depreciation, Depletion and Amortization
|
126,048
|
|
|
960,613
|
|
|
4,249,507
|
|
|
18,069
|
|
|
—
|
|
|
5,354,237
|
|
||||||
Total Property, Plant and Equipment-Net
|
90,400
|
|
|
4,995,594
|
|
|
5,097,863
|
|
|
7,110
|
|
|
—
|
|
|
10,190,967
|
|
||||||
Other Assets:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Deferred Income Taxes
|
884,310
|
|
|
(439,725
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
444,585
|
|
||||||
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
|
|
|
32,016
|
|
|
10,188
|
|
|
—
|
|
|
227,077
|
|
||||||
Total Other Assets
|
10,920,537
|
|
|
(229,914
|
)
|
|
847,191
|
|
|
10,188
|
|
|
(10,607,154
|
)
|
|
940,848
|
|
||||||
Total Assets
|
$
|
11,238,682
|
|
|
$
|
5,431,883
|
|
|
$
|
6,267,799
|
|
|
$
|
468,099
|
|
|
$
|
(10,735,554
|
)
|
|
$
|
12,670,909
|
|
Liabilities and Equity:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Current Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Accounts Payable
|
$
|
177,734
|
|
|
$
|
166,182
|
|
|
$
|
154,936
|
|
|
$
|
9,130
|
|
|
$
|
—
|
|
|
$
|
507,982
|
|
Accounts Payable (Recoverable)—Related Parties
|
3,599,216
|
|
|
23,981
|
|
|
(3,749,584
|
)
|
|
254,787
|
|
|
(128,400
|
)
|
|
—
|
|
||||||
Current Portion Long-Term Debt
|
1,554
|
|
|
5,953
|
|
|
5,222
|
|
|
756
|
|
|
—
|
|
|
13,485
|
|
||||||
Short-Term Notes Payable
|
25,073
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
25,073
|
|
||||||
Accrued Income Taxes
|
20,488
|
|
|
13,731
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
34,219
|
|
||||||
Borrowings Under Securitization Facility
|
—
|
|
|
—
|
|
|
—
|
|
|
37,846
|
|
|
—
|
|
|
37,846
|
|
||||||
Other Accrued Liabilities
|
135,407
|
|
|
57,074
|
|
|
566,485
|
|
|
9,528
|
|
|
—
|
|
|
768,494
|
|
||||||
Total Current Liabilities
|
3,959,472
|
|
|
266,921
|
|
|
(3,022,941
|
)
|
|
312,047
|
|
|
(128,400
|
)
|
|
1,387,099
|
|
||||||
Long-Term Debt:
|
3,005,515
|
|
|
46,081
|
|
|
121,523
|
|
|
1,467
|
|
|
—
|
|
|
3,174,586
|
|
||||||
Deferred Credits and Other Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Postretirement Benefits Other Than Pensions
|
—
|
|
|
—
|
|
|
2,832,401
|
|
|
—
|
|
|
—
|
|
|
2,832,401
|
|
||||||
Pneumoconiosis Benefits
|
—
|
|
|
—
|
|
|
174,781
|
|
|
—
|
|
|
—
|
|
|
174,781
|
|
||||||
Mine Closing
|
—
|
|
|
—
|
|
|
446,727
|
|
|
—
|
|
|
—
|
|
|
446,727
|
|
||||||
Gas Well Closing
|
—
|
|
|
80,097
|
|
|
68,831
|
|
|
—
|
|
|
—
|
|
|
148,928
|
|
||||||
Workers’ Compensation
|
—
|
|
|
—
|
|
|
155,342
|
|
|
306
|
|
|
—
|
|
|
155,648
|
|
||||||
Salary Retirement
|
218,004
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
218,004
|
|
||||||
Reclamation
|
—
|
|
|
—
|
|
|
47,965
|
|
|
—
|
|
|
—
|
|
|
47,965
|
|
||||||
Other
|
101,899
|
|
|
24,518
|
|
|
4,608
|
|
|
—
|
|
|
—
|
|
|
131,025
|
|
||||||
Total Deferred Credits and Other Liabilities
|
319,903
|
|
|
104,615
|
|
|
3,730,655
|
|
|
306
|
|
|
—
|
|
|
4,155,479
|
|
||||||
Total CONSOL Energy Inc. Stockholders’ Equity
|
3,953,792
|
|
|
5,014,313
|
|
|
5,438,562
|
|
|
154,279
|
|
|
(10,607,154
|
)
|
|
3,953,792
|
|
||||||
Noncontrolling Interest
|
—
|
|
|
(47
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(47
|
)
|
||||||
Total Liabilities and Equity
|
$
|
11,238,682
|
|
|
$
|
5,431,883
|
|
|
$
|
6,267,799
|
|
|
$
|
468,099
|
|
|
$
|
(10,735,554
|
)
|
|
$
|
12,670,909
|
|
|
Parent
|
|
CNX Gas
Guarantor
|
|
Other Subsidiary Guarantors
|
|
Non-
Guarantors
|
|
Elimination
|
|
Consolidated
|
||||||||||||
Net Cash Provided by (Used in) Operating Activities
|
$
|
(58,410
|
)
|
|
$
|
82,036
|
|
|
$
|
741,699
|
|
|
$
|
(37,196
|
)
|
|
$
|
—
|
|
|
$
|
728,129
|
|
Cash Flows from Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Capital Expenditures
|
$
|
(49,973
|
)
|
|
$
|
(532,636
|
)
|
|
$
|
(992,621
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(1,575,230
|
)
|
(Investments in), net of Distributions from, Equity Affiliates
|
200,000
|
|
|
(37,400
|
)
|
|
13,949
|
|
|
—
|
|
|
(200,000
|
)
|
|
(23,451
|
)
|
||||||
Proceeds From Sales of Assets
|
—
|
|
|
360,129
|
|
|
286,182
|
|
|
254
|
|
|
—
|
|
|
646,565
|
|
||||||
Other Investing Activities
|
—
|
|
|
—
|
|
|
(48,294
|
)
|
|
—
|
|
|
—
|
|
|
(48,294
|
)
|
||||||
Net Cash (Used in) Provided by Investing Activities
|
$
|
150,027
|
|
|
$
|
(209,907
|
)
|
|
$
|
(740,784
|
)
|
|
$
|
254
|
|
|
$
|
(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
|
)
|
|
(2,009
|
)
|
|
37,404
|
|
|
—
|
|
|
52,423
|
|
||||||
Net Cash (Used in) Provided by Financing Activities
|
$
|
(111,468
|
)
|
|
$
|
(205,504
|
)
|
|
$
|
(2,009
|
)
|
|
$
|
37,404
|
|
|
$
|
200,000
|
|
|
$
|
(81,577
|
)
|
|
Parent
Issuer
|
|
CNX Gas
Guarantor
|
|
Other
Subsidiary
Guarantors
|
|
Non-
Guarantors
|
|
Elimination
|
|
Consolidated
|
||||||||||||
Sales—Outside
|
$
|
—
|
|
|
$
|
751,767
|
|
|
$
|
4,678,910
|
|
|
$
|
234,998
|
|
|
$
|
(4,862
|
)
|
|
$
|
5,660,813
|
|
Sales—Gas Royalty Interests
|
—
|
|
|
66,929
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
66,929
|
|
||||||
Sales—Purchased Gas
|
—
|
|
|
4,344
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,344
|
|
||||||
Freight—Outside
|
—
|
|
|
—
|
|
|
231,536
|
|
|
—
|
|
|
—
|
|
|
231,536
|
|
||||||
Other Income
|
876,233
|
|
|
58,923
|
|
|
63,161
|
|
|
26,309
|
|
|
(871,006
|
)
|
|
153,620
|
|
||||||
Total Revenue and Other Income
|
876,233
|
|
|
881,963
|
|
|
4,973,607
|
|
|
261,307
|
|
|
(875,868
|
)
|
|
6,117,242
|
|
||||||
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)
|
108,681
|
|
|
388,507
|
|
|
2,678,210
|
|
|
228,291
|
|
|
97,609
|
|
|
3,501,298
|
|
||||||
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
|
—
|
|
|
—
|
|
|
231,347
|
|
|
—
|
|
|
—
|
|
|
231,347
|
|
||||||
Selling, General and Administrative Expenses
|
—
|
|
|
50,429
|
|
|
123,553
|
|
|
1,485
|
|
|
—
|
|
|
175,467
|
|
||||||
Depreciation, Depletion and Amortization
|
12,194
|
|
|
206,821
|
|
|
396,979
|
|
|
2,403
|
|
|
—
|
|
|
618,397
|
|
||||||
Interest Expense
|
235,370
|
|
|
9,398
|
|
|
3,911
|
|
|
53
|
|
|
(388
|
)
|
|
248,344
|
|
||||||
Taxes Other Than Income
|
950
|
|
|
34,023
|
|
|
306,450
|
|
|
3,037
|
|
|
—
|
|
|
344,460
|
|
||||||
Abandonment of Long-Lived Assets
|
—
|
|
|
—
|
|
|
115,817
|
|
|
—
|
|
|
—
|
|
|
115,817
|
|
||||||
Transaction and Financing Fees
|
14,907
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
14,907
|
|
||||||
Loss on Debt Extinguishment
|
16,090
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
16,090
|
|
||||||
Total Costs
|
392,959
|
|
|
752,386
|
|
|
3,830,547
|
|
|
237,255
|
|
|
116,142
|
|
|
5,329,289
|
|
||||||
Earnings (Loss) Before Income Taxes
|
483,274
|
|
|
129,577
|
|
|
1,143,060
|
|
|
24,052
|
|
|
(992,010
|
)
|
|
787,953
|
|
||||||
Income Tax Expense (Benefit)
|
(149,223
|
)
|
|
51,876
|
|
|
243,705
|
|
|
9,098
|
|
|
—
|
|
|
155,456
|
|
||||||
Net Income (Loss) Attributable to CONSOL Energy Inc. Shareholders
|
$
|
632,497
|
|
|
$
|
77,701
|
|
|
$
|
899,355
|
|
|
$
|
14,954
|
|
|
$
|
(992,010
|
)
|
|
$
|
632,497
|
|
|
Parent
Issuer
|
|
CNX Gas
Guarantor
|
|
Other
Subsidiary
Guarantors
|
|
Non-
Guarantors
|
|
Elimination
|
|
Consolidated
|
||||||||||||
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Current Assets:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Cash and Cash Equivalents
|
$
|
37,342
|
|
|
$
|
336,727
|
|
|
$
|
1,269
|
|
|
$
|
398
|
|
|
$
|
—
|
|
|
$
|
375,736
|
|
Accounts and Notes Receivable:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Trade
|
—
|
|
|
63,299
|
|
|
500
|
|
|
399,013
|
|
|
—
|
|
|
462,812
|
|
||||||
Notes Receivable
|
2,669
|
|
|
311,754
|
|
|
527
|
|
|
—
|
|
|
—
|
|
|
314,950
|
|
||||||
Other Receivables
|
2,913
|
|
|
91,582
|
|
|
7,458
|
|
|
3,755
|
|
|
—
|
|
|
105,708
|
|
||||||
Inventories
|
—
|
|
|
8,600
|
|
|
206,096
|
|
|
43,639
|
|
|
—
|
|
|
258,335
|
|
||||||
Deferred Income Taxes
|
191,689
|
|
|
(50,606
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
141,083
|
|
||||||
Prepaid Expenses
|
28,470
|
|
|
159,900
|
|
|
49,224
|
|
|
1,759
|
|
|
—
|
|
|
239,353
|
|
||||||
Total Current Assets
|
263,083
|
|
|
921,256
|
|
|
265,074
|
|
|
448,564
|
|
|
—
|
|
|
1,897,977
|
|
||||||
Property, Plant and Equipment:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Property, Plant and Equipment
|
198,004
|
|
|
5,488,094
|
|
|
8,376,831
|
|
|
24,390
|
|
|
—
|
|
|
14,087,319
|
|
||||||
Less-Accumulated Depreciation, Depletion and Amortization
|
109,924
|
|
|
778,716
|
|
|
3,855,323
|
|
|
16,940
|
|
|
—
|
|
|
4,760,903
|
|
||||||
Total Property, Plant and Equipment-Net
|
88,080
|
|
|
4,709,378
|
|
|
4,521,508
|
|
|
7,450
|
|
|
—
|
|
|
9,326,416
|
|
||||||
Other Assets:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Deferred Income Taxes
|
963,332
|
|
|
(455,608
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
507,724
|
|
||||||
Restricted Cash
|
1,857
|
|
|
—
|
|
|
20,291
|
|
|
—
|
|
|
—
|
|
|
22,148
|
|
||||||
Investment in Affiliates
|
9,126,453
|
|
|
96,914
|
|
|
760,548
|
|
|
—
|
|
|
(9,801,879
|
)
|
|
182,036
|
|
||||||
Notes Receivable
|
4,148
|
|
|
296,344
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
300,492
|
|
||||||
Other
|
116,624
|
|
|
110,128
|
|
|
52,009
|
|
|
10,146
|
|
|
—
|
|
|
288,907
|
|
||||||
Total Other Assets
|
10,212,414
|
|
|
47,778
|
|
|
832,848
|
|
|
10,146
|
|
|
(9,801,879
|
)
|
|
1,301,307
|
|
||||||
Total Assets
|
$
|
10,563,577
|
|
|
$
|
5,678,412
|
|
|
$
|
5,619,430
|
|
|
$
|
466,160
|
|
|
$
|
(9,801,879
|
)
|
|
$
|
12,525,700
|
|
Liabilities and Equity:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Current Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Accounts Payable
|
$
|
140,823
|
|
|
$
|
206,072
|
|
|
$
|
164,521
|
|
|
$
|
10,587
|
|
|
$
|
—
|
|
|
$
|
522,003
|
|
Accounts Payable (Recoverable)-Related Parties
|
3,133,603
|
|
|
9,431
|
|
|
(3,455,705
|
)
|
|
312,671
|
|
|
—
|
|
|
—
|
|
||||||
Current Portion of Long-Term Debt
|
805
|
|
|
5,587
|
|
|
13,543
|
|
|
756
|
|
|
—
|
|
|
20,691
|
|
||||||
Accrued Income Taxes
|
68,819
|
|
|
6,814
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
75,633
|
|
||||||
Other Accrued Liabilities
|
240,102
|
|
|
58,401
|
|
|
459,997
|
|
|
11,570
|
|
|
—
|
|
|
770,070
|
|
||||||
Total Current Liabilities
|
3,584,152
|
|
|
286,305
|
|
|
(2,817,644
|
)
|
|
335,584
|
|
|
—
|
|
|
1,388,397
|
|
||||||
Long-Term Debt:
|
3,001,092
|
|
|
50,326
|
|
|
124,674
|
|
|
1,331
|
|
|
—
|
|
|
3,177,423
|
|
||||||
Deferred Credits and Other Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Postretirement Benefits Other Than Pensions
|
—
|
|
|
—
|
|
|
3,059,671
|
|
|
—
|
|
|
—
|
|
|
3,059,671
|
|
||||||
Pneumoconiosis Benefits
|
—
|
|
|
—
|
|
|
173,553
|
|
|
—
|
|
|
—
|
|
|
173,553
|
|
||||||
Mine Closing
|
—
|
|
|
—
|
|
|
406,712
|
|
|
—
|
|
|
—
|
|
|
406,712
|
|
||||||
Gas Well Closing
|
—
|
|
|
61,954
|
|
|
62,097
|
|
|
—
|
|
|
—
|
|
|
124,051
|
|
||||||
Workers’ Compensation
|
—
|
|
|
—
|
|
|
150,786
|
|
|
248
|
|
|
—
|
|
|
151,034
|
|
||||||
Salary Retirement
|
269,069
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
269,069
|
|
||||||
Reclamation
|
—
|
|
|
—
|
|
|
39,969
|
|
|
—
|
|
|
—
|
|
|
39,969
|
|
||||||
Other
|
98,379
|
|
|
16,899
|
|
|
9,658
|
|
|
—
|
|
|
—
|
|
|
124,936
|
|
||||||
Total Deferred Credits and Other Liabilities
|
367,448
|
|
|
78,853
|
|
|
3,902,446
|
|
|
248
|
|
|
—
|
|
|
4,348,995
|
|
||||||
Total CONSOL Energy Inc. Stockholders’ Equity
|
3,610,885
|
|
|
5,262,928
|
|
|
4,409,954
|
|
|
128,997
|
|
|
(9,801,879
|
)
|
|
3,610,885
|
|
||||||
Noncontrolling Interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total Liabilities and Equity
|
$
|
10,563,577
|
|
|
$
|
5,678,412
|
|
|
$
|
5,619,430
|
|
|
$
|
466,160
|
|
|
$
|
(9,801,879
|
)
|
|
$
|
12,525,700
|
|
|
Parent
|
|
CNX Gas
Guarantor
|
|
Other Subsidiary Guarantors
|
|
Non-
Guarantors
|
|
Elimination
|
|
Consolidated
|
||||||||||||
Net Cash Provided by (Used In) Operating Activities
|
$
|
530,444
|
|
|
$
|
329,360
|
|
|
$
|
669,704
|
|
|
$
|
(1,902
|
)
|
|
$
|
—
|
|
|
$
|
1,527,606
|
|
Cash Flows from Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Capital Expenditures
|
$
|
(41,172
|
)
|
|
$
|
(664,612
|
)
|
|
$
|
(676,587
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(1,382,371
|
)
|
Distributions from, net of Investments in, Equity Affiliates
|
—
|
|
|
50,626
|
|
|
5,250
|
|
|
—
|
|
|
—
|
|
|
55,876
|
|
||||||
Proceeds From Sales of Assets
|
10
|
|
|
746,956
|
|
|
(469
|
)
|
|
1,474
|
|
|
—
|
|
|
747,971
|
|
||||||
Net Cash (Used in) Provided by Investing Activities
|
$
|
(41,162
|
)
|
|
$
|
132,970
|
|
|
$
|
(671,806
|
)
|
|
$
|
1,474
|
|
|
$
|
—
|
|
|
$
|
(578,524
|
)
|
Cash Flows from Financing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Dividends Paid
|
$
|
(96,356
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(96,356
|
)
|
Payments on Short-Term Borrowings
|
(155,000
|
)
|
|
(129,000
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(284,000
|
)
|
||||||
Payments on Securitization Facility
|
(200,000
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(200,000
|
)
|
||||||
Payments on Long Term Notes, including redemption premium
|
(265,785
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(265,785
|
)
|
||||||
Proceeds from Long-Term Notes
|
250,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
250,000
|
|
||||||
Other Financing Activities
|
5,749
|
|
|
(13,162
|
)
|
|
(1,793
|
)
|
|
(793
|
)
|
|
—
|
|
|
(9,999
|
)
|
||||||
Net Cash (Used in) Provided by Financing Activities
|
$
|
(461,392
|
)
|
|
$
|
(142,162
|
)
|
|
$
|
(1,793
|
)
|
|
$
|
(793
|
)
|
|
$
|
—
|
|
|
$
|
(606,140
|
)
|
|
Parent
Issuer
|
|
CNX Gas
Guarantor
|
|
Other
Subsidiary
Guarantors
|
|
Non-
Guarantors
|
|
Elimination
|
|
Consolidated
|
||||||||||||
Sales—Outside
|
$
|
—
|
|
|
$
|
745,809
|
|
|
$
|
4,002,790
|
|
|
$
|
196,118
|
|
|
$
|
(6,014
|
)
|
|
$
|
4,938,703
|
|
Sales—Gas Royalty Interests
|
—
|
|
|
62,869
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
62,869
|
|
||||||
Sales—Purchased Gas
|
—
|
|
|
11,227
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
11,227
|
|
||||||
Freight—Outside
|
—
|
|
|
—
|
|
|
125,715
|
|
|
—
|
|
|
—
|
|
|
125,715
|
|
||||||
Other Income
|
565,780
|
|
|
5,174
|
|
|
51,004
|
|
|
29,851
|
|
|
(554,302
|
)
|
|
97,507
|
|
||||||
Total Revenue and Other Income
|
565,780
|
|
|
825,079
|
|
|
4,179,509
|
|
|
225,969
|
|
|
(560,316
|
)
|
|
5,236,021
|
|
||||||
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion, and amortization shown below)
|
102,645
|
|
|
304,645
|
|
|
2,589,993
|
|
|
10,858
|
|
|
254,186
|
|
|
3,262,327
|
|
||||||
Gas Royalty Interests Costs
|
—
|
|
|
53,839
|
|
|
—
|
|
|
—
|
|
|
(64
|
)
|
|
53,775
|
|
||||||
Purchased Gas Costs
|
—
|
|
|
9,736
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9,736
|
|
||||||
Related Party Activity
|
(11,676
|
)
|
|
—
|
|
|
(10,059
|
)
|
|
180,398
|
|
|
(158,663
|
)
|
|
—
|
|
||||||
Freight Expense
|
—
|
|
|
—
|
|
|
125,544
|
|
|
—
|
|
|
—
|
|
|
125,544
|
|
||||||
Selling, General and Administrative Expenses
|
—
|
|
|
46,519
|
|
|
102,623
|
|
|
1,068
|
|
|
—
|
|
|
150,210
|
|
||||||
Depreciation, Depletion and Amortization
|
10,641
|
|
|
190,424
|
|
|
363,961
|
|
|
2,637
|
|
|
—
|
|
|
567,663
|
|
||||||
Interest Expense
|
188,343
|
|
|
7,196
|
|
|
9,838
|
|
|
25
|
|
|
(370
|
)
|
|
205,032
|
|
||||||
Taxes Other Than Income
|
6,599
|
|
|
29,882
|
|
|
289,160
|
|
|
2,817
|
|
|
—
|
|
|
328,458
|
|
||||||
Transaction and Financing Fees
|
62,031
|
|
|
3,330
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
65,363
|
|
||||||
Total Costs
|
358,583
|
|
|
645,571
|
|
|
3,471,062
|
|
|
197,803
|
|
|
95,089
|
|
|
4,768,108
|
|
||||||
Earnings (Loss) Before Income Taxes
|
207,197
|
|
|
179,508
|
|
|
708,447
|
|
|
28,166
|
|
|
(655,405
|
)
|
|
467,913
|
|
||||||
Income Tax Expense (Benefit)
|
(139,584
|
)
|
|
73,378
|
|
|
164,838
|
|
|
10,655
|
|
|
—
|
|
|
109,287
|
|
||||||
Net Income (Loss)
|
346,781
|
|
|
106,130
|
|
|
543,609
|
|
|
17,511
|
|
|
(655,405
|
)
|
|
358,626
|
|
||||||
Less: Net Income Attributable to Noncontrolling Interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(11,845
|
)
|
|
(11,845
|
)
|
||||||
Net Income (Loss) Attributable to CONSOL Energy Inc. Shareholders
|
$
|
346,781
|
|
|
$
|
106,130
|
|
|
$
|
543,609
|
|
|
$
|
17,511
|
|
|
$
|
(667,250
|
)
|
|
$
|
346,781
|
|
|
Parent
|
|
CNX Gas
Guarantor
|
|
Other Subsidiary Guarantors
|
|
Non-
Guarantors
|
|
Elimination
|
|
Consolidated
|
||||||||||||
Net Cash Provided by (Used in) Operating Activities
|
$
|
93,623
|
|
|
$
|
361,073
|
|
|
$
|
675,627
|
|
|
$
|
989
|
|
|
$
|
—
|
|
|
$
|
1,131,312
|
|
Cash Flows from Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Capital Expenditures
|
$
|
—
|
|
|
$
|
(421,428
|
)
|
|
$
|
(732,596
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(1,154,024
|
)
|
Acquisition of Dominion Exploration and Production Business
|
—
|
|
|
—
|
|
|
(3,470,212
|
)
|
|
—
|
|
|
—
|
|
|
(3,470,212
|
)
|
||||||
Purchase of CNX Gas Noncontrolling Interest
|
(991,034
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(991,034
|
)
|
||||||
Distributions from, net of (Investments in), Equity Affiliates
|
(3,470,212
|
)
|
|
1,501
|
|
|
9,951
|
|
|
—
|
|
|
3,470,212
|
|
|
11,452
|
|
||||||
Proceeds From Sales of Assets
|
—
|
|
|
562
|
|
|
59,282
|
|
|
—
|
|
|
—
|
|
|
59,844
|
|
||||||
Net Cash (Used in) Provided by Investing Activities
|
$
|
(4,461,246
|
)
|
|
$
|
(419,365
|
)
|
|
$
|
(4,133,575
|
)
|
|
$
|
—
|
|
|
$
|
3,470,212
|
|
|
$
|
(5,543,974
|
)
|
Cash Flows from Financing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Dividends Paid
|
$
|
(85,861
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(85,861
|
)
|
Payments on (Proceeds from) Short-Term Borrowings
|
(260,000
|
)
|
|
71,150
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(188,850
|
)
|
||||||
Proceeds from Securitization Facility
|
150,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
150,000
|
|
||||||
Proceeds from Long-Term Notes
|
2,750,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,750,000
|
|
||||||
Proceeds from Issuance of Common Stock
|
1,828,862
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,828,862
|
|
||||||
Proceeds from (Payments to) Parent
|
—
|
|
|
—
|
|
|
3,470,212
|
|
|
—
|
|
|
(3,470,212
|
)
|
|
—
|
|
||||||
Other Financing Activities
|
(63,545
|
)
|
|
2,577
|
|
|
(12,793
|
)
|
|
(541
|
)
|
|
—
|
|
|
(74,302
|
)
|
||||||
Net Cash Provided by (Used in) Financing Activities
|
$
|
4,319,456
|
|
|
$
|
73,727
|
|
|
$
|
3,457,419
|
|
|
$
|
(541
|
)
|
|
$
|
(3,470,212
|
)
|
|
$
|
4,379,849
|
|
|
Parent
|
|
CNX Gas
Guarantor
|
|
Other
Subsidiary
Guarantors
|
|
Non-
Guarantors
|
|
Elimination
|
|
Consolidated
|
||||||||||||
Net Income (Loss)
|
$
|
388,470
|
|
|
$
|
24,363
|
|
|
$
|
656,185
|
|
|
$
|
11,171
|
|
|
$
|
(692,116
|
)
|
|
$
|
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
|
)
|
|
785,416
|
|
|
11,171
|
|
|
(746,328
|
)
|
|
442,285
|
|
||||||
Less: Comprehensive Loss Attributable to Noncontrolling Interest
|
—
|
|
|
397
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
397
|
|
||||||
Comprehensive Income (Loss) Attributable to CONSOL Energy Inc. Shareholders
|
$
|
442,682
|
|
|
$
|
(50,259
|
)
|
|
$
|
785,416
|
|
|
$
|
11,171
|
|
|
$
|
(746,328
|
)
|
|
$
|
442,682
|
|
|
Parent
|
|
CNX Gas
Guarantor
|
|
Other
Subsidiary
Guarantors
|
|
Non-Guarantors
|
|
Elimination
|
|
Consolidated
|
||||||||||||
Net Income (Loss)
|
$
|
632,497
|
|
|
$
|
77,701
|
|
|
$
|
899,355
|
|
|
$
|
14,954
|
|
|
$
|
(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)
|
$
|
705,281
|
|
|
$
|
183,394
|
|
|
$
|
866,542
|
|
|
$
|
14,954
|
|
|
$
|
(1,064,890
|
)
|
|
$
|
705,281
|
|
|
Parent
|
|
CNX Gas
Guarantor
|
|
Other
Subsidiary
Guarantors
|
|
Non-
Guarantors
|
|
Elimination
|
|
Consolidated
|
||||||||||||
Net Income (Loss)
|
$
|
346,781
|
|
|
$
|
106,130
|
|
|
$
|
543,609
|
|
|
$
|
17,511
|
|
|
$
|
(655,405
|
)
|
|
$
|
358,626
|
|
Other Comprehensive Income (Loss):
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Treasury Rate Lock
|
(84
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(84
|
)
|
||||||
Actuarially Determined Long-Term Liability Adjustments
|
(221,228
|
)
|
|
—
|
|
|
(221,228
|
)
|
|
—
|
|
|
221,228
|
|
|
(221,228
|
)
|
||||||
Net Increase (Decrease) in the Value of Cash Flow Hedge
|
140,985
|
|
|
140,985
|
|
|
—
|
|
|
—
|
|
|
(140,985
|
)
|
|
140,985
|
|
||||||
Reclassification of Cash Flow Hedge from OCI to Earnings
|
(166,276
|
)
|
|
(166,276
|
)
|
|
—
|
|
|
—
|
|
|
166,276
|
|
|
(166,276
|
)
|
||||||
Purchase of CNX Gas Noncontrolling Interest
|
18,026
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
18,026
|
|
||||||
Other Comprehensive Income (Loss):
|
$
|
(228,577
|
)
|
|
$
|
(25,291
|
)
|
|
$
|
(221,228
|
)
|
|
$
|
—
|
|
|
$
|
246,519
|
|
|
$
|
(228,577
|
)
|
Comprehensive Income (Loss)
|
118,204
|
|
|
80,839
|
|
|
322,381
|
|
|
17,511
|
|
|
(408,886
|
)
|
|
130,049
|
|
||||||
Less: Comprehensive Income Attributable to Noncontrolling Interest
|
(5,257
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(11,845
|
)
|
|
(17,102
|
)
|
||||||
Comprehensive Income (Loss) Attributable to CONSOL Energy Inc. Shareholders
|
$
|
112,947
|
|
|
$
|
80,839
|
|
|
$
|
322,381
|
|
|
$
|
17,511
|
|
|
$
|
(420,731
|
)
|
|
$
|
112,947
|
|
|
December 31,
|
|
December 31,
|
|
|
||||
|
2012
|
|
2011
|
|
Location on Balance Sheet
|
||||
Reimbursement for CONE Expenses
|
1,336
|
|
|
2,009
|
|
|
Accounts Receivable–Other
|
||
Reimbursement for Services Provided to CONE
|
341
|
|
|
414
|
|
|
Accounts Receivable–Other
|
||
CONE Gathering Capital Reimbursement
|
18
|
|
|
8,042
|
|
|
Accounts Receivable–Other
|
||
CONE Gathering Fee Payable
|
(4,837
|
)
|
|
(1,499
|
)
|
|
Accounts Payable
|
||
Net (Payable) Receivable due (to) from CONE
|
$
|
(3,142
|
)
|
|
$
|
8,966
|
|
|
|
|
|
Millions of Tons
|
|||||||||||||
|
|
For the Year Ended December 31,
|
|||||||||||||
|
|
2012
|
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
Proved and probable reserves at beginning of period
|
|
4,314
|
|
|
4,229
|
|
|
4,350
|
|
|
4,372
|
|
|
4,355
|
|
Purchased reserves
|
|
—
|
|
|
6
|
|
|
4
|
|
|
5
|
|
|
—
|
|
Reserves sold in place
|
|
(155
|
)
|
|
—
|
|
|
(41
|
)
|
|
(3
|
)
|
|
(12
|
)
|
Production
|
|
(55
|
)
|
|
(62
|
)
|
|
(62
|
)
|
|
(58
|
)
|
|
(65
|
)
|
Revisions and other changes
|
|
125
|
|
|
141
|
|
|
(22
|
)
|
|
34
|
|
|
94
|
|
Consolidated proved and probable reserves at end of period*
|
|
4,229
|
|
|
4,314
|
|
|
4,229
|
|
|
4,350
|
|
|
4,372
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Proved and probable reserves of unconsolidated equity affiliates
|
|
41
|
|
|
145
|
|
|
172
|
|
|
170
|
|
|
171
|
|
|
|
As of December 31,
|
||||||
|
|
2012
|
|
2011
|
||||
Proven properties
|
|
$
|
1,549,773
|
|
|
$
|
1,495,772
|
|
Unproven properties
|
|
1,266,444
|
|
|
1,258,455
|
|
||
Wells and related equipment
|
|
2,113,414
|
|
|
1,755,617
|
|
||
Gathering assets
|
|
1,006,882
|
|
|
963,494
|
|
||
Total Property, Plant and Equipment
|
|
5,936,513
|
|
|
5,473,338
|
|
||
Accumulated Depreciation, Depletion and Amortization
|
|
(953,873
|
)
|
|
(773,027
|
)
|
||
Net Capitalized Costs
|
|
$
|
4,982,640
|
|
|
$
|
4,700,311
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2012
|
|
2011
|
|
2010
|
||||||
Property acquisitions
|
|
|
|
|
|
|
||||||
Proven properties
|
|
$
|
50,005
|
|
|
$
|
6,673
|
|
|
$
|
1,476,470
|
|
Unproven properties
|
|
28,634
|
|
|
58,731
|
|
|
1,922,334
|
|
|||
Development
|
|
339,608
|
|
|
463,401
|
|
|
472,691
|
|
|||
Exploration
|
|
130,312
|
|
|
131,419
|
|
|
58,655
|
|
|||
Total
|
|
$
|
548,559
|
|
|
$
|
660,224
|
|
|
$
|
3,930,150
|
|
(*)
|
Includes costs incurred whether capitalized or expensed.
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2012
|
|
2011
|
|
2010
|
||||||
Production Revenue
|
|
$
|
660,442
|
|
|
$
|
751,767
|
|
|
$
|
745,809
|
|
Royalty Interest Gas Revenue
|
|
49,405
|
|
|
66,929
|
|
|
62,869
|
|
|||
Purchased Gas Revenue
|
|
3,316
|
|
|
4,344
|
|
|
11,227
|
|
|||
Total Revenue
|
|
713,163
|
|
|
823,040
|
|
|
819,905
|
|
|||
Lifting Costs
|
|
90,835
|
|
|
106,477
|
|
|
64,820
|
|
|||
Ad Valorem, Severance & Other Taxes
|
|
|
|
|
|
|
||||||
Gathering Costs
|
|
160,575
|
|
|
142,339
|
|
|
127,927
|
|
|||
Royalty Interest Gas Costs
|
|
38,922
|
|
|
59,377
|
|
|
53,839
|
|
|||
Direct Administrative, Selling & Other Costs
|
|
47,567
|
|
|
60,355
|
|
|
63,941
|
|
|||
Other Costs
|
|
39,029
|
|
|
18,095
|
|
|
25,220
|
|
|||
Purchased Gas Costs
|
|
2,711
|
|
|
3,831
|
|
|
9,736
|
|
|||
DD&A
|
|
202,956
|
|
|
206,821
|
|
|
190,424
|
|
|||
Total Costs
|
|
608,740
|
|
|
623,556
|
|
|
559,148
|
|
|||
Pre-tax Operating Income
|
|
104,423
|
|
|
199,484
|
|
|
260,757
|
|
|||
Income Taxes
|
|
39,827
|
|
|
79,873
|
|
|
106,598
|
|
|||
Results of Operations for Producing Activities excluding Corporate and Interest Costs
|
|
$
|
64,596
|
|
|
$
|
119,611
|
|
|
$
|
154,159
|
|
|
|
For the Years Ended December 31,
|
||||||||||
|
|
2012
|
|
2011
|
|
2010
|
||||||
Production in million cubic feet
|
|
156,325
|
|
|
153,504
|
|
|
127,875
|
|
|||
Average gas sales price before effects of financial settlements (per thousand cubic feet)
|
|
$
|
3.01
|
|
|
$
|
4.27
|
|
|
$
|
4.53
|
|
Average effects of financial settlements (per thousand cubic feet)
|
|
$
|
1.21
|
|
|
$
|
0.63
|
|
|
$
|
1.30
|
|
Average gas sales price including effects of financial settlements (per thousand cubic feet)
|
|
$
|
4.22
|
|
|
$
|
4.90
|
|
|
$
|
5.83
|
|
Average lifting costs, excluding ad valorem and severance taxes (per thousand cubic feet)
|
|
$
|
0.58
|
|
|
$
|
0.68
|
|
|
$
|
0.50
|
|
|
|
Gross
|
|
Net(1)
|
||
Producing Wells (including gob wells)
|
|
14,906
|
|
|
12,819
|
|
Proved Developed Acreage
|
|
555,160
|
|
|
465,392
|
|
Proved Undeveloped Acreage
|
|
118,384
|
|
|
83,574
|
|
Unproved Acreage
|
|
4,930,181
|
|
|
4,038,515
|
|
Total Acreage
|
|
5,603,725
|
|
|
4,587,481
|
|
(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.
|
|
|
Consolidated Operations
|
|||||||
|
|
2012
|
|
2011
|
|
2010
|
|||
Net Reserve Quantity (MMcfe)
|
|
|
|
|
|
|
|||
Beginning reserves
|
|
3,480,027
|
|
|
3,731,597
|
|
|
1,911,391
|
|
Price Changes
|
|
(526,611
|
)
|
|
(9,976
|
)
|
|
13,612
|
|
Plan and other revisions (a)
|
|
241,989
|
|
|
(73,837
|
)
|
|
366,365
|
|
Extensions and discoveries(b)
|
|
954,378
|
|
|
517,178
|
|
|
621,270
|
|
Production
|
|
(156,325
|
)
|
|
(153,504
|
)
|
|
(127,875
|
)
|
Purchases of reserves in-place
|
|
—
|
|
|
—
|
|
|
946,834
|
|
Sale of reserves in-place
|
|
—
|
|
|
(531,431
|
)
|
|
—
|
|
Ending reserves(c)
|
|
3,993,458
|
|
|
3,480,027
|
|
|
3,731,597
|
|
(a)
|
Plan and other revisions are due to corporate planning changes that affect the number of wells forecasted to be drilled in our various areas and reservoirs. These changes along with upward revisions attributable to efficiencies in operations and well performance had the total affect of a positive revision.
|
(b)
|
Extensions and Discoveries are due to the addition of wells on our Marcellus Shale acreage more than one offset location away with reliable technology.
|
(c)
|
Proved developed and proved undeveloped gas reserves are defined by SEC Rule 4.10(a) of Regulation S-X. Generally, these reserves would be commercially recovered under current economic conditions, operating methods and government regulations. CONSOL Energy cautions that there are many inherent uncertainties in estimating proved reserve quantities,
|
|
|
2012
|
|
2011
|
|
2010
|
||||||||||||||||||||||
|
|
|
|
|
|
Oil
|
|
|
|
|
|
Oil
|
|
|
|
|
|
Oil
|
||||||||||
|
|
All Products
|
|
Natural Gas mmcf
|
|
mmcfe (a)
|
|
All Products
|
|
Natural Gas mmcf
|
|
mmcfe (a)
|
|
All Products
|
|
Natural Gas mmcf
|
|
mmcfe (a)
|
||||||||||
Proved developed reserves (consolidated entities only)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Beginning of year
|
|
2,135,805
|
|
|
2,126,330
|
|
|
9,475
|
|
|
1,931,272
|
|
|
1,924,036
|
|
|
7,236
|
|
|
1,040,257
|
|
|
1,039,052
|
|
|
1,205
|
|
|
End of year
|
|
2,165,483
|
|
|
2,160,214
|
|
|
5,269
|
|
|
2,135,805
|
|
|
2,126,330
|
|
|
9,475
|
|
|
1,931,272
|
|
|
1,924,036
|
|
|
7,236
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Proved undeveloped reserves (consolidated entities only)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Beginning of year
|
|
1,344,222
|
|
|
1,344,222
|
|
|
—
|
|
|
1,800,325
|
|
|
1,800,325
|
|
1,800,325
|
|
—
|
|
|
871,134
|
|
|
871,134
|
|
|
—
|
|
End of year
|
|
1,827,975
|
|
|
1,827,975
|
|
|
—
|
|
|
1,344,222
|
|
|
1,344,222
|
|
1,344,222
|
|
—
|
|
|
1,800,325
|
|
|
1,800,325
|
|
|
—
|
|
(a)
|
Gas equivalent reserves are expressed in billions of cubic feet equivalent (BCFE), determined using the ratio of six billion cubic feet of gas to one million barrels of oil.
|
|
|
For the Year
|
|
|
|
Ended
|
|
|
|
December 31,
|
|
|
|
2012
|
|
Proved Undeveloped Reserves (MMcfe)
|
|
|
|
Beginning proved undeveloped reserves
|
|
1,344,222
|
|
Undeveloped reserves transferred to developed(a)
|
|
(159,322
|
)
|
Disposition of reserves in place
|
|
—
|
|
Price Changes
|
|
(386,319
|
)
|
Plan and other revisions (b)
|
|
169,506
|
|
Extension and discoveries
|
|
859,888
|
|
Ending proved undeveloped reserves(c)
|
|
1,827,975
|
|
(a)
|
During 2012, various exploration and development drilling and evaluations were completed. Approximately, $
51,206
of
capital was spent in the year ended December 31, 2012 related to undeveloped reserves that were transferred to developed.
|
(c)
|
Included in proved undeveloped reserves at December 31, 2012 are approximately 133,917 MMcfe of reserves that have been reported for more than five years. These reserves specifically relate to CONSOL Energy's Buchanan Mine, more specifically, to GOB (a rubble zone formed in the cavity created by the extraction of coal) production due to a complex fracture being generated in the overburden strata above the mined seam. Mining operations take a significant amount of time and our GOB forecasts are consistent with the future plans of the Buchanan Mine. Evidence also exists that supports the continual operation of the mine beyond the current plan, unless there was an extreme circumstance which resulted from an external factor. These reasons constitute that specific circumstances exist to continue recognizing these reserves for CONSOL Energy.
|
(a)
|
Costs held in exploratory for more than one year represent exploration wells away from existing infrastructure. The additional planned exploration expenditures will allow us to invest in infrastructure to support these fields. There were no wells removed from the previous year-end schedule.
|
|
|
December 31,
|
||||||||||
|
|
2012
|
|
2011
|
|
2010
|
||||||
Costs reclassified to wells, equipment and facilities based on the determination of proved reserves
|
|
$
|
14,447
|
|
|
$
|
189
|
|
|
$
|
93,482
|
|
Costs expensed due to determination of dry hole or abandonment of project
|
|
$
|
3,320
|
|
|
$
|
5,108
|
|
|
$
|
9,614
|
|
|
|
December 31,
|
||||||||||
|
|
2012
|
|
2011
|
|
2010
|
||||||
Future Cash Flows:
|
|
|
|
|
|
|
||||||
Revenues
|
|
$
|
11,777,550
|
|
|
$
|
14,804,398
|
|
|
$
|
16,723,795
|
|
Production costs
|
|
(4,823,670
|
)
|
|
(5,262,635
|
)
|
|
(5,175,563
|
)
|
|||
Development costs
|
|
(2,450,589
|
)
|
|
(1,674,829
|
)
|
|
(2,720,243
|
)
|
|||
Income tax expense
|
|
(1,711,251
|
)
|
|
(2,989,435
|
)
|
|
(3,354,444
|
)
|
|||
Future Net Cash Flows
|
|
2,792,040
|
|
|
4,877,499
|
|
|
5,473,545
|
|
|||
Discounted to present value at a 10% annual rate
|
|
(2,055,834
|
)
|
|
(3,130,318
|
)
|
|
(3,812,724
|
)
|
|||
Total standardized measure of discounted net cash flows
|
|
$
|
736,206
|
|
|
$
|
1,747,181
|
|
|
$
|
1,660,821
|
|
|
|
December 31,
|
||||||||||
|
|
2012
|
|
2011
|
|
2010
|
||||||
Balance at beginning of period
|
|
$
|
1,747,181
|
|
|
$
|
1,660,821
|
|
|
$
|
894,351
|
|
Net changes in sales prices and production costs
|
|
(1,480,573
|
)
|
|
(339,098
|
)
|
|
721,997
|
|
|||
Sales net of production costs
|
|
(104,518
|
)
|
|
(217,186
|
)
|
|
(286,883
|
)
|
|||
Net change due to revisions in quantity estimates
|
|
(104,158
|
)
|
|
(83,580
|
)
|
|
414,704
|
|
|||
Net change due to extensions, discoveries and improved recovery
|
|
14,645
|
|
|
324,755
|
|
|
326,584
|
|
|||
Net change due to (divestiture) acquisition
|
|
—
|
|
|
(559,132
|
)
|
|
500,376
|
|
|||
Development costs incurred during the period
|
|
333,640
|
|
|
463,401
|
|
|
295,142
|
|
|||
Difference in previously estimated development costs compared to actual costs incurred during the period
|
|
(96,749
|
)
|
|
154,137
|
|
|
(12,060
|
)
|
|||
Changes in estimated future development costs
|
|
(153,104
|
)
|
|
155,619
|
|
|
(426,870
|
)
|
|||
Net change in future income taxes
|
|
619,045
|
|
|
130,746
|
|
|
(612,114
|
)
|
|||
Accretion of discount and other
|
|
(39,203
|
)
|
|
56,698
|
|
|
(154,406
|
)
|
|||
Total discounted cash flow at end of period
|
|
$
|
736,206
|
|
|
$
|
1,747,181
|
|
|
$
|
1,660,821
|
|
|
|
Three Months Ended
|
||||||||||||||
|
|
March 31,
|
|
June 30,
|
|
September 30,
|
|
December 31,
|
||||||||
|
|
2012
|
|
2012
|
|
2012
|
|
2012
|
||||||||
Sales
|
|
$
|
1,324,516
|
|
|
$
|
1,199,477
|
|
|
$
|
1,097,962
|
|
|
$
|
1,256,712
|
|
Freight Revenue
|
|
$
|
49,293
|
|
|
$
|
49,472
|
|
|
$
|
27,430
|
|
|
$
|
15,741
|
|
Cost of Goods Sold and Other Operating Charges (including Gas Royalty Interests' Costs and Purchased Gas Costs)
|
|
$
|
914,807
|
|
|
$
|
864,882
|
|
|
$
|
838,810
|
|
|
$
|
845,032
|
|
Freight Expense
|
|
$
|
49,293
|
|
|
$
|
49,472
|
|
|
$
|
27,430
|
|
|
$
|
15,741
|
|
Net Income (Loss)
|
|
$
|
97,196
|
|
|
$
|
152,710
|
|
|
$
|
(11,473
|
)
|
|
$
|
149,640
|
|
Net Income (Loss) Attributable to CONSOL Energy Inc Shareholders
|
|
$
|
97,196
|
|
|
$
|
152,739
|
|
|
$
|
(11,368
|
)
|
|
$
|
149,903
|
|
Total Earnings per Share
|
|
|
|
|
|
|
|
|
||||||||
Basic
|
|
$
|
0.43
|
|
|
$
|
0.67
|
|
|
$
|
(0.05
|
)
|
|
$
|
0.66
|
|
Diluted
|
|
$
|
0.42
|
|
|
$
|
0.67
|
|
|
$
|
(0.05
|
)
|
|
$
|
0.65
|
|
Weighted Average Shares Outstanding
|
|
|
|
|
|
|
|
|
||||||||
Basic
|
|
227,269,269
|
|
|
227,548,394
|
|
|
227,654,395
|
|
|
227,898,021
|
|
||||
Diluted
|
|
230,124,011
|
|
|
229,252,185
|
|
|
227,654,395
|
|
|
229,934,465
|
|
|
|
Three Months Ended
|
||||||||||||||
|
|
March 31,
|
|
June 30,
|
|
September 30,
|
|
December 31,
|
||||||||
|
|
2011
|
|
2011
|
|
2011
|
|
2011
|
||||||||
Sales
|
|
$
|
1,405,293
|
|
|
$
|
1,503,435
|
|
|
$
|
1,439,930
|
|
|
$
|
1,383,431
|
|
Freight Revenue
|
|
$
|
36,868
|
|
|
$
|
59,572
|
|
|
$
|
59,871
|
|
|
$
|
75,225
|
|
Cost of Goods Sold and Other Operating Charges (including Gas Royalty Interests' Costs and Purchased Gas Costs)
|
|
$
|
831,192
|
|
|
$
|
943,541
|
|
|
$
|
895,075
|
|
|
$
|
894,543
|
|
Freight Expense
|
|
$
|
36,679
|
|
|
$
|
59,572
|
|
|
$
|
59,871
|
|
|
$
|
75,225
|
|
Net Income
|
|
$
|
192,149
|
|
|
$
|
77,384
|
|
|
$
|
167,329
|
|
|
$
|
195,635
|
|
Net Income Attributable to CONSOL Energy Inc Shareholders
|
|
$
|
192,149
|
|
|
$
|
77,384
|
|
|
$
|
167,329
|
|
|
$
|
195,635
|
|
Total Earnings per Share
|
|
|
|
|
|
|
|
|
||||||||
Basic
|
|
$
|
0.85
|
|
|
$
|
0.34
|
|
|
$
|
0.74
|
|
|
$
|
0.86
|
|
Diluted
|
|
$
|
0.84
|
|
|
$
|
0.34
|
|
|
$
|
0.73
|
|
|
$
|
0.85
|
|
Weighted Average Shares Outstanding
|
|
|
|
|
|
|
|
|
||||||||
Basic
|
|
226,350,594
|
|
|
226,647,752
|
|
|
226,744,011
|
|
|
226,971,597
|
|
||||
Diluted
|
|
228,814,838
|
|
|
229,138,024
|
|
|
229,163,537
|
|
|
229,314,370
|
|
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 AND EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
|
Name
|
|
Age
|
|
Position
|
J. Brett Harvey
|
|
62
|
|
Chairman of the Board and Chief Executive Officer
|
Nicholas J. DeIuliis
|
|
44
|
|
President
|
William J. Lyons
|
|
64
|
|
Executive Vice President and Chief Financial Officer
|
Robert F. Pusateri
|
|
62
|
|
Executive Vice President - Energy Sales and Transportation Services
|
Stephen W. Johnson
|
|
54
|
|
Executive Vice President - Chief Legal and Corporate Affairs Officer
|
David M. Khani
|
|
49
|
|
Vice President - Finance
|
James C. Grech
|
|
51
|
|
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.
|
2.1
|
|
Purchase and Sale Agreement, dated as of March 14, 2010, among Dominion Resources, Inc., Dominion Transmission, Inc., Dominion Energy, Inc. and CONSOL Energy Holdings LLC VI, incorporated by reference to Exhibit 2.1 to Form 8-K (file no. 001-14901) filed on March 16, 2010.
|
2.2
|
|
Parent Guarantee, dated March 14, 2010, by and among CONSOL Energy Inc. and Dominion Resources, Inc., Dominion Transmission, Inc. and Dominion Energy, Inc., incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on March 16, 2010.
|
2.3
|
|
Asset Acquisition Agreement dated August 17, 2011 between CNX Gas Company LLC and Noble Energy, Inc., incorporated by reference to Exhibit 2.1 to Form 8-K (file no. 001-14901) filed on August 18, 2011.
|
2.4
|
|
Joint Development Agreement by and among CNX Gas Company LLC and Noble Energy, Inc. dated as of September 30, 2011, incorporated 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.
|
3.1
|
|
Restated Certificate of Incorporation of CONSOL Energy Inc., incorporated by reference to Exhibit 3.1 to Form 8-K (file no. 001-14901) filed on May 8, 2006.
|
3.2
|
|
Amended and Restated Bylaws of CONSOL Energy Inc., dated as of February 23, 2011, incorporated by reference to Exhibit 3.2 to Form 8-K (file no. 001-14901) filed on March 1, 2011.
|
4.1
|
|
Indenture, dated as of April 1, 2010, among CONSOL Energy Inc., the Subsidiary Guarantors named therein and The Bank of Nova 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.
|
4.2
|
|
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.
|
4.3
|
|
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.
|
4.4
|
|
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.
|
4.5
|
|
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.
|
4.6
|
|
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.
|
4.7
|
|
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.
|
4.8
|
|
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.
|
4.9
|
|
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.
|
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.
|
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
|
|
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.
|
10.38
|
|
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.
|
10.39
|
|
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.
|
10.40
|
|
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.
|
10.41
|
|
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.
|
10.42
|
|
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.
|
10.43
|
|
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.
|
10.44
|
|
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.
|
10.45
|
|
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.
|
10.46
|
|
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.
|
10.47
|
|
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.
|
10.48
|
|
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.
|
10.49
|
|
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.
|
10.50
|
|
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.
|
10.51
|
|
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.
|
10.52
|
|
Executive Annual Incentive Plan, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on May 1, 2008.
|
10.53
|
|
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.
|
10.54
|
|
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.
|
10.55
|
|
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.
|
10.56
|
|
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.
|
10.57
|
|
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.
|
10.58
|
|
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.
|
10.59
|
|
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.
|
10.60
|
|
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.
|
10.61
|
|
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.
|
10.62
|
|
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.
|
10.63
|
|
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.
|
10.64
|
|
Election Form to Exchange CNX Gas Performance Share Units into CONSOL Energy Inc. Restricted Stock Units (Private Placement), incorporated by reference to Exhibit 10.2 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2009, filed on April 27, 2009.
|
10.65
|
|
Form of CONSOL Energy Inc. Restricted Stock Unit Award Agreement for Individuals Exchanging CNX Gas Performance Share Units into CONSOL Energy Inc. Restricted Stock Units (Private Placement), incorporated by reference to Exhibit 10.3 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2009, filed on April 27, 2009.
|
10.66
|
|
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.
|
10.67
|
|
Summary of Non-Employee Director Compensation, incorporated by reference to Exhibit 10.60 to Form 10-K for the year ended December 31, 2010 (file no. 001-14901), filed on February 10, 2011.
|
10.68
|
|
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.
|
10.69
|
|
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.
|
10.70
|
|
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.
|
10.71
|
|
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.
|
10.72
|
|
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.
|
10.73
|
|
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.
|
10.74
|
|
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.
|
10.75
|
|
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.
|
10.76
|
|
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.
|
10.77
|
|
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.
|
10.78
|
|
CNX Gas Corporation Equity Incentive Plan, as amended, incorporated by reference to Exhibit 10.23 to the CNX Gas Corporation Form 10-K for the year ended December 31, 2008 (file no. 001-32723), filed on February 17, 2009.
|
10.79
|
|
Form of Award Agreements under CNX Gas Corporation Equity Incentive Plan, as amended, incorporated by reference to Exhibit 10.5 to Amendment No. 1 to the Form S-1 (file no. 333-127483) for CNX Gas Corporation, filed on September 29, 2005.
|
10.80
|
|
Discretionary Bonus Agreement - William J. Lyons, dated as of December 19, 2012.
|
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, 2012 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
|
|
(Principal Executive Officer)
|
|
|
|
/
S
/ W
ILLIAM
J. L
YONS
|
|
Chief Financial Officer and Executive Vice President
|
William J. Lyons
|
|
(Principal Financial 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
/ W
ILLIAM
E. D
AVIS
|
|
Director
|
William E. Davis
|
|
|
|
|
|
/
S
/ R
AJ
K. G
UPTA
|
|
Director
|
Raj K. Gupta
|
|
|
|
|
|
/
S
/ P
ATRICIA
A. H
AMMICK
|
|
Director
|
Patricia A. Hammick
|
|
|
|
|
|
/
S
/ D
AVID
C. H
ARDESTY,
J
R.
|
|
Director
|
David C. Hardesty, Jr.
|
|
|
|
|
|
/
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, 2012
|
|
|
|
|
|
|
|
|
|
|
||||||||||
State operating loss carry-forwards
|
|
$
|
34,980
|
|
|
$
|
1,079
|
|
|
$
|
(232
|
)
|
|
$
|
—
|
|
|
$
|
35,827
|
|
Deferred deductible temporary differences
|
|
6,036
|
|
|
199
|
|
|
(55
|
)
|
|
(871
|
)
|
|
5,309
|
|
|||||
Total
|
|
$
|
41,016
|
|
|
$
|
1,278
|
|
|
$
|
(287
|
)
|
|
$
|
(871
|
)
|
|
$
|
41,136
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Year Ended December 31, 2011
|
|
|
|
|
|
|
|
|
|
|
||||||||||
State operating loss carry-forwards
|
|
$
|
39,744
|
|
|
$
|
1,530
|
|
|
$
|
(6,294
|
)
|
|
$
|
—
|
|
|
$
|
34,980
|
|
Deferred deductible temporary differences
|
|
22,924
|
|
|
—
|
|
|
(10,747
|
)
|
|
(6,141
|
)
|
|
6,036
|
|
|||||
Total
|
|
$
|
62,668
|
|
|
$
|
1,530
|
|
|
$
|
(17,041
|
)
|
|
$
|
(6,141
|
)
|
|
$
|
41,016
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Year Ended December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
||||||||||
State operating loss carry-forwards
|
|
$
|
37,052
|
|
|
$
|
3,917
|
|
|
$
|
(1,225
|
)
|
|
$
|
—
|
|
|
$
|
39,744
|
|
Deferred deductible temporary differences
|
|
24,571
|
|
|
287
|
|
|
(1,934
|
)
|
|
—
|
|
|
22,924
|
|
|||||
Total
|
|
$
|
61,623
|
|
|
$
|
4,204
|
|
|
$
|
(3,159
|
)
|
|
$
|
—
|
|
|
$
|
62,668
|
|
Phone:
|
724/485-4018
|
|
Fax:
|
724/485-4849
|
|
e-mail:
|
jbrettharvey@consolenergy.com
|
|
Web:
|
www.consolenergy.com
|
|
/s/ J. Brett Harvey
|
|
J. Brett Harvey
|
|
Chairman of the Board and Chief Executive Officer
|
|
(Principal Executive Officer)
|
/s/ William J. Lyons
|
|
|
Twelve Months Ended December 31,
|
||||||||||||||||||
|
|
2012
|
|
|
2011
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|||||
Earnings:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Income from continuing operations before income taxes
|
|
$
|
497,274
|
|
|
$
|
787,953
|
|
|
$
|
467,913
|
|
|
$
|
788,345
|
|
|
$
|
725,595
|
|
Fixed charges, as shown below
|
|
297,769
|
|
|
301,178
|
|
|
249,804
|
|
|
69,277
|
|
|
69,402
|
|
|||||
Equity in income of investees
|
|
(27,048
|
)
|
|
(24,663
|
)
|
|
(21,428
|
)
|
|
(15,707
|
)
|
|
(11,140
|
)
|
|||||
Noncontrolling Interest–Gas
|
|
397
|
|
|
—
|
|
|
(11,845
|
)
|
|
(27,425
|
)
|
|
(43,191
|
)
|
|||||
Adjusted Earnings (Loss)
|
|
$
|
768,392
|
|
|
$
|
1,064,468
|
|
|
$
|
684,444
|
|
|
$
|
814,490
|
|
|
$
|
740,666
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed charges:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest on indebtedness, expensed or capitalized
|
|
$
|
258,114
|
|
|
$
|
263,891
|
|
|
$
|
218,425
|
|
|
$
|
43,290
|
|
|
$
|
48,345
|
|
Interest within rent expense
|
|
39,655
|
|
|
37,287
|
|
|
31,379
|
|
|
25,987
|
|
|
21,057
|
|
|||||
Total Fixed Charges
|
|
$
|
297,769
|
|
|
$
|
301,178
|
|
|
$
|
249,804
|
|
|
$
|
69,277
|
|
|
$
|
69,402
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Ratio of Earnings to Fixed Charges
|
|
2.58
|
|
|
3.53
|
|
|
2.74
|
|
|
11.76
|
|
|
10.67
|
|
AMVEST Coal & Rail, LLC. (a Virginia limited liability company)
|
|
Eighty-Four Mining Company (a Pennsylvania corporation)
|
AMVEST Coal Sales, Inc. (a Virginia corporation)
|
|
Fairmont Supply Company (a Delaware corporation)
|
AMVEST Corporation (a Virginia corporation)
|
|
Fairmont Supply Oil and Gas LLC (formerly North Penn
|
AMVEST Gas Resources, Inc. (a Virginia corporation)
|
|
Pipe & Supply, LLC) (a Pennsylvania limited liability company)
|
AMVEST Mineral Services, Inc. (a Virginia corporation)
|
|
Fola Coal Company, LLC. d/b/a Powellton Coal Company (a West
|
AMVEST Minerals Company, LLC. (a Virginia limited liability
|
|
Virginia limited liability company)
|
company)
|
|
Glamorgan Coal Company, LLC. (a Virginia limited liability
|
AMVEST Oil & Gas, Inc. (a Virginia corporation)
|
|
company)
|
AMVEST West Virginia Coal, LLC. (a West Virginia limited
|
|
Helvetia Coal Company (a Pennsylvania corporation)
|
liability company)
|
|
Island Creek Coal Company (a Delaware corporation)
|
Braxton-Clay Land & Mineral, Inc. (a West Virginia corporation)
|
|
Keystone Coal Mining Corporation (a Pennsylvania corporation)
|
Cardinal States Gathering Company (a Virginia general partnership)
|
|
Knox Energy, LLC. (a Tennessee limited liability company)
|
Central Ohio Coal Company (an Ohio corporation)
|
|
Laurel Run Mining Company (a Virginia corporation)
|
CNX Funding Corporation (a Delaware corporation)
|
|
Leatherwood, Inc. (a Pennsylvania corporation)
|
CNX Gas Company LLC (a Virginia limited liability company)
|
|
Little Eagle Coal Company, L.L.C. (a West Virginia limited liability
|
CNX Gas Corporation (a Delaware corporation)
|
|
company)
|
CNX Land Resources Inc. (a Delaware corporation)
|
|
McElroy Coal Company (a Delaware corporation)
|
CNX Marine Terminals Inc. (formerly Consolidation
|
|
MOB Corporation (a Pennsylvania corporation)
|
Coal Sales Company) (a Delaware corporation)
|
|
Mon River Towing, Inc. (a Pennsylvania corporation)
|
CNX Water Assets LLC (formerly CONSOL of WV LLC) (a West
|
|
Mon-View, LLC (a West Virginia limited liability company)
|
Virginia limited liability company)
|
|
MTB, Inc. (a Delaware corporation)
|
Coalfield Pipeline Company (a Tennessee corporation)
|
|
Nicholas-Clay Land & Mineral, Inc. (a Virginia corporation)
|
Conrhein Coal Company (a Pennsylvania general partnership)
|
|
Peters Creek Mineral Services, Inc. (a Virginia corporation)
|
CONSOL Energy Canada Ltd. (a Canadian corporation)
|
|
Piping and Equipment, Inc. (a Florida corporation)
|
CONSOL Energy Holdings LLC VI (a Delaware limited liability
|
|
Reserve Coal Properties Company (a Delaware corporation)
|
company)
|
|
Rochester & Pittsburgh Coal Company (a Pennsylvania corporation)
|
CONSOL Energy Sales Company (formerly CONSOL Sales
|
|
Southern Ohio Coal Company (a West Virginia corporation)
|
Company) (a Delaware corporation)
|
|
TEAGLE Company, LLC. (a Virginia limited liability company)
|
CONSOL Financial Inc. (a Delaware corporation)
|
|
TECPART Corporation (a Delaware corporation)
|
CONSOL of Canada Inc. (a Delaware corporation)
|
|
Terra Firma Company (a West Virginia corporation)
|
CONSOL of Central Pennsylvania LLC (a Pennsylvania limited
|
|
Terry Eagle Coal Company, L.L.C. (a West Virginia limited liability
|
liability company)
|
|
company)
|
CONSOL of Kentucky Inc. (a Delaware corporation)
|
|
Terry Eagle Limited Partnership (a West Virginia limited
|
CONSOL of Ohio LLC (an Ohio limited liability company)
|
|
partnership)
|
Consol Pennsylvania Coal Company LLC (formerly Consol
|
|
Twin Rivers Towing Company (a Delaware corporation)
|
Pennsylvania Coal Company) (a Delaware limited liability
|
|
Vaughan Railroad Company (a West Virginia corporation)
|
company)
|
|
Windsor Coal Company (a West Virginia corporation)
|
Consolidation Coal Company (a Delaware corporation)
|
|
Wolfpen Knob Development Company (a Virginia corporation)
|
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, 2013
|
|
|
|
|
/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, 2013
|
|
|
|
|
/s/ William J. Lyons
|
|
|
William J. Lyons
|
|
|
Chief Financial Officer and Executive Vice President
(Principal Financial Officer and Principal Accounting Officer)
|
|
|
|
CNX GAS CORPORATION
|
||
|
|
|
|
|
|
|
By:
|
/s/ John M. Reilly
|
|
|
|
Name:
|
John M. Reilly
|
|
|
|
Title:
|
Vice President & Treasurer
|
|
|
|
|
|
|
|
|
PNC BANK, NATIONAL ASSOCIATION
|
||
|
|
|
|
|
|
|
By:
|
/s/ Richard C. Munsick
|
|
|
|
Name:
|
Richard C. Munsick
|
|
|
|
Title:
|
Senior Vice President
|
|
|
|
|
|
|
|
|
BANK OF AMERICA, N.A., as a Lender
|
||
|
|
|
|
|
|
|
By:
|
/s/ Adam H. Fey
|
|
|
|
Name:
|
Adam H. Fey
|
|
|
|
Title:
|
Director
|
|
|
|
|
|
|
|
|
BANK OF MONTREAL, CHICAGO BRANCH
|
||
|
|
|
|
|
|
|
By:
|
/s/ Yaco Uba Kane
|
|
|
|
Name:
|
Yaco Uba Kane
|
|
|
|
Title:
|
Vice President
|
|
|
|
|
|
|
|
|
BOKF, NA dba Bank of Oklahoma, as a Lender
|
||
|
|
|
|
|
|
|
By:
|
/s/ Jason B. Webb
|
|
|
|
Name:
|
Jason B. Webb
|
|
|
|
Title:
|
Vice President
|
|
|
|
|
|
|
|
|
Branch Banking and Trust Company, as a Lender
|
||
|
|
|
|
|
|
|
By:
|
/s/ Ryan K. Michael
|
|
|
|
Name:
|
Ryan K. Michael
|
|
|
|
Title:
|
Senior Vice President
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital One, National Association, as a Lender
|
||
|
|
|
|
|
|
|
By:
|
/s/ Nancy M. Mak
|
|
|
|
Name:
|
Nancy M. Mak
|
|
|
|
Title:
|
Vice President
|
|
|
|
|
|
|
|
|
CIBC Inc., as a Lender
|
||
|
|
|
|
|
|
|
By:
|
/s/ Trudy Nelson
|
|
|
|
Name:
|
Trudy Nelson
|
|
|
|
Title:
|
Authorized Signatory
|
|
|
|
|
|
|
|
|
By:
|
/s/ Richard Antl
|
|
|
|
Name:
|
Richard Antl
|
|
|
|
Title:
|
Authorized Signatory
|
|
|
|
|
|
|
|
|
COMERICA BANK, as a Lender
|
||
|
|
|
|
|
|
|
By:
|
/s/ John S. Lesikar
|
|
|
|
Name:
|
John S. Lesikar
|
|
|
|
Title:
|
Assistant Vice President
|
|
|
|
|
|
|
|
|
COMMONWEALTH BANK OF AUSTRALIA, as a Lender
|
||
|
|
|
|
|
|
|
By:
|
/s/ Greg A. Calone
|
|
|
|
Name:
|
Greg A. Calone
|
|
|
|
Title:
|
Head of Natural Resources - Americas
|
|
|
|
|
|
|
|
|
COMPASS BANK, as a Lender
|
||
|
|
|
|
|
|
|
By:
|
/s/ Trey Lewis
|
|
|
|
Name:
|
Trey Lewis
|
|
|
|
Title:
|
Assistant Vice President
|
|
|
|
|
|
|
|
|
Credit Agricole Corporate and Investment Bank, as a Lender
|
||
|
|
|
|
|
|
|
By:
|
/s/ Matthias Guillet
|
|
|
|
Name:
|
Matthias Guillet
|
|
|
|
Title:
|
Director
|
|
|
|
|
|
|
|
|
By:
|
/s/ Melvin Smith
|
|
|
|
Name:
|
Melvin Smith
|
|
|
|
Title:
|
Vice President
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fifth Third Bank, as a Lender
|
||
|
|
|
|
|
|
|
By:
|
/s/ Jim Janovsky
|
|
|
|
Name:
|
Jim Janovsky
|
|
|
|
Title:
|
Vice President
|
|
|
|
|
|
|
|
|
First National Bank of Pennsylvania, as a Lender
|
||
|
|
|
|
|
|
|
By:
|
/s/ Anthony M. Marfisi
|
|
|
|
Name:
|
Anthony M. Marfisi
|
|
|
|
Title:
|
Senior Vice President and Regional Manager
|
|
|
|
|
|
|
|
|
GOLDMAN SACHS BANK USA, as a Lender
|
||
|
|
|
|
|
|
|
By:
|
/s/ Ashwin Ramakrishna
|
|
|
|
Name:
|
Ashwin Ramakrishna
|
|
|
|
Title:
|
Authorized Signatory
|
|
|
|
|
|
|
|
|
ING CAPITAL LLC, as a Lender
|
||
|
|
|
|
|
|
|
By:
|
/s/ Charles Hall
|
|
|
|
Name:
|
Charles Hall
|
|
|
|
Title:
|
Managing Director
|
|
|
|
|
|
|
|
|
JPMorgan Chase Bank, N.A., as a Lender
|
||
|
|
|
|
|
|
|
By:
|
/s/ Jo Linda Papadakis
|
|
|
|
Name:
|
Jo Linda Papadakis
|
|
|
|
Title:
|
Authorized Officer
|
|
|
|
|
|
|
|
|
NATIXIS, as a Lender
|
||
|
|
|
|
|
|
|
By:
|
/s/ Liana Tchernysheva
|
|
|
|
Name:
|
Liana Tchernysheva
|
|
|
|
Title:
|
Managing Director
|
|
|
|
|
|
|
|
|
By:
|
/s/ Donovan C. Broussard
|
|
|
|
Name:
|
Donovan C. Broussard
|
|
|
|
Title:
|
Managing Director
|
|
|
|
|
|
|
|
|
PNC BANK, NATIONAL ASSOCIATION, as a Lender Individually and as Administrative Agent
|
||
|
|
|
|
|
|
|
By:
|
/s/ Richard C. Munsick
|
|
|
|
Name:
|
Richard C. Munsick
|
|
|
|
Title:
|
Senior Vice President
|
|
|
|
|
|
|
|
|
Fifth Third Bank, as a Lender
|
||
|
|
|
|
|
|
|
By:
|
/s/ Jim Janovsky
|
|
|
|
Name:
|
Jim Janovsky
|
|
|
|
Title:
|
Vice President
|
|
|
|
|
|
|
|
|
First National Bank of Pennsylvania, as a Lender
|
||
|
|
|
|
|
|
|
By:
|
/s/ Anthony M. Marfisi
|
|
|
|
Name:
|
Anthony M. Marfisi
|
|
|
|
Title:
|
Senior Vice President and Regional Manager
|
|
|
|
|
|
|
|
|
GOLDMAN SACHS BANK USA, as a Lender
|
||
|
|
|
|
|
|
|
By:
|
/s/ Ashwin Ramakrishna
|
|
|
|
Name:
|
Ashwin Ramakrishna
|
|
|
|
Title:
|
Authorized Signatory
|
|
|
|
|
|
|
|
|
ING CAPITAL LLC, as a Lender
|
||
|
|
|
|
|
|
|
By:
|
/s/ Charles Hall
|
|
|
|
Name:
|
Charles Hall
|
|
|
|
Title:
|
Managing Director
|
|
|
|
|
|
|
|
|
JPMorgan Chase Bank, N.A., as a Lender
|
||
|
|
|
|
|
|
|
By:
|
/s/ Jo Linda Papadakis
|
|
|
|
Name:
|
Jo Linda Papadakis
|
|
|
|
Title:
|
Authorized Officer
|
|
|
|
|
|
|
|
|
NATIXIS, as a Lender
|
||
|
|
|
|
|
|
|
By:
|
/s/ Liana Tchernysheva
|
|
|
|
Name:
|
Liana Tchernysheva
|
|
|
|
Title:
|
Managing Director
|
|
|
|
|
|
|
|
|
By:
|
/s/ Donovan C. Broussard
|
|
|
|
Name:
|
Donovan C. Broussard
|
|
|
|
Title:
|
Managing Director
|
|
|
|
|
|
|
|
|
PNC BANK, NATIONAL ASSOCIATION, as a Lender Individually and as Administrative Agent
|
||
|
|
|
|
|
|
|
By:
|
/s/ Richard C. Munsick
|
|
|
|
Name:
|
Richard C. Munsick
|
|
|
|
Title:
|
Senior Vice President
|
|
|
Soverign Bank, as a Lender
|
||
|
|
|
|
|
|
|
By:
|
/s/ Daniela Hofer-Gautschi
|
|
|
|
Name:
|
Daniela Hofer-Gautschi
|
|
|
|
Title:
|
Vice President
|
|
|
|
|
|
|
|
|
TD Bank, N.A., as a Lender
|
||
|
|
|
|
|
|
|
By:
|
/s/ Marla Willner
|
|
|
|
Name:
|
Marla Willner
|
|
|
|
Title:
|
Senior Vice President
|
|
|
|
|
|
|
|
|
The Bank of Nova Scotia, as a Lender
|
||
|
|
|
|
|
|
|
By:
|
/s/ Frank Sandler
|
|
|
|
Name:
|
Frank Sandler
|
|
|
|
Title:
|
Managing Director
|
|
|
|
|
|
|
|
|
The Bank of Tokyo-Mitsubishi UFJ, Ltd., as a Lender
|
||
|
|
|
|
|
|
|
By:
|
/s/ Andrew Oram
|
|
|
|
Name:
|
Andrew Oram
|
|
|
|
Title:
|
Managing Director
|
|
|
|
|
|
|
|
|
The Huntington National Bank, as a Lender
|
||
|
|
|
|
|
|
|
By:
|
/s/ Chad A. Lowe
|
|
|
|
Name:
|
Chad A. Lowe
|
|
|
|
Title:
|
Vice President
|
|
|
|
|
|
|
|
|
THE ROYAL BANK OF SCOTLAND plc, as a Lender
|
||
|
|
|
|
|
|
|
By:
|
/s/ Sanjay Remond
|
|
|
|
Name:
|
Sanjay Remond
|
|
|
|
Title:
|
Authorised Signatory
|
|
|
|
|
|
|
|
|
TriState Capital Bank, as a Lender
|
||
|
|
|
|
|
|
|
By:
|
/s/ Paul J. Oris
|
|
|
|
Name:
|
Paul J. Oris
|
|
|
|
Title:
|
Senior Vice President
|
|
|
Union Bank, as a Lender
|
||
|
|
|
|
|
|
|
By:
|
/s/ Bradley Kraus
|
|
|
|
Name:
|
Bradley Kraus
|
|
|
|
Title:
|
Investment Banking Officer
|
|
|
|
|
|
|
|
|
U.S. Bank National Association, as a Lender
|
||
|
|
|
|
|
|
|
By:
|
/s/ Tyler Fauerback
|
|
|
|
Name:
|
Tyler Fauerbach
|
|
|
|
Title:
|
Vice President
|
|
|
|
|
|
|
|
|
Wells Fargo, N.A., as a Lender
|
||
|
|
|
|
|
|
|
By:
|
/s/ Joseph Rottinghaus
|
|
|
|
Name:
|
Joseph Rottinghaus
|
|
|
|
Title:
|
Assistant Vice President
|
(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, 2013
|
|
|
|
|
/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, 2013
|
|
|
|
|
/s/ William J. Lyons
|
|
|
William J. Lyons
|
|
|
Chief Financial Officer and Executive Vice President
(Principal Financial Officer and Principal Accounting Officer)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
6
|
|
|
—
|
|
|
No
|
|
No
|
|
—
|
|
|
—
|
|
|
—
|
|
Bailey
|
|
36-07230
|
|
74
|
|
|
—
|
|
|
5
|
|
|
—
|
|
|
2
|
|
|
$
|
569
|
|
|
—
|
|
|
No
|
|
No
|
|
10
|
|
|
2
|
|
|
4
|
|
Blacksville 2
|
|
46-01968
|
|
183
|
|
|
—
|
|
|
5
|
|
|
—
|
|
|
1
|
|
|
$
|
482
|
|
|
1
|
|
|
No
|
|
No
|
|
27
|
|
|
2
|
|
|
5
|
|
Buchanan
|
|
44-04856
|
|
141
|
|
|
—
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
$
|
627
|
|
|
1
|
|
|
No
|
|
No
|
|
34
|
|
|
4
|
|
|
4
|
|
Central Repair Shop
|
|
46-03240
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
No
|
|
No
|
|
—
|
|
|
—
|
|
|
—
|
|
Enlow Fork
|
|
36-07416
|
|
51
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
$
|
94
|
|
|
—
|
|
|
No
|
|
No
|
|
11
|
|
|
2
|
|
|
3
|
|
Ireland Dock Loadout
|
|
46-01438
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
No
|
|
No
|
|
6
|
|
|
—
|
|
|
—
|
|
Keystone Cleaning Plant
|
|
36-08540
|
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
1
|
|
|
—
|
|
|
No
|
|
No
|
|
—
|
|
|
—
|
|
|
—
|
|
Loveridge
|
|
46-01433
|
|
183
|
|
|
—
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
$
|
1,218
|
|
|
—
|
|
|
No
|
|
No
|
|
26
|
|
|
3
|
|
|
2
|
|
McElroy
|
|
46-01437
|
|
305
|
|
|
—
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
$
|
962
|
|
|
—
|
|
|
No
|
|
No
|
|
27
|
|
|
4
|
|
|
4
|
|
Miller Creek PP #1
|
|
46-05890
|
|
15
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
9
|
|
|
—
|
|
|
No
|
|
No
|
|
2
|
|
|
—
|
|
|
2
|
|
Minway Surface
|
|
46-06089
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
1
|
|
|
—
|
|
|
No
|
|
No
|
|
—
|
|
|
—
|
|
|
—
|
|
MT-34UG
|
|
46-09424
|
|
9
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
9
|
|
|
—
|
|
|
No
|
|
No
|
|
—
|
|
|
—
|
|
|
—
|
|
Peach Orchard Prep Plant
|
|
46-08376
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
No
|
|
No
|
|
—
|
|
|
—
|
|
|
—
|
|
Robinson Run
|
|
46-01318
|
|
197
|
|
|
—
|
|
|
8
|
|
|
—
|
|
|
1
|
|
|
$
|
928
|
|
|
1
|
|
|
No
|
|
No
|
|
27
|
|
|
3
|
|
|
1
|
|
Shoemaker
|
|
46-01436
|
|
162
|
|
|
—
|
|
|
11
|
|
|
—
|
|
|
—
|
|
|
$
|
580
|
|
|
—
|
|
|
No
|
|
No
|
|
24
|
|
|
1
|
|
|
7
|
|
Wiley Creek (MT-13/500)
|
|
46-09185
|
|
9
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
9
|
|
|
—
|
|
|
No
|
|
No
|
|
1
|
|
|
—
|
|
|
—
|
|
Wiley Surface(MT34/Peg Fork)
|
|
46-09035
|
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
5
|
|
|
—
|
|
|
No
|
|
No
|
|
1
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Inactive Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Amonate
|
|
46-05449
|
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
No
|
|
No
|
|
—
|
|
|
—
|
|
|
—
|
|
Big Branch #1Belt/Spruce Creek
|
|
46-09177
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
1
|
|
|
—
|
|
|
No
|
|
No
|
|
—
|
|
|
—
|
|
|
—
|
|
Bronzite II (MT-41)
|
|
46-09307
|
|
7
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
20
|
|
|
—
|
|
|
No
|
|
No
|
|
2
|
|
|
—
|
|
|
1
|
|
Bronzite III (Jacobs)
|
|
46-05978
|
|
12
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
23
|
|
|
—
|
|
|
No
|
|
No
|
|
3
|
|
|
—
|
|
|
2
|
|
Emery
|
|
42-00079
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
2
|
|
|
—
|
|
|
No
|
|
No
|
|
1
|
|
|
—
|
|
|
2
|
|
Fola Surface
|
|
46-08377
|
|
3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
3
|
|
|
—
|
|
|
No
|
|
No
|
|
1
|
|
|
—
|
|
|
1
|
|
Ike Fork (5 Block Mine)
|
|
46-09420
|
|
9
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
$
|
13
|
|
|
—
|
|
|
No
|
|
No
|
|
2
|
|
|
2
|
|
|
—
|
|
Impoundment 14-N
|
|
36-08094
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
No
|
|
No
|
|
—
|
|
|
—
|
|
|
—
|
|
Lick Branch
|
|
46-08676
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
2
|
|
|
—
|
|
|
No
|
|
No
|
|
1
|
|
|
—
|
|
|
—
|
|
Little Eagle Mine #1
|
|
46-08560
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
No
|
|
No
|
|
—
|
|
|
—
|
|
|
—
|
|
Meigs #31 Mine
|
|
33-01172
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
No
|
|
No
|
|
—
|
|
|
—
|
|
|
—
|
|
Miles Branch
|
|
44-03932
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
No
|
|
No
|
|
—
|
|
|
—
|
|
|
—
|
|
Mine 84
|
|
36-00958
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
No
|
|
No
|
|
—
|
|
|
—
|
|
|
—
|
|
Muskingum
|
|
33-00989
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
No
|
|
No
|
|
—
|
|
|
—
|
|
|
—
|
|
Powellton/Bridge Fork
|
|
46-08889
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
No
|
|
No
|
|
—
|
|
|
—
|
|
|
—
|
|
Reclamation #061
|
|
33-00962
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
No
|
|
No
|
|
—
|
|
|
—
|
|
|
—
|
|
Rend Lake
|
|
11-00601
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
No
|
|
No
|
|
—
|
|
|
—
|
|
|
—
|
|
Robena Prep
|
|
36-04175
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
No
|
|
No
|
|
1
|
|
|
1
|
|
|
—
|
|
Rock Lick
|
|
46-09171
|
|
6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
70
|
|
|
—
|
|
|
No
|
|
No
|
|
8
|
|
|
1
|
|
|
1
|
|
Terry Eagle PP #1
|
|
46-02295
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
No
|
|
No
|
|
—
|
|
|
—
|
|
|
—
|
|
Twin Branch Surface
|
|
46-09075
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
No
|
|
No
|
|
—
|
|
|
—
|
|
|
—
|
|
Winoc Prep Plant
|
|
46-08172
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
No
|
|
No
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
1,377
|
|
|
—
|
|
|
42
|
|
|
—
|
|
|
5
|
|
|
$
|
5,628
|
|
|
3
|
|
|
|
|
|
|
215
|
|
|
25
|
|
|
39
|
|
Mine or Operating Name/MSHA Identification Number
|
|
Contests of Citations, Orders
(as of 12.31.12)
(a)
|
|
Contests of Proposed Penalties
(as of 12.31.12)
(b)
|
|
Complaints for Compensation
(as of 12.31.12)
(c)
|
|
Complaints of Discharge, Discrimination or Interference
(as of 12.31.12)
(d)
|
|
Applications for Temporary Relief
(as of 12.31.12)
(e)
|
|
Appeals of Judges' Decisions or Order
(as of 12.31.12)
(f)
|
|||||||||||
|
|
|
|||||||||||||||||||||
|
|
Dockets
|
|
Citations
|
|
|
|
|
|||||||||||||||
Active Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Alma No. 1 Mine
|
|
46-09277
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Bailey
|
|
36-07230
|
|
—
|
|
|
10
|
|
|
34
|
|
|
—
|
|
|
4
|
|
|
—
|
|
|
—
|
|
Blacksville 2
|
|
46-01968
|
|
—
|
|
|
27
|
|
|
288
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Buchanan
|
|
44-04856
|
|
—
|
|
|
44
|
|
|
421
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
—
|
|
Central Repair Shop
|
|
46-03240
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Enlow Fork
|
|
36-07416
|
|
—
|
|
|
11
|
|
|
59
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Ireland Dock Loadout
|
|
46-01438
|
|
—
|
|
|
6
|
|
|
10
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Keystone Cleaning Plant
|
|
36-08540
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Loveridge
|
|
46-01433
|
|
—
|
|
|
26
|
|
|
177
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
McElroy
|
|
46-01437
|
|
—
|
|
|
27
|
|
|
324
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Miller Creek PP #1
|
|
46-05890
|
|
—
|
|
|
2
|
|
|
7
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Minway Surface
|
|
46-06089
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Peach Orchard Prep Plant
|
|
46-08376
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Robinson Run
|
|
46-01318
|
|
—
|
|
|
27
|
|
|
524
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
Shoemaker
|
|
46-01436
|
|
—
|
|
|
24
|
|
|
205
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Wiley Creek (MT‑13/500)
|
|
46-09185
|
|
—
|
|
|
1
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Wiley Surface(MT34/Peg Fork)
|
|
46-09035
|
|
—
|
|
|
1
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Inactive Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Amonate
|
|
46-05449
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Big Branch #1Belt/Spruce Creek
|
|
46-09177
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Bronzite II (MT‑41)
|
|
46-09307
|
|
—
|
|
|
2
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Bronzite III (Jacobs)
|
|
46-05978
|
|
—
|
|
|
3
|
|
|
14
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Emery
|
|
42-00079
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Fola Surface
|
|
46-08377
|
|
—
|
|
|
1
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Ike Fork (5 Block Mine)
|
|
46-09420
|
|
—
|
|
|
2
|
|
|
—
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Impoundment 14‑N
|
|
36-08094
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Jones Fork E‑3(Sold)
|
|
15-18589
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Jones Fork Prep Plant(Sold)
|
|
15-17021
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Laurel Fork
|
|
46-09084
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Lick Branch
|
|
46-08676
|
|
—
|
|
|
1
|
|
|
—
|
|
|
3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Little Eagle Mine #1
|
|
46-08560
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Meigs #31 Mine
|
|
33-01172
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Miles Branch
|
|
44-03932
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Mine 84
|
|
36-00958
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Muskingum
|
|
33-00989
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Powellton/Bridge Fork
|
|
46-08889
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Reclamation #061
|
|
33-00962
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Rend Lake
|
|
11-00601
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Robena Prep
|
|
36-04175
|
|
—
|
|
|
1
|
|
|
—
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Rock Lick
|
|
46-09171
|
|
—
|
|
|
8
|
|
|
38
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Terry Eagle PP #1
|
|
46-02295
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Wiley (MT‑11)
|
|
46-09138
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Winoc Prep Plant
|
|
46-08172
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
—
|
|
|
226
|
|
|
2,111
|
|
|
11
|
|
|
6
|
|
|
—
|
|
|
1
|
|
|
|
Net Reserves
|
|
Future Net Revenue (M$)
|
||||||||
|
|
Oil
|
|
Gas
|
|
|
|
Present Worth
|
||||
Category
|
|
(MBBL)
|
|
(MMCF)
|
|
Total
|
|
at 10%
|
||||
Proved Developed Producing
|
|
1,579.2
|
|
|
2,017,020.6
|
|
|
4,889,994.6
|
|
|
2,228,780.8
|
|
Proved Developed Non-Producing
|
|
—
|
|
|
109,309.0
|
|
|
313,862.4
|
|
|
142,341.7
|
|
Proved Undeveloped
|
|
—
|
|
|
1,344,222.3
|
|
|
2,663,075.8
|
|
|
490,185.7
|
|
Total Proved
|
|
1,579.2
|
|
|
3,470,552.0
|
|
|
7,866,934.0
|
|
|
2,861,308.5
|
|
|
|
|
NETHERLAND, SEWELL & ASSOCIATES, INC.
|
|
|
|
|
Texas Registered Engineering Firm F-002699
|
|
|
|
|
|
|
|
|
|
By:
|
/s/ C.H. (Scott) Rees III
|
|
|
|
|
C.H. (Scott) Rees III, P.E.
|
|
|
|
|
Chairman and Chief Executive Officer
|
|
|
|
|
|
By:
|
/s/ Richard B. Talley, Jr.
|
|
By:
|
/s/ David E. Nice
|
|
Richard B. Talley, Jr., P.E. 102425
|
|
|
David E. Nice, P.G. 346
|
|
Vice President
|
|
|
Vice President
|
|
|
|
|
|
Date Signed: January 31, 2012
|
|
Date Signed: January 31, 2012
|
||
|
|
|
|
|
RBT:DEG
|
|
|
|
SUMMARY OF NET RESERVES AND FUTURE REVENUE
|
|||||||||||||||||||||||||||
CONSOL ENERGY INC. INTEREST
|
|||||||||||||||||||||||||||
AS OF DECEMBER 31, 2011
|
|||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
|
|
|
|
|
|||||||||
|
|
Net Reserves
|
|
Future
|
|
Operating
|
|
Production
|
|
Ad Valorem
|
|
Including
|
|
Future Net Revenue (M$)
|
|||||||||||||
|
|
Oil
|
|
Gas
|
|
Gross Revenue
|
|
Expense
|
|
Tax
|
|
Tax
|
|
Abandonment
|
|
|
|
Discounted
|
|||||||||
Category
|
|
(MBBL)
|
|
(MMCF)
|
|
(M$)
|
|
(M$)
|
|
(M$)
|
|
(M$)
|
|
(M$)
|
|
Total
|
|
At 10%
|
|||||||||
Proved Developed Producing
|
|
1,579.2
|
|
|
2,017,020.6
|
|
|
8,432,550.0
|
|
|
3,075,809.5
|
|
|
240,241.5
|
|
|
73,429.9
|
|
|
265,226.2
|
|
|
4,777,841.5
|
|
|
2,112,065.0
|
|
Gas Contract Revenue
|
|
—
|
|
|
—
|
|
|
184,724.9
|
|
|
72,571.8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
112,153.1
|
|
|
116,715.8
|
|
Total Proved Developed Producing
|
|
1,579.2
|
|
|
2,017,020.6
|
|
|
8,617,274.9
|
|
|
3,148,381.3
|
|
|
240,241.5
|
|
|
73,429.9
|
|
|
265,226.2
|
|
|
4,889,994.6
|
|
|
2,228,780.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Proved Developed Non-Producing
|
|
—
|
|
|
109,309.0
|
|
|
468,840.1
|
|
|
119,596.5
|
|
|
9,549.8
|
|
|
2,746.6
|
|
|
23,084.8
|
|
|
313,862.4
|
|
|
142,341.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Proved Undeveloped
|
|
—
|
|
|
1,344,222.3
|
|
|
5,718,283.5
|
|
|
1,519,013.1
|
|
|
119,367.2
|
|
|
30,309.4
|
|
|
1,386,518.6
|
|
|
2,663,075.8
|
|
|
490,185.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||
Total Proved
|
|
1,579.2
|
|
|
3,470,552.0
|
|
|
14,804,399.0
|
|
|
4,786,991.0
|
|
|
369,158.5
|
|
|
106,485.9
|
|
|
1,674,829.3
|
|
|
7,866,934.0
|
|
|
2,861,308.5
|
|