UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Form 10-K

 

 

Commission File Number 1-16463

 

 

 

Peabody Energy Corporation

(Exact name of registrant as specified in its charter)

 

(314) 342-3400

Registrant’s telephone number, including area code

 

Securities Registered Pursuant to Section 12(b) of the Act:

 

 

Securities Registered Pursuant to Section 12(g) of the Act:
None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes þ     No o

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes o     No þ

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.  Yes þ     No o

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o

 

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):

 

(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, 2008: Common Stock, par value $0.01 per share, $23.9 billion.

 

Number of shares outstanding of each of the Registrant’s classes of Common Stock, as of February 13, 2009: Common Stock, par value $0.01 per share, 267,362,965 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 2009 Annual Meeting of Stockholders (the Company’s 2009 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.

 

 

CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS

 

This report includes statements of our expectations, intentions, plans and beliefs that constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 and are intended to come within the safe harbor protection provided by those sections. These statements relate to future events or our future financial performance, including, without limitation, the section captioned “Outlook.” We use words such as “anticipate,” “believe,” “expect,” “may,” “project,” “should,” “estimate,” or “plan” or other similar words to identify forward-looking statements.

 

Without limiting the foregoing, all statements relating to our future outlook, anticipated capital expenditures, future cash flows and borrowings, and sources of funding are forward-looking statements 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:

 

 

 

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.

 

TABLE OF CONTENTS

 

 

 

Overview

 

We are the largest private-sector coal company in the world. During the year ended December 31, 2008, we sold 255.5 million tons of coal including 224.3 million tons from our United States (U.S.) and Australian mining operations and 31.2 million tons through our brokerage activities. During this period, we sold coal to 329 electricity generating and industrial plants in 21 countries. Our coal products fuel 10% of all U.S. electricity generation and 2% of worldwide electricity generation. At December 31, 2008, we had 9.2 billion tons of proven and probable coal reserves.

 

We own majority interests in 30 coal mining operations located in the U.S. and Australia. Additionally, we own a minority interest in one Venezuelan operating mine through a joint venture arrangement. We shipped 200.4 million tons from our 20 U.S. mining operations and 23.9 million tons from our 10 Australia operations in 2008. We shipped 85% of our U.S. mining operations’ coal sales volume from the western U.S. during the year ended December 31, 2008, and the remaining 15% from the midwestern U.S. In the western U.S., we own and operate mines in Arizona, Colorado, New Mexico and Wyoming. Over the last five years, our overall western U.S. coal production has increased from 129.6 million tons in 2003 to 169.9 million tons in 2008, a compound annual growth rate of 5.6%. Most of our production in the western U.S. is low-sulfur coal from the Powder River Basin. In the midwestern U.S., we own and operate mines in Illinois and Indiana. We also own 10 mines in Australia, five in Queensland and five in New South Wales. Our Australian production includes both low-sulfur domestic and export thermal (steam) and metallurgical coal products. The export thermal and metallurgical coal is predominantly shipped to customers in the Asia-Pacific region. For the year ended December 31, 2008, 90% of our global production was from non-union mines.

 

For the year ended December 31, 2008, 82% of our total sales (by volume) were to U.S. electricity generators, 16% were to customers outside the U.S. and 2% were to the U.S. industrial sector. Approximately 90% of our worldwide coal sales during 2008 were under long-term (one year or greater) contracts. Our sales backlog, including backlog subject to price reopener and/or extension provisions, was over one billion tons as of December 31, 2008, representing nearly five years of current production. Contracts in backlog have remaining terms ranging from one to 17 years. We are targeting 2009 production of 190 to 195 million tons in the U.S. and 22 to 24 million tons in Australia, including 6 to 7 million tons of metallurgical coal. As of January 27, 2009, our 2009 production is largely sold out in the U.S. with 4 to 5 million tons of Australian metallurgical coal and 5 to 6 million tons of Australian steam coal available to price.

 

Our mining operations consist of three principal operating segments: Western U.S. Mining, Midwestern U.S. Mining, and Australian Mining. In addition to our mining operations, we market, broker and trade coal through our Trading and Brokerage Operations segment. Our total tons traded were 192.9 million for the year ended December 31, 2008. Our international trading group has locations in London, England; Newcastle, Australia; and Beijing, China. Our China office also engages in sales, marketing and business development to pursue potential long-term growth opportunities there. Our other energy-related commercial activities include expansion of our Australian export capability with a 17.7% sponsorship of the Newcastle Infrastructure Group terminal currently under construction, 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 sequestration initiatives in the U.S., China and Australia.

For financial information regarding each of our operating segments, see Note 22 to our consolidated financial statements.

 

Discontinued Operations

 

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.

 

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. The results of operations relating to these items are classified as discontinued operations for all periods presented.

 

History

 

Peabody, Daniels and Co. was founded in 1883 as a retail coal supplier, entering the mining business in 1888 as Peabody & Co. with the opening of our first coal mine in Illinois. In 1926, Peabody Coal Company was listed on the Chicago Stock Exchange and, beginning in 1949, on the New York Stock Exchange.

 

In 1955, Peabody Coal Company, primarily an underground mine operator, merged with Sinclair Coal Company, a major surface mining company. Peabody Coal Company was acquired by Kennecott Copper Company in 1968. The company was then sold to Peabody Holding Company in 1977, which was formed by a consortium of companies.

 

During the 1980s, Peabody grew through expansion and acquisition, opening the North Antelope Mine in Wyoming’s coal-rich Powder River Basin in 1983 and the Rochelle Mine in 1985.

 

In July 1990, Hanson PLC acquired Peabody Holding Company. In the 1990s, Peabody continued to grow through expansion and acquisitions. In February 1997, Hanson spun off its energy-related businesses, including Eastern Group and Peabody Holding Company, into The Energy Group PLC. The Energy Group was a publicly traded company in the United Kingdom and its American Depository Receipts (ADRs) were publicly traded on the New York Stock Exchange.

 

In May 1998, Lehman Brothers Merchant Banking Partners II L.P. and affiliates (Merchant Banking Fund), an affiliate of Lehman Brothers Inc. (Lehman Brothers), purchased Peabody Holding Company and its affiliates, Peabody Resources Limited and Citizens Power LLC in a leveraged buyout transaction that coincided with the purchase by Texas Utilities of the remainder of The Energy Group. In August 2000, Citizens Power, our subsidiary that marketed and traded electric power and energy-related commodity risk management products, was sold to Edison Mission Energy and in January 2001, we sold our Peabody Resources Limited (in Australia) operations to Coal & Allied, a subsidiary of Rio Tinto Limited.

 

In April 2001, we changed our name to Peabody Energy Corporation, reflecting our position as a premier energy supplier. In May 2001, we completed an initial public offering of common stock, and our shares began trading on the New York Stock Exchange under the ticker symbol “BTU,” the globally recognized symbol for energy.

 

In April 2004, we acquired coal operations from RAG Coal International AG, expanding our presence in both Australia and Colorado. In December 2004, we completed the purchase of a 25.5% equity interest in Carbones del Guasare from RAG Coal International, S.A. Carbones del Guasare, a joint venture with Anglo American plc and a Venezuelan governmental partner, operates Venezuela’s largest coal mine, the Paso Diablo Mine in northwestern Venezuela. In October 2006, we expanded our presence in Australia with the acquisition of Excel Coal Limited (Excel), an independent coal company in Australia. The Excel acquisition included operating and development-stage mines, along with proven and probable coal reserves of up to 500 million tons.

In October 2007, we spun off portions of our formerly Eastern U.S. Mining operations business segment to form Patriot, as discussed above.

 

In 2008, we began shipping coal from our new El Segundo Mine in New Mexico, which is expected to produce 6 million tons of coal annually. We purchased the remaining 15.4% share of the Millennium Mine in Queensland, Australia from the former minority shareholders for $110.1 million. In early 2009, we obtained an option to purchase up to a 50% interest in a joint venture holding Polo Resources Limited’s (AIM: PRL) coal and mineral interests in Mongolia as well as warrants to enable us to acquire an approximate 15% equity interest in Polo Resources Limited. Mongolia is known for its metallurgical and thermal coal resources.

 

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, acquisitions, divestitures and strategic operational restructuring. We have four core strategies to achieve growth:

 

 

Mining Operations

 

We conduct our mining business through three principal mining operating segments: Western U.S. Mining, Midwestern U.S. Mining, and Australian Mining. 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 steam coal, sold primarily to electric utilities. Internationally, we operate metallurgical and thermal coal mines in Queensland and New South Wales, Australia and have a 25.5% investment in a Venezuelan mine. All of our operating segments are discussed in Note 22 to our consolidated financial statements.

The following describes the operating characteristics of the principal mines and reserves of each of our business units and affiliates. The maps below show mine locations as of December 31, 2008. All of our mining operations are owned and managed by our subsidiaries. The subsidiary that manages a particular mining operation is not necessarily the same as the subsidiary or subsidiaries which own the assets utilized in that mining operation. Unless otherwise indicated, we own 100% of the subsidiary that manages the respective mining operations or owns the related assets.

 

U.S. Mining Operations

 

 

Powder River Basin Operations

 

We control approximately 3.2 billion tons of proven and probable coal reserves in the Powder River Basin, the largest and fastest growing major U.S. coal-producing region. We manage three low-sulfur, non-union surface mining complexes in Wyoming that sold 147.1 million tons of coal during the year ended December 31, 2008, or approximately 58% of our total coal sales volume.

 

Our Wyoming Powder River Basin reserves are classified as surface mineable, subbituminous coal with seam thickness varying from 60 to 115 feet. The sulfur content of the coal in current production ranges from 0.2% to 0.4% and the heat value ranges from 8,100 to 8,800 Btu’s per pound.

 

North Antelope Rochelle Mine

 

The North Antelope Rochelle Mine is located 65 miles south of Gillette, Wyoming. This coal mine is the largest in the world, selling 97.5 million tons of compliance coal (defined as having sulfur dioxide content of 1.2 pounds or less per million Btu) during 2008. The North Antelope Rochelle Mine produces premium quality coal with a sulfur content averaging 0.2% and a heat value ranging from 8,600 to 8,800 Btu per pound. The North Antelope Rochelle Mine traditionally produces the lowest sulfur coal in the U.S., using three draglines along with five overburden truck-and-shovel fleets and is serviced by both major western railroads, the Burlington Northern Santa Fe (BNSF) Railway and the Union Pacific Railroad. In 2008, we completed new blending and loading facilities that are designed to result in a lower cost structure while also increasing capacity.

Caballo Mine

 

The Caballo Mine is located 20 miles south of Gillette, Wyoming. During 2008, it sold 31.2 million tons of compliance coal. Caballo is a cast/dozer/truck-and-shovel assist operation with a coal handling system that includes two 12,000-ton silos and two 11,000-ton silos and is serviced by both major western railroads, the BNSF Railway and the Union Pacific Railroad. The Caballo Mine produces compliance coal with a sulfur content averaging 0.34% and a heat value averaging 8,100 Btu per pound.

 

Rawhide Mine

 

The Rawhide Mine is located 10 miles north of Gillette, Wyoming. During 2008, it sold 18.4 million tons of compliance coal. Rawhide is a cast/dozer-push/truck-and-shovel assist operation with a coal handling system that includes two 12,000-ton silos and four 11,000-ton silos and is serviced by the BNSF Railway. The Rawhide Mine produces compliance coal with a sulfur content averaging 0.36% and a heat value averaging 8,300 Btu per pound.

 

Southwest Operations

 

We own four coal mines in our Southwest operations, two in Arizona and two in New Mexico. Kayenta, in Arizona, and Lee Ranch and El Segundo in New Mexico, are all in operation, while the Black Mesa Mine in Arizona suspended operations as of December 31, 2005. We control 1.0 billion tons of proven and probable coal reserves in our Southwest operations.

 

Kayenta Mine

 

The Kayenta Mine, located on the Navajo Nation and Hopi Tribe lands in Arizona, uses four draglines in three mining areas. It sold approximately 8.0 million tons of coal during 2008 and supplies primarily bituminous compliance coal under a long-term coal supply agreement to an electricity generating station in the region. The coal is crushed, then carried 17 miles by conveyor belt to storage silos where it is loaded onto a private rail line and transported 83 miles to the Navajo Generating Station, operated by the Salt River Project near Page, Arizona. The mine and railroad were designed to deliver coal exclusively to the power plant, which has no other source of coal. The Navajo coal supply agreement extends until 2011. Hourly workers at this mine are members of the United Mine Workers of America (UMWA) under a contract that extends through 2013.

 

Lee Ranch Mine

 

The Lee Ranch Mine, located near Grants, New Mexico, sold approximately 3.4 million tons of subbituminous medium sulfur coal during 2008. Lee Ranch shipped the majority of its coal to two customers in New Mexico and Arizona under coal supply agreements extending until 2014 and 2020, respectively. Lee Ranch is a non-union surface mine that uses a combination of dragline and truck-and-shovel mining techniques and ships coal to its customers via the BNSF Railway.

 

El Segundo Mine

 

The El Segundo Mine, located near Grants, New Mexico, started producing subbituminous medium sulfur coal in mid-2008 and sold approximately 2.6 million tons in 2008. El Segundo is a non-union surface mine that uses truck-and-shovel mining techniques and ships coal to its customers via the BNSF Railway.

 

Colorado Operations

 

We control approximately 0.2 billion tons of proven and probable coal reserves and have one operating mine in the Colorado Region.

Twentymile Mine

 

The Twentymile Mine is located in Routt County, Colorado and sold 8.6 million tons of compliance, low-sulfur, steam coal to customers throughout the U.S. during 2008. Our Twentymile Mine is a non-union longwall operation and is one of the largest underground mines in the U.S. Approximately 75% of all coal shipped is loaded on the Union Pacific railroad; the remainder is hauled by truck to the nearby Hayden Generating Station, operated by the Public Service of Colorado, under a coal supply agreement that extends until 2011.

 

Midwest Operations

 

Our Midwest operations consist of 13 mines in Illinois and Indiana. We control approximately 3.7 billion tons of proven and probable coal reserves in the Midwest. In 2008, these operations collectively sold 30.7 million tons of coal (including purchased coal), more than any other Illinois Basin coal producer (which covers portions of Illinois, Indiana and Kentucky). We ship coal from these mines primarily to electricity generators in the Midwest and to industrial customers for power generation.

 

Gateway Mine

 

The Gateway Mine is a non-union underground mine located in Randolph County, Illinois. During 2008, the Gateway Mine sold 3.2 million tons of steam coal. Coal from the Gateway Mine is shipped by rail direct to customers’ plants, by rail and barge for customers located on the Ohio and Mississippi rivers, and by truck to certain industrial customers.

 

Air Quality Mine

 

The Air Quality Mine is an underground mine located near Monroe City, Indiana that sold 1.9 million tons of compliance coal in 2008. The Air Quality Mine has a non-union workforce. Coal is shipped from the Air Quality Mine by truck, by truck and rail, and by truck and barge.

 

Farmersburg Mine

 

The Farmersburg Mine is a surface mine located in Vigo and Sullivan counties in Indiana that sold 3.3 million tons of medium sulfur coal in 2008. The Farmersburg Mine has a non-union workforce. Coal is shipped from the Farmersburg Mine by rail and by truck to customers’ plants.

 

Francisco Mine Complex

 

The Francisco Mine Complex, which has both an underground and surface mine, is located in Gibson County, Indiana and sold 3.4 million tons of medium sulfur coal in 2008. The Francisco Mine Complex has a non-union workforce and ships coal by rail to utility customers’ plants.

 

Somerville Mine Complex

 

The Somerville Mine Complex consists of three surface mines located in Gibson County, Indiana. These mines collectively sold 7.9 million tons of medium sulfur coal in 2008. The Somerville Mine Complex has a non-union workforce and ships coal by rail, truck and rail, and truck and barge.

 

Viking Mine

 

The Viking Mine is a surface mine located in Indiana that sold 1.6 million tons of medium sulfur coal in 2008. The Viking Mine has a non-union workforce and ships coal by truck and rail to customers’ plants.

Miller Creek Mine

 

The Miller Creek Mine is a surface mine located in Indiana that sold 1.8 million tons of medium sulfur coal in 2008. The Miller Creek Mine has a non-union workforce and ships coal by truck and by truck and rail to customers’ plants.

 

Wildcat Hills Mine Complex

 

The Wildcat Hills Mine Complex, which has both an underground and surface mine, is located in Gallatin and Saline counties in southern Illinois. During 2008, these mines sold 3.0 million tons of medium sulfur coal that is primarily shipped by barge to downriver utility plants. The Wildcat Hills Mine Complex has a non-union workforce.

 

Willow Lake Mine

 

The Willow Lake Mine is an underground mine in southern Illinois. During 2008, the mine sold 3.7 million tons of medium sulfur coal that is primarily shipped by barge to downriver utility plants. The hourly workforce at the Willow Lake Mine is represented under an International Brotherhood of Boilermakers labor agreement, which will expire April 15, 2011.

 

Australian Mining Operations

 

 

We manage five mines in Queensland, Australia, and five mines in New South Wales, Australia. During 2008, our Australian operations sold 23.9 million tons of coal, 8.3 millions tons of which were metallurgical coal. Coal from the Queensland mines is shipped via rail and truck to the Dalrymple Bay Coal Terminal and the Port of Brisbane, where the coal is loaded onto ocean-going vessels. Coal from the New South Wales mines is shipped via rail and truck to domestic customers and to the Ports of Newcastle and Kembla. Most of the sales from our Australian mines are denominated in U.S. dollars. Our Australian mines operate with site-specific collective bargaining labor agreements. Our Australian operations control 1.1 billion tons of proven and probable coal reserves.

Wilkie Creek Mine

 

The Wilkie Creek Mine, located in Queensland, Australia, is a surface, truck-and-shovel operation. In 2008, the Wilkie Creek Mine sold 2.5 million tons of thermal coal, all of which was sold to the Asian export market through the Port of Brisbane.

 

Burton Mine

 

The Burton Mine, located in Queensland, Australia, is a surface mine using the truck-and-shovel terrace mining technique. We own 95% of the Burton operation and the remaining 5% interest is owned by the contract miner that operates on reserves we control. During 2008, we sold 2.6 million tons of metallurgical coal and 0.1 million tons of thermal coal from the Burton Mine through the Dalrymple Bay Coal Terminal.

 

Millennium Mine

 

The Millennium Mine, located in Queensland, Australia, began operations in 2007 and is a surface operation utilizing truck-and-shovel mining methods. We manage this mine utilizing a contract miner. In 2008, we purchased the remaining 15.4% share of the Millennium Mine from the former minority shareholders. During 2008, the Millennium Mine sold 1.3 million tons of metallurgical coal through the Dalrymple Bay Coal Terminal.

 

North Goonyella Mine

 

The North Goonyella Mine, located in Queensland, Australia is a longwall underground operation that produces metallurgical coal. During 2008, the North Goonyella Mine sold 1.8 million tons of metallurgical coal through the Dalrymple Bay Coal Terminal.

 

Eaglefield Mine

 

The Eaglefield Mine, located in Queensland, Australia, is a surface operation utilizing truck-and-shovel mining methods. It is adjacent to, and fulfills contract tonnages in conjunction with, the North Goonyella underground mine. Coal is mined by a contractor from reserves that we control. During 2008, the Eaglefield Mine sold 1.2 million tons of metallurgical coal through the Dalrymple Bay Coal Terminal.

 

Wambo Open-Cut Mine

 

The Wambo Open-Cut Mine, located in New South Wales, Australia, is a surface operation utilizing truck-and-shovel mining methods. During 2008, the Wambo Open-Cut Mine sold 3.0 million tons of thermal coal. The coal from this mine was shipped through the Port of Newcastle. We have a 100% interest in the Wambo Open-Cut Mine, but only retain 75% of profits as part of a profit sharing interest with the non-voting minority owner. The mine’s operations are managed utilizing a contract miner.

 

North Wambo Underground Mine

 

The North Wambo Underground Mine, located in New South Wales, Australia, is a longwall underground mine which was commissioned in 2007. During 2008, the North Wambo Underground Mine sold 2.2 million tons of thermal coal. The coal from this mine was shipped through the Port of Newcastle. We have a 100% interest in the Wambo Underground Mine, but only retain 75% of profits as part of a profit sharing interest with the non-voting minority owner.

 

Metropolitan Mine

 

The Metropolitan Mine, located in New South Wales, Australia, is a longwall underground operation. In 2008, the Metropolitan Mine sold 1.4 million tons of metallurgical coal. Coal shipments from this mine are to export customers through Port Kembla and to an Australian customer.

Wilpinjong Mine

 

The Wilpinjong Mine, located in New South Wales, Australia, is a surface mine that was commissioned in 2006. The mine produces thermal coal for export customers through the Port of Newcastle in addition to serving an Australian electricity generator. Coal is mined by a contractor from reserves that we control. During 2008, the Wilpinjong Mine sold 7.3 million tons of thermal coal.

 

Chain Valley Mine

 

The Chain Valley Mine located in New South Wales, Australia, is a room and pillar underground operation. The Chain Valley Mine produces thermal coal which is sold locally to power authorities and to export customers through the Port of Newcastle. During 2008, the Chain Valley Mine sold 0.5 million tons of thermal coal for the year. We own 80% of the Chain Valley Mine.

 

Venezuelan Mining Operation

 

Paso Diablo Mine

 

We own a 25.5% 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 in Venezuela. The Paso Diablo Mine is a surface operation in northwestern Venezuela that produced approximately 4.8 million tons of steam coal in 2008 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.

 

Export Facilities

 

We own a 37.5% interest in Dominion Terminal Associates, a partnership that leases a coal export terminal from the Peninsula Ports Authority of Virginia 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 facility has a rated throughput capacity of approximately 20 million tons of coal per year and had 13.7 million tons of throughput in 2008. The facility also has ground storage capacity of approximately 1.7 million tons. The facility exports both metallurgical and steam coal primarily to European and Brazilian markets.

 

We own 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, will be backed by take or pay agreements and will have an initial stage capacity of 33 million tons per annum of which our share is 5.8 million tons, with expansion capacity of up to 66 million tons per annum.

 

Resource Management

 

We hold approximately 9.2 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.

 

Trading and Brokerage Operations

 

Through our Trading and Brokerage segment, we primarily 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 a trading operations office in London in 2007. The sales and marketing operations include our COALTRADE Australia and COALTRADE International operations that broker coal in the Australia and

Pacific Rim markets. We also have a sales, marketing and business development office in Beijing, China to pursue potential long-term growth opportunities in this market.

 

Coal Supply Agreements

 

As of December 31, 2008, 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 in backlog. Agreements in backlog have remaining terms ranging from one to 17 years. As of December 31, 2007, we had a sales backlog of almost one billion tons of coal. For 2008, we sold approximately 90% of our worldwide sales volume under long-term coal supply agreements. In 2008, we sold coal to 329 electricity generating and industrial plants in 21 countries.

 

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 11% of our mining operations sales volume in 2008. 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. Typically, 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 Macquarie Generation in Australia, which runs through 2025 and will supply approximately 127 million tons in total from our Wilpinjong Mine.

 

Transportation

 

Coal consumed in the U.S. is usually sold at the mine with transportation costs borne by the purchaser. 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.

 

The majority of our sales volume is shipped by rail in the U.S., but a portion of our production is shipped by other modes of transportation, including barge, truck and ocean-going vessels. Our transportation department manages the loading of coal via these transportation modes.

 

Our Australian export volume (18 to 19 million tons annually) is shipped via ocean going vessels to customers. The majority of this coal reaches the loading port via rail. The majority of our Australian domestic volume (4 to 5 million tons annually) is shipped via rail.

 

Suppliers

 

The main types of goods we purchase are mining equipment and replacement parts, ammonium-nitrate based explosives, diesel fuel, off-the-road (OTR) tires, steel-related (including roof control materials) products and lubricants. 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 has been relatively consistent in recent years, although there continues to be some consolidation. Consolidation of suppliers of explosives has limited the number of sources for these materials. Although our current U.S. supply of explosives is concentrated with two suppliers (one primary and one smaller secondary), some alternative sources are available to us in the regions where we operate. Further consolidation of underground equipment suppliers has resulted in a situation where purchases of certain underground mining equipment are 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 had increased. However, as a result of the global economic slowdown in the last half of 2008, lead times for nearly all items have been decreasing. 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. A recent example of this is a collaboration with a third party and two universities to develop and test a programmable fuel controller for diesel mining equipment to reduce fuel consumption and particulate emissions without loss of performance.

 

During 2008, three major equipment and infrastructure upgrades were completed at North Antelope Rochelle Mine, our largest operation. A new dragline was commissioned with more efficient bucket design, faster cycle times, improved swing motion controls to increase component life and better monitors to enable increased payloads. A new overland conveyor and near pit truck dump and crusher facility were built to reduce truck haulage, conserve fuel and increase mine capacity. New high capacity blending and loading facilities were also completed that are designed to result in a lower cost structure while also increasing capacity.

 

Technology to quickly capture, analyze and transfer information regarding safety, performance and maintenance conditions at our operations is a priority. A wireless data acquisition system was installed at the Caballo Mine to more efficiently dispatch mobile equipment and monitor performance and condition of all major mining equipment on a real-time basis. This system has been performing well for two years at the nearby North Antelope Rochelle Mine. In addition, we have deployed at our North Antelope Rochelle Mine a component of our Enterprise Resource Planning system that connects to an application allowing us to collect equipment performance data and mine shipments detail in real-time. Also at our North Antelope Rochelle Mine and Caballo Mine, we have upgraded our wireless networks in support of a fully integrated mining data system. 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.

 

We use maintenance standards based on reliability-centered maintenance practices at all operations. Use of these techniques allows us to increase equipment utilization and reduce maintenance and capital spending by extending the equipment life, while minimizing the risk of premature failures. Optimized equipment strategies are being developed to help identify the appropriate preventative and predictive maintenance activities, emphasizing work being scheduled on condition rather than time. Benefits from analysis derived from lubrication, vibration and infrared technologies typically include lower lubrication consumption, better equipment performance and extended component life. 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.

 

Our mines use software to schedule and monitor trains, mine and pit blending, quality and customer shipments. This software was developed in-house and provides a competitive tool to differentiate our reliability and product consistency. Our preparation plant at the Twentymile Mine in Colorado utilizes low profile design and high capacity equipment for improved maintenance practices and overall plant utilization. The process circuitry uses large diameter heavy media cyclones and two stage fine coal cleaning with water-only cyclones

and spirals to enhance process performance and yield. A number of safety and monitoring features have been incorporated in the plant including an internet-accessible camera system.

 

We are also contributing to the commercial development and advancement of Btu Conversion technologies (see the Generation Development, Btu Conversion and Clean Coal Technology discussion that follows for more details).

 

Competition

 

The markets in which we sell our coal are highly competitive. According to the National Mining Association’s “2007 Coal Producer Survey,” the top 10 coal companies in the U.S. produced approximately 66% of total U.S. coal in 2007. Our principal U.S. competitors are other large coal producers, including Arch Coal, Inc., Rio Tinto Energy America, CONSOL Energy Inc. and Foundation Coal Corporation, which collectively accounted for approximately 35% of total U.S. coal production in 2007. Major international competitors include Rio Tinto, Anglo-American PLC, BHP Billiton, Shenhua Group, China Coal and Xstrata PLC.

 

A number of factors beyond our control affect the markets in which we sell our coal. Continued demand for our coal and the prices obtained by us depend primarily on the coal consumption patterns of the electricity generation and steel industries in the U.S., China, India and elsewhere around the world; the availability, location, cost of transportation and price of competing coal; and other electricity generation and fuel supply sources such as natural gas, oil, nuclear, hydroelectric, and other renewables. Coal consumption patterns are affected primarily by the demand for electricity, environmental and governmental legislation and regulations, and technological developments. We compete on the basis of coal quality, delivered price, customer service and support, and reliability.

 

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 taking a leading position in 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.

 

 

The U.S. Energy Information Administration estimates prices for oil and natural gas in 2030 will be materially higher than 2007 levels: imported crude oil prices are projected to increase 94% and domestic natural gas prices are forecasted to rise more than 30%. We are determining how to best participate in Btu Conversion technologies to economically convert our coal resources to natural gas and transportation fuels.

 

 

We are advancing the development of clean coal technologies, including carbon capture and sequestration, through a number of initiatives.

 

 

Certain Liabilities

 

We have long-term liabilities for reclamation (also called asset retirement obligations), pensions and retiree health care. In addition, one labor contract with the UMWA (the Western Surface Agreement) and voluntary arrangements with non-union employees include long-term benefits, notably health care coverage for retired employees and future retirees and their dependents. The majority of our existing liabilities relate to our past operations, including operations spun off with Patriot.

 

Asset Retirement Obligations.  Asset retirement obligations primarily represent the present value of future anticipated costs to restore surface lands to productivity levels equal to or greater than pre-mining conditions, as required by applicable laws and regulations. Expense from continuing operations (which includes liability accretion and asset amortization) for the years ended December 31, 2008, 2007 and 2006 was $48.2 million, $23.7 million, and $14.2 million, respectively. As of December 31, 2008, our asset retirement obligations of $422.6 million included $387.2 million related to locations with active mining operations and $35.4 million related to locations that are closed or inactive.

 

Pension-Related Provisions.  Pension-related costs represent the actuarially-estimated cost of pension benefits. Annual minimum contributions to the pension plans are determined by consulting actuaries based on the minimum funding standards of the Employee Retirement Income Security Act of 1974, as amended (ERISA), and an agreement with the Pension Benefit Guaranty Corporation (PBGC). On January 1, 2008, new minimum funding standards were required by the Pension Protection Act of 2006. Net pension-related liabilities were $216.0 million as of December 31, 2008, $1.6 million of which was a current liability. Net pension cost reflects a benefit of $7.4 million for the year ended December 31, 2008 and expense of $19.6 million and $26.3 million for the years ended December 31, 2007 and 2006, respectively.

 

Retiree Health Care.  Consistent with Statement of Financial Accounting Standard (SFAS) No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” we record a liability representing the estimated cost of providing retiree health care benefits to current retirees and active employees who will retire in the future. Provisions for active employees represent the amount recognized to date, based on their service to date; additional amounts are accrued periodically so that the total estimated liability is accrued when

the employee retires. Our retiree health care liabilities were $833.4 million as of December 31, 2008, $67.3 million of which was a current liability. In 2007, we spun off Patriot. Retiree health care expense related to the spin-off of Patriot for the years ended December 31, 2007 and 2006 was $46.6 million and $41.4 million, respectively, and was included in “Discontinued operations.”

 

Employees

 

As of December 31, 2008, we had approximately 7,200 employees. As of such date, approximately 28% of our hourly employees were represented by organized labor unions and generated 10% of the 2008 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 UMWA, 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, 2008. 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 8% of our U.S. subsidiaries’ hourly employees, who generated approximately 2% of our U.S. production during the year ended December 31, 2008.

 

Australia Labor Relations

 

The Australian coal mining industry is unionized and the majority of workers employed at our Australian Mining operations are members of trade unions. The Construction Forestry Mining and Energy Union represents our Australian subsidiary’s hourly production employees, including those employed through contract mining relationships. The labor agreements at our Australian subsidiary’s Metropolitan Mine were renewed in 2007 and expire in 2010. The labor agreements at our Australian subsidiary’s Chain Valley Mine and Wambo Mine coal handling plant were renewed in 2008 and expire in 2011. The labor agreements for our Australian subsidiary’s Wambo Underground Mine and North Goonyella Mine are under negotiation. The Wambo Underground Mine agreement expired in November 2008 while the North Goonyella Mine’s existing agreement expires in May 2009.

 

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.

 

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 the 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 2008, our safety performance set a new standard in our 125-year history. The U.S. injury incidence rate of 1.7 (computed per 200,000 worker hours) for 2008 was 34% better than the previous year and more than 61% better than the U.S. average for our industry. All of the operating regions showed incidence rate improvements in 2008, and more importantly, there were no fatal accidents at any of our facilities. 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.

 

Stringent health and safety standards have been in effect since Congress enacted the Coal Mine Health and Safety Act of 1969. The Federal Mine Safety and Health Act of 1977 significantly expanded the enforcement of safety and health standards and imposed safety and health standards on all aspects of mining operations. Congress enacted The Mine Improvement and New Emergency Response Act of 2006 (The Miner Act) as a result of the increase in fatal accidents primarily at U.S. underground mines. Among the new requirements, each miner must have at least two, one-hour Self Contained Self Rescue (SCSR) devices for their use in the event of an emergency (each miner had at least one SCSR device prior to The Miner Act) with additional caches of SCSRs in the escape routes leading to the surface. Also, refuge chambers have been installed in all of our U.S. underground mines to protect miners who may become trapped in the event of an emergency. 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 technologies are not yet fully developed, we are working with the National Institute for Occupational Safety and Health and several manufacturers to develop new systems.

 

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.

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 corresponding 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. 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.

The EPA promulgated the Clean Air Interstate Rule (CAIR) and the Clean Air Mercury Rule (CAMR) in March 2005. CAIR requires reduction of sulfur dioxide and nitrogen oxide emissions from electricity generating plants in 28 states and the District of Columbia. Substantial reductions in such emissions were already made beginning in the 1990’s under requirements of Title IV of the Clean Air Act. Once fully implemented over two rounds in 2009-2010 and 2015, CAIR is projected to reduce sulfur dioxide from power plants by approximately 73% and nitrogen oxide emissions by approximately 61% from 2003 levels.

 

In July and December 2008, in a case brought by the State of North Carolina and others against the EPA, the U.S. Court of Appeals for the District of Columbia rendered decisions remanding, but not vacating, CAIR (i.e., the rule as promulgated remains in effect until EPA acts on the remand). If the decision stands, the EPA will have to revisit its requirements regarding sulfur dioxide and nitrogen oxide emissions.

 

CAMR sought to permanently cap and reduce nationwide mercury emissions from coal-fired power plants. When fully implemented in 2018, the rule as promulgated would have reduced mercury emissions by nearly 70% according to the EPA. CAMR contained standards of performance limiting mercury emissions from new and existing power plants and sought to create a cap-and-trade program. Some states have adopted rules that are more stringent than the federal program and other states are considering such rules. In February 2008, in a case brought by the State of New Jersey and others against the EPA, the U.S. Court of Appeals for the District of Columbia (D.C. Circuit) rendered a decision effectively vacating CAMR. Although the EPA appealed the decision to the U.S. Supreme Court in October 2008, on February 6, 2009, the EPA withdrew its petition to appeal the D.C. Circuit’s decision on CAMR. Instead, the EPA plans to issue technology-based standards under the Clean Air Act’s National Emission Standards for Hazardous Air Pollutants program to regulate mercury emissions from power plants. Industry petitioners of the D.C. Circuit’s CAMR decision intend to continue their appeal.

 

Implementation of CAIR, federal requirements regarding mercury emissions and related state rules could cause our customers to switch to other fuels to the extent it becomes economically preferable for them to do so.

 

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 CAIR and CAMR. 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.

 

In September 2006, the EPA promulgated new National Ambient Air Quality Standards revising and updating the particulate matter standards issued in July 1997. The new regulations made the 24-hour standard for very fine particulate matter (PM2.5) more stringent but left the annual PM2.5 standard unchanged. They also left the 24-hour standard for PM10 (particulate matter equal to 10 microns or more) unchanged and terminated the annual PM10 standard. The change to the 24-hour PM2.5 standard is expected to affect the use of coal for electric generation, but we believe that effect cannot be quantified at this time. Lawsuits seeking to compel the EPA to adopt more stringent standards both for PM2.5 and PM10 have been filed and are pending in court. We believe the outcome of those lawsuits cannot be reliably predicted at this time. Under the rule as currently promulgated, some states will be required to change their existing implementation plans to attain and maintain compliance with the new air quality standards. Our mining operations and electricity generating customers are likely to be directly affected when the revisions to the air quality standards are implemented by the states. Such implementation could also restrict our ability to develop new mines or require us to modify our existing operations.

 

The Justice Department, on behalf of the EPA, has filed a number of lawsuits since November 1999, alleging that a number of electricity generators violated the new source review provisions of the Clean Air Act Amendments (NSR) at power plants in the midwestern and southern U.S. Some electricity generators announced settlements with the Justice Department requiring the installation of additional control equipment on selected generating units. If the remaining electricity generators are found to be in violation, they could be subject to civil penalties and could be required to install the required control equipment or cease operations. In April 2007, the U.S. Supreme Court ruled, in Environmental Defense Fund v. Duke Energy Corp., against a

generator in an enforcement proceeding, reversing the decision of the appellate court. This decision could potentially expose numerous electricity generators to government or citizen actions based on failure to obtain NSR permits for changes to emissions sources and effectively increase the costs to them of continuing to use coal. Our customers are among the electricity generators subject to 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. If our customers decide to install additional pollution control equipment at the affected plants, we believe we will have the ability to supply coal from the regions in which we operate to meet any new coal requirements.

 

In April 2007, the U.S. Supreme Court in Massachusetts v. EPA held that the Clean Air Act authorizes the EPA to regulate emissions of greenhouse gases from new motor vehicles, if the EPA makes the statutory finding concerning “endangerment” that is a prerequisite to such regulation. The Court also held that the EPA had not provided an adequate justification for its 2003 decision to deny a petition for such regulation. Although that petition related to new motor vehicles, the reasoning of the Court’s decision could affect other Clean Air Act regulatory programs, including those that directly relate to coal use. In July 2008, the EPA published an advance notice of proposed rulemaking soliciting public comment on issues concerning possible regulation under the Clean Air Act of greenhouse gas emissions from a variety of categories of emission sources, including stationary sources that burn coal.

 

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.

 

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.

 

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 aforementioned 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.

 

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 will be 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. The NTA and laws protecting Aboriginal cultural heritage and archeological sites have had no significant impact on our current operations.

 

Environmental

 

The federal system requires that approval is obtained for any activity which will have a significant impact on a matter of national environmental significance. Matters of national environmental significance include listed endangered species, nuclear actions, World Heritage areas, National Heritage areas and migratory species. An application for such an approval may require public consultation and may be approved, refused or granted subject to conditions. Otherwise, responsibility for environmental regulation in Australia is primarily vested in the states.

 

Each state and territory in Australia has its own environmental and planning regime for the development of mines. In addition, each state and territory also has a specific act dealing with mining in particular, regulating the granting of mining licenses and leases. The mining legislation in each state and territory operates concurrently with environmental and planning legislation. The mining legislation governs mining licenses and leases, including the restoration of land following the completion of mining activities. Apart from the grant of rights to mine (which are covered by the mining statutes), all licensing, permitting, consent and approval requirements are contained in the various state and territory environmental and planning statutes.

 

The particular provisions of the various state and territory environmental and planning statutes vary depending upon the jurisdiction. Despite variation in details, each state and territory has a system involving at least two major phases. First, obtaining the developmental application and, if that is granted, obtaining the detailed operational pollution control licenses, which authorize emissions up to a maximum level; and second, obtaining pollution control approvals, which authorize the installation of pollution control equipment and devices. In the first regulatory phase, an application to a regulatory authority is filed. The relevant authority will either grant a conditional consent, an unconditional consent, or deny the application based on the details of the application and on any submissions or objections lodged by members of the public. If the developmental application is granted, the detailed pollution control license may then be issued and such license may regulate emissions to the atmosphere; emissions in waters; noise impacts, including impacts from blasting; dust impacts; the generation, handling, storage and transportation of waste; and requirements for the rehabilitation and restoration of land.

Each state and territory in Australia also has either a specific statute or certain sections in environmental and planning statutes relating to the contamination of land and vesting powers in the various regulatory authorities in respect of the remediation of contaminated land. Those statutes are based on varying policies — the primary difference between the statutes is that in certain states and territories, liability for remediation is placed upon the occupier of the land, regardless of the culpability of that occupier for the contamination. In other states and territories, primary liability for remediation is placed on the original polluter, whether or not the polluter still occupies the land. If the original polluter cannot itself carry out the remediation, then a number of the statutes contain provisions which enable recovery of the costs of remediation from the polluter as a debt.

 

Many of the environmental planning statutes across the states and territories contain “third-party” appeal rights in relation, particularly, to the first regulatory phase. This means that any party has a right to take proceedings for a threatened or actual breach of the statute, without first having to establish that any particular interest of that person (other than as a member of the public) stands to be affected by the threatened or actual breach.

 

Accordingly, in most states and territories throughout Australia, mining activities involve a number of regulatory phases. Following exploratory investigations pursuant to a mining lease, the activity proposed to be carried out must be the subject of an application for the activity or development. This phase of the regulatory process, as noted above, usually involves the preparation of extensive documents to constitute the application, addressing all of the environmental impacts of the proposed activity. It also generally involves extensive notification and consultation with other relevant statutory authorities and members of the public. Once a decision is made to allow a mine to be developed by the grant of a development consent, permit or other approval, then a formal mining lease can be obtained under the mining statute. In addition, operational licenses and approvals can then be applied for and obtained in relation to pollution control devices and emissions to the atmosphere, to waters and for noise. The obtaining of licenses and approvals, during the operational phase, generally does not involve any extensive notification or consultation with members of the public, as most of these issues are anticipated to be resolved in the first regulatory phase.

 

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. Our incident rate in Australia improved 26% from the prior year.

 

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. The federal government is currently conducting a review of health and safety legislation with a view to harmonizing requirements across the country.

 

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, beginning July 1, 2008. 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.

 

In the first reporting year, July 1, 2008 to June 30, 2009, a controlling corporation must register in the National Greenhouse and Energy Register if its corporate group emits a carbon dioxide equivalent of 125 kilotonnes or more. This threshold is reduced progressively in the following reporting years. Once registered, a corporation must report each financial year about its greenhouse gas emissions and energy production and consumption.

 

Carbon Pollution Reduction Scheme

 

The Federal Labor Government ratified the Kyoto Protocol in December 2007. Under the treaty, Australia has a target of restricting greenhouse gas emissions to 108% of 1990 levels during the 2008-2012 commitment period. To assist in meeting Australia’s target, the Federal Government has announced that it will establish a cap and trade emissions trading scheme by July 2010 named the Carbon Pollution Reduction Scheme. There are no plans for a carbon tax. At this stage, the Federal Government has released a Green Paper and a White Paper outlining a proposed scheme. Any final legislation will require approval from both houses of parliament.

 

Global Climate Change

 

Global climate change continues to attract public and scientific attention. Widely publicized scientific reports in 2007, 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 reducing greenhouse gas emissions, including coal combustion by power plants.

 

Legislation was introduced in the U.S. Congress in 2006, 2007 and 2008 to reduce greenhouse gas emissions in the U.S., and additional legislation is likely to be introduced in the future. Presently there are no federal mandatory greenhouse gas reduction requirements. While it is possible that Congress will adopt some form of mandatory greenhouse gas emission reduction legislation in the future, the timing and specific requirements of any such legislation are highly uncertain.

 

In July 2008, the EPA published an advance notice of proposed rulemaking soliciting public comment on issues concerning possible regulation under the Clean Air Act of greenhouse gas emissions from a variety of categories of emission sources, including stationary sources that burn coal. While it is possible that the EPA may adopt regulations under the Clean Air Act with respect to greenhouse gas emissions in the future, the timing and specific requirements of any such regulations are highly uncertain.

 

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 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 to establish a regional greenhouse gas reduction goal and develop market-based strategies to achieve emissions reductions. In 2006, the California legislature approved legislation allowing the imposition of statewide caps on, and cuts in, carbon dioxide emissions; and Arizona’s governor signed an executive order in September 2006 that calls for the state to reduce 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.

 

We continue to support clean coal technology development and voluntary 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 and the Asia-Pacific Partnership for Clean Development and Climate. 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 participate in the U.S. DOE’s Voluntary Reporting of Greenhouse Gases Program, and regularly disclose the quantity of greenhouse gases emitted by us per ton of coal produced in the U.S. The vast majority of our greenhouse gas 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 new 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 greenhouse gas emissions from our operations.

 

Enactment of laws and passage of regulations regarding greenhouse gas emissions by the U.S. or some of its states or by other countries, or other actions to limit carbon dioxide emissions, could result in electricity generators switching from coal to other fuel sources. The potential financial impact on us of future regulation will depend primarily upon the degree to which any such regulation 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 regulation.

 

Additional Information

 

We file annual, quarterly and current reports, and our amendments to those reports, proxy statements and other information with the Securities and Exchange Commission (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.

 

 

The following risk factors relate specifically to the risks associated with our continuing operations.

 

Risks Associated with Our Operations

 

The duration or severity of the current global economic downturn and disruptions in the financial markets, and their impact on us, are uncertain.

 

The recent global economic downturn, coupled with the global financial and credit market disruptions, have had a negative impact on us and on the coal industry generally. While we believe that the long-term prospects for coal remain bright, we are unable to predict the duration or severity of the current global economic and financial crisis. 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 protracted continuation or worsening of the global economic downturn or disruptions in the financial markets could have a material 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:

 

 

As of January 27, 2009, our 2009 production is largely sold out in the U.S. with 4 to 5 million tons of Australian metallurgical coal and 5 to 6 million tons of Australian thermal coal available to price. The current global financial slowdown has reduced gross domestic product expectations for U.S., China and other major world economies, which is expected to temper the growth of coal demand in the near term. As a result, we expect 2009 coal prices to be lower than 2008 levels for our unpriced 2009 Australian-based metallurgical and thermal coal. If we continue to experience a weak coal pricing environment or if we see a further deterioration in coal prices, we could experience an adverse effect on our revenues and profitability.

 

A decrease in our production of metallurgical coal could reduce our anticipated profitability.

 

In 2008, we produced 7.8 million tons of metallurgical coal for export from our Australian Mining operations and realized prices for metallurgical coal at historically high levels, which significantly increased our profitability. Although we have annual capacity to produce approximately 8 to 10 million tons of metallurgical coal from these operations, we project that our 2009 metallurgical coal production will be reduced by up to two million tons due to the decline in worldwide steel demand. To the extent that demand for metallurgical coal further deteriorates, our profitability could be adversely affected.

 

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. For the year ended December 31, 2008, 90% of our worldwide sales volume was sold under long-term coal supply agreements. At December 31, 2008, 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 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.

 

The loss of, or significant reduction in, purchases by our largest customers could adversely affect our revenues.

 

For the year ended December 31, 2008, we derived 24% of our total coal revenues from sales to our five largest customers. At December 31, 2008, we had 66 coal supply agreements and trading transactions with these customers expiring at various times from 2009 to 2014. 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 depends on the continued creditworthiness of our customers. Our customer base has changed with deregulation as utilities have sold their power plants to their non-regulated affiliates or third parties. These new power plant owners or other customers may have credit ratings that are below investment grade. If deterioration of the creditworthiness of our customers occurs, our $275.0 million accounts receivable securitization program and our business could be adversely affected.

 

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, 2008, 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.

 

Coal producers depend upon rail, barge, trucking, overland conveyor and ocean-going vessels to deliver coal to markets. While our coal customers typically arrange and pay for transportation of coal from the mine or port to the point of use, disruption of these transportation services because of weather-related problems, infrastructure damage, strikes, lock-outs, lack of fuel or maintenance items, transportation delays or other events could temporarily impair our ability to supply coal to our customers and thus could adversely affect our

results of operations. For example, two primary railroads serve the Powder River Basin mines. Due to the high volume of coal shipped from all Powder River Basin mines, the loss of access to rail capacity could create temporary congestion on the rail systems servicing that region. In Australia we currently ship coal through the ports of Dalrymple Bay, Brisbane, Newcastle and Port Kembla. In most instances, we rail coal to these ports. The Australian coal supply chains (rail and port) can be impacted by a number of factors including weather events, breakdown or underperformance of the port and rail infrastructure, congestion and balancing systems which are imposed to manage vessel queuing and demurrage. As a result, we are susceptible to increased costs or lost sales due to Australian coal chain problems.

 

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 two suppliers. 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 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, 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, the ability of our freight sources to fulfill their delivery obligations and other factors. The recent market volatility and price increases for coal 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.

 

If the coal industry experiences overcapacity in the future, our profitability could be impaired.

 

Coal prices in most regions of the U.S. and globally were approaching record highs in the first half of 2008, which encouraged producers to increase planned capacity. Many of these planned capacity increases and existing production plans have been delayed or reduced due to the global economic downturn and coal price reductions in the second half of 2008. To the extent that demand drops below supply, our profitability could be materially 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 financial condition and results of operations.

 

Our ability to operate our company effectively could be impaired if we lose key personnel or fail to attract qualified personnel.

 

We manage our business with a number of key personnel, the loss of a number of whom could have a material adverse effect on us. In addition, as our business develops and expands, we believe that our future success will depend greatly on our continued ability to attract and retain highly skilled and qualified personnel. We cannot assure that key personnel will continue to be employed by us or that we will be able to attract and retain qualified personnel in the future. 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, 2008, we had approximately 7,200 employees. In the U.S., approximately 15% of our U.S. subsidiaries’ hourly employees are represented by unions and they generated approximately 6% of our U.S. production during the year ended December 31, 2008. In Australia, the majority of workers are members of trade unions, including those employed through contract mining relationships. Relations with our employees and, where applicable, organized labor are important to our success.

 

Due to the higher labor costs and the increased risk of strikes and other work-related stoppages that may be associated with union operations in the coal industry, our competitors who operate without union labor may have a competitive advantage in areas where they compete with our unionized operations. If some or all of our current non-union operations were to become unionized, we could incur an increased risk of work stoppages, reduced productivity and higher labor costs.

 

Our operations could be adversely affected if we fail to appropriately secure our obligations.

 

U.S. federal and state laws and Australian laws require us to secure certain of our obligations to reclaim lands used for mining, to pay federal and state workers’ compensation, to secure coal lease obligations and to satisfy other miscellaneous obligations. The primary 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, 2008, we had $773.4 million of self bonding in place for our reclamation obligations. As of December 31, 2008, we also had outstanding surety bonds with third parties and letters of credit of $1,128.6 million, of which $740.7 million was for post-mining reclamation, $74.2 million related to workers’ compensation obligations, $99.2 million was for coal lease obligations and $214.5 million was for other obligations, including collateral for surety companies and bank guarantees, road maintenance and performance guarantees. As of December 31, 2008, the amount of letters of credit securing Patriot obligations was $7.0 million related to Patriot’s workers’ compensation obligations. Surety bonds are typically renewable on a yearly basis. Surety bond issuers and holders may not continue to renew the bonds or may demand additional collateral upon those renewals. Letters of credit are subject to our successful renewal of our bank Revolving Credit 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:

 

 

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 or local authorities data pertaining to the effect or impact that any proposed exploration for or production of coal may have upon the environment. The costs, liabilities and requirements associated with these regulations may be costly and time-consuming and may delay commencement or continuation of exploration or production. The possibility exists that new legislation and/or regulations and orders related to the environment or employee health and safety may be adopted and may materially adversely affect our mining operations, our cost structure and/or our customers’ ability to use coal. New legislation or administrative regulations (or judicial interpretations of existing laws and regulations), including proposals related to the protection of the environment 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. A predecessor owner of ours, Hanson PLC, transferred ownership of Gold Fields to us in the February 1997 spin-off of its energy business. Gold Fields is currently a defendant in several lawsuits and has received notices of several other potential claims arising out of lead contamination from mining and milling operations it conducted in northeastern Oklahoma. Gold Fields is also involved in investigating or remediating a number of other contaminated sites. Although we have accrued for many of these liabilities known to us, the amounts of other potential losses cannot be estimated. Significant uncertainty exists as to whether claims will be pursued against Gold Fields in all cases, and where they are pursued, the amount of the eventual costs and liabilities, which could be greater or less than our accrual. Although we believe many of these liabilities are likely to be resolved without a material adverse effect on us, future developments, such as new information concerning areas known to be or suspected of being contaminated for which we may be responsible, the discovery of new contamination for which we may be responsible, or the inability to share costs with other parties that may be responsible for the contamination, could have a material adverse effect on our financial condition or results of operations.

Our future success depends upon our ability to continue acquiring and developing coal reserves that are economically recoverable.

 

Our recoverable reserves decline as we produce coal. We have not yet applied for the permits required or developed the mines necessary to use all of our reserves. Furthermore, we may not be able to mine all of our reserves as profitably as we do at our current operations. Our future success depends upon our conducting successful exploration and development activities or acquiring properties containing economically recoverable reserves. Our current strategy includes increasing our reserves through acquisitions of government and other leases and producing properties and continuing to use our existing properties. The federal government also leases natural gas and coalbed methane reserves in the West, including in the Powder River Basin. Some of these natural gas and coalbed methane reserves are located on, or adjacent to, some of our Powder River Basin reserves, potentially creating conflicting interests between us and lessees of those interests. Other lessees’ rights relating to these mineral interests could prevent, delay or increase the cost of developing our coal reserves. These lessees may also seek damages from us based on claims that our coal mining operations impair their interests. Additionally, the federal government limits the amount of federal land that may be leased by any company to 150,000 acres nationwide. As of December 31, 2008, we leased a total of 64,154 acres from the federal government. The limit could restrict our ability to lease additional federal lands.

 

Our planned mine development projects and acquisition activities may not result in significant additional reserves, and we may not have continuing success developing additional mines. Most of our mining operations are conducted on properties owned or leased by us. Because 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 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.

 

Growth in our global operations increases our risks unique to international mining and trading operations.

 

We currently have international mining operations in Australia and Venezuela. We have a business development, sales and marketing office in Beijing, China and an international trading group in our Trading and Brokerage operations. In addition, we are actively pursuing long-term operating, trading and joint-venture opportunities in China, Mongolia and Mozambique. 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 expropriation and the inability to repatriate earnings on our investment. In particular, the Venezuelan government has suggested its desire to increase government ownership in Venezuelan energy assets and natural resources. Actions to nationalize Venezuelan coal properties could be detrimental to our investment in the Paso Diablo Mine. During 2008, the Paso Diablo Mine contributed $5.7 million to segment Adjusted EBITDA in “Corporate and Other Adjusted EBITDA” (see Item 7) and paid a dividend of $19.9 million. At December 31, 2008, our investment in Paso Diablo was $54.2 million, recorded in “Investments and other assets” on the consolidated balance sheet.

 

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, 2008, 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.

 

Our financial performance could be affected by our indebtedness. As of December 31, 2008, our total indebtedness was $3.2 billion, and we had $1.5 billion of available borrowing capacity under our Revolving Credit Facility. The indentures governing our Convertible Junior Subordinated Debentures (the Debentures) and 7.375% and 7.875% Senior Notes do not limit the 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:

 

 

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 these agreements would be in default and could be accelerated by our lenders. If our indebtedness is accelerated, we may not be able to repay our debt or borrow sufficient funds to refinance it. Even if we are able to obtain new financing, it may not be on commercially reasonable terms, on terms that are acceptable to us or at all. If our debt is in default for any reason, our business, financial condition and results of operations could be materially and adversely affected. In addition, complying with these covenants may also cause us to take actions that are not favorable to holders of our other debt or equity securities and may make it more difficult for us to successfully execute our business strategy and compete against companies who are not subject to such restrictions.

 

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 spin-off from us.

 

Patriot is responsible for certain federal and state black lung occupational disease liabilities up to $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 under SFAS No. 106, which was a liability of $833.4 million as of December 31, 2008, $67.3 million of which was a current liability. Net pension liabilities were $216.0 million as of December 31, 2008, $1.6 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 led to a decline in the value of our pension plan assets as of December 31, 2008. We have experienced additional asset value declines in early 2009. The decline in asset values will, without a significant recovery of asset values in 2009, increase the required contributions to our pension plans in future periods.

 

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. Widely publicized scientific reports in 2007, 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 reducing greenhouse gas emissions, including coal combustion by power plants.

 

Enactment of laws and passage of regulations regarding greenhouse gas emissions by the U.S. or some of its states, or other actions to limit carbon dioxide emissions, could result in electricity generators switching from coal to other fuel sources. The potential financial impact on us of future regulation will depend primarily upon the degree to which any such regulation 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 regulation.

 

Further developments in connection with legislation, regulations or other limits on greenhouse gas emissions and other environmental impacts from coal combustion, both in the U.S. and in other countries where we sell coal, could have a material adverse effect on our results of operations, cash flows and financial condition.

 

As we continue to pursue Btu Conversion activities, we face challenges and risks that differ from those in our 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). 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 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.

 

 

None.

 

 

Coal Reserves

 

We had an estimated 9.2 billion tons of proven and probable coal reserves as of December 31, 2008. An estimated 8.1 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 4.2 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 38% of these reserves and lease property containing the remaining 62%. 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.

 

 

 

 

Reserves are defined by SEC Industry Guide 7 as that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination. Proven and probable coal reserves are defined by SEC Industry Guide 7 as follows:

 

Proven (Measured) Reserves — Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so close and the geographic character is so well defined that size, shape, depth and mineral content of reserves are well-established.

 

Probable (Indicated) Reserves — Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) reserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven (measured) reserves, is high enough to assume continuity between points of observation.

 

Our estimates of proven and probable coal reserves are established within these guidelines. Proven reserves require the coal to lie within one-quarter mile of a valid point of measure or point of observation, such as exploratory drill holes or previously mined areas. Estimates of probable reserves may lie more than one-quarter mile, but less than three-quarters of a mile, from a point of thickness measurement. Estimates within the proven category have the highest degree of assurance, while estimates within the probable category have only a moderate degree of geologic assurance. Further exploration is necessary to place probable reserves into the proven reserve category. Our active properties generally have a much higher degree of reliability because of increased drilling density. Active surface reserves generally have points of observation as close as 330 feet to 660 feet.

 

Our reserve estimates are prepared by our staff of geologists, whose experience ranges from 10 to over 32 years. We also have a chief geologist of reserve reporting whose primary responsibility is to track changes in reserve estimates, supervise our other geologists and coordinate periodic third-party reviews of our reserve estimates by qualified mining consultants.

 

Our reserve estimates are predicated on information obtained from our ongoing drilling program, which totals nearly 500,000 individual drill holes. We compile data from individual drill holes in a computerized drill-hole database from which the depth, thickness and, where core drilling is used, the 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 federal coal leases that are administered by the U.S. Department of the Interior under the Federal Coal Leasing Amendments Act of 1976. These leases cover our principal reserves in Wyoming and other reserves in Montana and Colorado. Each of these leases continues indefinitely, provided there is diligent development of the property and continued operation of the related mine or mines. The Bureau of Land Management has asserted the right to adjust the terms and conditions of these leases, including rent and royalties, after the first 20 years of their term and at 10-year intervals thereafter. Annual rents on surface land under our federal coal leases are now set at $3.00 per acre. Production royalties on federal leases are set by statute at 12.5% of the gross proceeds of coal mined and sold for surface-mined coal and 8% for underground-mined coal. The federal government limits by statute the amount of federal land that may be leased by any company and its affiliates at any time to 75,000 acres in any one state and 150,000 acres nationwide. As of December 31, 2008, we leased 11,478 acres of federal land in Colorado, 11,254 acres in Montana and 41,422 acres in Wyoming, for a total of 64,154 nationwide.

 

Similar provisions govern three coal leases with the Navajo and Hopi Indian tribes. These leases cover coal contained in 65,000 acres of land in northern Arizona lying within the boundaries of the Navajo Nation and Hopi Indian reservations. We also lease coal-mining properties from various state governments.

 

Private 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. With a portfolio of approximately 9.2 billion tons, we believe that we have sufficient reserves to replace capacity from depleting mines for the foreseeable future and that our significant reserve holdings is one of our strengths. We believe that the current level of production at our major mines is sustainable for the foreseeable future.

 

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.

 

The following chart provides a summary, by mining complex, of production for the years ended December 31, 2008 and 2007 and 2006, 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)

 

 

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, 2008

 

(Tons in Millions)

 

 

 

 

From time to time, we or our subsidiaries are involved in legal proceedings arising in the ordinary course of business or related to indemnities or historical operations. We believe we have recorded adequate reserves for these liabilities and that there is no individual case pending that is likely to have a material adverse effect on our financial condition, results of operations or cash flows. We discuss our significant legal proceedings below.

 

Litigation Relating to Continuing Operations

 

Navajo Nation Litigation

 

On June 18, 1999, the Navajo Nation served three of our subsidiaries, including Peabody Western Coal Company (Peabody Western), with a complaint that had been filed in the U.S. District Court for the District of Columbia. The Navajo Nation has alleged 16 claims, including Civil Racketeer Influenced and Corrupt Organizations Act (RICO) violations and fraud. The complaint alleges that the defendants jointly participated in unlawful activity to obtain favorable coal lease amendments. The plaintiff is seeking various remedies including actual damages of at least $600 million, which could be trebled under the RICO counts, punitive damages of at least $1 billion, a determination that Peabody Western’s two coal leases have terminated due to Peabody Western’s breach of these leases and a reformation of these leases to adjust the royalty rate to 20%. Subsequently, the court allowed the Hopi Tribe to intervene in this lawsuit and the Hopi Tribe is also seeking unspecified actual damages, punitive damages and reformation of its coal lease. One of our subsidiaries named as a defendant is now a subsidiary of Patriot. However, we are responsible for this litigation under the Separation Agreement entered into with Patriot in connection with the spin-off. On February 9, 2005, the U.S. District Court for the District of Columbia granted a consent motion to stay the litigation until further order of the court to allow parties to mediate. The mediation terminated without resolution and in March 2008 the court lifted the stay and litigation resumed.

 

The outcome of this litigation is subject to numerous uncertainties. Based on our evaluation of the issues and their potential impact, the amount of any future loss cannot be reasonably estimated. However, based on current information, we believe this matter is likely to be resolved without a material adverse effect on our financial condition, results of operations or cash flows.

 

Salt River Project Agricultural Improvement and Power District — Mine Closing and Retiree Health Care

 

Salt River Project and the other owners of the Navajo Generating Station filed a lawsuit on September 27, 1996, in the Superior Court of Maricopa County in Arizona seeking a declaratory judgment that certain costs relating to final reclamation, environmental monitoring work and mine decommissioning and costs primarily

relating to retiree health care benefits are not recoverable by our subsidiary, Peabody Western, under the terms of a coal supply agreement dated February 18, 1977. The contract expires in 2011. The trial court subsequently ruled that the mine decommissioning costs were subject to arbitration but that the retiree health care costs were not subject to arbitration. All of the parties have negotiated and signed a comprehensive settlement to fully resolve all of the underlying claims and demands and to dismiss the associated litigation with prejudice, which became final and binding upon all of the parties on June 30, 2008. As a result of the retiree heath care cost settlement, we recorded pre-tax earnings of $56.9 million in 2008. We have a receivable for mine decommissioning costs of $90.4 million as of December 31, 2008 and $87.7 million as of December 31, 2007, and a receivable for retiree health care costs of $67.6 million as of December 31, 2008 included in “Investments and other assets” in the consolidated balance sheets.

 

Gulf Power Company Litigation

 

On June 22, 2006, Gulf Power Company filed a breach of contract lawsuit against one of our subsidiaries in the U.S. District Court, Northern District of Florida, contesting the force majeure declaration by our subsidiary under a coal supply agreement with Gulf Power Company and seeking damages for alleged past and future tonnage shortfalls of nearly five million tons under the agreement, which expired on December 31, 2007. In February 2008, the court denied our motion to dismiss the Florida lawsuit or to transfer it to Illinois and retained jurisdiction over the case.

 

The outcome of this litigation is subject to numerous uncertainties. Based on our evaluation of the issues and their potential impact, the amount of any future loss cannot reasonably be estimated. However, based on current information, we believe this matter is likely to be resolved without a material adverse effect on our financial condition, results of operations or cash flows.

 

Claims and Litigation Relating to Indemnities or Historical Operations

 

Oklahoma Lead Litigation

 

Gold Fields is a dormant, non-coal producing entity that was previously managed and owned by Hanson PLC, our predecessor owner. In a February 1997 spin-off, Hanson PLC transferred ownership of Gold Fields to us, despite the fact that Gold Fields had no ongoing operations and we had no prior involvement in its past operations. Gold Fields is currently one of our subsidiaries. We indemnified TXU Group with respect to certain claims relating to a former affiliate of Gold Fields. A predecessor of Gold Fields formerly operated two lead mills near Picher, Oklahoma prior to the 1950s and mined, in accordance with lease agreements and permits, approximately 0.15% of the total amount of the crude ore mined in the county.

 

Gold Fields and two other companies are defendants in two class action lawsuits allegedly involving past operations near Picher, Oklahoma. The plaintiffs have asserted claims predicated on allegations of intentional lead exposure by the defendants and are seeking compensatory damages, punitive damages and the implementation of medical monitoring and relocation programs for the affected individuals. In December 2003, the Quapaw Indian tribe and certain Quapaw land owners filed a lawsuit against Gold Fields, five other companies and the U.S. The plaintiffs are seeking compensatory and punitive damages based on a variety of theories. In December 2007, the court dismissed the tribe’s medical monitoring claim. In July 2008, the court dismissed the tribe’s claim for interim and lost use damages under the CERCLA without prejudice to refile at the point the U.S. EPA selects a final remedy for the site. Gold Fields has filed a third-party complaint against the U.S. and other parties. In February 2005, the state of Oklahoma on behalf of itself and several other parties sent a notice to Gold Fields and other companies regarding a possible natural resources damage claim. All of the lawsuits are pending in the U.S. District Court for the Northern District of Oklahoma.

 

The outcome of litigation and these claims are subject to numerous uncertainties. Based our evaluation of the issues and their potential impact, the amount of any future loss cannot be reasonably estimated. However, based on current information, we believe this matter is likely to be resolved without a material adverse effect on our financial condition, results of operations or cash flows.

Environmental Claims and Litigation

 

Environmental claims have been asserted against Gold Fields related to activities of Gold Fields or a former affiliate. Gold Fields or the former affiliate has been named a potentially responsible party (PRP) at five national priority list sites based on the Superfund Amendments and Reauthorization Act of 1986. Claims were asserted at 11 additional sites, bringing the total to 16, which have since been reduced to 12 by completion of work, transfer or regulatory inactivity. The number of PRP sites in and of itself is not a relevant measure of liability, because the nature and extent of environmental concerns varies by site, as does the estimated share of responsibility for Gold Fields or the former affiliate. Undiscounted liabilities for environmental cleanup-related costs for all of the sites noted above were $45.3 million as of December 31, 2008 and $43.5 million as of December 31, 2007, $7.6 million and $7.1 million of which was reflected as a current liability, respectively. These amounts represent those costs that we believe are probable and reasonably estimable. In September 2005, Gold Fields and other PRPs received a letter from the U.S. Department of Justice alleging that the PRP’s mining operations caused the EPA to incur approximately $125 million in residential yard remediation costs at Picher, Oklahoma and will cause the EPA to incur additional remediation costs relating to historical mining sites. In September 2008, Gold Fields and other PRPs received letters from the U.S. Department of Justice and the EPA re-initiating settlement negotiations. Gold Fields is participating in the settlement discussions. Gold Fields believes it has meritorious defenses to these claims. Gold Fields is involved in other litigation in the Picher area, and we indemnified TXU Group with respect to a defendant as is more fully discussed under the “Oklahoma Lead Litigation” caption above. Significant uncertainty exists as to whether claims will be pursued against Gold Fields in all cases, and where they are pursued, the amount of the eventual costs and liabilities, which could be greater or less than the liabilities recorded in the consolidated balance sheets. Based on our evaluation of the issues and their potential impact, the amount of any future loss cannot be reasonably estimated. However, based on current information, we believe these claims and litigation are likely to be resolved without a material adverse effect on our financial condition, results of operations or cash flows.

 

Other

 

In addition, at times we become a party to other claims, lawsuits, arbitration proceedings and administrative procedures in the ordinary course of business in the U.S., Australia and other countries where we do business. Based on current information, we believe that the ultimate resolution of such other pending or threatened proceedings is not reasonably likely to have a material adverse effect on our financial position, results of operations or liquidity.

 

New York Office of the Attorney General Subpoena

 

The New York Office of the Attorney General sent a letter to us dated September 14, 2007 that referred to our “plans to build new coal-fired electric generating units,” and said that the “increase in CO₂ emissions from the operation of these units, in combination with Peabody Energy’s other coal-fired power plants, will subject Peabody Energy to increased financial, regulatory, and litigation risks.” We currently have no electricity generating capacity in place. The letter included a subpoena issued under New York state law, which seeks information and documents relating to our analysis of the risks associated with climate change and possible climate change legislation or regulations, and its disclosure of such risks to investors. We believe that we have made full and proper disclosure of these potential risks.

 

Alaskan Villages’ Claims

 

In February 2008, the Native Village of Kivalina and the City of Kivalina filed a lawsuit in the U.S. District Court for the Northern District of California against us, several owners of electricity generating facilities and several oil companies. The plaintiffs are the governing bodies of a village in Alaska that they contend is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for nuisance, and allege that the defendants have acted in concert and are jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which cost is alleged to be

$95 million to $400 million. We believe that this lawsuit is without merit and intend to defend against and oppose it vigorously, but cannot predict its outcome. Based on our evaluation of the issues and their potential impact, the amount of any future loss cannot be reasonably estimated. However, based on current information, we believe this matter is likely to be resolved without a material adverse effect on our financial condition, results of operations or cash flows.

 

 

No matters were submitted to a vote of security holders during the quarter ended December 31, 2008.

 

Set forth below are the names, ages as of February 25, 2009 and current positions of our executive officers. Executive officers are appointed by, and hold office at the discretion of, our Board of Directors.

 

 

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 of the Company in March 2005, and assumed the position of Chief Executive Officer in January 2006. Mr. Boyce served as President of the Company from October 2003 to December 2007 and as Chief Operating Officer of the Company 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 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 (NCC) and the Coal Industry Advisory Board of the International Energy Agency. He is a Board member of the Business Roundtable, the American Coalition for Clean Coal Electricity (ACCCE). He is a member of the Board of Trustees of St. Louis Children’s Hospital; 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 was named our President and Chief Commercial Officer in January 2008. He served as our Executive Vice President of Corporate Development from July 2006 to January 2008 and as Chief Financial Officer from October 1999 to June 2008. He 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 Director of the United Way of Greater St. Louis; a Director of the Missouri Historical Society; a member of Financial Executives International and the Civic Entrepreneurs Organization; 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 the Company in 1998 as Senior Manager of Financial Reporting, and has served as Assistant Corporate Controller, Director of Planning, Assistant Treasurer 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, with executive responsibility for human resources, information services, procurement, flight services and facilities management. 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 Vice President of the Chancellor’s Council of the University of Missouri St. Louis. She is also a 2008 YWCA Leader of Distinction Award recipient.

 

Eric Ford was named our Executive Vice President and Chief Operating Officer in March 2007, with responsibility for all of our global mining operations, as well as the areas of safety, operations improvement, engineering, and technical services. Mr. Ford has 35 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, with responsibility for all of our legal and corporate secretary functions. Prior to joining us, Mr. Schoch served as Vice President and General Counsel for Emerson Process Management, an operating segment of Emerson Electric Company and leading supplier of process-automation products. Mr. Schoch also served in 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.

 

 

Our common stock is listed on the New York Stock Exchange, under the symbol “BTU.” As of February 13, 2009, there were 1,243 holders of record of our common stock.

The table below sets forth the range of quarterly high and low sales prices for our common stock on the New York Stock Exchange during the calendar quarters indicated.

 

 

Dividend Policy

 

We paid quarterly dividends totaling $0.24 per share for each of the years ended December 31, 2008 and 2007. Most recently, our Board of Directors declared a dividend of $0.06 per share of Common Stock on January 28, 2009, payable on March 4, 2009, to stockholders of record on February 11, 2009. 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

 

Share Repurchase Program

 

In July 2005, our Board of Directors authorized a share repurchase program of up to 5% of the then outstanding shares of our common stock, approximately 13 million shares. The repurchases may be made from time to time based on an evaluation of our outlook and general business conditions, as well as alternative investment and debt repayment options. In addition, our Board of Directors had previously authorized our Chairman and Chief Executive Officer to repurchase up to $100 million of our common stock outside the share repurchase program. In October 2008, our Board of Directors amended the share repurchase program to increase the total authorized amount to $1 billion. The amended repurchase program does not have an expiration date and may be discontinued at any time. Share repurchases made by us under this program in the year ended December 31, 2008 totaled 5.5 million shares for $199.8 million. As of December 31, 2008, there was $700.4 million available for share repurchases under the program.

 

The following table summarizes the share repurchases for the three months ended December 31, 2008: