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Peabody Energy 10-K 2007
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
Form 10-K/A
(Amendment No. 1)
     
þ
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
    For the Fiscal Year Ended December 31, 2006
 
or
 
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number 1-16463
 
(PEABODY LOGO)
Peabody Energy Corporation
(Exact name of registrant as specified in its charter)
     
Delaware   13-4004153
(State or other jurisdiction of incorporation or organization)   (I.R.S. Employer Identification No.)
 
701 Market Street, St. Louis, Missouri
  63101
(Address of principal executive offices)   (Zip Code)
(314) 342-3400
Registrant’s telephone number, including area code
Securities Registered Pursuant to Section 12(b) of the Act:
     
Title of Each Class   Name of Each Exchange on Which Registered
     
Common Stock, par value $0.01 per share
Preferred Share Purchase Rights
  New York Stock Exchange
New York Stock Exchange
Securities Registered Pursuant to Section 12(g) of the Act:
None
      Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act     Yes þ          No o
      Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act     Yes o          No þ
      Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     Yes þ          No o
      Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.     þ
      Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ          Accelerated filer o          Non-accelerated filer     o
      Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the of the Exchange Act)     Yes o          No þ
      Aggregate market value of the voting stock held by non-affiliates (shareholders who are not directors or executive officers) of the Registrant, calculated using the closing price on June 30, 2006: Common Stock, par value $0.01 per share, $14.6 billion.
      Number of shares outstanding of each of the Registrant’s classes of Common Stock, as of February 16, 2007: Common Stock, par value $0.01 per share, 264,685,954 shares outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
      Portions of the Company’s Proxy Statement to be filed with the Securities and Exchange Commission in connection with the Company’s Annual Meeting of Stockholders to be held on May 1, 2007 (the “Company’s 2007 Proxy Statement”) are incorporated by reference into Part III hereof. Other documents incorporated by reference in this report are listed in the Exhibit Index of this Form 10-K.
 
 


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Explanatory Note
           Peabody Energy Corporation is filing this Amendment No. 1 on Form 10-K/A (“Amended Filing”) in order to amend our Annual Report on Form 10-K for the fiscal year ended December 31, 2006, originally filed February 28, 2007 (“Original Filing”), to provide additional disclosures concerning our practices and policies related to exploration and drilling costs, advanced stripping costs, and coal reserve estimates. The expanded disclosure is based on correspondence with the Securities and Exchange Commission (“SEC”) in conjunction with the SEC’s review of our Original Filing. The following items were impacted by these expanded disclosures:
  •     Part I. Item 1A. Risk Factors — We added a new risk factor on page 12 labeled “Diversity in interpretation and application of accounting literature in the mining industry may impact our reported financial results”;
 
  •  Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates — We added new critical accounting policies on page 35 regarding the treatment of “Exploration and Drilling Costs” and “Advance Stripping Costs”; and
 
  •  Part II. Item 8. Financial Statements and Supplementary Data and Part IV. Exhibits and Financial Statement Schedules —Consolidated Financial Statements — We expanded the description of our “Inventories” and “Property, Plant, Equipment and Mine Development” policies contained in Note 1, Summary of Significant Accounting Policies.
We are also including Part I. Item 2. Properties to reflect the correction of footing errors for certain category totals within the coal reserve tables; total proven and probable coal reserves remain unchanged at 10.2 billion tons. Except as described in this note, this Amended Filing does not modify or update the disclosures in our Original Filing. See our Quarterly Reports on Form 10-Q and Current Reports on Form 8-K filed with the SEC subsequent to our Original Filing for updated information.
We are also including new certifications of the principal executive officer and principal financial officer as exhibits to this Amended Filing.


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CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS
      This report includes statements of our expectations, intentions, plans and beliefs that constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 and are intended to come within the safe harbor protection provided by those sections. These statements relate to future events or our future financial performance, including, without limitation, the section captioned “Outlook.” We use words such as “anticipate,” “believe,” “expect,” “may,” “project,” “will” or other similar words to identify forward-looking statements.
      Without limiting the foregoing, all statements relating to our future outlook, anticipated capital expenditures, future cash flows and borrowings, and sources of funding are forward-looking statements. These forward-looking statements are based on numerous assumptions that we believe are reasonable, but are subject to a wide range of uncertainties and business risks and actual results may differ materially from those discussed in these statements. Among the factors that could cause actual results to differ materially are:
  •  ability to renew sales contracts;
 
  •  reductions of purchases by major customers;
 
  •  transportation performance and costs, including demurrage;
 
  •  geology, equipment and other risks inherent to mining;
 
  •  weather;
 
  •  legislation, regulations and court decisions;
 
  •  new environmental requirements affecting the use of coal including mercury and carbon dioxide related limitations;
 
  •  changes in postretirement benefit and pension obligations;
 
  •  changes to contribution requirements to multi-employer benefit funds;
 
  •  availability, timing of delivery and costs of key supplies, capital equipment or commodities such as diesel fuel, steel, explosives and tires;
 
  •  replacement of coal reserves;
 
  •  price volatility and demand, particularly in higher-margin products and in our trading and brokerage businesses;
 
  •  performance of contractors, third-party coal suppliers or major suppliers of mining equipment or supplies;
 
  •  negotiation of labor contracts, employee relations and workforce availability;
 
  •  availability and costs of credit, surety bonds and letters of credit;
 
  •  risks associated with customer contracts, including credit and performance risk;
 
  •  the effects of acquisitions or divestitures, including integration of new acquisitions;
 
  •  economic strength and political stability of countries in which we have operations or serve customers;
 
  •  risks associated with our Btu conversion or generation development initiatives;
 
  •  risks associated with the conversion of our current information systems;
 
  •  growth of domestic and international coal and power markets;
 
  •  coal’s market share of electricity generation;

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  •  prices of fuels which compete with or impact coal usage, such as oil or natural gas;
 
  •  future worldwide economic conditions;
 
  •  successful implementation of business strategies;
 
  •  variation in revenues related to synthetic fuel production due to expiration of related tax credits at the end of 2007;
 
  •  the effects of changes in currency exchange rates, primarily the Australian dollar;
 
  •  inflationary trends, including those impacting materials used in our business;
 
  •  interest rate changes;
 
  •  litigation, including claims not yet asserted;
 
  •  terrorist attacks or threats;
 
  •  impacts of pandemic illnesses;
 
  •  other factors, including those discussed in Legal Proceedings, set forth in Item 3 of the Original Filing and Risk Factors, set forth in Item 1A of this report.
      When considering these forward-looking statements, you should keep in mind the cautionary statements in this document and in our other SEC filings. We do not undertake any obligation to update these statements, except as required by federal securities laws.

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TABLE OF CONTENTS
             
        Page
         
 PART I.
   Risk Factors     2  
   Properties     12  
 PART II.
   Management’s Discussion and Analysis of Financial Condition and Results of Operations     21  
   Financial Statements and Supplementary Data     45  
 PART IV.
   Exhibits and Financial Statement Schedules     46  
 Consent of Ernst & Young LLP
 302 Certification of Chief Executive Officer
 302 Certification of Chief Financial Officer
 906 Certification of Chief Executive Officer
 906 Certification of Chief Financial Officer

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  Note:  The words “we,” “our,” “Peabody” or “the Company” as used in this report, refer to Peabody Energy Corporation or its applicable subsidiary or subsidiaries.
PART I
Item 1A.     Risk Factors.
If a substantial portion of our long-term coal supply agreements terminate, our revenues and operating profits could suffer if we were unable to find alternate buyers willing to purchase our coal on comparable terms to those in our contracts.
      Most of our sales are made under coal supply agreements, which are important to the stability and profitability of our operations. The execution of a satisfactory coal supply agreement is frequently the basis on which we undertake the development of coal reserves required to be supplied under the contract. For the year ended December 31, 2006, 90% of our sales volume was sold under long-term coal supply agreements. At December 31, 2006, our coal supply agreements had remaining terms ranging from one to 19 years and an average volume-weighted remaining term of approximately 5 years.
      Many of our coal supply agreements contain provisions that permit the parties to adjust the contract price upward or downward at specified times. We may adjust these contract prices based on inflation or deflation and/or changes in the factors affecting the cost of producing coal, such as taxes, fees, royalties and changes in the laws regulating the mining, production, sale or use of coal. In a limited number of contracts, failure of the parties to agree on a price under those provisions may allow either party to terminate the contract. We sometimes experience a reduction in coal prices in new long-term coal supply agreements replacing some of our expiring contracts. Coal supply agreements also typically contain force majeure provisions allowing temporary suspension of performance by us or the customer during the duration of specified events beyond the control of the affected party. Most coal supply agreements contain provisions requiring us to deliver coal meeting quality thresholds for certain characteristics such as Btu, sulfur content, ash content, grindability and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, the rejection of deliveries or termination of the contracts. Moreover, some of these agreements permit the customer to terminate the contract if transportation costs, which our customers typically bear, increase substantially. In addition, some of these contracts allow our customers to terminate their contracts in the event of changes in regulations affecting our industry that increase the price of coal beyond specified limits.
      The operating profits we realize from coal sold under supply agreements depend on a variety of factors. In addition, price adjustment and other provisions may increase our exposure to short-term coal price volatility provided by those contracts. If a substantial portion of our coal supply agreements were modified or terminated, we could be materially adversely affected to the extent that we are unable to find alternate buyers for our coal at the same level of profitability. Market prices for coal vary by mining region and country. As a result, we cannot predict the future strength of the coal market overall or by mining region and cannot assure you that we will be able to replace existing long-term coal supply agreements at the same prices or with similar profit margins when they expire. In addition, one of our largest coal supply agreements is the subject of ongoing litigation and arbitration.

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The loss of, or significant reduction in, purchases by our largest customers could adversely affect our revenues.
      For the year ended December 31, 2006, we derived 22% of our total coal revenues from sales to our five largest customers. At December 31, 2006, we had 123 coal supply agreements with these customers expiring at various times from 2007 to 2016. We are currently discussing the extension of existing agreements or entering into new long-term agreements with some of these customers, but these negotiations may not be successful and those customers may not continue to purchase coal from us under long-term coal supply agreements. If a number of these customers significantly reduce their purchases of coal from us, or if we are unable to sell coal to them on terms as favorable to us as the terms under our current agreements, our financial condition and results of operations could suffer materially.
If transportation for our coal becomes unavailable or uneconomic for our customers, our ability to sell coal could suffer.
      Transportation costs represent a significant portion of the total cost of coal and the cost of transportation is a critical factor in a customer’s purchasing decision. Increases in transportation costs and the lack of sufficient rail and port capacity could lead to reduced coal sales. As of December 31, 2006, certain coal supply agreements, which account for less than 5% of our tons sold, permit the customer to terminate the contract if the cost of transportation increases by an amount over specified levels in any given 12-month period.
      Coal producers depend upon rail, barge, trucking, overland conveyor and ocean-going vessels to deliver coal to markets. While our coal customers typically arrange and pay for transportation of coal from the mine or port to the point of use, disruption of these transportation services because of weather-related problems, infrastructure damage, strikes, lock-outs, lack of fuel or maintenance items, transportation delays or other events could temporarily impair our ability to supply coal to our customers and thus could adversely affect our results of operations. For example, two primary railroads serve the Powder River Basin mines. Due to the high volume of coal shipped from all Powder River Basin mines, the loss of access to rail capacity could create temporary congestion on the rail systems servicing that region. We are also susceptible to port congestion and demurrage fees. In Australia, we export our Queensland production from Dalrymple Bay Coal Terminal and the Ports of Gladstone and Brisbane. We export our New South Wales production from the Ports of Newcastle and Kembla.
Risks inherent to mining could increase the cost of operating our business.
      Our mining operations are subject to conditions that can impact the safety of our workforce, or delay coal deliveries or increase the cost of mining at particular mines for varying lengths of time. These conditions include fires and explosions from methane gas or coal dust; accidental minewater discharges; weather, flooding and natural disasters; unexpected maintenance problems; key equipment failures; variations in coal seam thickness; variations in the amount of rock and soil overlying the coal deposit; variations in rock and other natural materials and variations in geologic conditions. We maintain insurance policies that provide limited coverage for some of these risks, although there can be no assurance that these risks would be fully covered by our insurance policies. Despite our efforts, significant mine accidents could occur and have a substantial impact.
Our mining operations are extensively regulated, which imposes significant costs on us, and future regulations and developments could increase those costs or limit our ability to produce coal.
      Federal, state and local authorities regulate the coal mining industry with respect to matters such as employee health and safety, permitting and licensing requirements, air quality standards, water pollution, plant and wildlife protection, reclamation and restoration of mining properties after mining is completed, the discharge of materials into the environment, surface subsidence from underground mining and the effects that mining has on groundwater quality and availability. In addition, significant legislation mandating specified benefits for retired coal miners affects our industry. Numerous governmental permits

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and approvals are required for mining operations. We are required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed exploration for or production of coal may have upon the environment. The costs, liabilities and requirements associated with these regulations may be costly and time-consuming and may delay commencement or continuation of exploration or production. The possibility exists that new legislation and/or regulations and orders related to the environment or employee health and safety may be adopted and may materially adversely affect our mining operations, our cost structure and/or our customers’ ability to use coal. New legislation or administrative regulations (or judicial interpretations of existing laws and regulations), including proposals related to the protection of the environment that would further regulate and tax the coal industry, may also require us or our customers to change operations significantly or incur increased costs. The majority of our coal supply agreements contain provisions that allow a purchaser to terminate its contract if legislation is passed that either restricts the use or type of coal permissible at the purchaser’s plant or results in specified increases in the cost of coal or its use. These factors and legislation, if enacted, could have a material adverse effect on our financial condition and results of operations.
      According to the Department of Energy’s Energy Information Administration, “Emissions of Greenhouse Gases in the United States 2003,” coal accounts for 31% of greenhouse gas emissions in the United States, and efforts to control greenhouse gas emissions could result in reduced use of coal if electricity generators switch to lower carbon sources of fuel. Legislation was introduced in Congress in 2006 to reduce greenhouse gas emissions in the United States. Such or similar federal legislative action could be taken in 2007 or later years (see additional discussion in Item 1 under the heading “Global Climate Change”). Further developments in connection with legislation, regulations or other limits on greenhouse emissions, both in the United States and in other countries where we sell coal, could have a material adverse effect on our financial condition or results of operations.
      A number of laws, including in the U.S. the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA” or “Superfund”), impose liability relating to contamination by hazardous substances. Such liability may involve the costs of investigating or remediating contamination and damages to natural resources, as well as claims seeking to recover for property damage or personal injury caused by hazardous substances. Such liability may arise from conditions at formerly as well as currently owned or operated properties, and at properties to which hazardous substances have been sent for treatment, disposal, or other handling. Liability under CERCLA and similar state statutes is without regard to fault, and typically is joint and several, meaning that a person may be held responsible for more than its share, or even all of, the liability involved. Our mining operations involve some use of hazardous materials. In addition, we have accrued for liability arising out of contamination associated with Gold Fields Mining, LLC (“Gold Fields”), a dormant, non-coal-producing subsidiary of ours that was previously managed and owned by Hanson PLC, or with Gold Fields’ former affiliates. A predecessor owner of ours, Hanson PLC transferred ownership of Gold Fields to us in the February 1997 spin-off of its energy business. Gold Fields is currently a defendant in several lawsuits and has received notices of several other potential claims arising out of lead contamination from mining and milling operations it conducted in northeastern Oklahoma. Gold Fields is also involved in investigating or remediating a number of other contaminated sites. Although we have accrued for many of these liabilities known to us, the amounts of other potential losses cannot be estimated. Significant uncertainty exists as to whether claims will be pursued against Gold Fields in all cases, and where they are pursued, the amount of the eventual costs and liabilities, which could be greater or less than our accrual. Although we believe many of these liabilities are likely to be resolved without a material adverse effect on us, future developments, such as new information concerning areas known to be or suspected of being contaminated for which we may be responsible, the discovery of new contamination for which we may be responsible, or the inability to share costs with other parties that may be responsible for the contamination, could have a material adverse effect on our financial condition or results of operations.

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Our expenditures for postretirement benefit and pension obligations could be materially higher than we have predicted if our underlying assumptions prove to be incorrect.
      We provide postretirement health and life insurance benefits to eligible union and non-union employees. We calculated the total accumulated postretirement benefit obligation under SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” which we estimate had a present value of $1.45 billion as of December 31, 2006, $82.6 million of which was a current liability. We have estimated these unfunded obligations based on assumptions described in the notes to our consolidated financial statements. If our assumptions do not materialize as expected, cash expenditures and costs that we incur could be materially higher. Moreover, regulatory changes could increase our obligations to provide these or additional benefits.
      We are party to an agreement with the Pension Benefit Guaranty Corporation (the “PBGC”) and TXU Europe Limited, an affiliate of our former parent corporation, under which we are required to make specified contributions to two of our defined benefit pension plans and to maintain a $37.0 million letter of credit in favor of the PBGC. If we or the PBGC give notice of an intent to terminate one or more of the covered pension plans in which liabilities are not fully funded, or if we fail to maintain the letter of credit, the PBGC may draw down on the letter of credit and use the proceeds to satisfy liabilities under the Employment Retirement Income Security Act of 1974, as amended. The PBGC, however, is required to first apply amounts received from a $110.0 million guaranty in place from TXU Europe Limited in favor of the PBGC before it draws on our letter of credit. On November 19, 2002, TXU Europe Limited was placed under the administration process in the United Kingdom (a process similar to bankruptcy proceedings in the United States) and continues under this process as of December 31, 2006.
      In addition, certain of our subsidiaries participate in two defined benefit multi-employer pension funds that were established as a result of collective bargaining with the UMWA pursuant to the National Bituminous Coal Wage Agreement as periodically negotiated. The UMWA 1950 Pension Plan provides pension and disability pension benefits to qualifying represented employees retiring from a participating employer where the employee last worked prior to January 1, 1976. This is a closed group of beneficiaries with no new entrants. The UMWA 1974 Pension Plan provides pension and disability pension benefits to qualifying represented employees retiring from a participating employer where the employee last worked after December 31, 1975. In December 2006, the 2007 National Bituminous Coal Wage Agreement was signed, which required funding of the 1974 Pension Plan through 2011 under a phased funding schedule. The funding is based on an hourly rate for certain UMWA workers. Under the labor contract, the per hour funding rate increased from zero to $2.00 in 2007 and increased each year thereafter until reaching $5.50 in 2011. Although our subsidiaries are not a party to that labor agreement, they are required to contribute to the 1974 Pension Plan at the new hourly rates. During 2006, represented employees subject to the new rate worked a total of approximately four million hours.
      Contributions to these funds could increase as a result of future collective bargaining with the UMWA, a shrinking contribution base as a result of the insolvency of other coal companies who currently contribute to these funds, lower than expected returns on pension fund assets, higher medical and drug costs or other funding deficiencies.
      The United Mine Workers of America Combined Fund was created by federal law in 1992. This multi-employer fund provides health care benefits to a closed group of retirees including our retired former employees who last worked prior to 1976, as well as orphaned beneficiaries of bankrupt companies who were receiving benefits as orphans prior to the 1992 law. No new retirees will be added to this group. The liability is subject to increases or decreases in per capita health care costs, offset by the mortality curve in this aging population of beneficiaries. Another fund, the 1992 Benefit Plan created by the same federal law in 1992, provides benefits to qualifying retired former employees of bankrupt companies who have defaulted in providing their former employees with retiree medical benefits. Beneficiaries continue to be added to this fund as employers default in providing their former employees with retiree medical benefits, but the overall exposure for new beneficiaries into this fund is limited to retirees covered under their employer’s plan who retired prior to October 1, 1994. A third fund, the 1993 Benefit Plan, was established

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through collective bargaining and provides benefits to qualifying retired former employees who retired after September 30, 1994 of certain signatory companies who have gone out of business and have defaulted in providing their former employees with retiree medical benefits. Beneficiaries continue to be added to this fund as employers go out of business.
      The Surface Mining Control and Reclamation Act Amendments of 2006 (the “2006 Act”), which was enacted in December 2006, amended the federal laws establishing the Combined Fund, 1992 Benefit Plan and the 1993 Benefit Plan. Among other things, the 2006 Act guarantees full funding of all beneficiaries in the Combined Fund, provides funds on a phased-in basis for the 1992 Benefit Plan, and authorizes the trustees of the 1993 Benefit Plan to determine the contribution rates through 2010 for pre-2007 beneficiaries. The new and additional federal expenditures to the Combined Fund, 1992 Benefit Plan, 1993 Benefit Plan and certain Abandoned Mine Land payments to the states and Indian tribes are collectively limited by an aggregate annual cap of $490 million. To the extent that (i) the annual funding of the programs exceeds this amount (plus the amount of interest from the AML trust fund paid with respect to the Combined Benefit Fund), and (ii) Congress does not allocate additional funds to cover the shortfall, contributing employers and affiliates, including some of our subsidiaries, would be responsible for the additional costs.
      Based upon the enactment of the Medicare Prescription Drug, Improvement and Modernization Act of 2003, we estimated future cash savings which allowed us to reduce our projected postretirement benefit obligations and related expense. Failure to achieve these assumed future savings under all benefit plans could adversely affect our financial condition, results of operations and cash flows.
A decrease in the availability or increase in costs of key supplies, capital equipment or commodities such as diesel fuel, steel, explosives and tires could decrease our anticipated profitability.
      Our mining operations require a reliable supply of replacement parts, explosives, fuel, tires, steel-related products (including roof control) and lubricants. If the cost of any of these inputs increased significantly, or if a source for these supplies or mining equipment were unavailable to meet our replacement demands, our profitability could be reduced from our current expectations. Recent consolidation of suppliers of explosives has limited the number of sources for these materials, and our current supply of explosives is concentrated with one supplier. Further, our purchases of some items of underground mining equipment are concentrated with one principal supplier. Over the past few years, industry-wide demand growth has exceeded supply growth for certain surface and underground mining equipment and other capital equipment as well as off-the-road tires. As a result, lead times for some items have increased significantly.
Our future success depends upon our ability to continue acquiring and developing coal reserves that are economically recoverable.
      Our recoverable reserves decline as we produce coal. We have not yet applied for the permits required or developed the mines necessary to use all of our reserves. Furthermore, we may not be able to mine all of our reserves as profitably as we do at our current operations. Our future success depends upon our conducting successful exploration and development activities or acquiring properties containing economically recoverable reserves. Our current strategy includes increasing our reserves through acquisitions of government and other leases and producing properties and continuing to use our existing properties. The federal government also leases natural gas and coalbed methane reserves in the West, including in the Powder River Basin. Some of these natural gas and coalbed methane reserves are located on, or adjacent to, some of our Powder River Basin reserves, potentially creating conflicting interests between us and lessees of those interests. Other lessees’ rights relating to these mineral interests could prevent, delay or increase the cost of developing our coal reserves. These lessees may also seek damages from us based on claims that our coal mining operations impair their interests. Additionally, the federal government limits the amount of federal land that may be leased by any company to 150,000 acres nationwide. As of December 31, 2006, we leased a total of 63,463 acres from the federal government. The limit could restrict

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our ability to lease additional federal lands. For additional discussion of our federal leases see Item 2. Properties.
      Our planned mine development projects and acquisition activities may not result in significant additional reserves, and we may not have continuing success developing additional mines. Most of our mining operations are conducted on properties owned or leased by us. Because title to most of our leased properties and mineral rights are not thoroughly verified until a permit to mine the property is obtained, our right to mine some of our reserves may be materially adversely affected if defects in title or boundaries exist. In addition, in order to develop our reserves, we must receive various governmental permits. We cannot predict whether we will continue to receive the permits necessary for us to operate profitably in the future. We may not be able to negotiate new leases from the government or from private parties, obtain mining contracts for properties containing additional reserves or maintain our leasehold interest in properties on which mining operations are not commenced during the term of the lease. From time to time, we have experienced litigation with lessors of our coal properties and with royalty holders.
A decrease in the price or our production of metallurgical coal could decrease our anticipated profitability.
      We have annual capacity to produce approximately 15 to 18 million tons of metallurgical coal. Prices for metallurgical coal at the end of 2005 and during 2006 were near historically high levels. As a result, our margins from these sales have increased significantly, and represented a larger percentage of our overall revenues and profits and are expected to continue to favorably contribute in the future. To the extent we experience either production or transportation difficulties that impair our ability to ship metallurgical coal to our customers at anticipated levels, our profitability will be reduced in 2007.
      The majority of our 2007 metallurgical coal production will be priced during the first quarter of 2007; however, early indications are that prices will be down from historical highs. As a result, a decrease in metallurgical coal prices could decrease our profitability.
Our financial performance could be adversely affected by our debt.
      Our financial performance could be affected by our indebtedness. As of December 31, 2006, our total indebtedness was $3.26 billion, and we had $1.29 billion of available borrowing capacity under our revolving credit facility. The indentures governing the convertible debentures and senior notes do not limit the amount of indebtedness that we may issue, and the indentures governing our other senior notes permit the incurrence of additional indebtedness.
      The degree to which we are leveraged could have important consequences, including, but not limited to:
  •  making it more difficult for us to pay interest and satisfy our debt obligations;
 
  •  increasing our vulnerability to general adverse economic and industry conditions;
 
  •  requiring the dedication of a substantial portion of our cash flow from operations to the payment of principal of, and interest on, our indebtedness, thereby reducing the availability of the cash flow to fund working capital, capital expenditures, research and development or other general corporate uses;
 
  •  limiting our ability to obtain additional financing to fund future working capital, capital expenditures, research and development or other general corporate requirements;
 
  •  limiting our flexibility in planning for, or reacting to, changes in our business and in the coal industry; and
 
  •  placing us at a competitive disadvantage compared to less leveraged competitors.

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      In addition, our indebtedness subjects us to financial and other restrictive covenants. Failure by us to comply with these covenants could result in an event of default that, if not cured or waived, could have a material adverse effect on us.
      If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to sell assets, seek additional capital or seek to restructure or refinance our indebtedness. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to sell material assets or operations to attempt to meet our debt service and other obligations. The senior unsecured credit facility and indentures governing certain of our notes restrict our ability to sell assets and use the proceeds from the sales. We may not be able to consummate those sales or to obtain the proceeds which we could realize from them and these proceeds may not be adequate to meet any debt service obligations then due.
The covenants in our senior unsecured credit facility and the indentures governing our senior notes and convertible debentures impose restrictions that may limit our operating and financial flexibility.
      Our senior unsecured credit facility, the indentures governing our senior notes and convertible debentures and the instruments governing our other indebtedness contain certain restrictions and covenants which restrict our ability to incur liens and debt or provide guarantees in respect of obligations of any other person. Under our senior unsecured credit facility, we must comply with certain financial covenants on a quarterly basis including a minimum interest coverage ratio and a maximum leverage ratio, as defined. The financial covenants also place limitations on our investments in joint ventures, unrestricted subsidiaries, indebtedness of non-loan parties and the imposition of liens on our assets. These covenants and restrictions are reasonable and customary and have not impacted our business in the past.
      Operating results below current levels or other adverse factors, including a significant increase in interest rates, could result in our inability to comply with the financial covenants contained in our senior unsecured credit facility. If we violate these covenants and are unable to obtain waivers from our lenders, our debt under these agreements would be in default and could be accelerated by our lenders. If our indebtedness is accelerated, we may not be able to repay our debt or borrow sufficient funds to refinance it. Even if we are able to obtain new financing, it may not be on commercially reasonable terms, on terms that are acceptable to us or at all. If our debt is in default for any reason, our business, financial condition and results of operations could be materially and adversely affected. In addition, complying with these covenants may also cause us to take actions that are not favorable to holders of our other debt or equity securities and may make it more difficult for us to successfully execute our business strategy and compete against companies who are not subject to such restrictions.
Our operations could be adversely affected if we fail to appropriately secure our obligations.
      U.S. federal and state laws and Australian laws require us to secure certain of our obligations to reclaim lands used for mining, to pay federal and state workers’ compensation, to secure coal lease obligations and to satisfy other miscellaneous obligations. The primary method for us to meet those obligations is to post a corporate guarantee (i.e. self bond), provide a third-party surety bond or provide a letter of credit. As of December 31, 2006, we had $685.2 million of self bonds in place primarily for our reclamation obligations. As of December 31, 2006, we also had outstanding surety bonds with third parties and letters of credit of $1.09 billion, of which $445.6 million was for post-mining reclamation, $188.5 million related to workers’ compensation obligations, $119.4 was for retiree healthcare obligations, $104.2 million was for coal lease obligations, and $236.0 million was for other obligations, including collateral for surety companies and bank guarantees, road maintenance, and performance guarantees. Surety bonds are typically renewable on a yearly basis. Surety bond issuers and holders may not continue to renew the bonds or may demand additional collateral upon those renewals. Letters of credit are subject to our successful renewal of our bank revolving credit facilities, which are currently set to expire in 2011. Our failure to maintain, or inability to acquire, surety bonds, or letters of credit, or to provide a suitable

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alternative would have a material adverse effect on us. That failure could result from a variety of factors including the following:
  •  lack of availability, higher expense or unfavorable market terms of new surety bonds;
 
  •  restrictions on the availability of collateral for current and future third-party surety bond issuers under the terms of our indentures or senior unsecured credit facility;
 
  •  the exercise by third-party surety bond issuers of their right to refuse to renew the surety; and
 
  •  inability to renew our credit facility.
      Our ability to self bond reduces our costs of providing financial assurances. To the extent we are unable to maintain our current level of self bonding, due to legislative or regulatory changes or changes in our financial condition, our costs would increase.
The conversion of our outstanding convertible debentures may result in the dilution of the ownership interests of our existing stockholders.
      If the conditions permitting the conversion of our convertible debentures are met and holders of the convertible debentures exercise their conversion rights, any conversion value in excess of the principal amount will be delivered in shares of our common stock. If any common stock is issued in connection with a conversion of our convertible debentures, our existing stockholders will experience dilution in the voting power of their common stock and earnings per share could be negatively impacted.
Provisions of our convertible debentures could discourage an acquisition of us by a third-party.
      Certain provisions of our convertible debentures could make it more difficult or more expensive for a third-party to acquire us. Upon the occurrence of certain transactions constituting a “change of control” as defined in the indenture relating to our convertible debentures, holders of our convertible debentures will have the right, at their option, to convert their convertible debentures and thereby require us to pay the principal amount of such converted debentures in cash.
An inability of contract miner or brokerage sources to fulfill the delivery terms of their contracts with us could reduce our profitability.
      In conducting our trading, brokerage and mining operations, we utilize third-party sources of coal production, including contract miners and brokerage sources, to fulfill deliveries under our coal supply agreements. In Australia, the majority of our mines utilize contract miners. Employee relations at mines that use contract miners is the responsibility of the contractor.
      Recently, certain of our brokerage sources and contract miners in the United States have experienced adverse geologic mining, escalated operating costs and/or financial difficulties that have made their delivery of coal to us at the contracted price difficult or uncertain. In some instances, the contract miners and third-party suppliers have suspended mining operations, and it has become increasing difficult to identify and retain contract workers. Our profitability or exposure to loss on transactions or relationships such as these is dependent upon the reliability (including financial viability) and price of the third-party supply, our obligation to supply coal to customers in the event that adverse geologic mining conditions restrict deliveries from our suppliers, our willingness to participate in temporary cost increases experienced by our third-party coal suppliers, our ability to pass on temporary cost increases to our customers, the ability to substitute, when economical, third-party coal sources with internal production or coal purchased in the market, and other factors.
If the coal industry experiences overcapacity in the future, our profitability could be impaired.
      During the mid-1970s and early 1980s, a growing coal market and increased demand for coal attracted new investors to the coal industry, spurred the development of new mines and resulted in production capacity in excess of market demand throughout the industry. Similarly, increases in future coal

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prices could encourage the development of expanded capacity by new or existing coal producers. Recently, the coal industry experienced lower demand as electricity usage was at lower than historical growth levels. Therefore, as of December 2006, total coal inventories of 130 to 140 million tons at generators were above the five-year average.
We could be negatively affected if we fail to maintain satisfactory labor relations.
      As of December 31, 2006, we had approximately 9,200 employees. As of December 31, 2006, approximately 40% of our hourly employees were represented by unions and they generated approximately 14% of our 2006 coal production. Relations with our employees and, where applicable, organized labor are important to our success.
      Due to the higher labor costs and the increased risk of strikes and other work-related stoppages that may be associated with union operations in the coal industry, our competitors who operate without union labor may have a competitive advantage in areas where they compete with our unionized operations. If some or all of our current non-union operations were to become unionized, we could incur an increased risk of work stoppages, reduced productivity and higher labor costs.
United States Labor Relations
      Approximately 66% of our U.S. miners are non-union and are employed in the states of Wyoming, Colorado, Indiana, New Mexico, Illinois and Kentucky. The UMWA represented approximately 26% of our subsidiaries’ hourly employees, who generated 11% of our U.S. production during the year ended December 31, 2006. An additional 5% of our hourly employees are represented by labor unions other than the UMWA. These employees generated 1% of our production during the year ended December 31, 2006. Hourly workers at our mine in Arizona are represented by the UMWA under the Western Surface Agreement of 2000, which is effective through September 1, 2007. Our union workforce east of the Mississippi River is primarily represented by the UMWA. The UMWA-represented workers at one of our eastern mines operate under a contract that expires on December 31, 2007. The remainder of our UMWA-represented workers in the east operate under a recently signed, five-year labor agreement expiring December 31, 2011. This contract replaced a contract that had expired on December 31, 2006 and mirrors the 2007 National Bituminous Coal Wage Agreement.
Australia Labor Relations
      The Australian coal mining industry is unionized and the majority of workers employed at our Australian Mining Operations are members of trade unions. The Construction Forestry Mining and Energy Union represents our hourly production employees. As of December 31, 2006, our Australian hourly employees were approximately 9% or our hourly workforce and generated 2% of our total production in the year then ended. The labor agreement at our Wilkie Creek Mine was renewed in June 2006 and that agreement expires in June 2009. The North Goonyella Mine operates under an agreement due to expire in 2008, and the Metropolitan Mine operates under an agreement that expires in June 2007.
Our ability to operate our company effectively could be impaired if we lose key personnel or fail to attract qualified personnel.
      We manage our business with a number of key personnel, the loss of a number of whom could have a material adverse effect on us. In addition, as our business develops and expands, we believe that our future success will depend greatly on our continued ability to attract and retain highly skilled and qualified personnel. We cannot assure you that key personnel will continue to be employed by us or that we will be able to attract and retain qualified personnel in the future. We do not have “key person” life insurance to cover our executive officers. Failure to retain or attract key personnel could have a material adverse effect on us.
      Due to the current demographics of our mining workforce, a high portion of our current hourly employees are eligible to retire over the next decade. Additionally, many of our mine sites are in more

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secluded areas of the United States, such as the Native American reservations of Arizona and the Southern Powder River Basin of Wyoming. These geographic locations provide limited pools of qualified resources, and it is challenging to locate resources interested in working in some of these regions. Failure to attract new employees to the mining workforce could have a material adverse effect on us.
Our ability to collect payments from our customers could be impaired if their creditworthiness deteriorates.
      Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. Our customer base has changed with deregulation as utilities have sold their power plants to their non-regulated affiliates or third parties. These new power plant owners or other customers may have credit ratings that are below investment grade. If deterioration of the creditworthiness of our customers occurs, our $225.0 million accounts receivable securitization program and our business could be adversely affected.
Our certificate of incorporation and by-laws include provisions that may discourage a takeover attempt.
      Provisions contained in our certificate of incorporation and by-laws and Delaware law could make it more difficult for a third-party to acquire us, even if doing so might be beneficial to our stockholders. Provisions of our by-laws and certificate of incorporation impose various procedural and other requirements that could make it more difficult for stockholders to effect certain corporate actions. For example, a change of control of our Company may be delayed or deterred as a result of the stockholders’ rights plan adopted by our Board of Directors. These provisions could limit the price that certain investors might be willing to pay in the future for shares of our common stock and may have the effect of delaying or preventing a change in control.
The extent to which we are able to successfully integrate the newly acquired Excel operations and successfully complete the development of the new mine sites acquired from Excel will have a bearing on our future financial results.
      The process of integrating the operations of the Excel coal mines could cause an interruption of, or loss of momentum in, the activities of the business or the development of new mines. We will need to make significant capital expenditures to utilize and maintain the assets we acquired in the Excel acquisition. There are currently three development-stage mines, two of which are scheduled to begin production in early 2007. Delays in optimizing the operations of the development-stage mines, and to a lesser extent the existing Excel operations, could impact our future financial results. Additionally, our ability to integrate and manage the Excel operations will have a direct bearing on the realization of anticipated cost savings and synergies. Further, we may encounter unanticipated risks associated with the Excel acquisition.
Growth in our global operations increases our risks unique to international mining and trading operations.
      We currently have international mining operations in Australia and Venezuela. We have recently opened a business development, sales and marketing office in Beijing, China and an international trading group in our trading and brokerage operations. The international expansion of our operations increases our exposure to country and currency risks. Some of our international activities include expansion into developing countries where business practices and counterparty reputations may not be as well developed as in our domestic or Australian operations. We are also challenged by political risks, including expropriation and the inability to repatriate earnings on our investment. In particular, the Venezuelan government has suggested its desire to increase government ownership in Venezuelan energy assets and natural resources. Actions to nationalize Venezuelan coal properties could be detrimental to our investments in the Paso Diablo Mine and Cosila development project. During 2006, the Paso Diablo Mine contributed $28.0 million to segment Adjusted EBITDA in “Corporate and Other Adjusted EBITDA”

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(see Item 7) and paid a dividend of $18.2 million. At December 31, 2006, our investment in Paso Diablo was $60.1 million, recorded in “Investment and other assets” on the consolidated balance sheet.
As we continue to pursue development of Generation Development and Btu Conversion activities, we face challenges and risks that differ from those in our mining business.
      We continue to pursue the development of coal-fueled generating projects in the U.S., including mine-mouth generating plants using our surface lands and coal reserves. Our ultimate role in these projects could take numerous forms, including, but not limited to, equity partner, contract miner or coal sales. The projects we are currently pursuing include the 1,600 plus-megawatt Prairie State Energy Campus in Washington County, Illinois and the 1,500-megawatt Thoroughbred Energy Campus in Muhlenberg County, Kentucky. We also continue to pursue opportunities to participate in technologies to economically convert our coal resources to natural gas and liquids, such as diesel fuel, gasoline and jet fuel (Btu conversion).
      As we move forward with all of these projects, we are exposed to risks related to the performance of our partners, securing required financing, obtaining necessary permits, meeting stringent regulatory laws, maintaining strong supplier relationships and managing (along with our partners) large projects, including managing through long lead times for ordering and obtaining capital equipment. Our work in new or recently commercialized technologies could expose us to unanticipated risks, evolving legislation and uncertainty regarding the extent of future government support and funding.
The extent of our success in converting our current information systems to our new enterprise resource planning system will directly impact our ability to perform functions critical to our day-to-day business.
      To support the continued growth and globalization of our businesses, we are converting our existing information systems across major business processes to an integrated information technology system provided by SAP AG. The project began in the first quarter of 2006 and certain phases of implementation are expected to be completed in 2007. The successful conversion of our information technology systems will have direct bearing on our ability to perform certain day-to-day functions critical to our business, including billing, processing invoices, certain Treasury functions, recordkeeping and financial reporting.
Diversity in interpretation and application of accounting literature in the mining industry may impact our reported financial results.
      The mining industry has limited industry specific accounting literature and, as a result, we understand diversity in practice exists in the interpretation and application of accounting literature to mining specific issues. For example, some companies capitalize drilling and related costs incurred to delineate and classify mineral resources as proven and probable reserves, and other companies expense such costs. In addition, some industry participants expense pre-production stripping costs associated with developing new pits at existing surface mining operations, while other companies capitalize pre-production stripping costs for new pit development at existing operations. The materiality of such expenditures can vary greatly relative to a given company’s respective financial position and results of operations. As diversity in mining industry accounting is addressed, we may need to restate our reported results if the resulting interpretations differ from our current accounting practices (for additional information regarding our accounting policies with respect to drilling costs and advance stripping costs, please see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates).
Item 2. Properties.
Coal Reserves
      We had an estimated 10.2 billion tons of proven and probable coal reserves as of December 31, 2006. An estimated 9.4 billion tons of our proven and probable coal reserves are in the United States and 0.8 billion tons are in Australia. Forty-three percent of our reserves, or 4.4 billion tons, are compliance coal and 57% are non-compliance coal. We own approximately 42% of these reserves and lease property containing the remaining 58%. Compliance coal is defined by Phase II of the Clean Air Act as coal having sulfur dioxide content of 1.2 pounds or less per million Btu. Electricity generators are able to use coal that exceeds these specifications by using emissions reduction technology, using emission allowance credits or blending higher sulfur coal with lower sulfur coal.

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      Below is a table summarizing the locations and reserves of our major operating regions.
                               
        Proven and Probable
        Reserves as of
        December 31, 2006(1)
         
        Owned   Leased   Total
Operating Regions   Locations   Tons   Tons   Tons
                 
        (Tons in millions)
Midwest
  Illinois, Indiana and Kentucky     3,270       900       4,170  
Powder River Basin
  Wyoming and Montana     67       3,400       3,467  
Southwest
  Arizona and New Mexico     617       363       980  
Appalachia
  West Virginia and Ohio     249       306       555  
Colorado
  Colorado     43       184       227  
                       
 
Total United States
        4,246       5,153       9,399  
Australia
  New South Wales           466       466  
Australia
  Queensland           337       337  
                       
 
Total Proven and Probable Coal Reserves
        4,246       5,956       10,202  
                       
 
(1) Reserves have been adjusted to take into account estimated losses involved in producing a saleable product.
      Reserves are defined by SEC Industry Guide 7 as that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination. Proven and probable coal reserves are defined by SEC Industry Guide 7 as follows:
        Proven (Measured) Reserves — Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so close and the geographic character is so well defined that size, shape, depth and mineral content of reserves are well-established.
 
        Probable (Indicated) Reserves — Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) reserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven (measured) reserves, is high enough to assume continuity between points of observation.
      Our estimates of proven and probable coal reserves are established within these guidelines. Proven reserves require the coal to lie within one-quarter mile of a valid point of measure or point of observation, such as exploratory drill holes or previously mined areas. Estimates of probable reserves may lie more than one-quarter mile, but less than three-quarters of a mile, from a point of thickness measurement. Estimates within the proven category have the highest degree of assurance, while estimates within the probable category have only a moderate degree of geologic assurance. Further exploration is necessary to place probable reserves into the proven reserve category. Our active properties generally have a much higher degree of reliability because of increased drilling density. Active surface reserves generally have points of observation as close as 330 feet to 660 feet.
      Our reserve estimates are prepared by our staff of geologists, whose experience ranges from 10 to 30 years. We also have a chief geologist of reserve reporting whose primary responsibility is to track changes in reserve estimates, supervise our other geologists and coordinate periodic third-party reviews of our reserve estimates by qualified mining consultants.
      Our reserve estimates are predicated on information obtained from our ongoing drilling program, which totals nearly 500,000 individual drill holes. We compile data from individual drill holes in a computerized drill-hole database from which the depth, thickness and, where core drilling is used, the

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quality of the coal are determined. The density of the drill pattern determines whether the reserves will be classified as proven or probable. The reserve estimates are then input into our computerized land management system, which overlays the geological data with data on ownership or control of the mineral and surface interests to determine the extent of our reserves in a given area. The land management system contains reserve information, including the quantity and quality (where available) of reserves as well as production rates, surface ownership, lease payments and other information relating to our coal reserves and land holdings. We periodically update our reserve estimates to reflect production of coal from the reserves and new drilling or other data received. Accordingly, reserve estimates will change from time to time to reflect mining activities, analysis of new engineering and geological data, changes in reserve holdings, modification of mining methods and other factors.
      Our estimate of the economic recoverability of our reserves is based upon a comparison of unassigned reserves to assigned reserves currently in production in the same geologic setting to determine an estimated mining cost. These estimated mining costs are compared to existing market prices for the quality of coal expected to be mined and taking into consideration typical contractual sales agreements for the region and product. Where possible, we also review production by competitors in similar mining areas. Only reserves expected to be mined economically are included in our reserve estimates. Finally, our reserve estimates include reductions for recoverability factors to estimate a saleable product.
      We periodically engage independent mining and geological consultants to review estimates of our coal reserves. The most recent of these audits, which was completed in January 2007, included a review of the procedures used by us to prepare our internal estimates, verification of the accuracy of selected property reserve estimates and retabulation of reserve groups according to standard classifications of reliability. This audit confirmed that we controlled approximately 10.2 billion tons of proven and probable reserves as of December 31, 2006.
      With respect to the accuracy of our reserve estimates, our experience is that recovered reserves are within plus or minus 10% of our proven and probable estimates, on average, and our probable estimates are generally within the same statistical degree of accuracy when the necessary drilling is completed to move reserves from the probable to the proven classification. On a regional basis, the expected degree of variance from reserve estimate to tons produced is lower in the Powder River Basin, Southwest and Illinois Basin due to the continuity of the coal seams as confirmed by the mining history. Appalachia, however, has a higher degree of risk due to the mountainous nature of the topography which makes exploration drilling more difficult. Our recovered reserves in Appalachia are less predictable and may vary by an additional one to two percent above the threshold discussed above.
      We have numerous federal coal leases that are administered by the U.S. Department of the Interior under the Federal Coal Leasing Amendments Act of 1976. These leases cover our principal reserves in Wyoming and other reserves in Montana and Colorado. Each of these leases continues indefinitely, provided there is diligent development of the property and continued operation of the related mine or mines. The Bureau of Land Management has asserted the right to adjust the terms and conditions of these leases, including rent and royalties, after the first 20 years of their term and at 10-year intervals thereafter. Annual rents on surface land under our federal coal leases are now set at $3.00 per acre. Production royalties on federal leases are set by statute at 12.5% of the gross proceeds of coal mined and sold for surface-mined coal and 8% for underground-mined coal. The federal government limits by statute the amount of federal land that may be leased by any company and its affiliates at any time to 75,000 acres in any one state and 150,000 acres nationwide. As of December 31, 2006, we leased 11,103 acres of federal land in Colorado, 11,254 acres in Montana and 41,106 acres in Wyoming, for a total of 63,463 nationwide.
      Similar provisions govern three coal leases with the Navajo and Hopi Indian tribes. These leases cover coal contained in 65,000 acres of land in northern Arizona lying within the boundaries of the Navajo Nation and Hopi Indian reservations. We also lease coal-mining properties from various state governments.
      Private coal leases normally have terms of between 10 and 20 years and usually give us the right to renew the lease for a stated period or to maintain the lease in force until the exhaustion of mineable and merchantable coal contained on the relevant site. These private leases provide for royalties to be paid to

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the lessor either as a fixed amount per ton or as a percentage of the sales price. Many leases also require payment of a lease bonus or minimum royalty, payable either at the time of execution of the lease or in periodic installments.
      The terms of our private leases are normally extended by active production on or near the end of the lease term. Leases containing undeveloped reserves may expire or these leases may be renewed periodically. With a portfolio of approximately 10.2 billion tons, we believe that we have sufficient reserves to replace capacity from depleting mines for the foreseeable future and that our significant reserve holdings is one of our strengths. We believe that the current level of production at our major mines is sustainable for the foreseeable future.
      Consistent with industry practice, we conduct only limited investigation of title to our coal properties prior to leasing. Title to lands and reserves of the lessors or grantors and the boundaries of our leased properties are not completely verified until we prepare to mine those reserves.

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      The following chart provides a summary, by mining complex, of production for the years ended December 31, 2006 and 2005 and 2004, tonnage of coal reserves that is assigned to our operating mines, our property interest in those reserves and other characteristics of the facilities.
PRODUCTION AND ASSIGNED RESERVES(1)
(Tons in millions)
                                                                                                         
            Sulfur Content(2)       As of December 31, 2006
    Production                
            <1.2 lbs.   >1.2 to 2.5 lbs.   >2.5 lbs.   As   Assigned    
    Year Ended   Year Ended   Year Ended       sulfur dioxide   sulfur dioxide   sulfur dioxide   Received   Proven and    
Geographic Region/Mining   Dec. 31,   Dec. 31,   Dec. 31,   Type of   per   per   per   Btu per   Probable    
Complex   2006   2005   2004   Coal   Million Btu   Million Btu   Million Btu   pound(3)   Reserves   Owned   Leased   Surface   Underground
                                                     
Appalachia:
                                                                                                   
 
Federal
    4.6       4.1       4.9       Steam                   31       13,300       31     11     20             31  
 
Big Mountain
    2.0       1.9       1.9       Steam       4       30             12,300       34         34             34  
 
Kanawha Eagle(4)
    1.9                   Steam/Met.       31       22             13,100       53         53             53  
 
Harris
    1.6       2.0       3.0       Steam/Met.       5       3             13,800       8         8             8  
 
Rocklick
    2.2       2.6       2.0       Steam/Met.       5       7       1       13,100       13         13       3       10  
 
Wells
    2.3       2.6       2.6       Steam/Met.       20       29             12,800       49         49             49  
                                                                                                 
   
Total
    14.6       13.2       14.4               65       91       32               188     11     177       3       185  
Midwest:
                                                                                                   
 
Highland
    3.7       3.8       3.2       Steam                   88       11,400       88     31     57             88  
 
Patriot
    3.9       4.2       4.1       Steam                   41       10,800       41     4     37       3       38  
 
Air Quality
    2.2       2.1       1.8       Steam             25       33       10,700       58     5     53             58  
 
Riola/ Vermilion Grove
    1.7       2.3       2.3       Steam                   19       10,500       19         19             19  
 
Miller Creek
    1.6       1.0       0.9       Steam             2       28       10,000       30     29     1       30        
 
Francisco Surface
    2.0       1.8       2.1       Steam                   6       10,500       6     2     4       6        
 
Francisco Underground
    1.1       1.2       0.9       Steam                   22       10,600       22     3     18             22  
 
Farmersburg
    3.8       3.8       4.2       Steam       1       11       95       10,300       107     93     14       107        
 
Somerville Central
    3.5       3.4       3.2       Steam                   4       10,300       4     2     2       4        
 
Somerville — North
    2.4       2.4       2.1       Steam                   7       10,500       7     6     1       7        
 
Somerville — South
    2.5       2.4       2.0       Steam                   14       10,000       14     8     6       14        
 
Viking
    1.5       1.5       1.5       Steam             1       7       10,700       8         8       8        
 
Wildcat Hills Surface/Underground
    2.4       2.6       2.7       Steam                   10       10,300       10     5     5       10        
 
Willow Lake
    3.6       3.7       3.4       Steam                   64       11,200       64     48     17             64  
 
Gateway
    2.6       0.5             Steam                   20       10,300       20     20                 20  
 
Dodge Hill
    1.1       1.2       1.2       Steam                   8       11,100       8     3     5             8  
                                                                                                 
   
Total
    39.6       37.9       35.6               1       39       466               506     259     247       189       317  
Powder River Basin:
                                                                                                   
 
North Antelope/ Rochelle
    88.6       82.7       82.5       Steam       1,171                   8,800       1,171         1,171       1,171        
 
Caballo
    32.8       30.5       26.5       Steam       787       122       22       8,600       931         931       931        
 
Rawhide
    17.0       12.4       6.9       Steam       290       62       55       8,600       407         407       407        
                                                                                                 
   
Total
    138.4       125.6       115.9               2,248       184       77               2,509         2,509       2,509        
Southwest/ Colorado:
                                                                                                   
 
Black Mesa
          3.9       4.8       Steam       10       1             10,600       11         11       11        
 
Kayenta
    8.2       8.2       8.2       Steam       185       82       3       11,000       270         270       270        
 
Lee Ranch
    5.5       5.3       5.8       Steam       20       123       12       10,000       155     88     67       155        
 
Twentymile
    8.6       9.4       6.4       Steam       73                   10,800       73     14     59             73  
 
Seneca
          1.1       1.5       Steam                         NA                            
                                                                                                 
   
Total
    22.3       27.9       26.7               288       206       15               509     102     407       436       73  

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            Sulfur Content(2)       As of December 31, 2006
    Production                
            <1.2 lbs.   >1.2 to 2.5 lbs.   >2.5 lbs.   As   Assigned    
    Year Ended   Year Ended   Year Ended       sulfur dioxide   sulfur dioxide   sulfur dioxide   Received   Proven and    
Geographic Region/Mining   Dec. 31,   Dec. 31,   Dec. 31,   Type of   per   per   per   Btu per   Probable    
Complex   2006   2005   2004   Coal   Million Btu   Million Btu   Million Btu   pound(3)   Reserves   Owned   Leased   Surface   Underground
                                                     
Australia:
                                                                                                   
 
North Goonyella/ Eaglefield
    2.2       2.1       1.7       Met.       48                   12,800       48         48       2       46  
 
Metropolitan
    0.4                   Met.       40                   12,700       40         40             40  
 
Wilkie Creek
    2.0       1.9       1.4       Steam       223                   10,800       223         223       223        
 
Chain Valley (80.0%)(5)
    0.2                   Steam       17                   11,900       17         17             17  
 
Wambo Open Cut(4)
    1.2                   Steam       106                   12,400       106         106       106        
 
Burton (95.0%)(5)
    4.3       4.4       3.2       Steam/Met.       38                   12,400       38         38       38        
 
Baralaba(4)
    0.2                   Steam/Met.             2             12,200       2         2       2        
 
Wilpinjong
    0.3                   Steam             165             9,900       165         165       165        
 
Millennium(4)
    0.1                   Met.       26                   12,800       26         26       26        
                                                                                                 
   
Total
    10.9       8.4       6.3               498       167                     665         665       562       103  
                                                                                                 
Total
    225.8       213.0       198.9               3,100       687       590               4,377     372     4,005       3,699       678  
                                                                                                 

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     The following chart provides a summary of the amount of our proven and probable coal reserves in each U.S. state and Australia state, the predominant type of coal mined in the applicable location, our property interest in the reserves and other characteristics of the facilities.
ASSIGNED AND UNASSIGNED PROVEN AND PROBABLE COAL RESERVES
As of December 31, 2006
(Tons in millions)
                                                                                                               
                            Sulfur Content(2)                    
                                                 
                        <1.2 lbs.   >1.2 to 2.5 lbs.   >2.5 lbs.   As        
    Total Tons   Proven and               sulfur dioxide   sulfur dioxide   sulfur dioxide   Received   Reserve Control   Mining Method
        Probable           Type of   per   per   per   Btu per        
Coal Seam Location   Assigned   Unassigned   Reserves(6)   Proven   Probable   Coal   Million Btu   Million Btu   Million Btu   pound(3)   Owned   Leased   Surface   Underground
                                                         
Appalachia:
                                                                                                           
 
Ohio
          25       25       19       6     Steam                 25       11,300       25                   25  
 
West Virginia
    188       342       530       310       220     Steam/Met.     141       190       199       13,000       224       306       15       515  
                                                                                                           
 
Appalachia
    188       367       555       329       226           141       190       224               249       306       15       540  
Midwest:
                                                                                                           
 
Illinois
    113       2,292       2,405       1,190       1,215     Steam     5       38       2,362       10,400       2,195       210       78       2,327  
 
Indiana
    255       353       608       410       198     Steam     1       40       567       10,300       402       206       258       350  
 
Kentucky
    138       1,019       1,157       622       535     Steam           1       1,156       10,800       673       484       105       1,052  
                                                                                                           
 
Midwest
    506       3,664       4,170       2,222       1,948           6       79       4,085               3,270       900       441       3,729  
Powder River Basin:
                                                                                                           
 
Montana
          162       162       158       4     Steam     15       117       30       8,600       67       95       162        
 
Wyoming
    2,509       796       3,305       3,226       79     Steam     3,020       183       102       8,700             3,305       3,305        
                                                                                                           
 
Powder River Basin
    2,509       958       3,467       3,384       83           3,035       300       132               67       3,400       3,467        
Southwest/ Colorado:
                                                                                                           
 
Arizona
    281             281       281           Steam     195       83       3       10,900             281       281        
 
Colorado
    73       154       227       165       62     Steam     139             88       10,600       43       184             227  
 
New Mexico
    155       544       699       636       63     Steam     91       344       264       9,200       617       82       699        
                                                                                                           
 
Southwest
    509       698       1,207       1,082       125           425       427       355               660       547       980       227  
Australia:
                                                                                                           
 
New South Wales
    328       138       466       253       213     Steam/Met.     466                   12,400             466       271       195  
 
Queensland
    337             337       104       233     Steam/Met.     335       2             11,200             337       291       46  
                                                                                                           
 
Australia
    665       138       803       357       446           801       2                           803       562       241  
                                                                                                           
Total Proven and Probable
    4,377       5,825       10,202       7,374       2,828           4,408       998       4,796               4,246       5,956       5,465       4,737  
                                                                                                           

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(1)  Assigned reserves represent recoverable coal reserves that we have committed to mine at locations operating as of December 31, 2006. Unassigned reserves represent coal at suspended locations and coal that has not been committed. These reserves would require new mine development, mining equipment or plant facilities before operations could begin on the property.
 
(2)  Compliance coal is defined by Phase II of the Clean Air Act as coal having sulfur dioxide content of 1.2 pounds or less per million Btu. Non-compliance coal is defined as coal having sulfur dioxide content in excess of this standard. Electricity generators are able to use coal that exceeds these specifications by using emissions reduction technology, using emissions allowance credits or blending higher sulfur coal with lower sulfur coal.
 
(3)  As-received Btu per pound includes the weight of moisture in the coal on an as sold basis. The following table reflects the average moisture content used in the determination of as-received Btu by region:
           
Appalachia
    6.0 %
Midwest:
       
 
Illinois
    14.0 %
 
Indiana
    15.0 %
 
Kentucky
    12.5 %
 
Missouri/ Oklahoma
    12.0 %
Powder River Basin:
       
 
Montana
    26.5 %
 
Wyoming
    27.5 %
Southwest:
       
 
Arizona
    13.0 %
 
Colorado
    14.0 %
 
New Mexico
    15.5 %
Australia
    10.0 %
(4)  These joint ventures are consolidated in our results and their proven and probable coal reserves are reflected at 100%. Our effective percentage interest in each operation is as follows: Kanawha Eagle — 73.9%; Wambo Open-Cut — 75.0%; Baralaba — 62.5% and Millennium — 84.6%.
 
(5)  Proven and probable coal reserves for these joint ventures reflect our proportional ownership as indicated parenthetically.
 
(6)  Proven and probable reserves exclude approximately 30 million tons located in Zulia State, Venezuela, related to the Las Carmelitas Project, which is held through our 51% interest in Excelven Pty Ltd.

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PART II
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Overview
      We are the largest private sector coal company in the world, with majority interests in 40 coal operations located throughout all major U.S. coal producing regions and internationally in Australia and Venezuela. In 2006, we sold 247.6 million tons of coal, which was approximately 38% greater than the sales of our closest competitor. Our domestic sales represented 22% of all U.S. coal sales and was approximately 80% greater than the sales of our closest domestic competitor. Based on Energy Information Administration (“EIA”) estimates, demand for coal in the United States was approximately 1.1 billion tons in 2006. Domestic coal consumption is expected to grow at an average rate of 1.8% per year through 2030 when U.S. coal demand is forecasted to be 1.8 billion tons. The EIA expects demand for coal use at coal-to-liquids (“CTL”) plants to grow to 112 million tons by 2030. Coal-fueled generation is used in most cases to meet baseload electricity requirements, and coal use generally grows at the approximate rate of electricity growth, which is expected to average 1.5% annually through 2030. Coal production located west of the Mississippi River is projected to provide most of the incremental growth as Western production increases to an estimated 68% share of total production in 2030. In 2005, coal’s share of electricity generation was approximately 50%, a share that the EIA projects will grow to 57% by 2030.
      Our primary customers are U.S. utilities, which accounted for 87% of our sales in 2006. We typically sell coal to utility customers under long-term contracts (those with terms longer than one year). During 2006, approximately 90% of our sales were under long-term contracts. As of December 31, 2006, production totaled 226.2 million tons and sales totaled 247.6 million tons. As discussed more fully in Item 1A. Risk Factors, our results of operations in the near-term could be negatively impacted by poor weather conditions, unforeseen geologic conditions or equipment problems at mining locations, and by the availability of transportation for coal shipments. On a long-term basis, our results of operations could be impacted by our ability to secure or acquire high-quality coal reserves, find replacement buyers for coal under contracts with comparable terms to existing contracts, or the passage of new or expanded regulations that could limit our ability to mine, increase our mining costs, or limit our customers’ ability to utilize coal as fuel for electricity generation. In the past, we have achieved production levels that are relatively consistent with our projections.
      We conduct business through four principal operating segments: Western U.S. Mining, Eastern U.S. Mining, Australian Mining, and Trading and Brokerage. Our Western U.S. Mining operations consist of our Powder River Basin, Southwest and Colorado operations, and our Eastern U.S. Mining operations

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consist of our Appalachia and Midwest operations. The principal business of the Western U.S. Mining segment is the mining, preparation and sale of steam coal, sold primarily to electric utilities. The principal business of the Eastern U.S. Mining segment is the mining, preparation and sale of steam coal, sold primarily to electric utilities, as well as the mining of metallurgical coal, sold to steel and coke producers.
      Geologically, Western operations mine bituminous and subbituminous coal deposits and Eastern operations mine bituminous coal deposits. Our Western U.S. Mining operations are characterized by predominantly surface extraction processes, lower sulfur content and Btu of coal, and higher customer transportation costs (due to longer shipping distances). Our Eastern U.S. Mining operations are characterized by predominantly underground extraction processes, higher sulfur content and Btu of coal, and lower customer transportation costs (due to shorter shipping distances).
      Australian Mining operations are characterized by both surface and underground extraction processes, mining various qualities of low-sulfur, high Btu coal (metallurgical coal) as well as steam coal primarily sold to an international customer base with a small portion sold to Australian steel producers and power generators. In the second half of 2006, through two separate transactions, we acquired Excel Coal Limited (“Excel”), an independent coal company in Australia for a total acquisition price of US$1.51 billion, net of cash received, plus approximately US$293.0 million in assumed debt. See Liquidity and Capital Resources for information on the financing of the Excel transaction. Assets acquired include three operating mines and three development-stage mines, along with more than 500 million tons of proven and probable coal reserves.
      We own a 25.5% interest in Carbones del Guasare, which owns and operates the Paso Diablo Mine in Venezuela. The Paso Diablo Mine produces approximately 6 to 8 million tons of steam coal annually for export to the United States and Europe. During 2006, the Paso Diablo Mine contributed $28.0 million to segment Adjusted EBITDA in “Corporate and Other Adjusted EBITDA” and paid a dividend of $18.2 million. At December 31, 2006, our investment in Paso Diablo was $60.1 million.
      Metallurgical coal is produced primarily from four of our Australian mines (two of which were acquired in the Excel transaction) and two of our U.S. mines. Metallurgical coal is approximately 5% of our total sales volume and approximately 3% of U.S. sales volume.
      In addition to our mining operations, which comprised 87% of revenues in 2006, our trading and brokerage operations (13% of revenues), transactions utilizing our vast natural resource position (selling non-core land holdings and mineral interests) and other ventures generate revenues and additional cash flows.
      We continue to pursue the development of coal-fueled generating projects in areas of the U.S. where electricity demand is strong and where there is access to land, water, transmission lines and low-cost coal. The projects involve mine-mouth generating plants using our surface lands and coal reserves. Our ultimate role in these projects could take numerous forms, including, but not limited to, equity partner, contract miner or coal sales. The projects we are currently pursuing include the 1,600-megawatt Prairie State Energy Campus in Washington County, Illinois and the 1,500-megawatt Thoroughbred Energy Campus in Muhlenberg County, Kentucky. The plants, assuming all necessary permits and financing are obtained and following selection of partners and sale of a majority of the output of each plant, could be operational following a four-year construction phase. In October 2006, we entered an agreement with CMS Enterprises to share equally an expected 30% equity interest in the Prairie State Energy Campus and to oversee development and operation of the generating plant and coal mine. In the third quarter of 2006, the Prairie State Energy Campus received affirmation of the air quality permit from the U.S. Environmental Protection Agency, and in the fourth quarter of 2006, parties that had previously challenged the permit filed a new appeal.
      The EIA projects that the high price of oil will lead to an increase in demand for unconventional sources of transportation fuel, including Btu conversion technologies, and that coal will increase its share as a fuel for generation of electricity. We are exploring several Btu conversion projects, which are designed to

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expand the uses of coal through various technologies, and we are continuing to explore options particularly as they relate to Btu conversion technologies such as coal-to-liquids and coal gasification.
      Effective February 22, 2006, we implemented a two-for-one stock split on all shares of our common stock. All share and per share amounts in this annual report reflect this split. In July 2005, our Board of Directors authorized a share repurchase program of up to 5% of the outstanding shares of our common stock. The repurchases may be made from time to time based on an evaluation of our outlook and general business conditions, as well as alternative investment and debt repayment options. In 2006, we repurchased 2.2 million of our common shares for $99.8 million under this repurchase program.
Results of Operations
Adjusted EBITDA
      The discussion of our results of operations below includes references to and analysis of our segments’ Adjusted EBITDA results. Adjusted EBITDA is defined as income from continuing operations before deducting early debt extinguishment costs, net interest expense, income taxes, minority interests, asset retirement obligation expense and depreciation, depletion and amortization. Adjusted EBITDA is used by management primarily as a measure of our segments’ operating performance. Because Adjusted EBITDA is not calculated identically by all companies, our calculation may not be comparable to similarly titled measures of other companies. Adjusted EBITDA is reconciled to its most comparable measure, under generally accepted accounting principles, in Note 25 to our consolidated financial statements.
Year Ended December 31, 2006 Compared to Year Ended December 31, 2005
Summary
      Higher average sales prices and increased volumes in the Eastern U.S., Powder River Basin and Australian mining operations, including the October 2006 acquisition of three mines in Australia, contributed to a 13.2% increase in revenues to $5.26 billion compared to 2005. Segment Adjusted EBITDA increased 13.8% to $1.23 billion primarily on growth in international volumes and higher sales prices from our Australian mining operations and increased results from Trading and Brokerage operations. Increases in sales volumes and prices in our U.S. mining operations were partially offset by operational challenges experienced during the period such as ongoing shipping constraints from rail performance in the Powder River Basin and port congestion in Australia; geologic, equipment and third-party supply issues as well as mine closures in our Western U.S. mining operations in late 2005. Net income was $600.7 million in 2006, or $2.23 per diluted share, an increase of 42.1% over 2005 net income of $422.7 million, or $1.58 per diluted share.
Tons Sold
      The following table presents tons sold by operating segment for the year ended December 31, 2006 and 2005:
                                   
    Year Ended   Increase
    December 31,   (Decrease)
         
    2006   2005   Tons   %
                 
    (Tons in millions)
Western U.S. Mining Operations
    160.5       154.3       6.2       4.0 %
Eastern U.S. Mining Operations
    54.7       52.5       2.2       4.2 %
Australian Mining Operations
    11.0       8.3       2.7       32.5 %
Trading and Brokerage Operations
    21.4       24.8       (3.4 )     (13.7 )%
                         
 
Total tons sold
    247.6       239.9       7.7       3.2 %
                         

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Revenues
      The following table presents revenues for the year ended December 31, 2006 and 2005:
                                   
        Increase to
    Year Ended December 31,   Revenues
         
    2006   2005   $   %
                 
    (Dollars in thousands)
Sales
  $ 5,144,925     $ 4,545,323     $ 599,602       13.2 %
Other revenues
    111,390       99,130       12,260       12.4 %
                         
 
Total revenues
  $ 5,256,315     $ 4,644,453     $ 611,862       13.2 %
                         
      In 2006, our total revenues were $5.26 billion, an increase of $611.9 million, or 13.2%, compared to prior year, which resulted from sales price increases in all regions, particularly in our Eastern and Australian operations and demand-driven sales volume increases in the Powder River Basin, Midwest and Australian operations. Volumes related to the October 2006 Excel acquisition accounted for 2.1 million tons of the increase to tons sold and approximately 43% of the increase to sales in Australia. Partially offsetting sales price increases were lower regional sales due to late 2005 mine closures in the Western U.S. Mining operations and lower brokerage volumes.
      Sales increased $599.6 million, or 13.2%, to $5.14 billion in 2006, which included increases of $91.9 million in Western U.S. Mining sales, $318.1 million in Eastern U.S. Mining sales and $245.1 million in Australian Mining sales, partially offset by a decrease of $55.5 million in our brokerage operations. Overall, prices and volumes in our Western U.S. Mining operations increased, mainly reflecting increases to sales prices of over $0.70 per ton and volumes of 12.7 million tons in the Powder River Basin. These increases at our Powder River Basin operations resulted from strong demand for the mines’ low-sulfur products and improved rail conditions compared to 2005, when the region was dealing with major railroad maintenance. Despite rail performance improvements relative to 2005, constrained rail capacity continued to limit growth in the region in 2006. Offsetting this increase was lower production due to the cessation of mining operations at our Seneca and Black Mesa mines in late 2005 and unfavorable geologic conditions and equipment issues at our Twentymile Mine. On average, per ton sales prices in our Eastern U.S. Mining operations increased, driven by increases in metallurgical and steam coal prices. Sales volumes increased due to a newly developed mine, which began operation in late 2005, and the expansion of several existing mines, partially offset by lower production at one of our mines and at contract miner operations, as both managed geologic, equipment and, in certain locations, supplier issues. Sales from our Australian Mining operations were $245.1 million, or 41.0%, higher than in 2005, primarily due to higher international metallurgical coal prices, higher production at our underground mine following installation of a new longwall in the second quarter of 2006 and additional volumes from our newly acquired mines ($105.1 million). A higher per ton sales price reflected higher contract prices in 2006 for metallurgical coal as well as the slower realization of metallurgical coal price increases in 2005 when we operated under some lower priced carry-over contracts from 2004 through most of the first nine months of 2005. Brokerage operations’ sales decreased $55.5 million in 2006 compared to prior year due to lower sales volumes, partially offset by higher sales prices.
      Other revenues increased $12.3 million, or 12.4%, compared to prior year. The increase includes proceeds of $28.2 million from settlement of commitments by a third-party coal producer following a brokerage contract restructuring. Offsetting this increase were lower revenues related to synthetic fuel facilities as customers idled their synthetic fuel plants due to high crude oil prices.

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Segment Adjusted EBITDA
      Our total segment Adjusted EBITDA was $1.23 billion for the year ended 2006, compared with $1.08 billion in the prior year. Details were as follows:
                                   
        Increase to Segment
    Year Ended December 31,   Adjusted EBITDA
         
    2006   2005   $   %
                 
    (Dollars in thousands)
Western U.S. Mining Operations
  $ 473,074     $ 459,039     $ 14,035       3.1 %
Eastern U.S. Mining Operations
    384,107       374,628       9,479       2.5 %
Australian Mining Operations
    278,411       202,582       75,829       37.4 %
Trading and Brokerage Operations
    92,604       43,058       49,546       115.1 %
                         
 
Total Segment Adjusted EBITDA
  $ 1,228,196     $ 1,079,307     $ 148,889       13.8 %
                         
      Adjusted EBITDA from our Western U.S. Mining operations increased $14.0 million, or 3.1%, during 2006 primarily reflecting an increase in sales volumes of 12.7 million tons at our Powder River Basin operations, which resulted from continued strong demand and improved rail performance relative to 2005. Western U.S. Mining operations sales price per ton increased moderately due to mix changes resulting from ceasing operations at our Black Mesa and Seneca mines. Western U.S. Mining operations cost increases were driven by higher fuel costs, an increase in revenue-based royalties and production taxes, and the timing of major repairs. In addition, we experienced unfavorable geologic conditions and equipment issues related to the new longwall system at our Twentymile Mine; however, a recovery of certain costs associated with the equipment difficulties lessened the impact of these issues on our 2006 results. The Western U.S. Mining operations were also negatively impacted by the cessation of operations at the Black Mesa mine in late 2005.
      Eastern U.S. Mining operations’ Adjusted EBITDA increased $9.5 million, or 2.5%, compared to prior year primarily due to higher sales volumes partially offset by a decrease in margin per ton. Results improved compared to prior year as benefits of higher volumes, product mix and sales prices were partially offset by higher costs. The Eastern U.S. Mining operations experienced higher costs per ton due to fuel costs, revenue-based royalties and production taxes as well as higher costs associated with equipment, geologic and contract miner issues. The 2006 results were also negatively impacted by lower revenues from synthetic fuel facilities of $10.1 million as customers idled their synthetic fuel plants. Also impacting Eastern U.S. Mining results was $8.9 million of income from a settlement related to customer billings regarding coal quality.
      Our Australian Mining operations’ Adjusted EBITDA increased $75.8 million, or 37.4%, compared to prior year primarily due to increased sales volumes following increased production from the second quarter installation of a new longwall system at our underground mine, higher metallurgical coal sales prices, and a $19.7 million contribution from our newly acquired mines.
      Trading and Brokerage operations’ Adjusted EBITDA increased $49.5 million from the prior year, as 2006 results included proceeds from restructuring the brokerage contract mentioned above, improved brokerage margins and contribution from the newly established international operation, partially offset by lower domestic trading results.

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Income Before Income Taxes and Minority Interests
      The following table presents income before income taxes and minority interests for the years ended December 31, 2006 and 2005:
                                   
        Increase (Decrease)
    Year Ended December 31,   to Income
         
    2006   2005   $   %
                 
    (Dollars in thousands)
Total Segment Adjusted EBITDA
  $ 1,228,196     $ 1,079,307     $ 148,889       13.8 %
Corporate and Other Adjusted EBITDA
    (147,792 )     (208,909 )     61,117       29.3 %
Depreciation, depletion and amortization
    (377,210 )     (316,114 )     (61,096 )     (19.3 )%
Asset retirement obligation expense
    (40,112 )     (35,901 )     (4,211 )     (11.7 )%
Interest expense and early debt extinguishment costs
    (144,846 )     (102,939 )     (41,907 )     (40.7 )%
Interest income
    12,726       10,641       2,085       19.6 %
                         
 
Income before income taxes and minority interests
  $ 530,962     $ 426,085     $ 104,877       24.6 %
                         
      Income before income taxes and minority interests of $531.0 million for 2006 is $104.9 million, or 24.6%, higher than 2005 primarily due to improved segment Adjusted EBITDA as discussed above.
      Corporate and Other Adjusted EBITDA results include selling and administrative expenses, equity income from our joint ventures, net gains on asset disposals or exchanges, costs associated with past mining obligations and revenues and expenses related to our other commercial activities such as coalbed methane, generation development, Btu conversion and resource management. The $61.1 million improvement in Corporate and Other Adjusted EBITDA (net expense) in 2006 compared to 2005 includes the following:
  •  Higher gains on asset disposals and exchanges of $30.7 million. The 2006 activity included sales with a combined gain of $66.3 million from the sale of non-strategic coal reserves and surface lands located in Kentucky and West Virginia, a $39.2 million gain on an exchange with the Bureau of Land Management of approximately 63 million tons of leased coal reserves at our Caballo mining operation for approximately 46 million tons of coal reserves contiguous with our North Antelope Rochelle mining operation and other gains on asset disposals totaling $26.7 million. In comparison, activity in 2005 included a $37.4 million gain on exchange of coal reserves as part of a dispute settlement with a third-party supplier, a $31.1 million gain from sale of our remaining 0.838 million units of Penn Virginia Resource Partners, L.P., a $12.5 million gain from the sale of non-strategic coal reserves and properties, a $6.2 million gain on an asset exchange from which we received Illinois Basin coal and other gains on asset disposals of $14.3 million;
 
  •  Lower selling and administrative expenses of $13.9 million primarily associated with lower performance-based incentive costs, partially offset by increases to share-based compensation expense as a result of the new requirement to expense stock options, costs to support corporate and international growth initiatives and costs for the development and installation of a new enterprise resource planning system. The lower costs associated with the performance-based incentive plan related to a long-term, executive incentive plan that is driven by shareholder return and reflected lower stock price appreciation in 2006 than in the prior year;
 
  •  Higher equity income of $8.0 million from our 25.5% interest in Carbones del Guasare, which owns and operates the Paso Diablo Mine in Venezuela; and
 
  •  Lower net expenses of $4.7 million related to the development of the Prairie State Energy Campus due to a higher rate of cost reimbursement from the partners in 2006.

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      Depreciation, depletion and amortization increased $61.1 million in 2006 due to higher production volume, acquisitions and the impact of escalating costs and new capital, including two new longwall installations and new mine development. Also, 2005 depreciation, depletion and amortization was net of amortization of acquired contract liabilities.
      Interest expense and early debt extinguishment costs increased $41.9 million primarily due to approximately $1.7 billion in new debt issuances in the second half of 2006 to finance the Excel acquisition. See Liquidity and Capital Resources for more details of the debt issued.
Net Income
      The following table presents net income for the year ended December 31, 2006 and 2005:
                                   
        Increase (Decrease)
    Year Ended December 31,   to Income
         
    2006   2005   $   %
                 
    (Dollars in thousands)
Income before income taxes and minority interests
  $ 530,962     $ 426,085     $ 104,877       24.6 %
Income tax benefit (provision)
    81,515       (960 )     82,475       n/a  
Minority interests
    (11,780 )     (2,472 )     (9,308 )     (376.5 )%
                         
 
Net income
  $ 600,697     $ 422,653     $ 178,044       42.1 %
                         
      Net income increased $178.0 million in 2006 compared to prior year due to the increase in income before income taxes and minority interests discussed above and an income tax benefit compared to an income tax provision in 2005. The income tax benefit for the year ended 2006 related primarily to a reduction in tax reserves no longer required due to the finalization of various federal and state returns and expiration of applicable statute of limitations, and a reduction in a portion of the valuation allowance related to net operating loss (“NOL”) carry-forwards. The reduction to the valuation allowance resulted from an increase to estimated future taxable income primarily resulting from long-term contracts signed in late 2006 which increased our ability to realize these benefits in the future. Minority interests increased primarily as a result of acquiring an additional interest in a joint venture near the end of the first quarter of 2006.
Year Ended December 31, 2005 Compared to Year Ended December 31, 2004
Summary
      Our 2005 revenues of $4.64 billion increased 27.9% over the prior year. Revenues were driven higher by improved pricing in all of our mining operations and increased sales volume with 239.9 million tons sold compared to 227.2 million tons in 2004. Segment Adjusted EBITDA of $1.08 billion was a 39.5% increase over the prior year due to increases in sales volumes and prices at our U.S. and Australian Mining Operations. Results in our Western U.S. Mining Operations segment include amounts for our April 15, 2004, acquisition of the Twentymile Mine in Colorado. Results in our Australian Mining Operations segment include amounts for our April 15, 2004, acquisition of the Burton and North Goonyella Mines as well as the opening of the Eaglefield Mine adjacent to the North Goonyella Mine in the fourth quarter of 2004. Our Corporate and Other segment includes results from our December 2004 acquisition of a 25.5% interest in Carbones del Guasare, which owns and operates the Paso Diablo Mine in Venezuela. In addition, higher gains on property transactions contributed to higher year over year results. Net income was $422.7 million in 2005, or $1.58 per diluted share, an increase of 141.0% over 2004 net income of $175.4 million, or $0.69 per diluted share.

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Tons Sold
      The following table presents tons sold by operating segment for the years ended December 31, 2005 and 2004:
                                   
    Year Ended   Increase
    December 31,   (Decrease)
         
    2005   2004   Tons   %
                 
    (Tons in millions)
Western U.S. Mining Operations
    154.3       142.2       12.1       8.5 %
Eastern U.S. Mining Operations
    52.5       51.7       0.8       1.5 %
Australian Mining Operations
    8.3       6.1       2.2       36.1 %
Trading and Brokerage Operations
    24.8       27.2       (2.4 )     (8.8 )%
                         
 
Total tons sold
    239.9       227.2       12.7       5.6 %
                         
Revenues
      The table below presents revenues for the years ended December 31, 2005 and 2004:
                                   
    Year Ended December 31,   Increase to Revenues
         
    2005   2004   $   %
                 
    (Dollars in thousands)
Sales
  $ 4,545,323     $ 3,545,027     $ 1,000,296       28.2 %
Other revenues
    99,130       86,555       12,575       14.5 %
                         
 
Total revenues
  $ 4,644,453     $ 3,631,582     $ 1,012,871       27.9 %
                         
      Our revenues increased by $1.01 billion, or 27.9%, to $4.64 billion compared to prior year. The three mines we acquired in the second quarter of 2004 contributed $365.2 million of revenue growth due to the additional 105 days of operations in 2005 compared to the prior year. The remaining $647.7 million of revenue growth was driven by higher sales prices and volumes across all mining segments and improved volumes in our brokerage operations.
      Sales increased 28.2% to $4.55 billion in 2005, reflecting increases in every operating segment. Western U.S. Mining sales increased $222.2 million, Eastern U.S. Mining sales were $224.0 million higher, sales in Australia Mining improved $328.0 million and sales from our brokerage operations increased $226.0 million. Sales in every segment increased on improved pricing, and volumes were higher in every segment other than Trading and Brokerage. Our average sales price per ton increased 17.4% during 2005 due to increased demand for all of our coal products, which drove pricing higher, particularly in the regions where we produce metallurgical coal. Prices for metallurgical coal and our ultra-low sulfur Powder River Basin coal have been the subject of increasing demand. We sell metallurgical coal from our Eastern U.S. and Australian Mining operations. We sell ultra-low sulfur Powder River Basin coal from our Western U.S. Mining operations. The sales mix also improved due to an increase in sales from our Australian Mining segment, where per ton prices are higher than in domestic markets due primarily to a higher proportion of metallurgical coal production in the Australian segment sales mix.
      The increase in Eastern U.S. Mining operations sales was primarily due to improved pricing for both steam and metallurgical coal from the region. On average, prices in our Eastern U.S. Mining operations increased 14.1% to $33.10 per ton. Sales increased in our Western U.S. Mining operations due to higher demand-driven volumes and prices, particularly in the Powder River Basin. Overall, prices in our Western U.S. Mining operations increased 6.6% to $10.45 per ton. Powder River Basin production and sales volumes were up as a result of increasingly strong demand for the mines’ low-sulfur product, which continues to expand its market area geographically. Powder River Basin operations were able to ship record volumes during 2005 by overcoming train derailments, weather and track maintenance disruptions on the main shipping line out of the basin. Our Twentymile Mine, acquired in April of 2004, contributed to higher sales in 2005 due to an additional four months of ownership, higher prices and increased mine

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productivity. Sales from our Australian Mining operations were $328.0 million, or 122.1%, higher than in 2004. The increase in Australian sales was due primarily to a 63.3% increase in per ton sales prices largely due to higher international metallurgical coal prices, an increase in volumes which included the opening of our Eaglefield surface mine at the end of 2004, and $197.6 million of incremental sales from the two mines we acquired in April 2004 due to 105 additional days of operations in 2005 compared to 2004. Our Trading and Brokerage operations sales increased $226.0 million in 2005 compared to prior year due to an increase in average per ton prices and higher eastern U.S. and international brokerage volumes.
      Other revenues increased $12.6 million, or 14.5%, compared to prior year primarily due to proceeds from a purchase contract restructuring and higher synthetic fuel revenues in the Midwest.
Segment Adjusted EBITDA
      Our total segment Adjusted EBITDA of $1.08 billion for 2005 was $305.5 million higher than 2004 segment Adjusted EBITDA of $773.8 million, and was composed of the following:
                                   
        Increase to Segment
    Year Ended December 31,   Adjusted EBITDA
         
    2005   2004   $   %
                 
    (Dollars in thousands)
Western U.S. Mining Operations
  $ 459,039     $ 402,052     $ 56,987       14.2 %
Eastern U.S. Mining Operations
    374,628       280,357       94,271       33.6 %
Australian Mining Operations
    202,582       50,372       152,210       302.2 %
Trading and Brokerage Operations
    43,058       41,039       2,019       4.9 %
                         
 
Total Segment Adjusted EBITDA
  $ 1,079,307     $ 773,820     $ 305,487       39.5 %
                         
      Adjusted EBITDA from our Western U.S. Mining operations increased $57.0 million during 2005 due to a margin per ton increase of $0.15, or 5.3%, and a sales volume increase of 12.1 million tons. Results in the Powder River Basin operations contributed to the increase in Western U.S. Mining operations as it earned 12.3% higher per ton margins while increasing volumes 8.5% in response to greater demand for our low-sulfur products. Improved revenues overcame increased unit costs that resulted from higher fuel and explosives costs, lower than anticipated volume due to rail difficulties and an increase in revenue-based royalties and production taxes. The Twentymile Mine, acquired in April of 2004, contributed $25.4 million more to Adjusted EBITDA in 2005 than in 2004, due to four months of incremental ownership and a 22.2% increase in per ton margin.
      Eastern U.S. Mining operations’ Adjusted EBITDA increased $94.3 million, or 33.6%, compared to prior year primarily due to an increase in margin per ton of $1.71, or 31.5%. Our Eastern U.S. Mining operations’ Adjusted EBITDA increased as a result of sales price increases, partially offset by lower production at two of our mines and higher costs related to geologic issues, contract mining, fuel, repair and maintenance and the impact of heavy rainfall on surface operations early in the year.
      Our Australian Mining operations’ Adjusted EBITDA increased $152.2 million in the current year, a 302.2% increase compared to prior year due to an increase of $16.23, or 197.4%, in margin per ton and 2.2 million additional tons shipped. Our Australian operations produce mostly (75% to 85%) high margin metallurgical coal. The two mines we acquired in April 2004 added $87.4 million to Adjusted EBITDA compared to eight months of ownership in 2004. The remaining increase of $64.8 million was primarily due to an increase in volume, including tonnage from our surface operation opened at the end of the prior year, and an increase of 63.3% in average per ton sale price. While current year margins benefited from strong sales prices, margin growth was limited by the impact of port congestion, related demurrage costs and higher costs due to geological problems at the underground mine.
      Trading and Brokerage operations’ Adjusted EBITDA increased $2.0 million from the prior year primarily due to higher brokerage results. Results in 2005 included a net charge of $4.0 million, primarily related to the breach of a coal supply contract by a producer.

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Reconciliation of Segment Adjusted EBITDA to Income Before Income Taxes and Minority Interests
                                   
        Increase (Decrease)
    Year Ended December 31,   to Income
         
    2005   2004   $   %
                 
    (Dollars in thousands)
Total Segment Adjusted EBITDA
  $ 1,079,307     $ 773,820     $ 305,487       39.5 %
Corporate and Other Adjusted EBITDA
    (208,909 )     (214,576 )     5,667       2.6 %
Depreciation, depletion and amortization
    (316,114 )     (270,159 )     (45,955 )     (17.0 )%
Asset retirement obligation expense
    (35,901 )     (42,387 )     6,486       15.3 %
Interest expense and early debt extinguishment costs
    (102,939 )     (98,544 )     (4,395 )     (4.5 )%
Interest income
    10,641       4,917       5,724       116.4 %
                         
 
Income before income taxes and minority interests
  $ 426,085     $ 153,071     $ 273,014       178.4 %
                         
      Income before income taxes and minority interest of $426.1 million for the current year is $273.0 million, or 178.4%, higher than prior year primarily due to improved segment Adjusted EBITDA as discussed above. Increases in depreciation, depletion and amortization expense and interest expense offset improvements in Corporate and Other Adjusted EBITDA, asset retirement obligation expense, debt extinguishment costs and interest income.
      Corporate and Other Adjusted EBITDA results include selling and administrative expenses, equity income from our Venezuelan joint venture, net gains on asset disposals or exchanges, costs associated with past mining obligations and revenues and expenses related to our other commercial activities such as coalbed methane, generation development and resource management. The $5.7 million improvement in Corporate and Other Adjusted EBITDA (net expense) in 2005 compared to 2004 included:
  •  net gains on asset sales that were $77.7 million higher than prior year primarily due to a $37.4 million gain from a property exchange related to settlement of a contract dispute with a third-party coal supplier (see Note 3 to our consolidated financial statements), sales of Penn Virginia Resource Partners, L.P. (“PVR”) units ($31.1 million) (see Note 9 to our consolidated financial statements), resource sales involving non-strategic coal assets and properties ($12.5 million), and an asset exchange in which we acquired Illinois Basin coal reserves ($6.2 million). The gain from PVR unit sales in 2005 was from the sale of all of our remaining 0.838 million units compared to a gain of $15.8 million on the sale of 0.775 million units in two separate transactions during 2004. All other gains on asset disposals in 2005 and 2004 were $14.3 million and $8.0 million, respectively;
 
  •  higher equity income of $18.7 million from our 25.5% interest in Carbones del Guasare (acquired in December 2004), which owns and operates the Paso Diablo Mine in Venezuela, and;
 
  •  lower net expenses related to generation development of $5.1 million, primarily due to reimbursements from the Prairie State Energy Campus partnership group.
      These improvements were partially offset by:
  •  a $36.0 million increase in past mining obligations expense, primarily related to higher retiree health care costs. The increase in retiree health care costs was actuarially driven by higher trend rates, and lower interest discount assumptions and higher amortization of actuarial losses in 2005, and;
 
  •  an increase of $46.8 million in selling and administrative expenses primarily related to accruals for higher short-term and long-term performance-based incentive plans ($32.2 million). These incentives are principally long-term plans that are driven by total shareholder returns. Our share price increased 104% during 2005, significantly outperforming industrial benchmarks and our coal

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  peer group average. The remaining increase in selling and administrative expenses was due to higher personnel and outside services costs needed to advance our growth initiatives in areas such as China and BTU conversion, acquisitions and regulatory costs (e.g. Sarbanes-Oxley), and an increase in advertising costs related to an industry awareness campaign launched in late 2005.
      Depreciation, depletion and amortization increased $46.0 million during 2005. Approximately 56% of the increase was due to acquisitions completed during 2004 and the remainder was from increased volumes at existing mines and operations opened during 2005. Asset retirement obligation expense decreased $6.5 million in 2005 due to additional expenses incurred in 2004 to accelerate the planned reclamation of certain closed mine sites. Interest expense increased $6.1 million primarily related to a full year of interest in 2005 on $250 million of 5.875% Senior Notes issued in late March of 2004 and increases in the cost of floating rate debt due to higher interest rates. Interest income improved $5.7 million due to higher yields on short-term interest rates and an increase in invested balances due to improved cash flows during 2005.
Net Income
                                   
        Increase (Decrease)
    Year Ended December 31,   to Income
         
    2005   2004   $   %
                 
    (Dollars in thousands)
Income before income taxes and minority interests
  $ 426,085     $ 153,071     $ 273,014       178.4%  
Income tax benefit (provision)
    (960 )     26,437       (27,397 )     (103.6 )%
Minority interests
    (2,472 )     (1,282 )     (1,190 )     (92.8 )%
                         
 
Income from continuing operations
    422,653       178,226       244,427       (137.1 )%
Loss from discontinued operations
          (2,839 )     2,839       n/a  
                         
 
Net income
  $ 422,653     $ 175,387     $ 247,266       141.0%  
                         
      Net income increased $247.3 million, or 141.0%, compared to the prior year due to the increase in income before income taxes and minority interests discussed above, partially offset by increases in our income tax provision. The income tax benefit in 2004 included a $25.9 million reduction in the valuation allowance on net operating loss carry-forwards and alternative minimum tax credits. The income tax provision in 2005 was higher based on the increase in pretax income which was partially offset by the higher permanent benefit of percentage depletion and the partial benefit of tax loss from a deemed liquidation of a subsidiary arising as an indirect consequence of a comprehensive and strategic internal restructuring we completed during 2005. This restructuring resulted from efforts to better align corporate ownership of subsidiaries on a geographic and functional basis.
Outlook
Events Impacting Near-Term Operations
      In October 2006, we acquired Excel Coal Limited, which included three operating mines, two late development-stage mines and a development-stage mine. These development-stage mines are expected to begin shipments in 2007, and our 2007 results will be impacted to the extent we complete ramp up activities at these development-stage mines on time and at expected capacity. Furthermore, our two primary Australian shipping points, Dalrymple Bay Coal Terminal and Port of Newcastle, are experiencing significant queues of vessels, which could result in delayed shipments and demurrage charges.
      Currently depressed Central Appalachian coal prices combined with escalating costs of our third-party contractors could adversely impact our saleable production as it becomes uneconomic to mine.
      Although we expect that the Twentymile longwall system will allow for expanded capacity over the next several years, we continue to manage equipment and lower coal quality issues at our Twentymile mine.

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      Shipments from our Powder River Basin mines improved in 2006, but were still impacted by rail service disruptions. Rail carriers are expected to continue improvements in 2007. Although we currently expect to increase our shipment levels from our Powder River Basin operations in 2007 compared with 2006, our ability to reach these targeted shipment levels is dependent upon the performance of the rail carriers.
      Our union workforce east of the Mississippi River is primarily represented by the UMWA. The UMWA-represented workers at one of our eastern mines operate under a contract that expires on December 31, 2007. The remainder of our UMWA-represented workers in the east operate under a recently signed, five-year labor agreement expiring December 31, 2011. The new contract mirrors the 2007 National Bituminous Coal Wage Agreement and stipulates a $1.50 per hour increase to wages effective January 1, 2007 and a total wage increase of $4.00 per hour over the life of the agreement. The contract also calls for a $1,000 bonus for each of our UMWA-represented employees.
Long-Term Outlook
      Our outlook for the coal markets remains positive. We believe strong coal markets will continue worldwide, as long as growth continues in the U.S., Asia and other industrialized economies that are increasing coal demand for electricity generation and steelmaking. Approximately 115 gigawatts of new coal-fueled electricity generating capacity is scheduled to come on line around the world over the next three years, and the EIA projects an additional 156 gigawatts of new U.S. coal-fueled generation by 2030, which by itself represents more than 500 million tons of additional coal demand.
      Global coal markets continued to grow, driven by increased demand from growing economies. The U.S. economy grew at an annual rate of 3.5% based on fourth quarter 2006 data as reported by the U.S. Commerce Department, while China’s economy grew 10.7% in 2006 as published by the National Bureau of Statistics of China. Metallurgical coal continued to sell at a significant premium to steam coal. Metallurgical markets, while off record levels, remain strong as seaborne metallurgical coal prices for the upcoming fiscal year were settling from a reference price near $100 per metric ton and as China steel production shows signs of continued growth over 2005 levels. We expect to capitalize on the strong global market for metallurgical coal primarily through production and sales of metallurgical coal from our Appalachia and Australian operations. In response to growing international markets, we established an international trading group in 2006, and added another operations office in Europe in early 2007.
      Coal-to-gas and coal-to-liquids (“CTL”) plants represent a significant avenue for long-term industry growth. The EIA continues to project an increase in demand for unconventional sources of transportation fuel, including coal-to-liquids, and in the U.S. coal-to-liquid technologies are receiving growing bipartisan support as demonstrated by the newly introduced CTL bills such as the “Coal-to-Liquid Fuel Promotion Act” within the Senate. China and India are developing coal-to-gas and coal-to-liquids facilities.
      Demand for Powder River Basin coal remains strong, particularly for our ultra-low sulfur products. The Powder River Basin represents more than half of our production. We control approximately 3.5 billion tons of proven and probable reserves in the Southern Powder River Basin, and we sold 138.4 million tons of coal from this region during 2006, an increase of 10.1% over the prior year.
      We are targeting 2007 production of 240 to 260 million tons and total sales volume of 265 to 285 tons, including 15 to 18 million tons of metallurgical coal. As of December 31, 2006, our unpriced 2007 volumes for planned produced tonnage were 5 to 15 million U.S. tons and 14 million Australia tons. Our total unpriced planned production for 2008 is approximately 70 to 80 million tons in the United States and 20 to 22 million tons in Australia.
      Management plans to aggressively control costs and operating performance to mitigate external cost pressures, geologic conditions and potentially adverse port and rail performance. We are experiencing increases in operating costs related to fuel, explosives, steel, tires, contract mining and healthcare, and have taken measures to mitigate the increases in these costs, including a company-wide initiative to instill best

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practices at all operations. In addition, historically low long-term interest rates also have a negative impact on expenses related to our actuarially determined, employee-related liabilities. We may also encounter poor geologic conditions, lower third-party contract miner or brokerage source performance or unforeseen equipment problems that limit our ability to produce at forecasted levels. To the extent upward pressure on costs exceeds our ability to realize sales increases, or if we experience unanticipated operating or transportation difficulties, our operating margins would be negatively impacted. See “Cautionary Notice Regarding Forward-Looking Statements” and Item 1A. Risk Factors for additional considerations regarding our outlook.
Critical Accounting Policies and Estimates
      Our discussion and analysis of our financial condition, results of operations, liquidity and capital resources is based upon our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Generally accepted accounting principles require that we make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. On an on-going basis, we evaluate our estimates. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates.
Employee-Related Liabilities
      We have significant long-term liabilities for our employees’ postretirement benefit costs, workers’ compensation obligations and defined benefit pension plans. Detailed information related to these liabilities is included in Notes 14, 15 and 16 to our consolidated financial statements. The adoption of SFAS No. 158 on December 31, 2006 resulted in each of these liabilities recorded on the consolidated balance sheet as of December 31, 2006 being equal to the funded status of the plans. Liabilities for postretirement benefit costs and workers’ compensation obligations are not funded. Our pension obligations are funded in accordance with the provisions of federal law. Expense for the year ended December 31, 2006, for these liabilities totaled $178.7 million, while payments were $146.2 million.
      Each of these liabilities are actuarially determined and we use various actuarial assumptions, including the discount rate and future cost trends, to estimate the costs and obligations for these items. Our discount rate is determined by utilizing a hypothetical bond portfolio model which approximates the future cash flows necessary to service our liabilities.
      We make assumptions related to future trends for medical care costs in the estimates of retiree health care and work-related injuries and illnesses obligations. Our medical trend assumption is developed by annually examining the historical trend of our cost per claim data. In addition, we make assumptions related to future compensation increases and rates of return on plan assets in the estimates of pension obligations.
      If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could differ materially from our current estimates. Moreover, regulatory changes could increase our obligation to satisfy these or additional obligations. Our most significant employee liability is postretirement health care, and assumed discount rates and health care cost trend rates have a significant effect on the expense and liability amounts reported for health care plans.

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      Below we have provided two separate sensitivity analyses to demonstrate the significance of these assumptions in relation to reported amounts.
      Health care cost trend rate:
                 
    One-Percentage-   One-Percentage-
    Point Increase   Point Decrease
         
    (Dollars in thousands)
Effect on total service and interest cost components(1)
  $ 9,501     $ (7,989 )
Effect on total postretirement benefit obligation(1)
  $ 179,264     $ (150,765 )
      Discount rate:
                 
    One-Half   One-Half
    Percentage-   Percentage-
    Point Increase   Point Decrease
         
    (Dollars in thousands)
Effect on total service and interest cost components(1)
  $ 1,064     $ (1,496 )
Effect on total postretirement benefit obligation(1)
  $ (78,243 )   $ 82,702  
 
(1)  In addition to the effect on total service and interest cost components of expense, changes in trend and discount rates would also increase or decrease the actuarial gain or loss amortization expense component. The gain or loss amortization would approximate the increase or decrease in the obligation divided by 8.47 years at December 31, 2006.
Asset Retirement Obligations
      Our asset retirement obligations primarily consist of spending estimates for surface land reclamation and support facilities at both surface and underground mines in accordance with federal and state reclamation laws as defined by each mining permit. Asset retirement obligations are determined for each mine using various estimates and assumptions including, among other items, estimates of disturbed acreage as determined from engineering data, estimates of future costs to reclaim the disturbed acreage, the timing of these cash flows, and a credit-adjusted, risk-free rate. As changes in estimates occur (such as mine plan revisions, changes in estimated costs, or changes in timing of the reclamation activities), the obligation and asset are revised to reflect the new estimate after applying the appropriate credit-adjusted, risk-free rate. If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could be materially different than currently estimated. Moreover, regulatory changes could increase our obligation to perform reclamation and mine closing activities. Asset retirement obligation expense for the year ended December 31, 2006, was $40.1 million, and payments totaled $36.6 million. See detailed information regarding our asset retirement obligations in Note 13 to our consolidated financial statements.
Income Taxes
      We account for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes” (“SFAS No. 109”), which requires that deferred tax assets and liabilities be recognized using enacted tax rates for the effect of temporary differences between the book and tax basis of recorded assets and liabilities. SFAS No. 109 also requires that deferred tax assets be reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. In our annual evaluation of the need for a valuation allowance, we take into account various factors, including the expected level of future taxable income and available tax planning strategies. If actual results differ from the assumptions made in our annual evaluation of our valuation allowance, we may record a change in valuation allowance through income tax expense in the period such determination is made.
      We establish reserves for tax contingencies when, despite the belief that our tax return positions are fully supported, certain positions are likely to be challenged and may not be fully sustained. The tax contingency reserves are analyzed on a quarterly basis and adjusted based upon changes in facts and circumstances, such as the progress of federal and state audits, case law and emerging legislation. Our effective tax rate includes the impact of tax contingency reserves and changes to the reserves, including

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related interest. We establish the reserves based upon management’s assessment of exposure associated with permanent tax differences (i.e. tax depletion expense, etc.) and certain tax sharing agreements. We are subject to federal audits for several open years due to our previous inclusion in multiple consolidated groups and the various parties involved in finalizing those years. Additional details regarding the effect of income taxes on our consolidated financial statements is available in Note 11.
      Interpretation No. 48 “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109” (“FIN No. 48”) prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN No. 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. This interpretation is effective for fiscal years beginning after December 15, 2006 (January 1, 2007 for the Company).
Revenue Recognition
      In general, we recognize revenues when they are realizable and earned. We generated 98% of our revenue in 2006 from the sale of coal to our customers. Revenue from coal sales is realized and earned when risk of loss passes to the customer. Coal sales are made to our customers under the terms of coal supply agreements, most of which are long-term (greater than one year). Under the typical terms of these coal supply agreements, title and risk of loss transfer to the customer at the mine or port, where coal is loaded to the rail, barge, ocean-going vessel, truck or other transportation source(s) that delivers coal to its destination.
      With respect to other revenues, other operating income, or gains on asset sales recognized in situations unrelated to the shipment of coal, we carefully review the facts and circumstances of each transaction and apply the relevant accounting literature as appropriate, and do not recognize revenue until the following criteria are met: persuasive evidence of an arrangement exists; delivery has occurred or services have been rendered; the seller’s price to the buyer is fixed or determinable; and collectibility is reasonably assured.
Trading Activities
      We engage in the buying and selling of coal in over-the-counter markets. Our coal trading contracts are accounted for on a fair value basis under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” To establish fair values for our trading contracts, we use bid/ask price quotations obtained from multiple, independent third-party brokers to value coal and emission allowance positions. Prices from these sources are then averaged to obtain trading position values. We could experience difficulty in valuing our market positions if the number of third-party brokers should decrease or market liquidity is reduced.
      All of the contracts in our trading portfolio as of December 31, 2006 were valued utilizing prices from over-the-counter market sources, adjusted for coal quality and traded transportation differentials. As of December 31, 2006, 41% of the estimated future value of our trading portfolio was scheduled to be realized by the end of 2007 and 80% within 24 months. See Note 5 to our consolidated financial statements for additional details regarding assets and liabilities from our coal trading activities.
      Exploration and Drilling Costs
     Exploration expenditures are charged to operating costs as incurred, including costs related to drilling and study costs incurred to convert or upgrade mineral resources to reserves.
      Advance Stripping Costs
     Pre-production: At existing surface operations, additional pits may be added to increase production capacity in order to meet customer requirements. These expansions may require significant capital to purchase additional equipment, expand the workforce, build or improve existing haul roads and create the initial pre-production box cut to remove overburden (i.e., advance stripping costs) for new pits at existing operations. If these pits operate in a separate and distinct area of the mine, the costs associated with initially uncovering coal (i.e., advance stripping costs incurred for the initial box cuts) for production are capitalized and amortized over the life of the developed pit consistent with coal industry practices.
     Post-production: Advance stripping costs related to post-production are expensed as incurred. Where new pits are routinely developed as part of a contiguous mining sequence, we expense such costs as incurred. The development of a contiguous pit typically reflects the planned progression of an existing pit, thus maintaining production levels from the same mining area utilizing the same employee group and equipment.
     Since the January 1, 2006 adoption of EITF 04-6, we have not incurred development costs (advance stripping costs) related to opening new pits at existing surface operations. However, we anticipate such development expenditures will be incurred in the latter part of 2007 and beyond.
Liquidity and Capital Resources
      Our primary sources of cash include sales of our coal production to customers, cash generated from our trading and brokerage activities, sales of non-core assets and financing transactions, including the sale of our accounts receivable (through our securitization program). Our primary uses of cash include our cash costs of coal production, capital expenditures, interest costs and costs related to past mining obligations as well as planned acquisitions. Our ability to pay dividends, service our debt (interest and principal) and acquire new productive assets or businesses is dependent upon our ability to continue to generate cash from the primary sources noted above in excess of the primary uses. Future dividends,

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among other things, are subject to limitations imposed by our Senior Notes and Debenture covenants. We expect to fund all of our capital expenditure requirements with cash generated from operations.
      Net cash provided by operating activities was $595.7 million for the year ended December 31, 2006, a decrease of $107.1 million compared to $702.8 million provided by operating activities in the prior year. The decrease was primarily related to the timing of working capital needs. The decrease in cash from operating activities would have been $30.4 million lower had 2006 and 2005 operating cash flows been shown on a comparable basis. The 2006 operating cash flows include a required reclassification of the excess tax benefit related to stock option exercises ($33.2 million) from operating to financing activities.
      Net cash used in investing activities was $2.14 billion for the year ended December 31, 2006 compared to $584.2 million used in the prior year. The increase reflects the acquisition of Excel for $1.51 billion, net of cash acquired, higher capital expenditures of $93.4 million, higher federal coal lease expenditures of $59.8 million, the acquisition of an additional interest in a joint venture for $44.5 million, and the receipt of notes in lieu of payments on asset sales of $45.6 million, partially offset by higher proceeds from asset disposals of $46.9 million in 2006 and the purchase of mining and related assets of $141.2 million in 2005. Capital expenditures included longwall equipment and mine development at our Australian mines (including our recently acquired Excel operations), the opening of new mines and the purchase of equipment for expansion. The $141.2 million purchase of mining and related assets in 2005 included 70 million tons of Illinois and Indiana coal reserves, surface properties and equipment from Lexington Coal Company ($56.5 million) and rail, loadout and surface facilities as well as other mining assets for $84.7 million from another major coal producer.
      Net cash provided by financing activities was $1.37 billion during the year ended December 31, 2006, compared to a use of $4.9 million in 2005. In 2006, we issued net borrowings of $1.74 billion, which were utilized to fund the $1.51 billion Excel acquisition, the repayment of Excel’s bank facility and a portion of its outstanding bonds, and other corporate purposes. See the detailed discussion of our Senior Unsecured Credit Facility, Convertible Junior Subordinated Debentures, Senior Notes offerings and borrowings under our Senior Unsecured Credit Facility below. In addition to the net issuance of debt related to the Excel acquisition, we repaid $23.8 million of debt held by a majority-owned joint venture, purchased $7.7 million of our 5.875% Senior Notes in the open market, and made scheduled debt repayments of $11.1 million on our 5% Subordinated Note and other notes payable.
      The 2006 activity compared to 2005 also reflected payments for common stock repurchases of $99.8 million, debt issuance costs of $40.6 million and higher dividends of $18.9 million. During the year ended December 31, 2006, we repurchased 2.2 million of our common shares at a cost of $99.8 million under our share repurchase program as authorized by the Board of Directors. The 2006 activity included a decrease in the usage of our accounts receivable securitization program of $5.8 million compared to an increase of $25.0 million in 2005. The 2006 activity compared to 2005 also reflected $7.0 million lower proceeds from the exercise of stock options as well as a $33.2 million tax benefit related to stock option exercises included in financing activity based on the newly adopted accounting standard for share-based compensation (see “Newly Adopted Accounting Pronouncements” below for more discussion about the adoption of this standard). In 2005, the tax benefit related to stock option exercises (totaling $30.4 million) was included in operating activities.

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      Our total indebtedness as of December 31, 2006 and 2005 consisted of the following:
                   
    December 31,
     
    2006   2005
         
    (Dollars in thousands)
Term Loan under Senior Unsecured Credit Facility
  $ 547,000     $  
Term Loan under Senior Secured Credit Facility
          442,500  
Convertible Junior Subordinated Debentures due 2066
    732,500        
7.375% Senior Notes due 2016
    650,000        
6.875% Senior Notes due 2013
    650,000       650,000  
7.875% Senior Notes due 2026
    246,897        
5.875% Senior Notes due 2016
    231,845       239,525  
5.0% Subordinated Note
    59,504       66,693  
6.84% Series C Bonds due 2016
    43,000        
6.34% Series B Bonds due 2014
    21,000        
6.84% Series A Bonds due 2014
    10,000        
Capital lease obligations
    56,707       1,529  
Fair value of interest rate swaps
    (13,784 )     (8,879 )
Other
    29,157       14,138  
             
 
Total
  $ 3,263,826     $ 1,405,506  
             
Senior Unsecured Credit Facility
      In September 2006, we entered into a Third Amended and Restated Credit Agreement, which established a $2.75 billion Senior Unsecured Credit Facility and which amended and restated in full our then existing $1.35 billion Senior Secured Credit Facility. The Senior Unsecured Credit Facility provides a $1.8 billion Revolving Credit Facility and a $950.0 million Term Loan Facility. The Revolving Credit Facility replaced our previous $900.0 million revolving credit facility and the increased capacity is intended to accommodate working capital needs, letters of credit, the funding of capital expenditures and other general corporate purposes. The Revolving Credit Facility also includes a $50.0 million sub-facility available for same-day swingline loan borrowings. In September 2006, we borrowed $312.0 million under the Revolver in conjunction with the Excel acquisition and repaid this $312.0 million outstanding balance in December 2006 with net proceeds from the Debentures.
      The Term Loan Facility consisted of an unsecured $440.0 million portion, which was drawn at closing to replace the previous term loan ($437.5 million balance at time of replacement; $442.5 million at December 31, 2005) issued under the Senior Secured Credit Facility. The Term Loan Facility also included a Delayed Draw Term Loan Sub-Facility of up to $510.0 million, which was fully drawn in October 2006 in connection with the Excel acquisition. In December 2006, $403.0 million of the outstanding balance of the Term Loan Facility ($950.0 million was outstanding at time of repayment) was repaid with the net proceeds from the Debentures. In conjunction with the establishment of the Senior Unsecured Credit Facility, we incurred $8.6 million in financing costs, of which $5.6 million related to the Revolving Credit Facility and $3.0 million related to the Term Loan Facility. These debt issuance costs will be amortized to interest expense over five years, the term of the Senior Unsecured Credit Facility.
      Loans under the facility are available in U.S. dollars, with a sub-facility under the Revolving Credit Facility available in Australian dollars, pounds sterling and Euros. Letters of credit under the Revolving Credit Facility are available to us in U.S. dollars with a sub-facility available in Australian dollars, pounds sterling and Euros. The interest rate payable on the Revolving Credit Facility and the Term Loan Facility under the Senior Unsecured Credit Facility is LIBOR plus 1.0% with step-downs to LIBOR plus 0.50% based on improvement in the leverage ratio, as defined in the Third Amended and Restated Credit Agreement. The rate applicable to the Term Loan Facility was 6.35% at December 31, 2006.

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      Under the Senior Unsecured Credit Facility, we must comply with certain financial covenants on a quarterly basis including a minimum interest coverage ratio and a maximum leverage ratio, as defined in the Third Amended and Restated Credit Agreement. The financial covenants also place limitations on our investments in joint ventures, unrestricted subsidiaries, indebtedness of non-loan parties, and the imposition of liens on our assets. The new facility is less restrictive with respect to limitations on our dividend payments, capital expenditures, asset sales or stock repurchases. The Senior Unsecured Credit Facility matures on September 15, 2011.
      As of December 31, 2006, we had no borrowings outstanding under our Revolving Credit Facility. Our revolving line of credit was primarily used for standby letters of credit until September 2006, when we also used the revolving line of credit to facilitate the Excel acquisition. As discussed above, the $312.0 million outstanding under the revolving line of credit was repaid in December 2006 with net proceeds from the Debentures. The remaining available borrowing capacity ($1.29 billion as of December 31, 2006) will be used to fund strategic acquisitions or meet other financing needs, including standby letters of credit. During 2005, we had no borrowings outstanding under our previous $900.0 million revolving line of credit, which we used primarily for standby letters of credit. We were in compliance with all of the covenants of the Senior Unsecured Credit Facility, the 6.875% Senior Notes, the 5.875% Senior Notes, the 7.375% Senior Notes, the 7.875% Senior Notes, and the Convertible Junior Subordinated Debentures as of December 31, 2006.
Convertible Junior Subordinated Debentures
      On December 20, 2006, we issued $732.5 million aggregate principal amount of 4.75% Convertible Junior Subordinated Debentures due 2066 (the “Debentures”), including $57.5 million issued pursuant to the underwriters’ exercise of their over-allotment option. Net proceeds from the offering, after deducting underwriting discounts and offering expenses, were $715.0 million and were used to repay indebtedness under our Senior Unsecured Credit Facility. The Debentures will pay interest semiannually at a rate of 4.75% per year. We may elect to, and if and to the extent that a mandatory trigger event (as defined in the indenture governing the Debentures) has occurred and is continuing will be required to, defer interest payments on the Debentures. After five years of deferral at our option, or upon the occurrence of a mandatory trigger event, we generally must sell warrants or preferred stock with specified characteristics and use the funds from that sale to pay deferred interest, subject to certain limitations. In no event may we defer payments of interest on the Debentures for more than ten years.
      The Debentures are convertible at any time on or prior to December 15, 2036 if any of the following conditions occur: (i) our closing common stock price exceeds 140% of the then applicable conversion price for the Debentures (currently $86.73 per share) for at least 20 of the final 30 trading days in any quarter; (ii) a notice of redemption is issued with respect to the Debentures; (iii) a change of control, as defined in the indenture governing the Debentures; (iv) satisfaction of certain trading price conditions; and (v) other specified corporate transactions described in the indenture governing the Debentures. In addition, the Debentures are convertible at any time after December 15, 2036 to December 15, 2041, the scheduled maturity date. In the case of conversion following a notice of redemption or upon a non-stock change of control, as defined in the indenture governing the Debentures, holders may convert their Debentures into cash in the amount of the principal amount of their Debentures and shares of our common stock for any conversion value in excess of the principal amount. In all other conversion circumstances, holders will receive perpetual preferred stock (see Note 17 to our consolidated financial statements) with a liquidation preference equal to the principal amount of their Debentures, and any conversion value in excess of the principal amount will be settled with our common stock. The consideration delivered upon conversion will be based upon an initial conversion rate of 16.1421 shares of common stock per $1,000 principal amount of Debentures, subject to adjustment. This conversion rate represents an initial conversion price of approximately $61.95 per share, a 40% premium over the closing stock price of $44.25 on December 14, 2006, the date of the pricing of the offering of the Debentures.
      The Debentures are unsecured obligations, ranking junior to all existing and future senior and subordinated debt (excluding trade accounts payable or accrued liabilities arising in the ordinary course of

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business) except for any future debt that ranks equal to or junior to the Debentures. The Debentures will rank equal in right of payment with our obligations to trade creditors. Substantially, all of our existing indebtedness is senior to the Debentures. In addition, the Debentures will be effectively subordinated to all indebtedness of our subsidiaries. The indenture governing the Debentures places no limitation on the amount of additional indebtedness that we or any of our subsidiaries may incur (see Note 12 of our consolidated financial statements for additional information on the Debentures).
7.375% Senior Notes Due November 2016 and 7.875% Senior Notes Due November 2026
      On October 12, 2006, we completed a $650 million offering of 7.375% 10-year Senior Notes due 2016 and $250 million of 7.875% 20-year Senior Notes due 2026. The notes are general unsecured obligations and rank senior in right of payment to any subordinated indebtedness; equally in right of payment with any senior indebtedness; effectively junior in right of payment to our existing and future secured indebtedness, to the extent of the value of the collateral securing that indebtedness; and effectively junior to all the indebtedness and other liabilities of our subsidiaries that do not guarantee the notes. Interest payments are scheduled to occur on May 1 and November 1 of each year, commencing on May 1, 2007.
      The notes are guaranteed by our Subsidiary Guarantors, as defined in the note indenture. The note indenture contains covenants that, among other things, limit our ability to create liens and enter into sale and lease-back transactions. The notes are redeemable at a redemption price equal to 100% of the principal amount of the notes being redeemed plus a make-whole premium, if applicable, and any accrued unpaid interest to the redemption date. Net proceeds from the offering, after deducting underwriting discounts and expenses, were $886.1 million.
Series Bonds
      As of December 31, 2006, we had $74.0 million in Series Bonds outstanding, which were assumed as part of the Excel acquisition. The 6.84% Series A Bonds have a balloon maturity in December 2014. The 6.34% Series B Bonds mature in December 2014 and are payable in installments beginning December 2008. The 6.84% Series C Bonds mature in December 2016 and are payable in installments beginning December 2012. Interest payments occur in June and December of each year.
Interest Rate Swaps
      Prior to completion of the Senior Unsecured Credit Facility, we had two $400.0 million interest rate swaps. A $400.0 million notional amount floating-to-fixed interest rate swap was designated as a hedge of changes in expected cash flows on the previous term loan under the Senior Secured Credit Facility. Under this swap, we paid a fixed rate of 6.764% and received a floating rate of LIBOR plus 2.5% that reset each March 15, June 15, September 15 and December 15 based upon the three-month LIBOR rate. A $400.0 million notional amount fixed-to-floating interest rate swap was designated as a hedge of the changes in the fair value of the 6.875% Senior Notes due 2013. Under this swap, we paid a floating rate of LIBOR plus 1.97% that reset each March 15, June 15, September 15 and December 15 based upon the three-month LIBOR rate and received a fixed rate of 6.875%.
      In conjunction with the completion of the new Senior Unsecured Credit Facility, the $400.0 million notional amount floating-to-fixed interest rate swap was terminated and resulted in payment to us of $5.2 million. We recorded the $5.2 million fair value of the swap in “Accumulated other comprehensive loss” on the consolidated balance sheet and will amortize this amount to interest expense over the remaining term of the forecasted interest payments initially hedged. We then entered into a $120.0 million notional amount floating-to-fixed interest rate swap with a fixed rate of 6.25% and a floating rate of LIBOR plus 1.0%. This interest rate swap was designated as a hedge of the variable interest payments on the Term Loan under the new Senior Unsecured Credit Facility.
      We also terminated $280.0 million of our $400.0 million notional amount fixed-to-floating interest rate swap designated as a hedge of the changes in fair value of the 6.875% Senior Notes due 2013. Reducing the notional amount of the interest rate swap to $120.0 million resulted in payment of $5.2 million to the

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counterparty. Reduction of the notional amount of the swap did not affect our floating and fixed rates. The $5.2 million of fair value associated with the termination of the $280.0 million portion of the swap was recorded as an adjustment to the carrying value of long-term debt and will be amortized to interest expense through maturity of the 6.875% Senior Notes due 2013.
      Because the critical terms of the swaps and the respective debt instruments they hedge coincide, there was no hedge ineffectiveness recognized in the consolidated statements of operations during the years ended December 31, 2006 and 2005. At December 31, 2006 there was an unrealized loss related to the cash flow hedge of $2.5 million and at December 31, 2005 there was an unrealized gain related to the cash flow hedge of $2.3 million. As of December 31, 2006 and 2005, the net unrealized loss on the fair value hedges discussed above were $13.8 million and $8.9 million, respectively, which is reflected as an adjustment to the carrying value of the Senior Notes (see table above).
Third-party Security Ratings
      In 2006, third-party rating agencies performed a comprehensive review of our securities’ ratings based on our entrance into the new senior unsecured credit facility and the issuance of additional debt securities to facilitate the Excel acquisition. The ratings for our senior unsecured credit facility and our senior unsecured notes are as follows: Moody’s issued a Ba1 rating, Standard & Poor’s issued a BB rating and Fitch issued a BB+ rating. The rating on our convertible junior subordinated debentures issued in December 2006 were as follows: Moody’s issued a Ba2 rating, Standard & Poor’s issued a B rating and Fitch issued a BB- rating. These security ratings reflected the views of the rating agency only. An explanation of the significance of these ratings may be obtained from the rating agency. Such ratings are not a recommendation to buy, sell or hold securities, but rather an indication of creditworthiness. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant the change. Each rating should be evaluated independently of any other rating.
Shelf Registration Statement
      On July 28, 2006, we filed an automatic shelf registration statement on Form S-3 as a well-known seasoned issuer with the Securities and Exchange Commission. The registration was for an indeterminate number of securities and is effective for three years, at which time we can file an automatic shelf registration statement that would become immediately effective for another three-year term. Under this universal shelf registration statement, we have the capacity to offer and sell from time to time securities, including common stock, preferred stock, debt securities, warrants and units. The Debentures, 7.375% Senior Notes due 2016 and 7.875% Senior Notes due 2026 were issued pursuant to the shelf registration statement.
Excel Transaction
      On July 5, 2006, we signed a merger implementation agreement to acquire Excel Coal Limited (“Excel”), an independent coal company, by means of a scheme of arrangement transaction under Australian law. The merger implementation agreement was amended on September 18, 2006, and we agreed to pay A$9.50 per share (US$7.16 as of the amendment date) for the outstanding shares of Excel. On September 20, 2006, as part of the amended agreement, we acquired 19.99% of the outstanding shares of Excel at A$9.50 per share, resulting in payment of A$408.3 million, or US$307.8 million. In October 2006, we acquired the remaining interest in Excel for A$9.50 per share (US$7.07 per share), a total of A$1.63 billion or US$1.21 billion. The total acquisition price, including the advance purchase of 19.99% and related costs, was US$1.54 billion in cash plus assumed debt of US$293.0 million, less US$30.0 million of cash acquired in the transaction, and was financed with borrowings under our Senior Unsecured Credit Facility and Senior Notes due 2016 and 2026 (see Note 12 of our consolidated financial statements for additional information on the financing of the Excel acquisition). The Excel acquisition includes three operating mines (Wambo Open-Cut Mine, Metropolitan Mine and Chain Valley Mine) and three development-stage mines (North Wambo Underground Mine, Wilpinjong Mine and Millennium Mine), with more than 500 million tons of proven and probable coal reserves. We also acquired a 51.0%

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interest in Excelven Pty Ltd., which owns Transportes Coal-Sea de Venezuela C.A. and a 96.7% interest in Cosila Complejo Siderurgico Del Lago S.A., which owns the Las Carmelitas coal mine development project. The results of operations of Excel are included in our Australian Mining Operations segment from October 2006. The acquisition was accounted for as a purchase in accordance with SFAS No. 141, “Business Combinations” (see Note 4 of our consolidated financial statements for additional information on the Excel acquisition).
Contractual Obligations
      The following is a summary of our contractual obligations as of December 31, 2006:
                                   
    Payments Due By Year
     
    Within       After
    1 Year   2-3 Years   4-5 Years   5 Years
                 
    (Dollars in thousands)
Long-term debt obligations (principal and interest)
  $ 303,849     $ 481,974     $ 859,965     $ 4,323,807  
Capital lease obligations (principal and interest)
    11,335       21,806       15,686       23,428  
Operating leases obligations
    102,256       152,264       101,386       168,076  
Unconditional purchase obligations(1)
    125,791                    
Coal reserve lease and royalty obligations
    216,996       344,407       25,459       46,611  
Other long-term liabilities(2)
    170,716       337,809       396,113       1,362,711  
                         
 
Total contractual cash obligations
  $ 930,943     $ 1,338,260     $ 1,398,609     $ 5,924,633  
                         
 
(1)  We have purchase agreements with approved vendors for most types of operating expenses. However, our specific open purchase orders (which have not been recognized as a liability) under these purchase agreements, combined with any other open purchase orders, are not material. The commitments in the table above relate to significant capital purchases.
 
(2)  Represents long-term liabilities relating to our postretirement benefit plans, work-related injuries and illnesses, defined benefit pension plans and mine reclamation and end of mine closure costs.
      As of December 31, 2006, we had $125.8 million of purchase obligations for capital expenditures and $479.8 million of obligations related to federal coal reserve lease payments due over the next three years. Total capital expenditures for 2007 are expected to range from $450 million to $525 million, excluding federal coal reserve lease payments, and relate to replacement, improvement, or expansion of existing mines, particularly in Australia, Appalachia and the Midwest, and growth initiatives such as increasing capacity in the Powder River Basin. Approximately $10 million of the expenditures relate to safety equipment that will be utilized to comply with recently issued federal and state regulations. Capital expenditures were funded primarily through operating cash flow. Despite the acquisition of three development stage mines in 2006, we will exercise capital discipline in 2007, limiting capital expenditures to 2006 levels.
      Our subsidiary, Peabody Pacific, has committed to pay up to a maximum of A$0.20/tonne (approximately US$0.15/tonne) of coal sales for a period of five years to the Australian COAL21 Fund. The COAL21 Fund is a voluntary coal industry fund to support clean coal technology demonstration projects and research in Australia. All major coal companies in Australia have committed to this fund. The commitment to pay starts on April 1, 2007 with a levy of A$0.10/tonne of coal sales. This levy is expected to rise to A$0.20/tonne on July 1, 2007.
Off-Balance Sheet Arrangements
      In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees, indemnifications, financial instruments with off-balance sheet risk, such

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as bank letters of credit and performance or surety bonds and our accounts receivable securitization. Liabilities related to these arrangements are not reflected in our consolidated balance sheets, and we do not expect any material adverse effects on our financial condition, results of operations or cash flows to result from these off-balance sheet arrangements.
      We use a combination of surety bonds, corporate guarantees (i.e. self bonds) and letters of credit to secure our financial obligations for reclamation, workers’ compensation, postretirement benefits and coal lease obligations as follows as of December 31, 2006:
                                                 
            Workers’   Retiree        
    Reclamation   Lease   Compensation   Healthcare        
    Obligations   Obligations   Obligations   Obligations   Other(1)   Total
                         
    (Dollars in millions)
Self Bonding
  $ 685.3     $     $     $     $ 2.9     $ 688.2  
Surety Bonds
    441.5       83.9       31.7             27.2       584.3  
Letters of Credit
    4.1       20.3       156.8       119.4       208.8       509.4  
                                     
    $ 1,130.9     $ 104.2     $ 188.5     $ 119.4     $ 238.9     $ 1,781.9  
                                     
 
(1)  Includes financial guarantees primarily related to joint venture debt, the Pension Benefit Guarantee Corporation and collateral for surety companies.
      As part of arrangements through which we obtain exclusive sales representation agreements with small coal mining companies (the “Counterparties”), we issued financial guarantees on behalf of the Counterparties. These guarantees facilitate the Counterparties’ efforts to obtain bonding or financing. In July 2006, we issued $5.2 million of financial guarantees, expiring at various dates through July 2013, on behalf of a small coal producer to facilitate its efforts in obtaining financing. In the event of default, we have multiple recourse options, including the ability to assume the loans and procure title and use of the equipment purchased through the loans. If default occurs, we have the ability and intent to exercise our recourse options, so the liability associated with the guarantee has been valued at zero. We have also guaranteed bonding for a partnership in which we formerly held an interest. The aggregate amount guaranteed for all such Counterparties was $12.1 million, and the fair value of the guarantees recognized as a liability was $0.4 million as of December 31, 2006. Our obligations under the guarantees extend to September 2015. In March 2006, we issued a guarantee for certain equipment lease arrangements on behalf of one of the sales representation parties with maximum potential future payments totaling $2.7 million at December 31, 2006, and with lease terms that extend to April 2010. See Note 21 to our consolidated financial statements included in this report for a discussion of our guarantees.
      Under our accounts receivable securitization program, undivided interests in a pool of eligible trade receivables contributed to our wholly-owned, bankruptcy-remote subsidiary are sold, without recourse, to a multi-seller, asset-backed commercial paper conduit (“Conduit”). Purchases by the Conduit are financed with the sale of highly rated commercial paper. We utilize proceeds from the sale of our accounts receivable as an alternative to other forms of debt, effectively reducing our overall borrowing costs. The funding cost of the securitization program was $1.9 million and $2.5 million for the years ended December 31, 2006 and 2005, respectively. The securitization program is scheduled to expire in September 2009. The securitization transactions have been recorded as sales, with those accounts receivable sold to the Conduit removed from the consolidated balance sheets. The amount of undivided interests in accounts receivable sold to the Conduit was $219.2 million and $225.0 million as of December 31, 2006 and 2005 (see Note 6 to our consolidated financial statements for additional information on accounts receivable securitization).

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      The following is a summary of specified types of commercial commitments available to us as of December 31, 2006:
                                         
    Expiration Per Year
     
    Total Amounts   Within       Over
    Committed   1 Year   2-3 Years   4-5 Years   5 Years
                     
    (Dollars in thousands)
Lines of credit and/ or standby letters of credit
  $ 1,800,000     $     $     $ 1,800,000     $  
Newly Adopted Accounting Pronouncements
      We adopted Emerging Issues Task Force (“EITF”) Issue No. 04-6, “Accounting for Stripping Costs in the Mining Industry” (“EITF Issue No. 04-6”) on January 1, 2006 and utilized the cumulative effect adjustment approach whereby a cumulative effect adjustment reduced retained earnings by $150.3 million, net of tax. EITF Issue No. 04-6 states “that stripping costs incurred during the production phase of a mine are variable production costs that should be included in the costs of the inventory produced during the period that the stripping costs are incurred.” Advance stripping costs include those costs necessary to remove overburden above an unmined coal seam as part of the surface mining process and prior to the adoption were included as the “work-in-process” component of “Inventories” in the consolidated balance sheet. EITF Issue No. 04-6 and its interpretations require stripping costs incurred during a period to be attributed only to the inventory costs of the coal that is extracted during that same period, and therefore, advance stripping costs are no longer separately classified as a component of inventory.
      On January 1, 2006, we adopted SFAS No. 123 (revised 2004), “Share-Based Payment” (“SFAS No. 123(R)”), which is a revision of SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123”). SFAS No. 123(R) supersedes Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB Opinion No. 25”) and amends SFAS No. 95, “Statement of Cash Flows.” Prior to January 1, 2006, we applied APB Opinion No. 25 and related interpretations in accounting for our stock option plans, as permitted under SFAS No. 123 and SFAS No. 148 “Accounting for Stock-Based Compensation-Transition and Disclosure.” We applied SFAS No. 123(R) through use of the modified prospective method, in which compensation cost is recognized beginning with the effective date (a) based on the requirements of SFAS No. 123(R) for all share-based payments granted or modified after the effective date and (b) based on the requirements of SFAS No. 123 for all awards granted to employees prior to the effective date of SFAS No. 123(R) that remain unvested on the effective date. SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values at the grant date. SFAS No. 123(R) also requires that the excess income tax benefits from stock options exercised be recorded as financing cash inflow on the statements of cash flows. The excess income tax benefit from stock option exercises during 2005 and 2004 are included in operating cash flows, netted in deferred tax activity.
      For share-based payment instruments excluding restricted stock, we recognized $17.7 million (or $0.07 per diluted share), $24.8 million (or $0.09 per diluted share) and $12.8 million (or $0.05 per diluted share) of expense, net of taxes, for the years ended December 31, 2006, 2005 and 2004, respectively. As a result of adopting SFAS No. 123(R), our net income for the year ended December 31, 2006 was $4.4 million (or $0.02 per diluted share) lower than if we had continued to account for share-based compensation under APB Opinion No. 25. Share-based compensation expense is recorded in “Selling and administrative expenses” in the consolidated statements of operations. We used the Black-Scholes option pricing model to determine the fair value of stock options and employee stock purchase plan share-based payments made before and after the adoption of SFAS No. 123(R). We began utilizing restricted stock as part of our equity-based compensation strategy in January 2005. Accounting for restricted stock awards was not changed by the adoption of SFAS No. 123(R). As of December 31, 2006, the total unrecognized compensation cost related to nonvested awards was $24.0 million, net of taxes, which is expected to be

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recognized over 5.0 years with a weighted-average period of 1.3 years. See Note 18 to our consolidated financial statements for further discussion of our share-based compensation plans.
      In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (“SFAS No. 158”). For fiscal years ending after December 15, 2006, SFAS No. 158 requires recognition of the funded status of pension and other postretirement benefit plans (an asset for overfunded status or a liability for underfunded status) in a company’s balance sheet. In addition, the standard requires recognition of actuarial gains and losses, prior service cost, and any remaining transition amounts from the initial application of SFAS No. 87, “Employers’ Accounting for Pensions” (“SFAS No. 87”) and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” (“SFAS No. 106”) when determining a plan’s funded status, with a corresponding charge to accumulated other comprehensive income (loss).
      We adopted SFAS No. 158 on December 31, 2006, and as a result, recorded a noncurrent liability of $376.1 million, which reflected the total underfunded status of the pension, retiree healthcare and workers’ compensation plans. The funded status of each plan was measured as the difference between the fair value of the assets and the projected benefit obligation (the “funded status”). SFAS No. 158 did not impact net income. The impact to the balance sheet was as follows (see Notes 14, 15, and 16 to our consolidated financial statements for additional details):
                         
            After Application
    Before Application       of
    of SFAS No. 158   Adjustments   SFAS No. 158
             
    (Dollars in thousands)
Workers’ compensation obligations
  $ 237,965     $ (4,558 )   $ 233,407  
Accrued postretirement benefit costs
    973,164       395,522       1,368,686  
Other noncurrent liabilities (includes long-term pension and UMWA Combined Fund liabilities)
    375,485       (14,855 )     360,630  
Deferred income taxes (long-term liability)
    344,712       (149,499 )     195,213  
Total liabilities
    6,915,583       226,610       7,142,193  
Accumulated other comprehensive loss
    (22,448 )     (226,610 )     (249,058 )
Total stockholders’ equity
    2,565,136       (226,610 )     2,338,526  
Accounting Pronouncements Not Yet Implemented
      In June 2006, the FASB issued FIN No. 48. This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN No. 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. This interpretation is effective for fiscal years beginning after December 15, 2006 (January 1, 2007 for the Company). Any adjustments required upon the adoption of this interpretation must be recorded directly to retained earnings in the year of adoption and reported as a change in accounting principle. We expect the adoption of FIN No. 48 will not have a material impact on our financial position.

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Item 8. Financial Statements and Supplementary Data.
      See Part IV, Item 15 of this report for information required by this Item.

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PART IV
Item 15. Exhibits and Financial Statement Schedules.
      (a) Documents Filed as Part of the Report
        (1) Financial Statements.
 
        The following consolidated financial statements of Peabody Energy Corporation are included herein on the pages indicated:
         
    Page
     
Report of Independent Registered Public Accounting Firm
    F-1  
Consolidated Statements of Operations — Years Ended December 31, 2006, 2005 and 2004
    F-2  
Consolidated Balance Sheets — December 31, 2006 and December 31, 2005
    F-3  
Consolidated Statements of Cash Flows — Years Ended December 31, 2006, 2005 and 2004
    F-4  
Consolidated Statements of Changes in Stockholders’ Equity — Years Ended December 31, 2006, 2005 and 2004
    F-5  
Notes to Consolidated Financial Statements
    F-6  
        (2) Financial Statement Schedule.
 
        The following financial statement schedule of Peabody Energy Corporation and the report thereon of the independent registered public accounting firm are at the pages indicated:
         
    Page
     
Report of Independent Registered Public Accounting Firm on Financial Statement Schedule
    F-72  
Valuation and Qualifying Accounts
    F-73  
        All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions or are inapplicable and, therefore, have been omitted.
 
        (3) Exhibits.
 
        See Exhibit Index hereto.

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SIGNATURE
      Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
  PEABODY ENERGY CORPORATION
 
  /s/ RICHARD A. NAVARRE
 
 
  Richard A. Navarre
  Chief Financial Officer and Executive
Vice President of Corporate Development
Date: September 7, 2007

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Peabody Energy Corporation
      We have audited the accompanying consolidated balance sheets of Peabody Energy Corporation as of December 31, 2006 and 2005, and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
      We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
      In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Peabody Energy Corporation at December 31, 2006 and 2005, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.
      As discussed in Note 1 to the consolidated financial statements, on January 1, 2006, the Company changed its method of accounting for stripping costs and share-based payments, and on December 31, 2006, the Company changed its method of accounting for defined pension benefit and other postretirement plans.
      We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Peabody Energy Corporation’s internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 20, 2007, expressed an unqualified opinion thereon.
  /s/ Ernst & Young LLP
St. Louis, Missouri
February 20, 2007

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PEABODY ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
                             
    Year Ended December 31,
     
    2006   2005   2004
             
    (Dollars in thousands, except share and per share data)
Revenues
                       
 
Sales
  $ 5,144,925     $ 4,545,323     $ 3,545,027  
 
Other revenues
    111,390       99,130       86,555  
                   
   
Total revenues
    5,256,315       4,644,453       3,631,582  
Costs and Expenses
                       
 
Operating costs and expenses
    4,155,984       3,715,836       2,965,541  
 
Depreciation, depletion and amortization
    377,210       316,114       270,159  
 
Asset retirement obligation expense
    40,112       35,901       42,387  
 
Selling and administrative expenses
    175,941       189,802       143,025  
 
Other operating income:
                       
   
Net gain on disposal or exchange of assets
    (132,162 )     (101,487 )     (23,829 )
   
Income from equity affiliates
    (23,852 )     (30,096 )     (12,399 )
                   
Operating Profit
    663,082       518,383       246,698  
 
Interest expense
    143,450       102,939       96,793  
 
Early debt extinguishment costs
    1,396             1,751  
 
Interest income
    (12,726 )     (10,641 )     (4,917 )
                   
Income From Continuing Operations Before Income Taxes and Minority Interests
    530,962       426,085       153,071  
 
Income tax provision (benefit)
    (81,515 )     960       (26,437 )
 
Minority interests
    11,780       2,472       1,282  
                   
Income From Continuing Operations
    600,697       422,653       178,226  
 
Loss from discontinued operations, net of income tax benefit of $1,893
                (2,839 )
                   
Net Income
  $ 600,697     $ 422,653     $ 175,387  
                   
Basic Earnings Per Share
                       
 
Income from continuing operations
  $ 2.28     $ 1.62     $ 0.72  
 
Loss from discontinued operations
                (0.01 )
                   
   
Net income
  $ 2.28     $ 1.62     $ 0.71  
                   
Weighted Average Shares Outstanding — Basic
    263,419,344       261,519,424       248,732,744  
                   
Diluted Earnings Per Share
                       
 
Income from continuing operations
  $ 2.23     $ 1.58     $ 0.70  
 
Loss from discontinued operations
                (0.01 )
                   
   
Net income
  $ 2.23     $ 1.58     $ 0.69  
                   
Weighted Average Shares Outstanding — Diluted
    269,166,005       268,013,476       254,812,632  
                   
Dividends Declared Per Share
  $ 0.24     $ 0.17     $ 0.13  
                   
See accompanying notes to consolidated financial statements

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PEABODY ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
                       
    December 31,
     
    2006   2005
         
    (Dollars in thousands, except
    share and per share data)
ASSETS
Current assets
               
 
Cash and cash equivalents
  $ 326,511     $ 503,278  
 
Accounts receivable, net of allowance for doubtful accounts of $11,144 and $10,853 at December 31, 2006 and 2005, respectively
    358,242       202,134  
 
Inventories
    215,384       389,771  
 
Assets from coal trading activities
    150,373       146,596  
 
Deferred income taxes
    106,967       9,027  
 
Other current assets
    116,863       54,431  
             
   
Total current assets
    1,274,340       1,305,237  
Property, plant, equipment and mine development
               
 
Land and coal interests
    7,127,385       4,775,126  
 
Buildings and improvements
    893,049       793,254  
 
Machinery and equipment
    1,516,765       1,237,184  
 
Less accumulated depreciation, depletion and amortization
    (1,985,682 )     (1,627,856 )
             
Property, plant, equipment and mine development, net
    7,551,517       5,177,708  
Goodwill
    240,667        
Investments and other assets
    447,532       369,061  
             
   
Total assets
  $ 9,514,056     $ 6,852,006  
             
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
               
 
Current maturities of long-term debt
  $ 95,757     $ 22,585  
 
Liabilities from coal trading activities
    126,731       132,373  
 
Accounts payable and accrued expenses
    1,145,043       867,965  
             
   
Total current liabilities
    1,367,531       1,022,923  
Long-term debt, less current maturities
    3,168,069       1,382,921  
Deferred income taxes
    195,213       338,488  
Asset retirement obligations
    423,031       399,203  
Workers’ compensation obligations
    233,407       237,574  
Accrued postretirement benefit costs
    1,368,686       959,222  
Other noncurrent liabilities
    386,256       330,658  
             
   
Total liabilities
    7,142,193       4,670,989  
Minority interests
    33,337       2,550  
Stockholders’ equity
               
 
Preferred Stock — $0.01 per share par value; 10,000,000 shares authorized, no shares issued or outstanding as of December 31, 2006 or 2005
           
   
Series A Junior Participating Preferred Stock — 1,500,000 shares authorized, no shares issued or outstanding as of December 31, 2006 or 2005
           
   
Perpetual Preferred Stock — 750,000 shares authorized, no shares issued or outstanding as of December 31, 2006 or 2005
           
 
Series Common Stock — $0.01 per share par value; 40,000,000 shares authorized, no shares issued or outstanding as of December 31, 2006 or 2005
           
 
Common Stock — $0.01 per share par value; 800,000,000 shares authorized, 266,554,157 shares issued and 263,846,839 shares outstanding as of December 31, 2006 and 400,000,000 shares authorized, 263,879,762 shares issued and 263,357,402 shares outstanding as of December 31, 2005
    2,666       2,638  
 
Additional paid-in capital
    1,572,614       1,497,454  
 
Retained earnings
    1,115,994       729,086  
 
Accumulated other comprehensive loss
    (249,058 )     (46,795 )
 
Treasury shares, at cost: 2,707,318 shares as of December 31, 2006 and 522,360 shares as of December 31, 2005
    (103,690 )     (3,916 )
             
   
Total stockholders’ equity
    2,338,526       2,178,467  
             
     
Total liabilities and stockholders’ equity
  $ 9,514,056     $ 6,852,006  
             
See accompanying notes to consolidated financial statements

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Table of Contents

PEABODY ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
                             
    Year Ended December 31,
     
    2006   2005   2004
             
    (Dollars in thousands)
Cash Flows From Operating Activities
                       
Net income
  $ 600,697     $ 422,653     $ 175,387  
 
Loss from discontinued operations
                2,839  
                   
   
Income from continuing operations
    600,697       422,653       178,226  
Adjustments to reconcile income from continuing operations to net cash provided by operating activities:
                       
 
Depreciation, depletion and amortization
    377,210       316,114       270,159  
 
Deferred income taxes
    (189,243 )     (24,962 )     (31,925 )
 
Amortization of debt discount and debt issuance costs
    7,410       6,938       8,330  
 
Net gain on disposal or exchange of assets
    (132,162 )     (101,487 )     (23,829 )
 
Income from equity affiliates
    (23,852 )     (30,096 )     (12,399 )
 
Dividends received from equity affiliates
    28,063       7,552       13,614  
 
Changes in current assets and liabilities, net of acquisitions:
                       
   
Accounts receivable, net of sale
    (103,399 )     (52,757 )     (34,649 )
   
Inventories
    (38,208 )     (67,125 )     (57,781 )
   
Net assets from coal trading activities
    (9,419 )     11,377       (3,583 )
   
Other current assets
    (24,108 )     (10,769 )     (1,438 )
   
Accounts payable and accrued expenses
    88,014       173,919       66,576  
 
Asset retirement obligations
    (52 )     (981 )     (6,571 )
 
Workers’ compensation obligations
    391       11,390       10,479  
 
Accrued postretirement benefit costs
    13,942       19,719       (32,499 )
 
Contributions to pension plans
    (6,146 )     (7,162 )     (62,082 )
 
Other, net
    6,588       28,436       3,132  
                   
   
Net cash provided by operating activities
    595,726       702,759       283,760  
                   
Cash Flows From Investing Activities
                       
Acquisition of Excel Coal, net of cash acquired
    (1,507,775 )            
Other acquisitions, net
    (44,538 )           (429,061 )
Additions to property, plant, equipment and mine development
    (477,721 )     (384,304 )     (151,944 )
Purchase of mining and related assets
          (141,195 )      
Federal coal lease expenditures
    (178,193 )     (118,364 )     (114,653 )
Proceeds from disposal of assets, net of notes receivable
    77,579       76,227       39,339  
Additions to advance mining royalties
    (11,021 )     (14,566 )     (16,239 )
Investments in joint ventures
    (2,149 )     (2,000 )     (32,472 )
                   
   
Net cash used in investing activities
    (2,143,818 )     (584,202 )     (705,030 )
                   
Cash Flows From Financing Activities
                       
Proceeds from long-term debt
    2,580,295       11,734       700,013  
Payments of long-term debt
    (1,045,973 )     (20,198 )     (482,924 )
Common stock repurchase
    (99,774 )            
Dividends paid
    (63,456 )     (44,535 )     (32,568 )
Payment of debt issuance costs
    (40,611 )           (12,875 )
Excess tax benefit related to stock options exercised
    33,173              
Net proceeds from equity offering
                383,125  
Proceeds from stock options exercised
    15,617       22,573       27,266  
Distributions to minority interests
    (6,664 )     (2,498 )     (1,007 )
Increase (decrease) of securitized interests in accounts receivable
    (5,800 )     25,000       110,000  
Proceeds from employee stock purchases
    4,518       3,009       2,374  
                   
   
Net cash provided by (used in) financing activities
    1,371,325       (4,915 )     693,404  
                   
Net increase (decrease) in cash and cash equivalents
    (176,767 )     113,642       272,134  
Cash and cash equivalents at beginning of year
    503,278       389,636       117,502  
                   
Cash and cash equivalents at end of year
  $ 326,511     $ 503,278     $ 389,636  
                   
See accompanying notes to consolidated financial statements

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PEABODY ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
                                                               
                Accumulated            
        Additional   Other   Other           Total
    Common   Paid-In   Employee   Comprehensive   Retained   Treasury   Stockholders’
    Stock   Capital   Stock Loans   Loss   Earnings   Stock   Equity
                             
    (Dollars in thousands)
December 31, 2003
  $ 2,190     $ 1,007,008     $ (31 )   $ (81,572 )   $ 208,149     $ (3,687 )   $ 1,132,057  
 
Comprehensive income:
                                                       
   
Net income
                            175,387             175,387  
   
Increase in fair value of cash flow hedges (net of $9,945 tax provision)
                      14,915                   14,915  
   
Minimum pension liability adjustment (net of $4,026 tax provision)
                      6,039                   6,039  
                                           
 
Comprehensive income
                                                    196,341  
 
Issuance of common stock in connection with equity offering, net of expenses
    352       382,773                               383,125  
 
Dividends paid
                            (32,568 )           (32,568 )
 
Loan repayments
                31                         31  
 
Stock options exercised
    54       27,621                               27,675  
 
Income tax benefits from stock options exercised
          15,718                               15,718  
 
Employee stock purchases
          2,343                               2,343  
 
Employee stock grants
                                         
 
Share-based compensation
          99                               99  
 
Shares repurchased
                                  (229 )     (229 )
                                           
December 31, 2004
  $ 2,596     $ 1,435,562     $     $ (60,618 )   $ 350,968     $ (3,916 )   $ 1,724,592  
 
Comprehensive income:
                                                       
   
Net income
                            422,653             422,653  
   
Increase in fair value of cash flow hedges (net of $7,613 tax provision)
                      11,421                   11,421  
   
Minimum pension liability adjustment (net of $1,601 tax provision)
                      2,402                   2,402  
                                           
 
Comprehensive income
                                                    436,476  
 
Dividends paid
                            (44,535 )           (44,535 )
 
Stock options exercised
    36       22,627                               22,663  
 
Income tax benefits from stock options exercised
          30,437                               30,437  
 
Employee stock purchases
    2       3,007                               3,009  
 
Employee stock grants
    4       (4 )                              
 
Share-based compensation
          5,825                               5,825  
                                           
December 31, 2005
  $ 2,638     $ 1,497,454     $     $ (46,795 )   $ 729,086     $ (3,916 )   $ 2,178,467  
 
Comprehensive income:
                                                       
   
Net income
                            600,697             600,697  
   
Increase in fair value of cash flow hedges (net of $16,230 tax provision)
                      24,347                   24,347  
   
Minimum pension liability adjustment (net of $16,842 tax provision)
                      22,377                   22,377  
                                           
 
Comprehensive income
                                                    647,421  
 
Postretirement plans and workers’ compensation obligations (net of $149,499 tax benefit):
                                                       
     
Accumulated actuarial loss, net of tax
                      (241,954 )                    
     
Prior service cost, net of tax
                      (7,033 )                    
                                           
                              (248,987 )                     (248,987 )
 
Dividends paid
                            (63,456 )           (63,456 )
 
Stock options exercised
    20       15,600                               15,620  
 
Share-based compensation
          21,877                               21,877  
 
Income tax benefits from stock options exercised
          33,173                               33,173  
 
Employee stock purchases
    2       4,516                               4,518  
 
Employee stock grants
    6       (6 )                              
 
Advance stripping adjustment (net of $95,189 tax benefit)
                            (150,333 )           (150,333 )
 
Shares repurchased
                                  (99,774 )     (99,774 )
                                           
December 31, 2006
  $ 2,666     $ 1,572,614     $     $ (249,058 )   $ 1,115,994     $ (103,690 )   $ 2,338,526  
                                           
See accompanying notes to consolidated financial statements

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Table of Contents

PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Summary of Significant Accounting Policies
Basis of Presentation
      The consolidated financial statements include the accounts of Peabody Energy Corporation (“the Company”) and its affiliates. All intercompany transactions, profits and balances have been eliminated in consolidation.
Description of Business
      The Company is engaged in the mining of steam coal for sale primarily to electric utilities and metallurgical coal for sale to industrial customers. The Company’s mining operations are located in the United States and Australia, and include an equity interest in mining operations in Venezuela. In addition to the Company’s mining operations, the Company markets, brokers and trades coal. The Company’s other energy related commercial activities include the development of mine-mouth coal-fueled generating plants, the management of its vast coal reserve and real estate holdings, coalbed methane production and Btu conversion technologies. The Company’s Btu conversion projects are designed to expand the uses of coal through various technologies such as coal-to-liquids and coal gasification.
New Accounting Pronouncements
      In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standard (“SFAS”) No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (“SFAS No. 158”). For fiscal years ending after December 15, 2006, SFAS No. 158 requires recognition of the funded status of pension and other postretirement benefit plans (an asset for overfunded status or a liability for underfunded status) in a company’s balance sheet. In addition, the standard requires recognition of actuarial gains and losses, prior service cost, and any remaining transition amounts from the initial application of SFAS No. 87, “Employers’ Accounting for Pensions” (“SFAS No. 87”) and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” (“SFAS No. 106”) when determining a plan’s funded status, with a corresponding charge to accumulated other comprehensive income (loss).
      The Company adopted SFAS No. 158 on December 31, 2006, and as a result, recorded a noncurrent liability of $376.1 million, which reflected the net underfunded status of the pension, retiree healthcare and workers’ compensation plans. The funded status of each plan was measured as the difference between the fair value of the assets and the projected benefit obligation (the “funded status”). SFAS No. 158 did not impact net income. The impact to the balance sheet was as follows (see Notes 14, 15, and 16 for additional details):
                         
    Before Application       After Application
    of SFAS No. 158   Adjustments   of SFAS No. 158
             
    (Dollars in thousands)
Workers’ compensation obligations
  $ 237,965     $ (4,558 )   $ 233,407  
Accrued postretirement benefit costs
    973,164       395,522       1,368,686  
Other noncurrent liabilities (includes long-term pension and UMWA Combined Fund liabilities)
    375,485       (14,855 )     360,630  
Deferred income taxes (long-term liability)
    344,712       (149,499 )     195,213  
Total liabilities
    6,915,583       226,610       7,142,193  
Accumulated other comprehensive loss
    (22,448 )     (226,610 )     (249,058 )
Total stockholders’ equity
    2,565,136       (226,610 )     2,338,526  

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Table of Contents

PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      In June 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109” (“FIN No. 48”). This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN No. 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. This interpretation is effective for fiscal years beginning after December 15, 2006 (January 1, 2007 for the Company). Any adjustments required upon the adoption of this interpretation must be recorded directly to retained earnings in the year of adoption and reported as a change in accounting principle. The Company expects the adoption of FIN No. 48 will not have a material impact on its results of operations or financial position.
      In March 2005, the Emerging Issues Task Force (“EITF”) issued EITF Issue No. 04-6, “Accounting for Stripping Costs in the Mining Industry” (“EITF Issue No. 04-6”). EITF Issue No. 04-6 and its interpretations require stripping costs incurred during a period to be attributed only to the inventory costs of the coal that is extracted during that same period. The Company adopted EITF Issue No. 04-6 on January 1, 2006 and utilized the cumulative effect adjustment approach whereby the cumulative effect adjustment reduced retained earnings by $150.3 million, net of tax. This non-cash item is excluded from the consolidated statements of cash flows. Advance stripping costs are primarily expensed as incurred.
      In December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment” (“SFAS No. 123(R)”), which is a revision of SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123”). SFAS No. 123(R) supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB Opinion No. 25”) and amends FASB Statement No. 95, “Statement of Cash Flows.” Generally, the approach in SFAS No. 123(R) is similar to the approach described in SFAS No. 123. However, SFAS No. 123(R) requires all share-based payments to employees, including employee stock options, to be recognized in the income statement based on their fair values at the grant date.
      The Company adopted SFAS No. 123(R) on January 1, 2006 and used the modified prospective method, in which compensation cost is recognized beginning with the effective date (a) based on the requirements of SFAS No. 123(R) for all share-based payments granted or modified after the effective date and (b) based on the requirements of SFAS No. 123 for all awards granted to employees prior to the effective date of SFAS No. 123(R) that remain unvested on the effective date. Prior to January 1, 2006, the Company had elected to apply APB Opinion No. 25 and related interpretations in accounting for its stock option plans, as permitted under SFAS No. 123 and SFAS No. 148 “Accounting for Stock-Based Compensation-Transition and Disclosure.” Beginning in 2006, SFAS No. 123(R) also requires that excess income tax benefits from stock options exercised be recorded as financing cash inflow on the statements of cash flows. The excess income tax benefit from stock option exercises during 2005 and 2004 is included in operating cash flows, netted in deferred tax activity.
Sales
      The Company’s revenue from coal sales is realized and earned when risk of loss passes to the customer. Coal sales are made to the Company’s customers under the terms of coal supply agreements, most of which are long-term (greater than one year). Under the typical terms of these coal supply agreements, title and risk of loss transfer to the customer at the mine or port, where coal is loaded to the rail, barge, ocean-going vessel, truck or other transportation source(s) that serves each of the Company’s mines. The Company incurs certain “add-on” taxes and fees on coal sales. Coal sales are reported including taxes and fees charged by various federal and state governmental bodies.

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PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Other Revenues
      Other revenues include royalties related to coal lease agreements, sales agency commissions, farm income, coalbed methane revenues, property and facility rentals, generation development activities, net revenues from coal trading activities accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”), as amended, and contract termination or restructuring payments. Royalty income generally results from the lease or sublease of mineral rights to third parties, with payments based upon a percentage of the selling price or an amount per ton of coal produced. Certain agreements require minimum annual lease payments regardless of the extent to which minerals are produced from the leasehold. The terms of these agreements generally range from specified periods of five to 15 years, or can be for an unspecified period until all reserves are depleted.
Discontinued Operations
      The Company classifies items within discontinued operations in the consolidated statements of operations when the operations and cash flows of a particular component (defined as operations and cash flows that can be clearly distinguished, operationally and for financial reporting purposes, from the rest of the entity) of the Company have been (or will be) eliminated from the ongoing operations of the Company as a result of a disposal transaction, and the Company will no longer have any significant continuing involvement in the operations of that component. Discontinued operations for the year ended December 31, 2004, reflected a $2.8 million loss, net of taxes, related to the Company’s former Citizens Power subsidiary.
Cash and Cash Equivalents
      Cash and cash equivalents are stated at cost, which approximates fair value. Cash equivalents consist of highly liquid investments with original maturities of three months or less.
Inventories
      Materials and supplies and coal inventory are valued at the lower of average cost or market. Raw coal represents coal stockpiles that may be sold in current condition or may be further processed prior to shipment to a customer. Coal inventory costs include labor, supplies, equipment, operating overhead and other related costs. Prior to the adoption of EITF Issue No. 04-6, advance stripping consisted of the costs to remove overburden above an unmined coal seam as part of the surface mining process. As a result of the adoption of EITF Issue No. 04-6 on January 1, 2006, advance stripping costs are expensed as incurred except to the extent such costs are included as a component of inventory costs.
Assets and Liabilities from Coal Trading Activities
      The Company’s coal trading activities are evaluated under SFAS No. 133, as amended. Trading contracts that meet the SFAS No. 133 definition of a derivative are accounted for at fair value, while contracts that do not qualify as derivatives are accounted for under the accrual method. All trading contracts are recorded subject to the requirements of EITF Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (“EITF Issue No. 02-3”).
      The Company’s trading contracts are reflected at fair value and are included in “Assets and liabilities from coal trading activities” in the consolidated balance sheets as of December 31, 2006 and 2005. Under EITF Issue No. 02-3, all mark-to-market gains and losses on energy trading contracts (including derivatives and hedged contracts) are presented on a net basis in the statement of operations, even if

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Table of Contents

PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
settled physically. The Company’s consolidated statements of operations reflect revenues related to all mark-to-market trading contracts on a net basis in “Other revenues.”
Property, Plant, Equipment and Mine Development
      Property, plant, equipment and mine development are recorded at cost. Interest costs applicable to major asset additions are capitalized during the construction period, including $3.0 million, $0.1 million and $0.2 million for the years ended December 31, 2006, 2005 and 2004, respectively.
      Expenditures which extend the useful lives of existing plant and equipment assets are capitalized. Maintenance and repairs are charged to operating costs as incurred, Costs incurred to develop coal mines or to expand the capacity of operating mines are capitalized. Costs incurred to maintain current production capacity at a mine and exploration expenditures are charged to operating costs as incurred, including costs related to drilling and study costs incurred to convert or upgrade mineral resources to reserves. Costs to acquire computer hardware and the development and/or purchase of software for internal use are capitalized and depreciated over the estimated useful lives.
      Coal reserves are recorded at cost, or at fair value in the case of acquired businesses. As of December 31, 2006 and 2005, the net book value of coal reserves totaled $5.2 billion and $3.7 billion, respectively. These amounts included $2.1 billion and $1.8 billion at December 31, 2006 and 2005, respectively, attributable to properties where the Company was not currently engaged in mining operations or leasing to third parties and, therefore, the coal reserves were not currently being depleted. Included in the book value of coal reserves are mineral rights for leased coal interests including advance royalties and the net book value of these mineral rights was $3.5 billion and $2.1 billion at December 31, 2006 and 2005, respectively. The remaining net book value of our coal reserves of $1.7 billion and $1.6 billion, at December 31, 2006 and 2005, respectively, relates to coal reserves held by fee ownership.
      Depletion of coal reserves and amortization of advance royalties is computed using the units-of-production method utilizing only proven and probable reserves (as adjusted for recoverability factors) in the depletion base. Mine development costs are principally amortized over the estimated lives of the mines using the straight-line method.
      Depreciation of plant and equipment (excluding life of mine assets) is computed using the straight-line method over the estimated useful lives as follows:
         
    Years
     
Building and improvements
    10 to 30  
Machinery and equipment
    3 to 30  
Leasehold improvements
    Life of Lease  
      In addition, certain plant and equipment assets associated with mining are depreciated using the straight-line method over the estimated life of the mine, which varies from one to 33 years.
Goodwill and Intangible Assets
      Assets and liabilities acquired in business combinations are accounted for using the purchase method and recorded at their respective fair values. Substantially all goodwill is assigned to the reporting unit that acquires a business. A reporting unit is an operating segment as defined in SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information,” or a business one level below an operating segment if discrete financial information is prepared and regularly reviewed by the segment manager. The Company conducts a formal impairment test of goodwill on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. Under the impairment test, if a reporting unit’s carrying amount exceeds its estimated fair value, a goodwill impairment is recognized to the extent that the reporting unit’s carrying amount of goodwill exceeds the implied fair value of the goodwill.

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Table of Contents

PEABODY ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
      All of the Company’s intangibles (other than goodwill) are subject to amortization. Intangibles consist of contractual obligations and are amortized based on tons sold. These intangibles are also subject to evaluation for potential impairment if an event occurs or circumstances change that indicate the carrying amount may not be recoverable.
Investments in Joint Ventures
      The Company accounts for its investments in less than majority owned corporate joint ventures under either the equity or cost method. The Company applies the equity method to investments in joint ventures when it has the ability to exercise significant influence over the operating and financial policies of the joint venture. Investments accounted for under the equity method are initially recorded at cost, and any difference between the cost of the Company’s investment and the underlying equity in the net assets of the joint venture at the investment date is amortized over the lives of the related assets that gave rise to the difference. The Company’s pro rata share of earnings from joint ventures and basis difference amortization is reported in the consolidated statements of operations in “Income from equity affiliates.” The book value of the Company’s equity method investments as of December 31, 2006 and 2005 was $65.5 million and $97.2 million, respectively, and is reported in “Investments and other assets” in the consolidated balance sheets. Included in the Company’s equity method investments was its 25.5% interest in Carbones del Guasare, which owns and operates the Paso Diablo Mine in Venezuela. The Company’s investment