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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
Form 10-K
 
     
þ
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the Fiscal Year Ended December 31, 2009
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
(State or other jurisdiction of incorporation or organization)
  13-4004153
(I.R.S. Employer Identification No.)
701 Market Street, St. Louis, Missouri
(Address of principal executive offices)
  63101
(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   New York Stock Exchange
Preferred Share Purchase Rights   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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes þ     No o
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) 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, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
Large accelerated filer þ Accelerated filer o Non-accelerated filer o Smaller reporting company o
(Do not check if a smaller reporting company)
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 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, 2009: Common Stock, par value $0.01 per share, $8.1 billion.
 
Number of shares outstanding of each of the Registrant’s classes of Common Stock, as of February 12, 2010: Common Stock, par value $0.01 per share, 268,757,971 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 2010 Annual Meeting of Stockholders (the Company’s 2010 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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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” in Management’s Discussion and Analysis of Financial Condition and Results of Operations. We use words such as “anticipate,” “believe,” “expect,” “may,” “project,” “should,” “estimate,” or “plan” or other similar words to identify forward-looking statements.
 
Without limiting the foregoing, all statements relating to our future operating results, anticipated capital expenditures, future cash flows and borrowings, and sources of funding are forward-looking statements and speak only as of the date of this report. 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:
 
  •  demand for coal in United States (U.S.), China and other international power generation and steel production markets;
 
  •  price volatility and demand, particularly in higher-margin products and in our trading and brokerage businesses;
 
  •  reductions and/or deferrals of purchases by major customers and ability to renew sales contracts;
 
  •  credit and performance risks associated with customers, suppliers, trading, banks and other financial counterparties;
 
  •  geologic, equipment, permitting and operational risks related to mining;
 
  •  transportation availability, performance and costs;
 
  •  availability, timing of delivery and costs of key supplies, capital equipment or commodities such as diesel fuel, steel, explosives and tires;
 
  •  impact of weather on demand, production and transportation;
 
  •  successful implementation of business strategies, including our Btu Conversion and generation development initiatives;
 
  •  negotiation of labor contracts, employee relations and workforce availability;
 
  •  changes in postretirement benefit and pension obligations and funding requirements;
 
  •  replacement and development of coal reserves;
 
  •  access to capital and credit markets and availability and costs of credit, margin capacity, surety bonds, letters of credit, and insurance;
 
  •  effects of changes in interest rates and currency exchange rates (primarily the Australian dollar);
 
  •  effects of acquisitions or divestitures;
 
  •  economic strength and political stability of countries in which we have operations or serve customers;
 
  •  legislation, regulations and court decisions or other government actions, including new environmental requirements, changes in federal or state income tax regulations or other regulatory taxes;


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  •  litigation, including claims not yet asserted;
 
  •  terrorist attacks or threats;
 
  •  impacts of pandemic illnesses; and
 
  •  other factors, including those discussed in Legal Proceedings, set forth in Item 3 of this report 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 Securities and Exchange Commission (SEC) filings. These forward-looking statements speak only as of the date on which such statements were made, and we undertake no obligation to update these statements except as required by federal securities laws.


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TABLE OF CONTENTS
 
                 
        Page
 
PART I.
  Item 1.     Business     2  
  Item 1A.     Risk Factors     17  
  Item 1B.     Unresolved Staff Comments     27  
  Item 2.     Properties     27  
  Item 3.     Legal Proceedings     32  
  Item 4.     Submission of Matters to a Vote of Security Holders     32  
        Executive Officers of the Company     32  
 
PART II.
  Item 5.     Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities     34  
  Item 6.     Selected Financial Data     35  
  Item 7.     Management’s Discussion and Analysis of Financial Condition and Results of Operations     37  
  Item 7A.     Quantitative and Qualitative Disclosures About Market Risk     55  
  Item 8.     Financial Statements and Supplementary Data     58  
  Item 9.     Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     58  
  Item 9A.     Controls and Procedures     58  
  Item 9B.     Other Information     61  
 
PART III.
  Item 10.     Directors, Executive Officers and Corporate Governance     61  
  Item 11.     Executive Compensation     61  
  Item 12.     Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     61  
  Item 13.     Certain Relationships and Related Transactions, and Director Independence     61  
  Item 14.     Principal Accounting Fees and Services     62  
 
PART IV.
  Item 15.     Exhibits, Financial Statement Schedules     62  
 EX-10.45
 EX-10.46
 EX-10.47
 EX-10.48
 EX-10.49
 EX-10.51
 EX-10.53
 EX-21
 EX-23
 EX-31.1
 EX-31.2
 EX-32.1
 EX-32.2
 EX-101 INSTANCE DOCUMENT
 EX-101 SCHEMA DOCUMENT
 EX-101 CALCULATION LINKBASE DOCUMENT
 EX-101 LABELS LINKBASE DOCUMENT
 EX-101 PRESENTATION LINKBASE DOCUMENT
 EX-101 DEFINITION LINKBASE DOCUMENT


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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. Unless otherwise noted herein, disclosures in this Annual Report on Form 10-K relate only to our continuing operations.
 
PART I
 
Item 1.   Business.
 
History and Development of Business
 
Peabody Energy Corporation is the world’s largest private-sector coal company. We were incorporated in Delaware in 2001 and our history in the coal mining business dates back to 1883. We own majority interests in 28 coal mining operations located in the U.S. and Australia. In addition to our mining operations, we market, broker and trade coal through our Trading and Brokerage segment. In response to growing international markets, we have expanded our international trading group in the last few years, most recently with the addition of a trading office in Singapore and a business development office in Indonesia.
 
In the U.S., we have transformed in recent years from a high-sulfur, high-cost coal company to a predominately low-sulfur, low-cost coal producer, marketer/trader of coal and manager of vast natural resources through organic growth, divestitures and strategic operational restructuring. Internationally, we expanded our presence through the acquisition of Excel Coal Limited (Excel) in Australia. We have four core strategies to achieve growth:
 
  1)  Executing the basics of best-in-class safety, operations and marketing;
 
  2)  Capitalizing on organic growth opportunities;
 
  3)  Expanding in high-growth global markets; and
 
  4)  Participating in new generation and Btu Conversion technologies designed to expand the uses of coal through coal-to-liquids and coal gasification technologies, and the advancement of clean coal technologies, including carbon capture and storage.
 
In 2007, we spun off portions of our formerly Eastern U.S. Mining segment through a dividend of all outstanding shares of Patriot Coal Corporation (Patriot), which is now an independent public company traded on the New York Stock Exchange (symbol PCX). The spin-off included eight company-operated mines, two joint venture mines, and numerous contractor operated mines serviced by eight coal preparation facilities along with 1.2 billion tons of proven and probable coal reserves. Our results for all periods presented reflect Patriot as a discontinued operation.
 
Segments
 
Our operations consist of four principal segments: our three mining segments and our Trading and Brokerage segment. Our three mining segments are Western U.S. Mining, Midwestern U.S. Mining and Australian Mining. Our fifth segment, Corporate and Other, includes mining and export/transportation joint ventures, energy-related commercial activities as well as the management of our vast coal reserve and real estate holdings through initiatives such as 1) participation in developing mine-mouth coal-fueled generating plants; 2) developing Btu Conversion technologies, which are designed to convert coal to natural gas and transportation fuels; and 3) advancing carbon capture and storage initiatives. Our operating segments are discussed in more detail below with financial information contained in Note 22 to our consolidated financial statements.
 
U.S. and Australian Mining Operations
 
Mining Segments.  Our Western U.S. Mining operations consist of our Powder River Basin, Southwest and Colorado operations, and our Midwestern U.S. Mining operations consist of our Illinois and Indiana operations. The principal business of our U.S. Mining segments is the mining, preparation and sale of thermal (steam) coal, sold primarily to electric utilities. Our Australian Mining operations consist of metallurgical and thermal coal mines in Queensland and New South Wales, Australia.


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The maps below display our mine locations as of December 31, 2009. Also noted are the primary ports utilized in the U.S. and in Australia for our coal exports and our corporate headquarters. The U.S. map does not include our Bear Run Mine in western Indiana, which is expected to begin operations in mid-2010.
 
(MAP)
 
(MAP)


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The table below presents information regarding each of our 28 mines, including mine location, type of mine, mining method, coal type, transportation method and tons sold in 2009. The mines are sorted by tons sold within each mining segment.
 
                             
                        2009
 
        Mine
  Mining
  Coal
  Transport
  Tons Sold
 
Mine
 
Location
  Type   Method   Type   Method   (In millions)  
 
Western U.S. Mining
                           
North Antelope Rochelle
  Wright, WY   S   DL, T/S   Thermal   R     98.3  
Caballo
  Gillette, WY   S   D, T/S   Thermal   R     23.3  
Rawhide
  Gillette, WY   S   D, T/S   Thermal   R     15.8  
Twentymile
  Oak Creek, CO   U   LW   Thermal   R, T     7.7  
Kayenta
  Kayenta, AZ   S   DL, T/S   Thermal   R     7.5  
El Segundo
  Grants, NM   S   T/S   Thermal   R     5.4  
Lee Ranch
  Grants, NM   S   DL, T/S   Thermal   R     2.1  
Midwestern U.S. Mining
                           
Farmersburg
  Pimento, IN   S   DL, D, T/S   Thermal   T, R     3.6  
Willow Lake
  Equality, IL   U   CM   Thermal   T/B     3.5  
Gateway
  Coulterville, IL   U   CM   Thermal   T, R, R/B     3.4  
Somerville Central
  Oakland City, IN   S   DL, D, T/S   Thermal   R, T/R, T/B     3.4  
Cottage Grove
  Equality, IL   S   D, T/S   Thermal   T/B     2.1  
Francisco Underground
  Francisco, IN   U   CM   Thermal   R     2.0  
Somerville North
  Oakland City, IN   S   D, T/S   Thermal   R, T/R, T/B     2.0  
Miller Creek
  Bicknell, IN   S   D, T/S   Thermal   T, T/R     2.0  
Somerville South
  Oakland City, IN   S   D, T/S   Thermal   R, T/R, T/B     1.7  
Air Quality
  Vincennes, IN   U   CM   Thermal   T, T/R, T/B     1.6  
Viking
  Cannelburg, IN   S   D, T/S   Thermal   T, T/R     1.6  
Wildcat Hills Underground
  Eldorado, IL   U   CM   Thermal   T/B     0.7  
Other(1)
              4.2  
Australian Mining
                           
Wilpinjong*
  Wilpinjong, New South Wales   S   T/S   Thermal   R, EV     8.3  
Burton*(2)
  Glenden, Queensland   S   T/S   Thermal/Met   R, EV     2.5  
Wilkie Creek
  Macalister, Queensland   S   T/S   Thermal   R, EV     2.3  
North Wambo Underground
  Warkworth, New South Wales   U   LW   Thermal/Met**   R, EV     2.3  
Wambo Open-Cut*
  Warkworth, New South Wales   S   T/S   Thermal   R, EV     1.9  
North Goonyella
  Glenden, Queensland   U   LW   Met   R, EV     1.8  
Metropolitan
  Helensburgh, New South Wales   U   LW   Met   R, EV     1.5  
Eaglefield*
  Glenden, Queensland   S   T/S   Met   R, EV     0.9  
Millennium
  Moranbah, Queensland   S   T/S   Met   R, EV     0.8  
 
             
Legend:
       
S
  Surface Mine   R   Rail
U
  Underground Mine   T   Truck
DL
  Dragline   R/B   Rail and Barge
D
  Dozer/Casting   T/B   Truck and Barge
T/S
  Truck and Shovel   T/R   Truck and Rail
LW
  Longwall   EV   Export Vessel
CM
  Continuous Miner   Thermal   Thermal/Steam
        Met   Metallurgical
 
 
* Mine is operated by a contract miner
 
** Metallurgical coal is pulverized coal injection, or PCI
 
(1) “Other” in Midwestern U.S. Mining primarily consists of purchased coal used to satisfy certain coal supply agreements and shipments made from operations closed during 2009.
 
(2) The Burton Mine is a 95% proportionally owned and consolidated mine.


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See Item 2. Properties. for additional information regarding coal reserves, coal characteristics and tons produced for each mine.
 
Trading and Brokerage Segment
 
Through our Trading and Brokerage segment, we broker coal sales of other coal producers both as principal and agent, and trade coal, freight and freight-related contracts. We also provide transportation-related services in support of our coal trading strategy, as well as hedging activities in support of our mining operations.
 
In response to growing international markets, we expanded our international trading group in 2006 and added trading operations offices in London, England in 2007 and in Singapore in 2009. Our trading and brokerage entities broker and trade coal in the Australia and Pacific Rim markets. We also have sales, marketing and business development offices in Beijing, China and Jakarta, Indonesia (opened in 2009) to pursue potential long-term growth opportunities in the Asian market.
 
Corporate and Other Segment
 
Resource Management.  We hold approximately 9.0 billion tons of proven and probable coal reserves and more than 500,000 acres of surface property. Our resource development group regularly reviews these reserves for opportunities to generate earnings and cash flow through the sale of non-strategic coal reserves and surface land. In addition, we generate revenue through royalties from coal reserves and oil and gas rights leased to third parties, and farm income from surface land under third-party contracts.
 
Export Facilities.  We own a 37.5% interest in Dominion Terminal Associates, a partnership that operates a coal export terminal in Newport News, Virginia. The facility has a rated throughput capacity of approximately 20 million tons of coal per year and had 11.0 million tons of throughput in 2009. The facility also has ground storage capacity of approximately 1.7 million tons. The facility exports both metallurgical and thermal coal primarily to European and Brazilian markets.
 
We control a 17.7% interest in the Newcastle Coal Infrastructure Group, which is currently constructing a coal transloading facility in Newcastle, Australia. The facility, which is expected to be completed in 2010, is backed by take or pay agreements and will have an initial capacity of 33 million tons per year of which our share is 5.8 million tons, with expansion capacity of up to 66 million tons per year.
 
Generation Development, Btu Conversion and Clean Coal Technology.  To maximize our coal assets and land holdings for long-term growth, we are contributing to the development of coal-fueled generation, pursuing Btu Conversion projects that would convert coal to natural gas or transportation fuels and advancing clean coal technologies.
 
Generation development projects involve using our surface lands and coal reserves as the basis for mine-mouth plants. Our ultimate role in these projects could take numerous forms, including, but not limited to, equity partner, contract miner or coal lessor. We are currently a 5.06% owner in the Prairie State Energy Campus (Prairie State), a 1,600 megawatt coal-fueled electricity generation project under construction in Washington County, Illinois. Prairie State will be fueled by over six million tons of coal each year produced from its adjacent underground mining operations. We sold 94.94% of the land and coal reserves to our partners in Prairie State and we are responsible for our 5.06% share of costs to construct the facility. The plant is scheduled to begin generating electricity in 2011.
 
We are exploring Btu Conversion projects designed to expand the uses of coal through coal-to-liquids (CTL) and coal gasification technologies. Currently, we are pursuing development of a coal-to-gas (CTG) facility known as Kentucky NewGas, a planned “mine-mouth” gasification project using ConocoPhillips proprietary E-Gastm technology to produce clean synthesis gas with carbon storage potential. We also own an equity interest in GreatPoint Energy, Inc., which is commercializing its coal-to-pipeline quality natural gas technology. We are also pursuing a project with the government of Inner Mongolia and other Chinese partners to explore development opportunities for a large surface mine and downstream coal gasification facility that would produce methanol, chemicals or fuel products.


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We are participating in the advancement of clean coal technologies, including carbon capture and storage, in the U.S., China and Australia. We are a founding member of the FutureGen Alliance, a non-profit company working in partnership with the U.S. Department of Energy (DOE), which under its new configuration, would develop multiple carbon capture and storage sites. We are the only non-Chinese equity partner in GreenGen, a near-zero emissions coal-fueled power plant with carbon capture and storage. In Australia, we made a 10-year commitment to fund the Australian COAL21 Fund designed to support clean coal technology demonstration projects and research in Australia. We are also a founding member or member of a number of related partnerships including the Global Carbon Capture and Storage Institute (Australia), the U.S.-China Energy Cooperation Program, the Asia-Pacific Partnership for Clean Development and Climate, the Consoritium for Clean Coal Utilization, the National Carbon Capture Center, and the Western Kentucky Carbon Storage Foundation.
 
Mongolia Joint Venture.  In 2009, we acquired a 50% interest in a joint venture holding with Polo Resources Limited (AIM: PRL), which holds coal and mineral interests in Mongolia. In connection with this acquisition, we obtained warrants to enable us to acquire an approximate 15% equity interest in Polo Resources Limited. The joint venture is in the development stage and plans to ship metallurgical and thermal coal to Asian markets once developed.
 
Paso Diablo Mine.  We own a 25.5% equity interest in Carbones del Guasare, S.A., a joint venture that includes Anglo American plc and a Venezuelan governmental partner. Carbones del Guasare operates the Paso Diablo Mine, which is a surface operation in northwestern Venezuela that produces thermal coal for export primarily to the U.S. and Europe. We are responsible for marketing our pro-rata share of sales from Paso Diablo; the joint venture is responsible for production, processing and transportation of coal to ocean-going vessels for delivery to customers. In December 2009, we entered into an arrangement to assume Anglo American’s interest, which is conditional on the approval of various parties (including the Venezuelan governmental partner) and regulatory approvals.
 
Coal Supply Agreements
 
As of January 31, 2010 we had a sales backlog of over one billion tons of coal, including backlog subject to price reopener and/or extension provisions, representing nearly five years of current production. Agreements in backlog have remaining terms ranging from one to 17 years. For 2009, approximately 93% of our worldwide sales (by volume) were under long-term coal supply agreements. In 2009, we sold coal to 345 electricity generating and industrial plants in 23 countries. For the year ended December 31, 2009, we derived 28% of our total coal sales revenues from our five largest customers (excluding trading transactions). At December 31, 2009, we had 79 coal supply agreements with these customers expiring at various times from 2010 to 2016.
 
U.S.  We expect to continue selling a significant portion of our coal under long-term supply agreements. Customers continue to pursue long-term sales agreements as the importance of reliability, service and predictable prices are recognized. The terms of coal supply agreements result from competitive bidding and extensive negotiations with customers. Consequently, the terms of these agreements vary significantly in many respects, including price adjustment features, price reopener terms, coal quality requirements, quantity parameters, permitted sources of supply, treatment of environmental constraints, extension options, force majeure, and termination and assignment provisions. Our strategy is to selectively renew, or enter into new, long-term supply agreements when we can do so at prices we believe are favorable.
 
Australia.  Our international coal mining activities accounted for 10% of our mining operations sales volume in 2009. Our production is sold primarily into the export metallurgical and thermal markets. Price reopener provisions are present in the majority of our multi-year international coal agreements. Historically, these provisions allow either party to commence a renegotiation of the agreement price annually. A majority of the reopener provisions relate to metallurgical coal repriced annually in the second quarter of each year. We also have a long-term coal supply agreement with a customer in Australia, which runs through 2025 and is expected to supply approximately 130 million tons from our Wilpinjong Mine.


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Transportation
 
Coal consumed in the U.S. is usually sold at the mine with transportation costs borne by the purchaser. Australian and U.S. export coal is usually sold at the loading port, with purchasers paying ocean freight. Producers usually pay shipping costs from the mine to the port, including any demurrage costs (fees paid to third-party shipping companies for loading time that exceeded the stipulated time). We believe we have good relationships with rail carriers and barge companies due, in part, to our modern coal-loading facilities and the experience of our transportation coordinators. See the table on page 4 for transportation methods by mine.
 
Suppliers
 
The main types of goods we purchase are mining equipment and replacement parts, ammonium-nitrate and emulsion based explosives, diesel fuel, off-the-road (OTR) tires, steel-related (including roof control materials) products and lubricants. We also purchase services at our mine sites that include maintenance services for mining equipment, temporary labor and other various contracted services, including contract miners. Although we have many well-established, strategic relationships with our key suppliers, we do not believe that we are dependent on any of our individual suppliers, except as noted below. The supplier base providing mining materials to the coal industry has been relatively consistent in recent years, although there continues to be some consolidation. Supplier consolidation in explosives and underground equipment has limited the number of sources for these materials, resulting in our purchases of these items being concentrated with one principal supplier; however, some supplier competition continues to be present. In recent years, demand and lead times for certain surface and underground mining equipment and OTR tires has increased. However, we do not expect lead times to have a near-term material impact on our financial condition, results of operations or cash flows.
 
Technical Innovation
 
We continue to place great emphasis on the application of technical innovation to improve new and existing equipment performance. This research and development effort is typically undertaken and funded by equipment manufacturers using our input and expertise. Our engineering, maintenance and purchasing personnel work together with manufacturers to design and produce equipment that we believe will add value to the business. In 2009, we began a program to upgrade the mining equipment at our North Antelope Rochelle Mine, both to increase overburden removal capacity and improve mining cost with larger more efficient trucks and shovels. Our engineers have also been working with several major equipment vendors to develop conceptual designs of in-pit crushing and conveying systems in place of trucks in an effort to move large quantities of overburden resulting in cost savings and a more environmentally friendly operation. We are currently working with a vendor to implement the “Landmark” longwall shearer navigation system at our North Wambo Underground Mine. This system includes hardware and software that monitors and controls the pitch, roll and depth of cut of the shearer to maintain the face alignment, allowing the shearer to mine more efficiently. We have also begun pilot testing of a paste slurry pumping system that, if successful, will allow coal refuse from the Metropolitan Mine to be disposed of in abandoned areas of the underground workings rather than transported to the surface.
 
Our enterprise resource planning system provides detailed equipment and mining performance data for all our U.S. operations. Proprietary software for hand-held Personal Digital Assistant devices was developed in-house, and has been deployed at all U.S. underground mines to record safety observations, safety audits, underground front-line supervisor reports and delay information. Wireless data acquisition systems are installed at our two largest mines, North Antelope Rochelle and Caballo, to dispatch mobile equipment more efficiently and monitor performance and condition of all major mining equipment on a real-time basis.
 
We use maintenance standards based on reliability-centered maintenance practices at all operations to increase equipment utilization and reduce maintenance and capital spending by extending the equipment life, while minimizing the risk of premature failures. Specialized maintenance reliability software is used at many operations to better support improved equipment strategies, predict equipment condition and aid analysis necessary for better decision-making for such issues as component replacement timing.


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We also use in-house developed software to schedule and monitor trains, mine and pit blending, quality and customer shipments to enhance our reliability and product consistency.
 
Competition
 
The markets in which we sell our coal are highly competitive. According to the National Mining Association’s “2008 Coal Producer Survey,” the top 10 coal companies in the U.S. produced approximately 70% of total U.S. coal in 2008. Our principal U.S. competitors (listed alphabetically) are other large coal producers, including Alpha Natural Resources, Inc., Arch Coal, Inc., Cloud Peak Energy Inc., CONSOL Energy Inc. and Massey Energy Company, which collectively accounted for approximately 41% of total U.S. coal production in 2008 (most recent publicly available data). Major international competitors (listed alphabetically) include Anglo-American PLC, BHP Billiton, China Coal, Rio Tinto, Shenhua Group, and Xstrata PLC. In Australia, the top 10 coal companies produced approximately 84% of the country’s coal in 2009. We compete on the basis of coal quality, delivered price, customer service and support and reliability.
 
Employees
 
As of December 31, 2009, we had approximately 7,300 employees, which included approximately 5,400 hourly employees. As of such date, approximately 29% of our hourly employees were represented by organized labor unions and generated 10% of 2009 coal production. Relations with our employees and, where applicable, organized labor are important to our success.
 
U.S. Labor Relations.  Hourly workers at our Kayenta Mine in Arizona are represented by the United Mine Workers of America, under the Western Surface Agreement, which is effective through September 2, 2013. This agreement covers approximately 7% of our U.S. subsidiaries’ hourly employees, who generated approximately 4% of our U.S. production during the year ended December 31, 2009. Hourly workers at our Willow Lake Mine in Illinois are represented by the International Brotherhood of Boilermakers, under a labor agreement that expires April 15, 2011. This agreement covers approximately 9% of our U.S. subsidiaries’ hourly employees, who generated approximately 2% of our U.S. production during the year ended December 31, 2009.
 
Australian 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 Australian subsidiary’s hourly production and engineering employees, including those employed through contract mining relationships. All the Australian subsidiary’s mine sites have enterprise bargaining agreements. The current labor agreement at our Metropolitan Mine expires in June 2010; renegotiations for a new agreement will commence in the first quarter of 2010. The labor agreement for the Wambo Mine coal handling plant was renewed in 2008 and expires in 2011. The labor agreement for the Wambo Underground Mine was renewed in early 2009 and will expire in 2012. For the Wilkie Creek Mine (expired October 2009) and the North Goonyella Mine (expired May 2009), we have reached agreements in principle, with the vote of the unions and employees expected to take place in late February 2010.
 
Regulatory Matters — U.S.
 
Federal, state and local authorities regulate the U.S. 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, the reclamation and restoration of mining properties after mining has been completed, the discharge of materials into the environment, surface subsidence from underground mining and the effects of mining on groundwater quality and availability. In addition, the industry is affected by significant legislation mandating certain benefits for current and retired coal miners. Numerous federal, state and local governmental permits and approvals are required for mining operations. We believe that we have obtained all permits currently required to conduct our present mining operations.


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We endeavor to conduct our mining operations in compliance with all applicable federal, state and local laws and regulations. However, because of extensive and comprehensive regulatory requirements, violations during mining operations occur from time to time in the industry. None of our violations to date or the monetary penalties assessed has been material.
 
Mine Safety and Health.  Our goal is to provide a workplace that is incident free. We believe that it is our responsibility to our employees to provide a superior safety and health environment. We seek to implement this goal by: training employees in safe work practices; openly communicating with employees; establishing, following and improving safety standards; involving employees in safety processes; and recording, reporting and investigating all accidents, incidents and losses to avoid reoccurrence. A portion of the annual performance incentives for our operating units is tied to their safety performance.
 
During 2009, our worldwide safety performance set a new standard in our 126-year history. The U.S. injury incidence rate of 2.06 (computed per 200,000 worker hours) was slightly higher compared to last year’s record performance, but the Australian operations improved by nearly 40% versus the previous year. This drove the worldwide Peabody incidence rate to a new low of 2.82 for 2009, which was 21% better than the previous record year and approximately 31% better than the U.S. average for our industry. We received multiple state and federal safety awards during the year. Our training centers educate our employees in safety best practices and reinforce our company-wide belief that productivity and profitability follow when safety is the cornerstone at all of our operations.
 
Following passage of The Mine Improvement and New Emergency Response Act of 2006 (The Miner Act), the U.S. Mine Safety and Health Administration (MSHA), significantly increased the enforcement of safety and health standards and imposed safety and health standards on all aspects of mining operations. There has also been a dramatic increase in the dollar penalties assessed for citations issued over the past two years.
 
The Miner Act requires the installation of wireless, two-way communication systems for miners, and mine operators must have the ability to track the location of each miner at work in an underground mine. Since these developing technologies are nearly ready for MSHA approval, we anticipate expenditures in 2010 to fully equip all of our underground mines with this improved capability.
 
Most of the states in which we operate have inspection programs for mine safety and health. Collectively, federal and state safety and health regulations in the coal mining industry are perhaps the most comprehensive and pervasive systems for protection of employee health and safety affecting any segment of U.S. industry.
 
Black Lung.  Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each U.S. coal mine operator must pay federal black lung benefits and medical expenses to claimants who are current and former employees and last worked for the operator after July 1, 1973. Coal mine operators must also make payments to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1, 1973. Historically, less than 7% of the miners currently seeking federal black lung benefits are awarded these benefits. The trust fund is funded by an excise tax on U.S. production of up to $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price.
 
Environmental Laws.  We are subject to various federal and state environmental laws. Some of these laws, discussed below, place many requirements on our coal mining operations. Federal and state regulations require regular monitoring of our mines and other facilities to ensure compliance.
 
Surface Mining Control and Reclamation Act.  In the U.S., the Surface Mining Control and Reclamation Act of 1977 (SMCRA), which is administered by the Office of Surface Mining Reclamation and Enforcement (OSM), established mining, environmental protection and reclamation standards for all aspects of U.S. surface mining as well as many aspects of deep mining. Mine operators must obtain SMCRA permits and permit renewals for mining operations from the OSM. Where state regulatory agencies have adopted federal mining programs under SMCRA, the state becomes the regulatory authority. Except for Arizona, states in which we have active mining operations have achieved primary control of enforcement through federal authorization. In Arizona, we mine on tribal lands and are regulated by OSM because the tribes do not have SMCRA authorization.


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SMCRA permit provisions include requirements for coal prospecting; mine plan development; topsoil removal, storage and replacement; selective handling of overburden materials; mine pit backfilling and grading; protection of the hydrologic balance; subsidence control for underground mines; surface drainage control; mine drainage and mine discharge control and treatment; and re-vegetation.
 
The U.S. mining permit application process is initiated by collecting baseline data to adequately characterize the pre-mine environmental condition of the permit area. This work includes surveys of cultural resources, soils, vegetation, wildlife, assessment of surface and ground water hydrology, climatology and wetlands. In conducting this work, we collect geologic data to define and model the soil and rock structures and coal that we will mine. We develop mine and reclamation plans by utilizing this geologic data and incorporating elements of the environmental data. The mine and reclamation plan incorporates the provisions of SMCRA, the state programs and the complementary environmental programs that impact coal mining. Also included in the permit application are documents defining ownership and agreements pertaining to coal, minerals, oil and gas, water rights, rights of way and surface land and documents required of the OSM’s Applicant Violator System.
 
Once a permit application is prepared and submitted to the regulatory agency, it goes through a completeness and technical review. Public notice of the proposed permit is given for a comment period before a permit can be issued. Some SMCRA mine permits take over a year to prepare, depending on the size and complexity of the mine and often take six months to two years to be issued. Regulatory authorities have considerable discretion in the timing of the permit issuance and the public has the right to comment on and otherwise engage in the permitting process, including public hearings and through intervention in the courts.
 
Before a SMCRA permit is issued, a mine operator must submit a bond or other form of financial security to guarantee the performance of reclamation obligations. The Abandoned Mine Land Fund, which is part of SMCRA, requires a fee on all coal produced in the U.S. The proceeds are used to rehabilitate lands mined and left unreclaimed prior to August 3, 1977 and to pay health care benefit costs of orphan beneficiaries of the Combined Fund. The fee was $0.35 per ton of surface-mined coal and $0.15 per ton of deep-mined coal, effective through September 30, 2007. Pursuant to the Tax Relief and Health Care Act of 2006, from October 1, 2007 through September 30, 2012, the fee is $0.315 per ton of surface-mined coal and $0.135 per ton of underground mined coal. From October 1, 2012 through September 30, 2021, the fee will be reduced to $0.28 per ton of surface-mined coal and $0.12 per ton of underground mined coal.
 
SMCRA stipulates compliance with many other major environmental programs. These programs include the Clean Air Act; Clean Water Act; Resource Conservation and Recovery Act (RCRA); and Comprehensive Environmental Response, Compensation, and Liability Acts (CERCLA, commonly known as Superfund). Besides OSM, other federal regulatory agencies are involved in monitoring or permitting specific aspects of mining operations. The U.S. Environmental Protection Agency (EPA) is the lead agency for states or tribes with no authorized programs under the Clean Water Act, RCRA and CERCLA. The U.S. Army Corps of Engineers regulates activities affecting navigable waters and the U.S. Bureau of Alcohol, Tobacco and Firearms regulates the use of explosive blasting.
 
We do not believe there are any matters that pose a material risk to maintaining our existing mining permits or materially hinder our ability to acquire future mining permits. It is our policy to comply in all material respects with the requirements of the SMCRA and the state and tribal laws and regulations governing mine reclamation.
 
Clean Air Act.  The Clean Air Act and the comparable state laws that regulate the emissions of materials into the air affect U.S. coal mining operations both directly and indirectly. Direct impacts on coal mining and processing operations may occur through the Clean Air Act permitting requirements and/or emission control requirements relating to particulate matter. It is possible that the more stringent ambient air quality standards (NAAQS) will directly impact our mining operations by, for example, requiring additional controls of emissions from our mining equipment and vehicles. Moreover, if the areas in which our mines and coal preparation plants are located suffer from extreme weather events such as droughts, or are designated as non-attainment areas, we could be required to incur significant costs to install additional emissions control equipment, or otherwise change our operations and future development. In addition, in September 2009 the


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EPA adopted new rules tightening and adding additional particulate matter emissions limits for coal preparation and processing plants constructed, reconstructed or modified after April 28, 2008.
 
The Clean Air Act indirectly, but more significantly, affects the coal industry by extensively regulating the air emissions of sulfur dioxide, nitrogen oxides, mercury and other substances emitted by coal-based electricity generating plants. In addition to the issues discussed under “Global Climate Change” on page 14, the air emissions programs that may affect our operations, directly or indirectly, include, but are not limited to, the Acid Rain Program, NOx SIP Call, the Clean Air Interstate Rule (CAIR), Maximum Achievable Control Technology (MACT) emissions limits for Hazardous Air Pollutants, the Regional Haze program and New Source Review. In addition, the EPA has adopted NAAQS for particulate matter, nitrogen oxide and sulfur dioxide. The EPA has proposed more stringent NAAQS for sulfur dioxide and ozone. Almost all of these programs and regulations have resulted in litigation which has not been completely resolved.
 
Programs such as the Acid Rain Program and CAIR use a cap and trade system. Affected power plants have sought to reduce sulfur dioxide emissions by switching to lower sulfur fuels, installing pollution control devices, reducing electricity generating levels or purchasing or trading sulfur dioxide emissions allowances. As a result of the CAIR program, the MACT requirements and more stringent nitrogen oxides, particulate and ozone NAAQS, many power plants have been or will be required to install additional emission control measures, such as scrubbers and selective catalytic reduction devices.
 
Our customers are among the electricity generators subject to New Source Review enforcement actions and if found not to be in compliance, our customers could be required to install additional control equipment at the affected plants or they could decide to close some or all of those plants. The Regional Haze program may also require retrofitting of existing facilities with additional control equipment.
 
In recent years Congress has considered legislation that would require reductions in emissions of sulfur dioxide, nitrogen oxide and mercury, greater and sooner than those required by existing law. No such legislation has passed either house of Congress. If enacted into law, such legislation could impact the amount of coal supplied to electricity generating customers if they decide to switch to other sources of fuel whose use would result in lower emissions of sulfur dioxide, nitrogen oxide and mercury.
 
Clean Water Act.  The Clean Water Act of 1972 affects U.S. coal mining operations by requiring effluent limitations and treatment standards for waste water discharge through the National Pollutant Discharge Elimination System (NPDES). Regular monitoring, reporting requirements and performance standards are requirements of NPDES permits that govern the discharge of pollutants into water. Section 404 under the Clean Water Act requires mining companies to obtain U.S. Army Corps of Engineers permits to place material in streams for the purpose of creating slurry ponds, water impoundments, refuse areas, valley fills or other mining activities.
 
States are empowered to develop and enforce “in stream” water quality standards. These standards are subject to change and must be approved by the EPA. Discharges must either meet state water quality standards or be authorized through available regulatory processes such as alternate standards or variances. “In stream” standards vary from state to state. Additionally, through the Clean Water Act section 401 certification program, states have approval authority over federal permits or licenses that might result in a discharge to their waters. States consider whether the activity will comply with its water quality standards and other applicable requirements in deciding whether or not to certify the activity.
 
Total Maximum Daily Load (TMDL) regulations established a process by which states designate stream segments as impaired (not meeting present water quality standards). Industrial dischargers, including coal mines, may be required to meet new TMDL effluent standards for these stream segments. States are also adopting anti-degradation regulations in which a state designates certain water bodies or streams as “high quality/exceptional use.” These regulations would restrict the diminution of water quality in these streams. Waters discharged from coal mines to high quality/exceptional use streams may be required to meet additional conditions or provide additional demonstrations and/or justification. In general, these Clean Water Act requirements could result in higher water treatment and permitting costs or permit delays, which could adversely affect our coal production costs or efforts.


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Resource Conservation and Recovery Act.  RCRA, which was enacted in 1976, affects U.S. coal mining operations by establishing “cradle to grave” requirements for the treatment, storage and disposal of hazardous wastes. Typically, the only hazardous wastes generated at a mine site are those from products used in vehicles and for machinery maintenance. Coal mine wastes, such as overburden and coal cleaning wastes, are not considered hazardous wastes under RCRA.
 
Subtitle C of RCRA exempted fossil fuel combustion wastes from hazardous waste regulation until the EPA completed a report to Congress and made a determination on whether the wastes should be regulated as hazardous. In a 1993 regulatory determination, the EPA addressed some high volume-low toxicity coal combustion materials generated at electric utility and independent power producing facilities. In May 2000, the EPA concluded that coal combustion materials do not warrant regulation as hazardous wastes under RCRA. The EPA has retained the hazardous waste exemption for these materials. The EPA is evaluating national non-hazardous waste guidelines for coal combustion materials placed at a mine. National guidelines for mine-fills may affect the cost of ash placement at mines. The EPA has announced that it is developing a proposal for requirements for coal combustion residue management.
 
CERCLA (Superfund).  CERCLA affects U.S. coal mining and hard rock operations by creating liability for investigation and remediation in response to releases of hazardous substances into the environment and for damages to natural resources. Under CERCLA, joint and several liabilities may be imposed on waste generators, site owners or operators and others regardless of fault. Under the EPA’s Toxic Release Inventory process, companies are required annually to report the use, manufacture or processing of listed toxic materials that exceed defined thresholds, including chemicals used in equipment maintenance, reclamation, water treatment and ash received for mine placement from power generation customers.
 
The Energy Policy Act of 2005.  The Domenici-Barton Energy Policy Act of 2005 (EPACT) was signed by President Bush in August 2005. EPACT contains tax incentives and directed spending totaling an estimated $14.1 billion intended to stimulate supply-side energy growth and increased efficiency. In addition to rules affecting the leasing process of federal coal properties, EPACT programs and incentives include funding to demonstrate advanced coal technologies, including coal gasification; grants and a loan guarantee program to encourage deployment of advanced clean coal-based power generation technologies, including integrated gasification combined cycle (IGCC); a federal loan guarantee program for the cost of advanced fossil energy projects, including coal gasification; funding for energy research, development, demonstration and commercial application programs relating to coal and power systems; and tax incentives for IGCC, industrial gasification and other advanced coal-based generation projects, as well as for coal sold from Indian lands. Finally, certain sections of EPACT are potentially applicable to the area of Btu Conversion, such as the fossil energy project loan guarantee program as well as a provision allowing taxpayers to capitalize 50% of the cost of refinery investments which increase the total throughput of qualified fuels — including synthetic fuels produced from coal — by at least 25%. In addition, EPACT requires the Secretary of Defense to develop a strategy to use fuel produced from coal, oil shale and tar sands (covered fuel) to assist in meeting the fuel requirements of the U.S. Department of Defense (DOD). The law authorizes the DOD to enter into multi-year contracts to procure a covered fuel to meet one or more of its fuel requirements and to carry out an assessment of potential locations for covered fuel sources.
 
Endangered Species Act.  The U.S. Endangered Species Act and counterpart state legislation is intended to protect species whose populations allow for categorization as either endangered or threatened. With respect to obtaining mining permits, protection of endangered or threatened species may have the effect of prohibiting, limiting the extent or causing delays that may include permit conditions on the timing of, soil removal, timber harvesting, road building and other mining or agricultural activities in areas containing the associated species. Based on the species that have been identified on our properties and the current application of these laws and regulations, we do not believe that they will have a material adverse effect on our ability to mine the planned volumes of coal from our properties in accordance with current mining plans. However, there are ongoing lawsuits and petitions under these laws and regulations that, if successful, could have a material adverse effect on our ability to mine some of our properties in accordance with our current mining plans.


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Use of Explosives.  Our surface mining operations are subject to numerous regulations relating to blasting activities. Pursuant to these regulations, we incur costs to design and implement blast schedules and to conduct pre-blast surveys and blast monitoring. In addition, the storage of explosives is subject to strict regulatory requirements established by four different federal regulatory agencies. For example, pursuant to a rule issued by the U.S. Department of Homeland Security in 2007, facilities in possession of chemicals of interest, including ammonium nitrate at certain threshold levels, must complete a screening review in order to help determine whether there is a high level of security risk such that a security vulnerability assessment and site security plan will be required.
 
Regulatory Matters — Australia
 
The Australian mining industry is regulated by Australian federal, state and local governments with respect to environmental issues such as land reclamation, water quality, air quality, dust control, noise, planning issues (such as approvals to expand existing mines or to develop new mines), and health and safety issues. The Australian federal government retains control over the level of foreign investment and export approvals. Industrial relations are regulated under both federal and state laws. Australian state governments also require coal companies to post deposits or give other security against land which is being used for mining, with those deposits being returned or security released after satisfactory reclamation is completed.
 
Native Title and Cultural Heritage.  Since 1992, the Australian courts have recognized that native title to lands, as recognized under the laws and customs of the Aboriginal inhabitants of Australia, may have survived the process of European settlement. These developments are supported by the Federal Native Title Act (NTA) which recognizes and protects native title, and under which a national register of native title claims has been established.
 
Native title rights do not extend to minerals; however, native title rights can be affected by the mining process unless those rights have previously been extinguished. Native title rights can be extinguished either by a valid act of government (as set out in the NTA) or by the loss of connection between the land and the group of Aboriginal peoples concerned.
 
The NTA provides that where native title rights still exist and the mining project will affect those native title rights, it is necessary to consult with the relevant Aboriginal group and to come to an agreement on issues such as the preservation of sacred or important sites, the employment of members of the group by the mine operator, and the payment of compensation for the effect on native title of the mining project. In the absence of agreement with the relevant Aboriginal group, the NTA provides for arbitration.
 
There is also federal and state legislation to prevent damage to Aboriginal cultural heritage and archeological sites.
 
Mining Tenements and Environmental.  In Queensland and New South Wales the development of a mine requires both the grant of a right to and also an approval which authorizes the environmental impacts of the mine. These approvals are obtained under separate legislation from separate government authorities. However, the application processes run concurrently and are also concurrent with any native title or cultural heritage process that is required.
 
The environmental impacts of mining projects are regulated by local, state and federal governments. Federal regulation will only apply if the particular project will significantly impact a matter of national environmental significance (e.g., endangered species or particular protected places). If so, it will also be regulated by the federal government.
 
Generally, the process involves an assessment of the environmental impacts of the project and how these can be managed which is submitted to the state government for consideration (also to the federal government if federal approval is required). Based on the environmental assessment, conditions will be imposed on the environmental approval (if granted). The conditions commonly relate to limits on emissions to the atmosphere, emissions in water, noise impacts, dust impacts, the generation, handling, storage and transportation of waste and requirements for the rehabilitation and restoration of land. Environmental assessments and applications for approval are generally publicly notified and third parties may lodge submissions.


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Queensland and New South Wales each have their own mining tenement legislation which regulates the process for applying for and renewing mining tenements. Before obtaining a mining lease which allows production, it is necessary to hold an exploration license. This exploration license allows exploratory drilling to take place but does not permit production.
 
Occupational Health and Safety.  The combined effect of various state and federal statutes requires an employer to ensure that persons employed in a mine are safe from injury by providing a safe working environment and systems of work; safety machinery; equipment, plant and substances; and appropriate information, instruction, training and supervision.
 
Currently all states and territories are responsible for making and enforcing their own laws. Although these draw on a similar approach for regulating workplaces, there are some differences in the application and detail of the laws. However, in December 2009, the Workplace Relations Ministers’ Council endorsed a model Work Health and Safety Act. Each of the states and territories has agreed to implement their own legislation adopting the model legislation by December 2011 to achieve consistent requirements across the country.
 
In recognition of the specialized nature of mining and mining activities, specific occupational health and safety obligations have been mandated under state legislation that deals specifically with the coal mining industry. Mining employers, owners, directors and managers, persons in control of work places, mine managers, supervisors and employees are all subject to these duties.
 
It is mandatory for an employer to have insurance coverage with respect to the compensation of injured workers; similar coverage is in effect throughout Australia which is of a no fault nature and which provides for benefits up to a prescribed level. The specific benefits vary by jurisdiction, but generally include the payment of weekly compensation to an incapacitated employee, together with payment of medical, hospital and related expenses. The injured employee has a right to sue his or her employer for further damages if a case of negligence can be established.
 
Industrial Relations.  A national industrial relations system administered by the federal government applies to all private sector employers and employees. The system largely became operational in July 2009 and fully operational in January 2010. The matters regulated under the national system regulates include:
 
  •  employment conditions;
 
  •  unfair dismissal;
 
  •  enterprise bargaining;
 
  •  industrial action; and
 
  •  resolution of workplace disputes.
 
National Greenhouse and Energy Reporting Act 2007 (NGER Act).  The NGER Act introduces a single national reporting system relating to greenhouse gas emissions and energy production and consumption, which will underpin a future emissions trading scheme.
 
The NGER Act imposes requirements for certain corporations to report greenhouse gas emissions and abatement actions, as well as energy production and consumption. Both foreign and local corporations that meet the prescribed CO2 and energy production of consumption limits in Australia (controlling corporations) must comply with the NGER Act.
 
Peabody Energy Australia Pty Ltd, one of our subsidiaries, is now registered as a controlling corporation and must report each financial year about the greenhouse gas emissions and energy production and consumption of our Australian entities.
 
Regulatory Matters — Mongolia
 
The Mongolian mining industry is regulated by Mongolian federal, provincial and local governments with respect to exploration, development, production, occupational health, mine safety, water use, environmental protection and remediation, foreign investment and other related matters. The Mineral Resources Authority of


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Mongolia is the government agency with the authority to issue, extend and revoke mineral licenses, which generally give the license holder the right to engage in the mining of minerals within the license area for 30 years (with the right to extend for two additional periods of 20 years). Mongolian law provides for state participation in the exploitation of any mineral deposit of “strategic importance,” as determined by the Mongolian Parliament.
 
Global Climate Change
 
Global climate change continues to attract public and scientific attention. Numerous reports, such as the Fourth Assessment Report of the Intergovernmental Panel on Climate Change (IPCC), have also engendered concern about the impacts of human activity, especially fossil fuel combustion, on global climate change. In turn, increasing government attention is being paid to global climate change and to emissions of what are commonly referred to as greenhouse gases, including emissions of carbon dioxide from coal combustion by power plants.
 
Presently there are no U.S. federal mandatory greenhouse gas reduction requirements. In June 2009, the U.S. House of Representatives passed legislation which calls for a cap-and-trade system and other measures. Under a cap-and-trade program, or emissions trading scheme, allowances would be granted or auctioned, with the quantity based on the acceptable limits of aggregate emissions. Over time, those allowable emissions would likely be decreased. The price would depend on a number of factors including the market for such allowances and the cost of emissions control technologies or alternatives. The U.S. Senate has not acted on legislation in this area. While it is possible that the U.S. will adopt legislation in the future, the timing and specific requirements of any such legislation are highly uncertain.
 
Even in the absence of new U.S. federal legislation, greenhouse gas emissions may be regulated in the future by the U.S. EPA pursuant to the Clean Air Act. In response to the 2007 U.S. Supreme Court ruling Massachusetts v. EPA that the EPA has authority to regulate carbon dioxide emissions under the Clean Air Act, the EPA has taken several actions towards emissions regulation.
 
In December 2009, the EPA published its finding that atmospheric concentrations of greenhouse gases endanger public health and welfare within the meaning of the Clean Air Act, and that emissions of greenhouse gases from new motor vehicles and new motor vehicle engines are contributing to air pollution that are endangering public health and welfare within the meaning of the Clean Air Act. The finding does not by itself impose any regulatory requirements and does not contain any specific targets for reducing greenhouse gases. While the EPA’s finding is technically limited to greenhouse gas emissions from new motor vehicles and new motor vehicle engines, the finding may lead to endangerment findings under other Clean Air Act programs, including those that relate directly to emissions from stationary sources. In February 2010, we filed a petition with the EPA requesting reconsideration of the finding as well as a petition to review the finding with the U.S. Court of Appeals for the District of Columbia Circuit. Our petitions are based primarily on the release of email and other information from the University of East Anglia Climatic Research Unit (CRU) in November 2009. We believe that the CRU information undermines a number of the central pillars on which the finding rests, particularly the work of the IPCC.
 
In October 2009, the EPA published a proposed rule to regulate the emission of greenhouse gases from certain stationary sources with an initial focus on facilities that release more than 25,000 tons of greenhouse gases a year, and that would require best available control technology for such emissions whenever such facilities are built or significantly modified (the so-called “tailoring rule”). It is unclear as to whether the EPA has the statutory authority under the Clean Air Act to adopt the tailoring rule. In addition, in September 2009 the EPA adopted a rule requiring certain emitters of greenhouse gases, including coal-fired power plants, to monitor and report their emissions to the EPA.
 
A number of states in the U.S. have taken steps to regulate greenhouse gas emissions. For example, 10 northeastern states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island and Vermont) have formed the Regional Greenhouse Gas Initiative (RGGI), which is a mandatory cap-and-trade program to reduce carbon dioxide emissions from power plants. Six midwestern states (Illinois, Iowa, Kansas, Michigan, Minnesota and Wisconsin) and one Canadian province have entered


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into the Midwestern Regional Greenhouse Gas Reduction Accord to establish regional greenhouse gas reduction targets and develop a multi-sector cap-and-trade system to help meet the targets. Seven western states (Arizona, California, Montana, New Mexico, Oregon, Utah and Washington) and two Canadian provinces have entered into the Western Climate Initiative (WCI) to establish a regional greenhouse gas reduction goal and develop market-based strategies to achieve emissions reductions. However, the Governor of Arizona announced in February 2010 that Arizona will not implement the greenhouse gas cap-and-trade proposal advanced by the WCI, which begins on January 1, 2012. In 2006, the California legislature approved legislation allowing the imposition of statewide caps on, and cuts in, carbon dioxide emissions. Similar legislation was adopted in 2007 in Hawaii, Minnesota and New Jersey.
 
In December 1997, in Kyoto, Japan, the signatories to the 1992 Framework Convention on Climate Change, which addresses emissions of greenhouse gases, established a binding set of emission targets for developed nations. The U.S. has signed the Kyoto Protocol, but it has not been ratified by the U.S. Senate. As noted previously, Australia ratified the Kyoto Protocol in December 2007 and became a full member in March 2008. International discussions are underway to develop a treaty to replace the Kyoto Protocol after its expiration in 2012, including the Copenhagen meetings in late 2009.
 
In May 2009, legislation was introduced in Australia’s Parliament to establish a national emissions trading market, called the Carbon Pollution Reduction Scheme (CPRS). If enacted, the CPRS would set a cap on greenhouse gas emissions in Australia and issue permit allowances up to the cap limit. The CPRS was passed by Australia’s House of Representatives in June 2009, but was voted down by the Australian Senate in August 2009. The Australian government reintroduced the CPRS for consideration by Parliament in October 2009, but it was voted down by the Australian Senate in December 2009.
 
We continue to support clean coal technology development and other initiatives addressing global climate change through our participation as a founding member of the FutureGen Alliance in the U.S. and the COAL21 Fund in Australia and through our participation in the Power Systems Development Facility, the PowerTree Carbon Company LLC, the Midwest Geopolitical Sequestration Consortium, the Asia-Pacific Partnership for Clean Development and Climate, the U.S.-China Energy Cooperation Program, the Consortium for Clean Coal Utilization, the National Carbon Capture Center and the Western Kentucky Carbon Storage Foundation. In addition, we are the only non-Chinese equity partner in GreenGen, the first near-zero emissions coal-fueled power plant with carbon capture and storage which is under development in China. We are also a founding member of the Global Carbon Capture and Storage Institute, an international initiative to accelerate commercialization of carbon capture and storage (CCS) technologies through development of 20 integrated, industrial-scale demonstration projects.
 
In the U.S., clean coal technology development is being accelerated by the American Recovery and Reinvestment Act of 2009 (the ARRA), which was signed into law by President Obama in February 2009. The ARRA targets $3.4 billion for U.S. Department of Energy (DOE) fossil fuel programs, including $1 billion for CCS research; $800 million for the Clean Coal Power Initiative, a 10-year program supporting commercial CCS; and $50 million for geology research.
 
In addition, in February 2010, President Obama announced the formation of an Interagency Task Force on Carbon Capture and Storage (the Task Force) to develop a comprehensive and coordinated federal strategy to speed the commercial development and deployment of clean coal technologies. The Task Force has been asked to develop a proposed plan to overcome the barriers to the widespread, cost-effective deployment of CCS within 10 years, with a goal of bringing five to 10 commercial demonstration projects online by 2016.
 
We participate in the DOE’s Voluntary Reporting of Greenhouse Gases Program, and regularly disclose the quantity of emissions per ton of coal produced by us in the U.S. The vast majority of our emissions are generated by the operation of heavy machinery to extract and transport coal at our mines. We continue to evaluate and implement improvements in technology and infrastructure — such as the overland conveyor and near pit truck dump and crusher facility at our North Antelope Rochelle Mine in Wyoming — that are expected to reduce the level of emissions from our operations.


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Enactment of laws or passage of regulations regarding emissions from the mining of coal by the U.S. or some of its states or by other countries, or other actions to limit such emissions, are not expected to have a material adverse effect on our results of operations, financial condition or cash flows.
 
Enactment of laws or passage of regulations regarding emissions from the combustion of coal by the U.S. or some of its states or by other countries, or other actions to limit such emissions, could result in electricity generators switching from coal to other fuel sources. The potential financial impact on us of future laws or regulations will depend upon the degree to which any such laws or regulations forces electricity generators to diminish their reliance on coal as a fuel source. That, in turn, will depend on a number of factors, including the specific requirements imposed by any such laws or regulations, the time periods over which those laws or regulations would be phased in and the state of commercial development and deployment of CCS technologies. In view of the significant uncertainty surrounding each of these factors, it is not possible for us to reasonably predict the impact that any such laws or regulations may have on our results of operations, financial condition or cash flows.
 
Additional Information
 
We file annual, quarterly and current reports, and our amendments to those reports, proxy statements and other information with the SEC. You may access and read our SEC filings free of charge through our website, at www.peabodyenergy.com, or the SEC’s website, at www.sec.gov. Information on such websites does not constitute part of this document. You may also read and copy any document we file at the SEC’s public reference room located at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room.
 
You may also request copies of our filings, free of charge, by telephone at (314) 342-3400 or by mail at: Peabody Energy Corporation, 701 Market Street, Suite 900, St. Louis, Missouri 63101, attention: Investor Relations.
 
Item 1A.   Risk Factors.
 
The following risk factors relate specifically to the risks associated with our continuing operations.
 
Risks Associated with Our Operations
 
The global economic recession and disruptions in the financial markets, and their impact on us, are uncertain.
 
The magnitude and pace of recovery from the global economic recession and the worldwide financial and credit market disruptions is uncertain. We are focused on strong cost control and productivity improvements, increased contributions from our high-margin operations, and exercising tight capital discipline. However, there can be no assurance that these actions, or any others that we may take in response to further deterioration in economic and financial conditions, will be sufficient. A return to the global recession or further disruptions in the financial markets could have an adverse effect on our business, financial condition or results of operations.
 
A decline in coal prices could negatively affect our profitability.
 
Our profitability depends upon the prices we receive for our coal. Coal prices are dependent upon factors beyond our control, including:
 
  •  the demand for electricity and the strength of the global economy;
 
  •  the demand for steel, which may lead to price fluctuations in the annual repricing of our metallurgical coal contracts;
 
  •  the supply of U.S. domestic and international thermal and metallurgical coal;
 
  •  competition within our industry and the availability and price of alternative fuels and energy sources;
 
  •  the proximity, capacity and cost of transportation;


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  •  coal industry capacity;
 
  •  domestic and foreign governmental regulations and taxes, including those establishing air emission standards for coal-fueled power plants;
 
  •  regulatory, administrative and judicial decisions, including those affecting future mining permits; and
 
  •  technological developments, including those intended to convert coal to liquids or gas and those aimed at capturing and storing carbon dioxide.
 
As of January 26, 2010, we are fully contracted for 2010 at planned production levels in the U.S. and have 4.5 to 5.5 million tons of Australian metallurgical coal and 6.5 to 7.0 million tons of Australian thermal coal available to price. If we experience a weak coal pricing environment resulting in a deterioration of coal prices, we could experience an adverse effect on our revenues and profitability.
 
If a substantial number of our long-term coal supply agreements terminate, our revenues and operating profits could suffer if we are 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, particularly in the U.S. In 2009, 93% of our worldwide sales volume was sold under long-term coal supply agreements. At January 31, 2010, our sales backlog, including backlog subject to price reopener and/or extension provisions, was over one billion tons, representing nearly five years of current production in backlog. Contracts in backlog have remaining terms ranging from one to 17 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 restricts the use or type of coal permissible at the customer’s plant or 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.


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The loss of, or significant reduction in, purchases by our largest customers could adversely affect our revenues.
 
In 2009, we derived 28% of our total coal sales revenues from our five largest customers (excluding trading transactions). At December 31, 2009, we had 79 coal supply agreements with these customers expiring at various times from 2010 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. In addition, our revenue could be adversely affected by a decline in customer purchases due to lack of demand, cost of competing fuels and environmental regulations.
 
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 or for financially settled contracts depends on the continued creditworthiness of our customers and counterparties. 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 $275.0 million accounts receivable securitization program and our business could be adversely affected.
 
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 on our results of operations, financial condition or cash flows.
 
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, 2009, certain coal supply agreements 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.
 
We 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, underperformance of the port and rail infrastructure, congestion and balancing systems which are imposed to manage vessel queuing and demurrage, 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.


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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 mining equipment, replacement parts, explosives, fuel, tires, steel-related products (including roof control) and lubricants. 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. 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.
 
An inability of trading, brokerage, mining or freight 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 and transportation, including contract miners and brokerage sources, to fulfill deliveries under our coal supply agreements. In Australia, the majority of our volume comes from mines that utilize contract miners. Employee relations at mines that use contract miners is the responsibility of the contractor.
 
Our profitability or exposure to loss on transactions or relationships is dependent upon the reliability (including financial viability) and price of the third-party suppliers, 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 the ability of our freight sources to fulfill their delivery obligations. Market volatility and price increases for coal or freight on the international and domestic markets could result in non-performance by third-party suppliers under existing contracts with us, in order to take advantage of the higher prices in the current market. Such non-performance could have an adverse impact on our ability to fulfill deliveries under our coal supply agreements.
 
Our hedging activities may expose us to earnings volatility and other risks.
 
We enter into hedging arrangements designed primarily to manage our exposure to explosives, diesel fuel, foreign currency and interest rate fluctuations. Generally, we attempt to designate hedging arrangements as cash flow hedges with gains or losses recorded as a separate component of stockholders’ equity until the hedged transaction occurs (or until hedge ineffectiveness is determined). While we utilize a variety of risk monitoring and mitigation strategies, those strategies require judgment and they cannot anticipate every potential outcome or the timing of such outcomes. As such, there is potential for these hedges to no longer qualify for hedge accounting. If that were to happen, we will be required to recognize the mark to market movements through current year earnings, possibly resulting in increased volatility in our income in future periods.
 
Additionally, some of our hedging arrangements require us to post margin based on the value of those hedging arrangements and other credit factors. If our credit is downgraded, the fair value of our hedge positions move significantly, or laws or regulations are passed requiring all hedge arrangements to be exchange-traded or exchange-cleared, we could be required to post additional margin, which could impact our liquidity.
 
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 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


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qualified personnel in the future. Failure to retain or attract key personnel could have a material adverse effect on us.
 
We could be negatively affected if we fail to maintain satisfactory labor relations.
 
As of December 31, 2009, we had approximately 7,300 employees. Approximately 29% of our hourly employees were represented by unions and they generated approximately 10% of our 2009 coal production. Additionally, those employed through contract mining relationships in Australia are also members of unions. Relations with our employees and, where applicable, organized labor are important to our success. 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.
 
Our mining 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 methods for us to meet those obligations are 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, 2009, we had $821.9 million of self bonding in place for our reclamation obligations. As of December 31, 2009, we also had outstanding surety bonds with third parties and letters of credit of $1,270.3 million, of which $807.2 million was for post-mining reclamation, $51.7 million related to workers’ compensation obligations, $116.3 million was for coal lease obligations and $295.1 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 Senior Unsecured Credit Facility, which expires in 2011. Our failure to maintain, or inability to acquire, surety bonds or letters of credit or to provide a suitable 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.
 
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. Numerous governmental permits and approvals are required for mining operations. We are required to prepare and present to federal, state and local authorities data pertaining to the effect that any proposed exploration for or production of coal may have upon the environment. The public, including non-governmental organizations, opposition groups and individuals, have statutory rights to comment upon and submit objections to requested permits and approvals. 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.


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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 or the reduction of greenhouse gas emissions that would further regulate and tax the coal industry, may also require us or our customers to change operations significantly or incur increased costs. Some 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.
 
A number of laws, including in the U.S. the CERCLA, 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. Hanson PLC, which is a predecessor owner of ours, 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. See Note 20 to our consolidated financial statements for a description of pending legal proceedings involving Gold Fields.
 
If the assumptions underlying our asset retirement obligations for reclamation and mine closures are materially inaccurate, our costs could be significantly greater than anticipated.
 
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 in the U.S. and Australia as defined by each mining permit. These 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 and the timing of these cash flows, discounted using a credit-adjusted, risk-free rate. Our management and engineers periodically review these estimates. 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. The resulting estimated asset retirement obligation could change significantly if actual amounts change significantly from our assumptions, which could have a material adverse effect on our results of operation, and financial condition.
 
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. Moreover, the amount of proven and probable coal reserves described in Item 2. Properties. involved the use of certain estimates and those estimates could be inaccurate. 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 U.S. federal government also leases natural gas and coalbed methane reserves


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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 U.S. federal government limits the amount of federal land that may be leased by any company to 150,000 acres nationwide. As of December 31, 2009, we leased a total of 64,260 acres from the federal government. The limit could restrict our ability to lease additional U.S. federal lands.
 
Our planned mine development projects and acquisition activities may not result in significant additional reserves, and we may not have success developing additional mines. Most of our mining operations are conducted on properties owned or leased by us. Because we do not thoroughly verify title to most of our leased properties and mineral rights until we obtain a permit to mine the property, 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 also own the rights to the related surface property and 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. In addition, from time to time our permit applications have been challenged.
 
Growth in our global operations increases our risks unique to international mining and trading operations.
 
We currently have international mining operations in Australia. We have business development, sales and marketing offices in Beijing, China and Jakarta, Indonesia and an international trading group in our Trading and Brokerage segment with offices in London, England and Singapore. We also have joint venture mining and exploration interests in Venezuela and Mongolia. In addition, we are actively pursuing long-term operating, trading and joint-venture opportunities in China, Mongolia, Mozambique, Indonesia and India. 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 U.S. or Australian operations. We are also challenged by political risks, including the potential for expropriation of assets and limits on the repatriation of earnings. Despite our efforts to mitigate these risks, our results of operation, financial position or cash flow could be adversely affected by these activities.
 
Risks Associated with Our Indebtedness
 
We could be adversely affected by the failure of financial institutions to fulfill their commitments under our Senior Unsecured Credit Facility.
 
As of December 31, 2009, we had $1.5 billion of available borrowing capacity under our Senior Unsecured Credit Facility, net of outstanding letters of credit. This committed facility, which matures on September 15, 2011, is provided by a syndicate of financial institutions, with each institution agreeing severally (and not jointly) to make revolving credit loans to us in accordance with the terms of the facility. If one or more of the financial institutions providing the Senior Unsecured Credit Facility were to default on its obligation to fund its commitment, the portion of the facility provided by such defaulting financial institution would not be available to us.
 
Our financial performance could be adversely affected by our debt.
 
As of December 31, 2009, our total indebtedness was $2.8 billion, and we had $1.5 billion of available borrowing capacity under our Senior Unsecured Credit Facility. The indentures governing our Convertible Junior Subordinated Debentures (the Debentures) and 7.375% and 7.875% Senior Notes do not limit the


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amount of indebtedness that we may issue, and the indentures governing our 6.875% and 5.875% 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, and interest on, our indebtedness, thereby reducing the availability of our cash flow to fund working capital, capital expenditures, acquisitions, Btu Conversion and clean coal technology projects or other general corporate uses;
 
  •  limiting our ability to obtain additional financing to fund future working capital, capital expenditures, acquisitions, Btu Conversion and clean coal technology projects 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.
 
In addition, our debt agreements subject 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 Debentures impose restrictions that may limit our operating and financial flexibility.
 
Our Senior Unsecured Credit Facility, the indentures governing our 6.875% and 5.875% Senior Notes and 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 our Senior Unsecured Credit Facility and our 6.875% and 5.875% Senior Notes and Debentures 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


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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.
 
The conversion of our Debentures may result in the dilution of the ownership interests of our existing stockholders.
 
If the conditions permitting the conversion of our Debentures are met and holders of the 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 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 Debentures could discourage an acquisition of us by a third-party.
 
Certain provisions of our 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 Debentures, holders of our Debentures will have the right, at their option, to convert their Debentures and thereby require us to pay the principal amount of such Debentures in cash.
 
Other Business Risks
 
Under certain circumstances, we could be responsible for certain federal and state black lung occupational disease liabilities assumed by Patriot in connection with its 2007 spin-off from us.
 
Patriot is responsible for certain federal and state black lung occupational disease liabilities, which are expected to be less than $150 million, as well as related credit capacity in support of these liabilities. Should Patriot not fund these obligations as they become due, we could be responsible for such costs when incurred.
 
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, which was a liability of $982.2 million as of December 31, 2009, $68.1 million of which was a current liability. Net pension liabilities were $215.3 million as of December 31, 2009, $1.8 million of which was a current liability.
 
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 have made 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 or changes in medical benefits provided by the government could increase our obligation to satisfy these or additional obligations.
 
The decline in the stock market and real estate values which occurred in 2008 and 2009 led to a decline in the value of our pension plan assets which required an increase in contributions in 2009 and will likely require increased contributions in future years.


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Concerns about the environmental impacts of coal combustion, including perceived impacts on global climate change, are resulting in increased regulation of coal combustion in many jurisdictions, and interest in further regulation, which could significantly affect demand for our products.
 
Global climate change continues to attract public and scientific attention. Numerous reports, such as the Fourth Assessment Report of the Intergovernmental Panel on Climate Change, have also engendered concern about the impacts of human activity, especially fossil fuel combustion, on global climate change. In turn, increasing government attention is being paid to global climate change and to emissions of what are commonly referred to as greenhouse gases, including emissions of carbon dioxide from coal combustion by power plants.
 
Enactment of laws or passage of regulations regarding emissions from the combustion of coal by the U.S. or some of its states or by other countries, or other actions to limit such emissions, could result in electricity generators switching from coal to other fuel sources. The potential financial impact on us of future laws or regulations will depend upon the degree to which any such laws or regulations forces electricity generators to diminish their reliance on coal as a fuel source. That, in turn, will depend on a number of factors, including the specific requirements imposed by any such laws or regulations, the time periods over which those laws or regulations would be phased in and the state of commercial development and deployment of carbon capture and storage technologies. In view of the significant uncertainty surrounding each of these factors, it is not possible for us to reasonably predict the impact that any such laws or regulations may have on our results of operations, financial condition or cash flows.
 
As we continue to pursue Btu Conversion and clean coal technology activities, we face challenges and risks that differ from others in the mining business.
 
We continue to pursue opportunities to participate in technologies to economically convert a portion of our coal resources to natural gas and liquids such as diesel fuel, gasoline and jet fuel (Btu Conversion). We are also promoting the development of clean coal technologies that would reduce the emissions from the use of coal, and/or capture and store the emissions from the use of coal. As we move forward with 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.
 
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 in 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.
 
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


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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.
 
Item 1B.   Unresolved Staff Comments.
 
None.
 
Item 2.   Properties.
 
Coal Reserves
 
We had an estimated 9.0 billion tons of proven and probable coal reserves as of December 31, 2009. An estimated 7.9 billion tons of our proven and probable coal reserves are in the U.S. and 1.1 billion tons are in Australia. 45% of our reserves, or 4.0 billion tons, are compliance coal and 55% are non-compliance coal (assuming application of the U.S. industry standard definition of compliance coal to all of our reserves). We own approximately 39% of these reserves and lease property containing the remaining 61%. 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.
 
Below is a table summarizing the locations and reserves of our major operating regions.
 
                             
        Proven and Probable
 
        Reserves as of
 
        December 31, 2009(1)  
        Owned
    Leased
    Total
 
Operating Regions
 
Locations
 
Tons
   
Tons
    Tons  
              (Tons in millions)        
 
Midwest
  Illinois, Indiana and Kentucky     2,627       939       3,566  
Powder River Basin
  Wyoming and Montana     67       2,948       3,015  
Southwest
  Arizona and New Mexico     811       309       1,120  
Colorado
  Colorado     44       196       240  
                             
Total United States
        3,549       4,392       7,941  
Australia
  New South Wales           451       451  
Australia
  Queensland           623       623  
                             
Total Australia
              1,074       1,074  
                             
Total Proven and Probable Coal Reserves
        3,549       5,466       9,015  
                             
 
 
(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


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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 experienced geologists. 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 quality of the coal is 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 expected 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 and consider their input regarding the procedures used by us to prepare our internal estimates of coal reserves, selected property reserve estimates and tabulation of reserve groups according to standard classifications of reliability.
 
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.
 
We have numerous U.S. 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


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and 8% for underground-mined coal. The U.S. 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, 2009, we leased 11,592 acres of federal land in Colorado, 11,256 acres in Montana and 41,412 acres in Wyoming, for a total of 64,260 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 in the U.S.
 
Private U.S. 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 U.S. leases provide for royalties to be paid to the lessor either as a fixed amount per ton or as a percentage of the sales price. Many U.S. 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 U.S. leases are normally extended by active production at or near the end of the lease term. U.S. leases containing undeveloped reserves may expire or these leases may be renewed periodically.
 
Mining and exploration in Australia is generally carried on under leases or licenses granted by state governments. Mining leases are typically for an initial term of up to 21 years (but which may be renewed) and contain conditions relating to such matters as minimum annual expenditures, restoration and rehabilitation. Royalties are paid to the state government as a percentage of sale prices. Generally landowners do not own the mineral rights or have the ability to grant rights to mine those minerals. These rights are retained by state governments. Compensation is payable to landowners for loss of access to the land, and the amount of compensation can be determined by agreement or arbitration. Surface rights are typically acquired directly from landowners and, in the absence of agreement, there is an arbitration provision in the mining law.
 
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.
 
With a portfolio of approximately 9.0 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.


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The following chart provides a summary, by mining complex, of production for the years ended December 31, 2009, 2008 and 2007, 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)
 
                                                                                                     
    Production         Sulfur Content(2)                                      
    Year
    Year
    Year
        <1.2 lbs.
    >1.2 to 2.5 lbs.
    >2.5 lbs.
    As
    As of December 31, 2009  
    Ended
    Ended
    Ended
        sulfur dioxide
    sulfur dioxide
    sulfur dioxide
    Received
    Assigned
                         
    Dec. 31,
    Dec. 31,
    Dec. 31,
    Type of
  per
    per
    per
    Btu
    Proven and
                         
Geographic Region / Mining Complex
  2009     2008     2007     Coal   Million Btu     Million Btu     Million Btu     per pound(3)     Probable Reserves     Owned     Leased     Surface     Underground  
 
Midwest:
                                                                                                   
Air Quality
    1.6       1.9       2.1     Thermal     17       1       32       11,300       50       2       48             50  
Bear Run
                    Thermal     2       30       194       11,100       226       112       114       226        
Miller Creek
    2.0       1.9       1.6     Thermal           1       21       11,100       22       21       1       14       8  
Francisco Surface (Mined out in 2009)
    1.4       1.9       2.2     Thermal                       11,100                                
Francisco Underground
    2.0       1.5       0.9     Thermal                 46       11,300       46       8       38             46  
Farmersburg
    3.5       3.4       3.5     Thermal           1       20       10,900       21       18       3       21        
Somerville Central
    3.3       3.5       3.4     Thermal                       NA                                
Somerville North
    2.0       2.2       2.5     Thermal                 2       11,200       2       2             2        
Somerville South
    1.8       2.2       2.5     Thermal                 16       11,100       16       12       4       16        
Viking
    1.6       1.6       1.7     Thermal           1       6       11,500       7             7       7        
Cottage Grove
    0.7       0.7       0.9     Thermal                 15       12,400       15       8       7       15        
Wildcat Hills Underground
    2.1       2.2       2.0     Thermal                 23       12,200       23       15       8             23  
Willow Lake
    3.4       3.6       3.6     Thermal                 25       12,100       25       18       7             25  
Gateway
    3.3       3.2       2.7     Thermal                 18       11,000       18       17       1             18  
                                                                                                     
Total
    28.7       29.8       29.6           19       34       418               471       233       238       301       170  
Powder River Basin:
                                                                                                   
North Antelope Rochelle
    98.3       97.6       91.5     Thermal     850             9       8,700       859             859       859        
Caballo
    23.3       31.2       31.2     Thermal     681       131       33       8,200       845             845       845        
Rawhide
    15.8       18.4       17.2     Thermal     290       66       24       8,300       380             380       380        
                                                                                                     
Total
    137.4       147.2       139.9           1,821       197       66               2,084             2,084       2,084        
Southwest/Colorado:
                                                                                                   
Kayenta
    7.5       8.0       8.0     Thermal     171       81       4       11,100       256             256       256        
Lee Ranch
    1.8       3.3       5.3     Thermal     19       144       21       9,400       184       144       40       184        
Twentymile
    7.8       8.0       8.3     Thermal     49                   11,200       49       8       41             49  
El Segundo
    5.1       3.3           Thermal     25       88       69       9,300       182       168       14       182        
                                                                                                     
Total
    22.2       22.6       21.6           264       313       94               671       320       351       622       49  
Australia:
                                                                                                   
North Goonyella / Eaglefield
    2.5       2.8       2.8     Met.     38                   12,900       38             38       3       35  
Metropolitan
    1.5       1.5       1.5     Met.     44                   12,600       44             44             44  
Wilkie Creek
    2.3       2.6       2.4     Thermal     370                   10,800       370             370       370        
Wambo(4)
    4.1       5.4       4.4     Thermal/Met.     201                   12,200       201             201       33       168  
Burton (95.0%)(5)
    2.0       2.6       3.1     Thermal/Met.     33                   12,700       33             33       33        
Wilpinjong
    8.4       7.5       5.1     Thermal           206             11,200       206             206       206        
Millennium
    0.9       1.2       1.3     Met.     41                   12,600       41             41       41        
                                                                                                     
Total
    21.7       23.6       20.6           727       206                     933             933       686       247  
Total Continuing Operations
    210.0       223.2       211.7           2,831       750       578               4,159       553       3,606       3,693       466  
Discontinued Operations
    0.8       2.0       19.4                                                              
                                                                                                     
Total Assigned
    210.8       225.2       231.1           2,831       750       578               4,159       553       3,606       3,693       466  
                                                                                                     

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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, 2009
 
(Tons in Millions)
 
                                                                                                             
                                      Sulfur Content(2)                                
                                      <1.2 lbs.
    >1.2 to 2.5 lbs.
    >2.5 lbs.
    As
                         
                Proven and
                    sulfur dioxide
    sulfur dioxide
    sulfur dioxide
    Received
                         
    Total Tons     Probable
                Type of
  per
    per
    per
    Btu
    Reserve Control     Mining Method  
Coal Seam Location
  Assigned     Unassigned     Reserves     Proven     Probable     Coal   Million Btu     Million Btu     Million Btu     per pound(3)     Owned     Leased     Surface     Underground  
 
Midwest:
                                                                                                           
Illinois
    81       2,193       2,274       1,161       1,113     Thermal                 2,274       10,900       1,902       372       69       2,205  
Indiana
    390       412       802       571       231     Thermal     19       39       744       11,200       451       351       415       387  
Kentucky
          490       490       230       260     Thermal           1       489       11,800       274       216       20       470  
                                                                                                             
Midwest
    471       3,095       3,566       1,962       1,604           19       40       3,507               2,627       939       504       3,062  
Powder River Basin:
                                                                                                           
Montana
          162       162       158       4     Thermal     9       121       32       8,500       67       95       162        
Wyoming
    2,084       769       2,853       2,811       42     Thermal     2,625       196       32       8,500             2,853       2,853        
                                                                                                             
Powder River Basin
    2,084       931       3,015       2,969       46           2,634       317       64               67       2,948       3,015        
Southwest/Colorado:
                                                                                                           
Arizona
    256             256       256           Thermal     173       81       2       11,100             256       256        
Colorado
    49       191       240       149       91     Thermal     193             47       10,700       44       196             240  
New Mexico
    366       498       864       777       87     Thermal     160       373       331       9,000       811       53       848       16  
                                                                                                             
Southwest
    671       689       1,360       1,182       178           526       454       380               855       505       1,104       256  
Australia:
                                                                                                           
New South Wales
    451             451       372       79     Thermal/Met.     247       204             11,800             451       249       202  
Queensland
    482       141       623       351       272     Thermal/Met.     623                   11,300             623       588       35  
                                                                                                             
Australia
    933       141       1,074       723       351           870       204                           1,074       837       237  
                                                                                                             
Total Proven and Probable
    4,159       4,856       9,015       6,836       2,179           4,049       1,015       3,951               3,549       5,466       5,460       3,555  
                                                                                                             


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(1) Assigned reserves represent recoverable coal reserves that are controlled and accessible at active operations as of December 31, 2009. Unassigned reserves represent coal at currently non-producing locations that 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 range of variability of the moisture content in coal across a given region may affect the actual shipped Btu content of current production from assigned reserves.
 
(4) The North Wambo Underground Mine produces both thermal and pulverized coal injection, or PCI metallurgical coal.
 
(5) Proven and probable coal reserves for our Burton Mine reflects our 95% proportional ownership and consolidation.
 
Item 3.   Legal Proceedings.
 
See Note 20 to our consolidated financial statements for a description of our pending legal proceedings, which is incorporated herein by reference.
 
Item 4.   Submission of Matters to a Vote of Security Holders.
 
No matters were submitted to a vote of security holders during the quarter ended December 31, 2009.
 
Executive Officers of the Company
 
Set forth below are the names, ages as of February 24, 2010 and current positions of our executive officers. Executive officers are appointed by, and hold office at the discretion of, our Board of Directors, subject to the terms of any employment agreements.
 
             
Name
 
Age
 
Position
 
Gregory H. Boyce
    55     Chairman and Chief Executive Officer, Director
Richard A. Navarre
    49     President and Chief Commercial Officer
Michael C. Crews
    43     Executive Vice President and Chief Financial Officer
Sharon D. Fiehler
    53     Executive Vice President and Chief Administrative Officer
Eric Ford
    55     Executive Vice President and Chief Operating Officer
Alexander C. Schoch
    55     Executive Vice President Law, Chief Legal Officer and Secretary
 
Gregory H. Boyce was elected Chairman of the Board on October 10, 2007 and has been a director of the Company since March 2005. He was named Chief Executive Officer Elect in March 2005, and assumed the position of Chief Executive Officer in January 2006. Mr. Boyce served as our President from October 2003 to December 2007 and as our Chief Operating Officer from October 2003 to December 2005. He previously served as Chief Executive — Energy of Rio Tinto plc (an international natural resource company) from 2000 to 2003. Other prior positions include President and Chief Executive Officer of Kennecott Energy Company from 1994 to 1999 and President of Kennecott Minerals Company from 1993 to 1994. He has extensive engineering and operating experience with Kennecott and also served as Executive Assistant to the Vice Chairman of Standard Oil of Ohio from 1983 to 1984. Mr. Boyce serves on the board of

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directors of Marathon Oil Corporation. He is Vice Chairman of the World Coal Institute and the National Mining Association. He is a member of the National Coal Council and the Coal Industry Advisory Board of the International Energy Agency. He is a Board member of the Business Roundtable, and the American Coalition for Clean Coal Electricity. He is a member of the Board of Trustees of St. Louis Children’s Hospital; the Board of Trustees of Washington University in St. Louis; the School of Engineering and Applied Science National Council at Washington University in St. Louis; and the Advisory Council of the University of Arizona’s Department of Mining and Geological Engineering.
 
Richard A. Navarre is our President and Chief Commercial Officer. He previously served as our Executive Vice President of Corporate Development and Chief Financial Officer from July 2006 to January 2008 and as Chief Financial Officer from October 1999 to June 2008. Mr. Navarre is a member of the Hall of Fame of the College of Business at Southern Illinois University Carbondale; a member of the Board of Advisors of the College of Business and Administration and the School of Accountancy of Southern Illinois University Carbondale; a member of the International Business Advisory Board of the University of Missouri — St. Louis; a member of the Board of Directors of the Regional Chamber and Growth Association of St. Louis; a Director of the United Way of Greater St. Louis; a Vice Chair of the Missouri Historical Society; a member of Financial Executives International and the Civic Entrepreneurs Organization; Fellow, Foreign Policy Association; and a former chairman of the Bituminous Coal Operators’ Association.
 
Michael C. Crews was named our Executive Vice President and Chief Financial Officer in June 2008. He joined us in 1998 as Senior Manager of Financial Reporting, and has served as Assistant Corporate Controller, Director of Planning, Assistant Treasurer, Vice President of Planning, Analysis, and Performance Assessment, and Vice President of Operations Planning. Prior to joining us, Mr. Crews served for three years in financial positions with MEMC Electronic Materials, Inc. and six years at KPMG Peat Marwick in St. Louis. He has a Bachelor of Science degree in Accountancy from the University of Missouri at Columbia and a Master of Business Administration (MBA) degree from Washington University in St. Louis.
 
Sharon D. Fiehler has been our Executive Vice President and Chief Administrative Officer since January 2008. From April 2002 to January 2008, she served as our Executive Vice President of Human Resources and Administration. Ms. Fiehler joined us in 1981 as Manager — Salary Administration and has held a series of employee relations, compensation and salaried benefits positions. She holds degrees in social work and psychology and a MBA, and prior to joining us was a personnel representative for Ford Motor Company. Ms. Fiehler is a Director of the Federal Reserve Bank of St. Louis. She is a member of the Executive Committee and Board of Directors of Junior Achievement of St. Louis; a member of the Board of Directors of the St. Louis Zoo Association; and President of the Chancellor’s Council of the University of Missouri St. Louis. She was a recipient of the 2006 St. Louis Business Journal Most Influential Women Award and a recipient of the 2008 YWCA Leader of Distinction Award.
 
Eric Ford was named our Executive Vice President and Chief Operating Officer in March 2007. Mr. Ford has 38 years of extensive international management, operating and engineering experience and most recently served as Chief Executive Officer of Anglo Coal Australia Pty Ltd. He joined Anglo Coal in 1971 and, after a series of increasingly complex operating assignments, was appointed President and Chief Executive Officer of Anglo American’s joint venture coal mining operation in Colombia in 1998. In 2000, he returned to Anglo American Corporation as Executive Director of Operations for Anglo Platinum Corporation Limited. He was subsequently appointed Chief Executive Officer of Anglo Coal Australia Pty Ltd in 2001. Mr. Ford holds a Master of Science degree in Management Science from Imperial College in London and a Bachelor of Science degree in Mining Engineering (cum laude) from the University of the Witwatersrand in Johannesburg, South Africa. He was previously Deputy Chairman and a member of the Executive Committee of the Coal Industry Advisory Board of the International Energy Agency, and Vice Chairman and Director of the Minerals Council of Australia.
 
Alexander C. Schoch was named our Executive Vice President Law and Chief Legal Officer in October 2006 and our Secretary in May 2008. Prior to joining us, Mr. Schoch served as Vice President and General Counsel for Emerson Process Management, an operating segment of Emerson Electric Co. and a leading supplier of process-automation products, from August 2004 to October 2006. Mr. Schoch also served in


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several legal positions with Goodrich Corporation, a global supplier to the aerospace and defense industries, from 1987 to 2004, including Vice President, Associate General Counsel and Secretary. Prior to that, he worked for Marathon Oil Company as an attorney in its international exploration and production division. Mr. Schoch holds a Juris Doctorate from Case Western Reserve University in Ohio, as well as a Bachelor of Arts in Economics from Kenyon College in Ohio. He is admitted to practice law in several states, and is a member of the American and International Bar Associations.
 
PART II
 
Item 5.   Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
 
Our common stock is listed on the New York Stock Exchange, under the symbol “BTU”. As of February 12, 2010, there were 1,395 holders of record of our common stock.
 
The table below sets forth the range of quarterly high and low sales prices (including intraday prices) for our common stock on the New York Stock Exchange during the calendar quarters indicated.
 
                         
    Share Price   Dividends
    High   Low   Paid
 
2008
                       
First Quarter
  $ 63.97     $ 42.05     $ 0.06  
Second Quarter
    88.69       49.38       0.06  
Third Quarter
    88.39       39.06       0.06  
Fourth Quarter
    43.99       16.00       0.06  
2009
                       
First Quarter
  $ 30.95     $ 20.17     $ 0.06  
Second Quarter
    37.44       23.56       0.06  
Third Quarter
    41.54       27.19       0.06  
Fourth Quarter
    48.21       34.54       0.07  
 
Dividend Policy
 
We paid quarterly dividends totaling $0.25 per share and $0.24 per share for the years ended December 31, 2009 and 2008, respectively. Most recently, our Board of Directors declared a dividend of $0.07 per share of Common Stock on January 27, 2010, payable on March 3, 2010, to stockholders of record on February 10, 2010. The declaration and payment of dividends and the amount of dividends will depend on our results of operations, financial condition, cash requirements, future prospects, any limitations imposed by our debt instruments and other factors deemed relevant by our Board of Directors. Limitations on our ability to pay dividends imposed by our debt instruments are discussed in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
 
Share Repurchases
 
Our Board of Directors has authorized a share repurchase program of up to $1 billion of the then 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. Our Chairman and Chief Executive Officer also has the authority to direct us to repurchase up to $100 million of our common stock outside the share repurchase program. The repurchase program does not have an expiration date and may be discontinued at any time. Through December 31, 2009, we have made repurchases of 7.7 million shares at a cost of $299.6 million, leaving $700.4 million available for share repurchase under the program.


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The following table summarizes all share repurchases for the three months ended December 31, 2009:
 
                                 
                      Maximum Dollar
 
                      Value that May Yet
 
                Total Number of
    Be Used to
 
    Total
          Shares Purchased
    Repurchase
 
    Number of
    Average
    as Part of Publicly
    Shares Under the
 
    Shares
    Price per
    Announced
    Publicly Announced
 
Period
  Purchased(1)     Share     Program     Program (in millions)  
 
October 1 through October 31, 2009
    558     $ 43.37           $ 700.4  
November 1 through November 30, 2009
    1,358       39.59           $ 700.4  
December 1 through December 31, 2009
    570       45.21           $ 700.4  
                                 
Total
    2,486     $ 41.73                
                                 
 
 
(1) Represents 2,486 shares withheld to cover the withholding taxes upon the vesting of restricted stock.
 
Item 6.   Selected Financial Data.
 
The following table presents selected financial and other data about us for the most recent five fiscal years. The following table and the discussion of our results of operations in 2009, 2008 and 2007 in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations includes references to, and analysis of, our Adjusted EBITDA results. We define Adjusted EBITDA as income from continuing operations before deducting net interest expense, income taxes, asset retirement obligation expense and depreciation, depletion and amortization. Adjusted EBITDA is used by management to measure our segments’ operating performance, and management also believes it is a useful indicator of our ability to meet debt service and capital expenditure requirements. 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 U.S. generally accepted accounting principles (GAAP), as reflected at the end of Item 6. Selected Financial Data. and in Note 22 to our consolidated financial statements.
 
The selected financial data for all periods presented reflect the assets, liabilities and results of operations from subsidiaries spun off as Patriot as discontinued operations. We also have classified as discontinued operations those operations recently divested, as well as certain non-strategic mining assets held for sale where we have committed to the divestiture of such assets.
 
In October 2006, we acquired Excel. Our results of operations include Excel’s results of operations from the date of acquisition.
 
We have derived the selected historical financial data as of and for the years ended December 31, 2009, 2008, 2007, 2006 and 2005 from our audited financial statements. You should read the following table in conjunction with the financial statements, the related notes to those financial statements and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.


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The results of operations for the historical periods included in the following table are not necessarily indicative of the results to be expected for future periods. In addition, the Risk Factors section of Item 1A of this report includes a discussion of risk factors that could impact our future results of operations.
 
                                         
    Year Ended December 31,  
    2009     2008     2007     2006     2005  
    (In millions, except per share data)  
 
Results of Operations Data
                                       
Total revenues
  $ 6,012.4     $ 6,561.0     $ 4,523.8     $ 4,045.6     $ 3,597.9  
Costs and expenses
    5,167.6       5,164.7       3,924.1       3,432.8       3,166.3  
                                         
Operating profit
    844.8       1,396.3       599.7       612.8       431.6  
Interest expense, net
    193.1       217.0       228.8       127.8       88.9  
                                         
Income from continuing operations before income taxes
    651.7       1,179.3       370.9       485.0       342.7  
Income tax provision (benefit)
    193.8       191.4       (70.7 )     (85.6 )     62.3  
                                         
Income from continuing operations, net of income taxes
    457.9       987.9       441.6       570.6       280.4  
Income (loss) from discontinued operations, net of income taxes
    5.1       (28.8 )     (180.1 )     30.7       144.8  
                                         
Net income
    463.0       959.1       261.5       601.3       425.2  
Less: net income (loss) attributable to noncontrolling interests
    14.8       6.2       (2.3 )     0.6       2.5  
                                         
Net income attributable to common stockholders
  $ 448.2     $ 952.9     $ 263.8     $ 600.7     $ 422.7  
                                         
Basic earnings per share from continuing operations(1)
  $ 1.66     $ 3.63     $ 1.67     $ 2.15     $ 1.06  
Diluted earnings per share from continuing operations(1)
  $ 1.64     $ 3.60     $ 1.64     $ 2.11     $ 1.04  
Weighted average shares used in calculating basic earnings per share
    265.5       268.9       264.1       263.4       261.5  
Weighted average shares used in calculating diluted earnings per share
    267.5       270.7       268.6       268.8       267.3  
Dividends declared per share
  $ 0.25     $ 0.24     $ 0.24     $ 0.24     $ 0.17  
Other Data
                                       
Tons sold
    243.6       255.0       235.5       221.2       213.7  
Net cash provided by (used in) continuing operations:
                                       
Operating activities
  $ 1,053.5     $ 1,409.8     $ 460.7     $ 611.1     $ 672.4  
Investing activities
    (408.2 )     (419.3 )     (538.9 )     (2,055.6 )     (506.3 )
Financing activities
    (102.3 )     (487.0 )     41.7       1,403.0       (41.4 )
Adjusted EBITDA
    1,290.1       1,846.9       969.7       909.7       696.4  
Balance Sheet Data (at period end)
                                       
Total assets
  $ 9,955.3     $ 9,695.6     $ 9,082.3     $ 9,504.7     $ 6,852.0  
Total long-term debt (including capital leases)
    2,752.3       2,793.6       2,909.0       2,911.6       1,332.0  
Total stockholders’ equity
    3,755.9       3,119.5       2,735.3       2,587.0       2,178.5  
 
 
(1) Effective January 1, 2009, we adopted the two-class method to compute basic and diluted earnings per share. This method has been retrospectively applied to all periods presented.


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Adjusted EBITDA is calculated as follows (unaudited):
 
                                         
    Year Ended December 31,  
    2009     2008     2007     2006     2005  
    (Dollars in millions)  
 
Income from continuing operations, net of income taxes
  $ 457.9     $ 987.9     $ 441.6     $ 570.6     $ 280.4  
Income tax provision (benefit)
    193.8       191.4       (70.7 )     (85.6 )     62.3  
Depreciation, depletion and amortization
    405.2       402.4       346.3       282.7       244.9  
Asset retirement obligation expense
    40.1       48.2       23.7       14.2       19.9  
Interest expense, net
    193.1       217.0       228.8       127.8       88.9  
                                         
Adjusted EBITDA
  $ 1,290.1     $ 1,846.9     $ 969.7     $ 909.7     $ 696.4  
                                         
 
Item 7.   Management’s Discussion and Analysis of Financial Condition and Results of Operations.
 
Overview
 
We are the world’s largest private sector coal company, with majority interests in 28 coal mining operations in the U.S. and Australia. In 2009, we produced 210.0 million tons of coal and sold 243.6 million tons of coal. For 2009, our U.S. sales represented 19% of U.S. coal consumption and were approximately 50% greater than the sales of our closest U.S. competitor.
 
We conduct business through four principal segments: Western U.S. Mining, Midwestern U.S. Mining, Australian Mining, and Trading and Brokerage. The principal business of the Western and Midwestern U.S. Mining segments is the mining, preparation and sale of thermal coal, sold primarily to electric utilities. Our Western U.S. Mining operations consist of our Powder River Basin, Southwest and Colorado operations. Our Midwestern U.S. Mining operations consist of our Illinois and Indiana operations. The business of our Australian Mining Segment is the mining of various qualities of low-sulfur, high Btu coal (metallurgical coal) as well as thermal coal primarily sold to an international customer base with a portion sold to Australian steel producers and power generators. Metallurgical coal is produced primarily from five of our Australian mines. In 2009, metallurgical coal was approximately 3% of our total sales volume, but represented a larger share of our revenue, approximately 23%.
 
We typically sell coal to utility customers under long-term contracts (those with terms longer than one year). During 2009, approximately 93% of our worldwide sales (by volume) were under long-term contracts. For the year ended December 31, 2009, 81% of our total sales (by volume) were to U.S. electricity generators, 17% were to customers outside the U.S. and 2% were to the U.S. industrial sector.
 
Our Trading and Brokerage segment’s principal business is the brokering of coal sales of other producers both as principal and agent, and the trading of coal, freight and freight-related contracts. We also provide transportation-related services in support of our coal trading strategy, as well as hedging activities in support of our mining operations.
 
Our fifth segment, Corporate and Other, includes mining and export/transportation joint ventures, energy-related commercial activities, as well as the management of our vast coal reserve and real estate holdings.
 
We continue to pursue development of coal-fueled generating and Btu Conversion 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. Coal-fueled generating projects may 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. Currently, we own 5.06% of the 1,600-megawatt Prairie State Energy Campus that is under construction in Washington County, Illinois.
 
We are determining how to best participate in Btu Conversion technologies to economically convert our coal resources to natural gas and transportation fuels through the Kentucky NewGas and GreatPoint Energy projects in the U.S. We are also advancing the development of clean coal technologies, including carbon


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capture and sequestration, through a number of initiatives that include the FutureGen Alliance and university research programs in the U.S., GreenGen in China and COAL21 Fund in Australia.
 
As discussed more fully in Item 1A. Risk Factors, our results of operations in the near-term could be negatively impacted by the rate of the economic recovery, adverse 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 may adjust our production levels further in response to changes in market demand.
 
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
 
Summary
 
Our overall results for 2009 compared to 2008 reflect the unfavorable impact of lower global demand for coal as a result of the global economic recession. Despite the recession, our 2009 Adjusted EBITDA was the second highest in our 126-year history and second only to our 2008 Adjusted EBITDA. We also ended 2009 with total available liquidity of $2.5 billion. We continue to focus on strong cost control and productivity improvements, increased contributions from our high-margin operations and exercising tight capital discipline.
 
Our 2009 tons sold were below prior year levels reflecting planned production reductions in the Powder River Basin to match lower demand, partially offset by increased volumes associated with the full-year operation of our El Segundo Mine in the Southwest. In the U.S., the decreased demand from lower industrial output, lower natural gas prices that resulted in higher fuel switching, and higher coal stockpiles in the U.S. led to an 8.5 million ton decline in sales volume. In Australia, lower demand from steel customers resulted in a 1.3 million ton decline in metallurgical coal volume, although volumes in the second half of 2009 began to increase on an improved economic outlook led by demand from Asian-Pacific markets.
 
Our 2009 revenues declined compared to 2008 and were primarily impacted by Australia’s lower annual export contract pricing that commenced on April 1, 2009 as compared to 2008’s record pricing and the overall decline in volume. Lower revenues were also driven by the decline in Trading and Brokerage revenues that resulted from lower coal pricing volatility. The lower Australian and Trading and Brokerage revenues were partially offset by an increase in U.S. revenues per ton that reflect multi-year contracts signed at higher prices in recent years.
 
While our Segment Adjusted EBITDA reflects the lower revenue discussed above, our 2009 margins also reflect the impact of producing at reduced levels as well as higher sales related costs. In addition, our costs in Australia were higher due to two additional longwall moves compared to 2008 and the impact of mining in difficult geologic conditions that also included higher costs for overburden removal.
 
Net income declined in 2009 compared to 2008 reflecting the above items, as well as lower results from equity affiliates and decreased net gains on disposals of assets. Income from continuing operations, net of income taxes was $457.9 million in 2009, or $1.64 per diluted share, 53.6% below 2008 income from continuing operations, net of income taxes of $987.9 million, or $3.60 per diluted share.


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Tons Sold
 
The following table presents tons sold by operating segment for the years ended December 31, 2009 and 2008:
 
                                 
    Year Ended December 31,     Increase (Decrease)  
    2009     2008     Tons     %  
    (Tons in millions)  
 
Western U.S. Mining
    160.1       169.7       (9.6 )     (5.7 )%
Midwestern U.S. Mining
    31.8       30.7       1.1       3.6 %
Australian Mining
    22.3       23.4       (1.1 )     (4.7 )%
Trading and Brokerage
    29.4       31.2       (1.8 )     (5.8 )%
                                 
Total tons sold
    243.6       255.0       (11.4 )     (4.5 )%
                                 
 
Revenues
 
The following table presents revenues for the years ended December 31, 2009 and 2008:
 
                                 
          Increase (Decrease)
 
    Year Ended December 31,     to Revenues  
    2009     2008     $     %  
    (Dollars in millions)  
 
Western U.S. Mining
  $ 2,612.6     $ 2,533.1     $ 79.5       3.1 %
Midwestern U.S. Mining
    1,303.8       1,154.6       149.2       12.9 %
Australian Mining
    1,678.0       2,242.8       (564.8 )     (25.2 )%
Trading and Brokerage
    391.0       601.8       (210.8 )     (35.0 )%
Other
    27.0       28.7       (1.7 )     (5.9 )%
                                 
Total revenues
  $ 6,012.4     $ 6,561.0     $ (548.6 )     (8.4 )%
                                 
 
2009 revenues were below prior year driven by decreases in our Australian Mining and Trading and Brokerage segments as discussed below:
 
  •  Australian Mining operations’ average sales price decreased 21.4% from the prior year reflecting the lower annual export contract pricing that commenced April 1, 2009 compared to the record pricing realized in 2008. The price decreases were combined with volume decreases from the prior year (4.7%) due to overall lower demand experienced in the first half of 2009. 2009 metallurgical coal shipments of 6.9 million tons were 1.3 million tons below prior year. In the second half of 2009, 5.0 million tons of metallurgical coal were shipped, reflecting a partial recovery from the lower metallurgical coal shipments that occurred in the first half of the year.
 
  •  Trading and Brokerage revenues decreased from the prior year primarily due to lower coal pricing volatility in 2009 resulting in lower margins on trading transactions, partially offset by profit from business contracted in 2008 that was realized in 2009 on an international brokerage arrangement.
 
These decreases to revenues were partially offset by revenue increases in our Midwestern U.S. and Western U.S. Mining segments as discussed below:
 
  •  Midwestern U.S. Mining operations’ average sales price increased over the prior year (9.3%) driven by the benefit of higher Illinois Basin prices and increased shipments, including purchased coal used to satisfy certain coal supply agreements.
 
  •  Western U.S. Mining operations’ average sales price increased over the prior year (9.2%) due to a combination of higher contract pricing and a shift in sales mix. Revenues were also higher due to increased shipments from our El Segundo Mine (commissioned in June 2008) and customer contract termination and restructuring agreements. These increases were partially offset by the prior year


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  revenue recovery on a long-term coal supply agreement ($56.9 million) and an overall volume decrease (5.7%) reflecting our planned Powder River Basin production decreases to match demand.
 
Segment Adjusted EBITDA
 
The following table presents segment Adjusted EBITDA for the years ended December 31, 2009 and 2008:
 
                                 
          Increase (Decrease) to
 
    Year Ended December 31,     Segment Adjusted EBITDA  
    2009     2008     $     %  
    (Dollars in millions)  
 
Western U.S. Mining
  $ 721.5     $ 681.3     $ 40.2       5.9 %
Midwestern U.S. Mining
    281.9       177.3       104.6       59.0 %
Australian Mining
    437.8       1,016.6       (578.8 )     (56.9 )%
Trading and Brokerage
    193.4       218.9       (25.5 )     (11.6 )%
                                 
Total Segment Adjusted EBITDA
  $ 1,634.6     $ 2,094.1     $ (459.5 )     (21.9 )%
                                 
 
Australian Mining operations’ Adjusted EBITDA decreased compared to the prior year due to lower annual export contract pricing and lower sales volume due to reduced demand ($416.0 million) as discussed above. Also impacting the segment’s Adjusted EBITDA was higher production costs ($170.7 million) driven by increased overburden stripping ratios and decreased longwall mine performance, which included higher costs associated with two additional longwall moves in 2009 compared to 2008.
 
Trading and Brokerage Adjusted EBITDA decreased compared to prior year primarily due to lower net revenue discussed above.
 
Western U.S. Mining operations’ Adjusted EBITDA increased over the prior year driven by higher pricing ($205.5 million), partially offset by lower demand ($63.2 million), a prior year revenue recovery on a long-term coal supply agreement ($56.9 million), higher sales related costs ($52.0 million) and lower productivity due to increased stripping ratios ($20.8 million). The impact of lower demand was partially mitigated by revenues from customer contract termination and restructuring agreements ($27.8 million).
 
Midwestern U.S. Mining operations’ Adjusted EBITDA increased over the prior year primarily due to higher pricing ($110.7 million) and decreased commodity costs ($16.0 million), partially offset by higher costs associated with mining in more difficult geological conditions compared to the prior year ($20.7 million).
 
Income From Continuing Operations Before Income Taxes
 
The following table presents income from continuing operations before income taxes for the years ended December 31, 2009 and 2008:
 
                                 
          Increase (Decrease)
 
    Year Ended December 31,     to Income  
    2009     2008     $     %  
    (Dollars in millions)  
 
Total Segment Adjusted EBITDA
  $ 1,634.6     $ 2,094.1     $ (459.5 )     (21.9 )%
Corporate and Other Adjusted EBITDA
    (344.5 )     (247.2 )     (97.3 )     (39.4 )%
Depreciation, depletion and amortization
    (405.2 )     (402.4 )     (2.8 )     (0.7 )%
Asset retirement obligation expense
    (40.1 )     (48.2 )     8.1       16.8 %
Interest expense
    (201.2 )     (227.0 )     25.8       11.4 %
Interest income
    8.1       10.0       (1.9 )     (19.0 )%
                                 
Income from continuing operations before income taxes
  $ 651.7     $ 1,179.3     $ (527.6 )     (44.7 )%
                                 


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Income from continuing operations before income taxes decreased from prior year primarily due to the lower Total Segment Adjusted EBITDA discussed above and lower Corporate and Other Adjusted EBITDA, partially offset by lower interest expense and asset retirement obligation expense.
 
The decrease of $97.3 million in Corporate and Other Adjusted EBITDA during 2009 compared to 2008 was due to the following:
 
  •  Lower results from equity affiliates ($69.1 million) primarily from our joint venture interest in Carbones del Guasare (owner and operator of the Paso Diablo Mine in Venezuela). Carbones del Guasare incurred unfavorable results in 2009 compared to 2008 (our share of which was $25.6 million) due to lower productivity, higher operating costs and ongoing labor issues; in addition, we recognized a $34.7 million impairment loss on this investment. See Note 1 to our consolidated financial statements for additional information concerning this joint venture interest.
 
  •  Lower net gains on disposal or exchange of assets ($49.7 million) was due primarily to a $54.0 million gain in the prior year from the sale of non-strategic coal reserves and surface lands located in Kentucky.
 
  •  The above decreases to Corporate and Other Adjusted EBITDA were offset by lower costs associated with Btu Conversion activities ($16.9 million).
 
Interest expense was lower than prior year due to lower variable interest rates on our Term Loan Facility and accounts receivable securitization program and lower average borrowings on our Revolving Credit Facility.
 
Asset retirement obligation expense decreased in 2009 as compared to the prior year due primarily to a decrease in the ongoing and closed mine reclamation rates reflecting lower fuel and re-vegetation costs incurred in our Midwestern U.S. Mining segment.
 
Net Income Attributable to Common Stockholders
 
The following table presents net income attributable to common stockholders for the years ended December 31, 2009 and 2008:
 
                                 
          Increase (Decrease)
 
    (Dollars in millions)     to Income  
    2009     2008     $     %  
          (Dollars in millions)        
 
Income from continuing operations before income taxes
  $ 651.7     $ 1,179.3     $ (527.6 )     (44.7 )%
Income tax provision
    (193.8 )     (191.4 )     (2.4 )     (1.3 )%
                                 
Income from continuing operations, net of income taxes
    457.9       987.9       (530.0 )     (53.6 )%
Income (loss) from discontinued operations, net of income taxes
    5.1       (28.8 )     33.9       117.7 %
                                 
Net income
    463.0       959.1       (496.1 )     (51.7 )%
Net income attributable to noncontrolling interests
    (14.8 )     (6.2 )     (8.6 )     (138.7 )%
                                 
Net income attributable to common stockholders
  $ 448.2     $ 952.9     $ (504.7 )     (53.0 )%
                                 
 
Net income attributable to common stockholders decreased in 2009 compared to the prior year due to the decrease in income from continuing operations before incomes taxes discussed above.


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Income tax provision was impacted by the following:
 
  •  Increased expense associated with the remeasurement of non-U.S. tax accounts as a result of the strengthening Australian dollar against the U.S dollar ($139.6 million; exchange rate rose 29% in 2009 compared to a 21% decrease in 2008, as illustrated below); and
 
                                         
    December 31,   Rate Change
    2009   2008   2007   2009   2008
 
Australian dollar to U.S. dollar exchange rate
  $ 0.8969     $ 0.6928     $ 0.8816     $ 0.2041     $ (0.1888 )
 
  •  The prior year release of a foreign valuation allowance related to our Australian net operating loss carry forwards ($45.3 million) as a result of significantly higher earnings resulting from the higher contract pricing that was secured during 2008.
 
  •  The above increases to income tax expense were partially offset by lower pre-tax earnings in 2009, which drove a decrease to the income tax provision ($184.6 million).
 
Income from discontinued operations increased compared to the prior year as the prior year included operating losses, net of a $26.2 million gain on the sale of our Baralaba Mine, and an $11.7 million write-off of a coal excise tax receivable in the first quarter of 2008. In late 2008, legislation was passed which contained provisions that allowed for the refund of coal excise tax collected on certain coal shipments. In 2009, we received a coal excise tax refund resulting in approximately $35 million, net of income taxes, recorded in “Income (loss) from discontinued operations, net of income taxes” (see Note 2 to the consolidated financial statements for more information related to the excise tax refund). Partially offsetting the 2009 excise tax refund were operating losses associated with discontinued operations and assets held for sale ($20.6 million) and a $10.0 million loss on the sale of our Chain Valley Mine in Australia.
 
Year Ended December 31, 2008 Compared to Year Ended December 31, 2007
 
Summary
 
Higher average sales prices and volumes across all operating regions, particularly in Australia, contributed to an increase in revenues in 2008 compared to 2007. Segment Adjusted EBITDA rose primarily on the higher pricing mentioned above and favorable results from Trading and Brokerage. Increases in sales prices and volumes were partially offset by higher commodity, material, supply, sales-related and labor costs in all operating regions. Income from continuing operations, net of income taxes was $987.9 million in 2008, or $3.60 per diluted share, 123.7% above 2007 income from continuing operations, net of income taxes of $441.6 million, or $1.64 per diluted share.
 
Tons Sold
 
The following table presents tons sold by operating segment for the years ended December 31, 2008 and 2007:
 
                                 
    Year Ended December 31,     Increase  
    2008     2007     Tons     %  
    (Tons in millions)  
 
Western U.S. Mining
    169.7       161.4       8.3       5.1 %
Midwestern U.S. Mining
    30.7       29.6       1.1       3.7 %
Australian Mining
    23.4       20.4       3.0       14.7 %
Trading and Brokerage
    31.2       24.1       7.1       29.5 %
                                 
Total tons sold
    255.0       235.5       19.5       8.3 %
                                 


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Revenues
 
The following table presents revenues for the years ended December 31, 2008 and 2007:
 
                                 
          Increase (Decrease)
 
    Year Ended December 31,     to Revenues  
    2008     2007     $     %  
    (Dollars in millions)  
 
Western U.S. Mining
  $ 2,533.1     $ 2,063.2     $ 469.9       22.8 %
Midwestern U.S. Mining
    1,154.6       987.1       167.5       17.0 %
Australian Mining
    2,242.8       1,117.6       1,125.2       100.7 %
Trading and Brokerage
    601.8       320.7       281.1       87.7 %
Other
    28.7       35.2       (6.5 )     (18.5 )%
                                 
Total revenues
  $ 6,561.0     $ 4,523.8     $ 2,037.2       45.0 %
                                 
 
Total revenues increased in 2008 compared to the prior year across all operating segments. The primary drivers of the increases included the following:
 
  •  An increase in average sales price at our Australian Mining operations (75.0%), primarily driven by the strength of metallurgical coal prices on our Australian contracts that reprice annually in the second quarter of each year.
 
  •  U.S. Mining operations’ average sales price increased over the prior year (15.2%) driven by the benefit of higher priced coal supply agreements signed in recent years.
 
  •  Australia’s volumes increased over the prior year (14.7%) from strong demand during the first three quarters of 2008 and additional production from recently completed mines. Year-over-year increases were partially offset by heavy rainfall and flooding in Queensland during the first quarter of 2008 and customer shipment deferrals in the fourth quarter of 2008 due to the global economic slowdown.
 
  •  Increased demand also led to higher volumes across our U.S. operating segments, which overcame slightly lower volumes at some of our Midwestern U.S. Mining surface operations due to poor weather in that operating region that impacted production during the first and second quarters. The volume increase of 5.1% at our Western U.S. Mining operations resulted from greater throughput from capital improvements and contributions from our new El Segundo Mine, partially offset by the flooding in the midwestern U.S. that impacted railroad shipping performance related to western U.S. production during the second quarter of 2008.
 
  •  Trading and Brokerage revenues increased over the prior year due to increased trading positions allowing us to capture market movements derived from the volatility of both domestic and international coal markets.
 
  •  Also impacting year-over-year revenues in our Western U.S. Mining operations was an agreement to recover previously recognized postretirement healthcare and reclamation costs of $56.9 million in the second quarter of 2008.


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Segment Adjusted EBITDA
 
The following table presents segment Adjusted EBITDA for the years ended December 31, 2008 and 2007:
 
                                 
          Increase (Decrease) to
 
    Year Ended December 31,     Segment Adjusted EBITDA  
    2008     2007     $     %  
          (Dollars in millions)        
 
Western U.S. Mining
  $ 681.3     $ 595.4     $ 85.9       14.4 %
Midwestern U.S. Mining
    177.3       200.0       (22.7 )     (11.4 )%
Australian Mining
    1,016.6       167.2       849.4       508.0 %
Trading and Brokerage
    218.9       116.6       102.3       87.7 %
                                 
Total Segment Adjusted EBITDA
  $ 2,094.1     $ 1,079.2     $ 1,014.9       94.0 %
                                 
 
Adjusted EBITDA from our Western U.S. Mining operations increased in 2008 over the prior year primarily driven by an overall increase in average sales prices per ton across the region ($2.10) and higher volumes in the region due to increased demand and greater throughput as a result of capital improvements. Also contributing to the increase was the recovery of postretirement healthcare and reclamation costs discussed above. Partially offsetting the pricing and volume contributions were higher per ton costs ($1.78). The cost increases were primarily due to higher sales related costs, higher material, supply and labor costs, higher repair and maintenance costs in the Powder River Basin and increased commodity costs, net of hedging activities, driven by higher average fuel and explosives pricing.
 
Midwestern U.S. Mining operations’ Adjusted EBITDA decreased in 2008 as increases in average sales price per ton ($4.22) were offset by cost increases resulting from higher costs for commodities, net of hedging activities, driven by higher average fuel and explosives prices, as well as higher material, supply and labor costs. Heavy rains and flooding in the midwestern U.S. affected sales volume at some of our mines, particularly in the first half of the year. Also affecting the Midwestern U.S. Mining segment was the decrease in revenues from coal sold to synthetic fuel plants in the prior year ($28.9 million) due to the producers exiting the synthetic fuel market after expiration of federal tax credits at the end of 2007.
 
Our Australian Mining operations’ Adjusted EBITDA increased in 2008 primarily due to higher pricing negotiated in the second quarter of 2008 ($41.06 per ton), higher overall volumes as a result of strong export demand and contributions from our recently completed mines and lower demurrage costs. These favorable impacts were partially offset by higher fuel costs, an increase in labor and overburden removal expenses and higher contractor costs (five of ten Australian mines are managed utilizing contract miners).
 
Trading and Brokerage Adjusted EBITDA increased in 2008 over the prior year due to increased trading volumes and higher coal price volatility.


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Income From Continuing Operations Before Income Taxes
 
The following table presents income from continuing operations before income taxes for the years ended December 31, 2008 and 2007:
 
                                 
          Increase (Decrease)
 
    Year Ended December 31,     to Income  
    2008     2007     $     %  
    (Dollars in millions)  
 
Total Segment Adjusted EBITDA
  $ 2,094.1     $ 1,079.2     $ 1,014.9       94.0 %
Corporate and Other Adjusted EBITDA
    (247.2 )     (109.5 )     (137.7 )     (125.8 )%
Depreciation, depletion and amortization
    (402.4 )     (346.3 )     (56.1 )     (16.2 )%
Asset retirement obligation expense
    (48.2 )     (23.7 )     (24.5 )     (103.4 )%
Interest expense
    (227.0 )     (235.8 )     8.8       3.7 %
Interest income
    10.0       7.0       3.0       42.9 %
                                 
Income from continuing operations before income taxes
  $ 1,179.3     $ 370.9     $ 808.4       218.0 %
                                 
 
Income from continuing operations before income taxes increased over the prior year primarily due to the higher Total Segment Adjusted EBITDA discussed above, partially offset by lower Corporate and Other Adjusted EBITDA, higher depreciation, depletion and amortization, and higher asset retirement obligation expense.
 
The decrease in Corporate and Other Adjusted EBITDA during 2008 compared to 2007 was due to the following:
 
  •  Higher selling and administrative expenses ($54.7 million) primarily driven by an increase in performance-based incentive costs and legal expenses;
 
  •  Cost reimbursement and partner fees received in the prior year for the Prairie State project, primarily related to the entrance of new project partners ($29.5 million);
 
  •  Lower net gains on disposals or exchanges of assets ($15.7 million). 2008 activity included a gain of $54.0 million on the sale of approximately 58 million tons of non-strategic coal reserves and surface lands located in Kentucky. 2007 activity included a gain of $50.5 million on the exchange of oil and gas rights and assets in more than 860,000 acres in the Illinois Basin, West Virginia, New Mexico and the Powder River Basin for coal reserves in West Virginia and Kentucky and cash proceeds. The prior year also included a gain of $26.4 million on the sale of approximately 172 million tons of coal reserves and surface lands to the Prairie State equity partners; and
 
  •  Lower equity income ($15.5 million) from our joint venture interest in Carbones del Guasare (owner and operator of the Paso Diablo Mine in Venezuela) and higher costs associated with Btu Conversion activities of $14.3 million in 2008.
 
Depreciation, depletion and amortization was higher in 2008 compared to the prior year because of increased depletion across our operating platform resulting from the volume increases and the impact of mining higher value coal reserves. In addition, depreciation and depletion increases resulted from our recently completed Australian mines and depletion at our El Segundo Mine.
 
Asset retirement obligation expense increased in 2008 as compared to the prior year due to an increase in the ongoing and closed mine reclamation rates that reflect higher fuel, labor and re-vegetation costs, as well as an overall increase in the number of acres disturbed. The addition of the El Segundo Mine, which was completed in June 2008, also contributed to higher asset retirement obligation expense.


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Net Income Attributable to Common Stockholders
 
The following table presents net income attributable to common stockholders for the years ended December 31, 2008 and 2007:
 
                                 
          Increase (Decrease)
 
    (Dollars in millions)     to Income  
    2008     2007     $     %  
    (Dollars in millions)  
 
Income from continuing operations before income taxes
  $ 1,179.3     $ 370.9     $ 808.4       218.0 %
Income tax (provision) benefit
    (191.4 )     70.7       (262.1 )     (370.7 )%
                                 
Income from continuing operations, net of income taxes
    987.9       441.6       546.3       123.7 %
Loss from discontinued operations, net of income taxes
    (28.8 )     (180.1 )     151.3       84.0 %
                                 
Net income
    959.1       261.5       697.6       266.8 %
Net (income) loss attributable to noncontrolling interests
    (6.2 )     2.3       (8.5 )     (369.6 )%
                                 
Net income attributable to common stockholders
  $ 952.9     $ 263.8     $ 689.1       261.2 %
                                 
 
Net income attributable to common stockholders increased in 2008 compared to the prior year due to the increase in income from continuing operations before incomes taxes discussed above.
 
Income tax provision was impacted by the following:
 
  •  Increased expense in 2008 due to higher pre-tax earnings ($282.9 million); and
 
  •  Valuation allowance release against federal net operating loss credits recognized into income in 2007 ($197.8 million); partially offset by
 
  •  Income tax benefit associated with the remeasurement of non-U.S. tax accounts as a result of the weakening Australian dollar against the U.S dollar in 2008 ($121.2 million; exchange rate fell 21% in 2008 compared to an 11% increase in 2007, as illustrated below); and
 
                                         
    December 31,   Rate Change
    2008   2007   2006   2008   2007
 
Australian dollar to U.S. dollar exchange rate
  $ 0.6928     $ 0.8816     $ 0.7913     $ (0.1888 )   $ 0.0903  
 
  •  The favorable rate difference resulting from higher foreign generated income in 2008 ($106.2 million); and
 
  •  The release of a foreign valuation allowance against a portion of our Australian net operating loss carryforwards in 2008 ($45.3 million) as a result of significantly higher earnings resulting from the higher contract pricing that was secured during 2008.
 
Net income for 2008 was also impacted by a lower loss from discontinued operations as compared to the prior year due primarily to losses incurred for Patriot operations in 2007. The loss from discontinued operations for 2008 related to operating losses, net of a $26.2 million gain on the sale of our Baralaba Mine, and an $11.7 million write-off of an excise tax refund receivable (net of tax) as a result of an April 2008 U.S. Supreme Court ruling (see Note 2 to the consolidated financial statements).
 
Outlook
 
Near-Term Outlook
 
Global economies are showing signs of improvement, with 2010 economic forecasts estimating a 2.6 to 4.0% expansion — although slower than expected economic improvement could temper these estimates. The


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Asia-Pacific markets are expected to continue to outpace the U.S. and European markets in economic growth and therefore electricity generation and steel production. For 2009, China and India were the only steel producing ‘majors’ to outpace prior-year levels, with all other nations 23% lower on average. For 2010, the World Steel Association estimates global steel production will increase 9 percent over 2009. Globally, 72 gigawatts of new coal-fueled generation are under construction and expected to come on line during 2010, more than 70% of which are new units in China and India. New global coal-fueled generation for 2010 is estimated to require approximately 300 million tons of new annual coal demand.
 
In the U.S., higher coal use caused by colder winter weather lowered utility stockpiles an estimated 25 to 30 million tons between December 2009 and mid-January 2010. As of February 15, 2010, utility stockpiles were approximately 150 to 155 million tons, 24% above the 10-year average and 6% above the year-ago level. We believe U.S. coal demand could rise 60 to 80 million tons based on economic growth, increasing industrial production and an expected reduction of coal-to-gas switching due to rising natural gas prices. Conversely, the Energy Information Administration (EIA) estimates coal production will be 43 million tons lower in 2010, in part due to production declines initiated in 2009. With rising demand and lower production, utility coal inventories are likely to be reduced.
 
As of January 26, 2010, we are targeting full-year 2010 production of approximately 185 to 195 million tons in the U.S. and 26 to 28 million tons in Australia. Total 2010 sales are expected to be in a range of 240 to 260 million tons. We may continue to adjust our production levels in response to changes in market demand.
 
We are fully contracted for 2010 at planned production levels in the U.S. As of January 26, 2010 we had 4.5 to 5.5 million tons of Australian metallurgical coal unpriced for 2010, along with 6.5 to 7.0 million tons of unpriced export thermal coal. Unpriced 2010 volumes are primarily planned for deliveries over the last three quarters of 2010.
 
We continue to manage costs and operating performance to mitigate external cost pressures, geologic conditions and potential shipping delays resulting from adverse port and rail performance. To mitigate the external cost pressures, we have an ongoing company-wide initiative to instill best practices at all operations. We may have higher per ton costs as a result of below-optimal production levels due to market-driven changes in demand. We may also encounter poor geologic conditions, lower third-party contract miner or brokerage 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. of this report for additional considerations regarding our outlook.
 
We rely on ongoing access to the worldwide financial markets for capital, insurance, hedging and investments through a wide variety of financial instruments and contracts. To the extent these markets are not available or increase significantly in cost, this could have a negative impact on our ability to meet our business goals. Similarly, many of our customers and suppliers rely on the availability of the financial markets to secure the necessary financing and financial surety (letters of credit, performance bonds, etc.) to complete transactions with us. To the extent customers and suppliers are not able to secure this financial support, it could have a negative impact on our results of operations and/or counterparty credit exposure.
 
Long-Term Outlook
 
Our long-term global outlook remains positive. Coal has been the fastest-growing fuel in the world for each of the past six years, with consumption growing nearly twice as fast as total energy use.
 
The International Energy Agency’s (IEA) World Energy Outlook estimates world primary energy demand will grow 40% between 2007 and 2030, with demand for coal rising 53%. China and India alone account for more than half of the expected incremental energy demand.
 
Coal is expected to retain its strong presence as a fuel for the power sector worldwide, with its share of the power generation mix projected to rise to 44% in 2030. Currently, 217 gigawatts of coal-fueled electricity


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generating plants are under construction around the world, representing more than 800 million tons of annual coal demand expected to come online in the next several years. In the U.S., 16 gigawatts of new coal-based generating capacity have been completed in 2009 or are under construction, representing approximately 65 million tons of annual coal demand when they come online over the next three to five years as expected.
 
We believe that Btu Conversion applications such as CTG and CTL plants represent an avenue for potential long-term industry growth. The EIA continues to project an increase in demand for unconventional sources of transportation fuel such as CTL, which is estimated to add nearly 70 million tons of annual U.S. coal demand by 2035. In addition, China and India are developing CTG and CTL facilities.
 
The IEA projects natural gas demand will grow 1.5% per year to just under 4,310 billion cubic meters in 2030. The biggest increase in absolute terms occurs in the Middle East, which holds the majority of the world’s proven reserves, and non-OECD Asia. North America and Eastern Europe/Eurasia are expected to remain the leading gas consumers in 2030, even though their demand is expected to rise less in percentage terms than almost anywhere else globally. Globally, the share of renewables is projected to rise four percentage points to 22% between 2007 and 2030, with most of the growth coming from non-hydro sources. Nuclear power is expected to grow in all major regions with the exception of Europe, but its share in total generation is expected to fall between 2007 and 2030.
 
We continue to support clean coal technology development and other initiatives addressing global climate change through our participation in a number of projects in the U.S., China and Australia. In addition, clean coal technology development in the U.S. is being accelerated by funding under the American Recovery and Reinvestment Act of 2009 and by the formation of an Interagency Task Force on Carbon Capture and Storage to develop a comprehensive and coordinated federal strategy to speed the commercial development of clean coal technologies.
 
Enactment of laws or passage of regulations regarding emissions from the combustion of coal by the U.S. or some of its states or by other countries, or other actions to limit such emissions, could result in electricity generators switching from coal to other fuel sources. The potential financial impact on us of future laws or regulations will depend upon the degree to which any such laws or regulations forces electricity generators to diminish their reliance on coal as a fuel source. That, in turn, will depend on a number of factors, including the specific requirements imposed by any such laws or regulations, the time periods over which those laws or regulations would be phased in and the state of commercial development and deployment of carbon capture and storage technologies. In view of the significant uncertainty surrounding each of these factors, it is not possible for us to reasonably predict the impact that any such laws or regulations may have on our results of operations, financial condition or cash flows.
 
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, federal coal lease payments, interest costs and costs related to past mining obligations as well as 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 and share repurchases, among other restricted items, are subject to limitations imposed in the covenants of our 5.875% and 6.875% Senior Notes and the Debentures. We generally fund all of our capital expenditure requirements with cash generated from operations.
 
We believe our available borrowing capacity and operating cash flows will be sufficient in the near term. As of December 31, 2009, we had cash and cash equivalents of $988.8 million and $1.5 billion of available borrowing capacity under our Senior Unsecured Credit Facility, net of outstanding letters of credit. The Senior Unsecured Credit Facility matures on September 15, 2011.


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The Pension Protection Act of 2006 (the Pension Protection Act), which was effective January 1, 2008, increased the long-term funding targets for single employer pension plans from 90% to 100%. “At risk” plans, as defined by the Pension Protection Act, are restricted from making full lump sum payments and from increasing benefits unless they are funded immediately, and also requires that the plan give participants notice regarding the at-risk status of the plan. If a plan falls below 60%, lump sum payments are prohibited and participant benefit accruals cease. As of December 31, 2009, our pension plans were approximately 77% funded, before considering planned 2010 contributions. Our minimum funding requirement for 2010 is approximately $3 million, and the qualified plans would not be considered at-risk. Using current assumptions, our 2011 minimum funding requirement would be approximately $98 million.
 
We also have a share repurchase program that has an available capacity of $700.4 million at December 31, 2009. While no repurchases were made in 2009 under the program, 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. The repurchase program does not have an expiration date and may be discontinued at any time.
 
Net cash provided by operating activities from continuing operations for 2009 decreased $356.3 million compared to the prior year primarily due to the decline in operating cash flows generated from our Australian mining operations on lower volumes and lower average pricing and the timing of cash flows from our working capital, primarily driven by foreign income tax payments related to prior year earnings.
 
The decrease in cash used in discontinued operations of $117.4 million was primarily due to approximately $59 million of cash received related to coal excise tax refunds in 2009 (see Note 2 to the consolidated financial statements for more information related to the excise tax refund) and lower current year payments related to Patriot discontinued operations.
 
Net cash used in investing activities from continuing operations decreased $11.1 million in 2009 compared to the prior year. The decrease primarily reflects lower federal coal lease expenditures of $54.9 million in 2009, partially offset by higher spending for our share of the Prairie State construction costs and additional investments in equity affiliates and joint venture projects in the prior year. Capital expenditures in 2009 were consistent with prior year as current year spending related to the development of our Bear Run Mine was offset by prior year spending related to the completion of our El Segundo Mine and expenditures for our blending and loadout facility at our North Antelope Rochelle Mine in the Western U.S.
 
Net cash used in financing activities decreased $384.7 million, primarily due to 2008 payments related to the repurchase of common stock ($199.8 million), the acquisition of noncontrolling interests relating to our Millennium Mine ($110.1 million) and payments on our revolving line of credit ($97.7 million). During 2009, we purchased $10.0 million face value of our 6.84% Series A bonds and $10.0 million face value of our 6.84% Series C bonds for a combined total of $19.0 million.


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Our total indebtedness as of December 31, 2009 and 2008 consisted of the following:
 
                 
    December 31,  
    2009     2008  
    (Dollars in millions)  
 
Term Loan under Senior Unsecured Credit Facility
  $ 490.3     $ 490.3  
Convertible Junior Subordinated Debentures due December 2066
    371.5       369.9  
7.375% Senior Notes due November 2016
    650.0       650.0  
6.875% Senior Notes due March 2013
    650.0       650.0  
7.875% Senior Notes due November 2026
    247.1       247.0  
5.875% Senior Notes due March 2016
    218.1       218.1  
6.84% Series C Bonds due December 2016
    33.0       43.0  
6.34% Series B Bonds due December 2014
    15.0       18.0  
6.84% Series A Bonds due December 2014
          10.0  
Capital lease obligations
    67.5       81.2  
Fair value hedge adjustment
    8.4       15.1  
Other
    1.4       1.0  
                 
Total
  $ 2,752.3     $ 2,793.6  
                 
 
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 Debentures as of December 31, 2009.
 
Senior Unsecured Credit Facility.  Our Senior Unsecured Credit Facility provides a $1.8 billion Revolving Credit Facility and a $950.0 million Term Loan Facility. The Revolving Credit Facility 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.
 
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 is based on a pricing grid tied to our leverage ratio, as defined in the Third Amended and Restated Credit Agreement. At December 31, 2009, the interest rate payable on the Revolving Credit Facility and the Term Loan Facility was LIBOR plus 0.75%, or a total of 1.0%.
 
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 Senior Unsecured Credit Facility matures on September 15, 2011.
 
As of December 31, 2009, we had no borrowings and $315.7 million letters of credit outstanding under our Revolving Credit Facility.
 
Other Long-Term Debt.  A description of our other debt instruments is described in Note 12 to the consolidated financial statements.
 
Third-party Security Ratings.  The ratings for our Senior Unsecured Credit Facility and our Senior Unsecured Notes are as follows: Moody’s has issued a Ba1 rating, Standard & Poor’s a BB+ rating, and Fitch has issued a BB+ rating. The ratings on the Debentures are as follows: Moody’s has issued a Ba3 rating, Standard & Poor’s a B+ rating, and Fitch has 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


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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 August 7, 2009, we filed an automatic shelf registration statement on Form S-3 as a well-known seasoned issuer with the SEC. The registration was for an indeterminate number of securities and is effective for three years, at which time we expect to be able to 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.
 
Capital Expenditures.  Capital expenditures for 2010 are anticipated to be between $600 million to $650 million. The planned expenditures include sustaining capital at our existing mines, completion of our Bear Run Mine in western Indiana, expansion of our metallurgical and thermal coal export platform in Australia to serve the growth markets in Asia and funding of our Prairie State investment.
 
Contractual Obligations
 
The following is a summary of our contractual obligations as of December 31, 2009:
 
                                         
    Payments Due By Year  
          Less than
    1 - 3
    3 - 5
    More than
 
    Total     1 Year     Years     Years     5 Years  
                (Dollars in millions)        
 
Long-term debt obligations (principal and interest)
  $ 5,219.5     $ 203.4     $ 884.8     $ 964.8     $ 3,166.5  
Capital lease obligations (principal and interest)
    80.3       15.1       30.2       35.0        
Operating lease obligations
    468.1       96.4       153.6       100.3       117.8  
Unconditional purchase obligations(1)
    70.4       70.4                    
Coal reserve lease and royalty obligations
    79.9       11.3       16.8       15.0       36.8  
Take or pay obligations(2)
    1,864.4       110.7       297.4       310.4       1,145.9  
Other long-term liabilities(3)
    1,485.5       151.0       300.3       292.6       741.6  
                                         
Total contractual cash obligations
  $ 9,268.1     $ 658.3     $ 1,683.1     $ 1,718.1     $ 5,208.6  
                                         
 
 
(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 capital purchases.
 
(2) Represents various long- and short-term take or pay arrangements associated with rail and port commitments for the delivery of coal, some of which extend to 2040, including amounts relating to export facilities currently under construction which are expected to be completed in 2010.
 
(3) 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, 2009, we had $70.4 million of purchase obligations for capital expenditures and $0.9 million of obligations related to federal coal reserve lease payments due over the next five years. The purchase obligations for capital expenditures primarily relate to the replacement and improvement of equipment and facilities at existing mines.
 
We do not expect any of the $113.2 million of gross unrecognized tax benefits reported in our consolidated financial statements to require cash settlement within the next year. Beyond that, we are unable to make reasonably reliable estimates of periodic cash settlements with respect to such unrecognized tax benefits.


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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 as bank letters of credit and performance or surety bonds and our accounts receivable securitization. Assets and 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 (such as self bonds) and letters of credit to secure our financial obligations for reclamation, workers’ compensation, and coal lease obligations as follows as of December 31, 2009:
 
                                         
                Workers’
             
    Reclamation
    Lease
    Compensation
             
    Obligations     Obligations     Obligations     Other(1)     Total  
    (Dollars in millions)  
 
Self bonding
  $ 821.9     $     $     $     $ 821.9  
Surety bonds
    772.3       116.3       8.7       57.3       954.6  
Letters of credit
    34.9             43.0       237.8       315.7  
                                         
    $ 1,629.1     $ 116.3     $ 51.7     $ 295.1     $ 2,092.2  
                                         
 
 
(1) Other includes the six letter of credit obligations described below and an additional $61.1 million in letters of credit and surety bonds related to collateral for surety companies, road maintenance, performance guarantees and other operations.
 
We own a 37.5% interest in Dominion Terminal Associates, a partnership that operates a coal export terminal in Newport News, Virginia under a 30-year lease that permits the partnership to purchase the terminal at the end of the lease term for a nominal amount. The partners have severally (but not jointly) agreed to make payments under various agreements which in the aggregate provide the partnership with sufficient funds to pay rents and to cover the principal and interest payments on the floating-rate industrial revenue bonds issued by the Peninsula Ports Authority, and which are supported by letters of credit from a commercial bank. As of December 31, 2009, our maximum reimbursement obligation to the commercial bank was in turn supported by four letters of credit totaling $42.7 million.
 
We are party to an agreement with the Pension Benefit Guarantee Corporation (PBGC) and TXU Europe Limited, an affiliate of our former parent corporation, under which we are required to make special 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 Employee Retirement Income Security Act of 1974, as amended. The PBGC, however, is required to first apply amounts received from a $110.0 million guarantee 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 U.S.) and continues under this process as of December 31, 2009. As a result of these proceedings, TXU Europe Limited may be liquidated or otherwise reorganized in such a way as to relieve it of its obligations under its guarantee.
 
At December 31, 2009, we have a $154.3 million letter of credit for collateral for bank guarantees issued with respect to certain reclamation and performance obligations related to some of our Australian mines.
 
Other Guarantees.  See the “Other Guarantees” section of Note 19 to our consolidated financial statements for a description of our other guarantees.
 
Accounts Receivable Securitization Program.  Under our accounts receivable securitization program in place at December 31, 2009, a pool of eligible trade receivables contributed to our wholly-owned, bankruptcy-remote subsidiary were sold, without recourse, to a multi-seller, asset-backed commercial paper conduit


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(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 $4.0 million for the year ended December 31, 2009 and $10.8 million for the year ended December 31, 2008. The securitization program was renewed in May 2009 and amended in December 2009, and extends to May 2012, while the letter of credit commitment that supports the commercial paper facility underlying the securitization program must be renewed annually. The securitization transactions have been recorded as sales, with receivables sold to the Conduit removed from our consolidated balance sheets. The amount of interest in accounts receivable sold to the Conduit was $254.6 million as of December 31, 2009 and $275.0 million as of December 31, 2008 (see Note 6 to our consolidated financial statements for additional information on our accounts receivable securitization program). On January 25, 2010, the receivables purchase agreement for the accounts receivable securitization program was amended and restated to add a second multi-seller asset-backed commercial paper conduit as a purchaser.
 
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 GAAP. GAAP requires 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 ongoing 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 long-term liabilities for our employees’ postretirement benefit costs and defined benefit pension plans. Detailed information related to these liabilities is included in Notes 14 and 15 to our consolidated financial statements. Liabilities for postretirement benefit costs and workers’ compensation obligations are not funded. Our pension obligations are funded in accordance with the provisions of applicable law. Expense for the year ended December 31, 2009 for the pension and postretirement liabilities totaled $76.8 million, while funding payments were $110.3 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. For our postretirement health care liability, assumed discount rates and health care cost trend rates have a significant effect on the expense and liability amounts reported for health care plans. 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 millions)
 
Effect on total service and interest cost components(1)
  $ 6.7     $ (5.7 )
Effect on total postretirement benefit obligation(1)
  $ 98.3     $ (84.6 )


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Discount rate:
 
                 
    One-Half
  One-Half
    Percentage-
  Percentage-
    Point Increase   Point Decrease
    (Dollars in millions)
 
Effect on total service and interest cost components(1)
  $ 0.6     $ (0.6 )
Effect on total postretirement benefit obligation(1)
  $ (46.1 )   $ 52.2  
 
 
(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 10.92 years at December 31, 2009.
 
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 applicable reclamation laws in the U.S. and Australia 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 and the timing of these cash flows, discounted using 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, 2009 was $40.1 million, and payments totaled $12.4 million. See Note 13 to our consolidated financial statements for additional details regarding our asset retirement obligations.
 
Income Taxes.  We account for income taxes in accordance with accounting guidance which requires deferred tax assets and liabilities be recognized using enacted tax rates for the effect of temporary differences between the book and tax bases of recorded assets and liabilities. The guidance 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.
 
Our liability for unrecognized tax benefits contains uncertainties because management is required to make assumptions and to apply judgment to estimate the exposures associated with our various filing positions. We recognize the tax benefit from an uncertain tax position only if it is “more likely than not” that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position must be measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. We believe that the judgments and estimates are reasonable; however, actual results could differ.
 
Level 3 Fair Value Measurements.  In accordance with the “Fair Value Measurements and Disclosures” topic of the Financial Accounting Standards Board Accounting Standards Codification, we evaluate the quality and reliability of the assumptions and data used to measure fair value in the three hierarchy Levels 1, 2 and 3 (see Note 3 to our consolidated financial statements for additional information). Commodity swaps and options and physical commodity purchase/sale contracts transacted in less liquid markets or contracts, such as long-term arrangements, with limited price availability were classified in Level 3. Indicators of less liquid markets are those with periods of low trade activity or when broker quotes reflect wide pricing spreads. Generally, these instruments or contracts are valued using internally generated models that include forward pricing curve quotes from one to three reputable brokers. Our valuation techniques also include basis


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adjustments for heat rate, sulfur and ash content, port and freight costs, and credit and nonperformance risk. We validate our valuation inputs with third-party information and settlement prices from other sources where available. We also consider credit and nonperformance risk in the fair value measurement by analyzing the counterparty’s exposure balance, credit rating and average default rate, net of any counterparty credit enhancements (e.g., collateral), as well as our own credit rating for financial derivative liabilities.
 
We have consistently applied these valuation techniques in all periods presented, and believe we have obtained the most accurate information reasonably available for the types of derivative contracts held. Valuation changes from period to period for each level will increase or decrease depending on: (i) the relative change in fair value for positions held, (ii) new positions added, (iii) realized amounts for completed trades, and (iv) transfers between levels. Our coal trading strategies utilize various swaps and derivative physical contracts. Periodic changes in fair value for purchase and sale positions, which are executed to lock in coal trading spreads, occur in each level and therefore the overall change in value of our coal-trading platform requires consideration of valuation changes across all levels.
 
At December 31, 2009, 5% of our net financial assets were categorized as Level 3. At December 31, 2008, the percentage of Level 3 net financial assets compared to the total net financial liabilities is not meaningful due to the overall liability position at December 31, 2008. See Note 3 to our consolidated financial statements for additional information regarding fair value measurements.
 
Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented
 
See Note 1 to our consolidated financial statements for a discussion of newly adopted accounting pronouncements and accounting pronouncements not yet implemented.
 
Item 7A.   Quantitative and Qualitative Disclosures About Market Risk
 
The potential for changes in the market value of our coal and freight trading, emission allowances, crude oil, diesel fuel, natural gas, explosives, interest rate and currency portfolios is referred to as “market risk.” Market risk related to our coal trading and freight portfolio is evaluated using a value at risk (VaR) analysis. VaR analysis is not used to evaluate our non-trading interest rate, diesel fuel, explosives or currency hedging portfolios. A description of each market risk category is set forth below. We attempt to manage market risks through diversification, controlling position sizes and executing hedging strategies. Due to lack of quoted market prices and the long-term, illiquid nature of the positions, we have not quantified market risk related to our non-trading, long-term coal supply agreement portfolio.
 
Coal Trading Activities and Related Commodity Price Risk
 
We engage in over-the-counter, direct and brokered trading of coal, ocean freight and fuel-related commodities to support our coal trading related activities (coal trading). These activities give rise to commodity price risk, which represents the potential loss that can be caused by an adverse change in the market value of a particular commitment. We actively measure, monitor and adjust traded position levels to remain within risk limits prescribed by management. For example, we have policies in place that limit the amount of total exposure, as measured by VaR, that we may assume at any point in time.
 
We account for coal trading using the fair value method, which requires us to reflect financial instruments with third parties at market value in our consolidated financial statements. Our trading portfolio included forwards, swaps and options as of December 31, 2009 and 2008.
 
We perform a VaR analysis on our coal trading portfolio, which includes bilaterally-settled and exchange-settled over-the-counter and brokerage coal trading. The use of VaR allows us to quantify in dollars, on a daily basis, a measure of price risk inherent in our trading portfolio. VaR represents the potential loss in value of our mark-to-market portfolio due to adverse market movements over a defined time horizon (liquidation period) within a specified confidence level. Our VaR model is based on a variance/co-variance approach. This captures our exposure related to forwards, swaps and options positions. Our VaR model assumes a 5 to 15-day holding period and a 95% one-tailed confidence interval. This means that there is a one in 20 statistical


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chance that the portfolio would lose more than the VaR estimates during the liquidation period. Our volatility calculation incorporates an exponentially weighted moving average algorithm based on the previous 60 market days, which makes our volatility more representative of recent market conditions, while still reflecting an awareness of historical price movements. VaR does not capture the loss expected in the 5% of the time the portfolio value exceeds measured VaR.
 
The use of VaR allows us to aggregate pricing risks across products in the portfolio, compare risk on a consistent basis and identify the drivers of risk. We use historical data to estimate price volatility as an input to VaR. Given our reliance on historical data, we believe VaR is reasonably effective in characterizing risk exposures in markets in which there are not sudden fundamental changes or shifts in market conditions. Due to the subjectivity in the choice of the liquidation period, reliance on historical data to calibrate the models and the inherent limitations in the VaR methodology, we perform regular stress and scenario analyses to estimate the impacts of market changes on the value of the portfolio. Additionally, back-testing is regularly performed to monitor the effectiveness of our VaR measure. The results of these analyses are used to supplement the VaR methodology and identify additional market-related risks. An inherent limitation of VaR is that past changes in market risk factors may not produce accurate predictions of future market risk.
 
During the year ended December 31, 2009, the actual low, high, and average VaR for our coal trading portfolio were $2.7 million, $15.9 million, and $8.7 million, respectively. Our VaR decreased over the prior year due to less price volatility and lower overall prices in the U.S. and international coal markets.
 
As of December 31, 2009, the timing of the estimated future realization of the value of our trading portfolio was as follows:
 
         
Year of
  Percentage of
 
Expiration
  Portfolio Total  
 
2010
    46 %
2011
    51 %
2012
    3 %
         
      100 %
         
 
We also monitor other types of risk associated with our coal trading activities, including credit, market liquidity and counterparty nonperformance.
 
Nonperformance and Credit Risk
 
The fair value of our assets and liabilities reflect adjustments for nonperformance and credit risk. Our concentration of nonperformance and credit risk is substantially with electric utilities, steel producers, energy producers and energy marketers. Our policy is to independently evaluate each customer’s creditworthiness prior to entering into transactions and to regularly monitor the credit extended. If we engage in a transaction with a counterparty that does not meet our credit standards, we seek to protect our position by requiring the counterparty to provide an appropriate credit enhancement. Also, when appropriate (as determined by our credit management function), we have taken steps to reduce our exposure to customers or counterparties whose credit has deteriorated and who may pose a higher risk of failure to perform under their contractual obligations. These steps include obtaining letters of credit or cash collateral, requiring prepayments for shipments or the creation of customer trust accounts held for our benefit to serve as collateral in the event of a failure to pay or perform. To reduce our credit exposure related to trading and brokerage activities, we seek to enter into netting agreements with counterparties that permit us to offset receivables and payables with such counterparties and, to the extent required, will post or receive margin amounts associated with exchange-cleared positions.
 
We conduct our various hedging activities related to foreign currency, interest rate, and fuel and explosives exposures with a variety of highly-rated commercial banks. In light of the recent turmoil in the financial markets, we continue to closely monitor counterparty creditworthiness.


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Foreign Currency Risk
 
We utilize currency forwards and options to hedge currency risk associated with anticipated Australian dollar expenditures. The accounting for these derivatives is discussed in Note 3 to our consolidated financial statements. Assuming we had no hedges in place, our exposure in operating costs and expenses due to a $0.05 change in the Australian dollar/U.S. dollar exchange rate is approximately $82 million for 2010. However, taking into consideration hedges currently in place, our net exposure to the same rate change is approximately $17 million for 2010. The chart at the end of Item 7A shows the notional amount of our hedge contracts as of December 31, 2009.
 
Interest Rate Risk
 
Our objectives in managing exposure to interest rate changes are to limit the impact of interest rate changes on earnings and cash flows and to lower overall borrowing costs. To achieve these objectives, we manage fixed-rate debt as a percent of net debt through the use of various hedging instruments, which are discussed in detail in Note 3 to our consolidated financial statements. As of December 31, 2009, after taking into consideration the effects of interest rate swaps, we had $2.4 billion of fixed-rate borrowings and $0.4 billion of variable-rate borrowings outstanding. A one percentage point increase in interest rates would result in an annualized increase to interest expense of approximately $4.2 million on our variable-rate borrowings. With respect to our fixed-rate borrowings, a one percentage point increase in interest rates would result in a decrease of approximately $130 million in the estimated fair value of these borrowings.
 
Other Non-trading Activities — Commodity Price Risk
 
Long-term Coal Contracts.  We manage our commodity price risk for our non-trading, long-term coal contract portfolio through the use of long-term coal supply agreements (those with terms longer than one year), rather than through the use of derivative instruments. We sold 93% and 90% of our worldwide sales volume under long-term coal supply agreements during 2009 and 2008, respectively. We are fully contracted for 2010 at planned production levels in the U.S. We had 11 to 12.5 million tons remaining to be priced for 2010 in Australia at January 26, 2010.
 
Diesel Fuel and Explosives Hedges.  We manage commodity price risk of the diesel fuel and explosives used in our mining activities through the use of fixed price contracts, cost-plus contracts and a combination of forward contracts with our suppliers and financial derivative contracts, which are primarily swap contracts with financial institutions.
 
Notional amounts outstanding under fuel-related, derivative swap contracts are noted in the chart at the end of Item 7A. We expect to consume 130 to 135 million gallons of diesel fuel in 2010. Assuming we had no hedges in place, a $10 per barrel change in the price of crude oil (the primary component of a refined diesel fuel product) would increase or decrease our annual diesel fuel costs by approximately $31 million based on our expected usage. However, taking into consideration hedges currently in place, our net exposure to changes in the price of crude oil is approximately $14 million.
 
Notional amounts outstanding under explosives-related swap contracts are noted in the chart at the end of Item 7A. We expect to consume 345,000 to 355,000 tons of explosives during 2010 in the U.S. Explosives costs in Australia are generally included in the fees paid to our contract miners. Assuming we had no hedges in place, a price change in natural gas (often a key component in the production of explosives) of one dollar per million MMBtu would result in an increase or decrease in our annual explosives costs of approximately $6 million based on our expected usage. However, taking into consideration hedges currently in place, our net exposure to changes in the price of natural gas is approximately $3 million.


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Notional Amounts and Fair Value.  The following summarizes our interest rate, foreign currency and commodity positions at December 31, 2009:
 
                                                         
    Notional Amount by Year of Maturity
                            2015 and
    Total   2010   2011   2012   2013   2014   thereafter
 
Interest Rate Swaps
                                                       
Fixed-to-floating (dollars in millions)
  $ 50.0     $     $     $     $ 50.0     $     $  
Floating-to-fixed (dollars in millions)
  $ 120.0     $     $ 120.0     $     $     $     $  
Foreign Currency
                                                       
A$:US$ hedge contracts (A$ millions)
  $ 3,291.7     $ 1,299.3     $ 994.8     $ 742.6     $ 120.0     $ 135.0     $  
Commodity Contracts
                                                       
Diesel fuel hedge contracts (million gallons)
    177.8       71.1       65.3       41.4                    
U.S. explosives hedge contracts (million MMBtu)
    3.0       3.0                                
 
                                   
    Account Classification by      
    Cash flow
  Fair value
  Economic
    Fair Value Asset
    hedge   hedge   hedge     (Liability)
                  (Dollars in millions)
Interest Rate Swaps
                                 
Fixed-to-floating (dollars in millions)
  $     $ 50.0     $       $ 1.5  
Floating-to-fixed (dollars in millions)
  $ 120.0     $     $       $ (9.8 )
Foreign Currency
                                 
A$:US$ hedge contracts (A$ millions)
  $ 3,291.7     $     $       $ 206.1  
Commodity Contracts
                                 
Diesel fuel hedge contracts (million gallons)
    177.8                   $ (22.2 )
U.S. explosives hedge contracts (million MMBtu)
    3.0                   $ (4.8 )
 
Item 8.   Financial Statements and Supplementary Data.
 
See Part IV, Item 15 of this report for information required by this Item, which information is incorporated by reference herein.
 
Item 9.   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
 
None.
 
Item 9A.   Controls and Procedures.
 
Evaluation of Disclosure Controls and Procedures
 
Our disclosure controls and procedures are designed to, among other things, provide reasonable assurance that material information, both financial and non-financial, and other information required under the securities laws to be disclosed is accumulated and communicated to senior management, including the principal executive officer and principal financial officer, on a timely basis. As of December 31, 2009, the end of the period covered by this Annual Report on Form 10-K, we carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer have evaluated our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of December 31,


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2009, and concluded that such controls and procedures are effective to provide reasonable assurance that the desired control objectives were achieved.
 
Changes in Internal Control Over Financial Reporting
 
We periodically review our internal control over financial reporting as part of our efforts to ensure compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002. In addition, we routinely review our system of internal control over financial reporting to identify potential changes to our processes and systems that may improve controls and increase efficiency, while ensuring that we maintain an effective internal control environment. Changes may include such activities as implementing new systems, consolidating the activities of acquired business units, migrating certain processes to our shared services organizations, formalizing and refining policies and procedures, improving segregation of duties and adding monitoring controls. In addition, when we acquire new businesses, we incorporate our controls and procedures into the acquired business as part of our integration activities. There have been no changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2009 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
 
Management’s Report on Internal Control Over Financial Reporting
 
Management is responsible for maintaining and establishing adequate internal control over financial reporting. Our internal control framework and processes were designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external purposes in accordance with U.S. generally accepted accounting principles.
 
Because of inherent limitations, any system of internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
Management conducted an assessment of the effectiveness of our internal control over financial reporting using the criteria set by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Based on this assessment, management concluded that the Company’s internal control over financial reporting were effective to provide reasonable assurance that the desired control objectives were achieved as of December 31, 2009.
 
Our Independent Registered Public Accounting Firm, Ernst & Young LLP, has audited our internal control over financial reporting, as stated in their unqualified opinion report included herein.
 
         
     
/s/  Gregory H. Boyce

Gregory H. Boyce
Chairman and Chief Executive Officer
 
/s/  Michael C. Crews

Michael C. Crews
Executive Vice President and
Chief Financial Officer
 
February 24, 2010


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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
The Board of Directors and Stockholders
Peabody Energy Corporation
 
We have audited Peabody Energy Corporation’s (the Company’s) internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control — Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Peabody Energy Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
 
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
 
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
 
In our opinion, Peabody Energy Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on the COSO criteria.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Peabody Energy Corporation as of December 31, 2009 and 2008, 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, 2009, and our report dated February 24, 2010, expressed an unqualified opinion thereon.
 
/s/  Ernst & Young LLP
 
St. Louis, Missouri
February 24, 2010


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Item 9B.   Other Information.
 
None.
 
PART III
 
Item 10.   Directors, Executive Officers and Corporate Governance.
 
The information required by Item 401 of Regulation S-K is included under the caption “Election of Directors-Director Qualifications” in our 2010 Proxy Statement and in Part I of this report under the caption “Executive Officers of the Company.” The information required by Items 405, 406 and 407(c)(3), (d)(4) and (d)(5) of Regulation S-K is included under the captions “Ownership of Company Securities — Section 16(a) Beneficial Ownership Reporting Compliance,” “Corporate Governance Matters” and “Information Regarding Board of Directors and Committees-Committees of the Board of Directors-Audit Committee “ in our 2010 Proxy Statement. Such information is incorporated herein by reference.
 
Item 11.   Executive Compensation.
 
The information required by Items 402 and 407 (e)(4) and (e)(5) of Regulation S-K is included under the captions “Executive Compensation,” “Compensation Committee Interlocks and Insider Participation” and “Report of the Compensation Committee” in our 2010 Proxy Statement and is incorporated herein by reference.
 
Item 12.   Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
 
The information required by Items 403 of Regulation S-K is included under the caption “Ownership of Company Securities” in our 2010 Proxy Statement and is incorporated herein by reference.
 
Equity Compensation Plan Information
 
As required by Item 201(d) of regulation S-K, the following table provides information regarding our equity compensation plans as of December 31, 2009:
 
                         
                Number of Securities
 
                Remaining Available
 
                for Future Issuance
 
    (a)
          Under Equity
 
    Number of Securities
          Compensation Plans
 
    to be Issued
    Weighted-Average
    (Excluding
 
    upon Exercise of
    Exercise Price of
    Securities
 
    Outstanding Options,
    Outstanding Options,
    Reflected in Column
 
Plan Category
  Warrants and Rights     Warrants and Rights     (a))  
 
Equity compensation plans approved
                       
by security holders
    1,715,557     $ 20.78       14,588,584  
Equity compensation plans not approved
                       
by security holders
                 
                         
Total
    1,715,557     $ 20.78       14,588,584  
                         
 
Item 13.   Certain Relationships and Related Transactions, and Director Independence.
 
The information required by Items 404 and 407(a) of Regulation S-K is included under the captions “Policy for Approval of Related Person Transactions” and “Information Regarding Board of Directors and Committees-Director Independence” in our 2010 Proxy Statement and is incorporated herein by reference.


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Item 14.   Principal Accounting Fees and Services.
 
The information required by Item 9(e) of Schedule 14A is included under the caption “Fees Paid to Independent Registered Public Accounting Firm” in our 2010 Proxy Statement and is incorporated herein by reference.
 
PART IV
 
Item 15.   Exhibit, 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
 
    F-1  
    F-2  
    F-3  
    F-4  
    F-5  
    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  
 
    F-70  
    F-71  
 
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.
 
Pursuant to the Instructions to Exhibits, certain instruments defining the rights of holders of long-term debt securities of the Company and its consolidated subsidiaries are not filed because the total amount of securities authorized under any such instrument does not exceed 10 percent of the total assets of the Company and its subsidiaries on a consolidated basis. A copy of such instrument will be furnished to the Securities and Exchange Commission upon request.


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SIGNATURES
 
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/  GREGORY H. BOYCE
Gregory H. Boyce
Chairman and Chief Executive Officer
 
Date: February 24, 2010
 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons, on behalf of the registrant and in the capacities and on the dates indicated.
 
             
Signature
 
Title
 
Date
 
         
/s/  GREGORY H. BOYCE

Gregory H. Boyce
  Chairman and Chief Executive Officer,
Director (principal executive officer)
  February 24, 2010
         
/s/  MICHAEL C. CREWS

Michael C. Crews
  Executive Vice President and Chief
Financial Officer (principal financial and accounting officer)
  February 24, 2010
         
/s/  WILLIAM A. COLEY

William A. Coley
  Director   February 24, 2010
         
/s/  WILLIAM E. JAMES

William E. James
  Director   February 24, 2010
         
/s/  ROBERT B. KARN III

Robert B. Karn III
  Director   February 24, 2010
         
/s/  M. FRANCES KEETH

M. Frances Keeth
  Director   February 24, 2010
         
/s/  HENRY E. LENTZ

Henry E. Lentz
  Director   February 24, 2010
         
/s/  ROBERT A. MALONE

Robert A. Malone
  Director   February 24, 2010
         
/s/  WILLIAM C. RUSNACK

William C. Rusnack
  Director   February 24, 2010


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Signature
 
Title
 
Date
 
         
/s/  JOHN F. TURNER

John F. Turner
  Director   February 24, 2010
         
/s/  SANDRA VAN TREASE

Sandra Van Trease
  Director   February 24, 2010
         
/s/  ALAN H. WASHKOWITZ

Alan H. Washkowitz
  Director   February 24, 2010


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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 (the Company) as of December 31, 2009 and 2008, 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, 2009. 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, 2009 and 2008, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.
 
As discussed in Note 1 to the consolidated financial statements, on January 1, 2009, the Company changed its method for accounting for noncontrolling interests, its method for accounting for convertible debt that may be settled in cash upon conversion, and its method for accounting for earnings per share under the two-class method, and on January 1, 2008, the Company changed its method of accounting for the recognition of derivative positions with the same counterparty.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Peabody Energy Corporation’s internal control over financial reporting as of December 31, 2009, 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 24, 2010, expressed an unqualified opinion thereon.
 
/s/  Ernst & Young LLP
 
St. Louis, Missouri
February 24, 2010


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PEABODY ENERGY CORPORATION
 
CONSOLIDATED STATEMENTS OF OPERATIONS
 
                         
    Year Ended December 31,  
    2009     2008     2007  
    (Dollars in millions, except per share data)  
 
Revenues
                       
Sales
  $ 5,468.1     $ 6,004.0     $ 4,313.9  
Other revenues
    544.3       557.0       209.9  
                         
Total revenues
    6,012.4       6,561.0       4,523.8  
Costs and expenses
                       
Operating costs and expenses
    4,467.7       4,585.2       3,510.1  
Depreciation, depletion and amortization
    405.2       402.4       346.3  
Asset retirement obligation expense
    40.1       48.2       23.7  
Selling and administrative expenses
    208.7       201.8       147.1  
Other operating (income) loss:
                       
Net gain on disposal or exchange of assets
    (23.2 )     (72.9 )     (88.6 )
(Income) loss from equity affiliates
    69.1             (14.5 )
                         
Operating profit
    844.8       1,396.3       599.7  
Interest expense
    201.2       227.0       235.8  
Interest income
    (8.1 )     (10.0 )     (7.0 )
                         
Income from continuing operations before income taxes
    651.7       1,179.3       370.9  
Income tax provision (benefit)
    193.8       191.4       (70.7 )
                         
Income from continuing operations, net of income taxes
    457.9       987.9       441.6  
Income (loss) from discontinued operations, net of income taxes
    5.1       (28.8 )     (180.1 )
                         
Net income
    463.0       959.1       261.5  
Less: Net income (loss) attributable to noncontrolling interests
    14.8       6.2       (2.3 )
                         
Net income attributable to common stockholders
  $ 448.2     $ 952.9     $ 263.8  
                         
Income From Continuing Operations
                       
Basic earnings per share
  $ 1.66     $ 3.63     $ 1.67  
                         
Diluted earnings per share
  $ 1.64     $ 3.60     $ 1.64  
                         
Net Income Attributable to Common Stockholders
                       
Basic earnings per share
  $ 1.68     $ 3.52     $ 0.99  
                         
Diluted earnings per share
  $ 1.66     $ 3.50     $ 0.97  
                         
Dividends declared per share
  $ 0.25     $ 0.24     $ 0.24  
                         
 
See accompanying notes to consolidated financial statements


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PEABODY ENERGY CORPORATION
 
CONSOLIDATED BALANCE SHEETS
 
                 
    December 31, 2009     December 31, 2008  
    (Amounts in millions, except share and per share data)  
 
ASSETS
Current assets
               
Cash and cash equivalents
  $ 988.8     $ 449.7  
Accounts receivable, net of allowance for doubtful accounts of $18.3 at December 31, 2009 and $24.8 at December 31, 2008
    303.0       382.2  
Inventories
    325.1       276.2  
Assets from coal trading activities, net
    276.8       662.8  
Deferred income taxes
    40.0       1.7  
Other current assets
    255.3       198.7  
                 
Total current assets
    2,189.0       1,971.3  
Property, plant, equipment and mine development
Land and coal interests
    7,557.3       7,349.4  
Buildings and improvements
    908.0       858.1  
Machinery and equipment
    1,391.2       1,245.1  
Less: accumulated depreciation, depletion and amortization
    (2,595.0 )     (2,155.3 )
                 
Property, plant, equipment and mine development, net
    7,261.5       7,297.3  
Investments and other assets
    504.8       427.0  
                 
Total assets
  $ 9,955.3     $ 9,695.6  
                 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
               
Current maturities of long-term debt
  $ 14.1     $ 17.0  
Liabilities from coal trading activities, net
    110.6       304.2  
Accounts payable and accrued expenses
    1,187.7       1,535.0  
                 
Total current liabilities
    1,312.4       1,856.2  
Long-term debt, less current maturities
    2,738.2       2,776.6  
Deferred income taxes
    299.1       20.8  
Asset retirement obligations
    452.1       418.7  
Accrued postretirement benefit costs
    914.1       766.1  
Other noncurrent liabilities
    483.5       737.7  
                 
Total liabilities
    6,199.4       6,576.1  
Stockholders’ equity
               
Preferred Stock — $0.01 per share par value; 10,000,000 shares authorized, no shares issued or outstanding as of December 31, 2009 or December 31, 2008
           
Series A Junior Participating Preferred Stock — 1,500,000 shares authorized, no shares issued or outstanding as of December 31, 2009 or December 31, 2008
           
Perpetual Preferred Stock — 750,000 shares authorized, no shares issued or outstanding as of December 31, 2009 or December 31, 2008
           
Series Common Stock — $0.01 per share par value; 40,000,000 shares authorized, no shares issued or outstanding as of December 31, 2009 or December 31, 2008
           
Common Stock — $0.01 per share par value; 800,000,000 shares authorized, 276,848,279 shares issued and 268,203,815 shares outstanding as of December 31, 2009 and 275,211,240 shares issued and 266,644,979 shares outstanding as of December 31, 2008
    2.8       2.8  
Additional paid-in capital
    2,067.7       2,020.2  
Retained earnings
    2,183.8       1,802.4  
Accumulated other comprehensive loss
    (183.5 )     (388.5 )
Treasury shares, at cost: 8,644,464 shares as of December 31, 2009 and 8,566,261 shares as of December 31, 2008
    (321.1 )     (318.8 )