10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_____________________________________________

Form 10-K

( X )	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the Fiscal Year Ended December 31, 2011
or
( )	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number 1-16463

____________________________________________

Peabody Energy Corporation

(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)	13-4004153 (I.R.S. Employer Identification No.)
701 Market Street, St. Louis, Missouri (Address of principal executive offices)	63101 (Zip Code)

(314) 342-3400

Registrant’s telephone number, including area code

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

Title of Each Class	Name of Each Exchange on Which Registered
Common Stock, par value $0.01 per share	New York Stock Exchange
Preferred Share Purchase Rights	New York Stock Exchange

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

None

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

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 ( )    No ( X )

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 ( X )   No ( )

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes ( X )   No ( )

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ( )

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ( X ) Accelerated filer ( ) Non-accelerated filer ( ) Smaller reporting company ( )

(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 ( )     No ( X )

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, 2011: Common Stock, par value $0.01 per share, $15.9 billion.

Number of shares outstanding of each of the Registrant’s classes of Common Stock, as of February 17, 2012: Common Stock, par value $0.01 per share, 272,259,729 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 2012 Annual Meeting of Shareholders (the Company’s 2012 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” in Management’s Discussion and Analysis of Financial Condition and Results of Operations. We use words such as “anticipate,” “believe,” “expect,” “may,” “project,” “should,” “estimate,” or “plan” or other similar words to identify forward-looking statements.

Without limiting the foregoing, all statements relating to our future operating results, anticipated capital expenditures, future cash flows and borrowings, and sources of funding are forward-looking statements and speak only as of the date of this report. These forward-looking statements are based on numerous assumptions that we believe are reasonable, but are subject to a wide range of uncertainties and business risks and actual results may differ materially from those discussed in these statements. Among the factors that could cause actual results to differ materially are:

• global demand for coal, including the seaborne thermal and metallurgical coal markets;

• price volatility, particularly in higher-margin products and in our trading and brokerage businesses;

• impact of alternative energy sources, including natural gas and renewables;

• impact of weather and natural disasters on demand, production and transportation;

• reductions and/or deferrals of purchases by major customers and ability to renew sales contracts;

• credit and performance risks associated with customers, suppliers, contract miners, co-shippers, and trading, banks and other financial counterparties;

• geologic, equipment, permitting and operational risks related to mining;

• transportation availability, performance and costs;

• availability, timing of delivery and costs of key supplies, capital equipment or commodities such as diesel fuel, steel, explosives and tires;

• integration of the newly acquired Macarthur Coal Limited (Macarthur) operations;

• successful implementation of business strategies;

• negotiation of labor contracts, employee relations and workforce availability;

• changes in postretirement benefit and pension obligations and their related funding requirements;

• replacement and development of coal reserves;

• availability, access to and the related cost of capital and financial markets;

• effects of changes in interest rates and currency exchange rates (primarily the Australian dollar);

• effects of acquisitions or divestitures;

• economic strength and political stability of countries in which we have operations or serve customers;

• legislation, regulations and court decisions or other government actions, including new environmental and mine safety requirements, changes in income tax regulations or other regulatory taxes;

• litigation, including claims not yet asserted;

• terrorist attacks or threats;

• impacts of pandemic illnesses; and

• other factors, including those discussed in Legal Proceedings, set forth in Item 3 of this report and Risk Factors, set forth in Item 1A of this report.

When considering these forward-looking statements, you should keep in mind the cautionary statements in this document and in our other Securities and Exchange Commission (SEC) filings. These forward-looking statements speak only as of the date on which such statements were made, and we undertake no obligation to update these statements except as required by the federal securities laws.

i

TABLE OF CONTENTS

		Page
PART I.
Item 1.	Business	2
Item 1A.	Risk Factors	16
Item 1B.	Unresolved Staff Comments	25
Item 2.	Properties	25
Item 3.	Legal Proceedings	33
Item 4.	Mine Safety Disclosures	33
	Executive Officers of the Company	35
PART II.
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	36
Item 6.	Selected Financial Data	37
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	39
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	58
Item 8.	Financial Statements and Supplementary Data	61
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	61
Item 9A.	Controls and Procedures	61
Item 9B.	Other Information	64
PART III.
Item 10.	Directors, Executive Officers and Corporate Governance	64
Item 11.	Executive Compensation	64
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	64
Item 13.	Certain Relationships and Related Transactions, and Director Independence	65
Item 14.	Principal Accounting Fees and Services	65
PART IV.
Item 15.	Exhibits, Financial Statement Schedules	65

1

Note:   The words “we,” “our,” “Peabody” or “the Company” as used in this report, refer to Peabody Energy Corporation or its applicable subsidiary or subsidiaries. Unless otherwise noted herein, disclosures in this Annual Report on Form 10-K relate only to our continuing operations.

PART I

Item 1.   Business.

History and Development of Business

Peabody Energy Corporation is the world’s largest private-sector coal company. We own interests in 30 coal mining operations, including a majority interest in 29 coal operations located in the United States (U.S.) and Australia and a 50% equity interest in the Middlemount Mine in Australia. We also own an equity interest in a joint venture mining operation in Venezuela. In addition to our mining operations, we market, broker and trade coal through our Trading and Brokerage segment.

We were incorporated in Delaware in 1998 and became a public company in 2001. Our history in the coal mining business dates back to 1883. Over the past decade, we have made strategic acquisitions and divestitures to position our company to serve the highest demand coal markets. Acquisitions and divestitures of note include the following.

• In 2006, we expanded our presence in Australia with the acquisition of Excel Coal Limited.

• In 2007, we spun off Patriot Coal Corporation (Patriot) through a dividend of all outstanding shares, which included mines in West Virginia and Kentucky.

• In 2011, we acquired Macarthur, an independent coal company in Australia, which included two operating mines, a 50% equity-affiliate joint venture arrangement and several development projects, along with coal reserves of approximately 213 million tons (approximately 142 million tons on an attributable basis).

In 2011, we continued advancing multiple organic growth projects in Australia and the U.S. that involved future mines, as well as the expansion and extension of existing mines. In 2012 and the near term, our plans for our mining operations include further investments in organic growth projects. In the U.S., development work is expected to begin on our new Gateway North Mine in Illinois and the new Twentymile Sage Creek portal that will serve as an extension of our Twentymile Mine in Colorado. In Australia, we will continue advancing multiple projects that are expected to increase our seaborne coal volumes over the next few years. We also plan to convert our Wilpinjong and Millennium mines in Australia from contract mining to owner-operated mines. In addition, the integration of Macarthur into our Australian operations will continue as we seek to realize synergies through blending, sales and marketing, administrative costs, purchasing, infrastructure and capital project development. We also plan to accelerate development of the new Codrilla Mine, a legacy Macarthur project, which is expected to produce first coal in late 2013.

Other future plans include the continued expansion of our global trading and brokerage platform, which will include the additional sourcing of coal of third-parties from offtake arrangements and joint venture arrangements. We will also continue to explore opportunities to expand our presence in the Asia-Pacific region, such as through partnerships with other companies to utilize our mining experience for joint mine development.

Our core strategies to achieve growth are:

1) Executing the basics of best-in-class safety, operations and marketing;

2) Capitalizing on organic growth opportunities; and

3) Expanding in high-growth global markets.

We are also participating in new generation and Btu Conversion technologies designed to expand the uses of coal technologies, including carbon capture and storage.

2

Segments

Our operations consist of four principal segments: our three mining segments and our Trading and Brokerage segment. Our three mining segments are Western U.S. Mining, Midwestern U.S. Mining and Australian Mining. Our fifth segment, Corporate and Other, includes mining and export/transportation joint ventures, energy-related commercial activities as well as the management of our coal reserve and real estate holdings.

Our Western U.S. Mining operations consist of our Powder River Basin, Southwest and Colorado mines. The mines in that segment are characterized by predominantly surface mining extraction processes and coal with a lower sulfur content and Btu. In addition, the customer transportation costs are generally higher due to longer shipping distances. Our Midwestern U.S. Mining operations include our mines in Illinois and Indiana, which are characterized by a mix of surface and underground mining extraction processes and coal with a higher sulfur content and Btu. In addition, the customer transportation costs are generally lower due to shorter shipping distances. The principal business of our U.S. mining operations is the sale of thermal (steam) coal, sold primarily to electric utilities in the U.S. with a portion sold into the seaborne markets.

Our Australian Mining operations consist of our mines in Queensland and New South Wales, Australia. The mines in that segment are characterized by both surface and underground extraction processes, mining various qualities of metallurgical (low-sulfur, high Btu coal) and thermal coal. The metallurgical coal qualities include hard coking coal, semi-hard coking coal, semi-soft coal and pulverized coal injection (PCI) coal. PCI coal is generally used by steel producers as a replacement for coke made from coking coal. Our recent acquisition of Macarthur increased our proven and probable reserves, which included low volatile PCI (LV PCI) coal, coking coal and thermal coal. Our Australian Mining operations are primarily export focused with customers spread across several countries, while a portion of our coal is sold to Australian steel producers and power generators. Generally, revenues from individual countries vary year by year based on the demand for electricity, the demand for steel, the strength of the global economy and several other factors including those specific to each country.

Financial information regarding our operating segments is contained in Note 25 to our consolidated financial statements.

Mining Segments

The maps that follow display our mine locations as of December 31, 2011, excluding mines held for sale. Also noted are the primary ports utilized in the U.S. and in Australia for our coal exports and our corporate headquarters.

U.S. Mining Operations

3

Australian Mining Operations

4

The table below presents information regarding each of our 30 mines (excluding mines held for sale), including mine location, type of mine, mining method, coal type, transportation method and tons sold in 2011. The mines are sorted by tons sold within each mining segment.

Mine	Location	Mine  Type	Mining  Method	Coal Type	Transport  Method	2011Tons Sold  (In millions)
Western U.S. Mining
North Antelope Rochelle	Wright, WY	S	DL, T/S	T	R	109.0
Caballo	Gillette, WY	S	D, T/S	T	R	24.2
Rawhide	Gillette, WY	S	D, T/S	T	R	15.0
El Segundo	Grants, NM	S	T/S	T	R	8.0
Kayenta	Kayenta, AZ	S	DL, T/S	T	R	7.9
Twentymile	Oak Creek, CO	U	LW	T	R, T	7.5
Lee Ranch	Grants, NM	S	DL, T/S	T	R	2.0
Midwestern U.S. Mining
Bear Run	Carlisle, IN	S	DL, D, T/S	T	T, R	6.5
Gateway	Coulterville, IL	U	CM	T	T, R, R/B	3.5
Francisco Underground	Francisco, IN	U	CM	T	R	3.0
Somerville Central	Oakland City, IN	S	DL, D, T/S	T	R, T/R, T/B	2.8
Willow Lake	Equality, IL	U	CM	T	T/B	2.2
Cottage Grove	Equality, IL	S	D, T/S	T	T/B	1.9
Wild Boar	Lynnville, IN	S	D, T/S	T	T, R, R/B	1.8
Somerville North (1)	Oakland City, IN	S	D, T/S	T	R, T/R, T/B	1.4
Viking — Corning Pit	Cannelburg, IN	S	D, T/S	T	T, T/R	1.4
Somerville South (1)	Oakland City, IN	S	D, T/S	T	R, T/R, T/B	1.2
Air Quality	Vincennes, IN	U	CM	T	T, T/R, T/B	1.2
Wildcat Hills Underground	Eldorado, IL	U	CM	T	T/B	1.0
Other (2)	—	—	—	—	—	2.4
Australian Mining
Wilpinjong *	Wilpinjong, New South Wales	S	T/S	T	R, EV	9.8
North Wambo Underground (1)	Warkworth, New South Wales	U	LW	T/P	R, EV	3.1
Wambo Open-Cut * (1)	Warkworth, New South Wales	S	T/S	T	R, EV	2.9
Burton *	Glenden, Queensland	S	T/S	T/M	R, EV	2.3
Millennium *	Moranbah, Queensland	S	T/S	M	R, EV	1.9
Metropolitan	Helensburgh, New South Wales	U	LW	M	R, EV	1.6
Eaglefield *	Glenden, Queensland	S	T/S	M	R, EV	1.6
North Goonyella	Glenden, Queensland	U	LW	M	R, EV	1.2
Coppabella (3)	Moranbah, Queensland	S	DL, T/S	P	R, EV	0.5
Moorvale * (3)	Moranbah, Queensland	S	T/S	T/M/P	R, EV	0.4
Middlemount (4)	Middlemount, Queensland	S	T/S	M/P	R, EV	-

Legend:
S	Surface Mine	R	Rail
U	Underground Mine	T	Truck
DL	Dragline	R/B	Rail and Barge
D	Dozer/Casting	T/B	Truck and Barge
T/S	Truck and Shovel	T/R	Truck and Rail
LW	Longwall	EV	Export Vessel
CM	Continuous Miner	T	Thermal/Steam
*	Mine is operated by a contract miner	M	Metallurgical
		P	Pulverized Coal Injection

⁽¹⁾  Represents mines that have non-controlling ownership interests.

⁽²⁾  “Other” in Midwestern U.S. Mining primarily consists of purchased coal used to satisfy certain coal supply agreements.

⁽³⁾  We own a 73.3% undivided interest in an unincorporated joint venture that owns the Coppabella and Moorvale mines. Tons sold is for the period from the date of the acquisition (October 26, 2011) to December 31, 2011.

⁽⁴⁾  We own a 50.0% equity interest in Middlemount Coal Pty Ltd., which owns the Middlemount Mine in Queensland, Australia that was acquired as part of the Macarthur acquisition.

5

 We also own a 48.37% interest in Carbones del Guasare S.A., which operates the Paso Diablo Mine, a surface operation in northwestern Venezuela that produces thermal coal.

See Item 2. “Properties” for additional information regarding coal reserves, coal characteristics and tons produced for each mine.

Trading and Brokerage Segment

We have a global coal trading and brokerage platform with trading and business offices in China, Australia, the United Kingdom, Singapore, Indonesia, Germany and the U.S. Through our Trading and Brokerage segment, we engage in the brokering of coal sales both as principal and agent in support of various coal production-related activities that may involve coal to be produced from our mines, coal sourcing arrangements with third-party mining companies or offtake agreements with producers. We also engage in the trading of coal, freight and freight-related contracts. We also provide transportation-related services in support of our coal trading strategy, as well as hedging activities in support of our mining operations.

Corporate and Other Segment

Our Corporate and Other Segment includes selling and administrative items, activity associated with our joint ventures, resource management activity, past mining obligations and our other commercial activities such as generation development and Btu Conversion development costs.

Resource Management.  We hold approximately 9.0 billion tons of proven and probable coal reserves and more than 500,000 acres of surface property. We have an ongoing asset optimization program where our resource development group regularly reviews these reserves for opportunities to generate earnings and cash flow through the sale of non-strategic coal reserves and surface land. In addition, we generate revenue through royalties from coal reserves and oil and gas rights leased to third parties and farm income from surface land under third-party contracts.

Export Facilities.  We have an interest in a coal export terminal in Newport News, Virginia that exports both metallurgical and thermal coal primarily to European and Brazilian markets.

Generation Development.  We are a 5.06% owner in the Prairie State Energy Campus (Prairie State), a 1,600 megawatt coal-fueled electricity generation project. We are responsible for our 5.06% share of costs and marketing and selling of our share of electricity generated by the facility. The first unit began operations in 2011 and the second unit is expected to commence operations in 2012.

Btu Conversion. Btu Conversion involves projects designed to expand the uses of coal through coal-to-liquids (CTL) and coal gasification technologies. We own an equity interest in GreatPoint Energy, Inc., which is commercializing its coal-to-pipeline quality natural gas technology. We also are pursuing a project with the government of Inner Mongolia and other Chinese partners to explore development opportunities for a large surface mine and downstream coal gasification facility that would produce methanol, chemicals or fuel products.

Clean Coal Technology.  We continue to support clean coal technology development and other “green coal” initiatives seeking to reduce global atmospheric levels of carbon dioxide and other emissions. We are the only non-Chinese equity partner in GreenGen, which is constructing a near-zero emissions coal-fueled power plant with carbon capture and storage (CCS) near Tianjin, China and is expected to begin operations during 2012. In Australia, we have an ongoing commitment to the Australian COAL21 Fund designed to support clean coal technology demonstration projects and research in Australia.

We are also a founding member of the Global Carbon Capture and Storage Institute, an international initiative to accelerate commercialization of CCS technologies through development of 20 integrated, industrial-scale demonstration projects, as well as a participant in the Power Systems Development Facility, the PowerTree Carbon Company LLC, the Midwest Geopolitical Sequestration Consortium, the Asia-Pacific Partnership for Clean Development and Climate, the U.S.-China Energy Cooperation Program, the Consortium for Clean Coal Utilization, the National Carbon Capture Center and the Western Kentucky Carbon Storage Foundation.

6

Mongolia Joint Venture.  We own a 50% interest in Peabody-Winsway Resources B.V., a joint venture agreement with Winsway Coking Coal Holding Ltd. (Winsway), a Hong Kong stock exchange listed company. The joint venture is in the development stage and plans to ship metallurgical and thermal coal to Asian markets once developed. In 2011, we acquired a 5.1% equity interest in Winsway further strengthening the strategic partnership between the two companies.

Paso Diablo Mine.  We own a 48.37% interest in Carbones del Guasare S.A., which operates the Paso Diablo Mine, a surface operation in northwestern Venezuela that produces thermal coal for export primarily to the U.S. and Europe. We are responsible for marketing our pro-rata share of sales from Paso Diablo; the joint venture is responsible for production, processing and transportation of coal to ocean-going vessels for delivery to customers.

Middlemount Mine.  Through the acquisition of Macarthur, we own a 50% interest in the Middlemount Mine. The mine development was completed in late 2011 and test coal shipments to customers are ongoing. The mine is expected to reach full production in 2012.

Captive Insurance Entity.  A portion of our insurance risks associated with workers’ compensation, general liability and auto liability coverage is self-insured through a wholly-owned captive insurance company. The captive entity invoices certain of our subsidiaries for the premiums on these policies, pays the related claims, maintains reserves for anticipated losses and invests funds to pay future claims.

Coal Supply Agreements

Our coal supply agreements are primarily with electricity generators, industrial facilities and steel manufacturers. Most of our sales (excluding trading transactions) are made under long-term coal supply agreements (those with terms longer than one year). Sales under such agreements comprised approximately 91%, 91% and 93% of our worldwide sales (by volume) for the years ended December 31, 2011, 2010 and 2009, respectively.

For the year ended December 31, 2011, we derived 23% of our total coal sales revenues from our five largest customers. Those five customers were supplied primarily from 24 coal supply agreements (excluding trading transactions) expiring at various times from 2012 to 2025. The contract contributing the greatest amount of annual revenue in 2011 was approximately $311 million, or approximately 4% of our 2011 total revenue base and is due to expire in 2019.

Our sales backlog includes coal supply agreements subject to price reopener and/or extension provisions. As of January 31, 2012 and 2011, we had a sales backlog of over 1 billion tons of coal. Contracts in backlog have remaining terms ranging from one to 16 years, representing over four years of production based on our 2011 production of 227.5 million tons. As of January 31, 2012, approximately 78% of our backlog is expected to be filled beyond one year.

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. Revenue from our Australian Mining segment represented approximately 39%, 36% and 26% of our total revenue base for the years ended December 31, 2011, 2010 and 2009, respectively. Our Australian coal mining activities accounted for 11%, 12% and 9% of our mining operations sales volume in 2011, 2010 and 2009, respectively. Production is sold primarily into the export metallurgical and thermal markets. Historically, we predominately entered into multi-year international coal agreements that contained provisions allowing either party to commence a renegotiation of the agreement price annually in the second quarter of each year. Current industry practice, and our practice, is to negotiate pricing for metallurgical coal contracts quarterly and seaborne thermal coal contracts annually.

7

Transportation

Coal consumed in the U.S. is usually sold at the mine with transportation costs borne by the purchaser. Australian and U.S. export coal is usually sold at the loading port, with purchasers paying ocean freight. Producers usually pay shipping costs from the mine to the port, including any demurrage costs (fees paid to third-party shipping companies for loading time that exceeded the stipulated time). Demurrage continues to be part of the shipping costs for our Australian exports as certain ports continue to experience vessel queues due to factors such as lower than expected rail performance, supply constraints, adverse weather and delays in coal availability from time-to-time with those with whom we share vessels (co-shippers).

We believe we have good relationships with U.S. and Australian rail carriers and barge companies due, in part, to our modern coal-loading facilities and the experience of our transportation coordinators. See the table on page 5 for transportation methods by mine.

Our primary ports used for U.S. exports are the Dominion Terminal Associates coal terminal in Newport News, Virginia, the United Bulk Terminal near New Orleans, Louisiana and the Kinder Morgan terminal near Houston, Texas. Our U.S. mining operations exported approximately 3%, 1% and 1% of its tons sold for the years ended December 31, 2011, 2010 and 2009, respectively.

In Australia, we own interests in three east coast coal export terminals that are primarily funded through take-or-pay arrangements (see "Liquidity and Capital Resources" for additional information). In Queensland, seaborne metallurgical and thermal coal from our mines, including the Coppabella and Moorvale mines added with the acquisition of Macarthur, is exported through the Dalrymple Bay Coal Terminal. Our joint venture Middlemount Mine is ramping up operations with shipments sent through both Dalrymple Bay Coal Terminal and the Abbot Point Coal Terminal in Queensland, Australia. In New South Wales, our primary ports for exporting metallurgical and thermal coal are at Port Kembla and Newcastle, which includes both the Port Waratah Coal Services terminal and the terminal operated by Newcastle Coal Infrastructure Group (NCIG) that opened in 2010. Our Australian mining operations sold approximately 74%, 71% and 69% of its tons into the seaborne coal markets for the years ended December 31, 2011, 2010 and 2009.

We are also currently pursuing a U.S. west coast port facility that will allow us to export Powder River Basin coal to Asian markets. In Australia, we are exploring potential participation in the development of the Wiggins Island Coal Export Terminal at Gladstone, Queensland, as well as proposed expansion projects at the Abbot Point Coal Terminal.

Suppliers

The main types of goods we purchase in support of our mining activities are mining equipment and replacement parts, diesel fuel, ammonium-nitrate and emulsion-based explosives, off-the-road (OTR) tires, steel-related (including roof control materials) products, lubricants and electricity. For some of these goods, there has been some consolidation in the supplier base providing mining materials to the coal industry, such as with suppliers of explosives and both surface and underground equipment, that has limited the number of sources for these materials. In situations where we have chosen to concentrate a large portion of purchases with one supplier, it has been to take advantage of cost savings from larger volumes of purchases, to benefit from long-term pricing for parts and to ensure security of supply.

Demand and lead times for certain surface and underground mining equipment and OTR tires has increased. Despite these market challenges, we do not expect lead times to have a near-term material impact on our financial condition, results of operations or cash flows due to the strategic relationships and long-term supply contracts we have with our suppliers. In addition, we continue to use our global leverage with major suppliers to ensure security of supply to meet the requirements of our growth plans. We have many well-established, strategic relationships with our key suppliers of goods and do not believe we are overly dependent on any of our individual suppliers.

We also purchase services at our mine sites that include maintenance services for mining equipment, temporary labor and other various contracted services, including contract miners and explosive service providers. We do not believe that we are overly dependent on any of our individual service providers.

8

Technical Innovation

We continue to emphasize the application of technical innovation to improve equipment performance and operating efficiencies. Development is typically undertaken and funded by equipment manufacturers with our engineering, maintenance and purchasing personnel providing input and expertise to the manufacturers that will design and produce equipment that we believe will add value to the business. Some examples of these efforts include the following:

• Ultra class haul trucks to increase overburden removal capacity and lower mining cost;

• Fleet management and vehicle diagnostics systems to enhance equipment availability;

• Expanded networking and server capacity to gather detailed information on both production and vehicle diagnostics to allow for real time alerts and long term analysis used to improve production and reduce downtime; and

• Longwall automation technology to allow for more efficient longwall mining.

We use maintenance standards based on reliability-centered maintenance practices at all operations to increase equipment utilization and reduce maintenance and capital spending by extending the equipment life, while minimizing the risk of premature failures. Specialized maintenance reliability software is used at many operations to better support improved equipment strategies, predict equipment condition and aid analysis necessary for better decision-making for such issues as component replacement timing. We also use in-house developed software to schedule and monitor trains, mine and pit blending, quality and customer shipments to enhance our reliability and product consistency.

We also continue to advance new technologies to maximize safety. We are currently in process with a pilot program for a new proximity detection system at a section of one of our underground mines that is designed to automatically stop a continuous miner and coal hauler if a person is detected within the operating range. In addition, personnel tracking systems were deployed across all underground operations in the U.S. which can provide continuous real time locations of workers underground.

Competition

The markets in which we sell our coal are highly competitive. We compete on the basis of coal quality, delivered price, customer service and support and reliability. Demand for coal and the prices that we will be able to obtain for our coal are influenced by factors beyond our control, including the demand for electricity and steel and the availability and price of alternatives. Our principal U.S. competitors (listed alphabetically) are other large coal producers, including Alpha Natural Resources, Inc., Arch Coal, Inc., Cloud Peak Energy Inc., and CONSOL Energy Inc., which collectively accounted for approximately 40% of total U.S. coal production in 2010 (most recent publicly available data according to the National Mining Association's “2010 Coal Producer Survey”). Major international competitors (listed alphabetically) include Anglo-American PLC, BHP Billiton, China Coal, Rio Tinto, Shenhua Group and Xstrata PLC.

Employees

As of December 31, 2011, we had approximately 8,300 employees, which included approximately 5,600 hourly employees. As of such date, approximately 24% of our hourly employees were represented by organized labor unions and generated 7% of 2011 coal production. In the U.S., those represented by organized labor unions include hourly workers at our Kayenta Mine in Arizona and at our Willow Lake Mine in Illinois. In Australia, the coal mining industry is highly unionized and the majority of workers employed at our mining operations are members of trade unions. The Construction Forestry Mining and Energy Union represents our Australian hourly production and engineering employees, including those employed through contract mining relationships. All the Australian mine sites have enterprise bargaining agreements. Additional information on labor relations is contained in Note 21 to our consolidated financial statements.

Working Capital

We generally fund our business operations through a combination of available cash and cash equivalents and operating cash flow. In addition, our revolving credit facility (Revolver) available under our senior unsecured credit facility entered into in 2010 (Credit Facility) and our accounts receivable securitization program are available for additional working capital needs. See Liquidity and Capital Resources in Part II, Item 7 for additional information regarding working capital.

9

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 our violations to date or the monetary penalties assessed have been material.

Mine Safety and Health.  We are subject to health and safety standards both at the federal and state level. The regulations are comprehensive and affect numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, the equipment used in mining operations and other matters.

The Mine Safety and Health Administration (MSHA) is the entity responsible for monitoring compliance with the federal mine health and safety standards. MSHA has various enforcement tools that it can use, including the issuance of monetary penalties and orders of withdrawal from a mine or part of a mine. Some, but not all, of the costs of complying with existing regulations and implementing new safety and health regulations may be passed on to customers.

MSHA has recently taken a number of actions to identify mines with safety issues, and has engaged in a number of targeted enforcement, awareness, outreach and rulemaking activities to reduce the number of mining fatalities, accidents and illnesses. There has also been an industry-wide increase in the monetary penalties assessed for citations of a similar nature.

In Item 4. Mine Safety Disclosure and in Exhibit 95 to this Annual Report on Form 10-K, we provide additional details on how we monitor safety performance and MSHA compliance, as well as provide the mine safety disclosures required pursuant to Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd-Frank Act).

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.

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.

10

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 created by the Coal Industry Retiree Health Benefit Act of 1992. 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 waters of the U.S., including wetlands, and the U.S. Bureau of Alcohol, Tobacco and Firearms regulates the use of explosive blasting materials.

We do not believe there are any matters that pose a material risk to maintaining our existing mining permits or that materially hinder our ability to secure future mining permits. It is our policy to comply with the requirements of the SMCRA and the state and tribal laws and regulations governing mine reclamation.

Clean Air Act. The Clean Air Act and the comparable state laws that regulate the emissions of materials into the air affect U.S. coal mining operations both directly and indirectly. Direct impacts on coal mining and processing operations may occur through the Clean Air Act permitting requirements and/or emission control requirements relating to particulate matter. It is possible that the more stringent national ambient air quality standards (NAAQS) will directly impact our mining operations by, for example, requiring additional controls of emissions from our mining equipment and vehicles. Moreover, if the areas in which our mines and coal preparation plants are located suffer from extreme weather events such as droughts, or are designated as non-attainment areas, we could be required to incur significant costs to install additional emissions control equipment, or otherwise change our operations and future development. In addition, in September 2009 the EPA adopted new rules tightening and adding additional particulate matter emissions limits for coal preparation and processing plants constructed, reconstructed or modified after April 28, 2008.

The Clean Air Act indirectly, but more significantly, affects the coal industry by extensively regulating the air emissions of sulfur dioxide, nitrogen oxides, mercury, particulate matter and other substances emitted by coal-based electricity generating plants. Air emissions programs that may affect our operations, directly or indirectly, include, but are not limited to, the Acid Rain Program, NOx SIP Call, the Clean Air Interstate Rule (CAIR), New Source Performance Standards (NSPS), Maximum Achievable Control Technology (MACT) emissions limits for Hazardous Air Pollutants, the Regional Haze program and New Source Review. In addition, in recent years the EPA has adopted more stringent NAAQS for particulate matter, nitrogen oxide and sulfur dioxide. The EPA has also proposed a more stringent ozone standard but withdrew it last year; the ozone standard is due for reconsideration in 2013. Many of these programs and regulations have resulted in litigation which has not been completely resolved.

On July 6, 2011, the EPA finalized its final Cross State Air Pollution Rule (CSAPR) to address interstate transport of emissions from coal-based electrical generation plants. The rule, which was developed to replace CAIR and includes a supplemental rulemaking finalized on December 15, 2011, imposes state-by state budgets on nitrogen oxides and sulfur dioxide emissions from coal-based electrical generation plants in 23 states from Texas eastward (not including the New England states or Delaware) and provides for an allowance trading program to meet those budgets. While CSAPR has an initial compliance deadline of January 1, 2012, the rule was challenged and on December 30, 2011, the U.S. Court of Appeals for the District of Columbia stayed CSAPR and advised that the EPA is expected to continue administering CAIR until the pending challenges are resolved. Expedited briefing on the merits of the challenge is underway.

On December 16, 2011, the EPA issued the Mercury and Air Toxic Standards which imposes MACT emission limits on hazardous air emissions from new and existing coal-based electric generating plants. The rule also revised NSPS for nitrogen oxides, sulfur dioxides and particulate matter for coal-based electricity generating plants. The rule provides three years for compliance, or up to four years for existing sources if necessary. We believe that challenges to this rule are likely.

In December 2009, the EPA published its finding that atmospheric concentrations of greenhouse gases endanger public health and welfare within the meaning of the Clean Air Act, and that emissions of greenhouse gases from new motor vehicles and new motor vehicle engines are contributing to air pollution that are endangering public health and welfare within the meaning of the Clean Air Act. In May 2010, the EPA published final greenhouse gas emission standards for new motor vehicles pursuant to the Clean Air Act. Both the endangerment finding and motor vehicle standards are the subject of litigation.

11

Because the Clean Air Act specifies that the prevention of significant deterioration (PSD) program applies once emissions of regulated pollutants exceed either 100 or 250 tons per year (depending on the type of source), millions of sources previously unregulated under the Clean Air Act could be subject to greenhouse gas reduction measures. The EPA published a rule in June 2010 to limit the number of greenhouse gas sources that would be subject to the PSD program. In the so-called “tailoring rule,” the EPA limited the regulation of greenhouse gases from certain stationary sources to those that emit more than 75,000 tons of greenhouse gases per year (for sources that would be subject to PSD permitting regardless of greenhouse gas emissions due to other emissions) or 100,000 tons of greenhouse gases per year (for sources not subject to PSD permitting for any other air emissions), measured by “carbon dioxide equivalent.” Whether the EPA has the statutory authority under the Clean Air Act to adopt the tailoring rule is the subject of litigation.

In December 2010, the EPA announced a settlement with states and environmental groups that had filed litigation challenges to the EPA's decisions not to establish greenhouse gas emission standards for fossil fuel-fired power plants and for petroleum refineries under section 111 of the Clean Air Act. In the settlement, the EPA agreed: (1) to sign proposed new source performance standards for new and modified electric utility steam generating units under section 111(b), as well as proposed guidelines for states' development of emission standards for existing electric utility steam generating units under section 111(d), by July 26, 2011; and (2) to take final action on the proposed section 111(b) standards and section 111(d) guidelines by May 26, 2012. The EPA has not yet proposed these rules. Whatever the EPA determines the new source performance standards to be, this will then be the minimum requirement for best available control technology requirements under the PSD program.

Clean Water Act. The Clean Water Act of 1972 affects U.S. coal mining operations by requiring both technology-based and, if necessary, water quality-based effluent limitations and treatment standards for wastewater 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 from mine-related point sources into water. Section 404 of 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 apply “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 their water quality standards and other applicable requirements in deciding whether or not to certify the activity.

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 waste guidelines for coal combustion materials placed at a mine. National guidelines for mine-fills may affect the cost of ash placement at mines. The EPA revisited its May 2000 determination and proposed new requirements for coal combustion residue (CCR) management on June 21, 2010. That proposal contains two options: (1) to continue to regulate CCR as a non-hazardous waste, or (2) to regulate CCR as special waste under the hazardous waste regulations.

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.

12

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 affected 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.

Use of Explosives. Our surface mining operations are subject to numerous regulations relating to blasting activities. Pursuant to these regulations, we incur costs to design and implement blast schedules and to conduct pre-blast surveys and blast monitoring. In addition, the storage of explosives is subject to strict federal regulatory requirements.

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 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. There is also federal and state legislation to prevent damage to Aboriginal cultural heritage and archaeological sites.

Mining Tenements and Environmental.  In Queensland and New South Wales, the development of a mine requires both the grant of a right to impact the environment and an approval which authorizes the environmental impact. These approvals are obtained under separate legislation from separate government authorities. However, the application processes run concurrently and are also concurrent with any native title or cultural heritage process that is required. The environmental impacts of mining projects are regulated by state and federal governments. Federal regulation will only apply if the particular project will significantly impact a matter of national environmental significance (e.g., endangered species or particular protected places). If so, it will also be regulated by the federal government.

Occupational Health and Safety.  The combined effect of various state and federal statutes requires an employer to ensure that persons employed in a mine are safe from injury by providing a safe working environment and systems of work; safety machinery; equipment, plant and substances; and appropriate information, instruction, training and supervision. Currently all states and territories are responsible for making and enforcing their own laws. Although these draw on a similar approach for regulating workplaces, there are some differences in the application and detail of the laws. Mining legislation is currently being harmonized across Australia with a January 1, 2013 target date. The harmonization process will be achieved first by developing core legislation that will be consistent across all of the states; the remainder of each states' legislation may be state specific. The finalized core legislation is expected to be completed by July 1, 2012.

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.

Industrial Relations.  A national industrial relations system administered by the federal government applies to all private sector employers and employees. The system largely became operational in July 2009 and fully operational in January 2010. The matters regulated under the national system include employment conditions, unfair dismissal, enterprise bargaining, industrial action and resolution of workplace disputes.

13

National Greenhouse and Energy Reporting Act 2007 (NGER Act).  The NGER Act introduces a single national reporting system relating to greenhouse gas emissions and energy production and consumption, which will underpin a future emissions trading scheme. The NGER Act imposes requirements for certain corporations to report greenhouse gas emissions and abatement actions, as well as energy production and consumption. Both foreign and local corporations that meet the prescribed CO2 and energy production or consumption limits in Australia (controlling corporations) must comply with the NGER Act. One of our subsidiaries is now registered as a controlling corporation and must report each financial year about the greenhouse gas emissions and energy production and consumption of our Australian entities.

Carbon Pricing Framework. In the fourth quarter of 2011, the Australian government passed a legislative package that included a carbon pricing framework that commences July 1, 2012. The carbon price will initially be $23.00 Australian dollars per tonne of carbon dioxide equivalent emissions, escalated by 2.5% per year for inflation over a three year period. After June 30, 2015, the carbon price mechanism will transition to an emissions trading scheme. We believe that all of our Australian operations will be impacted by the fugitive emissions portion of the framework (defined as the methane and carbon dioxide which escapes into the atmosphere when coal is mined and gas is produced), which we estimate will initially average $2.00 to $3.25 Australian dollars per tonne of coal produced annually. Actual results will be dependent upon the volume of tons produced at each of our mining locations as the impact per tonne at our surface mines will generally be less than the impact per tonne at our underground mines. In addition, our Australian mines will be impacted by the phased reduction of the government's diesel fuel rebate to capture emissions from fuel combustion. Our North Goonyella, Wambo and Metropolitan mines will be eligible to apply for a portion of the government's approximately $1.3 billion Australian dollars of transition benefits that would provide assistance based on historical emissions intensity data to the most emissions-intensive coal mines over a six-year period.

Regulatory Matters — Mongolia

As noted above, we currently own a 50% interest in the Peabody-Winsway Resources B.V. joint venture, which holds coal and mineral interests in Mongolia and is regulated by Mongolian federal, provincial and local governments with respect to exploration, development, production, occupational health, mine safety, water use, environmental protection and remediation, foreign investment and other related matters. The Mineral Resources Authority of Mongolia is the government agency with the authority to issue, extend and revoke mineral licenses, which generally give the license holder the right to engage in the mining of minerals within the license area for 30 years (with the right to extend for two additional periods of 20 years). Mongolian law provides for state participation in the exploitation of any mineral deposit of “strategic importance,” as determined by the Mongolian Parliament.

Global Climate

In the U.S., Congress has considered legislation addressing global climate issues and greenhouse gas emissions, but to date nothing has been enacted. While it is possible that the U.S. will adopt legislation in the future, the timing and specific requirements of any such legislation are uncertain. In the absence of new U.S. federal legislation, the EPA is undertaking steps to regulate greenhouse gas emissions pursuant to the Clean Air Act. In response to the 2007 U.S. Supreme Court ruling in Massachusetts v. EPA, the EPA has commenced several rulemaking projects as described above under “Regulatory Matters-U.S. - Clean Air Act.”

A number of states in the U.S. have adopted programs to regulate greenhouse gas emissions. For example, ten northeastern states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island and Vermont) entered into the Regional Greenhouse Gas Initiative (RGCI) in 2005, which is a mandatory cap-and-trade program to cap regional carbon dioxide emissions from power plants. In 2011, New Jersey announced its withdrawal from RGGI effective January 1, 2012. Six midwestern states (Illinois, Iowa, Kansas, Michigan, Minnesota and Wisconsin) and one Canadian province have entered into the Midwestern Regional Greenhouse Gas Reduction Accord (MGGRA) to establish voluntary regional greenhouse gas reduction targets and develop a voluntary multi-sector cap-and-trade system to help meet the targets, though in the past year the group's website has been taken down and a senior official in the Midwestern Governors Association reported in February 2011 that the program was “effectively abandoned,” according to the press. Seven western states (Arizona, California, Montana, New Mexico, Oregon, Utah and Washington) and four Canadian provinces entered into the Western Climate Initiative (WCI) in 2008 to establish a voluntary regional greenhouse gas reduction goal and develop market-based strategies to achieve emissions reductions. However, in November 2011 the WCI announced that six states had withdrawn from the WCI, leaving California and four Canadian provinces as the remaining members. As of early 2012, only California and Quebec have adopted greenhouse gas cap-and-trade regulations and intend to move forward with a regional trading program. Due to litigation and other delays, the regional trading program is not scheduled to commence until January 1, 2013. Other participants in WCI, RGGI and MGGRA have either left those organizations entirely or have joined the new North America 2050 organization which seeks to address energy and climate issues in other ways.

14

In 2006, the California legislature approved legislation allowing the imposition of statewide caps on carbon dioxide emissions. Similar legislation was adopted in 2007 in Hawaii, Minnesota and New Jersey. The California Air Resources Board is in the process of finalizing regulations to implement a cap-and-trade program pursuant to the 2006 legislation, and that program started on January 1, 2012 with an enforceable compliance obligation beginning with the 2013 greenhouse gas emissions.

In the U.S., several states have enacted legislation requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power or that provide financial incentives to electricity suppliers for using renewable energy sources.

We participated in the DOE's Voluntary Reporting of Greenhouse Gases Program until its suspension in May 2011, and regularly disclose the quantity of emissions per ton of coal produced by us in the U.S. The vast majority of our emissions are generated by the operation of heavy machinery to extract and transport material at our mines.

The Kyoto Protocol, adopted in December 1997 by the signatories to the 1992 United Nations Framework Convention on Climate Change, established a binding set of emission targets for developed nations. The U.S. signed the Kyoto Protocol but it was not ratified by the U.S. Senate. Australia ratified the Kyoto Protocol in December 2007 and became a full member in March 2008. There are continuing discussions to develop a treaty to replace the Kyoto Protocol after its expiration in 2012, including at the Cancun meetings in late 2010 and initial steps toward that goal were taken and at the Durban meeting in late 2011. At the Durban meeting it was agreed that the Kyoto Protocol would have a second commitment period, from 2013 to 2017, but no further actions were agreed upon.

Australia's Parliament passed carbon pricing legislation in November 2011. The first three years of the program involve the imposition of a carbon tax commencing in July 2012, and a mandatory greenhouse gas emissions trading program commencing in 2015. However, the program is a central issue in current election debates.

Enactment of laws or passage of regulations by the U.S. or some of its states or by other countries regarding emissions from the mining of coal or other actions to limit such emissions, are not expected to have a material adverse effect on our results of operations, financial condition or cash flows.

Enactment of laws or passage of regulations by the U.S. or some of its states or by other countries regarding emissions from the combustion of coal or other actions to limit such emissions, could result in electricity generators switching from coal to other fuel sources. The potential financial impact on us of recent or future laws or regulations will depend upon the degree to which any such laws or regulations forces electricity generators to diminish their reliance on coal as a fuel source. That, in turn, will depend on a number of factors, including the specific requirements imposed by any such laws or regulations, the time periods over which those laws or regulations would be phased in, the state of commercial development and deployment of CCS technologies and the alternative markets for coal. In view of the significant uncertainty surrounding each of these factors, it is not possible for us to reasonably predict the impact that any such laws or regulations may have on our results of operations, financial condition or cash flows.

Additional Information

We file annual, quarterly and current reports, and any amendments to those reports, proxy statements and other information with the SEC. You may access and read our SEC filings free of charge through our website, at www.peabodyenergy.com, or the SEC’s website, at www.sec.gov. Information on such websites does not constitute part of this document. You may also read and copy any document we file at the SEC’s public reference room located at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room.

You may also request copies of our filings, free of charge, by telephone at (314) 342-3400 or by mail at: Peabody Energy Corporation, Peabody Plaza, 701 Market Street, Suite 900, St. Louis, Missouri 63101, attention: Investor Relations.

15

Item 1A.   Risk Factors.

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

Risks Associated with Our Operations

A decline in coal prices could negatively affect our profitability.

Our profitability depends upon the prices we receive for our coal. Coal prices are dependent upon factors beyond our control, including:

• the strength of the global economy;

• the demand for electricity;

• the demand for steel, which may lead to price fluctuations in the periodic repricing of our metallurgical coal contracts;

• the global supply of thermal and metallurgical coal;

• weather patterns and natural disasters;

• competition within our industry and the availability and price of alternatives, including natural gas;

• the proximity, capacity and cost of transportation;

• coal industry capacity;

• domestic and foreign governmental regulations and taxes, including those establishing air emission standards for coal-fueled power plants or mandating increased use of electricity from renewable energy sources;

• regulatory, administrative and judicial decisions, including those affecting future mining permits; and

• technological developments, including those intended to convert coal-to-liquids or gas and those aimed at capturing and storing carbon dioxide.

In the U.S., 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. In Australia, current industry practice, and our practice, is to negotiate pricing for metallurgical coal contracts quarterly and seaborne thermal coal contracts annually.

If a substantial number of our long-term coal supply agreements terminate, our revenues and operating profits could suffer if we are unable to find alternate buyers willing to purchase our coal on comparable terms to those in our contracts.

Most of our sales are made under coal supply agreements, which are important to the stability and profitability of our operations. The execution of a satisfactory coal supply agreement is frequently the basis on which we undertake the development of coal reserves required to be supplied under the contract, particularly in the U.S. In 2011, 91% of our worldwide sales volume was sold under long-term coal supply agreements. At January 31, 2012, our sales backlog, including backlog subject to price reopener and/or extension provisions, was over 1 billion tons, representing over four years of current production in backlog based on our 2011 production from continuing operations of 227.5 million tons. Contracts in backlog have remaining terms ranging up to 16 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 of our 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 restrict the use or type of coal permissible at the customer’s plant or increases the price of coal beyond specified limits.

16

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 provide assurance 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, 2011 we derived 23% of our total coal sales revenues from our five largest customers. Those five customers were supplied primarily from 24 coal supply agreements (excluding trading transactions) expiring at various times from 2012 to 2025. The contract contributing the greatest amount of annual revenue in 2011 was approximately $311 million, or approximately 4% of our 2011 total revenue base. 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 operating results could be adversely affected by unfavorable economic and financial market conditions.

In recent years, the global economic recession and the worldwide financial and credit market disruptions had a negative impact on us and on the coal industry generally. If any of these conditions return or if there are downturns in economic conditions, particularly in developing countries such as China and India, our business, financial condition or results of operations could be adversely affected. While we are focused on cost control, productivity improvements, increased contributions from our high-margin operations and capital discipline, there can be no assurance that these actions, or any others we may take, will be sufficient in response to downturns in economic and financial conditions.

Our ability to collect payments from our customers could be impaired if their creditworthiness deteriorates.

Our ability to receive payment for coal sold and delivered or for financially settled contracts depends on the continued creditworthiness of our customers and counterparties. Our customer base has changed with deregulation in the U.S. as utilities have sold their power plants to their non-regulated affiliates or third parties, and with our continued expansion in the Asia-Pacific region. These new customers may have credit ratings that are below investment grade or not rated. If deterioration of the creditworthiness of our customers occurs, our accounts receivable securitization program and our business could be adversely affected.

Risks inherent to mining could increase the cost of operating our business.

Our mining operations are subject to conditions that can impact the safety of our workforce, or delay coal deliveries or increase the cost of mining at particular mines for varying lengths of time. These conditions include fires and explosions from methane gas or coal dust; accidental minewater discharges; weather, flooding and natural disasters; unexpected maintenance problems; key equipment failures; variations in coal seam thickness; variations in the amount of rock and soil overlying the coal deposit; variations in rock and other natural materials and variations in geologic conditions. We maintain insurance policies that provide limited coverage for some of these risks, although there can be no assurance that these risks would be fully covered by our insurance policies. Despite our efforts, significant mine accidents could occur and have a substantial impact on our results of operations, financial condition or cash flows.

If transportation for our coal becomes unavailable or uneconomic for our customers, our ability to sell coal could suffer.

Transportation costs represent a significant portion of the total cost of coal and the cost of transportation is a critical factor in a customer’s purchasing decision. Increases in transportation costs and the lack of sufficient rail and port capacity could lead to reduced coal sales. As of December 31, 2011, 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.

17

We depend upon rail, barge, trucking, overland conveyor and ocean-going vessels to deliver coal to markets. While our coal customers typically arrange and pay for transportation of coal from the mine or port to the point of use, disruption of these transportation services because of weather-related problems, infrastructure damage, strikes, lock-outs, lack of fuel or maintenance items, underperformance of the port and rail infrastructure, congestion and balancing systems which are imposed to manage vessel queuing and demurrage, non-performance or delays by co-shippers, 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.

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, fuel, explosives, tires, steel-related products (including roof control materials), lubricants and electricity. There has been some consolidation in the supplier base providing mining materials to the coal industry, such as with suppliers of explosives and both surface and underground equipment, that has limited the number of sources for these materials. In situations where we have chosen to concentrate a large portion of purchases with one supplier, it has been to take advantage of cost savings from larger volumes of purchases and to ensure security of supply. 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 or we could experience a delay or halt in our production.

An inability of trading, brokerage, mining or freight sources to fulfill the delivery terms of their contracts with us could reduce our profitability.

In conducting our trading, brokerage and mining operations, we utilize third-party sources of coal production and transportation, including contract miners and brokerage sources, to fulfill deliveries under our coal supply agreements. In Australia, the majority of our volume comes from mines that utilize contract miners. Employee relations at mines that use contract miners are 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 weather, flooding, natural disasters or adverse geologic mining conditions restrict deliveries from our suppliers, our willingness to participate in temporary cost increases experienced by our third-party coal suppliers, our ability to pass on temporary cost increases to our customers, the ability to substitute, when economical, third-party coal sources with internal production or coal purchased in the market and the ability of our freight sources to fulfill their delivery obligations. Market volatility and price increases for coal or freight on the international and domestic markets could result in non-performance by third-party suppliers under existing contracts with us, in order to take advantage of the higher prices in the current market. Such non-performance could have an adverse impact on our ability to fulfill deliveries under our coal supply agreements.

Our trading and hedging activities may expose us to earnings volatility and other risks.

We enter into hedging arrangements designed primarily to manage market price volatility of foreign currency (primarily the Australian dollar), diesel fuel and explosives. Also, from time to time, we manage the interest rate risk associated with our variable and fixed rate borrowings using interest rate swaps. Generally, we attempt to designate hedging arrangements as cash flow hedges with gains or losses recorded as a separate component of stockholders’ equity until the hedged transaction occurs (or until hedge ineffectiveness is determined). While we utilize a variety of risk monitoring and mitigation strategies, those strategies require judgment and they cannot anticipate every potential outcome or the timing of such outcomes. As such, there is potential for these hedges to no longer qualify for hedge accounting. If that were to happen, we will be required to recognize the mark to market movements through current year earnings, possibly resulting in increased volatility in our income in future periods. In addition, to the extent that we engage in hedging activities, we may be prevented from realizing the benefits of future price decreases of foreign currency, diesel fuel and explosives.

We also enter into derivative trading instruments, some of which require us to post margin based on the value of those instruments and other credit factors. If our credit is downgraded, the fair value of our hedge positions move significantly, or laws or regulations are passed requiring all hedge arrangements to be exchange-traded or exchange-cleared, we could be required to post additional margin, which could impact our liquidity.

18

Through our trading and hedging activities, we are also exposed to the nonperformance and credit risk with various counterparties, including exchanges and other financial intermediaries. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements, which could negatively impact our profitability and/or liquidity. In addition, some of our trading and brokerage activities include an increasing number of exchange-settled transactions, which exposes us to the margin requirements of the exchange for daily changes in the value of our positions. If there are significant and extended unfavorable price movements against our positions, or if there are future regulations that impose new margin requirements, position limits and capital charges, even if not directly applicable to us, our liquidity could be impacted.

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

We manage our business with a number of key personnel, the loss of whom could have a material adverse effect on us. In addition, as our business develops and expands, we believe that our future success will depend greatly on our continued ability to attract and retain highly skilled and qualified personnel, particularly personnel with mining experience. We cannot provide assurance 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, 2011, we had approximately 8,300 employees, which included approximately 5,600 hourly employees. Approximately 24% of our hourly employees were represented by organized labor unions and generated 7% of 2011 coal production. Additionally, those employed through contract mining relationships in Australia are also members of trade unions. Relations with our employees and, where applicable, organized labor are important to our success. If some or all of our current non-union operations were to become unionized, we could incur an increased risk of work stoppages, reduced productivity and higher labor costs. Also, if we fail to maintain good relations with our union workforce, we could experience labor disputes, work stoppages or other disruptions in production that could negatively impact our profitability.

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

U.S. federal and state laws and Australian laws require us to secure certain of our obligations to reclaim lands used for mining, to pay federal and state workers’ compensation, to secure coal lease obligations and to satisfy other miscellaneous obligations. The primary methods we use 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, 2011, we had $929.6 million of self bonding in place for our reclamation obligations. As of December 31, 2011, we also had outstanding surety bonds with third parties, bank guarantees and letters of credit of $1,214.6 million, of which $791.6 million was for post-mining reclamation, $76.1 million related to workers’ compensation obligations, $104.7 million was for coal lease obligations and $242.2 million was for other obligations, including collateral for surety companies and bank guarantees, road maintenance and performance guarantees. Surety bonds are typically renewable on a yearly basis. Surety bond issuers and holders may not continue to renew the bonds or may demand additional collateral upon those renewals. Letters of credit are subject to us maintaining compliance under our two primary facilities used for such items, which is our Credit Facility and our accounts receivable securitization program. Our failure to retain, or inability to acquire, surety bonds or letters of credit or to provide a suitable alternative would have a material adverse effect on us. That failure could result from a variety of factors including the following:

• lack of availability, higher expense or unfavorable market terms of new surety bonds;

• restrictions on the availability of collateral for current and future third-party surety bond issuers under the terms of our indentures, Credit Facility or our 2011 term loan facility (2011 Term Loan Facility);

• the exercise by third-party surety bond issuers of their right to refuse to renew the surety; and

• the inability to renew our Credit Facility.

Our ability to self bond reduces our costs of providing financial assurances. To the extent we are unable to maintain our current level of self bonding due to legislative or regulatory changes or changes in our financial condition, our costs would increase.

19

Our mining operations are extensively regulated, which imposes significant costs on us, and future regulations and developments could increase those costs or limit our ability to produce coal.

Federal, state and local authorities regulate the coal mining industry with respect to matters such as employee health and safety, permitting and licensing requirements, air quality standards, water pollution, plant and wildlife protection, reclamation and restoration of mining properties after mining is completed, the discharge of materials into the environment, surface subsidence from underground mining and the effects that mining has on groundwater quality and availability. Numerous governmental permits and approvals are required for mining operations. We are required to prepare and present to federal, state and local authorities data pertaining to the effect that any proposed exploration for or production of coal may have upon the environment. The public, including non-governmental organizations, opposition groups and individuals, have statutory rights to comment upon and submit objections to requested permits and approvals. The costs, liabilities and requirements associated with these regulations may be costly and time-consuming and may delay commencement or continuation of exploration or production.

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 new interpretations by the relevant government authorities 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., CERCLA, impose liability relating to contamination by hazardous substances. Such liability may involve the costs of investigating or remediating contamination and damages to natural resources, as well as claims seeking to recover for property damage or personal injury caused by hazardous substances. Such liability may arise from conditions at formerly, as well as currently, owned or operated properties, and at properties to which hazardous substances have been sent for treatment, disposal, or other handling. Liability under CERCLA and similar state statutes is without regard to fault, and typically is joint and several, meaning that a person may be held responsible for more than its share, or even all, of the liability involved. Our mining operations involve some use of hazardous materials. In addition, we have accrued for liability arising out of contamination associated with Gold Fields Mining, LLC (Gold Fields), a dormant, non-coal-producing subsidiary of ours that was previously managed and owned by Hanson PLC, or with Gold Fields’ former affiliates. Hanson PLC, which is a predecessor owner of ours, transferred ownership of Gold Fields to us in the February 1997 spin-off of its energy business. Gold Fields is currently a defendant in several lawsuits and has received notices of several other potential claims arising out of lead contamination from mining and milling operations it conducted in northeastern Oklahoma. Gold Fields is also involved in investigating or remediating a number of other contaminated sites. See Note 23 to our consolidated financial statements for a description of pending legal proceedings involving Gold Fields.

If the assumptions underlying our asset retirement obligations for reclamation and mine closures are materially inaccurate, our costs could be significantly greater than anticipated.

Our asset retirement obligations primarily consist of spending estimates for surface land reclamation and support facilities at both surface and underground mines in accordance with federal and state reclamation laws in the U.S. and Australia as defined by each mining permit. These obligations are determined for each mine using various estimates and assumptions including, among other items, estimates of disturbed acreage as determined from engineering data, estimates of future costs to reclaim the disturbed acreage and the timing of these cash flows, discounted using a credit-adjusted, risk-free rate. Our management and engineers periodically review these estimates. If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could be materially different than currently estimated. Moreover, regulatory changes could increase our obligation to perform reclamation and mine closing activities. The resulting estimated asset retirement obligation could change significantly if actual amounts change significantly from our assumptions, which could have a material adverse effect on our results of operations and financial condition.

20

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

Our recoverable reserves decline as we produce coal. We have not yet applied for the permits required or developed the mines necessary to use all of our reserves. Moreover, the amount of proven and probable coal reserves described in Item 2. “Properties” involved the use of certain estimates and those estimates could be inaccurate. Furthermore, we may not be able to mine all of our reserves as profitably as we do at our current operations. Our future success depends upon our conducting successful exploration and development activities or acquiring properties containing economically recoverable reserves. Our current strategy includes increasing our reserves through acquisitions of government and other leases and producing properties and continuing to use our existing properties. In certain locations, leases for oil, natural gas and coalbed methane reserves are located on, or adjacent to, some of our reserves, potentially creating conflicting interests between us and lessees of those interests. Other lessees’ rights relating to these mineral interests could prevent, delay or increase the cost of developing our coal reserves. These lessees may also seek damages from us based on claims that our coal mining operations impair their interests. Additionally, the U.S. federal government limits the amount of federal land that may be leased by any company to 150,000 acres nationwide. As of December 31, 2011, we leased a total of 83,582 acres from the federal government. The limit could restrict our ability to lease additional U.S. federal lands.

Our planned mine development projects and acquisition activities may not result in significant additional reserves, and we may not have success developing additional mines. Most of our mining operations are conducted on properties owned or leased by us. Because we do not thoroughly verify title to most of our leased properties and mineral rights until we obtain a permit to mine the property, our right to mine some of our reserves may be materially adversely affected if defects in title or boundaries exist. In addition, in order to develop our reserves, we must also own the rights to the related surface property and receive various governmental permits. We cannot predict whether we will continue to receive the permits necessary for us to operate profitably in the future. We may not be able to negotiate new leases from the government or from private parties, obtain mining contracts for properties containing additional reserves or maintain our leasehold interest in properties on which mining operations have not commenced during the term of the lease. From time to time, we have experienced litigation with lessors of our coal properties and with royalty holders. In addition, from time to time our permit applications have been challenged.

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

We continue to explore ways to expand our international mining operations and global trading and brokerage platform. These efforts have included and are expected to include in the future such things as joint venture mining and exploration interests, such as partnering with other companies to utilize our mining experience for joint mine development, and sourcing coal from off-take arrangements to be sold through our Trading and Brokerage segment. Our international expansion increases our exposure to country risks and the effects of changes in currency exchange rates. Some of our international activities include expansion into developing countries where the economic strength, business practices and counterparty reputations may not be as well developed as in our U.S. or Australian operations. We are also challenged by various political risks, including political instability, the potential for expropriation of assets, costs associated with the repatriation of earnings and the potential for unexpected changes in regulatory requirements. Despite our efforts to mitigate these risks, our results of operations, financial position or cash flow could be adversely affected by these activities.

Risks Related to the Macarthur Acquisition

The extent to which we are able to successfully integrate the newly acquired Macarthur operations and successfully operate and develop the mine sites acquired from Macarthur will have a bearing on our future financial results.

The speed at which we integrate the Macarthur operations will have a direct bearing on the realization of anticipated synergies and benefits. Delays in optimizing the operations of the producing mines and in advancing the development and resource projects into operating mines and coal reserves could impact our future financial results.

We are more exposed to currency exchange rate fluctuations following completion of the Macarthur acquisition, and there is an increased proportion of assets, liabilities and expenses denominated in non-U.S. dollar currencies.

As a result of the completion of the Macarthur acquisition, our consolidated financial results are more exposed to currency exchange rate fluctuations, and an increased proportion of assets, liabilities and expenses are transacted in non-U.S. dollar currencies.

21

We present our consolidated financial statements in U.S. dollars and will have a significant proportion of net assets and expenses denominated in the Australian dollar. Our consolidated financial results and capital ratios will, therefore, be sensitive to movements in foreign exchange rates. An appreciation of the Australian dollar relative to the U.S. dollar could have an adverse impact on our consolidated financial results.

If we fail to establish and maintain proper internal controls for the combined business, our ability to produce accurate financial statements or comply with applicable regulations could be impaired.

Prior to the acquisition, Macarthur was not subject to the reporting requirements of the Securities Exchange Act of 1934, as amended, or the Sarbanes-Oxley Act of 2002. As a subsidiary consolidated with our financial statements, Macarthur is subject to such rules and regulations. We are incorporating the internal controls and procedures of Macarthur into our internal control over financial reporting, and we expect to be able to perform an assessment of and report on internal control over financial reporting for the combined business for the year ending December 31, 2012. If we fail to establish and maintain proper internal controls for the combined business, our ability to produce accurate financial statements or comply with applicable regulations could be impaired.

Risks Associated with Our Indebtedness

We could be adversely affected by the failure of financial institutions to fulfill their commitments under our Credit Facility.

As of December 31, 2011, we had $1.5 billion of available ongoing borrowing capacity under the Revolver portion of our Credit Facility, net of outstanding letters of credit. This committed facility, which matures on June 18, 2015, 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. Although the Credit Facility syndicate consists of over 40 financial institutions, if one or more of these institutions were to default on its obligation to fund its commitment, the portion of the facility provided by such defaulting financial institution would not be available to us.

Our financial performance could be adversely affected by our debt.

As of December 31, 2011, our total indebtedness was $6.7 billion, and we had $1.5 billion of available borrowing capacity under the Revolver portion of our Credit Facility, net of outstanding letters of credit. The indentures governing our Convertible Junior Subordinated Debentures (the Debentures) and the 7.375%, 7.875%, 6.50%, 6.25% and 6.00% Senior Notes (collectively our Senior Notes) do not limit the amount of indebtedness that we may issue. The degree to which we are leveraged could have important consequences, including, but not limited to:

• making it more difficult for us to pay interest and satisfy our debt obligations;

• increasing the costs of borrowing under our existing credit facilities;

• increasing our vulnerability to general adverse economic and industry conditions;

• requiring the dedication of a substantial portion of our cash flow from operations to the payment of principal and interest on our indebtedness, thereby reducing the availability of our cash flow to fund working capital, capital expenditures, business development, Btu Conversion and clean coal technology projects or other general corporate requirements;

• limiting our ability to obtain additional financing to fund future working capital, capital expenditures, business development, Btu Conversion and clean coal technology projects or other general corporate requirements;

• making it more difficult to obtain surety bonds, letters of credit or other financing, particularly during periods in which credit markets are weak;

• limiting our flexibility in planning for, or reacting to, changes in our business and in the coal industry;

• causing a decline in our credit ratings; and

• placing us at a competitive disadvantage compared to less leveraged competitors.

In addition, our debt agreements subject us to financial and other restrictive covenants. Failure by us to comply with these covenants could result in an event of default that, if not cured or waived, could have a material adverse effect on us and result in amounts outstanding thereunder to be immediately due and payable.

22

Any downgrade in our credit ratings could result in an increase in interest rates on our credit facilities, requirements to post additional collateral on derivative trading instruments, or the loss of trading counterparties for corporate hedging and commodity brokerage and trading.

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. Certain agreements governing our indebtedness restrict our ability to sell assets and use the proceeds from the sales. We may not be able to complete 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 Credit Facility and 2011 Term Loan Facility, and the indentures governing our Senior Notes and Debentures impose restrictions that may limit our operating and financial flexibility.

Our Credit Facility, 2011 Term Loan Facility, the indentures governing our Senior Notes  and our Debentures and the instruments governing our other indebtedness contain certain restrictions and covenants which restrict our ability to incur liens and/or debt or provide guarantees in respect of obligations of any other person. Under our 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 covenants also place limitations on our investments in joint ventures, unrestricted subsidiaries, indebtedness and the imposition of liens on our assets.

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 Credit Facility and 2011 Term Loan Facility. If we violate these covenants and are unable to obtain waivers from our lenders, our Credit Facility, our 2011 Term Loan Facility, our Senior Notes and our Debentures would be in default and the debt owing under such agreements could be accelerated. 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 or on terms that are acceptable to us. 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.

Provisions of our Debentures could discourage an acquisition of us by a third-party.

Certain provisions of our Debentures could make it more difficult or more expensive for a third-party to acquire us. Upon the occurrence of certain transactions constituting a “change of control” as defined in the indenture relating to our Debentures, holders of our Debentures will have the right, at their option, to convert their Debentures and thereby require us to pay the principal amount of such Debentures in cash.

Other Business Risks

Under certain circumstances, we could be responsible for certain federal and state black lung occupational disease liabilities assumed by Patriot in connection with its 2007 spin-off from us.

Patriot is responsible for certain federal and state black lung occupational disease liabilities, which are expected to be less than $150 million, as well as related credit capacity in support of these liabilities. Should Patriot not fund these obligations as they become due, we could be responsible for such costs when incurred.

23

Our expenditures for postretirement benefit and pension obligations could be materially higher than we have predicted if our underlying assumptions prove to be incorrect.

We provide postretirement health and life insurance benefits to eligible union and non-union employees. We calculated the total accumulated postretirement benefit obligation, which was a liability of $1,121.5 million as of December 31, 2011, $68.4 million of which was a current liability. Net pension liabilities were $194.0 million as of December 31, 2011, $1.7 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 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. In addition, a decrease in the discount rate used to determine pension obligations could result in an increase in the valuation of pension obligations, which could affect the reported funding status of our pension plans and future contributions, as well as the periodic pension cost in subsequent fiscal years. If we experience poor financial performance in asset markets in future years, we may be required to increase contributions.

Concerns about the environmental impacts of coal combustion, including perceived impacts on global climate issues, 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 issues continue to attract public and scientific attention. Numerous reports, such as the Fourth Assessment Report of the Intergovernmental Panel on Climate Change, have also engendered concern about the impacts of human activity, especially fossil fuel combustion, on global climate issues. In turn, increasing government attention is being paid to global climate issues and to emissions of what are commonly referred to as greenhouse gases, including emissions of carbon dioxide from coal combustion by power plants.

Enactment of laws or passage of regulations regarding emissions from the combustion of coal by the U.S. or some of its states or by other countries, or other actions to limit such emissions, could result in electricity generators switching from coal to other fuel sources. The potential financial impact on us of future laws or regulations will depend upon the degree to which any such laws or regulations force electricity generators to diminish their reliance on coal as a fuel source. That, in turn, will depend on a number of factors, including the specific requirements imposed by any such laws or regulations, the time periods over which those laws or regulations would be phased in, the state of commercial development and deployment of CCS technologies. In view of the significant uncertainty surrounding each of these factors, it is not possible for us to reasonably predict the impact that any such laws or regulations may have on our results of operations, financial condition or cash flows.

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. 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.

24

Item 1B.  Unresolved Staff Comments.

None.

Item 2.  Properties.

Coal Reserves

We had an estimated 9.0 billion tons of proven and probable coal reserves as of December 31, 2011. An estimated 7.8 billion tons of our attributable proven and probable coal reserves are in the U.S. and 1.2 billion tons are in Australia. 32% of our Australian proven and probable coal reserves, or 380 million tons, are metallurgical coal with the remainder being thermal coal. 45% of our reserves, or 4.1 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 40% of these reserves and lease property containing the remaining 60%. Compliance coal is defined by Phase II of the Clean Air Act as coal having sulfur dioxide content of 1.2 pounds or less per million Btu. Electricity generators are able to use coal that exceeds these specifications by using emissions reduction technology, using emission allowance credits or blending higher sulfur coal with lower sulfur coal.

Below is a table summarizing the locations and reserves of our major operating regions.

		Proven and Probable Reserves as of December 31, 2011(1)
		Owned Tons	Leased Tons	Total Tons
Operating Regions	Locations
		(Tons in millions)
Midwest	Illinois, Indiana and Kentucky	2,719	926	3,645
Powder River Basin	Wyoming and Montana	67	2,791	2,858
Southwest	Arizona and New Mexico	805	274	1,079
Colorado	Colorado	46	182	228
Total United States		3,637	4,173	7,810
Australia	New South Wales	—	431	431
Australia	Queensland	—	770	770
Total Australia		—	1,201	1,201
Total Proven and Probable Coal Reserves		3,637	5,374	9,011

_______________________________________

⁽¹⁾  Reserves have been adjusted to take into account estimated losses involved in producing a saleable product.

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

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

25

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 experienced geologists. We also have a chief geologist of reserve reporting whose primary responsibility is to track changes in reserve estimates, supervise our other geologists and coordinate periodic third-party reviews of our reserve estimates by qualified mining consultants.

Our reserve estimates are predicated on information obtained from our ongoing drilling program, which totals nearly 500,000 individual drill holes. We compile data from individual drill holes in a computerized drill-hole database from which the depth, thickness and, where core drilling is used, the quality of the coal is determined. The density of the drill pattern determines whether the reserves will be classified as proven or probable. The reserve estimates are then input into our computerized land management system, which overlays the geological data with data on ownership or control of the mineral and surface interests to determine the extent of our reserves in a given area. The land management system contains reserve information, including the quantity and quality (where available) of reserves as well as production rates, surface ownership, lease payments and other information relating to our coal reserves and land holdings. We periodically update our reserve estimates to reflect production of coal from the reserves and new drilling or other data received. Accordingly, reserve estimates will change from time to time to reflect mining activities, analysis of new engineering and geological data, changes in reserve holdings, modification of mining methods and other factors.

Our estimate of the economic recoverability of our reserves is based upon a comparison of unassigned reserves to assigned reserves currently in production in the same geologic setting to determine an estimated mining cost. These estimated mining costs are compared to expected market prices for the quality of coal expected to be mined and taking into consideration typical contractual sales agreements for the region and product. Where possible, we also review production by competitors in similar mining areas. Only reserves expected to be mined economically are included in our reserve estimates. Finally, our reserve estimates include reductions for recoverability factors to estimate a saleable product.

We periodically engage independent mining and geological consultants and consider their input regarding the procedures used by us to prepare our internal estimates of coal reserves, selected property reserve estimates and tabulation of reserve groups according to standard classifications of reliability.

With respect to the accuracy of our reserve estimates, our experience is that recovered reserves are within plus or minus 10% of our proven and probable estimates, on average, and our probable estimates are generally within the same statistical degree of accuracy when the necessary drilling is completed to move reserves from the probable to the proven classification.

We have numerous U.S. federal coal leases that are administered by the U.S. Department of the Interior under the Federal Coal Leasing Amendments Act of 1976. These leases cover our principal reserves in Wyoming and other reserves in Montana and Colorado. Each of these leases continues indefinitely, provided there is diligent development of the property and continued operation of the related mine or mines. The Bureau of Land Management has asserted the right to adjust the terms and conditions of these leases, including rent and royalties, after the first 20 years of their term and at 10-year intervals thereafter. Annual rents on surface land under our federal coal leases are now set at $3.00 per acre. Production royalties on federal leases are set by statute at 12.5% of the gross proceeds of coal mined and sold for surface-mined coal and 8% for underground-mined coal. The U.S. federal government limits by statute the amount of federal land that may be leased by any company and its affiliates at any time to 75,000 acres in any one state and 150,000 acres nationwide. As of December 31, 2011, we leased 11,536 acres of federal land in Colorado, 11,254 acres in Montana, 60,152 acres in Wyoming and 640 acres in New Mexico, for a total of 83,582 nationwide.

Similar provisions govern three coal leases with the Navajo and Hopi Indian tribes. These leases cover coal contained in 64,785 acres of land in northern Arizona lying within the boundaries of the Navajo Nation and Hopi Indian reservations. We also lease coal-mining properties from various state governments in the U.S.

26

Private U.S. coal leases normally have terms of between 10 and 20 years and usually give us the right to renew the lease for a stated period or to maintain the lease in force until the exhaustion of mineable and merchantable coal contained on the relevant site. These private U.S. leases provide for royalties to be paid to the lessor either as a fixed amount per ton or as a percentage of the sales price. Many U.S. leases also require payment of a lease bonus or minimum royalty, payable either at the time of execution of the lease or in periodic installments. The terms of our private U.S. leases are normally extended by active production at or near the end of the lease term. U.S. leases containing undeveloped reserves may expire or these leases may be renewed periodically.

Mining and exploration in Australia is generally carried on under leases or licenses granted by state governments. Mining leases are typically for an initial term of up to 21 years (but which may be renewed) and contain conditions relating to such matters as minimum annual expenditures, restoration and rehabilitation. Royalties are paid to the state government as a percentage of the sales price. Generally landowners do not own the mineral rights or have the ability to grant rights to mine those minerals. These rights are retained by state governments. Compensation is payable to landowners for loss of access to the land, and the amount of compensation can be determined by agreement or arbitration. Surface rights are typically acquired directly from landowners and, in the absence of agreement, there is an arbitration provision in the mining law.

Consistent with industry practice, we conduct only limited investigation of title to our coal properties prior to leasing. Title to lands and reserves of the lessors or grantors and the boundaries of our leased properties are not completely verified until we prepare to mine those reserves.

With a portfolio of approximately 9.0 billion tons, we believe that we have sufficient reserves to replace capacity from depleting mines for the foreseeable future and that our significant reserve holdings is one of our strengths. We believe that the current level of production at our major mines is sustainable for the foreseeable future.

The following charts provide a summary, by mining complex, of production for the years ended December 31, 2011, 2010 and 2009, tonnage of coal reserves that is assigned to our operating mines, our property interest in those reserves and other characteristics of the facilities.

27

PRODUCTION
(Tons in Millions)
	Production				Sulfur Content (1)
	Year	Year	Year		<1.2 lbs.	>1.2 to 2.5 lbs.	>2.5 lbs.	As
	Ended	Ended	Ended		Sulfur	Sulfur	Sulfur	Received
Geographic Region /	Dec. 31,	Dec. 31,	Dec. 31,	Type of	Dioxide per	Dioxide per	Dioxide per	Btu per
Mining Complex	2011	2010	2009	Coal	Million Btu	Million Btu	Million Btu	pound (2)
Midwest:
Bear Run	6.5	2.8	—	T	5	27	233	11,500
Gateway	3.3	3.2	3.3	T	—	—	9	11,000
Somerville Central	3.0	3.4	3.3	T	—	—	7	11,300
Francisco Underground	3.0	2.7	2.0	T	—	—	45	11,500
Willow Lake	2.2	2.9	3.4	T	—	—	24	12,100
Cottage Grove	1.9	2.1	2.1	T	—	—	22	12,500
Wild Boar	1.8	0.1	—	T	—	—	14	11,000
Viking - Corning Pit	1.5	1.5	1.6	T	—	—	4	11,500
Somerville North	1.4	2.0	2.0	T	—	—	4	10,600
Somerville South	1.2	1.7	1.8	T	—	—	6	11,100
Air Quality	1.2	1.1	1.6	T	21	2	31	11,300
Wildcat Hills Underground	1.0	0.8	0.7	T	—	—	21	12,200
Viking - Knox Pit (Closed in 2010)	—	1.7	2.0	T	—	—	—	NA
Farmersburg (Closed in 2010)	—	1.5	3.5	T	—	—	—	NA
Francisco Surface (Closed in 2009)	—	—	1.4	T	—	—	—	NA
Total	28.0	27.5	28.7		26	29	420
Powder River Basin:
North Antelope Rochelle	109.1	105.8	98.3	T	1,388	—	—	8,700
Caballo	24.1	23.5	23.3	T	827	127	22	8,300
Rawhide	15.0	11.2	15.8	T	263	66	4	8,300
Total	148.2	140.5	137.4		2,478	193	26
Southwest:
Kayenta	8.1	7.8	7.5	T	162	75	2	10,600
El Segundo	8.1	6.6	5.1	T	23	83	76	9,000
Lee Ranch	2.0	1.6	1.8	T	18	111	13	9,300
Total	18.2	16.0	14.4		203	269	91
Colorado:
Twentymile	7.7	7.7	7.8	T	39	—	—	11,300
Australia:
Wilpinjong	10.9	9.6	8.4	T	—	186	—	11,200
Wambo (3)	5.8	6.6	4.1	T/P	207	—	—	12,200
North Goonyella / Eaglefield	2.2	3.2	2.5	M	113	—	—	12,900
Burton	2.1	2.5	2.0	T/M	47	—	—	12,700
Millennium	1.9	1.6	0.9	M	54	—	—	12,600
Metropolitan	1.8	1.6	1.5	M	38	—	—	12,600
Coppabella	0.4	—	—	P	33	—	—	12,700
Moorvale	0.3	—	—	T/M/P	16	—	—	12,100
Middlemount (4)	—	—	—	M/P	38	—	—	12,300
Total	25.4	25.1	19.4		546	186	—
Total Continuing Operations	227.5	216.8	207.7		3,292	677	537
Discontinued Operations	1.4	1.6	3.1		—	—	—
Total Assigned	228.9	218.4	210.8		3,292	677	537

T: Thermal

M: Metallurgical

P: Pulverized Coal Injection

28

ASSIGNED RESERVES (5)
AS OF DECEMBER 31, 2011
		Attributable Ownership					100% Project Basis
(Tons in Millions)		Proven and					Proven and
Geographic Region/Mining Complex	Interest	Probable Reserves	Owned	Leased	Surface	Underground	Probable Reserves	Owned	Leased	Surface	Underground
Midwest:
Bear Run	100%	265	136	129	265	—	265	136	129	265	—
Gateway	100%	9	8	1	—	9	9	8	1	—	9
Somerville Central	100%	7	6	1	7	—	7	6	1	7	—
Francisco Underground	100%	45	8	37	—	45	45	8	37	—	45
Willow Lake	100%	24	14	10	—	24	24	14	10	—	24
Cottage Grove	100%	22	13	9	22	—	22	13	9	22	—
Wild Boar	100%	14	10	4	14	—	14	10	4	14	—
Viking - Corning Pit	100%	4	—	4	4	—	4	—	4	4	—
Somerville North	100%	4	1	3	4	—	4	1	3	4	—
Somerville South	100%	6	5	1	6	—	6	5	1	6	—
Air Quality	100%	54	3	51	—	54	54	3	51	—	54
Wildcat Hills Underground	100%	21	16	5	—	21	21	16	5	—	21
Total		475	220	255	322	153
Powder River Basin:
North Antelope Rochelle	100%	1,388	—	1,388	1,388	—	1,388	—	1,388	1,388	—
Caballo	100%	976	—	976	976	—	976	—	976	976	—
Rawhide	100%	333	—	333	333	—	333	—	333	333	—
Total		2,697	—	2,697	2,697	—
Southwest:
Kayenta	100%	239	—	239	239	—	239	—	239	239	—
El Segundo	100%	182	167	15	182	—	182	167	15	182	—
Lee Ranch	100%	142	122	20	142	—	142	122	20	142	—
Total		563	289	274	563	—
Colorado:
Twentymile	100%	39	8	31	—	39	39	8	31	—	39
Australia:
Wilpinjong	100%	186	—	186	186	—	186	—	186	186	—
Wambo (3)	100%	207	—	207	73	134	207	—	207	73	134
North Goonyella / Eaglefield	100%	113	—	113	3	110	113	—	113	3	110
Burton	100%	47	—	47	47	—	47	—	47	47	—
Millennium	100%	54	—	54	54	—	54	—	54	54	—
Metropolitan	100%	38	—	38	—	38	38	—	38	—	38
Coppabella	73.3%	33	—	33	33	—	45	—	45	45	—
Moorvale	73.3%	16	—	16	16	—	22	—	22	22	—
Middlemount (4)	50.0%	38	—	38	38	—	75	—	75	75	—
Total		732	—	732	450	282
Total Assigned		4,506	517	3,989	4,032	474

29

ASSIGNED AND UNASSIGNED PROVEN AND PROBABLE COAL RESERVES
AS OF DECEMBER 31, 2011
(Tons in Millions)
	Attributable Ownership					100% Project Basis
			Proven and					Proven and
	Total Tons		Probable			Total Tons		Probable
Coal Seam Location	Assigned	Unassigned	Reserves	Proven	Probable	Assigned	Unassigned	Reserves	Proven	Probable
Midwest:
Illinois	76	2,232	2,308	1,186	1,122	76	2,232	2,308	1,186	1,122
Indiana	399	442	841	614	227	399	442	841	614	227
Kentucky	—	496	496	264	232	—	496	496	264	232
Total	475	3,170	3,645	2,064	1,581
Powder River Basin:
Montana	—	161	161	157	4	—	161	161	157	4
Wyoming	2,697	—	2,697	2,620	77	2,697	—	2,697	2,620	77
Total	2,697	161	2,858	2,777	81
Southwest:
Arizona	239	—	239	239	—	239	—	239	239	—
New Mexico	324	516	840	759	81	324	516	840	759	81
Total	563	516	1,079	998	81
Colorado	39	189	228	146	82	39	189	228	146	82
Australia:
New South Wales	431	—	431	368	63	431	—	431	368	63
Queensland (6)	301	469	770	675	95	356	484	840	726	114
Total	732	469	1,201	1,043	158
Total Proven and Probable	4,506	4,505	9,011	7,028	1,983

30

ASSIGNED AND UNASSIGNED - RESERVE CONTROL AND MINING METHOD
AS OF DECEMBER 31, 2011
(Tons in Millions)
	Attributable Ownership				100% Project Basis
	Reserve Control		Mining Method		Reserve Control		Mining Method
Coal Seam Location	Owned	Leased	Surface	Underground	Owned	Leased	Surface	Underground
Midwest:
Illinois	1,926	382	62	2,246	1,926	382	62	2,246
Indiana	489	352	427	414	489	352	427	414
Kentucky	304	192	89	407	304	192	89	407
Total	2,719	926	578	3,067
Powder River Basin:
Montana	67	94	161	—	67	94	161	—
Wyoming	—	2,697	2,697	—	—	2,697	2,697	—
Total	67	2,791	2,858	—
Southwest:
Arizona	—	239	239	—	—	239	239	—
New Mexico	805	35	813	27	805	35	813	27
Total	805	274	1,052	27
Colorado	46	182	—	228	46	182	—	228
Australia:
New South Wales	—	431	259	172	—	431	259	172
Queensland (6)	—	770	641	129	—	840	709	131
Total	—	1,201	900	301
Total Proven and Probable	3,637	5,374	5,388	3,623

31

ASSIGNED AND UNASSIGNED PROVEN AND PROBABLE COAL RESERVES - SULFUR CONTENT
AS OF DECEMBER 31, 2011
(Tons in Millions)
		Attributable Ownership			100% Project Basis
		Sulfur Content (1)			Sulfur Content (1)
		<1.2 lbs.	>1.2 to 2.5 lbs.	>2.5 lbs.	<1.2 lbs.	>1.2 to 2.5 lbs.	>2.5 lbs.	As
		Sulfur Dioxide	Sulfur Dioxide	Sulfur Dioxide	Sulfur Dioxide	Sulfur Dioxide	Sulfur Dioxide	Received
	Type of	per	per	per	per	per	per	Btu
Coal Seam Location	Coal	Million Btu	Million Btu	Million Btu	Million Btu	Million Btu	Million Btu	per Pound (2)
Midwest:
Illinois	T	—	—	2,308	—	—	2,308	10,300
Indiana	T	26	38	777	26	38	777	10,300
Kentucky	T	—	1	495	—	1	495	10,900
Total		26	39	3,580
Powder River Basin:
Montana	T	9	121	31	9	121	31	8,600
Wyoming	T	2,478	193	26	2,478	193	26	8,700
Total		2,487	314	57
Southwest:
Arizona	T	162	75	2	162	75	2	10,900
New Mexico	T	157	402	281	157	402	281	9,400
Total		319	477	283
Colorado	T	222	—	6	222	—	6	10,700
Australia:
New South Wales	T/M/P	245	186	—	245	186	—	11,800
Queensland (6)	T/M/P	770	—	—	840	—	—	11,700
Total		1,015	186	—
Total Proven and Probable		4,069	1,016	3,926

T: Thermal

M: Metallurgical

P: Pulverized Coal Injection

32

⁽¹⁾  Compliance coal is defined by Phase II of the Clean Air Act as coal having sulfur dioxide content of 1.2 pounds or less per million Btu. Non-compliance coal is defined as coal having sulfur dioxide content in excess of this standard. Electricity generators are able to use coal that exceeds these specifications by using emissions reduction technology, using emissions allowance credits or blending higher sulfur coal with lower sulfur coal.

⁽²⁾  As-received Btu per pound includes the weight of moisture in the coal on an as sold basis. The range of variability of the moisture content in coal across a given region may affect the actual shipped Btu content of current production from assigned reserves.

⁽³⁾  Wambo includes the Wambo Open-Cut Mine and the North Wambo Underground Mine. The North Wambo Underground Mine produces both thermal and pulverized coal injection, or PCI metallurgical coal.

⁽⁴⁾ Middlemount represents our 50.0% interest in Middlemount Coal Pty Ltd., which owns the Middlemount Mine in Queensland, Australia that was acquired as part of the Macarthur acquisition.

⁽⁵⁾  Assigned reserves represent recoverable coal reserves that are controlled and accessible at active operations as of December 31, 2011. Unassigned reserves represent coal at currently non-producing locations that would require new mine development, mining equipment or plant facilities before operations could begin on the property.

⁽⁶⁾  Unassigned reserves in Queensland includes approximately 198 million tons of reserves held for sale associated with our Wilkie Creek Mine.

Item 3.      Legal Proceedings.

See Note 23 to our consolidated financial statements for a description of our pending legal proceedings, which is incorporated herein by reference.

Item 4.      Mine Safety Disclosures.

Safety is a core value that is integrated into all areas of our business. Our goal is to provide a workplace that is incident free. We believe that it is our responsibility to employees to provide a safe and healthy work 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 accidents, incidents and losses to avoid recurrence. As part of our training, we collaborate with MSHA and other government agencies to identify and test emerging safety technologies. We also believe personal accountability is key; every employee commits to our safety goals and governing principles. Managers, frontline supervisors and employees are held responsible for their safety and the safety of other employees.

We also partner with several companies and governmental agencies to pursue new technologies that have the potential to improve our safety performance and provide better safety protections for employees. We have installed communications and tracking systems at our U.S. underground mines, which allow persons on the surface to determine the location of and communicate with all persons underground. In addition, we are testing a proximity detection system at a section of one of our mines, which is designed to automatically stop mining equipment if a person is detected within the operating range of a continuous miner or coal hauler.

33

The incidence rate is a measure of safety performance, which is tracked through our safety tracking system. The incidence rate is computed as the number of injuries, MSHA reportable injury degree codes 1 through 6, multiplied by 200,000, divided by employee hours worked [(number of reportable incidents X 200,000) ÷ employee hours worked]. Since MSHA is a branch of the U.S. Department of Labor, its jurisdiction applies only to our U.S. mines. However, we also track incidence rate for our Australian mines to measure safety performance on the same basis as our U.S. mines. The following table reflects our incidence rates (as of February 23, 2012) and the comparable MSHA incidence rates:

	Year Ended December 31,
	2011	2010	2009
U.S.	1.37	1.98	2.16
Australia(1)	2.77	4.03	4.43
Total Peabody Energy Corporation(1)	1.92	2.71	2.92
MSHA (U.S. coal mines)(2)	3.69	3.93	4.14

⁽¹⁾ Results exclude Macarthur for all periods presented. Macarthur's incidence rate for the acquisition date through December 31, 2011 was 1.54. Results for all periods presented include our Wilkie Creek Mine, which is held for sale as of December 31, 2011.

⁽²⁾ For the U.S., the comparable MSHA incidence rate is from MSHA's Mine Injury and Worktime Operators report and represents the all incidence rate for U.S. coal mines, excluding the impact of office workers (“All Incidence Rate”). The 2011 MSHA all incidence rate of 3.69 reflected above represents preliminary results for January-December 2011 (latest data available) as published by MSHA as of February 23, 2012.

We monitor MSHA compliance using violations per inspection day (in the U.S. only), which is calculated as the total count of violations per five hour MSHA inspector day. For the years ended December 31, 2011, 2010 and 2009, our U.S. violations per inspection day were 0.81, 0.84 and 1.11, respectively.

The historical incidence rates and violations per inspection day may be adjusted over time to reflect the final resolution of incidents, citations and orders by MSHA. The impact of these adjustments, which has not historically resulted in significant changes to the results originally reported, is reflected in the MSHA database. The MSHA incidence rates disclosed above reflect the rates in the MSHA Mine Injury and Worktime Operators report, which are not updated by MSHA once a final report has been issued.

The information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Act and Item 104 of Regulation S-K is included in Exhibit 95 to this Annual Report on Form 10-K.

34

Executive Officers of the Company

Set forth below are the names, ages as of February 17, 2012 and current positions of our executive officers. Executive officers are appointed by, and hold office at the discretion of, our Board of Directors, subject to the terms of any employment agreements.

Name	Age	Position
Gregory H. Boyce	57	Chairman and Chief Executive Officer, Director
Richard A. Navarre	51	President and Chief Commercial Officer
Michael C. Crews	44	Executive Vice President and Chief Financial Officer
Sharon D. Fiehler	55	Executive Vice President and Chief Administrative Officer
Eric Ford	57	Executive Vice President and Chief Operating Officer
Jeane L. Hull	57	Executive Vice President - Technical Services
Alexander C. Schoch	57	Executive Vice President Law, Chief Legal Officer and Secretary

Gregory H. Boyce was elected Chairman of the Board on October 10, 2007 and has been a director of the Company since March 2005. He was named Chief Executive Officer Elect in March 2005, and assumed the position of Chief Executive Officer in January 2006. Mr. Boyce served as our President from October 2003 to December 2007 and as our Chief Operating Officer from October 2003 to December 2005. He previously served as Chief Executive - Energy of Rio Tinto plc (an international natural resource company) from 2000 to 2003. Other prior positions include President and Chief Executive Officer of Kennecott Energy Company from 1994 to 1999 and President of Kennecott Minerals Company from 1993 to 1994. He has extensive engineering and operating experience with Kennecott and also served as Executive Assistant to the Vice Chairman of Standard Oil of Ohio from 1983 to 1984. Mr. Boyce serves on the board of directors of Marathon Oil Corporation. He is Chairman of the National Mining Association and Deputy Chairman of the Coal Industry Advisory Board of the International Energy Agency. He is a member of the National Coal Council; The Business Council; Business Roundtable; the Board of Trustees of St. Louis Children's Hospital; the Board of Trustees of Washington University in St. Louis; and the Advisory Council of the University of Arizona's Department of Mining and Geological Engineering.

Richard A. Navarre is our President and Chief Commercial Officer. He previously served as our Executive Vice President of Corporate Development and Chief Financial Officer from July 2006 to January 2008 and as Chief Financial Officer from October 1999 to June 2008. Mr. Navarre is a member of the Hall of Fame of the College of Business at Southern Illinois University Carbondale; a member of the Board of Advisors of the College of Business and Administration and the School of Accountancy of Southern Illinois University Carbondale; a member of the Board of Directors of the Regional Chamber and Growth Association of St. Louis; and a member of the Foreign Policy Association. He is a Director of the United Way of Greater St. Louis; Vice Chair of CEOs Against Cancer; and a member of the Cardinal Glennon - Bob Costas Benefit Committee. He is Treasurer of the Missouri Historical Society; a member of Financial Executives International; and a former chairman of the Bituminous Coal Operators' Association.

Michael C. Crews was named our Executive Vice President and Chief Financial Officer in June 2008. He joined us in 1998 as Senior Manager of Financial Reporting, and has served as Assistant Corporate Controller, Director of Planning, Assistant Treasurer, Vice President of Planning, Analysis, and Performance Assessment, and Vice President of Operations Planning. Prior to joining us, Mr. Crews served for three years in financial positions with MEMC Electronic Materials, Inc. and six years at KPMG Peat Marwick in St. Louis. He serves on the Board of Directors of Action for Autism in St. Louis. Mr. Crews has a Bachelor of Science degree in Accountancy from the University of Missouri at Columbia, a Master of Business Administration (MBA) degree from Washington University in St. Louis and is a Certified Public Accountant in the state of Missouri.

Sharon D. Fiehler has been our Executive Vice President and Chief Administrative Officer since January 2008. From April 2002 to January 2008, she served as our Executive Vice President of Human Resources and Administration. Ms. Fiehler joined us in 1981 as Manager - Salary Administration and has held a series of employee relations, compensation and salaried benefits positions. She holds degrees in social work and psychology and a MBA, and prior to joining us was a personnel representative for Ford Motor Company. Ms. Fiehler is Deputy Chair and a Director of the Federal Reserve Bank of St. Louis; a member of the Board of Trustees of the Missouri Botanical Garden; Chair of the Board of Directors of Junior Achievement of Mississippi Valley, Inc.; a member of the Board of Directors of the St. Louis Zoo Association; and a member of the Chancellor's Council of the University of Missouri - St. Louis. She is also a member of the Missouri Women's Forum and the St. Louis Forum.

35

Eric Ford was named our Executive Vice President and Chief Operating Officer in March 2007. Mr. Ford has 40 years of extensive international management, operating and engineering experience and, prior to joining us, 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 serves on the board of directors of Compass Minerals International, Inc. Mr. Ford 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.

Jeane L. Hull was named our Executive Vice President - Technical Services in March 2011. She joined us in March 2007 as the Senior Vice President of Engineering and Technical Services, and then served as Group Executive - Powder River Basin and Southwest from June 2008 to March 2011. Prior to joining us, Ms. Hull served as Chief Operating Officer of Kennecott Utah Copper, a subsidiary of Rio Tinto. She held numerous management, engineering and operations positions with Rio Tinto and affiliates and also spent 12 years with Mobil Mining and Minerals and Mobil Chemical Company. A registered professional engineer, Ms. Hull graduated from the South Dakota School of Mines and Technology with a Bachelor of Science degree in Civil Engineering. She holds a MBA from Nova University in Florida.

Alexander C. Schoch was named our Executive Vice President Law and Chief Legal Officer in October 2006 and our Secretary in May 2008. Prior to joining us, Mr. Schoch served as Vice President and General Counsel for Emerson Process Management, an operating segment of Emerson Electric Co. and a leading supplier of process-automation products, from August 2004 to October 2006. Mr. Schoch also served in 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. Mr. Schoch serves as a Trustee at Large on the Board of Trustees for the Energy & Mineral Law Foundation and on the Board of Directors of North Side Community School in St. Louis, Missouri.

PART II

Item 5.  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Our common stock is listed on the New York Stock Exchange, under the symbol “BTU”. As of February 17, 2012, there were 1,386 holders of record of our common stock.

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

	Share Price				Dividends
	High		Low		Paid
2011
First Quarter	$	73.73	$	57.44	$	0.085
Second Quarter	73.95		52.44		0.085
Third Quarter	61.85		33.84		0.085
Fourth Quarter	47.81		30.60		0.085
2010
First Quarter	$	52.14	$	39.88	$	0.070
Second Quarter	50.25		34.89		0.070
Third Quarter	49.94		38.08		0.070
Fourth Quarter	64.59		48.76		0.085

36

Dividend Policy

We have declared and paid quarterly dividends since our initial public offering in 2001. Most recently, our Board of Directors declared a dividend of $0.085 per share of Common Stock on January 26, 2012, payable on March 1, 2012, to stockholders of record on February 9, 2012. 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

On October 24, 2008, we announced that our Board of Directors authorized a share repurchase program of up to $1 billion of the then outstanding shares of our common stock. While no such share repurchases were made in 2011, repurchases may be made from time to time based on an evaluation of our outlook and general business conditions, as well as alternative investment and debt repayment options. Our Chairman and Chief Executive Officer also has the authority to direct us to repurchase up to $100 million of our common stock outside the share repurchase program. The share repurchase program does not have an expiration date and may be discontinued at any time. Through December 31, 2011, we have made repurchases of 7.7 million shares at a cost of $299.6 million ($199.8 million and $99.8 million in 2008 and 2006, respectively), leaving $700.4 million available for share repurchases under the share repurchase program.

The following table summarizes all share repurchases for the three months ended December 31, 2011:

Period	Total Number of Shares Purchased(1)	Average Price per Share		Total Number of Shares Purchased as Part of Publicly Announced  Program	Maximum Dollar Value that May Yet Be Used to Repurchase Shares Under the Publicly Announced  Program (In millions)
October 1 through October 31, 2011	52,685	$	45.27	—	$	700.4
November 1 through November 30, 2011	4,157	36.06		—	700.4
December 1 through December 31, 2011	—	—		—	700.4
Total	56,842	$	44.60	—

⁽¹⁾  Represents shares withheld to cover the withholding taxes upon the vesting of restricted stock, which are not a part of the share repurchase program.

Item 6. Selected Financial Data.

The following table presents selected financial and other data about us for the most recent five fiscal years. The following table and the discussion of our results of operations in 2011, 2010 and 2009 in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” includes references to, and analysis of, our Adjusted EBITDA results. We define Adjusted EBITDA as income from continuing operations before deducting net interest expense, income taxes, asset retirement obligation expense and depreciation, depletion and amortization. Adjusted EBITDA is used by management to measure our segments’ operating performance, and management also believes it is a useful indicator of our ability to meet debt service and capital expenditure requirements. Because Adjusted EBITDA is not calculated identically by all companies, our calculation may not be comparable to similarly titled measures of other companies. Adjusted EBITDA is reconciled to its most comparable measure, under U.S. generally accepted accounting principles (GAAP), as reflected at the end of Item 6. “Selected Financial Data” and in Note 25 to our consolidated financial statements.

The selected financial data for all periods presented reflect the assets, liabilities and results of operations from subsidiaries spun off as Patriot as discontinued operations. We also have classified as discontinued operations those operations recently divested, as well as certain non-strategic mining assets held for sale where we have committed to the divestiture of such assets.

37

On October 26, 2011, we acquired Macarthur. Our results of operations include Macarthur’s results of operations from the date of acquisition. Macarthur's results are reflected in our Australian Mining Segment. See Note 2 to our consolidated financial statements for additional details.

We have derived the selected historical financial data as of and for the years ended December 31, 2011, 2010, 2009, 2008 and 2007 from our audited financial statements. You should read the following table in conjunction with the financial statements, the related notes to those financial statements and Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The results of operations for the historical periods included in the following table are not necessarily indicative of the results to be expected for future periods. In addition, the Risk Factors section of Item 1A. “Risk Factors” of this report includes a discussion of risk factors that could impact our future results of operations.

	Year Ended December 31,
	2011			2010			2009			2008			2007
	(In millions, except per share data)
Results of Operations Data
Total revenues	$	7,974.4		$	6,739.9		$	5,847.0		$	6,335.6		$	4,422.2
Costs and expenses	6,381.0			5,385.5			5,024.6			5,053.3			3,830.6
Operating profit	1,593.4			1,354.4			822.4			1,282.3			591.6
Interest expense, net	219.7			212.4			193.0			217.1			228.8
Income from continuing operations before income taxes	1,373.7			1,142.0			629.4			1,065.2			362.8
Income tax provision (benefit)	363.2			315.4			186.2			159.8			(73.1		)
Income from continuing operations, net of income taxes	1,010.5			826.6			443.2			905.4			435.9
(Loss) income from discontinued operations, net of income taxes	(64.2		)	(24.4		)	19.8			53.7			(174.4		)
Net income	946.3			802.2			463.0			959.1			261.5
Less: Net (loss) income attributable to noncontrolling interests	(11.4		)	28.2			14.8			6.2			(2.3		)
Net income attributable to common stockholders	$	957.7		$	774.0		$	448.2		$	952.9		$	263.8
Basic earnings per share from continuing operations	$	3.77		$	2.97		$	1.60		$	3.32		$	1.65
Diluted earnings per share from continuing operations	$	3.76		$	2.93		$	1.59		$	3.30		$	1.62
Weighted average shares used in calculating basic earnings per share	269.1			267.0			265.5			268.9			264.1
Weighted average shares used in calculating diluted earnings per share	270.3			269.9			267.5			270.7			268.6
Dividends declared per share	$	0.340		$	0.295		$	0.250		$	0.240		$	0.240
Other Data
Tons sold	250.6			244.2			241.3			252.5			233.1
Net cash provided by (used in) continuing operations:
Operating activities	$	1,658.1		$	1,116.7		$	1,044.9		$	1,317.0		$	462.6
Investing activities	(3,745.5		)	(694.5		)	(407.4		)	(412.6		)	(535.8		)
Financing activities	1,678.5			(77.1		)	(104.6		)	(498.0		)	37.4
Adjusted EBITDA	2,128.7			1,838.7			1,262.8			1,728.2			958.2
Balance Sheet Data (at period end)
Total assets	$	16,733.0		$	11,363.1		$	9,955.3		$	9,695.6		$	9,082.3
Total long-term debt (including capital leases)	6,657.5			2,750.0			2,752.3			2,793.6			2,909.0
Total stockholders’ equity	5,515.8			4,689.3			3,755.9			3,119.5			2,735.3

38

Adjusted EBITDA is calculated as follows (unaudited):

	Year Ended December 31,
	2011		2010		2009		2008		2007
			(Dollars in millions)
Income from continuing operations, net of income taxes	$	1,010.5	$	826.6	$	443.2	$	905.4	$	435.9
Income tax provision (benefit)	363.2		315.4		186.2		159.8		(73.1		)
Depreciation, depletion and amortization	482.2		437.1		400.5		397.8		342.9
Asset retirement obligation expense	53.1		47.2		39.9		48.1		23.7
Interest expense, net	219.7		212.4		193.0		217.1		228.8
Adjusted EBITDA	$	2,128.7	$	1,838.7	$	1,262.8	$	1,728.2	$	958.2

Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Overview

We are the world’s largest private sector coal company. We own interests in 30 coal mining operations, including a majority interest in 29 coal operations located in the U.S. and Australia and a 50% equity interest in the Middlemount Mine in Australia. We also own an equity interest in a joint venture mining operation in Venezuela. In 2011, we produced 227.5 million tons of coal from continuing operations and sold 250.6 million tons of coal.

We conduct business through four principal segments: Western U.S. Mining, Midwestern U.S. Mining, Australian Mining and Trading and Brokerage. The principal business of the Western and Midwestern U.S. Mining segments is the mining, preparation and sale of thermal coal, sold primarily to electric utilities. Our Western U.S. Mining segment consist of our Powder River Basin, Southwest and Colorado operations. Our Midwestern U.S. Mining segment consist of our Illinois and Indiana operations. The business of our Australian Mining segment is the mining of various qualities of low-sulfur, high Btu coal (metallurgical coal) as well as thermal coal.

On October 26, 2011, we acquired Macarthur. Our results of operations include Macarthur’s results of operations from the date of acquisition. Macarthur's results are reflected in our Australian Mining Segment.

In the U.S., we typically sell coal to utility customers under long-term contracts (those with terms longer than one year). Our Australia Mining operations are primarily export focused with customers spread across several countries, while a portion of our coal is sold to Australian steel producers and power generators. Generally, Australian revenues from individual countries vary year by year based on the demand for electricity, the demand for steel, the strength of the global economy and several other factors including those specific to each country. Historically in Australia Mining operations, we predominately entered into multi-year international coal agreements that contained provisions allowing either party to commence a renegotiation of the agreement price annually in the second quarter of each year. Current industry practice, and our practice, is to negotiate pricing for metallurgical coal contracts quarterly and seaborne thermal coal contracts annually.

During 2011, approximately 91% of our worldwide sales (by volume) were under long-term contracts. For the year ended December 31, 2011, 82% of our total sales (by volume) were to U.S. electricity generators, 15% were to customers outside the U.S. and 3% were to the U.S. industrial sector.

Our Trading and Brokerage segment’s principal business is the brokering of coal sales of other producers both as principal and agent, and the trading of coal, freight and freight-related contracts. We also provide transportation-related services in support of our coal trading strategy, as well as hedging activities in support of our mining operations.

Our fifth segment, Corporate and Other, includes mining and export/transportation joint ventures, energy-related commercial activities, Btu Conversion activities, as well as the optimization of our coal reserve and real estate holdings.

To maximize our coal assets and land holdings for long-term growth, we are contributing to the development of coal-fueled generation, pursuing Btu Conversion projects that would convert coal to natural gas or transportation fuels and advancing clean coal technologies, including CCS.

39

As discussed more fully in Item 1A. “Risk Factors,” our results of operations in the near-term could be negatively impacted by weather conditions, cost of competing fuels, availability of transportation for coal shipments, labor relations, unforeseen geologic conditions or equipment problems at mining locations and by the pace of the economic recovery. On a long-term basis, our results of operations could be impacted by our ability to secure or acquire high-quality coal reserves, find replacement buyers for coal under contracts with comparable terms to existing contracts or the passage of new or expanded regulations that could limit our ability to mine, increase our mining costs or limit our customers’ ability to utilize coal as fuel for electricity generation. In the past, we have achieved production levels that are relatively consistent with our projections. We may adjust our production levels in response to changes in market demand.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Summary

Global coal consumption rose to an estimated 7.7 billion tonnes in 2011 driven by increased coal use in China, India and other developing Asian nations. Global seaborne demand rose an estimated 6% and exceeded 1 billion tonnes, led by an increase in thermal demand to supply new coal-fueled electricity generation brought on line in 2011. Global steel production grew an estimated 7% while China and India's coal-fueled electricity generation rose 14% and 9%, respectively, in 2011.

In the U.S., coal markets have been impacted by a weak economy, low electricity generation and depressed near-term natural gas prices. U.S. coal electricity generation declined an estimated 6% in 2011 while U.S. coal exports increased 28% to an estimated 108 million tons.

Our revenues increased compared to the prior year by $1,234.5 million and Segment Adjusted EBITDA increased over the prior year by $372.8 million, led by higher average prices in all regions and increased volume in the U.S.

Income from continuing operations, net of income taxes, increased compared to the prior year by $183.9 million due to the increase in Segment Adjusted EBITDA discussed above, partially offset by lower Corporate and Other Adjusted EBITDA and increased income taxes, depreciation, depletion and amortization, and interest expense.

We ended the year with total available liquidity of $2.3 billion, as discussed further in “Liquidity and Capital Resources.”

Tons Sold

The following table presents tons sold by operating segment for the years ended December 31, 2011 and 2010:

	Year Ended December 31,		Increase (Decrease)
	2011	2010	Tons		%
	(Tons in millions)
Western U.S. Mining	173.6	163.8	9.8		6.0	%
Midwestern U.S. Mining	30.3	29.7	0.6		2.0	%
Australian Mining	25.3	25.3	—		—	%
Trading and Brokerage	21.4	25.4	(4.0	)	(15.7	)%
Total tons sold	250.6	244.2	6.4		2.6	%

40

Revenues

The following table presents revenues for the years ended December 31, 2011 and 2010:

	Year Ended December 31,				Increase (Decrease) to Revenues
	2011		2010		$		%
	(Dollars in millions)
Western U.S. Mining	$	2,900.4	$	2,706.3	$	194.1	7.2	%
Midwestern U.S. Mining	1,481.1		1,320.6		160.5		12.2	%
Australian Mining	3,080.7		2,399.9		680.8		28.4	%
Trading and Brokerage	475.1		291.1		184.0		63.2	%
Corporate and Other	37.1		22.0		15.1		68.6	%
Total revenues	$	7,974.4	$	6,739.9	$	1,234.5	18.3	%

The increase in Australian Mining operations’ revenues compared to the prior year was driven by a higher weighted average sales price of 26.5%, led by increased pricing for seaborne metallurgical and thermal coal due to a combination of increased global coal demand and coal supply constraints resulting from weather impacts in early 2011. In 2011, Macarthur operations contributed revenues of $152.9 million on 0.9 million tons sold. These favorable impacts were partially offset by lower metallurgical volumes due to a third quarter roof fall and recovery of longwall operations at our North Goonyella Mine and flooding in Queensland that began in late 2010 that lowered production and shipments in the first quarter of 2011. Metallurgical coal sales totaled 9.3 million tons in 2011 as compared to 9.8 million tons in 2010.

Western U.S. Mining operations’ revenues were higher compared to the prior year as volumes and the weighted average sales price were above the prior year. The volume increase of 6.0% was led by increased shipments from our Powder River Basin region due to increased customer demand. Our weighted average sales price rose modestly compared to the prior year (1.2%) as favorable contract pricing in our Southwest region was partially offset by lower pricing in the Powder River Basin region due to a combination of sales mix and the expiration of some higher-priced, long-term contracts signed before the economic recession in the 2008 and 2009 timeframe.

Trading and Brokerage revenues were higher compared to the prior year due to an increase in export volumes, which carry higher prices, and higher overall coal market pricing on our brokerage activity, partially offset by lower domestic volumes.

In the Midwestern U.S. Mining segment, revenue improvements compared to the prior year were due to a higher weighted average sales price of 9.8% driven by favorable contracts signed in recent years. Volumes were also higher (2.0%) due to incremental contributions from our Bear Run Mine (which commenced operations in May 2010) and Wild Boar Mine (which commenced operations in December 2010).

Segment Adjusted EBITDA

The following table presents segment Adjusted EBITDA for the years ended December 31, 2011 and 2010:

	Year Ended December 31,				Increase (Decrease) to Segment Adjusted EBITDA
	2011		2010		$			%
			(Dollars in millions)
Western U.S. Mining	$	766.0	$	816.7	$	(50.7	)	(6.2	)%
Midwestern U.S. Mining	408.9		322.1		86.8			26.9	%
Australian Mining	1,194.3		977.4		216.9			22.2	%
Trading and Brokerage	197.0		77.2		119.8			155.2	%
Total Segment Adjusted EBITDA	$	2,566.2	$	2,193.4	$	372.8		17.0	%

41

Australian Mining operations’ Adjusted EBITDA increased compared to the prior year due to a higher weighted average sales price ($742.6 million), partially offset by lower production and higher costs at our North Goonyella Mine due to a roof fall and recovery of longwall operations ($234.7 million), an unfavorable foreign currency impact on operating costs, net of hedging ($135.8 million), cost escalations for labor, materials and services ($64.0 million), increased royalty expense associated with our higher-priced coal shipments ($54.1 million) and lower volumes ($38.1 million), excluding the impact of the North Goonyella roof fall discussed above.

Trading and Brokerage Adjusted EBITDA increased primarily due to higher margins on our brokerage activity due to higher prices as discussed above.  

Midwestern U.S. Mining operations’ Adjusted EBITDA increased compared to the prior year due to a higher weighted average sales price ($112.5 million), partially offset by increased labor ($17.7 million) and materials and services costs ($12.4 million) related primarily to compliance measures at our underground mines.

Western U.S. Mining operations’ Adjusted EBITDA decreased as compared to the prior year due to higher volume-driven labor ($39.1 million) and materials and services costs ($31.3 million), increased equipment repairs and maintenance costs ($33.1 million), a provision related to litigation recorded in the second quarter of 2011 ($24.5 million), and increased commodity costs, net of hedging ($16.1 million). The above decreases to the segment's Adjusted EBITDA were partially offset by increased volumes ($88.0 million) and a higher weighted average sales price ($41.6 million) as discussed above.

Income From Continuing Operations Before Income Taxes

The following table presents income from continuing operations before income taxes for the years ended December 31, 2011 and 2010:

	Year Ended December 31,						Increase (Decrease) to Income
	2011			2010			$			%
	(Dollars in millions)
Total Segment Adjusted EBITDA	$	2,566.2		$	2,193.4		$	372.8		17.0	%
Corporate and Other Adjusted EBITDA(1)	(437.5		)	(354.7		)	(82.8		)	23.3	%
Depreciation, depletion and amortization	(482.2		)	(437.1		)	(45.1		)	10.3	%
Asset retirement obligation expense	(53.1		)	(47.2		)	(5.9		)	12.5	%
Interest expense	(238.6		)	(222.0		)	(16.6		)	7.5	%
Interest income	18.9			9.6			9.3			96.9	%
Income from continuing operations before income taxes	$	1,373.7		$	1,142.0		$	231.7		20.3	%

⁽¹⁾  Corporate and Other Adjusted EBITDA results include selling and administrative expenses, equity income (loss) from our joint ventures, certain asset sales, resource management costs and revenues, coal royalty expense, costs associated with past mining activities, expenses related to our other commercial activities such as generation development and Btu Conversion costs and provisions for certain litigation.

Income from continuing operations before income taxes was greater than the prior year primarily due to the higher Total Segment Adjusted EBITDA discussed above, partially offset by lower Corporate and Other Adjusted EBITDA and increased depreciation, depletion and amortization, and interest expense.

Corporate and Other Adjusted EBITDA reflects higher expenses compared to the prior year due primarily to the following:

• Higher current year expenses in support of our international expansion, acquisition activity and other growth initiatives, including $85.2 million of expenses associated with the acquisition of Macarthur; and

• Lower current year results from equity affiliates ($17.5 million) due to current year losses associated with our joint venture arrangement in Australia ($7.3 million) and earnings recognized in the prior year associated with transaction services related to our Mongolian joint venture ($10.0 million); partially offset by

• Increased gains on disposal or exchange of assets ($46.9 million) driven by current year non-cash exchanges of coal reserves in Kentucky and coal reserves and surface lands in Illinois for coal reserves in West Virginia ($37.7 million) and current year gains of $31.7 million associated with sales of non-strategic coal reserves in Kentucky and Illinois, partially offset by prior year gains associated with non-cash exchanges of coal reserves in Kentucky and coal reserves and surface lands in Illinois for coal reserves in West Virginia ($23.7 million); and

42

• A current year gain associated with the receipt of a $14.6 million project development fee related to our involvement in Prairie State.

Depreciation, depletion and amortization expense increased compared to the prior year primarily driven by additional expense associated with the assets acquired in the Macarthur acquisition.

Interest expense increased $16.6 million over the prior year due primarily to current year acquisition related interest expense of $45.3 million, which includes $29.1 million of expense related to ongoing financing and $16.2 million of expense for bridge financing, partially offset by costs in the prior year of $9.3 million associated with the refinancing of our five-year Credit Facility and $8.4 million of charges associated with the extinguishment of $650.0 million of senior notes.

Net Income Attributable to Common Stockholders

The following table presents net income attributable to common stockholders for the years ended December 31, 2011 and 2010:

	Year Ended December 31,						Increase (Decrease) to Income
	2011			2010			$			%
	(Dollars in millions)
Income from continuing operations before income taxes	$	1,373.7		$	1,142.0		$	231.7		20.3	%
Income tax provision	363.2			315.4			47.8			15.2	%
Income from continuing operations, net of income taxes	1,010.5			826.6			183.9			22.2	%
Loss from discontinued operations, net of income taxes	(64.2		)	(24.4		)	(39.8		)	163.1	%
Net income	946.3			802.2			144.1			18.0	%
Net (loss) income attributable to noncontrolling interests	(11.4		)	28.2			(39.6		)	(140.4	)%
Net income attributable to common stockholders	$	957.7		$	774.0		$	183.7		23.7	%

Net income attributable to common stockholders increased compared to the prior year due to the increased income from continuing operations before income taxes as discussed above.

The provision for income taxes increased compared to the prior year due to higher current year earnings ($81.1 million), a change in valuation allowances ($44.1 million) related primarily to alternative minimum tax credits released in the prior year and higher current year state income taxes ($17.1 million). The increases to income tax expense were partially offset by lower current year foreign earnings repatriation expense ($76.9 million) and a current year benefit of $0.9 million associated with the remeasurement of non-U.S. tax accounts as compared to remeasurement expense of $47.9 million in the prior year as the Australian exchange rate decreased against the U.S. dollar in the current year as compared to an increase in the prior year, as set forth in the table below.

	December 31,						Rate Change
	2011		2010		2009		2011			2010
Australian dollar to U.S. dollar exchange rate	$	1.0156	$	1.0163	$	0.8969	$	(0.0007	)	$	0.1194

Loss from discontinued operations for 2011 reflects a loss of $64.2 million as compared to a loss of $24.4 million in the prior year due primarily to higher current year losses associated with assets held for sale in our Australian Mining operations segment.

Net loss attributable to noncontrolling interests in the current year was driven by ArcelorMittal Mining Australasia B.V.'s interest in Macarthur from the acquisition and control date of October 26, 2011 to the date we acquired ArcelorMittal Mining Australasia B.V. on December 21, 2011.

Other

The net fair value of our foreign currency hedges decreased from an asset of $640.1 million at December 31, 2010 to an asset of $490.6 million at December 31, 2011 primarily due to the realization of hedge gains in 2011. This decrease is reflected in “Other current assets” and “Investments and other assets” in the consolidated balance sheets.

43

The fair value of our coal trading positions, before the application of margin, designated as cash flow hedges of forecasted sales changed from a liability of $174.2 million at December 31, 2010 to a liability of $22.4 million at December 31, 2011 due to favorable market price movements on our positions held and realization of completed transactions.

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

Summary

In the U.S., demand for coal rose approximately 75 million tons in 2010, led by a 5.5% increase in coal-fueled generation and an 18 million ton rise in exports. The international coal markets strengthened in 2010 due to strong Asian demand growth and weather-related generation recovery in the Atlantic markets, coupled with supply challenges across the major coal exporting nations of the Southern Hemisphere. Our analyses of general business conditions indicate the following:

• Seaborne coal demand increased an estimated 13% in 2010, led by a 32% recovery in global metallurgical coal demand;

• Pacific thermal coal demand for electricity generation rose 15% in 2010, while the Atlantic market declined 10%;

• Benchmark pricing of high quality, hard coking coal in the seaborne market has ranged between $200 to $225 per tonne from April to December 2010;

• The benchmark prompt seaborne thermal coal price in Newcastle, Australia rose 34% in 2010;

• U.S. coal generation accounted for nearly two-thirds of the growth in total power output in 2010 due to new coal-fueled generation, favorable weather, and a partial reversal of 2009’s coal-to-gas switching; and

• Indexed U.S. coal prices rose in 2010 in all regions, with increases ranging from 30 to 50%.

Our 2010 revenues increased compared to 2009 by $892.9 million and Segment Adjusted EBITDA increased over 2009 by $586.1 million, led by higher Australian pricing and sales volumes in 2010 despite unfavorable weather-related volume impacts that occurred late in 2010.

Income from continuing operations, net of income taxes, increased compared to 2009 by $383.4 million due to the increase in Segment Adjusted EBITDA discussed above, partially offset by increased income taxes, decreased Corporate and Other Adjusted EBITDA, and increased depreciation, depletion and amortization and interest expense.

We ended 2010 with total available liquidity of $2.7 billion, as discussed further in “Liquidity and Capital Resources.”

Tons Sold

The following table presents tons sold by operating segment for the years ended December 31, 2010 and 2009:

	Year Ended December 31,		Increase (Decrease)
	2010	2009	Tons		%
		(Tons in millions)
Western U.S. Mining	163.8	160.1	3.7		2.3	%
Midwestern U.S. Mining	29.7	31.8	(2.1	)	(6.6	)%
Australian Mining	25.3	20.0	5.3		26.5	%
Trading and Brokerage	25.4	29.4	(4.0	)	(13.6	)%
Total tons sold	244.2	241.3	2.9		1.2	%

44

Revenues

The following table presents revenues for the years ended December 31, 2010 and 2009:

	Year Ended December 31,				Increase (Decrease) to Revenues
	2010		2009		$			%
			(Dollars in millions)
Western U.S. Mining	$	2,706.3	$	2,612.6	$	93.7		3.6	%
Midwestern U.S. Mining	1,320.6		1,303.8		16.8			1.3	%
Australian Mining	2,399.9		1,512.6		887.3			58.7	%
Trading and Brokerage	291.1		391.0		(99.9		)	(25.5	)%
Corporate and Other	22.0		27.0		(5.0		)	(18.5	)%
Total revenues	$	6,739.9	$	5,847.0	$	892.9		15.3	%

The increase in Australian Mining operations’ revenues was driven by a higher weighted average sales price of 25.4%, led by increased pricing on seaborne metallurgical and thermal coals and a higher mix of metallurgical coal shipments. Volumes also increased in 2010 (26.5%) driven by increased demand for metallurgical coal (metallurgical coal shipments of 9.8 million tons were 2.9 million tons, or 42.0%, greater than 2009). These increases were muted to an extent by the flooding in Queensland in late 2010 that negatively impacted our production and also restricted throughput due to damage to the port and rail systems. The metallurgical coal demand increase reflects the strengthening of the coal markets as discussed above, coupled with 2009 customer destocking of inventory and lower capacity utilization at steel customers.

Western U.S. Mining operations’ revenues increased compared to 2009 due to increased sales volume (2.3%) driven by our Powder River Basin and Southwest regions due to increased customer demand and a higher weighted average sales price of 1.3%.

In the Midwestern U.S. Mining segment, revenue improvements due to an increase in our weighted average sales price of 8.4% from contractual price increases were largely offset by decreased shipments (6.6%) on lower customer demand.

Trading and Brokerage revenues were down primarily due to lower international brokerage revenues, unfavorable market movements on freight positions that support our export volumes and weather related shipment deferrals.

Segment Adjusted EBITDA

The following table presents segment Adjusted EBITDA for the years ended December 31, 2010 and 2009:

					Increase (Decrease) to
	Year Ended December 31,				Segment Adjusted EBITDA
	2010		2009		$			%
			(Dollars in millions)
Western U.S. Mining	$	816.7	$	721.5	$	95.2		13.2	%
Midwestern U.S. Mining	322.1		281.9		40.2			14.3	%
Australian Mining	977.4		410.5		566.9			138.1	%
Trading and Brokerage	77.2		193.4		(116.2		)	(60.1	)%
Total Segment Adjusted EBITDA	$	2,193.4	$	1,607.3	$	586.1		36.5	%

Our Australian Mining segment benefited from a higher weighted average sales price ($408.3 million) and increased volumes ($134.0 million) as discussed above, and productivity improvements at our North Goonyella and Wambo underground mines along with fewer longwall move days in 2010 ($116.0 million). Partially offsetting the above improvements were net higher adverse weather impacts driven by the flooding in late 2010, unfavorable foreign currency impact on operating costs, net of hedging ($34.5 million), increased royalty expense associated with our higher-priced metallurgical coal shipments ($31.7 million) and increased demurrage costs ($10.7 million).

45

Western U.S. Mining operations’ Adjusted EBITDA increased compared to 2009 due to the higher volumes ($49.8 million) and a higher weighted average sales price ($42.1 million) discussed above, lower repairs and maintenance costs due to timing of repairs and improved equipment efficiency ($35.0 million) and fewer longwall move days at our Twentymile Mine in 2010 ($10.0 million), partially offset by 2009 customer contract termination and restructuring agreements ($27.8 million) and increased commodity costs in the 2010 ($20.8 million).

In the Midwestern U.S. Mining segment, a higher weighted average sales price ($98.5 million), as discussed above, was partially offset by lower volumes ($42.3 million) due to decreased demand and increased costs on lower productivity due to compliance measures and geological conditions at certain underground mines.

Our Trading and Brokerage segment was down primarily due to the lower revenues as discussed above.

Income From Continuing Operations Before Income Taxes

The following table presents income from continuing operations before income taxes for the years ended December 31, 2010 and 2009:

							Increase (Decrease)
	Year Ended December 31,						to Income
	2010			2009			$			%
				(Dollars in millions)
Total Segment Adjusted EBITDA	$	2,193.4		$	1,607.3		$	586.1		36.5	%
Corporate and Other Adjusted EBITDA(1)	(354.7		)	(344.5		)	(10.2		)	3.0	%
Depreciation, depletion and amortization	(437.1		)	(400.5		)	(36.6		)	9.1	%
Asset retirement obligation expense	(47.2		)	(39.9		)	(7.3		)	18.3	%
Interest expense	(222.0		)	(201.1		)	(20.9		)	10.4	%
Interest income	9.6			8.1			1.5			18.5	%
Income from continuing operations before income taxes	$	1,142.0		$	629.4		$	512.6		81.4	%

⁽¹⁾  Corporate and Other Adjusted EBITDA results include selling and administrative expenses, equity income (loss) from our joint ventures, certain asset sales, resource management costs and revenue, coal royalty expense, costs associated with past mining obligations, expenses related to our other commercial activities such as generation development and Btu Conversion costs and provision for certain litigation.

Income from continuing operations before income taxes was higher compared to 2009 primarily due to the higher Total Segment Adjusted EBITDA discussed above, partially offset by lower Corporate and Other Adjusted EBITDA and higher depreciation, depletion and amortization expense and interest expense as discussed below:

• Corporate and Other Adjusted EBITDA:  higher expense was primarily driven by an increase in selling and administrative expenses due to costs to support our business development and international expansion (e.g. headcount, travel, professional services, legal). We also incurred increased post mining costs driven by higher retiree healthcare amortization of actuarial losses and interest cost. These items were partially offset by improved results from equity affiliates primarily due to 2009 losses of $54.6 million related to our equity investment in Carbones del Guasare, which included a $34.7 million impairment loss and $19.9 million of operating losses. See Note 1 to our consolidated financial statements for additional information.

• Depreciation, depletion and amortization:  higher compared to 2009 due to increased production at our Australian mines with higher per-ton depletion rates reflecting higher demand and additional depreciation expense associated with our new Bear Run Mine (commissioned in the second quarter of 2010).

• Interest expense:  higher primarily due to refinancing charges ($9.3 million) associated with our new five-year Credit Facility and charges ($8.4 million) associated with the extinguishment and refinancing of $650.0 million of senior notes.

46

Net Income Attributable to Common Stockholders

The following table presents net income attributable to common stockholders for the years ended December 31, 2010 and 2009:

	Year Ended December 31,					Increase (Decrease) to Income
	2010			2009		$			%
				(Dollars in millions)
Income from continuing operations before income taxes	$	1,142.0		$	629.4	$	512.6		81.4	%
Income tax provision	315.4			186.2		129.2			69.4	%
Income from continuing operations, net of income taxes	826.6			443.2		383.4			86.5	%
(Loss) income from discontinued operations, net of income taxes	(24.4		)	19.8		(44.2		)	(223.2	)%
Net income	802.2			463.0		339.2			73.3	%
Net income attributable to noncontrolling interests	28.2			14.8		13.4			90.5	%
Net income attributable to common stockholders	$	774.0		$	448.2	$	325.8		72.7	%

Net income attributable to common stockholders increased compared to 2009 due to the increased income from continuing operations before income taxes as discussed above.

Income tax provision was impacted by the following:

• Increased expense due to higher earnings ($179.4 million) and income tax resulting from foreign earnings repatriation ($84.5 million), partially offset by

• A change in the valuation allowance ($46.0 million) related primarily to alternative minimum tax credits, lower expense associated with the remeasurement of non-U.S. tax accounts as a result of the larger increase in the Australian exchange rate against the U.S. dollar in 2009 compared to 2010 ($26.5 million) as set forth in the table below, the favorable rate difference resulting from higher foreign generated income in 2010 ($41.1 million), and lower expense in 2010 due to the reduction of our gross unrecognized tax benefit resulting from the completion of the Internal Revenue Service examination of the 2005 federal income tax year ($15.2 million).

	December 31,						Rate Change
	2010		2009		2008		2010		2009
Australian dollar to U.S. dollar exchange rate	$	1.0163	$	0.8969	$	0.6928	$	0.1194	$	0.2041

(Loss) income from discontinued operations for 2010 reflects a loss of $24.4 million as compared to income of $19.8 million in 2009. 2010 and 2009 includes results of operations related to assets held for sale in Australia and the Midwestern U.S. 2009 also includes a coal excise tax refund receivable of approximately $35 million recorded in 2009 and a $10.0 million loss on disposal of our Australian Chain Valley Mine.

Other

The net fair value of our foreign currency hedges increased approximately $434 million in 2010 mostly due to the strengthening of the Australian dollar against the U.S. dollar. The increase is reflected in “Other current assets” and “Investments and other assets” in the consolidated balance sheets.

Outlook

Our near-term outlook is intended to address the next 12-24 months, with any subsequent periods addressed in our long-term outlook.

47

Near-Term Outlook

Global coal consumption rose in 2011 to an estimated 7.7 billion tonnes, driven by increased coal use in China, India and other developing Asian nations. Global seaborne demand rose an estimated 6% and exceeded 1 billion tonnes, led by an increase in thermal demand to supply approximately 81 gigawatts of new coal-fueled electricity generation brought on line in 2011. In the U.S., coal markets have been marked by a weak economy, low electricity generation and depressed near-term natural gas prices. U.S. coal electricity generation declined an estimated 6% in 2011 driven by more mild weather as compared to the prior year as well as some displacement from hydro and natural gas, while U.S. coal exports increased 28% to an estimated 108 million tons.

• The International Monetary Fund's January 2012 World Economic Outlook estimates global economic activity, as measured by gross domestic product (GDP), will grow 3.3% in 2012 and 3.9% in 2013, led by China and India. China's GDP is projected to grow 8.2% in 2012 and 8.8% in 2013. India, the world's second fastest growing economy, is projected to grow 7.0% in 2012 and 7.3% in 2013.

• According to the World Steel Association, global steel use is expected to increase 5.4% in 2012, with China expected to grow its steel use by 6.0%.

Prices for global seaborne metallurgical and thermal coal have come down from record highs during 2011, though recent settlements have still been higher than historical averages. Metallurgical coal prices for high quality hard coking coal and LV PCI settled at $235 and $171 per tonne, respectively, for quarterly contracts commencing January 2012. We have settled first quarter metallurgical coal shipments in line with these recent settlements, with essentially all remaining 2012 metallurgical coal production unpriced. We expect near-term macroeconomic movements to dictate quarterly pricing for the remainder of 2012 and we are targeting total 2012 metallurgical coal sales of approximately 14 to 15 million tons.

Seaborne thermal coal originating from Newcastle, Australia, has been settled for annual contracts beginning in January 2012 at $116 per tonne. As of January 24, 2012, we had 40% to 50% of 2012 seaborne thermal coal volumes available for pricing in Australia and we are targeting 2012 Australian thermal exports of 12 to 13 million tons.

Looking at U.S. markets, the Energy Information Administration's (EIA) February 2012 Short-Term Energy Outlook projects 2012 U.S. electric power coal consumption to decline by approximately 2%. U.S. coal production is also expected to decline by 2%, despite slight production expansion in the Western region. U.S. producers will look to increase exports as domestic markets remain weak relative to historic levels and global seaborne thermal markets provide growing sales opportunities.

The coal-fueled electric power generation decline in 2012 is projected to be primarily driven by depressed near-term natural gas prices that are resulting in elevated levels of coal-to-gas switching, with the largest impact projected to be on Central Appalachian coal supply. If coal-to-gas switching lasts for a prolonged period during 2012 due to significantly depressed natural gas prices, there may be more substantial unfavorable impacts to all coal supply regions, including the Powder River Basin. We continually adjust our production levels in response to changes in market demand.

We are targeting our U.S. volumes in 2012 to be on par with prior year levels and are fully committed on pricing. As of January 24, 2012, we had 45% to 55% of planned U.S. production unpriced for 2013. As a result of the current weak U.S. coal market environment, some customers may attempt to delay and/or cancel portions of contracted 2012 volumes. Our coal supply agreement contractual terms and conditions provide support for us to seek full performance from all customers. In selected cases, we may elect to reach agreement with customers on monetary settlements and/or contract extensions for 2013 and beyond in exchange for relief on 2012 volumes.

Macarthur is expected to contribute less than $100 million of EBITDA in 2012 given the significant cost increases necessary to correct overburden deficiencies at the Coppabella Mine and to complete major repairs at both the Coppabella and Moorvale mines that had been deferred under previous management. We expect that these expenditures will allow us to enter 2013 with a solid foundation for higher productivity, lower costs, and improved financial performance. In addition, we expect to incur increased depreciation, depletion and amortization expense in 2012 and beyond driven by a higher average depletion rate associated with the acquisition of Macarthur. As discussed in “Liquidity and Capital Resources” our debt service cost will also increase as a result of the debt incurred to fund the acquisition of Macarthur.

48

We continue to manage costs and operating performance in an effort to mitigate external cost pressures, geologic issues and potential shipping delays resulting from adverse port and rail performance. We may have higher per ton costs as a result of suboptimal production levels due to market-driven changes in demand. We may also encounter poor geologic conditions, lower third-party contract miner or brokerage performance or unforeseen equipment problems that limit our ability to produce at forecasted levels. To the extent upward pressure on costs exceeds our ability to realize sales increases, or if we experience unanticipated operating or transportation difficulties, our operating margins would be negatively impacted. Reductions in the relative cost of other fuels, including natural gas, could impact the use of coal for electricity generation. See Cautionary Notice Regarding Forward-Looking Statements and Item 1A. “Risk Factors” of this report for additional considerations regarding our outlook.

Dodd-Frank Act. On July 21, 2010, the Dodd-Frank Act was enacted, which includes a number of provisions applicable to us in the areas of corporate governance, executive compensation and mine safety and extractive industries disclosure. In addition, the Dodd-Frank Act imposes additional regulation of financial derivatives transactions that may apply to our hedging and our Trading and Brokerage activities. Although the Dodd-Frank Act generally became effective upon its enactment, many provisions have extended implementation periods and delayed effective dates and require further action by the federal regulatory authorities. As a result, the ultimate impact of the Dodd-Frank Act on us will not be fully known for an extended period of time. We do expect that the Dodd-Frank Act will increase compliance and transaction costs associated with our hedging and Trading and Brokerage activities.

European Union Derivatives Regulation. In October 2011, the European Commission adopted proposals to revise its directive on markets in financial instruments (MiFID) and to enact a new regulation on markets in financial instruments (MiFIR). These proposals, which are currently under negotiation by the European Commission, European Council and European Parliament, will likely impose additional regulation of financial derivatives transactions that may apply to our hedging and our Trading and Brokerage activities. While the ultimate impact of these proposals will not be known for some time, we do expect that they will increase compliance and transaction costs associated with our hedging and our Trading and Brokerage activities.

Minerals Resource Rent Tax. On May 2, 2010, the Australian government released a report on Australia's Future Tax System, which included a recommendation to replace the current resource taxing arrangements imposed on non-renewable resources by the Australian federal and state governments with a super profit resource rent tax (the Resource Tax) imposed and administered by the Australian government. As proposed, the Resource Tax would be profit-based and would apply to non-renewable resources projects, including existing projects. On July 2, 2010, the Australian government announced changes to the Resource Tax and proposed a new minerals resource rent tax (the MRRT). The MRRT would still be profit-based, but measures were introduced to lessen the impact of the MRRT. The Australian government and major industry policy makers are actively engaged to work through various structural aspects of the proposed MRRT together with detailed implementation issues. A committee charged with consulting with industry and preparing recommendations as to the final form of the MRRT submitted its report in late December 2010. That committee's recommendations largely endorsed the mining industry's understanding as to what was agreed with the federal government prior to the federal election. In March 2011, those recommendations were accepted by the federal government, which included the recommendation that all state royalties (current and future) are creditable against MRRT payments. An implementation group was formed, which included industry participants, to assist with drafting the legislation. Draft legislation and an accompanying explanatory memorandum was released for public consultation on June 7, 2011. The final exposure draft was released for further consultation on September 16, 2011 with legislation formally submitted to the House of Representatives in November 2011. The legislation was referred to the Senate Economics Legislation Committee on November 21, 2011 with the committee due to report back to the Senate on March 14, 2012. If the MRRT becomes law, the MRRT will apply to mining profits attributable to the value of resources earned after July 1, 2012 and may affect the level of taxation incurred by our Australian operations going forward.

Carbon Pricing Framework. In the fourth quarter of 2011, the Australian government passed a legislative package that included a carbon pricing framework that commences July 1, 2012. The carbon price will initially be $23.00 Australian dollars per tonne of carbon dioxide equivalent emissions, escalated by 2.5% per year for inflation over a three year period. After June 30, 2015, the carbon price mechanism will transition to an emissions trading scheme. We believe that all of our Australian operations will be impacted by the fugitive emissions portion of the framework (defined as the methane and carbon dioxide which escapes into the atmosphere when coal is mined and gas is produced), which we estimate will initially average $2.00 to $3.25 Australian dollars per tonne of coal produced annually. Actual results will be dependent upon the volume of tons produced at each of our mining locations as the impact per tonne at our surface mines will generally be less than the impact per tonne at our underground mines. In addition, our Australian mines will be impacted by the phased reduction of the government's diesel fuel rebate to capture emissions from fuel combustion. Our North Goonyella, Wambo and Metropolitan mines will be eligible to apply for a portion of the government's approximately $1.3 billion Australian dollars of transition benefits that would provide assistance based on historical emissions intensity data to the most emissions-intensive coal mines over a six-year period.

49

Cross-State Air Pollution Rule (CSAPR). On July 6, 2011, the U.S. EPA finalized CSAPR, which requires 28 states from Texas eastward (not including the New England states or Delaware) to significantly improve air quality by reducing power plant emissions that cross state lines and contribute to ozone and/or fine particle pollution in other states. The CSAPR is one of a number of significant regulations that the EPA has issued or expects to issue that will impose more stringent requirements relating to air, water and waste controls on electric generating units. Under the CSAPR, the first phase of the nitrogen oxide and sulfur dioxide emissions reductions would commence in 2012 with further reductions effective in 2014. In October 2011, the EPA proposed amendments to the CSAPR to increase emission budgets in ten states, including Texas, and ease limits on market-based compliance options. While CSAPR had an initial compliance deadline of January 1, 2012, the rule was challenged and on December 30, 2011, the U.S. Court of Appeals for the District of Columbia stayed CSAPR and advised that the EPA is expected to continue administering CAIR until the pending challenges are resolved. Expedited briefing on the merits of the challenge is underway. We continue to evaluate the possible scenarios associated with the CSAPR and the impacts it may have on our business and our results of operations, financial condition or cash flows.

Long-Term Outlook

Our long-term global outlook remains positive. According to the BP Statistical Review of World Energy 2011, coal has been the fastest-growing fuel in the world for the past decade.

The International Energy Agency (IEA) estimates in its World Energy Outlook 2011, current policies scenario, that world primary energy demand will grow 51% between 2009 and 2035. Demand for coal is projected to rise 65%, and the growth in global electricity generation from coal is expected to be greater than the growth in oil, natural gas, nuclear, hydro, biomass, geothermal and solar combined. China and India account for more than 75% of the 2009 - 2035 coal-based primary energy demand growth.

Under the current policies scenario, the IEA expects coal to retain its strong presence as a fuel for the power sector worldwide. Coal's share of the power generation mix was 47% in 2009. By 2035, the IEA estimates coal's fuel share of power generation to be 49% as it continues to have the largest share of worldwide electric power production. According to industry reports, approximately 370 gigawatts of coal-fueled electricity generating plants are currently planned or under construction around the world with expected completion between 2012 and 2016. Based on those estimates, when complete, those plants would require an estimated 1.2 billion tonnes of coal annually. In the U.S., while coal-based plant retirements are expected, the EIA is projecting coal demand to remain relatively constant through 2015.

The IEA projects that global natural gas-fueled electricity generation will have a compound annual growth rate of 2.7%, from 4.3 trillion kilowatt hours in 2009 to 8.7 trillion kilowatt hours in 2035. The total amount of electricity generated from natural gas is expected to be approximately one-half the total for coal, even in 2035. Renewables are projected to comprise 23% of the 2035 fuel mix versus 19% in 2009. Nuclear power is expected to grow 50%, however its share of total generation is expected to fall from 13.5% to 10% between 2009 and 2035. The recent events in Japan and Germany may impact these projections. Generation from liquid fuels is projected to decline an average of 2.1% annually to 1.5% of the 2035 generation mix.

We believe that Btu Conversion applications such as coal-to-gas (CTG) and CTL plants represent an avenue for potential long-term industry growth. Several CTG and CTL facilities are currently under development in China and India.

We continue to support clean coal technology development toward the ultimate goal of near-zero emissions, and we are advancing more than a dozen projects and partnerships in the U.S., China and Australia. Clean coal technology development in the U.S. has funding earmarked under the American Recovery and Reinvestment Act of 2009. In addition, the Interagency Task Force on Carbon Capture and Storage was formed to develop a comprehensive and coordinated federal strategy surrounding the commercial development of commercial carbon capture and storage projects. 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 long-term plans also include advancing projects to expand our presence in the Asia-Pacific region, some of which include sourcing coal to be sold through our Trading and Brokerage segment and partnerships to utilize our mining experience for joint mine development. In July 2011, we entered into a framework agreement to pursue development of a 50 million-ton-per-year surface mine in Xinjiang, China. Also in July 2011, we were selected to be part of a consortium to develop the Tavan Tolgoi coking coal reserve in the South Gobi region of Mongolia. The Government of Mongolia continues to evaluate the structure and components of the mine development, and we are negotiating with other parties and the Government of Mongolia regarding long-term agreements related to the project. Any agreements would then be submitted for consideration and approval by government agencies and the Parliament of Mongolia.

50

Enactment of laws or passage of regulations regarding emissions from the combustion of coal by the U.S. or some of its states or by other countries, or other actions to limit such emissions, could result in electricity generators switching from coal to other fuel sources. The potential financial impact on us of future laws or regulations will depend upon the degree to which any such laws or regulations force electricity generators to diminish their reliance on coal as a fuel source. That, in turn, will depend on a number of factors, including the specific requirements imposed by any such laws or regulations, the time periods over which those laws or regulations would be phased in, the state of commercial development and deployment of CCS technologies and the alternative markets for coal. In view of the significant uncertainty surrounding each of these factors, it is not possible for us to reasonably predict the impact that any such laws or regulations may have on our results of operations, financial condition or cash flows.

Liquidity and Capital Resources

Capital Resources

Our primary sources of cash are the sales of our coal production to customers and from the cash generated from our trading and brokerage activities. To a lesser extent, we also generate cash from the sale of non-strategic coal reserves and surface land and from financing transactions. Along with cash and cash equivalents, our liquidity includes the available balances from our Revolver under our Credit Facility, an accounts receivable securitization program and a bank overdraft facility in Australia. Our available liquidity as of December 31, 2011 was $2.3 billion, which included cash and cash equivalents of $0.8 billion, $1.5 billion available for borrowing under the Revolver, net of outstanding letters of credit of $21.0 million, and available capacity under our accounts receivable securitization program of $41.7 million, net of outstanding letters of credit and amounts drawn. Our liquidity is also impacted by activity under certain bilateral cash collateralization arrangements.

We assumed Macarthur's three year $330.0 million Australian dollar Corporate Funding Facility (Macarthur Corporate Funding Facility) as part of the acquisition that has a maturity date of November 30, 2013. As of December 31, 2011, we had no borrowings under the Macarthur Corporate Funding Facility. The Macarthur Corporate Funding Facility has a $130.0 million Australian dollar sub-limit for bank guarantees, leaving an available capacity of $200.0 million Australian dollars at December 31, 2011. Letters of credit and cash-backed bank guarantees totaling $65.0 million Australian dollars were outstanding as of December 31, 2011. We plan to terminate the Macarthur Corporate Funding Facility in 2012.

As of December 31, 2011, approximately $284 million of our cash was held in the U.S. with approximately $515 million held by foreign subsidiaries, primarily those in our Australia Mining segment. Nearly all of the cash held by our foreign subsidiaries is denominated in U.S. dollars and is subject to additional U.S. income taxes if repatriated. The cash held in Australia is currently expected to be used to fund, in part, our organic growth projects, sustaining capital expenditures and existing operations.

We currently expect that our available liquidity and cash flow from operations will be sufficient to meet our anticipated capital requirements during the next 12 months and for the foreseeable future. In addition to the above, alternative sources of liquidity include our ability to offer and sell securities under our shelf registration statement on file with the SEC.

Capital Requirements

Our primary uses of cash include the cash costs of coal production, capital expenditures, coal reserve lease and royalty payments, debt service costs (interest and principal), lease obligations, take or pay obligations and costs related to past mining obligations. When in compliance with the financial covenants and customary default provisions of our Credit Facility and 2011 Term Loan Facility, we are not restricted in our ability to pay dividends or repurchase capital stock provided that we may only redeem and repurchase capital stock with the proceeds received from the concurrent issue of capital stock or indebtedness permitted under the Credit Facility and 2011 Term Loan Facility.

Capital Expenditures. Capital expenditures for 2012 are anticipated to be $1.2 to $1.4 billion. Approximately $800 to $950 million is earmarked for growth projects that encompass future mine development, as well as the expansion and extension of existing mines, with much of the remaining allocated to sustaining capital expenditures for existing operations. The increase in planned capital expenditures for 2012 compared to 2011 is due to the continued advancement of multiple organic growth projects at our Millennium, Metropolitan and Burton mines. Approximately 75% of the growth and expansion capital is targeted for various Australian projects for metallurgical and thermal coal, with the remainder in the U.S. Our 2012 capital expenditures will include spending to begin converting two of our Australian mines from contract mining to owner operations.

51

Federal Coal Lease Expenditures. We currently anticipate that our federal coal lease expenditures will be $42.1 million in 2012 and for each of the next three years. These expenditures may increase in 2012 and beyond depending upon our participation in and the successful bidding on future federal coal leases.

Dividends. We have declared and paid quarterly dividends since our initial public offering in 2001. In January 2012, our Board of Directors approved a dividend of $0.085 per share of common stock, payable on March 1, 2012. 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.

Pension Contributions. During 2011, we made contributions of $46.7 million. In 2012, our anticipated pension contributions needed to be at or above the Pension Protection Act thresholds is approximately $5 million.

Share Repurchase Program. At December 31, 2011, our available capacity for share repurchases was $700.4 million, and our Chairman and Chief Executive Officer has authority to direct us to repurchase up to $100 million of our common stock outside of the share repurchase program. While no such share repurchases were made in 2011, 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.

NCIG. Financing for phase one of stage two of construction closed in 2010 with us providing our pro-rata share of funding of $59.7 million Australian dollars ($54.8 million U.S. dollars). NCIG may further expand the coal transloading facility’s capacity which could require us to fund our pro-rata share in a similar manner.

Debt Service Costs. With the acquisition of Macarthur in 2011, our debt service costs increased with the addition of $4.1 billion of new debt that included the following.

• A 2011 Term Loan Facility of $1.0 billion with an interest rate payable of LIBOR plus 2.0%, or 2.26% (as of December 31, 2011) and a maturity date of October 28, 2016;

• 6.00% Senior Notes of $1.6 billion due November 2018 (the 6.00% Senior Notes), with interest payable on May15 and November 15 of each year, commencing May15, 2012; and

• 6.25% Senior Notes of $1.5 billion due November 2021 (the 6.25% Senior Notes), with interest payable on May15 and November 15 of each year, commencing May15, 2012.

While these new debt instruments increased the annual amount of interest to be paid for 2012 and beyond, only the 2011 Term Loan Facility resulted in a $50.0 million increase to our annual amount of principal to be paid ($37.5 million in 2012). See the Contractual Obligations section for our estimated debt service costs as of December 31, 2011 for the next five years and thereafter. See Note 11 to our consolidated financial statements for additional information on all of our outstanding debt.

On November 15, 2011, we, the Guarantors and the initial purchasers of the 6.00% Senior Notes and the 6.25% Senior Notes entered into a registration rights agreement (the Registration Rights Agreement). Subject to the terms of the Registration Rights Agreement, we will use our reasonable best efforts to register with the SEC exchange notes having substantially identical terms as the 6.00% Senior Notes and the 6.25% Senior Notes and to exchange freely tradable exchange notes for such notes within 365 days after the issue date of the 6.00% Senior Notes and the 6.25% Senior Notes (effectiveness target date). If we fail to meet the effectiveness target date (a registration default), the annual interest rate on the 6.00% Senior Notes and the 6.25% Senior Notes will increase by 0.25% for each 90-day period during which the default continues, up to a maximum additional interest rate of 1.0% until the registration default is cured.

52

Our total indebtedness as of December 31, 2011 and 2010, consisted of the following:

	December 31,
	2011		2010
	(Dollars in millions)
Term Loan	$	468.8	$	493.8
2011 Term Loan Facility	1,000.0		—
5.875% Senior Notes due April 2016	—		218.1
7.375% Senior Notes due November 2016	650.0		650.0
6.00% Senior Notes due November 2018	1,600.0		—
6.50% Senior Notes due September 2020	650.0		650.0
6.25% Senior Notes due November 2021	1,500.0		—
7.875% Senior Notes due November 2026	247.3		247.2
Convertible Junior Subordinated Debentures due 2066	375.2		373.3
Capital lease obligations	122.8		69.6
Fair value hedge adjustment	—		2.2
Other	43.4		45.8
Total	$	6,657.5	$	2,750.0

We were in compliance with all of the covenants of the Credit Facility, the 2011 Term Loan Facility, the 7.375% Senior Notes, the 6.00% Senior Notes, the 6.50% Senior Notes, the 6.25% Senior Notes, the 7.875% Senior Notes and the Debentures as of December 31, 2011. As market conditions warrant, we may from time to time repurchase debt securities issued by us, in private negotiated or open market transactions, by tender offer or otherwise.

Margin. As part of our trading and brokerage activities, we may be required to post margin with an exchange or one of our counterparties. The amount and timing of margin posted can vary with the volume of trades and market price volatility. Total margin held at December 31, 2011 was $18.1 million as compared to total margin posted of $192.1 million at December 31, 2010. For the year ended December 31, 2011, net cash inflows for margin were $210.2 million. Net cash outflows for margin were $161.2 million for the year ended December 31, 2010.

Shelf Registration.  We have an effective shelf registration statement on file with the SEC for an indeterminate number of securities that is effective for three years (expires August 7, 2012), at which time we expect to be able to file an automatic shelf registration statement that would become immediately effective for another three-year term. Under this universal shelf registration statement, we have the capacity to offer and sell from time to time: securities, including common stock, preferred stock, debt securities, warrants and units.

Historical Cash Flows

	Year Ended December 31,						Increase (Decrease) to Cash Flow
	2011			2010			$			%
				(Dollars in millions)
Net cash provided by operating activities	$	1,633.2		$	1,087.1		$	546.1		50.2	%
Net cash used in investing activities	(3,807.8		)	(703.6		)	(3,104.2		)	441.2	%
Net cash provided by (used in) financing activities	1,678.5			(77.1		)	1,755.6			(2,277.0	)%

Operating Activities.  The changes from the prior year were due to the following:

• Higher cash inflows associated with a return of margin posted on trading activities;

• Increased operating cash flows generated from our Australian Mining operations driven by higher pricing; and

• A prior year decrease in the utilization of our accounts receivable securitization program.

53

Investing Activities.  The changes from the prior year were due to the following:

• $2.8 billion for the acquisition of a controlling interest in Macarthur; and

• Higher current year capital spending, including Prairie State, of $259.2 million related primarily to our expansion projects in Australia, partially offset by prior year spending to establish and ramp up operations at our Bear Run Mine.

Financing Activities. The changes from the prior year were due to the following:

• A net increase in borrowings of long-term debt compared to 2010 of $3.9 billion driven by the $4.1 billion of debt proceeds that were used, in part, to fund the Macarthur acquisition; and

• Acquisition of noncontrolling interests of $2.0 billion.

Contractual Obligations

The following is a summary of our contractual obligations as of December 31, 2011:

	Payments Due By Year
	Total		Less than 1 Year		2 - 3 Years		4 - 5 Years		More than 5 Years
	(Dollars in millions)
Long-term debt obligations (principal and interest)	$	10,704.2	$	458.8	$	961.1	$	2,722.8	$	6,561.5
Capital lease obligations (principal and interest)	142.0		32.3		67.2		20.8		21.7
Operating lease obligations	610.9		123.1		196.8		139.9		151.1
Unconditional purchase obligations(1)	1,313.0		743.6		569.4		—		—
Coal reserve lease and royalty obligations	227.8		50.7		98.8		50.4		27.9
Take or pay obligations(2)	4,547.6		443.1		824.4		469.0		2,811.1
Other long-term liabilities(3)	3,035.6		174.1		331.0		324.0		2,206.5
Total contractual cash obligations	$	20,581.1	$	2,025.7	$	3,048.7	$	3,726.9	$	11,779.8

⁽¹⁾  We have purchase agreements with approved vendors for most types of operating expenses. However, our specific open purchase orders (which have not been recognized as a liability) under these purchase agreements, combined with any other open purchase orders, are not material. The commitments in the table above relate to capital purchases. The purchase obligations for capital expenditures relate to new mines and expansion and extension projects in Australia and the U.S.

⁽²⁾  Represents various long- and short-term take or pay arrangements associated with rail and port commitments for the delivery of coal including amounts relating to export facilities. Also includes commitments under electricity, water and coal washing agreements with joint ventures.

⁽³⁾  Represents long-term liabilities relating to our postretirement benefit plans, work-related injuries and illnesses, defined benefit pension plans, mine reclamation and end of mine closure costs and exploration obligations.

We do not expect any of the $119.6 million of gross unrecognized tax benefits reported in our consolidated financial statements to require cash settlement within the next year. Beyond that, we are unable to make reasonably reliable estimates of periodic cash settlements with respect to such unrecognized tax benefits.

Off-Balance Sheet Arrangements

In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees, indemnifications, financial instruments with off-balance sheet risk, such as bank letters of credit, bank guarantees and surety bonds and our accounts receivable securitization program. Assets and liabilities related to these arrangements are not reflected in our consolidated balance sheets, and we do not expect any material adverse effects on our financial condition, results of operations or cash flows to result from these off-balance sheet arrangements.

54

Accounts Receivable Securitization. We have an accounts receivable securitization program (securitization program) with a maximum capacity of $275.0 million through our wholly-owned, bankruptcy-remote subsidiary (Seller). At December 31, 2011, we had $41.7 million available under the securitization program, net of outstanding letters of credit and amounts drawn. Under the securitization program, we contribute, on a revolving basis, trade receivables of most of our U.S. subsidiaries to the Seller, which then sells the receivables in their entirety to a consortium of unaffiliated asset-backed commercial paper conduits (the Conduits). After the sale, we, as servicer of the assets, collect the receivables on behalf of the Conduits for a nominal servicing fee. We utilize proceeds from the sale of our accounts receivable as an alternative to short-term borrowings under the Revolver portion of our Credit Facility, effectively managing our overall borrowing costs and providing an additional source for working capital. The current securitization program extends to May 2012, while the letter of credit commitment that supports the commercial paper facility underlying the securitization program must be renewed annually.

The Seller is a separate legal entity whose assets are available first and foremost to satisfy the claims of its creditors. Of the receivables sold to the Conduits, a portion of the amount due to the Seller is deferred until the ultimate collection of the underlying receivables. During the year ended December 31, 2011, we received total consideration of $4,633.4 million related to accounts receivable sold under the securitization program, including $3,462.7 million of cash up front from the sale of the receivables, an additional $1,004.8 million of cash upon the collection of the underlying receivables, and $165.9 million that had not been collected at December 31, 2011 and was recorded at fair value which approximates carrying value. The reduction in accounts receivable as a result of securitization activity with the Conduits was $150.0 million at December 31, 2011 and 2010.

The securitization activity has been reflected in the consolidated statements of cash flows as an operating activity because both the cash received from the Conduits upon sale of receivables as well as the cash received from the Conduits upon the ultimate collection of receivables are not subject to significantly different risks given the short-term nature of our trade receivables. We recorded expense associated with securitization transactions of $2.0 million, $2.4 million and $4.0 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Other Off-Balance Sheet Arrangements. From time to time, we enter into coal offtake agreements with counterparties where, as a part of the arrangements, we may provide certain financial guarantees on behalf of the counterparties. As of December 31, 2011, we had in place guarantees of $10.0 million on behalf of our counterparties relating to such agreements. To mitigate risk, we place liens on the counterparties' production equipment or require performance bonds.

In January 2011, we entered into a bilateral cash collateralization agreement in support of certain letters of credit whereby we posted cash collateral in lieu of utilizing our Credit Facility. The capacity under this new agreement is $37.0 million, all of which was posted as collateral at December 31, 2011. As of December 31, 2011, we had a total of $79.7 million posted as collateral under such agreements. The cash collateral is classified within "Cash and cash equivalents" given our ability to substitute letters of credit at any time for this cash collateral.

As discussed above in Capital Resources, we also had $65.0 million (Australian dollars) of letters of credit and cash backed bank guarantees outstanding under the Macarthur Corporate Funding Facility at December 31, 2011.

See Note 22 to our consolidated financial statements for a discussion of our guarantees.

55

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition, results of operations, liquidity and capital resources is based upon our financial statements, which have been prepared in accordance with U.S. GAAP. We are also required under U.S. GAAP to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. On an ongoing basis, we evaluate our estimates. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates.

Postretirement Benefit and Pension Liabilities.  We have long-term liabilities for our employees’ postretirement benefit costs and defined benefit pension plans. Detailed information related to these liabilities is included in Notes 14 and 15 to our consolidated financial statements. Liabilities for postretirement benefit costs are not funded. Our pension obligations are funded in accordance with the provisions of applicable law. Expense for the year ended December 31, 2011 for pension and postretirement liabilities totaled $119.7 million, while funding payments were $112.8 million.

Each of these liabilities is actuarially determined and we use various actuarial assumptions, including the discount rate and future cost trends, to estimate the costs and obligations for these items. Our discount rate is determined by utilizing a hypothetical bond portfolio model which approximates the future cash flows necessary to service our liabilities.

We make assumptions related to future trends for medical care costs in the estimates of retiree health care and work-related injuries and illnesses obligations. Our medical trend assumption is developed by annually examining the historical trend of our cost per claim data. In addition, we make assumptions related to future compensation increases and rates of return on plan assets in the estimates of pension obligations.

If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could differ materially from our current estimates. Moreover, regulatory changes could increase our obligation to satisfy these or additional obligations. For our postretirement health care liability, assumed discount rates and health care cost trend rates have a significant effect on the expense and liability amounts reported for health care plans. Below we have provided two separate sensitivity analyses to demonstrate the significance of these assumptions in relation to reported amounts.

Health care cost trend rate:	For Year Ended December 31, 2011
	One-Percentage- Point Increase		One-Percentage- Point Decrease
	(Dollars in millions)
Effect on total service and interest cost components(1)	$	8.2	$	(6.9	)
Effect on total postretirement benefit obligation(1)	$	121.8	$	(104.6	)

Discount rate:	For Year Ended December 31, 2011
	One-Half Percentage- Point Increase			One-Half Percentage- Point Decrease
	(Dollars in millions)
Effect on total service and interest cost components(1)	$	0.7		$	(0.7	)
Effect on total postretirement benefit obligation(1)	$	(56.8	)	$	64.8

⁽¹⁾  In addition to the effect on total service and interest cost components of expense, changes in trend and discount rates would also increase or decrease the actuarial gain or loss amortization expense component. The gain or loss amortization would approximate the increase or decrease in the obligation divided by 11.70 years at January 1, 2012.

56

Asset Retirement Obligations.  Our asset retirement obligations primarily consist of spending estimates for surface land reclamation and support facilities at both surface and underground mines in accordance with applicable reclamation laws in the U.S. and Australia as defined by each mining permit. Asset retirement obligations are determined for each mine using various estimates and assumptions including, among other items, estimates of disturbed acreage as determined from engineering data, estimates of future costs to reclaim the disturbed acreage and the timing of these cash flows, discounted using a credit-adjusted, risk-free rate. As changes in estimates occur (such as mine plan revisions, changes in estimated costs, or changes in timing of the reclamation activities), the obligation and asset are revised to reflect the new estimate after applying the appropriate credit-adjusted, risk-free rate. If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could be materially different than currently estimated. Moreover, regulatory changes could increase our obligation to perform reclamation and mine closing activities. Asset retirement obligation expense for the year ended December 31, 2011 was $53.1 million, and payments totaled $16.9 million. See Note 13 to our consolidated financial statements for additional details regarding our asset retirement obligations.

Income Taxes.  We account for income taxes in accordance with accounting guidance which requires deferred tax assets and liabilities be recognized using enacted tax rates for the effect of temporary differences between the book and tax bases of recorded assets and liabilities. The guidance also requires that deferred tax assets be reduced by a valuation allowance if it is “more likely than not” that some portion or all of the deferred tax asset will not be realized. In our annual evaluation of the need for a valuation allowance, we take into account various factors, including the expected level of future taxable income and available tax planning strategies. If actual results differ from the assumptions made in our annual evaluation of our valuation allowance, we may record a change in valuation allowance through income tax expense in the period such determination is made.

Our liability for unrecognized tax benefits contains uncertainties because management is required to make assumptions and to apply judgment to estimate the exposures associated with our various filing positions. We recognize the tax benefit from an uncertain tax position only if it is “more likely than not” that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position must be measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. We believe that the judgments and estimates are reasonable; however, actual results could differ.

Business Combinations.  We account for business combinations using the purchase method of accounting. The purchase method requires us to determine the fair value of all acquired assets, including identifiable intangible assets, and all assumed liabilities. The total cost of acquisitions is allocated to the underlying identifiable net assets, based on their respective estimated fair values. Determining the fair value of assets acquired and liabilities assumed requires management's judgment, and the utilization of independent valuation experts, and often involves the use of significant estimates and assumptions, including assumptions with respect to future cash inflows and outflows, discount rates, and asset lives, among other items.

Level 3 Fair Value Measurements.  In accordance with the “Fair Value Measurements and Disclosures” topic of the Financial Accounting Standards Board Accounting Standards Codification, we evaluate the quality and reliability of the assumptions and data used to measure fair value in the three level hierarchy, Levels 1, 2 and 3. Level 3 fair value measurements are those where inputs are unobservable, or observable but cannot be market-corroborated, requiring us to make assumptions about pricing by market participants. Commodity swaps and options and physical commodity purchase/sale contracts transacted in less liquid markets or contracts, such as long-term arrangements, with limited price availability were classified in Level 3. Indicators of less liquid markets are those with periods of low trade activity or when broker quotes reflect wide pricing spreads. Generally, these instruments or contracts are valued using internally generated models that include forward pricing curve quotes from one to three reputable brokers. Our valuation techniques also include basis adjustments for heat rate, sulfur and ash content, port and freight costs, and credit and nonperformance risk. We validate our valuation inputs with third-party information and settlement prices from other sources where available. We also consider credit and nonperformance risk in the fair value measurement by analyzing the counterparty’s exposure balance, credit rating and average default rate, net of any counterparty credit enhancements (e.g., collateral), as well as our own credit rating for financial derivative liabilities.

We have consistently applied these valuation techniques in all periods presented, and believe we have obtained the most accurate information reasonably available for the types of derivative contracts held. Valuation changes from period to period for each level will increase or decrease depending on: (i) the relative change in fair value for positions held, (ii) new positions added, (iii) realized amounts for completed trades, and (iv) transfers between levels. Our coal trading strategies utilize various swaps and derivative physical contracts. Periodic changes in fair value for purchase and sale positions, which are executed to lock in coal trading spreads, occur in each level and therefore the overall change in value of our coal-trading platform requires consideration of valuation changes across all levels.

57

At December 31, 2011 and 2010, 1% ($8.7 million) and 3% ($18.6 million), respectively, of our net financial assets were categorized as Level 3. See Notes 6 and 7 to our consolidated financial statements for additional information regarding fair value measurements.

Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented

See Note 1 to our consolidated financial statements for a discussion of newly adopted accounting pronouncements and accounting pronouncements not yet implemented.

Item 7A.  Quantitative and Qualitative Disclosures About Market Risk

The potential for changes in the market value of our coal and freight trading, crude oil, diesel fuel, natural gas, explosives, interest rate and currency portfolios is referred to as “market risk.” Market risk related to our coal trading and freight portfolio, which includes bilaterally-settled and exchange-settled over-the-counter trading as well as brokered trading of coal, is evaluated using a value at risk (VaR) analysis. VaR analysis is not used to evaluate our non-trading interest rate, diesel fuel, explosives and currency hedging portfolios or coal trading activities we employ in support of coal production (as discussed below). We attempt to manage market risks through diversification, controlling position sizes and executing hedging strategies. Due to lack of quoted market prices and the long-term, illiquid nature of the positions, we have not quantified market risk related to our non-trading, long-term coal supply agreement portfolio.

Coal Trading Activities and Related Commodity Price Risk

Coal Price Risk Monitored Using VaR. We engage in direct and brokered trading of coal, ocean freight and fuel-related commodities in over-the-counter markets. These activities give rise to commodity price risk, which represents the potential loss that can be caused by an adverse change in the market value of a particular commitment. We actively measure, monitor and adjust traded position levels to remain within risk limits prescribed by management. For example, we have policies in place that limit the amount of risk, as measured by VaR, that we may assume at any point in time on trading and brokerage activities.

We account for coal trading using the fair value method, which requires us to reflect financial instruments with third parties at market value in our condensed consolidated financial statements. Our trading portfolio included forwards, swaps and options as of December 31, 2011.

The use of VaR allows us to quantify in dollars, on a daily basis, a measure of price risk inherent in our trading portfolio. VaR represents the expected loss in portfolio value due to adverse market movements over a defined time horizon (liquidation period) within a specified confidence level. Our VaR model is based on a variance/co-variance approach. This captures our exposure related to forwards, swaps and options positions. Our VaR model calculates a 5 to 15-day holding period dependent upon the products within our portfolio at the time of VaR measurement and a 95% one-tailed confidence interval. This means that there is a one in 20 statistical chance that the portfolio would lose more than the VaR estimates during the liquidation period. Our volatility calculation incorporates an exponentially weighted moving average algorithm based on the previous 60 market days, which makes our volatility more representative of recent market conditions, while still reflecting an awareness of historical price movements. VaR does not estimate the maximum loss expected in the 5% of the time the portfolio value exceeds measured VaR.

The use of VaR allows us to aggregate pricing risks across products in the portfolio, compare risk on a consistent basis and identify the drivers of risk. We use historical data to estimate price volatility as an input to VaR. Given our reliance on historical data, we believe VaR is reasonably effective in characterizing risk exposures in markets in which there are not sudden fundamental changes or shifts in market conditions. Due to the subjectivity in the choice of the liquidation period, reliance on historical data to calibrate the models and the inherent limitations in the VaR methodology, we perform regular stress and scenario analyses to estimate the impacts of market changes on the value of the portfolio. Additionally, back-testing is regularly performed to monitor the effectiveness of our VaR measure. The results of these analyses are used to supplement the VaR methodology and identify additional market-related risks. An inherent limitation of VaR is that past changes in market risk factors may not produce accurate predictions of future market risk.

During the year ended December 31, 2011, the actual low, high, and average VaR was $3.5 million, $30.6 million and $13.4 million, respectively.

58

Other Risk Exposures. We also use our coal trading and brokerage platform to support various coal production-related activities. These transactions may involve coal to be produced from our mines, coal sourcing arrangements with third-party mining companies, joint venture positions with producers or offtake agreements with producers. While the support activities (e.g. forward sale of coal to be produced and/or purchased) may ultimately involve market risk sensitive instruments, the sourcing of coal in these arrangements does not involve market risk sensitive instruments and does not encompass the commodity price risks that we monitor through VaR, as discussed above.

Future Realization. As of December 31, 2011, the timing of the estimated future realization of the value of our trading portfolio was as follows:

Year of	Percentage of
Expiration	Portfolio Total
2012	65%
2013	29%
2014	4%
2015	2%
	100%

We also monitor other types of risk associated with our coal trading activities, including credit, market liquidity and counterparty nonperformance.

Nonperformance and Credit Risk

Coal Trading. The fair value of our coal trading assets and liabilities reflects adjustments for nonperformance and credit risk. Our exposure is substantially with electric utilities, energy producers and energy marketers. Our policy is to independently evaluate each customer’s creditworthiness prior to entering into transactions and to regularly monitor the credit extended. If we engage in a transaction with a counterparty that does not meet our credit standards, we seek to protect our position by requiring the counterparty to provide an appropriate credit enhancement. Also, when appropriate (as determined by our credit management function), we have taken steps to reduce our exposure to customers or counterparties whose credit has deteriorated and who may pose a higher risk of failure to perform under their contractual obligations. These steps include obtaining letters of credit or cash collateral (margin), requiring prepayments for shipments or the creation of customer trust accounts held for our benefit to serve as collateral in the event of a failure to pay or perform. To reduce our credit exposure related to trading and brokerage activities, we seek to enter into netting agreements with counterparties that permit us to offset receivables and payables with such counterparties and, to the extent required, will post or receive margin amounts associated with exchange-cleared positions.

Non-Coal Trading. The fair value of our non-coal trading derivative assets and liabilities also reflects adjustments for nonperformance and credit risk. We conduct our hedging activities related to foreign currency, interest rate, fuel and explosives exposures with a variety of highly-rated commercial banks and closely monitor counterparty creditworthiness. To reduce our credit exposure for these hedging activities, we seek to enter into netting agreements with counterparties that permit us to offset receivables and payables with such counterparties.

Foreign Currency Risk

We utilize currency forwards to hedge currency risk associated with anticipated Australian dollar expenditures. The accounting for these derivatives is discussed in Note 6 to our consolidated financial statements. Assuming we had no hedges in place, our exposure in operating costs and expenses due to a $0.05 change in the Australian dollar/U.S. dollar exchange rate is approximately $150 million for 2012. However, taking into consideration hedges currently in place, our net exposure to the same rate change is approximately $65 million for 2012. The table at the end of Item 7A shows the notional amount of our hedge contracts as of December 31, 2011.

59

Interest Rate Risk

Our objectives in managing exposure to interest rate changes are to limit the impact of interest rate changes on earnings and cash flows and to lower overall borrowing costs. From time to time, we manage our debt to achieve a certain ratio of fixed-rate debt and variable-rate debt as a percent of net debt through the use of various hedging instruments, which are discussed in detail in Note 6 to our consolidated financial statements. As of December 31, 2011, we had $5.2 billion of fixed-rate borrowings and $1.5 billion of variable-rate borrowings outstanding and had no interest rate swaps in place. A one percentage point increase in interest rates would result in an annualized increase to interest expense of approximately $15 million on our variable-rate borrowings. With respect to our fixed-rate borrowings, a one percentage point increase in interest rates would result in a decrease of approximately $338 million in the estimated fair value of these borrowings.

Other Non-trading Activities — Commodity Price Risk

Long-Term Coal Contracts. We manage our commodity price risk for our non-trading, long-term coal contract portfolio through the use of long-term coal supply agreements (those with terms longer than one year), rather than through the use of derivative instruments. Sales under such agreements comprised approximately 91%, 91% and 93% of our worldwide sales (by volume) for the years ended December 31, 2011, 2010 and 2009, respectively. Substantially all of our coal in the U.S. is contracted in 2012 at planned production levels. We had 40% to 50% of seaborne thermal coal volumes available for pricing in at January 24, 2012. We expect near-term macroeconomic movements to dictate quarterly metallurgical coal pricing for the remainder of the 2012 and we are targeting total 2012 metallurgical coal sales of approximately 14 to 15 million tons.

Diesel Fuel and Explosives Hedges. We manage commodity price risk of the diesel fuel and explosives used in our mining activities through the use of cost pass-through contracts and derivatives, primarily swaps.

Notional amounts outstanding under fuel-related, derivative swap contracts are noted in the table at the end of Item 7A. We expect to consume 160 to 165 million gallons of diesel fuel in 2012. Assuming we had no hedges in place, a $10 per barrel change in the price of crude oil (the primary component of a refined diesel fuel product) would increase or decrease our annual diesel fuel costs by approximately $38 million based on our expected usage. However, taking into consideration hedges currently in place, our net exposure to changes in the price of crude oil is approximately $15 million.

Notional amounts outstanding under explosives-related swap contracts are noted in the table at the end of Item 7A. We expect to consume 380,000 to 390,000 tons of explosives during 2012 in the U.S. Explosives costs in Australia are generally included in the fees paid to our contract miners. Assuming we had no hedges in place, a price change in natural gas (often a key component in the production of explosives) of one dollar per million MMBtu would result in an increase or decrease in our annual explosives costs of approximately $7 million based on our expected usage. However, taking into consideration hedges currently in place, our net exposure to changes in the price of natural gas is approximately $2 million.

60

Notional Amounts and Fair Value.  The following summarizes our interest rate, foreign currency and commodity positions at December 31, 2011:

	Notional Amount by Year of Maturity
	Total		2012		2013		2014		2015		2016		2017 and thereafter
Foreign Currency
A$:US$ hedge contracts (A$ millions)	$	3,910.6	$	1,750.5	$	1,309.6	$	850.5	$	—	$	—	$	—
GBP:US$ hedge contracts (GBP millions)	6.5		6.5		—		—		—		—		—
Commodity Contracts
Diesel fuel hedge contracts (million gallons)	189.6		86.0		68.0		35.6		—		—		—
U.S. explosives hedge contracts (million MMBtu)	7.7		3.9		2.6		1.2		—		—		—

	Account Classification by
	Cash flow hedge		Fair value hedge		Economic hedge		Fair Value Asset (Liability)
							(Dollars in millions)
Foreign Currency
A$:US$ hedge contracts (A$ millions)	$	3,910.6	$	—	$	—	$	491.3
GBP:US$ hedge contracts (GBP millions)	6.5		—		—		$	(0.7	)
Commodity Contracts
Diesel fuel hedge contracts (million gallons)	189.6		—		—		$	43.7
U.S. explosives hedge contracts (million MMBtu)	7.7		—		—		$	(10.7	)

Item 8.  Financial Statements and Supplementary Data.

See Part IV, Item 15 of this report for information required by this Item, which information is incorporated by reference herein.

Item 9.  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9A.   Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Our disclosure controls and procedures are designed to, among other things, provide reasonable assurance that material information, both financial and non-financial, and other information required under the securities laws to be disclosed is accumulated and communicated to senior management, including the principal executive officer and principal financial officer, on a timely basis. As of December 31, 2011, the end of the period covered by this Annual Report on Form 10-K, we carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer have evaluated our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of December 31, 2011, and concluded that such controls and procedures are effective to provide reasonable assurance that the desired control objectives were achieved.

61

Changes in Internal Control Over Financial Reporting

We periodically review our internal control over financial reporting as part of our efforts to ensure compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002. In addition, we routinely review our system of internal control over financial reporting to identify potential changes to our processes and systems that may improve controls and increase efficiency, while ensuring that we maintain an effective internal control environment. Changes may include such activities as implementing new systems, consolidating the activities of acquired business units, migrating certain processes to our shared services organizations, formalizing and refining policies and procedures, improving segregation of duties and adding monitoring controls. In addition, when we acquire new businesses, we incorporate our controls and procedures into the acquired business as part of our integration activities.

On October 26, 2011, we acquired Macarthur. As a result of the acquisition, we are in the process of reviewing the internal control structure of Macarthur and, if necessary, will make appropriate changes as we incorporate our controls and procedures into the acquired business. Except for the acquisition, there have been no changes in our internal control over financial reporting that occurred during the three months ended December 31, 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management's Report on Internal Control Over Financial Reporting

Management is responsible for maintaining and establishing adequate internal control over financial reporting. Our internal control framework and processes are designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external purposes in accordance with U.S. generally accepted accounting principles.

Because of inherent limitations, any system of internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management conducted an assessment of the effectiveness of our internal control over financial reporting using the criteria set by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. Based on this assessment, management concluded that the Company's internal control over financial reporting was effective to provide reasonable assurance that the desired control objectives were achieved as of December 31, 2011.

Management's assessment of the effectiveness of our internal control over financial reporting did not include the internal controls of Macarthur, which was acquired on October 26, 2011. In accordance with SEC guidance regarding the reporting of internal control over financial reporting in connection with an acquisition, management may omit an assessment of an acquired business' internal control over financial reporting from management's assessment of internal control over financial reporting for a period not to exceed one year from the date of acquisition. Management's assessment of the effectiveness of our internal control over financial reporting as of December 31, 2012 will include the internal controls of Macarthur. Macarthur is included in our consolidated financial statements and constituted $5.3 billion of total assets, $152.9 million of revenues and contributed a net loss of $47.9 million of our net income as of and for the year ended December 31, 2011.

Our Independent Registered Public Accounting Firm, Ernst & Young LLP, has audited our internal control over financial reporting, as stated in their unqualified opinion report included herein.

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

February 27, 2012

62

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Peabody Energy Corporation

We have audited Peabody Energy Corporation’s (the Company’s) internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). The Company’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

As indicated in the accompanying Management's Report on Internal Control Over Financial Reporting, management's assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of entities acquired through the Macarthur Coal Limited acquisition, which is included in the 2011 consolidated financial statements of the Company and constituted $5.3 billion and $5.0 billion of total and net assets, respectively, as of December 31, 2011, and $152.9 million and $47.9 million of revenues and net loss, respectively, for the year then ended. Our audit of internal control over financial reporting of the Company also did not include an evaluation of the internal control over financial reporting of entities acquired through the Macarthur Coal Limited acquisition.

In our opinion, Peabody Energy Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Peabody Energy Corporation as of December 31, 2011 and 2010, and the related consolidated statements of income, comprehensive income, changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2011 and our report dated February 27, 2012, expressed an unqualified opinion thereon.

/s/  Ernst & Young LLP

St. Louis, Missouri

February 27, 2012

63

Item 9B. Other Information.

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance.

The information required by Item 401 of Regulation S-K is included under the caption “Election of Directors-Director Qualifications” in our 2012 Proxy Statement and in Part I of this report under the caption “Executive Officers of the Company.” The information required by Items 405, 406 and 407(c)(3), (d)(4) and (d)(5) of Regulation S-K is included under the captions “Ownership of Company Securities — Section 16(a) Beneficial Ownership Reporting Compliance,” “Corporate Governance Matters” and “Information Regarding Board of Directors and Committees-Committees of the Board of Directors-Audit Committee” in our 2012 Proxy Statement. Such information is incorporated herein by reference.

Item 11. Executive Compensation.

The information required by Items 402 and 407(e)(4) and (e)(5) of Regulation S-K is included under the captions “Executive Compensation,” “Compensation Committee Interlocks and Insider Participation” and “Report of the Compensation Committee” in our 2012 Proxy Statement and is incorporated herein by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The information required by Item 403 of Regulation S-K is included under the caption “Ownership of Company Securities” in our 2012 Proxy Statement and is incorporated herein by reference.

Equity Compensation Plan Information

As required by Item 201(d) of Regulation S-K, the following table provides information regarding our equity compensation plans as of December 31, 2011:

	(a) Number of Securities to be Issued upon Exercise of Outstanding Options, Warrants and Rights		Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights			Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a))
Plan Category
Equity compensation plans approved
by security holders	1,703,574	(1)	$	32.53	(2)	16,929,167	(3)
Equity compensation plans not approved
by security holders	—		—			—
Total	1,703,574		$	32.53		16,929,167

⁽¹⁾  Includes 57,528 shares issuable pursuant to outstanding deferred stock units and 344,439 shares issuable pursuant to outstanding performance units.

⁽²⁾  The weighted average exercise price shown in the table does not take into account outstanding deferred stock units or performance awards.

⁽³⁾  Includes 2,142,300 shares available for issuance under our U.S. Employee Stock Purchase Plan and 962,604 shares available for issuance under our Australian Employee Stock Purchase Plan.

64

Item 13. Certain Relationships and Related Transactions, and Director Independence.

The information required by Items 404 and 407(a) of Regulation S-K is included under the captions “Policy for Approval of Related Person Transactions” and “Information Regarding Board of Directors and Committees-Director Independence” in our 2012 Proxy Statement and is incorporated herein by reference.

Item 14. Principal Accounting Fees and Services.

The information required by Item 9(e) of Schedule 14A is included under the caption “Fees Paid to Independent Registered Public Accounting Firm” in our 2012 Proxy Statement and is incorporated herein by reference.

PART IV

Item 15. Exhibit, Financial Statement Schedules.

(a) Documents Filed as Part of the Report

(1) Financial Statements.

The following consolidated financial statements of Peabody Energy Corporation are included herein on the pages indicated:

	Page
Report of Independent Registered Public Accounting Firm	F-1
Consolidated Statements of Income  — Years Ended December 31, 2011, 2010 and 2009	F-2
Consolidated Statements of Comprehensive Income  — Years Ended December 31, 2011, 2010 and 2009	F-3
Consolidated Balance Sheets — December 31, 2011 and December 31, 2010	F-4
Consolidated Statements of Cash Flows — Years Ended December 31, 2011, 2010 and 2009	F-5
Consolidated Statements of Changes in Stockholders’ Equity — Years Ended December 31, 2011, 2010 and 2009	F-7
Notes to Consolidated Financial Statements	F-8

(2) Financial Statement Schedule.

The following financial statement schedule of Peabody Energy Corporation and the report thereon of the independent registered public accounting firm are at the pages indicated:

	Page
Valuation and Qualifying Accounts	F-71

All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions or are inapplicable and, therefore, have been omitted.

(3) Exhibits.

See Exhibit Index hereto.

Pursuant to the Instructions to Exhibits, certain instruments defining the rights of holders of long-term debt securities of the Company and its consolidated subsidiaries are not filed because the total amount of securities authorized under any such instrument does not exceed 10% of the total assets of the Company and its subsidiaries on a consolidated basis. A copy of such instrument will be furnished to the Securities and Exchange Commission upon request.

65

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

PEABODY ENERGY CORPORATION

/s/  GREGORY H. BOYCE

Gregory H. Boyce

Chairman and Chief Executive Officer

Date: February 27, 2012

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons, on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/  GREGORY H. BOYCE	Chairman and Chief Executive Officer, Director (principal executive officer)	February 27, 2012
Gregory H. Boyce
/s/  MICHAEL C. CREWS	Executive Vice President and Chief Financial Officer (principal financial and accounting officer)	February 27, 2012
Michael C. Crews
/s/  WILLIAM A. COLEY	Director	February 27, 2012
William A. Coley
/s/  WILLIAM E. JAMES	Director	February 27, 2012
William E. James
/s/  ROBERT B. KARN III	Director	February 27, 2012
Robert B. Karn III
/s/  M. FRANCES KEETH	Director	February 27, 2012
M. Frances Keeth
/s/  HENRY E. LENTZ	Director	February 27, 2012
Henry E. Lentz
/s/  ROBERT A. MALONE	Director	February 27, 2012
Robert A. Malone
/s/  WILLIAM C. RUSNACK	Director	February 27, 2012
William C. Rusnack
/s/  JOHN F. TURNER	Director	February 27, 2012
John F. Turner
/s/  SANDRA VAN TREASE	Director	February 27, 2012
Sandra Van Trease
/s/  ALAN H. WASHKOWITZ	Director	February 27, 2012
Alan H. Washkowitz

66

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Peabody Energy Corporation

We have audited the accompanying consolidated balance sheets of Peabody Energy Corporation (the Company) as of December 31, 2011 and 2010, and the related consolidated statements of income, comprehensive income, changes in stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2011. Our audits also included the financial statement schedule listed in Item 15(a). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Peabody Energy Corporation at December 31, 2011 and 2010, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Peabody Energy Corporation’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2012, expressed an unqualified opinion thereon.

/s/  Ernst & Young LLP

St. Louis, Missouri

February 27, 2012

F - 1

PEABODY ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

	Year Ended December 31,
	2011			2010			2009
	(Dollars in millions, except per share data)
Revenues
Sales	$	7,091.3		$	6,211.2		$	5,303.1
Other revenues	883.1			528.7			543.9
Total revenues	7,974.4			6,739.9			5,847.0
Costs and expenses
Operating costs and expenses	5,550.0			4,697.3			4,339.2
Depreciation, depletion and amortization	482.2			437.1			400.5
Asset retirement obligation expense	53.1			47.2			39.9
Selling and administrative expenses	268.2			232.2			199.1
Acquisition costs related to Macarthur Coal Limited	85.2			—			—
Other operating (income) loss:
Net gain on disposal or exchange of assets	(76.9		)	(30.0		)	(23.2		)
Loss from equity affiliates	19.2			1.7			69.1
Operating profit	1,593.4			1,354.4			822.4
Interest expense	238.6			222.0			201.1
Interest income	(18.9		)	(9.6		)	(8.1		)
Income from continuing operations before income taxes	1,373.7			1,142.0			629.4
Income tax provision	363.2			315.4			186.2
Income from continuing operations, net of income taxes	1,010.5			826.6			443.2
(Loss) income from discontinued operations, net of income taxes	(64.2		)	(24.4		)	19.8
Net income	946.3			802.2			463.0
Less: Net (loss) income attributable to noncontrolling interests	(11.4		)	28.2			14.8
Net income attributable to common stockholders	$	957.7		$	774.0		$	448.2
Income From Continuing Operations
Basic earnings per share	$	3.77		$	2.97		$	1.60
Diluted earnings per share	$	3.76		$	2.93		$	1.59
Net Income Attributable to Common Stockholders
Basic earnings per share	$	3.53		$	2.88		$	1.68
Diluted earnings per share	$	3.52		$	2.84		$	1.66
Dividends declared per share	$	0.340		$	0.295		$	0.250

See accompanying notes to consolidated financial statements

F - 2

PEABODY ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Year Ended December 31,
	2011			2010			2009
	(Dollars in millions)
Net income	$	946.3		$	802.2		$	463.0
Other comprehensive income, net of income taxes:
Net unrealized losses on available-for-sale securities (net of $3.9 tax benefit for 2011)
Unrealized holding losses on available-for-sale securities	(5.8		)	—			—
Less: Reclassification for realized gains included in net income	(0.9		)	—			—
Unrealized losses on available-for-sale securities	(6.7		)	—			—
Unrealized gains on cash flow hedges (net of $6.2 tax benefit for 2011 and $129.5 and $220.9 tax provision for 2010 and 2009, respectively)
Increase in fair value of cash flow hedges	291.9			229.9			235.2
Less: Reclassification for realized (gains) losses included in net income	(251.0		)	(102.4		)	84.6
Unrealized gains on cash flow hedges	40.9			127.5			319.8
Postretirement plans and workers' compensation obligations (net of $63.4, $2.1 and $71.8 tax benefit for 2011, 2010, and 2009, respectively)
Net actuarial loss for the period	(149.2		)	(46.2		)	(128.4		)
Amortization of actuarial loss and prior service cost	40.5			34.3			13.6
Postretirement plan and worker's compensation obligations	(108.7		)	(11.9		)	(114.8		)
Other comprehensive (loss) income	(74.5		)	115.6			205.0
Comprehensive income	871.8			917.8			668.0
Less: Comprehensive (loss) income attributable to noncontrolling interests	(11.4		)	28.2			14.8
Comprehensive income attributable to common stockholders	$	883.2		$	889.6		$	653.2

See accompanying notes to consolidated financial statements

F - 3

PEABODY ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

	December 31,
	2011			2010
	(Amounts in millions, except per share data)
ASSETS
Current assets
Cash and cash equivalents	$	799.1		$	1,295.2
Accounts receivable, net of allowance for doubtful accounts of $17.0 at December 31, 2011 and $30.3 at December 31, 2010	922.5			555.8
Inventories	446.3			327.2
Assets from coal trading activities, net	44.6			192.5
Deferred income taxes	27.3			120.4
Other current assets	766.1			467.1
Total current assets	3,005.9			2,958.2
Property, plant, equipment and mine development
Land and coal interests	10,781.0			7,633.8
Buildings and improvements	1,131.4			1,067.4
Plant and equipment	2,862.4			1,664.5
Less: accumulated depreciation, depletion and amortization	(3,412.1		)	(2,987.6		)
Property, plant, equipment and mine development, net	11,362.7			7,378.1
Investments and other assets	2,364.4			1,026.8
Total assets	$	16,733.0		$	11,363.1
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	101.1		$	43.2
Liabilities from coal trading activities, net	10.3			181.7
Accounts payable and accrued expenses	1,712.3			1,288.8
Total current liabilities	1,823.7			1,513.7
Long-term debt, less current maturities	6,556.4			2,706.8
Deferred income taxes	554.2			545.1
Asset retirement obligations	621.3			490.7
Accrued postretirement benefit costs	1,053.1			963.9
Other noncurrent liabilities	608.5			453.6
Total liabilities	11,217.2			6,673.8
Stockholders’ equity
Preferred Stock — $0.01 per share par value; 10.0 shares authorized, no shares issued or outstanding as of December 31, 2011 or December 31, 2010	—			—
Series A Junior Participating Preferred Stock - $0.01 per share par value; 1.5 shares authorized, no shares issued or outstanding as of December 31, 2011 or December 31, 2010	—			—
Perpetual Preferred Stock — 0.8 shares authorized, no shares issued or outstanding as of December 31, 2011 or December 31, 2010	—			—
Series Common Stock — $0.01 per share par value; 40.0 shares authorized, no shares issued or outstanding as of December 31, 2011 or December 31, 2010	—			—
Common Stock — $0.01 per share par value; 800.0 shares authorized, 280.3 shares issued and 271.1 shares outstanding as of December 31, 2011 and 279.1 shares issued and 270.2 shares outstanding as of December 31, 2010	2.8			2.8
Additional paid-in capital	2,234.0			2,182.0
Retained earnings	3,744.0			2,878.4
Accumulated other comprehensive loss	(142.4		)	(67.9		)
Treasury shares, at cost: 9.2 shares as of December 31, 2011 and 8.9 shares as of December 31, 2010	(353.3		)	(334.6		)
Peabody Energy Corporation’s stockholders’ equity	5,485.1			4,660.7
Noncontrolling interests	30.7			28.6
Total stockholders’ equity	5,515.8			4,689.3
Total liabilities and stockholders’ equity	$	16,733.0		$	11,363.1

See accompanying notes to consolidated financial statements

F - 4

PEABODY ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2011			2010			2009
	(Dollars in millions)
Cash Flows From Operating Activities
Net income	$	946.3		$	802.2		$	463.0
Loss (income) from discontinued operations, net of income taxes	64.2			24.4			(19.8		)
Income from continuing operations, net of income taxes	1,010.5			826.6			443.2
Adjustments to reconcile income from continuing operations, net of income taxes
to net cash provided by operating activities:
Depreciation, depletion and amortization	482.2			437.1			400.5
Deferred income taxes	180.6			70.7			135.2
Share-based compensation	43.9			41.1			38.8
Net gain on disposal or exchange of assets	(76.9		)	(30.0		)	(23.2		)
Loss from equity affiliates	19.2			1.7			69.1
Changes in current assets and liabilities:
Accounts receivable	(221.0		)	(149.4		)	102.5
Change in receivable from accounts receivable securitization program	—			(104.6		)	(20.4		)
Inventories	(50.4		)	(8.5		)	(46.8		)
Net assets from coal trading activities	172.4			(109.6		)	70.9
Other current assets	(27.4		)	(28.5		)	(1.9		)
Accounts payable and accrued expenses	83.3			222.9			(120.4		)
Asset retirement obligations	30.9			31.2			27.5
Workers’ compensation obligations	10.4			(8.9		)	3.0
Accrued postretirement benefit costs	35.4			23.1			7.2
Pension costs	31.1			23.3			3.3
Contributions to pension plans	(46.7		)	(112.6		)	(38.7		)
Other, net	(19.4		)	(8.9		)	(4.9		)
Net cash provided by continuing operations	1,658.1			1,116.7			1,044.9
Net cash (used in) provided by discontinued operations	(24.9		)	(29.6		)	5.3
Net cash provided by operating activities	1,633.2			1,087.1			1,050.2
Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development	(846.9		)	(547.9		)	(383.4		)
Investment in Prairie State Energy Campus	(36.2		)	(76.0		)	(56.8		)
Proceeds from disposal of assets, net of notes receivable	40.1			19.2			53.9
Investments in equity affiliates and joint ventures	(39.7		)	(18.8		)	(15.0		)
Proceeds from sales of debt and equity securities	104.6			12.4			—
Purchases of debt and equity securities	(147.7		)	(74.6		)	—
Purchases of short-term investments	(100.0		)	—			—
Maturity of short-term investments	100.0			—			—
Acquisition of Macarthur Coal Limited, net of cash acquired	(2,756.7		)	—			—
Contributions to joint ventures	(145.4		)	—			—
Distributions from joint ventures	128.6			—			—
Repayment of loans from related parties	331.7			—			—
Advances to related parties	(371.3		)	—			—
Other, net	(6.6		)	(8.8		)	(6.1		)
Net cash used in continuing operations	(3,745.5		)	(694.5		)	(407.4		)
Net cash (used in) provided by discontinued operations	(62.3		)	(9.1		)	0.9
Net cash used in investing activities	(3,807.8		)	(703.6		)	(406.5		)

See accompanying notes to consolidated financial statements

F - 5

PEABODY ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS - (Continued)

	Year Ended December 31,
	2011			2010			2009
	(Dollars in millions)
Cash Flows From Financing Activities
Proceeds from long-term debt	$	4,101.4		$	1,150.0		$	—
Acquisition of noncontrolling interests	(1,994.8		)	—			—
Payments of long-term debt	(263.9		)	(1,167.3		)	(37.1		)
Dividends paid	(92.1		)	(79.4		)	(66.8		)
Repurchase of employee common stock relinquished for tax withholding	(18.7		)	(13.5		)	(2.3		)
Payment of debt issuance costs	(61.5		)	(32.2		)	—
Excess tax benefits related to share-based compensation	8.1			51.0			—
Other, net	—			14.3			1.6
Net cash provided by (used in) financing activities	1,678.5			(77.1		)	(104.6		)
Net change in cash and cash equivalents	(496.1		)	306.4			539.1
Cash and cash equivalents at beginning of year	1,295.2			988.8			449.7
Cash and cash equivalents at end of year	$	799.1		$	1,295.2		$	988.8

See accompanying notes to consolidated financial statements

F - 6

PEABODY ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

	Peabody Energy Corporation’s Stockholders’ Equity
	Common Stock		Additional Paid-in Capital			Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Loss			Noncontrolling Interests			Total Stockholders’ Equity
	(Dollars in millions)
December 31, 2008	$	2.8	$	2,020.2		$	(318.8	)	$	1,802.4		$	(388.5	)	$	1.4		$	3,119.5
Net income	—		—			—			448.2			—			14.8			463.0
Increase in fair value of cash flow hedges (net of $220.9 tax provision)	—		—			—			—			319.8			—			319.8
Postretirement plans and workers’ compensation obligations (net of $71.8 tax benefit)	—		—			—			—			(114.8		)	—			(114.8		)
Dividends paid	—		—			—			(66.8		)	—			—			(66.8		)
Share-based compensation	—		38.8			—			—			—			—			38.8
Stock options exercised	—		3.6			—			—			—			—			3.6
Employee stock purchases	—		5.1			—			—			—			—			5.1
Repurchase of employee common stock relinquished for tax withholding	—		—			(2.3		)	—			—			—			(2.3		)
Distributions to noncontrolling interests	—		—			—			—			—			(10.0		)	(10.0		)
December 31, 2009	$	2.8	$	2,067.7		$	(321.1	)	$	2,183.8		$	(183.5	)	$	6.2		$	3,755.9
Net income	—		—			—			774.0			—			28.2			802.2
Increase in fair value of cash flow hedges (net of $129.5 tax provision)			—			—			—			127.5			—			127.5
Postretirement plans and workers’ compensation obligations (net of $2.1 tax benefit)	—		—			—			—			(11.9		)	—			(11.9		)
Dividends paid	—		—			—			(79.4		)	—			—			(79.4		)
Share-based compensation	—		41.1			—			—			—			—			41.1
Excess tax benefits related to share-based compensation	—		51.0			—			—			—			—			51.0
Stock options exercised	—		16.4			—			—			—			—			16.4
Employee stock purchases	—		5.8			—			—			—			—			5.8
Repurchase of employee common stock relinquished for tax withholding	—		—			(13.5		)	—			—			—			(13.5		)
Distributions to noncontrolling interests	—		—			—			—			—			(5.8		)	(5.8		)
December 31, 2010	$	2.8	$	2,182.0		$	(334.6	)	$	2,878.4		$	(67.9	)	$	28.6		$	4,689.3
Net income (loss)	—		—			—			957.7			—			(11.4		)	946.3
Net unrealized losses on available-for-sale-securities (net of $3.9 tax benefit)	—		—			—			—			(6.7		)	—			(6.7		)
Increase in fair value of cash flow hedges (net of $6.2 tax benefit)	—		—			—			—			40.9			—			40.9
Postretirement plans and workers compensation obligations (net of $63.4 tax benefit)	—		—			—			—			(108.7		)	—			(108.7		)
Dividends paid	—		—			—			(92.1		)	—			—			(92.1		)
Share-based compensation	—		43.9			—			—			—			—			43.9
Excess tax benefits related to share-based compensation	—		8.1			—			—			—			—			8.1
Stock options exercised	—		4.8			—			—			—			—			4.8
Employee stock purchases	—		6.3			—			—			—			—			6.3
Repurchase of employee common stock relinquished for tax withholding	—		—			(18.7		)	—			—			—			(18.7		)
Macarthur Coal Limited noncontrolling interest at control date	—		—			—			—			—			2,011.9			2,011.9
Acquisitions of noncontrolling interests	—		(11.1		)	—			—			—			(1,983.7		)	(1,994.8		)
Distributions to noncontrolling interests	—		—			—			—			—			(15.9		)	(15.9		)
Contributions from noncontrolling interests	—		—			—			—			—			1.2			1.2
December 31, 2011	$	2.8	$	2,234.0		$	(353.3	)	$	3,744.0		$	(142.4	)	$	30.7		$	5,515.8

See accompanying notes to consolidated financial statements

F - 7

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Summary of Significant Accounting Policies Discussion

Basis of Presentation

The consolidated financial statements include the accounts of Peabody Energy Corporation (the Company) and its affiliates. All intercompany transactions, profits and balances have been eliminated in consolidation.

Description of Business

The Company is engaged in the mining of thermal coal for sale primarily to electric utilities and metallurgical coal for sale to industrial customers. The Company’s mining operations are located in the United States (U.S.) and Australia, and include equity-affiliate mining operations in Australia and Venezuela. The Company also markets, brokers coal sales of other coal producers both as principal and agent, and trades coal, freight and freight-related contracts. The Company’s other energy related commercial activities include participating in the development of a mine-mouth coal-fueled generating plant, the management of its coal reserve and real estate holdings, and the development of Btu Conversion and clean coal technologies.

Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented

In June 2011, the Financial Accounting Standards Board (FASB) issued guidance eliminating the option to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity. Instead, an entity will be required to present the components of net income, the components of other comprehensive income and the total of comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The guidance will become effective for interim and annual periods beginning after December 15, 2011 (January 1, 2012 for the Company), with the exception of disclosing reclassifications of items out of accumulated other comprehensive income, which is effective for interim and annual periods beginning after December 15, 2012 (January 1, 2013 for the Company). The Company has reflected the new presentation in its consolidated statements of comprehensive income with no impact on its results of operations, financial condition or cash flows.

In December 2010, the FASB issued guidance on accounting for business combinations that clarified a public entity’s disclosure requirements for pro forma presentation of revenue and earnings. If comparative statements are presented, the public entity should disclose revenue and earnings of the combined entity as though the business combination occurred as of the beginning of the comparable prior annual reporting period only. The guidance also requires the supplemental pro forma disclosures to include a description of the nature and amount of material nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. The guidance was effective for business combinations for which the acquisition date was on or after the beginning of the first annual reporting period that began on or after December 15, 2010 (January 1, 2011 for the Company). The guidance impacted the Company’s disclosures with no impact on the Company’s results of operations, financial condition or cash flows.

In July 2010, the FASB issued accounting guidance to improve disclosures about the credit quality of an entity's financing receivables and the reserves held against them. End of reporting period disclosures became effective for reporting periods ended on or after December 15, 2010. Disclosures about activity that occurred during a reporting period became effective for interim and annual periods that began on or after December 15, 2010. While the guidance impacted the Company's disclosures related to credit quality of financing receivables and the allowance for credit losses, the adoption of this guidance had no impact on its results of operations, financial condition or cash flows.

F - 8

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In January 2010, the FASB issued accounting guidance that required new fair value disclosures, including disclosures about significant transfers into and out of Level 1 and Level 2 fair value measurements and a description of the reasons for the transfers. In addition, the guidance required new disclosures regarding activity in Level 3 fair value measurements, including a gross basis reconciliation. The Company began complying with the new fair value disclosure requirements beginning January 1, 2010, except for the disclosure of activity within Level 3 fair value measurements, which became effective January 1, 2011. While the adoption of this guidance had an impact on the Company's disclosures, it did not affect the Company's results of operations, financial condition or cash flows. In May 2011, the FASB issued additional fair value measurement disclosure requirements that were intended to provide a consistent definition of fair value and ensure that the fair value measurement and disclosure requirements are similar between U.S. generally accepted accounting principles (GAAP) and International Financial Reporting Standards. That update required the categorization by level for financial instruments not measured at fair value but for which disclosure of fair value is required, disclosure of all transfers between Level 1 and Level 2, and additional disclosures for Level 3 measurements regarding the sensitivity of fair value to changes in unobservable inputs and any interrelationships between those inputs. The guidance will become effective for interim and annual periods beginning after December 15, 2011 (January 1, 2012 for the Company). The guidance issued in May 2011 will impact the Company's disclosures, but it is not expected to impact the Company's results of operations, financial condition or cash flows.

In June 2009, the FASB issued accounting guidance on consolidations which clarifies that the determination of whether a company is required to consolidate an entity is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly impact the entity’s economic performance. Also required is an ongoing reassessment of whether a company is the primary beneficiary of a variable interest entity, and additional disclosures about a company’s involvement in variable interest entities and any associated changes in risk exposure. The guidance became effective January 1, 2010, at which time there was no impact on the Company’s results of operations, financial condition or cash flows. The Company will continue monitoring and assessing its business ventures in accordance with the guidance.

In June 2009, the FASB issued guidance seeking to improve the relevance, representational faithfulness and comparability of the information a reporting entity provides in its financial statements about a transfer of financial assets; the effects of a transfer on its financial position, financial performance and cash flows; and a transferor’s continuing involvement, if any, in transferred financial assets. The guidance, which became effective January 1, 2010, had an impact on the Company’s disclosures for its accounts receivable securitization program, but did not affect the Company’s results of operations, financial condition or cash flows.

Sales

The Company’s revenue from coal sales is realized and earned when risk of loss passes to the customer. Under the typical terms of the Company’s coal supply agreements, title and risk of loss transfer to the customer at the mine or port, where coal is loaded to the transportation source(s) that serves each of the Company’s mines. The Company incurs certain “add-on” taxes and fees on coal sales. Reported coal sales include taxes and fees charged by various federal and state governmental bodies and the freight charges on destination customer contracts.

Other Revenues

Other revenues include net revenues from coal trading activities as discussed in Note 7 and coal revenues that were derived from the Company’s mining operations and sold through the Company’s coal trading business. Also included are revenues from contract termination or restructuring payments, royalties related to coal lease agreements, sales agency commissions, farm income, property and facility rentals and generation development activities. Royalty income generally results from the lease or sublease of mineral rights to third parties, with payments based upon a percentage of the selling price or an amount per ton of coal produced.

Discontinued Operations and Assets Held for Sale

The Company classifies items within discontinued operations in the consolidated financial statements when the operations and cash flows of a particular component (defined as operations and cash flows that can be clearly distinguished, operationally and for financial reporting purposes, from the rest of the entity) of the Company have been (or will be) eliminated from the ongoing operations of the Company as a result of a disposal transaction, and the Company will no longer have any significant continuing involvement in the operations of that component. See Note 3 for additional details related to discontinued operations and assets held for sale.

F - 9

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Cash and Cash Equivalents

Cash and cash equivalents are stated at cost, which approximates fair value. Cash equivalents consist of highly liquid investments with original maturities of three months or less.

Inventories

Materials and supplies and coal inventory are valued at the lower of average cost or market. Raw coal represents coal stockpiles that may be sold in current condition or may be further processed prior to shipment to a customer. Coal inventory costs include labor, supplies, equipment, operating overhead and other related costs.

Property, Plant, Equipment and Mine Development

Property, plant, equipment and mine development are recorded at cost. Interest costs applicable to major asset additions are capitalized during the construction period. Capitalized interest in 2011, 2010 and 2009 was immaterial. Expenditures which extend the useful lives of existing plant and equipment assets are capitalized. Maintenance and repairs are charged to operating costs as incurred. Costs incurred to develop coal mines or to expand the capacity of operating mines are capitalized. Costs incurred to maintain current production capacity at a mine are charged to operating costs as incurred. Costs to acquire computer hardware and the development and/or purchase of software for internal use are capitalized and depreciated over the estimated useful lives.

Coal reserves are recorded at cost, or at fair value in the case of nonmonetary exchanges of reserves or business acquisitions. The net book value of coal reserves totaled $7.7 billion as of December 31, 2011 and $5.0 billion as of December 31, 2010. These coal reserves include mineral rights for leased coal interests and advance royalties that had a net book value of $6.4 billion as of December 31, 2011 and $3.7 billion as of December 31, 2010. The remaining net book value of coal reserves of $1.3 billion at December 31, 2011 and $1.3 billion at December 31, 2010 relates to coal reserves held by fee ownership. Amounts attributable to properties where the Company was not currently engaged in mining operations or leasing to third parties and, therefore, the coal reserves were not currently being depleted was $2.7 billion as of December 31, 2011 and $1.3 billion as of December 31, 2010.

Depletion of coal reserves and amortization of advance royalties is computed using the units-of-production method utilizing only proven and probable reserves (as adjusted for recoverability factors) in the depletion base. Mine development costs are principally amortized over the estimated lives of the mines using the straight-line method. Depreciation of plant and equipment is computed using the straight-line method over the shorter of the asset's estimated useful life or the life of the mine. The estimated useful lives by category of assets are as follows:

	Years
Building and improvements	10 to 20
Plant and equipment	3 to 33
Leasehold improvements	Life of Lease

Depreciation and depletion expense associated with property, plant, equipment and mine development was $473.7 million, $424.8 million and $388.0 million for December 31, 2011, 2010, and 2009, respectively.

F - 10

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Investments in Joint Ventures

The Company accounts for its investments in less than majority owned corporate joint ventures under either the equity or cost method. The Company applies the equity method to investments in joint ventures when it has the ability to exercise significant influence over the operating and financial policies of the joint venture. Investments accounted for under the equity method are initially recorded at cost, and any difference between the cost of the Company’s investment and the underlying equity in the net assets of the joint venture at the investment date is amortized over the lives of the related assets that gave rise to the difference. The Company’s pro rata share of earnings from joint ventures and basis difference amortization is reported in the consolidated statements of income in “Loss from equity affiliates.” Included in the Company’s equity method investments is its joint venture interest in the Middlemount Mine in Australia, which was acquired as a part of the acquisition of Macarthur Coal Limited (see Note 2 for additional details). The Company also has an interest in Carbones del Guasare, which owns and operates the Paso Diablo Mine in Venezuela. In 2009, the Company recognized an impairment loss of $34.7 million million related to its interest in Carbones del Guasare based on the joint venture’s deteriorating operating results, ongoing cash flow issues resulting in no dividend payments since January 2008, the Company’s expectations concerning ongoing operating and cash flow issues for the joint venture and uncertainty impacting recoverability of this investment. The table below summarizes the book value of the Company’s equity method investments, which is reported in “Investments and other assets” in the consolidated balance sheets, and the (loss) income from its equity affiliates:

	Book Value at December 31,				(Loss) Income from Equity Affiliates for the Year Ended December 31,
	2011		2010		2011			2010			2009
	(Dollars in millions)
Interest in Middlemount Coal Pty Ltd.	$	449.7	$	—	$	(7.3	)	$	—		$	—
Interest in Monto Coal Pty Ltd.	73.1		—		—			—			—
Interest in Carbones del Guasare	—		—		—			—			(54.6		)
Interest in Peabody-Winsway Resources B.V.	—		—		(3.4		)	5.4			(8.2		)
Other equity method investments	3.8		2.7		(8.5		)	(7.1		)	(6.3		)
Total equity method investments	$	526.6	$	2.7	$	(19.2	)	$	(1.7	)	$	(69.1	)

Asset Retirement Obligations

The Company’s asset retirement obligation (ARO) liabilities primarily consist of spending estimates for surface land reclamation and support facilities at both surface and underground mines in accordance with applicable reclamation laws in the U.S. and Australia as defined by each mining permit.

The Company estimates its ARO liabilities for final reclamation and mine closure based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at the credit-adjusted, risk-free rate. The Company records an ARO asset associated with the discounted liability for final reclamation and mine closure. The obligation and corresponding asset are recognized in the period in which the liability is incurred. The ARO asset is amortized on the units-of-production method over its expected life and the ARO liability is accreted to the projected spending date. As changes in estimates occur (such as mine plan revisions, changes in estimated costs or changes in timing of the performance of reclamation activities), the revisions to the obligation and asset are recognized at the appropriate historical credit-adjusted, risk-free rate. The Company also recognizes an obligation for contemporaneous reclamation liabilities incurred as a result of surface mining. Contemporaneous reclamation consists primarily of grading, topsoil replacement and re-vegetation of backfilled pit areas.

Environmental Liabilities

Accruals for other environmental matters are recorded in operating expenses when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Accrued liabilities are exclusive of claims against third parties and are not discounted. In general, costs related to environmental remediation are charged to expense. The current portion of these accruals is included in “Accounts payables and accrued expenses” and the long-term portion is included in “Other noncurrent liabilities” in the consolidated balance sheets.

F - 11

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Income Taxes

Income taxes are accounted for using a balance sheet approach. The Company accounts for deferred income taxes by applying statutory tax rates in effect at the reporting date of the balance sheet to differences between the book and tax basis of assets and liabilities. A valuation allowance is established if it is “more likely than not” that the related tax benefits will not be realized. In determining the appropriate valuation allowance, the Company considers projected realization of tax benefits based on expected levels of future taxable income, available tax planning strategies and the overall deferred tax position.

The Company recognizes the tax benefit from uncertain tax positions only if it is “more likely than not” the tax position will be sustained on examination by the taxing authorities. The tax benefits recognized from such a position are measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. To the extent the Company’s assessment of such tax positions changes, the change in estimate will be recorded in the period in which the determination is made. Tax-related interest and penalties are classified as a component of income tax expense.

Postretirement Health Care and Life Insurance Benefits

The Company accounts for postretirement benefits other than pensions by accruing the costs of benefits to be provided over the employees’ period of active service. These costs are determined on an actuarial basis. The Company’s consolidated balance sheets reflect the funded status of postretirement benefits. See Note 14 for information related to postretirement benefits.

Pension Plans

The Company sponsors non-contributory defined benefit pension plans accounted for by accruing the cost to provide the benefits over the employees’ period of active service. These costs are determined on an actuarial basis. The Company’s consolidated balance sheets reflect the funded status of the defined benefit pension plans. See Note 15 for information related to pension plans.

Derivatives

The Company recognizes at fair value all derivatives as assets or liabilities in the consolidated balance sheets. Gains or losses from derivative financial instruments designated as fair value hedges are recognized immediately in earnings, along with the offsetting gain or loss related to the underlying hedged item.

Gains or losses on derivative financial instruments designated as cash flow hedges are recorded as a separate component of stockholders’ equity until the hedged transaction occurs (or until hedge ineffectiveness is determined), at which time gains or losses are reclassified to earnings in conjunction with the recognition of the underlying hedged item. To the extent that the periodic changes in the fair value of the derivatives exceed the changes in the hedged item, the ineffective portion of the periodic non-cash changes are recorded in earnings in the period of the change. If the hedge ceases to qualify for hedge accounting, the Company prospectively recognizes the mark-to-market movements in earnings in the period of the change. The potential for hedge ineffectiveness is present in the design of the Company’s cash flow hedge relationships and is discussed in detail in Notes 6 and 7.

Non-derivative contracts and derivative contracts for which the Company has elected to apply the normal purchases and normal sales exception are accounted for on an accrual basis.

Business Combinations

The Company accounts for business combinations using the purchase method of accounting. The purchase method requires the Company to determine the fair value of all acquired assets, including identifiable intangible assets, and all assumed liabilities. The total cost of acquisitions is allocated to the underlying identifiable net assets, based on their respective estimated fair values. Determining the fair value of assets acquired and liabilities assumed requires management's judgment, and the utilization of independent valuation experts, and often involves the use of significant estimates and assumptions, including assumptions with respect to future cash inflows and outflows, discount rates, and asset lives, among other items.

F - 12

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Use of Estimates in the Preparation of the Consolidated Financial Statements

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Impairment of Long-Lived Assets

The Company records impairment losses on long-lived assets used in operations when events and circumstances indicate that assets might be impaired and the undiscounted cash flows estimated to be generated by those assets under various assumptions are less than their carrying amounts. Impairment losses are measured by comparing the estimated fair value of the impaired asset to its carrying amount. There were no impairment losses recorded during the years ended December 31, 2011, 2010 or 2009.

Fair Value

For assets and liabilities that are recognized or disclosed at fair value in the consolidated financial statements, the Company defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The Company’s asset and liability derivative positions are offset on a counterparty-by-counterparty basis if the contractual agreement provides for the net settlement of contracts with the counterparty in the event of default or termination of any one contract.

Foreign Currency

Substantially all of the Company’s foreign subsidiaries utilize the U.S. dollar as their functional currency. As such, monetary assets and liabilities are remeasured at year-end exchange rates while non-monetary items are remeasured at historical rates. Income and expense accounts are remeasured at the average rates in effect during the year, except for those expenses related to balance sheet amounts that are remeasured at historical exchange rates. Gains and losses from foreign currency remeasurement related to tax balances are included as a component of "Income tax provision" while all other remeasurement gains and losses are included in "Operating costs and expenses." The total foreign currency remeasurement losses for the years ended December 31, 2011, 2010 and 2009 were $0.9 million, $38.5 million and $55.4 million, respectively.

Share-Based Compensation

The Company accounts for share-based compensation at the grant date fair value of awards and recognizes the related expense over the vesting period of the award. See Note 17 for information related to share-based compensation.

Exploration and Drilling Costs

Exploration expenditures are charged to operating costs as incurred, including costs related to drilling and study costs incurred to convert or upgrade mineral resources to reserves.

Advance Stripping Costs

Pre-production:  At existing surface operations, additional pits may be added to increase production capacity in order to meet customer requirements. These expansions may require significant capital to purchase additional equipment, expand the workforce, build or improve existing haul roads and create the initial pre-production box cut to remove overburden (i.e., advance stripping costs) for new pits at existing operations. If these pits operate in a separate and distinct area of the mine, the costs associated with initially uncovering coal (i.e., advance stripping costs incurred for the initial box cuts) for production are capitalized and amortized over the life of the developed pit consistent with coal industry practices.

Post-production:  Advance stripping costs related to post-production are expensed as incurred. Where new pits are routinely developed as part of a contiguous mining sequence, the Company expenses such costs as incurred. The development of a contiguous pit typically reflects the planned progression of an existing pit, thus maintaining production levels from the same mining area utilizing the same employee group and equipment.

F - 13

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(2) Acquisition of Macarthur Coal Limited

On October 23, 2011, PEAMCoal Pty Ltd (PEAMCoal), an Australian company that was then indirectly owned 60% by the Company and 40% by ArcelorMittal, acquired a majority interest in Macarthur Coal Limited (Macarthur) through an all cash off-market takeover offer. On October 26, 2011 (the acquisition and control date), the Company appointed its nominees to the Macarthur Board of Directors and executive management team. The acquisition was completed on December 20, 2011 as PEAMCoal acquired all of Macarthur's remaining outstanding shares of common stock for $4.8 billion, net of $261.2 million of acquired cash, of which the Company's share was $2.8 billion. PEAMCoal accounted for share acceptances under the takeover process as a single transaction occurring on October 26, 2011. On December 21, 2011, the Company acquired ArcelorMittal Mining Australasia B.V., an indirect subsidiary of ArcelorMittal that indirectly owned 40% of PEAMCoal, for $2.0 billion resulting in the Company's 100% ownership of Macarthur.

The Macarthur acquisition includes a 73.3% undivided interest in the assets and liabilities of Coppabella and Moorvale operating mines and the Codrilla Mine Project. It also includes a 50% interest in the Middlemount Mine and a prospective portfolio of coal mining assets at various stages of development and exploration. The acquisition expands the Company's Australian mining platform to serve the seaborne coal markets.

The Company funded the acquisition and purchase of noncontrolling interests using available cash on hand, cash proceeds from a new term loan facility of $1.0 billion and proceeds from the issuance of $3.1 billion aggregate principal amount of senior notes. The Company recorded $55.6 million in deferred financing costs associated with this debt, which are being amortized over the remaining term of the related debt. See Note 11 for information related to the Company's long-term debt.

The preliminary purchase accounting allocations have been recorded in the accompanying consolidated financial statements as of, and for the period subsequent to the acquisition and control date. The final valuation of the net assets acquired is expected to be finalized once third-party valuation appraisals are completed. The following table summarizes the preliminary estimated fair values of assets acquired and liabilities assumed that were recognized at the acquisition and control date (Dollars in millions):

Accounts receivable, net	$	106.6
Inventories	67.1
Other current assets	137.5
Property, plant, equipment and mine development	3,457.0
Investments and other assets	1,275.1
Current maturities of long-term debt	(11.0		)
Accounts payable and accrued expenses	(133.8		)
Long-term debt, less current maturities	(59.2		)
Asset retirement obligations	(39.3		)
Other noncurrent liabilities	(31.4		)
Noncontrolling interests	(2,011.9		)
Total purchase price, net of cash acquired of $261.2	$	2,756.7

Cash, accounts receivables, accounts payable and other current assets and liabilities were stated at their historical carrying values, which approximated fair value given their short-term nature. The Company is evaluating mine lives and reviewing coal reserve studies on the acquired properties, the outcome of which will determine the fair value allocated to coal reserve assets. In connection with acquisition of Macarthur, the Company acquired contract based intangibles consisting of port, rail and water take-or-pay obligations and recorded a liability of $30.5 million, net of tax. The liability is being amortized based on unutilized capacity over the terms of the applicable agreements, which extend to 2018.

Included in "Accounts receivable, net," "Other current assets" and "Investments and other assets" above are $34.5 million, $66.6 million and $234.9 million, respectively, of certain financing receivables that were acquired as part of the acquisition of Macarthur. For further discussion of these financing receivables, see Note 8.

F - 14

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Included in "Investments and other assets" is $368.9 million representing the balance of a loan facility agreement with MCG Coal Holdings Pty Ltd (MCGH). Macarthur had previously agreed to convert its receivable for a 90% equity interest in MCGH. The transaction was expected to be completed in May 2011. However, non-performance by a third party to the transaction resulted in Macarthur commencing litigation. The original loan balance was classified as a receivable pending the outcome of the legal proceedings. Subsequent to December 31, 2011, the court ruled that the outstanding loan balance is to be converted to a 90% equity interest. For further discussion of contingencies assumed as part of the acquisition of Macarthur, see Note 23.

Macarthur contributed revenues of $152.9 million and a loss net of income taxes of $47.9 million from the acquisition and control date to December 31, 2011, excluding the acquisition costs noted below and the interest expense associated with the debt secured to finance the acquisition. The results of Macarthur for the period from the acquisition and control date are included in the consolidated statements of income and are reported in the Australian Mining segment in Note 25, except for the activity associated with certain equity affiliate investments, which is reflected in the Corporate and Other segment.

In 2011, the Company recorded acquisition costs of $85.2 million, which primarily consisted of professional fees, losses on derivatives associated with the acquisition of Macarthur shares and Australian stamp duty associated with the acquisition. These acquisition costs are recorded in the “Acquisition Costs Related to Macarthur Coal Limited” line item in the consolidated statements of income. The Company also recognized $16.2 million of interest expense associated with bridge financing for the Macarthur acquisition.

The following unaudited pro forma financial information presents the combined results of operations of the Company and Macarthur, on a pro forma basis, as though the companies had been combined as of January 1, 2010. The pro forma financial information does not necessarily reflect the results of operations that would have occurred had the Company and Macarthur constituted a single entity during those periods or that may be attained in the future.

	Year Ended December 31,
	2011		2010
	(Dollars in millions, except earnings per share)
Revenue	$	8,696.5	$	7,579.5
Income from continuing operations, net of income taxes	1,046.7		781.5
Basic earnings per share	3.67		2.80
Diluted earnings per share	3.65		2.77

The pro forma income from continuing operations, net of income taxes includes adjustments to operating costs to reflect the additional expense for the estimated impact of the fair value adjustment for coal inventory, the estimated impact on depreciation, depletion and amortization for the fair value adjustment for property, plant and equipment (including mineral rights) and additional expense for the estimated impact of reflecting the equity affiliate interest at its estimated fair value.

(3) Discontinued Operations

Discontinued operations include certain non-strategic Midwestern and Australian mining assets held for sale where the Company has committed to the divestiture of such assets and other operations recently divested.

Revenues resulting from discontinued operations (including assets held for sale) were $121.6 million, $205.8 million and $466.9 million for the years ended December 31, 2011, 2010 and 2009, respectively. (Loss) income before income taxes from discontinued operations reflects a loss of $86.5 million and $33.5 million for the years ended December 31, 2011 and December 31, 2010, respectively, and income of $36.8 million for the year ended December 31, 2009. The income tax adjustment resulting from discontinued operations reflects a benefit of $22.3 million and $9.1 million for the years ended December 31, 2011 and December 31, 2010, respectively, and a provision of $17.0 million for the year ended December 31, 2009.

Total assets related to discontinued operations were $143.7 million and $77.6 million as of December 31, 2011 and 2010, respectively. Total liabilities associated with discontinued operations were $86.3 million and $43.3 million as of December 31, 2011 and 2010, respectively.

F - 15

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(4) Inventories

Inventories consisted of the following:

	December 31,
	2011		2010
	(Dollars in millions)
Materials and supplies	$	124.9	$	94.5
Raw coal	95.0		55.4
Saleable coal	226.4		177.3
Total	$	446.3	$	327.2

(5)  Investments

The Company’s short-term investments are defined as those investments with original maturities of greater than three months and up to one year, and long-term investments are defined as those investments with original maturities greater than one year.

The Company classifies its investments as either held-to-maturity or available-for-sale at the time of purchase and reevaluates such designation periodically. Investments are classified as held-to-maturity when the Company has the intent and ability to hold the securities to maturity.

Investments in securities not classified as held-to-maturity are classified as available-for-sale. Available-for-sale securities are carried at fair value, with unrealized gains and losses, net of income taxes, reported in “Accumulated other comprehensive loss” in the consolidated balance sheets. Realized gains and losses, determined on a specific identification method, are included in “Interest income” in the consolidated statements of income.

The Company did not have any held-to-maturity securities as of December 31, 2011 or December 31, 2010.

Investments in available-for-sale securities at December 31, 2011 were as follows:

Available-for-sale securities	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	(Dollars in millions)
Current:
Federal government securities	$	3.3	$	—	$	—		$	3.3
U.S. corporate bonds	3.9		—		—			3.9
Noncurrent:
Marketable equity securities	66.5		—		(9.5		)	57.0
Federal government securities	11.3		0.2		—			11.5
U.S. corporate bonds	7.7		0.1		—			7.8
Total	$	92.7	$	0.3	$	(9.5	)	$	83.5

F - 16

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Investments in available-for-sale securities at December 31, 2010 were as follows:

Available-for-sale securities	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
			(Dollars in millions)
Current:
Federal government securities	$	0.5	$	—	$	—	$	0.5
U.S. corporate bonds	1.9		—		—		1.9
Noncurrent:
Federal government securities	9.2		—		—		9.2
U.S. corporate bonds	6.3		—		—		6.3
Total	$	17.9	$	—	$	—	$	17.9

Contractual maturities for available-for-sale investments in debt securities at December 31, 2011 were as shown below. Expected maturities will differ from contractual maturities because borrowers may have the right to call or prepay obligations with or without call or prepayment penalties.

Contractual maturities for available-for-sale securities	Cost		Fair Value
	(Dollars in millions)
Due in one year or less	$	7.2	$	7.2
Due in one to five years	19.0		19.3
Total	$	26.2	$	26.5

The Company’s investments in marketable equity securities consist of an investment in Winsway Coking Coal Holdings Limited.

Proceeds from sales of securities amounted to $52.8 million and realized gains on the sales amounted to $1.6 million for the year ended December 31, 2011.

In addition to the securities described above, the Company held investments in debt and equity securities related to the Company's pro-rata share of funding in the Newcastle Coal Infrastructure Group (NCIG).  During the year ended December 31, 2011, the Company sold all of its previously held interests in these debt and equity securities. New debt securities were purchased for the funding of the next phase of NCIG's port expansion during the year ended December 31, 2011. These debt securities are recorded at cost, which approximates fair value, and are denominated in U.S. dollars. The fair value of these securities was $29.4 million at December 31, 2011.

At each reporting date, the Company performs separate evaluations of debt and equity securities to determine if any unrealized losses are other-than-temporary. None of the securities that were in an unrealized loss position at December 31, 2011 has been so for greater than 12 months. The Company did not recognize any other-than-temporary losses on any of its investments during the year ended December 31, 2011.

(6) Derivatives and Fair Value Measurements

Risk Management — Non Coal Trading Activities

The Company is exposed to various types of risk in the normal course of business, including price risk on commodities utilized in the Company's operations, interest rate risk on long-term debt, and foreign currency exchange rate risk for non-U.S. dollar expenditures. In most cases, commodity price risk (excluding coal trading activities) related to the sale of coal is mitigated through the use of long-term, fixed-price contracts rather than through the use of financial instruments. For the price risk exposure on other commodities, as well as for the interest rate risk and foreign currency exchange rate risk, the Company utilizes financial derivative instruments to manage the risks related to these fluctuations. All of these risks are actively monitored in an effort to ensure compliance with the risk management policies of the Company.

F - 17

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Interest Rate Swaps. The Company is exposed to interest rate risk on its fixed rate and variable rate long-term debt. From time to time, the Company manages the interest rate risk associated with the fair value of its fixed rate borrowings using fixed-to-floating interest rate swaps to effectively convert a portion of the underlying cash flows on the debt into variable rate cash flows. The Company designates these swaps as fair value hedges, with the objective of hedging against changes in the fair value of the fixed rate debt that results from market interest rate changes. From time to time, the interest rate risk associated with the Company’s variable rate borrowings is managed using floating-to-fixed interest rate swaps. The Company designates these swaps as cash flow hedges, with the objective of reducing the variability of cash flows associated with market interest rate changes. As of December 31, 2011, the Company had no interest rate swaps in place.

Foreign Currency Hedges. The Company is exposed to foreign currency exchange rate risk, primarily on Australian dollar expenditures made in its Australian Mining segment. This risk is managed by entering into forward contracts and options that the Company designates as cash flow hedges, with the objective of reducing the variability of cash flows associated with forecasted foreign currency expenditures.

Diesel Fuel and Explosives Hedges. The Company is exposed to commodity price risk associated with diesel fuel and explosives in the U.S. and Australia. This risk is managed through the use of cost pass-through contracts and derivatives, primarily swaps. The Company generally designates the swap contracts as cash flow hedges, with the objective of reducing the variability of cash flows associated with forecasted diesel fuel and explosives purchases. In Australia, the explosives costs and a portion of the diesel fuel costs are not hedged as they are usually included in the fees paid to the Company’s contract miners.

Notional Amounts and Fair Value.  The following summarizes the Company’s foreign currency and commodity positions at December 31, 2011:

	Notional Amount by Year of Maturity
	Total		2012		2013		2014		2015		2016		2017 and thereafter
Foreign Currency
A$:US$ hedge contracts (A$ millions)	$	3,910.6	$	1,750.5	$	1,309.6	$	850.5	$	—	$	—	$	—
GBP:US$ hedge contracts (GBP millions)	6.5		6.5		—		—		—		—		—
Commodity Contracts
Diesel fuel hedge contracts (million gallons)	189.6		86.0		68.0		35.6		—		—		—
U.S. explosives hedge contracts (million MMBtu)	7.7		3.9		2.6		1.2		—		—		—

	Account Classification by
	Cash Flow Hedge		Fair Value Hedge		Economic Hedge		Fair Value Asset (Liability)
							(Dollars in millions)
Foreign Currency
A$:US$ hedge contracts (A$ millions)	$	3,910.6	$	—	$	—	$	491.3
GBP:US$ hedge contracts (GBP millions)	6.5		—		—		(0.7		)
Commodity Contracts
Diesel fuel hedge contracts (million gallons)	189.6		—		—		$	43.7
U.S. explosives hedge contracts (million MMBtu)	7.7		—		—		$	(10.7	)

Hedge Ineffectiveness. The Company assesses, both at inception and at least quarterly thereafter, whether the derivatives used in hedging activities are highly effective at offsetting the changes in the anticipated cash flows of the hedged item. The effective portion of the change in the fair value is recorded in “Accumulated other comprehensive loss” until the hedged transaction impacts reported earnings, at which time any gain or loss is also reclassified to earnings. To the extent that the periodic changes in the fair value of the derivatives exceed the changes in the hedged item, the ineffective portion of the periodic non-cash changes are recorded in earnings in the period of the change. If the hedge ceases to qualify for hedge accounting, the Company prospectively recognizes the mark-to-market movements in earnings in the period of the change.

F - 18

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

A measure of ineffectiveness is inherent in hedging future diesel fuel purchases with derivative positions based on crude oil and refined petroleum products as a result of location and product differences.

The Company’s derivative positions for the hedging of future explosives purchases are based on natural gas, which is the primary price component of explosives. However, a small measure of ineffectiveness exists as the contractual purchase price includes manufacturing fees that are subject to periodic adjustments. In addition, other fees, such as transportation surcharges, can result in ineffectiveness, but have historically changed infrequently and comprise a small portion of the total explosives cost.

The Company’s derivative positions for the hedging of forecasted foreign currency expenditures contain a small measure of ineffectiveness due to timing differences between the hedge settlement and the purchase transaction, which could differ by less than a day and up to a maximum of 30 days.

The tables below show the classification and amounts of pre-tax gains and losses related to the Company’s non-trading hedges during the years ended December 31, 2011, 2010 and 2009:

		Year Ended December 31, 2011
	Income Statement Classification Gains (Losses) - Realized	Gain (loss) recognized in income on non- designated derivatives(1)			Gain (loss) recognized in other comprehensive income on derivative (effective portion)			Gain (loss) reclassified from other comprehensive income into income (effective portion)		Gain (loss) reclassified from other comprehensive income into income (ineffective portion)
Financial Instrument
		(Dollars in millions)
Commodity swaps and options	Operating costs and expenses	$	—		$	30.7		$	42.7	$	4.8
Foreign currency cash flow hedge contracts:
- Operating costs	Operating costs and expenses	—			193.4			342.2		—
- Capital expenditures	Depreciation, depletion and amortization	—			(0.5		)	—		—
Foreign currency economic hedge contracts	Acquisition costs related to Macarthur Coal Limited	$	(32.8	)	$	—		$	—	$	—
Total		$	(32.8	)	$	223.6		$	384.9	$	4.8

⁽¹⁾  Relates to foreign currency contracts associated with the acquisition of Macarthur shares under the takeover process.

		Year Ended December 31, 2010
	Income Statement Classification Gains (Losses) - Realized	Gain (loss) recognized in income on non- designated derivatives(2)			Gain (loss) recognized in other comprehensive income on derivative (effective portion)		Gain (loss) reclassified from other comprehensive income into income (effective portion)			Gain (loss) reclassified from other comprehensive income into income (ineffective portion)
Financial Instrument
		(Dollars in millions)
Interest rate swaps cash flow hedge contracts	Interest expense	$	(8.5	)	$	0.8	$	(0.5	)	$	—
Commodity swaps and options	Operating costs and expenses	—			29.9		(36.2		)	(1.1		)
Foreign currency cash flow hedge contracts	Operating costs and expenses	—			622.2		188.2			—
Total		$	(8.5	)	$	652.9	$	151.5		$	(1.1	)

⁽²⁾  Amounts relate to swaps that were de-designated and terminated in conjunction with the refinancing of the Company's previous credit facility.

F - 19

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

		Year Ended December 31, 2009
	Income Statement Classification Gains (Losses) - Realized	Gain (loss) recognized in income on non- designated derivatives(3)			Gain (loss) recognized in other comprehensive income on derivative (effective portion)		Gain (loss) reclassified from other comprehensive income into income (effective portion)			Gain (loss) reclassified from other comprehensive income into income (ineffective portion)
Financial Instrument
		(Dollars in millions)
Interest rate swaps cash flow hedge contracts	Interest expense	$	—		$	0.2	$	(5.5	)	$	—
Commodity swaps and options:
- Cash flow hedges	Operating costs and expenses	—			65.5		(98.3		)	0.7
- Economic hedges	Operating costs and expenses	(2.7		)	—		—			—
Foreign currency cash flow hedge contracts	Operating costs and expenses	—			458.0		(30.8		)	—
Total		$	(2.7	)	$	523.7	$	(134.6	)	$	0.7

⁽³⁾  Amounts relate to diesel fuel and explosives hedge derivatives that were de-designated in 2009.

Based on the net fair value of the Company’s non-coal trading positions held in “Accumulated other comprehensive loss” at December 31, 2011, unrealized gains to be reclassified from comprehensive income to earnings over the next 12 months associated with the Company’s foreign currency and diesel fuel hedge programs are expected to be approximately $266 million and $43 million, respectively. The unrealized losses to be realized under the explosives hedge program are expected to be approximately $6 million. As these unrealized gains are associated with derivative instruments that represent hedges of forecasted transactions, the amounts reclassified to earnings will partially offset the realized transactions, while the unrealized losses will add incremental expense to the consolidated statements of income.

The classification and amount of derivatives presented on a gross basis as of December 31, 2011 and 2010 are as follows:

	Fair Value as of December 31, 2011
	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
Financial Instrument
	(Dollars in millions)
Commodity swaps and options	$	43.4	$	11.7	$	7.1	$	15.0
Foreign currency cash flow hedge contracts	270.4		229.0		4.3		4.5
Total	$	313.8	$	240.7	$	11.4	$	19.5

	Fair Value as of December 31, 2010
	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
Financial Instrument
	(Dollars in millions)
Commodity swaps and options	25.8		27.0		12.0		0.6
Foreign currency cash flow hedge contracts	273.5		366.6		—		—
Total	$	299.3	$	393.6	$	12.0	$	0.6

After netting by counterparty where permitted, the fair values of the respective derivatives are reflected in “Other current assets,” “Investments and other assets,” “Accounts payable and accrued expenses” and “Other noncurrent liabilities” in the consolidated balance sheets.

See Note 7 for information related to the Company’s coal trading activities.

F - 20

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Fair Value Measurements

The Company uses a three-level fair value hierarchy that categorizes assets and liabilities measured at fair value based on the observability of the inputs utilized in the valuation. These levels include: Level 1, inputs are quoted prices in active markets for the identical assets or liabilities; Level 2, inputs other than quoted prices included in Level 1 that are directly or indirectly observable through market-corroborated inputs; and Level 3, inputs are unobservable, or observable but cannot be market-corroborated, requiring the Company to make assumptions about pricing by market participants.

Financial Instruments Measured on a Recurring Basis. The following tables set forth the hierarchy of the Company’s net financial asset (liability) positions for which fair value is measured on a recurring basis:

	December 31, 2011
	Level 1		Level 2		Level 3		Total
			(Dollars in millions)
Investment in debt and equity securities	$	83.5	$	—	$	—	$	83.5
Commodity swaps and options	—		33.0		—		33.0
Foreign currency cash flow hedge contracts	—		490.6		—		490.6
Total net financial assets	$	83.5	$	523.6	$	—	$	607.1

	December 31, 2010
	Level 1		Level 2		Level 3		Total
			(Dollars in millions)
Investment in debt securities	$	17.9	$	—	$	—	$	17.9
Commodity swaps and options	—		40.2		—		40.2
Foreign currency cash flow hedge contracts	—		640.1		—		640.1
Total net financial assets	$	17.9	$	680.3	$	—	$	698.2

For Level 1 and 2 financial assets and liabilities, the Company utilizes both direct and indirect observable price quotes, including interest rate yield curves, exchange indices, broker quotes, published indices and other market quotes. Below is a summary of the Company’s valuation techniques for Level 1 and 2 financial assets and liabilities:

• Investment in debt and equity securities: valued based on quoted prices in active markets (Level 1).

• Commodity swaps and options — diesel fuel and explosives: generally valued based on a valuation that is corroborated by the use of market-based pricing (Level 2).

• Foreign currency hedge contracts: valued utilizing inputs obtained in quoted public markets (Level 2).

The Company did not have any transfers between levels during 2011, 2010 or 2009 for its non-coal trading positions. The Company’s policy is to value all transfers between levels using the beginning of period valuation.

Other Financial Instruments. The following methods and assumptions were used by the Company in estimating fair values for other financial instruments as of December 31, 2011 and 2010:

• Cash and cash equivalents, accounts receivable, including those within the Company’s accounts receivable securitization program, and accounts payable and accrued expenses have carrying values which approximate fair value due to the short maturity or the liquid nature of these instruments.

• Investments in debt and equity securities related to the Company’s pro-rata share of funding in NCIG are included in “Investments and other assets” in the consolidated balance sheets. The debt securities are recorded at cost, which approximates fair value.

• Long-term debt fair value estimates are based on observed prices for securities with an active trading market when available, and otherwise on estimated borrowing rates to discount the cash flows to their present value. The carrying amounts of the 7.875% Senior Notes due 2026 and the Convertible Junior Subordinated Debentures due 2066 (the Debentures) are net of the respective unamortized note discounts.

F - 21

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The carrying amounts and estimated fair values of the Company’s debt are summarized as follows:

	December 31, 2011				December 31, 2010
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
			(Dollars in millions)
Long-term debt	$	6,657.5	$	6,922.7	$	2,750.0	$	2,960.0

Nonperformance and Credit Risk

The fair value of the Company’s non-coal trading derivative assets and liabilities reflects adjustments for nonperformance and credit risk. The Company manages its counterparty risk through established credit standards, diversification of counterparties, utilizing investment grade commercial banks and continuous monitoring of counterparty creditworthiness. To reduce its credit exposure for these hedging activities, the Company seeks to enter into netting agreements with counterparties that permit the Company to offset asset and liability positions with such counterparties.

(7) Coal Trading

Risk Management 

The Company engages in direct and brokered trading of coal, ocean freight and fuel-related commodities in over-the-counter markets (coal trading), some of which is subsequently exchange-cleared and some of which is bilaterally-settled. Except those for which the Company has elected to apply a normal purchases and normal sales exception, all derivative coal trading contracts are accounted for on a fair value basis.

The Company’s policy is to include instruments associated with coal trading transactions as a part of its trading book. Trading revenues are recorded in “Other revenues” in the consolidated statements of income and include realized and unrealized gains and losses on derivative instruments, including coal deliveries related to contracts accounted for under the normal purchases and normal sales exception. Therefore, the Company has elected the trading exemption to reflect the disclosures for its coal trading activities.

	Year Ended December 31,
Trading Revenue by Type of Instrument	2011			2010		2009
	(Dollars in millions)
Commodity swaps and options	$	(41.4	)	$	23.2	$	176.5
Physical commodity purchase / sale contracts	187.0			135.5		85.0
Total trading revenue	$	145.6		$	158.7	$	261.5

Hedge Ineffectiveness. The Company assesses, both at inception and at least quarterly thereafter, whether the derivatives used in hedging activities are highly effective at offsetting the changes in the anticipated cash flows of the hedged item. The effective portion of the change in the fair value is recorded in “Accumulated other comprehensive loss” until the hedged transaction impacts reported earnings, at which time gains and losses are also reclassified to earnings. To the extent that the periodic changes in the fair value of the derivatives exceed the changes in the hedged item, the ineffective portion of the periodic non-cash changes are recorded in earnings in the period of the change. If the hedge ceases to qualify for hedge accounting, the Company prospectively recognizes the mark-to-market movements in earnings in the period of the change.

In some instances, the Company has designated an existing coal trading derivative as a hedge and, thus, the derivative has a non-zero fair value at hedge inception. The “off-market” nature of these derivatives, which is best described as an embedded financing element within the derivative, is a source of ineffectiveness. In other instances, the Company uses a coal trading derivative that settles at a different time, has different quality specifications, or has a different location basis than the occurrence of the cash flow being hedged. These collectively yield ineffectiveness to the extent that the derivative hedge contract does not exactly offset changes in the fair value or expected cash flows of the hedged item.

F - 22

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Forecasted Transactions No Longer Probable. During 2011, the Company reclassified losses of $10.0 million out of “Accumulated other comprehensive loss” to earnings as the underlying forecasted transactions were deemed no longer probable of occurring.

Fair Value Measurements

The fair value of assets and liabilities from coal trading activities is set forth below:

	December 31,
	2011						2010
	Gross Basis			Net Basis			Gross Basis			Net Basis
	(Dollars in millions)
Assets from coal trading activities	$	170.4		$	44.6		$	1,706.2		$	192.5
Liabilities from coal trading activities	(84.0		)	(10.3		)	(1,843.5		)	(181.7		)
Subtotal	86.4			34.3			(137.3		)	10.8
Net margin posted (held)(1)	(52.1		)	—			148.1			—
Net value of coal trading positions	$	34.3		$	34.3		$	10.8		$	10.8

⁽¹⁾  Represents margin held from exchanges of $52.1 million at December 31, 2011; and margin posted with counterparties and exchanges of $148.2 million, net of margin held of $0.1 million at December 31, 2010. In addition, at December 31, 2010, the Company held letters of credit of $5.0 million from counterparties in lieu of margin posted. Of the margin held at December 31, 2011, approximately $23.4 million related to cash flow hedges.

The Company’s trading assets and liabilities are generally made up of forward contracts, financial swaps and margin. The fair value of coal trading positions designated as cash flow hedges of forecasted sales was a liability of $22.4 million and $174.2 million as of December 31, 2011 and December 31, 2010, respectively. The decreases in the gross basis amounts were primarily due to positions being realized during the year, as well as the premature settlement of trades that were brokered by MF Global UK Limited (MF Global UK) due to it being placed into the United Kingdom's administration process (a process similar to bankruptcy proceedings in the U.S.). The Company subsequently entered into similar positions with a new broker. The settlements did not have a material impact on the Company's consolidated statements of income. For additional information regarding MF Global UK, see the "MF Global UK Limited" disclosure at the end of this note.

The following tables set forth the hierarchy of the Company’s net financial asset (liability) trading positions for which fair value is measured on a recurring basis:

	December 31, 2011
	Level 1		Level 2			Level 3		Total
	(Dollars in millions)
Commodity swaps and options	$	21.2	$	(1.9	)	$	—	$	19.3
Physical commodity purchase/sale contracts	—		6.3			8.7		15.0
Total net financial assets	$	21.2	$	4.4		$	8.7	$	34.3

	December 31, 2010
	Level 1		Level 2			Level 3		Total
			(Dollars in millions)
Commodity swaps and options	$	10.7	$	(76.2	)	$	—	$	(65.5	)
Physical commodity purchase/sale contracts	—		57.7			18.6		76.3
Total net financial assets (liabilities)	$	10.7	$	(18.5	)	$	18.6	$	10.8

F - 23

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

For Level 1 and 2 financial assets and liabilities, the Company utilizes both direct and indirect observable price quotes, including U.S. interest rate curves, LIBOR yield curves, Chicago Mercantile Exchange (CME), New York Mercantile Exchange (NYMEX), Intercontinental Exchange indices (ICE), NOS Clearing ASA, LCH.Clearnet (formerly known as the London Clearing House), Singapore Exchange (SGX), broker quotes, published indices and other market quotes. Below is a summary of the Company’s valuation techniques for Level 1 and 2 financial assets and liabilities:

• Commodity swaps and options — generally valued based on unadjusted quoted prices in active markets (Level 1) or a valuation that is corroborated by the use of market-based pricing (Level 2).

• Physical commodity purchase/sale contracts — purchases and sales at locations with significant market activity corroborated by market-based information (Level 2).

Commodity swaps and options and physical commodity purchase/sale contracts transacted in less liquid markets or contracts, such as long-term arrangements with limited price availability, are classified in Level 3. Indicators of less liquid markets are those with periods of low trade activity or when broker quotes reflect wide pricing spreads. Generally, the Company’s Level 3 instruments or contracts are valued using internally generated models that include bid/ask price quotations, other market assessments obtained from multiple, independent third-party brokers or other transactional data. While the Company does not anticipate any decrease in the number of third-party brokers or market liquidity, such events could erode the quality of market information and therefore the valuing of its market positions should the number of third-party brokers decrease or if market liquidity is reduced. The Company’s valuation techniques also include basis adjustments for heat rate, sulfur and ash content, port and freight costs and credit and nonperformance risk. The Company validates its valuation inputs with third-party information and settlement prices from other sources where available. The Company has consistently applied these valuation techniques in all periods presented, and believes it has obtained the most accurate information available for the types of derivative contracts held.

The following table summarizes the changes in the Company’s recurring Level 3 net financial assets:

	Year Ended December 31,
	2011				2010			2009
	(Dollars in millions)
Beginning of year	$	18.6			$	17.0		$	37.8
Total gains (losses) realized/unrealized:
Included in earnings	8.9				2.1			(2.9		)
Included in other comprehensive income	—				(0.5		)	(1.6		)
Settlements	(2.1		)		(0.1		)	(20.5		)
Transfers in	1.0			—	—			—
Transfers out	(17.7		)		0.1			4.2
End of year	$	8.7			$	18.6		$	17.0

The following table summarizes the changes in unrealized gains relating to Level 3 net financial assets held both as of the beginning and the end of the year:

	Year Ended December 31,
	2011		2010		2009
	(Dollars in millions)
Changes in unrealized gains (1)	$	8.7	$	6.7	$	15.6

⁽¹⁾  Within the consolidated statements of income and consolidated statements of comprehensive income for the periods presented, unrealized gains and losses from Level 3 items are combined with unrealized gains and losses on positions classified in Level 1 or 2, as well as other positions that have been realized during the applicable periods.

The Company did not have any significant transfers between Level 1 and Level 2 during 2011, 2010 or 2009. Certain of the Company’s physical commodity purchase/sale contracts were transferred from Level 3 to Level 2 as the settlement dates entered a more liquid market. The Company’s policy is to value all transfers between levels using the beginning of period valuation.

F - 24

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Based on the net fair value of the Company’s coal trading positions held in “Accumulated other comprehensive loss” at December 31, 2011, unrealized losses to be reclassified from comprehensive income to earnings over the next 12 months are expected to be approximately $2 million. As these unrealized losses are associated with derivative instruments that represent hedges of forecasted transactions, the amounts reclassified to earnings may partially offset the realized transactions in the consolidated statements of income.

As of December 31, 2011, the timing of the estimated future realization of the value of the Company’s trading portfolio was as follows:

Year of	Percentage of
Expiration	Portfolio Total
2012	65	%
2013	29	%
2014	4	%
2015	2	%
	100	%

Nonperformance and Credit Risk. The fair value of the Company’s coal derivative assets and liabilities reflects adjustments for nonperformance and credit risk. The Company’s exposure is substantially with electric utilities, steel producers, energy marketers and energy producers. The Company’s policy is to independently evaluate each customer’s creditworthiness prior to entering into transactions and to regularly monitor the credit extended. If the Company engages in a transaction with a counterparty that does not meet its credit standards, the Company seeks to protect its position by requiring the counterparty to provide an appropriate credit enhancement. Also, when appropriate (as determined by its credit management function), the Company has taken steps to reduce its exposure to customers or counterparties whose credit has deteriorated and who may pose a higher risk of failure to perform under their contractual obligations. These steps include obtaining letters of credit or cash collateral (margin), requiring prepayments for shipments or the creation of customer trust accounts held for the Company’s benefit to serve as collateral in the event of a failure to pay or perform. To reduce its credit exposure related to trading and brokerage activities, the Company seeks to enter into netting agreements with counterparties that permit the Company to offset asset and liability positions with such counterparties and, to the extent required, will post or receive margin amounts associated with exchange-cleared positions.

At December 31, 2011, 78% of the Company’s credit exposure related to coal trading activities with investment grade counterparties while 21% with non-investment grade counterparties and 1% was with counterparties that are not rated.

Performance Assurances and Collateral.  Certain of the Company’s derivative trading instruments require the parties to provide additional performance assurances whenever a material adverse event jeopardizes one party’s ability to perform under the instrument. If the Company were to sustain a material adverse event (using commercially reasonable standards), the counterparties could request collateralization on derivative trading instruments in net liability positions which, based on an aggregate fair value at December 31, 2011 and 2010, would have amounted to collateral postings of approximately $11 million and $160 million, respectively, to its counterparties. As of December 31, 2011, zero collateral was posted to counterparties for such positions while $5.8 million was posted at December 31, 2010 (reflected in “Liabilities from coal trading activities, net”).

Certain of the Company’s other derivative trading instruments require the parties to provide additional performance assurances whenever a credit downgrade occurs below a certain level as specified in each underlying contract. The terms of such derivative trading instruments typically require additional collateralization, which is commensurate with the severity of the credit downgrade. If a credit downgrade were to have occurred below contractually specified levels, the Company’s additional collateral requirement owed to its counterparties would have been zero at December 31, 2011 and December 31, 2010 based on the aggregate fair value of all derivative trading instruments with such features that are in a net liability position. As such, the Company had no posting requirements for such instruments as of December 31, 2011. As of December 31, 2010, $5.0 million of margin was posted with a counterparty due to timing and market fluctuations (reflected in “Liabilities from coal trading activities, net”).

The Company is required to post collateral on positions that are in a net liability position with an exchange and is entitled to receive collateral on positions that are in a net asset position. This collateral is known as variation margin. At December 31, 2011, the Company was in a net asset position of $52.1 million as compared to a net liability position of $137.4 million at December 31, 2010. The margin held at December 31, 2011 is reflected in "Assets from coal trading activities, net" and the margin posted at December 31, 2010 is reflected in “Liabilities from coal trading activities, net.”

F - 25

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In addition, the Company is required by the exchange to post certain additional collateral, known as initial margin, which represents an estimate of potential future adverse price movements across the Company’s portfolio under normal market conditions. As of December 31, 2011 and 2010, the Company had posted initial margin of $34.0 million and $39.5 million, respectively (reflected in “Other current assets”). In addition, the Company posted $4.4 million of margin in excess of the exchange-required variation and initial margin discussed above as of December 31, 2010 (also reflected in “Other current assets”).

MF Global UK Limited

In October 2011, MF Global UK, a United Kingdom (U.K.) based broker-dealer, was placed into the U.K.'s administration process (a process similar to bankruptcy proceedings in the U.S.) by the Financial Services Authority following the Chapter 11 bankruptcy filing of its U.S. parent, MF Global Holdings Ltd. The Company had used MF Global UK to broker certain of its coal trading transactions. The interruption of the Company's trading operations was limited as the Company opened new accounts with different brokerage firms and transferred its open trading positions formerly held with MF Global UK to those new accounts. While the open trading positions were transferred from MF Global UK successfully, the related margin posted by the Company has been retained by MF Global UK pending resolution of the Company's claims with the special administrators. The Company had funds remaining with MF Global UK totaling approximately $53 million as of December 31, 2011, which is included in "Accounts receivable, net" in the consolidated balance sheets. The Company is pursuing collection and, due to the numerous uncertainties related to the claim, cannot reasonably estimate a potential reserve based upon information available as of the date of filing.

(8) Financing Receivables

At December 31, 2011, the Company had total financing receivables of $376.1 million, of which $51.3 million was included in "Accounts receivable, net", $65.0 million was included in "Other current assets" and $259.8 million was included in "Investments and other assets" in the consolidated balance sheets. The Company periodically assesses the collectability of accounts and loans receivable by considering factors such as specific evaluation of collectability, historical collection experience, the age of the receivable and other available evidence. Below is a description of the Company's financing receivables at December 31, 2011.

Codrilla Mine Project. In 2011, a wholly owned subsidiary of Macarthur completed the sale of its 85% interest in the Codrilla Mine Project to participants of the Coppabella Moorvale Joint Venture (CMJV) where Macarthur sold down its interest in the Codrilla project to the CMJV (Codrilla sell down) so that following completion of the sale, ownership of the Codrilla Mine Project reflected the existing ownership of the Coppabella and Moorvale mines, with Macarthur retaining a 73.3% ownership. Prior to the Company's acquisition of Macarthur, consideration of $15.0 million (Australian dollars) was received by Macarthur upon completion of the Codrilla sell down, representing 20% of the agreed price. Two remaining installments are due on the completion of certain milestones, with 40% due on granting of the related mining lease and the final 40% due upon the mine's first coal shipment. There are currently no indications of impairment and the Company expects to receive full payment of amounts currently due. At December 31, 2011, $34.2 million was included in "Accounts receivable, net" and $35.6 million was included in "Investments and other assets" in the consolidated balance sheets.

Middlemount Mine. A wholly owned subsidiary of Macarthur periodically makes contributions to the Middlemount Mine joint venture for the purposes of funding capital expenditures and working capital, in line with the related shareholders’ agreement. Middlemount intends to pay down the loans as excess cash is generated as required by the related shareholders' agreement. There are currently no indications of impairment and the Company expects to receive full payment of amounts currently due. At December 31, 2011, $65.0 million was included in "Other current assets" and $224.2 million was included in "Investments and other assets" in the consolidated balance sheets.

Other Financing Receivables. From time to time, the Company may enter into transactions resulting in accounts or notes receivable held by the Company. These notes are generally short term in nature with positive historical collection experience and do not represent a material credit risk to the Company.

F - 26

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(9) Income Taxes

Income from continuing operations before income taxes consisted of the following:

	Year Ended December 31,
	2011		2010		2009
	(Dollars in millions)
U.S.	$	815.7	$	535.5	$	281.4
Non-U.S.	558.0		606.5		348.0
Total	$	1,373.7	$	1,142.0	$	629.4

Total income tax provision consisted of the following:

	Year Ended December 31,
	2011		2010		2009
	(Dollars in millions)
Current:
U.S. federal	$	103.4	$	113.9	$	(0.7	)
Non-U.S.	58.9		78.8		50.0
State	12.2		1.0		1.7
Total current	174.5		193.7		51.0
Deferred:
U.S. federal	138.0		47.9		56.0
Non-U.S.	42.8		68.1		78.5
State	7.9		5.7		0.7
Total deferred	188.7		121.7		135.2
Total provision	$	363.2	$	315.4	$	186.2

The following is a reconciliation of the expected statutory federal income tax provision to the Company’s actual income tax provision:

	Year Ended December 31,
	2011			2010			2009
	(Dollars in millions)
Expected income tax provision at federal statutory rate	$	480.8		$	399.7		$	220.3
Excess depletion	(70.8		)	(53.5		)	(44.0		)
Foreign earnings provision differential	(99.2		)	(124.5		)	(83.4		)
Foreign earnings repatriation	7.6			84.5			—
Remeasurement of foreign income tax accounts	(0.9		)	47.9			74.4
State income taxes, net of U.S. federal tax benefit	12.3			(4.8		)	3.4
General business tax credits	(17.8		)	(17.0		)	(12.2		)
Changes in valuation allowance	15.4			(28.7		)	17.3
Changes in tax reserves	14.7			—			5.9
Other, net	21.1			11.8			4.5
Total provision	$	363.2		$	315.4		$	186.2

F - 27

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities consisted of the following:

	December 31,
	2011			2010
	(Dollars in millions)
Deferred tax assets:
Tax credits and loss carryforwards	$	432.8		$	425.2
Postretirement benefit obligations	485.4			427.7
Intangible tax asset and purchased contract rights	10.6			15.1
Accrued reclamation and mine closing liabilities	114.6			97.8
Accrued long-term workers’ compensation liabilities	15.6			15.5
Employee benefits	53.3			53.5
Hedge activities	—			30.6
Financial guarantee	18.5			18.8
Others	57.9			45.4
Total gross deferred tax assets	1,188.7			1,129.6
Deferred tax liabilities:
Property, plant, equipment and mine development, leased coal interests and advance royalties, principally due to differences in depreciation, depletion and asset writedowns	1,348.0			1,246.8
Unamortized discount on Convertible Junior Subordinated Debentures	132.5			135.5
Hedge activities	45.5			—
Investments and other assets	109.8			107.0
Total gross deferred tax liabilities	1,635.8			1,489.3
Valuation allowance	(79.8		)	(65.0		)
Net deferred tax liability	$	(526.9	)	$	(424.7	)
Deferred taxes are classified as follows:
Current deferred income taxes	$	27.3		$	120.4
Noncurrent deferred income taxes	(554.2		)	(545.1		)
Net deferred tax liability	$	(526.9	)	$	(424.7	)

The Company’s tax credits and loss carryforwards included alternative minimum tax (AMT), foreign tax and general business credits of $300.0 million, state net operating loss (NOL) carryforwards of $23.5 million and foreign loss carryforwards of $109.3 million as of December 31, 2011. The AMT credits, foreign NOL, and capital loss carryforwards have no expiration date. The foreign tax and general business credits begin to expire in 2020 and 2027, respectively. The state NOL carryforwards begin to expire in the year 2012. In assessing the near term use of NOLs and tax credits and corresponding valuation allowance adjustments, the Company evaluated the overall deferred tax position, available tax strategies and future taxable income. The $15.4 million change in the valuation allowance was due to an increase on foreign deferred tax assets. The remaining valuation allowance at December 31, 2011 of $79.8 million represents a reserve for state NOLs and certain foreign deferred tax assets.

F - 28

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Unrecognized Tax Benefits

The total amount of the net unrecognized tax benefits was $114.7 million ($119.6 million gross) at December 31, 2011 and was $107.9 million ($111.0 million gross) at December 31, 2010. The amount of the Company’s gross unrecognized tax benefits has increased by $8.6 million since January 1, 2011 due to additions for current and prior year positions. The amount of the net unrecognized tax benefits that, if recognized, would directly affect the effective tax rate is $114.7 million at December 31, 2011 and $107.9 million at December 31, 2010. A reconciliation of the beginning and ending amount of gross unrecognized tax benefits is as follows (dollars in millions):

	Year Ended December 31,
	2011		2010			2009
Balance at beginning of period	$	111.0	$	113.2		$	186.3
Additions for current year tax positions	5.2		3.4			2.7
Additions for prior year positions	3.4		13.8			15.7
Reductions for settlements with tax authorities	—		(19.4		)	(88.5		)
Reductions for expirations of statute of limitations	—		—			(3.0		)
Balance at end of period	$	119.6	$	111.0		$	113.2

The Company recognizes interest and penalties accrued related to unrecognized tax benefits in its income tax provision. The Company has recognized $11.4 million of interest for the year ended December 31, 2011. The Company had $26.0 million and $14.6 million of accrued interest related to uncertain tax positions at December 31, 2011 and 2010, respectively. The Company has considered the application of penalties on its unrecognized tax benefits and determined, based upon several factors, that no accrual of penalties is required.

Tax Returns Subject to Examination

The Company's federal income tax returns are under examination by the Internal Revenue Service (IRS) for the 2006 through 2008 income tax years. The Company's Australian income tax returns for the tax years 2004 through 2010 are under examination by the Australian Tax Office (ATO). The 2006 IRS audit remains open awaiting the IRS appeals decision for the 2006 proposed adjustment of interest income accrued by a foreign subsidiary. Should the IRS position ultimately be sustained at the conclusion of the appeals process, additional income tax charges would be required to the extent the Company's NOL carryforwards are reduced.The 2007-2008 IRS audit was substantially complete at December 31, 2011 with no significant adjustments proposed by the IRS. The ATO is reviewing a transaction resulting in a foreign currency loss, interest rates on intercompany loans and certain intercompany charges. No formal adjustments have been proposed as of December 31, 2011. The Company believes it is reasonably possible one or both of these audits will be completed or settled during the next 12 months resulting in a potential decrease to its net unrecognized tax benefits of up to $30 million.

Notwithstanding these audit cycles, the years 1999-2001, 2003 through 2004, 2009 and 2010 remain potentially subject to examination due to NOL carryforwards. The Company's state income tax returns for the tax years 1996 and beyond remain potentially subject to examination by various state taxing authorities due to NOL carryforwards.

Foreign Earnings

The total amount of undistributed earnings of foreign subsidiaries for income tax purposes was $1.3 billion at December 31, 2011 and $1.1 billion at December 31, 2010. The Company has not provided deferred taxes on foreign earnings of $1.3 billion for 2011 and $1.1 billion for 2010 because such earnings are considered to be indefinitely reinvested outside the U.S. Should the Company repatriate all of these earnings, a one-time income tax charge of up to $450.7 million could occur.

F - 29

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Tax Payments

The following table summarizes the Company’s tax payments:

	Year Ended December 31,
	2011		2010		2009
	(Dollars in millions)
U.S. — federal	$	200.0	$	65.0	$	—
U.S. — state and local	13.2		0.4		0.9
Non-U.S.	61.9		83.0		169.7
Total tax payments	$	275.1	$	148.4	$	170.6

(10) Accounts Payable and Accrued Expenses

Accounts payable and accrued expenses consisted of the following:

	December 31,
	2011		2010
	(Dollars in millions)
Trade accounts payable	$	735.6	$	465.5
Other accrued expenses	286.7		179.9
Accrued taxes other than income	196.8		185.3
Accrued payroll and related benefits	183.3		152.1
Accrued health care	77.8		85.9
Accrued royalties	77.8		72.6
Accrued interest	49.5		30.5
Workers’ compensation obligations	17.3		14.6
Accrued environmental	11.6		6.3
Commodity and foreign currency hedge contracts	7.9		2.9
Other accrued benefits	4.1		4.2
Income taxes payable	—		59.6
Liabilities associated with discontinued operations	63.9		29.4
Total accounts payable and accrued expenses	$	1,712.3	$	1,288.8

F - 30

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(11) Debt

The Company’s total indebtedness as of December 31, 2011 and 2010 consisted of the following:

	December 31,
	2011		2010
	(Dollars in millions)
Term Loan	$	468.8	$	493.8
2011 Term Loan Facility	1,000.0		—
5.875% Senior Notes due April 2016	—		218.1
7.375% Senior Notes due November 2016	650.0		650.0
6.00% Senior Notes due November 2018	1,600.0		—
6.50% Senior Notes due September 2020	650.0		650.0
6.25% Senior Notes due November 2021	1,500.0		—
7.875% Senior Notes due November 2026	247.3		247.2
Convertible Junior Subordinated Debentures due 2066	375.2		373.3
Capital lease obligations	122.8		69.6
Fair value hedge adjustment	—		2.2
Other	43.4		45.8
Total	$	6,657.5	$	2,750.0

Credit Facility

On June 18, 2010, the Company entered into an unsecured credit agreement (the Credit Agreement) which established a $2.0 billion credit facility (the Credit Facility) and replaced the Company’s third amended and restated credit agreement dated as of September 15, 2006. The Credit Agreement provides for a $1.5 billion revolving credit facility (the Revolver) and a $500.0 million term loan facility (the Term Loan). The Company has the option to request an increase in the capacity of the Credit Facility, provided the aggregate increase for the Revolver and Term Loan does not exceed $250.0 million, the minimum amount of the increase is $25.0 million, and certain other conditions are met under the Credit Agreement. The Revolver also includes a swingline sub-facility under which up to $50.0 million is available for same-day borrowings. The Revolver commitments and the Term Loan under the Credit Facility will mature on June 18, 2015.

The Revolver replaced the Company’s previous $1.8 billion revolving credit facility and the Term Loan replaced the Company’s previous term loan facility (the previous term loan had a balance of $490.3 million at the time of replacement). The Company recorded $21.9 million in deferred financing costs, which are being amortized to interest expense over the five-year term of the Credit Facility. The Company also recorded refinancing charges of $9.3 million, which was recorded in “Interest expense” in the 2010 consolidated statements of income. The $500.0 million of proceeds from the Term Loan was used to repay the balance due on the Company’s previous term loan facility.

All borrowings under the Credit Agreement (other than swingline borrowings and borrowings denominated in currencies other than U.S. dollars) bear interest, at the Company’s option, at either a “base rate” or a “eurocurrency rate”, as defined in the Credit Agreement, plus in each case, a rate adjustment based on the Company’s leverage ratio, as defined in the Credit Agreement, ranging from 2.50% to 1.30% per year for borrowings bearing interest at the “base rate” and from 3.50% to 2.25% per year for borrowings bearing interest at the “eurocurrency rate” (such rate added to the “eurocurrency rate,” the “Eurocurrency Margin”). Swingline borrowings bear interest at a “BBA LIBOR” rate equal to the rate at which deposits in U.S. dollars for a one month term are offered in the interbank eurodollar market, as determined by the administrative agent, plus the Eurocurrency Margin. Borrowings denominated in currencies other than U.S. dollars will bear interest at the “eurocurrency rate” plus the Eurocurrency Margin.

F - 31

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Company pays a usage-dependent commitment fee under the Revolver, which is dependent upon the Company’s leverage ratio, as defined in the Credit Agreement, and ranges from 0.500% to 0.375% of the available unused commitment. Swingline loans are not considered usage of the revolving credit facility for purposes of calculating the commitment fee. The fee accrues quarterly in arrears.

In addition, the Company pays a letter of credit fee calculated at a rate dependent on the Company’s leverage ratio, as defined in the Credit Agreement, ranging from 3.50% to 2.25% per year of the undrawn amount of each letter of credit and a fronting fee equal to 0.125% per year of the face amount of each letter of credit. These fees are payable quarterly in arrears.

The Term Loan is voluntarily prepayable from time to time without any premium or penalty, subject to certain customary reimbursements of the lenders' costs. The Term Loan, which is subject to quarterly repayment of 1.25% per quarter, commenced on December 31, 2010, with the final payment of all amounts outstanding (including accrued interest) being due on June 18, 2015.

Under the Credit Agreement, the Company must comply with certain financial covenants on a quarterly basis including a minimum interest coverage ratio and a maximum leverage ratio. The Credit Agreement also includes various affirmative and negative covenants that place limitations on the Company’s ability to, among other things, incur debt; make loans, investments, advances and acquisitions; sell assets; make redemptions and repurchases of capital stock; engage in mergers or consolidations; engage in affiliate transactions and restrict distributions from subsidiaries. When in compliance with the financial covenants and customary default provisions, the Company is not restricted in its ability to pay dividends, sell assets and make redemptions or repurchase capital stock provided that the Company may only redeem and repurchase capital stock with the proceeds received from the concurrent issue of capital stock or indebtedness permitted under the Credit Agreement.

Nearly all of the Company’s direct and indirect domestic subsidiaries guarantee all loans under the Credit Agreement. Certain of the Company’s foreign subsidiaries also, to the extent permitted by applicable law and existing contractual obligations, would be guarantors of loans made to one of the Company’s Dutch subsidiaries.

As of December 31, 2011, the Company had no borrowings on the Revolver, but had $21.0 million of letters of credit outstanding. The remaining capacity on the Revolver at December 31, 2011 was $1.5 billion.

The interest rate payable on the Revolver and the Term Loan was LIBOR plus 2.25%, or 2.51% at December 31, 2011.

2011 Term Loan Facility

On October 28, 2011, the Company entered into the 2011 Term Loan Facility that provides for borrowings up to $1.0 billion. The Company borrowed $1.0 billion under the 2011 Term Loan Facility to finance, in part, the acquisition of Macarthur. Borrowings under the 2011 Term Loan Facility bear interest, at the Company's option, at a rate equal to (i) LIBOR plus an applicable margin or (ii) a base rate (defined as the highest of (a) the Bank of America prime rate, (b) the Federal Funds rate plus 0.50% and (c) one month LIBOR plus 1.00%) plus an applicable margin. The applicable margin depends on the ratio of the Company's consolidated debt to its adjusted consolidated EBITDA, and may range from 1.75% to 3.00% per year for borrowings bearing interest at LIBOR and from 0.75% to 2.00% per year for borrowings bearing interest at the base rate, as defined in the 2011 Term Loan Facility.

The obligations under the 2011 Term Loan Facility are unsecured and are guaranteed by the Company's direct and indirect domestic subsidiaries that guarantee the Credit Facility. The 2011 Term Loan Facility contains covenants, including financial covenants, and events of default substantially the same as those set forth in the Credit Facility.

The 2011 Term Loan Facility is voluntarily prepayable from time to time without premium or penalty, subject to certain customary reimbursements of the lenders’ costs. The 2011 Term Loan Facility will be subject to quarterly repayment of 1.25% commencing April 28, 2012, with the final payment of all amounts outstanding due October 28, 2016.

As of December 31, 2011, the Company had $1.0 billion outstanding on the 2011 Term Loan Facility with an interest rate payable of LIBOR plus 2.0%, or 2.26%.

F - 32

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

5.875% Senior Notes

On April 15, 2011, the Company used cash on hand to redeem its 5.875% Senior Notes due in April 2016 (the 5.875% Notes) in the aggregate principal amount of $218.1 million. In compliance with the terms of the indenture governing the 5.875% Notes, the redemption price was equal to 100.979% of the aggregate principal amount of the 5.875% Notes plus accrued and unpaid interest to April 15, 2011. The Company recognized costs of $1.7 million associated with the redemption.

6.00%, 6.25%, 6.50%, 7.375% and 7.875% Senior Notes (collectively the Senior Notes)

The Senior Notes are senior unsecured obligations and rank senior in right of payment to any subordinated indebtedness; equally in right of payment with any senior indebtedness; are effectively junior in right of payment to the Company’s future secured indebtedness, to the extent of the value of the collateral securing that indebtedness; and effectively junior to all the indebtedness and other liabilities of its subsidiaries that do not guarantee the notes.

The Senior Notes are jointly and severally guaranteed by nearly all of the Company’s domestic subsidiaries, as defined in the note indentures. The note indentures contain covenants that, among other things, limit the Company’s ability to create liens and enter into sale and lease-back transactions. The Senior Notes are redeemable at a redemption price equal to 100% of the principal amount of the notes being redeemed plus a make-whole premium and any accrued unpaid interest to the redemption date. If the Company experiences specific kinds of changes in control and the credit rating assigned to the Senior Notes declines below specified levels within 90 days of that time, holders of such notes have the right to require the Company to repurchase their notes at a repurchase price equal to 101% of their principal amount, plus accrued and unpaid interest, if any, to the date of repurchase.

Interest payments on the Senior Notes are scheduled to occur each year as follows:

Senior Notes	Interest Payment Dates
6.00% Senior Notes	May 15 and November 15
6.25% Senior Notes	May 15 and November 15
6.50% Senior Notes	March 15 and September 15
7.375% Senior Notes	May 1 and November 1
7.875% Senior Notes	May 1 and November 1

On November 15, 2011, the Company completed a $1.6 billion offering of 6.00% Senior Notes due November 2018 (the 6.00% Senior Notes) and a $1.5 billion offering of 6.25% Senior Notes due November 2021 (the 6.25% Senior Notes), with the proceeds of the offering used, in part, to finance the acquisition of Macarthur. On the same date, the Company, the Guarantors and the initial purchasers of the 6.00% Senior Notes and the 6.25% Senior Notes entered into a registration rights agreement (the Registration Rights Agreement). Subject to the terms of the Registration Rights Agreement, the Company will use its reasonable best efforts to register with the Securities and Exchange Commission exchange notes having substantially identical terms as the 6.00% Senior Notes and the 6.25% Senior Notes and to exchange freely tradeable exchange notes for such notes within 365 days after the issue date of the 6.00% Senior Notes and the 6.25% Senior Notes (effectiveness target date). If the Company fails to meet the effectiveness target date (a registration default), the annual interest rate on the 6.00% Senior Notes and the 6.25% Senior Notes will increase by 0.25% for each 90-day period during which the default continues, up to a maximum additional interest rate of 1.0% until the registration default is cured.

On August 25, 2010, the Company completed a $650.0 million offering of 6.50% Senior Notes due September 2020 (the 6.50% Senior Notes). The Company used the net proceeds of $641.9 million from the issuance of the 6.50% Senior Notes, after deducting underwriting discounts and expenses, and cash on hand to extinguish its previously outstanding $650.0 million aggregate principal 6.875% Senior Notes formerly due in March 2013 (the 2013 Notes). All of the 2013 Notes were either tendered or redeemed during 2010. The Company recognized debt extinguishment costs of $8.4 million, which was recorded in “Interest expense” in the consolidated statements of income. The issuance of the 6.50% Senior Notes and the extinguishment of the 2013 Notes allowed the Company to extend the maturity of its senior indebtedness and lower the coupon rate.

F - 33

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Convertible Junior Subordinated Debentures

As of December 31, 2011, the Company had $732.5 million aggregate principal outstanding of Debentures that generally require interest to be paid semiannually at a rate of 4.75% per year. The Company may elect to, and to the extent that a mandatory trigger event (as defined in the indenture governing the Debentures) has occurred and is continuing will be required to, defer interest payments on the Debentures. After five years of deferral at the Company’s option, or upon the occurrence of a mandatory trigger event, the Company generally must sell warrants or preferred stock with specified characteristics and use the funds from that sale to pay deferred interest, subject to certain limitations. In no event may the Company defer payments of interest on the Debentures for more than 10 years.

The Debentures are convertible at any time on or prior to December 15, 2036 if any of the following conditions occur: (i) the Company’s closing common stock price exceeds 140% of the then applicable conversion price for the Debentures (currently $81.47 per share) for at least 20 of the final 30 trading days in any quarter; (ii) a notice of redemption is issued with respect to the Debentures; (iii) a change of control, as defined in the indenture governing the Debentures; (iv) satisfaction of certain trading price conditions; and (v) other specified corporate transactions described in the indenture governing the Debentures. In addition, the Debentures are convertible at any time after December 15, 2036 to December 15, 2041, the scheduled maturity date. In the case of conversion following a notice of redemption or upon a non-stock change of control, as defined in the indenture governing the Debentures, holders may convert their Debentures into cash in the amount of the principal amount of their Debentures and shares of the Company’s common stock for any conversion value in excess of the principal amount. In all other conversion circumstances, holders will receive perpetual preferred stock (see Note 16) with a liquidation preference equal to the principal amount of their Debentures, and any conversion value in excess of the principal amount will be settled with the Company’s common stock. As a result of the Patriot Coal Corp. (Patriot) spin-off, the conversion rate was adjusted. The conversion rate has also been adjusted when there has been a change in the Company’s dividend distribution rate. The current conversion rate is 17.1846 shares of common stock per $1,000 principal amount of Debentures effective February 7, 2012. This adjusted conversion rate represents a conversion price of $58.19.

The Debentures are not subject to redemption prior to December 20, 2011. Between December 20, 2011 and December 19, 2036, the Company may redeem the Debentures, in whole or in part, if for at least 20 out of the 30 consecutive trading days immediately prior to the date on which notice of redemption is given, the Company’s closing common stock price has exceeded 130% of the then applicable conversion price for the Debentures (currently $75.65 per share). On or after December 20, 2036, whether or not the redemption condition is satisfied, the Company may redeem the Debentures, in whole or in part. The Company may not redeem any Debentures unless (i) all accrued and unpaid interest on the Debentures has been paid in full on or prior to the redemption date and (ii) if any perpetual preferred stock is outstanding, the Company has first given notice to redeem the perpetual preferred stock in the same proportion as the redemption of the Debentures. Any redemption of the Debentures will be at a cash redemption price of 100% of the principal amount of the Debentures to be redeemed, plus accrued and unpaid interest to the date of redemption.

On December 15, 2041, the scheduled maturity date, the Company will use commercially reasonable efforts, subject to the occurrence of a market disruption event, as defined in the indenture governing the Debentures, to issue securities of equivalent equity content in an amount sufficient to pay the principal amount of the Debentures, together with accrued and unpaid interest. At the final maturity date of the Debentures on December 15, 2066, the entire principal amount will become due and payable, together with accrued and unpaid interest.

In connection with the issuance of the Debentures, the Company entered into a Capital Replacement Covenant (the CRC). Pursuant to the CRC, the Company covenanted for the benefit of holders of covered debt, as defined in the CRC (currently the Company’s 7.875% Senior Notes, issued in the aggregate principal amount of $250.0 million), that neither the Company nor any of its subsidiaries shall repay, redeem or repurchase all or any part of the Debentures on or after December 15, 2041 and prior to December 15, 2046, except to the extent that the total repayment, redemption or repurchase price does not exceed the sum of: (i) 400% of the Company’s net cash proceeds from the sale of its common stock and rights to acquire its common stock (including common stock issued pursuant to the Company’s dividend reinvestment plan or employee benefit plans); (ii) the Company’s net cash proceeds from the sale of its mandatorily convertible preferred stock, as defined in the CRC, or debt exchangeable for equity, as defined in the CRC; and (iii) the Company’s net cash proceeds from the sale of other replacement capital securities, as defined in the CRC, in each case, during the six months prior to the notice date for the relevant payment, redemption or repurchase.

F - 34

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Debentures are unsecured obligations of the Company, ranking junior to all existing and future senior and subordinated debt (excluding trade accounts payable or accrued liabilities arising in the ordinary course of business) except for any future debt that ranks equal to or junior to the Debentures. The Debentures will rank equal in right of payment with the Company’s obligations to trade creditors. Substantially all of the Company’s existing indebtedness is senior to the Debentures. In addition, the Debentures will be effectively subordinated to all indebtedness of the Company’s subsidiaries. The indenture governing the Debentures places no limitation on the amount of additional indebtedness that the Company or any of the Company’s subsidiaries may incur.

The Company accounts for the liability and equity components of the Debentures in a manner that reflects the nonconvertible debt borrowing rate when recognizing interest cost in subsequent periods. The following table illustrates the carrying amount of the equity and debt components of the Debentures:

	December 31,
	2011			2010
	(Dollars in millions)
Carrying amount of the equity component	$	215.4		$	215.4
Principal amount of the liability component	$	732.5		$	732.5
Unamortized discount	(357.3		)	(359.2		)
Net carrying amount	$	375.2		$	373.3

The following table illustrates the effective interest rate and the interest expense related to the Debentures:

	Year Ended December 31,
	2011			2010			2009
	(Dollars in millions)
Effective interest rate	4.9		%	4.9		%	4.9		%
Interest expense — contractual interest coupon	$	34.8		$	34.8		$	34.8
Interest expense — amortization of debt discount	1.9			1.8			1.6

The remaining period over which the discount will be amortized is 30 years as of December 31, 2011.

Macarthur Corporate Funding Facility

With the acquisition of Macarthur, the Company assumed Macarthur's three year $330.0 million (Australian dollar) Corporate Funding Facility that has a maturity date of November 30, 2013. As of December 31, 2011, the Company had no borrowings under the Macarthur Corporate Funding Facility. The Macarthur Corporate Funding Facility has a $130.0 million (Australian dollar) sub-limit for bank guarantees, leaving an available capacity of $200.0 million (Australian dollars) at December 31, 2011. Letters of credit and cash backed bank guarantees totaling $65.0 million (Australian dollars) were outstanding as of December 31, 2011. The Company plans to terminate the Macarthur Corporate Funding Facility in 2012.

Capital Lease Obligations

Capital lease obligations are for mining equipment (see Note 12 for additional information).

F - 35

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Debt Maturities, Interest Paid, and Financing Costs

The aggregate amounts of long-term debt maturities (including unamortized debt discounts) subsequent to December 31, 2011, including capital lease obligations, were as follows:

Year of Maturity	(Dollars in millions)
2012	$	101.1
2013	121.9
2014	107.8
2015	458.5
2016	1,475.7
2017 and thereafter	4,392.5
Total	$	6,657.5

Interest paid on long-term debt was $205.3 million, $197.9 million and $201.6 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Financing costs incurred with the issuance of the Company’s debt are being amortized to interest expense over the remaining term of the associated debt. The remaining balance at December 31, 2011 was $99.9 million, of which $69.2 million will be amortized to interest expense over the next five years.

(12) Leases

The Company leases equipment and facilities under various noncancelable lease agreements. Certain lease agreements require the maintenance of specified ratios and contain restrictive covenants which limit indebtedness, subsidiary dividends, investments, asset sales and other Company actions. Rental expense under operating leases was $170.6 million, $129.5 million and $116.6 million for the years ended December 31, 2011, 2010 and 2009, respectively. The gross value of property, plant, equipment and mine development assets under capital leases was $297.0 million as of December 31, 2011 and $109.5 million as of December 31, 2010, related primarily to the leasing of mining equipment. The accumulated depreciation for these items was $58.9 million and $39.5 million at December 31, 2011 and 2010, respectively.

The Company also leases coal reserves under agreements that require royalties to be paid as the coal is mined. Certain agreements also require minimum annual royalties to be paid regardless of the amount of coal mined during the year. Total royalty expense was $610.6 million, $540.6 million and $428.6 million for the years ended December 31, 2011, 2010 and 2009, respectively.

A substantial amount of the coal mined by the Company is produced from mineral reserves leased from the owner. One of the major lessors is the U.S. government, from which the Company leases substantially all of the coal it mines in Wyoming under terms set by Congress and administered by the U.S. Bureau of Land Management. These leases are generally for an initial term of ten years but may be extended by diligent development and mining of the reserves until all economically recoverable reserves are depleted. The Company has met the diligent development requirements for substantially all of these federal leases either directly through production, by including the lease as a part of a logical mining unit with other leases upon which development has occurred, or by paying an advance royalty in lieu of continued operations. Annual production on these federal leases must total at least 1.0% of the original amount of coal in the entire logical mining unit. In addition, royalties are payable monthly at a rate of 12.5% of the gross realization from the sale of the coal mined using surface mining methods and at a rate of 8.0% of the gross realization for coal produced using underground mining methods. The Company also leases coal reserves in Arizona from The Navajo Nation and the Hopi Tribe under leases that are administered by the U.S. Department of the Interior. These leases expire upon exhaustion of the leased reserves or upon the permanent ceasing of all mining activities on the related reserves as a whole. The royalty rates are also generally based upon a percentage of the gross realization from the sale of coal. These rates are subject to redetermination every ten years under the terms of the leases. The remainder of the leased coal is generally leased from state governments, land holding companies and various individuals. The duration of these leases varies greatly. Typically, the lease terms are automatically extended as long as active mining continues. Royalty payments are generally based upon a specified rate per ton or a percentage of the gross realization from the sale of the coal.

F - 36

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Mining and exploration in Australia is generally executed 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 the sales price. 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 the loss of access to the land where the landowner retains the surface rights, and the amount and type of compensation can be determined by agreement or arbitration as provided in the mining law. Surface rights are typically acquired directly from landowners by mutual agreement.

Future minimum lease and royalty payments as of December 31, 2011 are as follows:

	Capital Leases		Operating Leases		Coal Lease and Royalty Obligations
Year Ending December 31,
	(Dollars in millions)
2012	$	32.3	$	123.1	$	50.7
2013	41.3		106.2		50.0
2014	25.9		90.6		48.8
2015	10.5		76.4		46.6
2016	10.3		63.5		3.8
2017 and thereafter	21.7		151.1		27.9
Total minimum lease payments	142.0		$	610.9	$	227.8
Less interest	19.5
Present value of minimum capital lease payments	$	122.5

As of December 31, 2011, certain of the Company’s lease obligations were secured by outstanding surety bonds totaling $104.7 million.

(13) Asset Retirement Obligations

Reconciliations of the Company’s ARO liability are as follows:

	December 31,
	2011			2010
	(Dollars in millions)
Balance at beginning of year	$	490.7		$	447.6
Liabilities incurred or acquired	43.0			8.2
Liabilities settled or disposed	(8.8		)	(8.7		)
Accretion expense	28.7			26.4
Revisions to estimates	67.7			17.2
Balance at end of year	$	621.3		$	490.7
Balance at end of year — active locations	$	574.0		$	438.2
Balance at end of year — closed or inactive locations	$	47.3		$	52.5

The credit-adjusted, risk-free interest rates were 5.76%, 6.37%, and 7.92% at December 31, 2011, 2010 and 2009, respectively.

As of December 31, 2011 and 2010, the Company had $791.6 million and $704.4 million, respectively, in surety bonds and bank guarantees outstanding to secure reclamation obligations or activities. The amount of reclamation self-bonding in certain states in which the Company qualifies was $929.6 million and $920.3 million as of December 31, 2011 and 2010, respectively. Additionally, the Company had $0.1 million of letters of credit in support of reclamation obligations or activities as of December 31, 2010.

F - 37

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(14) Postretirement Health Care and Life Insurance Benefits

The Company currently provides health care and life insurance benefits to qualifying salaried and hourly retirees and their dependents from benefit plans established by the Company.  Plan coverage for health benefits is provided to future hourly and salaried retirees in accordance with the applicable plan document.  Life insurance benefits are provided to future hourly retirees in accordance with the applicable labor agreement.

Net periodic postretirement benefit cost included the following components:

	Year Ended December 31,
	2011		2010		2009
	(Dollars in millions)
Service cost for benefits earned	$	13.9	$	12.9	$	10.5
Interest cost on accumulated postretirement benefit obligation	57.9		58.2		55.2
Amortization of prior service cost	2.8		2.6		1.5
Amortization of actuarial loss	26.9		24.9		14.5
Net periodic postretirement benefit cost	$	101.5	$	98.6	$	81.7

The following includes amounts recognized in accumulated other comprehensive loss:

	Year Ended December 31,
	2011			2010			2009
	(Dollars in millions)
Net actuarial loss arising during year	$	86.0		$	45.3		$	165.2
Prior service cost arising during year	(1.4		)	7.9			(10.5		)
Amortization:
Actuarial loss	(26.9		)	(24.9		)	(14.5		)
Prior service cost	(2.8		)	(2.6		)	(1.5		)
Total recognized in other comprehensive loss	54.9			25.7			138.7
Net periodic postretirement benefit cost	101.5			98.6			81.7
Total recognized in net periodic postretirement benefit cost and other comprehensive loss	$	156.4		$	124.3		$	220.4

The Company amortizes actuarial gain and loss using a 0% corridor with an amortization period that covers the average future working lifetime of active employees (11.70 years and 12.06 years at January 1, 2012 and 2011, respectively). The estimated net actuarial loss and prior service cost that will be amortized from accumulated other comprehensive loss into net periodic postretirement benefit cost during the year ended December 31, 2012 are $32.8 million and $2.5 million, respectively.

F - 38

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table sets forth the plan’s funded status reconciled with the amounts shown in the consolidated balance sheets:

	December 31,
	2011			2010
	(Dollars in millions)
Change in benefit obligation:
Accumulated postretirement benefit obligation at beginning of period	$	1,031.2		$	982.2
Service cost	13.9			12.9
Interest cost	57.9			58.2
Participant contributions	1.9			2.1
Plan amendments(1)	(1.4		)	7.9
Benefits paid	(68.0		)	(77.4		)
Actuarial loss	86.0			45.3
Accumulated postretirement benefit obligation at end of period	1,121.5			1,031.2
Change in plan assets:
Fair value of plan assets at beginning of period	—			—
Employer contributions	66.1			75.3
Participant contributions	1.9			2.1
Benefits paid and administrative fees (net of Medicare Part D reimbursements)	(68.0		)	(77.4		)
Fair value of plan assets at end of period	—			—
Funded status at end of year	(1,121.5		)	(1,031.2		)
Less current portion (included in Accounts payable and accrued expenses)	68.4			67.3
Noncurrent obligation (included in Accrued postretirement benefit costs)	$	(1,053.1	)	$	(963.9	)

⁽¹⁾  Effective January 1, 2011, certain plans were modified to ensure consistency of benefits across the Company, the impact of which is reflected in the December 31, 2010 figures above.

The weighted-average assumptions used to determine the benefit obligations as of the end of each year were as follows:

	December 31,
	2011		2010
Discount rate	5.05	%	5.81	%
Rate of compensation increase	N/A		3.50	%
Measurement date	December 31, 2011		December 31, 2010

The weighted-average assumptions used to determine net periodic benefit cost during each year were as follows:

	Year Ended December 31,
	2011		2010		2009
Discount rate	5.81	%	6.14	%	6.85	%
Rate of compensation increase	3.50	%	3.50	%	3.50	%
Measurement date	December 31, 2010		December 31, 2009		December 31, 2008

F - 39

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following presents information about the assumed health care cost trend rate:

	Year Ended December 31,
	2011		2010
Health care cost trend rate assumed for next year	9.00	%	9.00	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	5.00	%	5.00	%
Year that the rate reaches the ultimate trend rate	2018		2017

Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. A one-percentage-point change in the assumed health care cost trend would have the following effects:

	One Percentage- Point Increase		One Percentage- Point Decrease
	(Dollars in millions)
Effect on total service and interest cost components	$	8.2	$	(6.9	)
Effect on total postretirement benefit obligation	$	121.8	$	(104.6	)

Plan Assets

The Company’s postretirement benefit plans are unfunded.

Estimated Future Benefit Payments

The following benefit payments (net of retiree contributions), which reflect expected future service, as appropriate, are expected to be paid by the Company:

	Postretirement
	Benefits
	(Dollars in millions)
2012	$	68.4
2013	72.9
2014	75.6
2015	77.8
2016	79.9
Years 2017-2021	410.3

(15) Pension and Savings Plans

One of the Company’s subsidiaries, Peabody Investments Corp. (PIC), sponsors a defined benefit pension plan covering certain U.S. salaried employees and eligible hourly employees at certain PIC subsidiaries (the Peabody Plan). A PIC subsidiary also has a defined benefit pension plan covering eligible employees who are represented by the United Mine Workers of America (UMWA) under the Western Surface Agreement (the Western Plan). PIC also sponsors an unfunded supplemental retirement plan to provide senior management with benefits in excess of limits under the federal tax law (collectively, the Plans).

Effective May 31, 2008, the Peabody Plan was frozen in its entirety for both participation and benefit accrual purposes. The Company adopted an enhanced savings plan contribution structure in lieu of benefits formerly accrued under the Peabody Plan.

F - 40

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Net periodic pension cost included the following components:

	Year Ended December 31,
	2011			2010			2009
	(Dollars in millions)
Service cost for benefits earned	$	1.7		$	1.5		$	1.4
Interest cost on projected benefit obligation	49.8			50.5			51.3
Expected return on plan assets	(64.4		)	(58.3		)	(60.9		)
Amortization of prior service cost	1.0			1.4			1.4
Amortization of actuarial losses	30.1			21.9			1.9
Total net periodic pension (benefit) cost	$	18.2		$	17.0		$	(4.9	)

The following includes amounts recognized in accumulated other comprehensive loss:

	Year Ended December 31,
	2011			2010			2009
	(Dollars in millions)
Net actuarial loss arising during year	$	144.2		$	13.1		$	46.1
Amortization:
Actuarial loss	(30.1		)	(21.9		)	(1.9		)
Prior service cost	(1.0		)	(1.4		)	(1.4		)
Total recognized in other comprehensive loss	113.1			(10.2		)	42.8
Net periodic pension (benefit) cost	18.2			17.0			(4.9		)
Total recognized in net periodic pension cost and other comprehensive loss	$	131.3		$	6.8		$	37.9

The Company amortizes actuarial gain and loss using a 5% corridor with a five-year amortization period. The estimated net actuarial loss and prior service cost that will be amortized from accumulated other comprehensive loss into net periodic pension cost during the year ended December 31, 2012 are $48.6 million and $1.0 million, respectively.

F - 41

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following summarizes the change in benefit obligation, change in plan assets and funded status of the Company’s plans:

	December 31,
	2011			2010
	(Dollars in millions)
Change in benefit obligation:
Projected benefit obligation at beginning of period	$	881.0		$	844.9
Service cost	1.7			1.5
Interest cost	49.8			50.5
Benefits paid	(52.8		)	(50.4		)
Actuarial loss	83.9			34.5
Projected benefit obligation at end of period	963.6			881.0
Change in plan assets:
Fair value of plan assets at beginning of period	771.6			629.6
Actual return on plan assets	4.1			79.8
Employer contributions	46.7			112.6
Benefits paid	(52.8		)	(50.4		)
Fair value of plan assets at end of period	769.6			771.6
Funded status at end of year	$	(194.0	)	$	(109.4	)
Amounts recognized in the consolidated balance sheets:
Current obligation (included in Accounts payable and accrued expenses)	$	(1.7	)	$	(1.8	)
Noncurrent obligation (included in Other noncurrent liabilities)	(192.3		)	(107.6		)
Net amount recognized	$	(194.0	)	$	(109.4	)

The weighted-average assumptions used to determine the benefit obligations as of the end of each year were as follows:

	December 31,
	2011		2010
Discount rate	5.00	%	5.84	%
Measurement date	December 31, 2011		December 31, 2010

The weighted-average assumptions used to determine net periodic benefit cost during each year were as follows:

	Year Ended December 31,
	2011		2010		2009
Discount rate	5.84	%	6.19	%	6.90	%
Expected long-term return on plan assets	8.25	%	8.25	%	8.75	%
Measurement date	December 31, 2010		December 31, 2009		December 31, 2008

The expected rate of return on plan assets is determined by taking into consideration expected long-term returns associated with each major asset class (net of inflation) based on long-term historical ranges, inflation assumptions and the expected net value from active management of the assets based on actual results. Effective January 1, 2012, the Company lowered its expected rate of return on plan assets from 8.25% to 8.0% given the decline in asset performance due to the continued global recession and disruption in the financial markets.

The projected benefit obligation and the accumulated benefit obligation exceeded plan assets for all plans as of December 31, 2011 and 2010. The accumulated benefit obligation for all pension plans was $963.6 million and $881.0 million as of December 31, 2011 and 2010, respectively.

F - 42

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Assets of the Plans

Assets of the Peabody Plan and the Western Plan are commingled in the PIC Master Trust (the Master Trust) and are invested in accordance with investment guidelines that have been established by each Plan's respective Retirement Committee (collectively, the Retirement Committees) after consultation with outside investment advisors and actuaries.

The asset allocation targets have been set with the expectation that the Plans’ assets will be managed with an appropriate level of risk so that they can fund each Plan’s expected liabilities. To determine the appropriate target asset allocations, the Retirement Committees consider the demographics of each Plan’s participants, the funding status of each Plan, the business and financial profile of the Company and other associated risk preferences. These allocation targets are reviewed by the Retirement Committees on a regular basis and revised as necessary. The current target allocations for plan assets are 60% equity securities and 40% fixed income investments. Plan assets currently include real estate investments representing approximately 3% of total plan assets. The Company is in the process of liquidating these real estate holdings.

Assets of the Plans are either under active management by third-party investment advisors or in index funds, all selected and monitored by the Retirement Committees. The Retirement Committees have established specific investment guidelines for each major asset class including performance benchmarks, allowable and prohibited investment types and concentration limits. In general, the Plans’ investment guidelines do not permit leveraging the assets held in the Master Trust. The investment managers in the Master Trust, however, may employ various strategies and derivative instruments in establishing overall portfolio characteristics consistent with the guidelines and investment objectives for their portfolios. Equity investment guidelines do not permit entering into put or call options (except as deemed appropriate to manage currency risk), and futures contracts are permitted only to the extent necessary to equitize cash holdings.

A financial instrument’s level within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. Following is a description of the valuation methodologies used for investments measured at fair value, including the general classification of such investments pursuant to the valuation hierarchy.

U.S. equity securities.  As of December 31, 2011, investment vehicles include an institutional mutual fund that holds various small-cap publicly traded common stocks and an institutional mutual fund that invests in large-cap stocks. These institutional mutual funds are classified within the Level 2 valuation hierarchy since fair value inputs are derived prices in active markets and the institutional mutual funds are not publicly traded on a national securities exchange. Prior to December 31, 2011, investment vehicles included various small-cap publicly traded common stocks, an exchange-traded fund and a common/collective trust. Publicly traded common stocks and the exchange-traded fund were traded on a national securities exchange and were valued at quoted market prices in active markets and were classified within Level 1 of the valuation hierarchy. While the common/collective trust invested in various large-cap publicly traded common stocks that were traded on a national securities exchange, it was classified within Level 2 of the valuation hierarchy since the net asset value (NAV) was based on a derived price in an active market and it was not publicly traded on a national securities exchange. U.S. equity securities are not subject to liquidity redemption restrictions.

International equity securities.  Investment vehicles include a common/collective trust and an institutional mutual fund that primarily invest in various large-cap international equity securities that are valued on the basis of quotations from the primary market in which they are traded and translated at each valuation date from the local currency into U.S. dollars using the mean between the bid and asked market rates for such currencies. The NAV of the fund and the calculation of the NAV of each underlying investment are determined in U.S. dollars by the custodial trustee or at the direction of the investment manager as of the end of each month. These investments are classified within the Level 2 valuation hierarchy since the NAV is based on a derived price in an active market and neither the common/collective trust nor the mutual fund are publicly traded on a national securities exchange. Redemptions can only occur as of the last business day of the month subject to each funds respective notification period.

Debt securities.  Investment vehicles include various institutional mutual funds that hold mortgage-backed debt securities, international debt securities and corporate debt securities. Institutional mutual funds are invested in various diversified portfolios of fixed-income instruments, and the NAV for each institutional mutual fund is calculated daily in actively traded markets by an independent custodian for the investment manager. The institutional mutual funds are classified within the Level 2 valuation hierarchy since fair value inputs are derived prices in active markets and the institutional mutual funds are not publicly traded on a national securities exchange. Debt securities are not subject to liquidity redemption restrictions.

F - 43

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Short-term investments.  Investment vehicles primarily include institutional mutual funds. Short-term investments include a diversified portfolio of liquid, short-term instruments of varying maturities. The institutional mutual funds are classified within the Level 2 valuation hierarchy since fair value inputs are derived prices in active markets and the institutional mutual funds are not publicly traded on a national securities exchange. Short-term investments are not subject to liquidity redemption restrictions.

Interests in real estate.  Investments in real estate represent interests in several limited partnerships, which invest in various real estate properties. They are valued using various methodologies including independent third party appraisals. For some investments, little market activity may exist and determination of fair value is then based on the best information available in the circumstances. This involves a significant degree of judgment by taking into consideration a combination of internal and external factors. Based on the above factors, interests in real estate are classified within the Level 3 valuation hierarchy. Certain interests in real estate are subject to liquidity redemption restrictions.

The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. Furthermore, while the Company believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date. The inputs or methodologies used for valuing investments are not necessarily an indication of the risk associated with investing in those investments.

The following tables present the fair value of assets in the Master Trust by asset category and by fair value hierarchy:

	December 31, 2011
	Level 1		Level 2		Level 3		Total
	(Dollars in millions)
U.S. equity securities	$	—	$	340.4	$	—	$	340.4
International equity securities	—		107.8		—		107.8
Mortgage-backed debt securities	—		98.9		—		98.9
U.S. debt securities	—		83.3		—		83.3
International debt securities	—		32.0		—		32.0
Corporate debt securities	—		45.8		—		45.8
Short-term investments	—		36.1		—		36.1
Interests in real estate	—		—		25.3		25.3
Total assets at fair value	$	—	$	744.3	$	25.3	$	769.6

	December 31, 2010
	Level 1		Level 2		Level 3		Total
	(Dollars in millions)
U.S. equity securities	$	82.6	$	250.5	$	—	$	333.1
International equity securities	—		118.9		—		118.9
Mortgage-backed debt securities	—		108.8		—		108.8
U.S. debt securities	—		60.2		—		60.2
International debt securities	—		25.7		—		25.7
Corporate debt securities	—		46.1		—		46.1
Short-term investments	—		31.1		—		31.1
Interests in real estate	—		—		47.7		47.7
Total assets at fair value	$	82.6	$	641.3	$	47.7	$	771.6

F - 44

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The table below sets forth a summary of changes in the fair value of the Master Trust’s Level 3 investments:

	Year Ended December 31,
	2011			2010
	(Dollars in millions)
Beginning of year	$	47.7		$	47.4
Assets held at the reporting date:
Realized losses	(8.9		)	(0.1		)
Unrealized gains, net	11.4			1.3
Purchases, sales and settlements, net	(24.9		)	(0.9		)
End of year	$	25.3		$	47.7

Contributions

Annual contributions to the qualified plans are made in accordance with minimum funding standards and the Company's agreement with the Pension Benefit Guaranty Corporation (PBGC). Funding decisions also consider certain funded status thresholds defined by the Pension Protection Act of 2006 (generally 80%). As of December 31, 2011, the Company’s qualified plans are expected to be at or above the Pension Protection Act thresholds and will therefore avoid benefit restrictions and at-risk penalties for 2012. The Company intends to contribute the necessary amount needed to maintain these funded status thresholds during 2012.

Estimated Future Benefit Payments

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid by the Master Trust:

	Pension Benefits
	(Dollars in millions)
2012	$	56.7
2013	58.0
2014	59.8
2015	61.8
2016	63.6
Years 2017-2021	333.3

Defined Contribution Plans

The Company sponsors employee retirement accounts under three 401(k) plans for eligible U.S. employees. The Company matches voluntary contributions to each plan up to specified levels. The expense for these plans was $54.5 million, $51.3 million and $47.9 million for the years ended December 31, 2011, 2010 and 2009, respectively. A performance contribution feature in one of the plans allows for additional contributions from the Company based upon meeting specified Company performance targets. Performance contributions related to the years ended December 31, 2011, 2010 and 2009 were $22.5 million, $20.6 million and $20.3 million, respectively.

F - 45

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(16) Stockholders’ Equity

Common Stock

The Company has 800.0 million authorized shares of $0.01 par value common stock. Holders of common stock are entitled to one vote per share on all matters to be voted upon by the stockholders and vote together, as one class, with the holders of the Company’s Series A Junior Participating Preferred Stock, if any such shares were issued and outstanding. The holders of common stock do not have cumulative voting rights in the election of directors. Holders of common stock are entitled to ratably receive dividends if, as and when dividends are declared from time to time by the Company’s Board of Directors out of funds legally available for that purpose, after payment of dividends required to be paid on outstanding preferred stock or series common stock, as described below. Upon liquidation, dissolution or winding up, any business combination or a sale or disposition of all or substantially all of the assets, the holders of common stock are entitled to ratably receive the assets available for distribution to the stockholders after payment of liabilities and accrued but unpaid dividends and liquidation preferences on any outstanding preferred stock or series common stock. The common stock has no preemptive or conversion rights and is not subject to further calls or assessment by the Company. There are no redemption or sinking fund provisions applicable to the common stock.

The following table summarizes common stock activity from January 1, 2009 to December 31, 2011:

	2011		2010		2009
Shares outstanding at the beginning of the year	270.2		268.2		266.6
Stock options exercised	0.3		1.5		0.5
Stock grants to employees	0.7		0.6		0.8
Employee stock purchases	0.2		0.2		0.4
Shares relinquished	(0.3	)	(0.3	)	(0.1	)
Shares outstanding at the end of the year	271.1		270.2		268.2

Preferred Stock and Series Common Stock

The Board of Directors is authorized to issue up to 10.0 million shares of preferred stock and up to 40.0 million shares of series common stock, both with a $0.01 per share par value. The Board of Directors can determine the terms and rights of each series, whether dividends (if any) will be cumulative or non-cumulative and the dividend rate of the series, redemption or sinking fund provisions, conversion terms, prices and rates, and amounts payable on shares of the series in the event of any voluntary or involuntary liquidation, dissolution or winding up of the affairs of the Company. The Board of Directors may also determine restrictions on the issuance of shares of the same series or of any other class or series, and the voting rights (if any) of the holders of the series. There were no outstanding shares of preferred stock or series common stock as of December 31, 2011.

F - 46

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Perpetual Preferred Stock

As discussed in Note 11, the Company had $732.5 million aggregate principal amount of Debentures outstanding as of December 31, 2011. Perpetual preferred stock issued upon a conversion of the Debentures will be fully paid and non-assessable, and holders will have no preemptive or preferential right to purchase any of the Company’s other securities. The perpetual preferred stock has a liquidation preference of $1,000 per share, is not convertible and is redeemable at the Company’s option at any time at a cash redemption price per share equal to the liquidation preference plus any accumulated dividends. Holders are entitled to receive cumulative dividends at an annual rate of 3.0875% if and when declared by the Company’s Board of Directors. If the Company fails to pay dividends on the perpetual preferred stock for five years, or upon the occurrence of a mandatory trigger event, as defined in the certificate of designations governing the perpetual preferred stock, the Company generally must sell warrants or preferred stock with specified characteristics and use the funds from that sale to pay accumulated dividends after the payment in full of any deferred interest on the Debentures, subject to certain limitations. In the event of a mandatory trigger event, the Company may not declare dividends on the perpetual preferred stock other than those funded through the sale of warrants or preferred stock as described above. Any deferred interest on the Debentures at the time of notice of conversion will be reflected as accumulated dividends on the perpetual preferred stock at issuance. Additionally, holders of the perpetual preferred stock are entitled to elect two additional members to serve on the Company’s Board of Directors if (i) prior to any remarketing of the perpetual preferred stock, the Company fails to declare and pay dividends with respect to the perpetual stock for 10 consecutive years or (ii) after any successful remarketing or any final failed remarketing of the perpetual preferred stock, the Company fails to declare and pay six dividends thereon, whether or not consecutive. The perpetual preferred stock may be remarketed at the holder’s election after December 15, 2046 or earlier, upon the first occurrence of a change of control if the Company does not redeem the perpetual preferred stock. There were no outstanding shares of perpetual preferred stock as of December 31, 2011.

Preferred Share Purchase Rights Plan and Series A Junior Participating Preferred Stock

Each outstanding share of common stock, par value $0.01 per share, of the Company carries one preferred share purchase right (a Right). The Rights are governed by a plan that expires in August 2012.

The Rights have certain anti-takeover effects. The Rights will cause substantial dilution to a person or group that attempts to acquire the Company on terms not approved by the Company’s Board of Directors, except pursuant to any offer conditioned on a substantial number of Rights being acquired. The Rights should not interfere with any merger or other business combination approved by the Board of Directors since the Rights may be redeemed by the Company at a redemption price of $0.001 per Right prior to the time that a person or group has acquired beneficial ownership of 15% or more of the common stock of the Company. In addition, the Board of Directors is authorized to reduce the 15% threshold to not less than 10%.

Each Right entitles the holder to purchase one quarter of one-hundredth of a share of Series A Junior Participating Preferred Stock from the Company at an exercise price of $27.50, which in turn provides rights to receive the number of common stock shares having a market value of two times the exercise price of the Right. The Right is exercisable only if a person or group acquires 15% or more of the Company’s common stock. The Board of Directors is authorized to issue up to 1.5 million shares of Series A Junior Participating Preferred Stock. There were no outstanding shares of Series A Junior Participating Preferred Stock as of December 31, 2011.

Treasury Stock

Share repurchase program.  The Company has a share repurchase program for its common stock with an authorized amount of $1.0 billion in which repurchases may be made from time to time based on an evaluation of the Company’s outlook and general business conditions, as well as alternative investment and debt repayment options. The Company’s Chairman and Chief Executive Officer also has authority to direct the Company to repurchase up to $100.0 million of common stock outside the share repurchase program. The share repurchase program does not have an expiration date and may be discontinued at any time. Through December 31, 2011, the Company made repurchases of 7.7 million shares at a cost of $299.6 million ($199.8 million in 2008 and $99.8 million in 2006), leaving $700.4 million available under the share repurchase program.

Shares relinquished.  The Company allows employees to relinquish common stock to pay estimated taxes upon the payout of performance units that are settled in common stock and the vesting of restricted stock. The amount of common stock shares relinquished were 311,709 for the year ended December 31, 2011 and 268,308 for the year ended December 31, 2010. The value of the common stock tendered by employees was based upon the closing price on the dates of the respective transactions.

F - 47

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(17) Share-Based Compensation

The Company has an equity incentive plan for employees and non-employee directors that allows for the issuance of share-based compensation in the form of stock appreciation rights, restricted stock, performance awards, incentive stock options, nonqualified stock options and deferred stock units. The plan made 14.0 million shares of the Company’s common stock available for grant, with 13.8 million shares available for grant as of December 31, 2011. The Company has two employee stock purchase plans that provide for the purchase of up to 6.0 million shares of the Company’s common stock, with 5.0 million shares authorized for purchase by U.S. employees and 1.0 million shares authorized for purchase by Australian employees.

Share-Based Compensation Expense and Cash Flows

The Company’s share-based compensation expense is recorded in “Selling and administrative expenses” in the consolidated statements of income. The cash received by the Company upon the exercise of stock options and when employees purchase stock under the employee stock purchase plans is reflected as a financing activity in the consolidated statements of cash flows. Share-based compensation expense and cash flow amounts were as follows:

	Year Ended December 31,
	2011		2010		2009
	(Dollars in millions)
Share-based compensation expense	$	43.9	$	41.1	$	38.8
Tax benefit	16.3		15.4		15.0
Share-based compensation expense, net of tax benefit	27.6		25.7		23.8
Cash received upon the exercise of stock options and from employee stock purchases	11.1		22.2		8.7
Excess tax benefits related to share-based compensation	8.1		51.0		—

As of December 31, 2011, the total unrecognized compensation cost related to nonvested awards was $30.3 million, net of taxes, which is expected to be recognized over 3.0 years with a weighted-average period of 0.8 years.

Deferred Stock Units

In 2011, 2010 and 2009, the Company granted deferred stock units to each of its non-employee directors. The fair value of these units is equal to the market price of the Company’s common stock at the date of grant. These deferred stock units generally vest after one year and are settled in common stock on the specified distribution date elected by each non-employee director. Beginning in 2011, non-employee directors were also given the option to receive their total annual cash retainer in the form of additional deferred stock units (based on the fair market value of the Company's common stock on the date of grant). The additional grant of deferred stock units is subject to the same grant timing, vesting and distribution date elections as the annual equity compensation grant.

Restricted Stock Awards

The primary share-based compensation tool used by the Company for its employee base is through awards of restricted stock. The majority of restricted stock awards are granted in January of each year with a lesser portion granted in the first month of the subsequent three quarters. Awards generally cliff vest after three years of service and only contain a service condition, with compensation cost recognized on a straight-line basis over the requisite service period, net of estimated forfeitures. For awards with service and performance conditions, the Company recognizes compensation cost using the graded-vesting method, net of estimated forfeitures. The fair value of restricted stock is equal to the market price of the Company’s common stock at the date of grant.

F - 48

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

A summary of restricted stock award activity is as follows:

	Year Ended December 31, 2011		Weighted Average Grant-Date Fair Value
Nonvested at December 31, 2010	1,894,299		$	39.32
Granted	618,124		59.63
Vested	(849,464	)	42.38
Forfeited	(131,867	)	47.10
Nonvested at December 31, 2011	1,531,092		$	45.16

The total fair value of restricted stock awards granted during the years ended December 31, 2011, 2010 and 2009, was $36.9 million, $23.3 million and $23.1 million, respectively. The total fair value of restricted stock awards vested during the years ended December 31, 2011, 2010 and 2009, was $50.0 million, $20.5 million and $11.2 million, respectively.

Stock Options

Over the past few years, the Company’s stock option awards have been primarily limited to senior management personnel. All stock options are granted at an exercise price equal to the market price of the Company’s common stock at the date of grant. Stock options generally vest in one-third increments over a period of three years or cliff vest after three years, and expire after 10 years from the date of grant. Expense is recognized ratably over the vesting period, net of estimated forfeitures. Option grants are typically made in January of each year or upon hire for eligible plan participants.

The Company used the Black-Scholes option pricing model to determine the fair value of stock options. The Company utilized U.S. Treasury yields as of the grant date for its risk-free interest rate assumption, matching the U.S. Treasury yield terms to the expected life of the option. The Company utilized historical company data to develop its dividend yield, expected volatility and expected option life assumptions.

A summary of outstanding option activity under the plans is as follows:

	Year Ended December 31, 2011		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life	Aggregate Intrinsic Value (in millions)
Options Outstanding at December 31, 2010	1,916,301		$	32.25	5.9	$	61.2
Granted	223,307		64.52
Exercised	(254,828	)	18.57
Forfeited	—		—
Options Outstanding at December 31, 2011	1,884,780		$	37.92	5.6	$	11.0
Vested and Exercisable	1,301,607		$	32.53	4.5	$	10.0

During the years ended December 31, 2011, 2010 and 2009, the total intrinsic value of options exercised, defined as the excess fair value of the underlying stock over the exercise price of the options, was $10.3 million, $53.7 million and $14.7 million, respectively. The weighted-average fair values of the Company’s stock options and the assumptions used in applying the Black-Scholes option pricing model were as follows:

	Year Ended December 31,
	2011			2010			2009
Weighted-average fair value	$	33.92		$	25.70		$	26.84
Risk-free interest rate	2.0		%	2.8		%	1.5		%
Expected option life	5.0 years			5.0 years			5.0 years
Expected volatility	64		%	64		%	60		%
Dividend yield	0.6		%	0.6		%	0.9		%

F - 49

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Performance Units

Performance units are typically granted annually in January and vest over a three-year measurement period and are primarily limited to senior management personnel. The performance units are usually subject to the achievement of two goals, 50% based on three-year stock price performance compared to both an industry peer group and a S&P index (market condition) and 50% based on a three-year return on capital target (performance condition). The performance units granted in 2011 are subject to the achievement of the performance and market conditions, while the 2010 and 2009 units granted are only subject to the achievement of the market condition. Three performance unit grants are outstanding for any given year. The payouts related to all active grants will be settled in the Company’s common stock.

A summary of performance unit activity is as follows:

	Year Ended December 31, 2011		Weighted Average Remaining Contractual Life
Nonvested at December 31, 2010	386,662		1.5
Granted	122,590
Forfeited	—
Vested	(248,263	)
Nonvested at December 31, 2011	260,989		1.5

As of December 31, 2011, there were 248,263 performance units vested that had an aggregate intrinsic value of $12.4 million and a conversion price per share of $34.37.

The performance condition awards were valued utilizing the grant date fair values of the Company’s stock adjusted for dividends foregone during the vesting period. The market condition awards were valued utilizing a Monte Carlo simulation which incorporates the total stockholder return hurdles set for each grant. The assumptions used in the valuations for grants were as follows:

	Year Ended December 31,
	2011		2010		2009
Risk-free interest rate	1.0	%	1.7	%	1.3	%
Expected volatility	64	%	64	%	60	%
Dividend yield	0.6	%	0.6	%	0.9	%

Employee Stock Purchase Plans

The Company’s eligible full-time and part-time employees are able to contribute up to 15% of their base compensation into the employee stock purchase plans, subject to a limit of $25,000 per person per year. Employees are able to purchase Company common stock at a 15% discount to the lower of the fair market value of the Company’s common stock on the initial or final trading dates of each six-month offering period. Offering periods begin on January 1 and July 1 of each year. The Company uses the Black-Scholes option pricing model to determine the fair value of employee stock purchase plan share-based payments. The fair value of the six-month “look-back” option in the Company’s employee stock purchase plans is estimated by adding the fair value of 0.15 of one share of stock to the fair value of 0.85 of an option on one share of stock. The Company utilized U.S. Treasury yields as of the grant date for its risk-free interest rate assumption, matching the Treasury yield terms to the six-month offering period. The Company utilized historical company data to develop its dividend yield and expected volatility assumptions.

Shares purchased under the plans were 0.2 million for the year ended December 31, 2011, 0.2 million for the year ended December 31, 2010 and 0.4 million for the year ended December 31, 2009.

F - 50

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(18) Accumulated Other Comprehensive Income (Loss)

The following table sets forth the after-tax components of comprehensive income (loss):

	Foreign Currency Translation Adjustment		Net Actuarial Loss Associated with Postretirement Plans and Workers’ Compensation Obligations			Prior Service Cost Associated with Postretirement Plans			Cash Flow Hedges			Available-For-Sale Securities			Total Accumulated Other Comprehensive Loss
	(Dollars in millions)
December 31, 2008	$	3.1	$	(220.4	)	$	(18.7	)	$	(152.5	)	$	—		$	(388.5	)
Net change in fair value	—		—			—			235.2			—			235.2
Reclassification from other comprehensive income to earnings	—		11.8			1.8			84.6			—			98.2
Current period change	—		(134.9		)	6.5			—			—			(128.4		)
December 31, 2009	3.1		(343.5		)	(10.4		)	167.3			—			(183.5		)
Net change in fair value	—		—			—			229.9			—			229.9
Reclassification from other comprehensive income to earnings	—		31.8			2.5			(102.4		)	—			(68.1		)
Current period change	—		(41.3		)	(4.9		)	—			—			(46.2		)
December 31, 2010	3.1		(353.0		)	(12.8		)	294.8			—			(67.9		)
Net change in fair value	—		—			—			291.9			(5.8		)	286.1
Reclassification from other comprehensive income to earnings	—		38.2			2.3			(251.0		)	(0.9		)	(211.4		)
Current period change	—		(150.1		)	0.9			—			—			(149.2		)
December 31, 2011	$	3.1	$	(464.9	)	$	(9.6	)	$	335.7		$	(6.7	)	$	(142.4	)

Comprehensive income (loss) differs from net income by the amount of unrealized gain or loss resulting from valuation changes of the Company’s cash flow hedges (see Note 6 and Note 7 for information related to the Company’s cash flow hedges), changes in the fair value of available-for-sale securities (see Note 5 for information related to the Company's investments in available-for-sale securities) and the change in actuarial loss and prior service cost during the periods. The values of the Company’s cash flow hedging instruments are primarily affected by changes in diesel fuel and coal prices, and the U.S. dollar/Australian dollar exchange rate.

(19) Resource Management and Other Commercial Events

In 2011, the Company exchanged coal reserves in Kentucky and coal reserves and surface lands in Illinois for coal reserves in West Virginia. Based on the fair value of the coal reserves received, the Company recognized a $37.7 million gain on the exchange. Fair value was determined by using a discounted cash flow model that included assumptions for future coal sales prices, operating costs and the discount rate. This non-cash transaction was excluded from the investing section of the condensed consolidated statement of cash flows. In 2010, the Company recognized gains of $23.7 million on similar transactions.

In 2011, the Company recognized income associated with the receipt of a $14.6 million project development fee related to its involvement in the Prairie State Energy Campus (Prairie State), a 1,600 megawatt coal-fueled electricity generation project.

In 2011, the Company sold non-strategic coal reserves and surface lands located in Kentucky and Illinois for $24.9 million of cash proceeds and notes receivable totaling $17.4 million and recognized a gain of $31.7 million. The non-cash portion of these transactions were excluded from the investing section of the consolidated statement of cash flows.

F - 51

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(20) Earnings per Share (EPS)

Basic and diluted EPS are computed using the two-class method, which is an earnings allocation that determines EPS for each class of common stock and participating securities according to dividends declared and participation rights in undistributed earnings. The Company’s restricted stock awards are considered participating securities because holders are entitled to receive non-forfeitable dividends during the vesting term. Diluted EPS includes securities that could potentially dilute basic EPS during a reporting period, for which the Company includes the Debentures and share-based compensation awards.

A conversion of the Debentures may result in payment for any conversion value in excess of the principal amount of the Debentures in the Company’s common stock. For diluted EPS purposes, potential common stock is calculated based on whether the market price of the Company’s common stock at the end of each reporting period is in excess of the conversion price of the Debentures. For a full discussion of the conditions under which the Debentures may be converted, the conversion rate to common stock and the conversion price, see Note 11.

For all but the performance units, the potentially dilutive impact of the Company’s share-based compensation awards is determined using the treasury stock method. Under the treasury stock method, awards are treated as if they had been exercised with any proceeds used to repurchase common stock at the average market price during the period. Any incremental difference between the assumed number of shares issued and purchased is included in the diluted share computation. For the Company’s other share-based compensation awards, performance units, their contingent features result in an assessment for any potentially dilutive common stock by using the end of the reporting period as if it were the end of the contingency period for all units granted. For a full discussion of the Company’s share-based compensation awards, see Note 17.

The computation of diluted EPS excludes anti-dilutive shares of approximately 0.2 million for the years ended December 31, 2011, 2010 and 2009. These anti-dilutive shares were due to certain share-based compensation awards calculated under the treasury stock method. This anti-dilution generally occurs where the exercise prices are higher than the average market value of the Company’s stock price during the applicable period.

F - 52

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following illustrates the earnings allocation method utilized in the calculation of basic and diluted EPS.

	Year Ended December 31,
	2011			2010			2009
	(In millions, except per share amounts)
EPS numerator:
Income from continuing operations, net of income taxes	$	1,010.5		$	826.6		$	443.2
Less: Net (loss) income attributable to noncontrolling interests	(11.4		)	28.2			14.8
Income from continuing operations attributable to common stockholders before allocation of earnings to participating securities	1,021.9			798.4			428.4
Less: Earnings allocated to participating securities	(5.3		)	(5.6		)	(2.9		)
Income from continuing operations attributable to common stockholders, after earnings allocated to participating securities(1)	1,016.6			792.8			425.5
(Loss) income from discontinued operations, net of income taxes	(64.2		)	(24.4		)	19.8
Net income attributable to common stockholders, after earnings allocated to participating securities(1)	$	952.4		$	768.4		$	445.3
EPS denominator:
Weighted average shares outstanding — basic	269.1			267.0			265.5
Impact of dilutive securities	1.2			2.9			2.0
Weighted average shares outstanding — diluted	270.3			269.9			267.5
Basic EPS attributable to common stockholders:
Income from continuing operations	$	3.77		$	2.97		$	1.60
(Loss) income from discontinued operations	(0.24		)	(0.09		)	0.08
Net income attributable to common stockholders	$	3.53		$	2.88		$	1.68
Diluted EPS attributable to common stockholders:
Income from continuing operations	$	3.76		$	2.93		$	1.59
(Loss) income from discontinued operations	(0.24		)	(0.09		)	0.07
Net income attributable to common stockholders	$	3.52		$	2.84		$	1.66

⁽¹⁾  The reallocation adjustment for participating securities to arrive at the numerator used to calculate diluted EPS was less than $0.1 million for the periods presented.

(21)     Management — Labor Relations

As of December 31, 2011, the Company had approximately 8,300 employees, which included approximately 5,600 hourly employees. As of December 31, 2011, approximately 24% of the Company’s hourly employees were represented by organized labor unions and generated 7% of its 2011 coal production.  In the U.S., two of the Company's mines were represented by organized labor unions. In Australia, the coal mining industry is unionized and the majority of workers employed at the Company’s Australian Mining operations are members of trade unions. The Construction Forestry Mining and Energy Union represents the Company’s Australian subsidiaries’ hourly production and engineering employees, including those employed through contract mining relationships. The Company could experience labor disputes, work stoppages or other disruptions in production that could negatively impact the Company’s profitability. The following table below presents the Company's operations in which the employees are represented by organized labor unions.

F - 53

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Mine	Current Agreement Expiration Date
U. S.
Willow Lake (1)	-
Kayenta (2)	September 2013
Australia
Owner-operated mines:
North Goonyella (3)	March 2012
North Wambo Underground (3)	April 2012
Wilkie Creek (4)	March 2013
Metropolitan	June 2013
Coppabella	July 2013
Wambo Coal Handling Plant	October 2014
Contractor-operated mines:
Burton (3)	February 2012
Wilpinjong	August 2012
Millennium	September 2012
Moorvale	October 2012
Eaglefield	June 2014
Wambo Open-Cut	August 2014

⁽¹⁾ The labor agreement for the hourly workers at the Company’s Willow Lake Mine in Illinois expired in April 2011. The mine continues to operate without a contract. This agreement covers approximately 9% of the Company’s U.S. subsidiaries’ hourly employees, who generated approximately 1% of the Company’s U.S. production during the year ended December 31, 2011.

⁽²⁾ Hourly workers at the Company’s 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 the Company’s U.S. subsidiaries’ hourly employees, who generated 4% of the Company’s U.S. production during the year ended December 31, 2011.

⁽³⁾ Negotiations for the North Goonyella, North Wambo Underground and Burton mines are underway.

⁽⁴⁾ The Wilkie Creek Mine was held for sale as of December 31, 2011.

(22) Financial Instruments and Guarantees With Off-Balance-Sheet Risk

In the normal course of business, the Company is a party to guarantees and financial instruments with off-balance-sheet risk, which are not reflected in the accompanying consolidated balance sheets. Such financial instruments are valued based on the amount of exposure under the instrument and the likelihood of required performance. In the Company’s past experience, virtually no claims have been made against these financial instruments. Management does not expect any material losses to result from these guarantees or off-balance-sheet instruments.

F - 54

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Financial Instruments with Off-Balance Sheet Risk

As of December 31, 2011, the Company had the following financial instruments with off-balance sheet risk:

	Reclamation Obligations		Lease Obligations		Workers’ Compensation Obligations		Other(1)		Total
	(Dollars in millions)
Self bonding	$	929.6	$	—	$	—	$	—	$	929.6
Surety bonds	613.2		104.7		13.5		11.0		742.4
Bank guarantees	178.4		—		—		211.2		389.6
Letters of credit	—		—		62.6		20.0		82.6
Bilateral cash collateralization agreements	—		—		—		79.7		79.7
	$	1,721.2	$	104.7	$	76.1	$	321.9	$	2,223.9

⁽¹⁾  Other includes bilateral cash collateralization agreement obligations described below and an additional $242.2 million in bank guarantees, letters of credit and surety bonds related to collateral for surety companies, road maintenance, performance guarantees and other operations.

The Company owns a 37.5% interest in Dominion Terminal Associates, a partnership that operates a coal export terminal in Newport News, Virginia under a 30-year lease that permits the partnership to purchase the terminal at the end of the lease term for a nominal amount. The partners have severally (but not jointly) agreed to make payments under various agreements which in the aggregate provide the partnership with sufficient funds to pay rents and to cover the principal and interest payments on the floating-rate industrial revenue bonds issued by the Peninsula Ports Authority, and which are supported by letters of credit from a commercial bank. As of December 31, 2011, the Company’s maximum reimbursement obligation to the commercial bank was in turn supported by four letters of credit totaling $42.7 million. The Company has a bilateral cash collateralization agreement for these letters of credit whereby the Company posted cash collateral in lieu of utilizing its Credit Facility. Such cash collateral is classified within "Cash and cash equivalents" given the Company has the ability to substitute letters of credit at any time for this cash collateral and it is, therefore, readily available to the Company.

The Company is party to an agreement with the PBGC and TXU Europe Limited, an affiliate of the Company’s former parent corporation, under which the Company is required to make special contributions to two of the Company’s defined benefit pension plans and to maintain a $37.0 million letter of credit in favor of the PBGC. If the Company or the PBGC gives notice of an intent to terminate one or more of the covered pension plans in which liabilities are not fully funded, or if the Company fails to maintain the letter of credit, the PBGC may draw down on the letter of credit and use the proceeds to satisfy liabilities under the Employee Retirement Income Security Act of 1974, as amended. The PBGC, however, is required to first apply amounts received from a $110.0 million guarantee in place from TXU Europe Limited in favor of the PBGC before it draws on the Company’s letter of credit. The Company has a bilateral cash collateralization agreement for this letter of credit whereby the Company posted cash collateral in lieu of utilizing its Credit Facility. Such cash collateral is classified within "Cash and cash equivalents" given the Company has the ability to substitute letters of credit at any time for this cash collateral and it is therefore readily available to the Company. On November 19, 2002, TXU Europe Limited was placed under the administration process in the United Kingdom (a process similar to bankruptcy proceedings in the U.S.) and continues under this process as of December 31, 2011. As a result of these proceedings, TXU Europe Limited may be liquidated or otherwise reorganized in such a way as to relieve it of its obligations under its guarantee.

Accounts Receivable Securitization

The Company has an accounts receivable securitization program (securitization program) with a maximum capacity of $275.0 million through its wholly-owned, bankruptcy-remote subsidiary (Seller). At December 31, 2011, the Company had $41.7 million available under the securitization program, net of outstanding letters of credit and amounts drawn. Under the securitization program, the Company contributes, on a revolving basis, trade receivables of most of the Company’s U.S. subsidiaries to the Seller, which then sells the receivables in their entirety to a consortium of unaffiliated asset-backed commercial paper conduits (the Conduits). After the sale, the Company, as servicer of the assets, collects the receivables on behalf of the Conduits for a nominal servicing fee. The Company utilizes proceeds from the sale of its accounts receivable as an alternative to short-term borrowings under its Credit Facility, effectively managing its overall borrowing costs and providing an additional source for working capital. The current securitization program extends to May 2012, while the letter of credit commitment that supports the commercial paper facility underlying the securitization program must be renewed annually.

F - 55

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Seller is a separate legal entity whose assets are available first and foremost to satisfy the claims of its creditors. Of the receivables sold to the Conduits, a portion of the amount due to the Seller is deferred until the ultimate collection of the underlying receivables. During the year ended December 31, 2011, the Company received total consideration of $4,633.4 million related to accounts receivable sold under the securitization program, including $3,462.7 million of cash up front from the sale of the receivables, an additional $1,004.8 million of cash upon the collection of the underlying receivables, and $165.9 million that had not been collected at December 31, 2011 and was recorded at fair value which approximates carrying value. The reduction in accounts receivable as a result of securitization activity with the Conduits was $150.0 million at December 31, 2011 and $150.0 million at December 31, 2010.

The securitization activity has been reflected in the consolidated statements of cash flows as operating activity because both the cash received from the Conduits upon sale of receivables as well as the cash received from the Conduits upon the ultimate collection of receivables are not subject to significantly different risks given the short-term nature of the Company’s trade receivables. The Company recorded expense associated with securitization transactions of $2.0 million, $2.4 million and $4.0 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Other

The Company is the lessee under numerous equipment and property leases. It is common in such commercial lease transactions for the Company, as the lessee, to agree to indemnify the lessor for the value of the property or equipment leased, should the property be damaged or lost during the course of the Company’s operations. The Company expects that losses with respect to leased property would be covered by insurance (subject to deductibles). The Company and certain of its subsidiaries have guaranteed other subsidiaries’ performance under their various lease obligations. Aside from indemnification of the lessor for the value of the property leased, the Company’s maximum potential obligations under its leases are equal to the respective future minimum lease payments, and the Company assumes that no amounts could be recovered from third parties.

In connection with the development of Prairie State, each owner, including one of the Company’s subsidiaries, has issued a guarantee for its proportionate share (5.06% for the Company) of the construction costs under an agreement with Bechtel Power Corporation.

The Company has provided financial guarantees under certain long-term debt agreements entered into by its subsidiaries, and substantially all of the Company’s subsidiaries provide financial guarantees under long-term debt agreements entered into by the Company. The maximum amounts payable under the Company’s debt agreements are equal to the respective principal and interest payments.

(23) Commitments and Contingencies

Commitments

As of December 31, 2011, purchase commitments for capital expenditures were $1,313.0 million, all of which is obligated within the next three years, with $743.6 million obligated in the next year. The purchase commitments for capital expenditures represent an increase of $854.8 million over amounts committed as of December 31, 2010 and primarily relate to new mines and expansion and extension projects in Australia and the U.S. Commitments made for expenditures under coal leases are reflected in Note 12. The Company also has various long- and short-term take or pay arrangements associated with rail and port commitments in Australia for the delivery of coal including amounts relating to export facilities. As of December 31, 2011, these commitments totaled $4,547.6 million with $1,644.0 million obligated within the next four years, of which $443.1 million was obligated within the next year. During 2011, the Company recognized approximately $284 million of expense, reflected in “Operating costs and expenses” in the consolidated statements of income, related to these take or pay arrangements.

A subsidiary of the Company owns a 5.06% undivided interest in Prairie State. The Company invested $36.2 million, $76.0 million and $56.8 million during the years ended December 31, 2011, 2010 and 2009, respectively, representing its 5.06% share of the construction costs for those periods. Included in “Investments and other assets” in the consolidated balance sheets as of December 31, 2011 and December 31, 2010, are costs of $238.7 million and $202.5 million, respectively. The Company’s share of total construction costs for Prairie State is expected to be approximately $250 million with the remaining funding expected in 2012.

F - 56

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Contingencies

From time to time, the Company or its subsidiaries are involved in legal proceedings arising in the ordinary course of business or related to indemnities or historical operations. The Company believes it has recorded adequate reserves for these liabilities and that there is no individual case pending that is likely to have a material adverse effect on the Company’s financial condition, results of operations or cash flows. The Company discusses its significant legal proceedings below.

Litigation Relating to Continuing Operations

Navajo Nation Litigation.  On June 18, 1999, the Navajo Nation served three of the Company’s 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 which alleged that the defendants jointly participated in unlawful activity to obtain favorable coal lease amendments. The plaintiff sought actual and punitive damages and the termination and reformation of two coal leases. The court allowed the Hopi Tribe to intervene in this lawsuit, and the Hopi Tribe sought unspecified actual and punitive damages and reformation of its coal lease. One of the Company’s subsidiaries named as a defendant is now a subsidiary of Patriot. However, the Company is responsible for this litigation under the Separation Agreement entered into with Patriot in connection with the spin-off.

In October 2010, the Company's subsidiaries and the other defendants settled the Hopi claims, and the court dismissed those claims. In August 2011, the Company's subsidiaries and other defendants settled the Navajo claims, and agreed to dismiss all of the pending litigation with prejudice. In connection with this settlement, the Company recorded a provision totaling $24.5 million in 2011. The court has dismissed this lawsuit, and this matter has concluded.

Gulf Power Company Litigation.  On June 22, 2006, Gulf Power Company (Gulf Power) filed a breach of contract lawsuit against a Company subsidiary in the U.S. District Court, Northern District of Florida, contesting the force majeure declaration by the Company’s subsidiary under a coal supply agreement with Gulf Power and seeking damages for alleged past and future tonnage shortfalls of nearly five million tons under the agreement, which expired on December 31, 2007. On June 30, 2009, the court granted Gulf Power’s motion for partial summary judgment on liability and denied the Company subsidiary’s motion for summary judgment. On September 30, 2010, the court entered its order on damages, awarding Gulf Power zero dollars in damages and the Company subsidiary its costs to defend the lawsuit. On November 1, 2010, Gulf Power filed a motion to alter or amend the judgment, contesting the trial court’s damages order, to which the Company subsidiary objected. The court entered an order on July 29, 2011 that affirmed its September 30, 2010 decision in all respects except for 2007 cover coal purchases and granted in part Gulf Power's motion to alter judgment with respect to 2007 cover coal purchases. On September 30, 2011, the court entered an order awarding Gulf Power damages in the the amount of $20.5 million for its 2007 cover coal purchases. On January 19, 2012, the court entered its order awarding Gulf Power prejudgment interest in the amount of $6.9 million plus post-judgment interest. The Company's subsidiary has filed its notice of appeal. Based on the Company's evaluation of information currently available concerning the issues and their potential impact, the Company believes that its subsidiary will be successful in the liability appeals process and, therefore, no liability has been recorded at this time.

Monto Coal Pty Limited, Monto Coal 2 Pty Ltd Limited and Macarthur Coal Limited. In October 2007, a statement of claim was delivered to Monto Coal Pty Ltd, a wholly owned subsidiary of Macarthur, and Monto Coal 2 Pty Ltd, an equity accounted investee, from the minority interest holders in the Monto Coal joint venture, alleging that Monto Coal 2 Pty Ltd breached the Monto Coal Joint Venture Agreement and Monto Coal Pty Ltd breached the Monto Coal Management Agreement. Monto Coal Pty Ltd is the manager of the Monto Coal joint venture pursuant to the Management Agreement. Monto Coal 2 Pty Ltd holds a 51% interest in the Monto Coal Joint Venture. The plaintiffs are Sanrus Pty ltd, Edge Developments Pty Ltd and H&J Enterprises (Qld) Pty Ltd. An additional statement of claim was delivered to Macarthur in November 2010 from the same minority interest holders in the Monto Coal Joint Venture, alleging that Macarthur induced Monto Coal 2 Pty Ltd and Monto Coal Pty Ltd to breach the Monto Coal Joint Venture Agreement and the Monto Coal Management Agreement, respectively. These actions, which are pending before the Supreme Court of Queensland, Australia, seek damages from the three defendants collectively of no less than $1,193.2 million Australian dollars plus interest and costs. The defendants dispute the claims and are vigorously defending their positions. Based on the Company's evaluation of the issues and their potential impact, the amount of any future loss cannot be reasonably estimated. However, based on current information, the Company believes these claims are likely to be finalized without a material adverse effect on its financial condition, results of operations or cash flows.

F - 57

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

MCG Coal Holdings Pty Ltd. In 2010, Macarthur loaned $360.0 million (Australian dollars) to MCG Coal Holdings Pty Ltd (MCG). The loan from Macarthur was based on an entitlement for Macarthur to convert the loan into a 90% interest in MCG, the indirect holder of a mineral development licence (MDL 162) that was acquired with the proceeds of the loan. MCG and two associated companies (MCG Coal Pty Ltd and Fortrus Resources Pty Ltd) refused to take the steps necessary to enable Macarthur to convert the loan into equity. Macarthur and its nominee, Macarthur Berrigurra Pty Ltd, commenced an action on May 24, 2011 in the Supreme Court of Queensland, Australia, to require MCG and the two associated companies to complete the conversion. On January 30, 2012, the court ordered that all parties perform the steps required to enable Macarthur to convert the loan to equity and that Macarthur's court costs be paid. Macarthur, through its nominee Macarthur Berrigurra, now holds its equity interest in MCG.

Claims and Litigation Relating to Indemnities or Historical Operations

Oklahoma Lead Litigation.  Gold Fields Mining, LLC (Gold Fields) is a dormant, non-coal producing entity that was previously managed and owned by Hanson PLC, the Company’s predecessor owner. In a February 1997 spin-off, Hanson PLC transferred ownership of Gold Fields to the Company, despite the fact that Gold Fields had no ongoing operations and the Company had no prior involvement in its past operations. Gold Fields is currently one of the Company’s subsidiaries. The Company 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 several other companies are defendants in a property damage lawsuit pending in the U.S. District Court for the Northern District of Oklahoma arising from past operations near Picher, Oklahoma. The plaintiffs are seeking compensatory damages for diminution in property values and punitive damages. Gold Fields has entered into a settlement with plaintiffs and the case has been stayed pending receipt of releases from all plaintiffs. Gold Fields was also a defendant in another case alleging property damage and pending in the U.S. District Court for the Northern District of Oklahoma arising out of past operations near Picher, Oklahoma, but the court granted summary judgment in Gold Field's favor in that case.

Gold Fields and several other companies are also defendants in a personal injury lawsuit pending in the U.S. District Court for the Northern District of Oklahoma arising from past operations near Picher, Oklahoma. The four plaintiffs are seeking compensatory damages for cognitive impairments allegedly caused by exposure to lead and punitive damages. Gold Fields has entered into a settlement with plaintiffs and other potential personal injury claimants. The case has been stayed pending receipt of releases from all plaintiffs/claimants and court approval of the settlement on behalf of minor plaintiffs/claimants.

In June 2005, Gold Fields and other potentially responsible parties (PRPs) received a letter from the U. S. Department of Justice alleging that the potentially responsible parties' mining operations caused the U.S. Environmental Protection Agency (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 June 2008, Gold Fields and other PRPs received letters from the U.S. Department of Justice and the EPA re-initiating settlement negotiations. Gold Fields continues to participate in the settlement discussions. Gold Fields believes it has meritorious defense to these claims.

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. The state of Oklahoma has also indicated that it seeks to recover remediation costs from these parties.

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

F - 58

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 13 additional sites, bringing the total to 18, which have since been reduced to 11 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 $52.5 million as of December 31, 2011 and $51.1 million as of December 31, 2010, $11.6 million and $6.3 million of which was reflected as a current liability, respectively. These amounts represent those costs that the Company believes are probable and reasonably estimable.

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 the Company’s evaluation of the issues and their potential impact, the total amount of any future loss cannot be reasonably estimated. However, based on current information, the Company believes these claims and litigation are likely to be resolved without a material adverse effect on its financial condition, results of operations or cash flows.

Native Village of Kivalina and City of Kivalina v. ExxonMobil Corporation, et al.  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 the Company, 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. The defendants filed motions to dismiss on the grounds of lack of personal and subject matter jurisdiction. In June 2009, the court granted defendants’ motion to dismiss for lack of subject matter jurisdiction finding that plaintiffs’ federal claim for nuisance is barred by the political question doctrine and for lack of standing. The plaintiffs appealed the court’s dismissal to the U.S. Court of Appeals for the Ninth Circuit, which heard oral arguments on November 28, 2011.

Other

In addition, at times the Company becomes 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 the Company does business.

In June 2007, the New York Office of the Attorney General served a letter and subpoena on the Company, seeking information and documents relating to the Company's disclosure to investors of risks associated with possible climate change and related legislation and regulations. The Company believes it has made full and proper disclosure of these potential risks. Based on current information, the Company believes that the ultimate resolution of such other pending or threatened proceedings is not reasonably likely to have a material adverse effect on its financial position, results of operations or liquidity.

F - 59

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(24) Summary Quarterly Financial Information (Unaudited)

A summary of the unaudited quarterly results of operations for the years ended December 31, 2011 and 2010 is presented below.

	Year Ended December 31, 2011
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(In millions, except per share data)
Revenues	$	1,743.1	$	1,980.5	$	1,997.2	$	2,253.6
Operating profit	314.3		479.3		381.5		418.3
Income from continuing operations, net of income taxes	194.6		307.8		285.6		222.5
Net income	178.7		292.2		281.4		194.0
Net income attributable to common stockholders	176.5		284.8		274.0		222.4
Basic EPS — continuing operations(1)	0.71		1.11		1.03		0.93
Diluted EPS — continuing operations(1)	$	0.70	$	1.10	$	1.02	$	0.92
Weighted average shares used in calculating basic EPS	268.9		269.0		269.2		269.3
Weighted average shares used in calculating diluted EPS	272.8		270.5		270.6		270.2

⁽¹⁾  EPS for the quarters may not sum to the amounts for the year as each period is computed on a discrete basis.

The fourth quarter results of operations include Macarthur’s results of operations from the date of acquisition. The third and fourth quarters operating profit reflects $9.1 million and $76.1 million, respectively, of acquisition costs related to the Macarthur acquisition and an adverse impact of a third quarter roof fall and recovery of longwall operations at the Company's North Goonyella Mine in Australia, impacting the third and fourth quarters by $122.9 million and $111.8 million, respectively. Income from continuing operations, net of income taxes in the first, second and fourth quarters included non-cash tax expense of $6.4 million, $15.4 million and $16.0 million, respectively, from the remeasurement of non-U.S. income tax accounts, while the third quarter included a non-cash tax benefit of $38.7 million.

	Year Ended December 31, 2010
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(In millions, except per share data)
Revenues	$	1,490.6	$	1,629.9	$	1,826.7	$	1,792.7
Operating profit	255.1		325.7		447.3		326.3
Income from continuing operations, net of income taxes	147.8		215.7		239.3		223.8
Net income	136.7		214.2		236.3		215.0
Net income attributable to common stockholders	133.7		206.2		224.1		210.0
Basic EPS — continuing operations(1)	0.54		0.77		0.84		0.81
Diluted EPS — continuing operations(1)	$	0.54	$	0.77	$	0.84	$	0.80
Weighted average shares used in calculating basic EPS	266.5		266.6		267.1		267.7
Weighted average shares used in calculating diluted EPS	268.2		268.3		268.6		270.3

⁽¹⁾  EPS for the quarters may not sum to the amounts for the year as each period is computed on a discrete basis.

Operating profit in the second, third and fourth quarters of 2010 reflects higher contract pricing in Australia. Operating profit for the fourth quarter also includes an adverse impact related to flooding in Queensland, Australia and lower results from the Company’s Trading and Brokerage operations. Income from continuing operations, net of income taxes in the first, third and fourth quarters included non-cash tax expense of $5.5 million, $43.0 million and $18.9 million, respectively, from the remeasurement of non-U.S. income tax accounts, while the second quarter included a non-cash tax benefit of $19.5 million.

F - 60

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(25) Segment Information

The Company reports its operations primarily through the following reportable operating segments: “Western U.S. Mining,” “Midwestern U.S. Mining,” “Australian Mining,” “Trading and Brokerage” and “Corporate and Other.” The Company's Western U.S. Mining operations reflect the aggregation of the Powder River Basin, Southwest and Colorado mining operations. The mines in that segment are characterized by predominantly surface mining extraction processes, coal with a lower sulfur content and Btu and higher customer transportation costs (due to longer shipping distances). The Company's Midwestern U.S. Mining operations reflect the Company’s Illinois and Indiana mining operations, which are characterized by a mix of surface and underground mining extraction processes, coal with a higher sulfur content and Btu and lower customer transportation costs (due to shorter shipping distances). Geologically, Western operations mine bituminous and subbituminous coal deposits, and Midwestern operations mine bituminous coal deposits. The principal business of the Western and Midwestern U.S. Mining segments is the mining, preparation and sale of thermal coal, sold primarily to electric utilities in the U.S., with a portion sold into the seaborne markets.

The Company’s Australian Mining operations consist of its mines in Queensland and New South Wales, Australia. The mines in that segment are characterized by both surface and underground extraction processes, mining various qualities of metallurgical (low-sulfur, high Btu coal) and thermal coal. The metallurgical coal qualities include hard coking coal, semi-hard coking coal, semi-soft coal and pulverized coal injection coal. The business of the Company's Australian Mining operations are primarily export focused with customers spread across several countries, while a portion of the coal is sold to Australian steel producers and power generators. Generally, revenues from individual countries vary year by year based on the demand for electricity, the demand for steel, the strength of the global economy and several other factors including those specific to each country.

The Company’s Trading and Brokerage segment brokers coal sales of other coal producers both as principal and agent, and trades coal, freight and freight-related contracts. Corporate and Other includes selling and administrative expenses, equity income (loss) from the Company's joint ventures, certain asset sales, resource management costs and revenues, coal royalty expense, costs associated with past mining obligations, expenses related to the Company’s other commercial activities such as generation development and Btu Conversion costs and provisions for certain litigation.

The Company’s chief operating decision maker uses Adjusted EBITDA as the primary measure of segment profit and loss. The Company defines Adjusted EBITDA as income from continuing operations before deducting net interest expense, income taxes, asset retirement obligation expense and depreciation, depletion and amortization.

Operating segment results for the year ended December 31, 2011 were as follows (total assets as of December 31, 2011):

	Western U.S. Mining		Midwestern U.S. Mining		Australian Mining		Trading and Brokerage		Corporate and Other			Consolidated
	(Dollars in millions)
Revenues	$	2,900.4	$	1,481.1	$	3,080.7	$	475.1	$	37.1		$	7,974.4
Adjusted EBITDA	766.0		408.9		1,194.3		197.0		(437.5		)	2,128.7
Total assets	3,095.8		672.5		8,568.9		633.3		3,762.5			16,733.0
Additions to property, plant, equipment and mine development	228.5		108.2		439.6		0.9		69.7			846.9
Loss from equity affiliates	—		—		—		—		19.2			19.2

F - 61

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Operating segment results for the year ended December 31, 2010 were as follows (total assets as of December 31, 2010):

	Western U.S. Mining		Midwestern U.S. Mining		Australian Mining		Trading and Brokerage		Corporate and Other			Consolidated
	(Dollars in millions)
Revenues	$	2,706.3	$	1,320.6	$	2,399.9	$	291.1	$	22.0		$	6,739.9
Adjusted EBITDA	816.7		322.1		977.4		77.2		(354.7		)	1,838.7
Total assets	3,008.4		608.0		3,603.4		398.2		3,745.1			11,363.1
Additions to property, plant, equipment and mine development	143.3		224.9		138.7		0.9		40.1			547.9
Loss from equity affiliates	—		—		—		—		1.7			1.7

Operating segment results for the year ended December 31, 2009 were as follows (total assets as of December 31, 2009):

	Western U.S. Mining		Midwestern U.S. Mining		Australian Mining		Trading and Brokerage		Corporate and Other			Consolidated
	(Dollars in millions)
Revenues	$	2,612.6	$	1,303.8	$	1,512.6	$	391.0	$	27.0		$	5,847.0
Adjusted EBITDA	721.5		281.9		410.5		193.4		(344.5		)	1,262.8
Total assets	3,087.6		444.4		3,386.8		673.0		2,363.5			9,955.3
Additions to property, plant, equipment and mine development	201.9		104.2		69.3		1.8		6.2			383.4
Loss from equity affiliates	—		—		—		—		69.1			69.1

A reconciliation of adjusted EBITDA to consolidated income from continuing operations, net of income taxes follows:

	Year Ended December 31,
	2011			2010			2009
	(Dollars in millions)
Total adjusted EBITDA	$	2,128.7		$	1,838.7		$	1,262.8
Depreciation, depletion and amortization	(482.2		)	(437.1		)	(400.5		)
Asset retirement obligation expense	(53.1		)	(47.2		)	(39.9		)
Interest expense	(238.6		)	(222.0		)	(201.1		)
Interest income	18.9			9.6			8.1
Income tax provision	(363.2		)	(315.4		)	(186.2		)
Income from continuing operations, net of income taxes	$	1,010.5		$	826.6		$	443.2

The following table presents revenues as a percent of total revenue from external customers by geographic region:

	Year Ended December 31,
	2011		2010		2009
U.S.	62.0	%	64.6	%	73.2	%
Japan	10.2	%	9.1	%	7.1	%
South Korea	5.5	%	3.7	%	2.2	%
India	5.2	%	4.9	%	3.8	%
Other	17.1	%	17.7	%	13.7	%
Total	100	%	100	%	100	%

The Company attributes revenue to individual countries based on the location of the physical delivery of the coal.

F - 62

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(26) Supplemental Guarantor/Non-Guarantor Financial Information

In accordance with the indentures governing the Senior Notes, including the 5.875% Senior Notes due April 2016 and the 6.875% Senior Notes due March 2013 extinguished in 2011 and 2010, respectively, certain wholly-owned U.S. subsidiaries of the Company have fully and unconditionally guaranteed these Senior Notes, on a joint and several basis. Separate financial statements and other disclosures concerning the Guarantor Subsidiaries are not presented because management believes that such information is not material to the holders of the Senior Notes. The following historical financial statement information is provided for the Guarantor/Non-Guarantor Subsidiaries.

PEABODY ENERGY CORPORATION

SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF INCOME

	Year Ended December 31, 2011
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(Dollars in millions)
Total revenues	$	—		$	4,758.4		$	3,509.4		$	(293.4	)	$	7,974.4
Costs and expenses
Operating costs and expenses	(386.3		)	3,598.6			2,631.1			(293.4		)	5,550.0
Depreciation, depletion and amortization	—			297.4			184.8			—			482.2
Asset retirement obligation expense	—			36.2			16.9			—			53.1
Selling and administrative expenses	34.0			215.0			19.2			—			268.2
Acquisition costs related to Macarthur Coal Limited	32.8			31.2			21.2			—			85.2
Other operating (income) loss:
Net gain on disposal or exchange of assets	—			(73.2		)	(3.7		)	—			(76.9		)
(Income) loss from equity affiliates	(881.5		)	8.6			10.6			881.5			19.2
Interest expense	243.1			47.3			67.2			(119.0		)	238.6
Interest income	(50.9		)	(31.1		)	(55.9		)	119.0			(18.9		)
Unrealized (gain) loss on derivatives	—			(1.3		)	1.3			—			—
Income from continuing operations before income taxes	1,008.8			629.7			616.7			(881.5		)	1,373.7
Income tax provision	46.5			172.0			144.7			—			363.2
Income from continuing operations, net of income taxes	962.3			457.7			472.0			(881.5		)	1,010.5
Loss from discontinued operations, net of income taxes	(4.6		)	(3.1		)	(56.5		)	—			(64.2		)
Net income	957.7			454.6			415.5			(881.5		)	946.3
Less: Net loss attributable to noncontrolling interests	—			—			(11.4		)	—			(11.4		)
Net income attributable to common stockholders	$	957.7		$	454.6		$	426.9		$	(881.5	)	$	957.7

F - 63

PEABODY ENERGY CORPORATION

SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF INCOME

	Year Ended December 31, 2010
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(Dollars in millions)
Total revenues	$	—		$	3,596.1		$	3,916.9		$	(773.1	)	$	6,739.9
Costs and expenses
Operating costs and expenses	(145.1		)	2,472.7			3,142.8			(773.1		)	4,697.3
Depreciation, depletion and amortization	—			294.1			143.0			—			437.1
Asset retirement obligation expense	—			31.9			15.3			—			47.2
Selling and administrative expenses	31.6			194.3			6.3			—			232.2
Other operating (income) loss:
Net (gain) loss on disposal or exchange of assets	—			(34.5		)	4.5			—			(30.0		)
(Income) loss from equity affiliates	(838.4		)	7.1			6.0			827.0			1.7
Interest expense	219.7			52.7			17.9			(68.3		)	222.0
Interest income	(18.8		)	(21.8		)	(37.3		)	68.3			(9.6		)
Income from continuing operations before income taxes	751.0			599.6			618.4			(827.0		)	1,142.0
Income tax (benefit) provision	(24.2		)	183.3			156.3			—			315.4
Income from continuing operations, net of income taxes	775.2			416.3			462.1			(827.0		)	826.6
Loss from discontinued operations, net of income taxes	(1.2		)	(23.2		)	—			—			(24.4		)
Net income	774.0			393.1			462.1			(827.0		)	802.2
Less: Net income attributable to noncontrolling interests	—			—			28.2			—			28.2
Net income attributable to common stockholders	$	774.0		$	393.1		$	433.9		$	(827.0	)	$	774.0

F - 64

PEABODY ENERGY CORPORATION

SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF INCOME

	Year Ended December 31, 2009
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(Dollars in millions)
Total revenues	$	—		$	4,283.9		$	2,312.5		$	(749.4	)	$	5,847.0
Costs and expenses
Operating costs and expenses	104.4			3,250.4			1,733.8			(749.4		)	4,339.2
Depreciation, depletion and amortization	—			282.9			117.6			—			400.5
Asset retirement obligation expense	—			33.1			6.8			—			39.9
Selling and administrative expenses	29.3			164.2			5.6			—			199.1
Other operating (income) loss:
Net gain on disposal or exchange of assets	—			(17.1		)	(6.1		)	—			(23.2		)
(Income) loss from equity affiliates	(620.9		)	6.3			62.8			620.9			69.1
Interest expense	198.4			52.5			16.2			(66.0		)	201.1
Interest income	(15.3		)	(28.9		)	(29.9		)	66.0			(8.1		)
Income from continuing operations before income taxes	304.1			540.5			405.7			(620.9		)	629.4
Income tax (benefit) provision	(122.3		)	176.5			132.0			—			186.2
Income from continuing operations, net of income taxes	426.4			364.0			273.7			(620.9		)	443.2
Income (loss) from discontinued operations, net of income taxes	21.8			12.0			(14.0		)	—			19.8
Net income	448.2			376.0			259.7			(620.9		)	463.0
Less: Net income attributable to noncontrolling interests	—			—			14.8			—			14.8
Net income attributable to common stockholders	$	448.2		$	376.0		$	244.9		$	(620.9	)	$	448.2

F - 65

PEABODY ENERGY CORPORATION

SUPPLEMENTAL CONDENSED CONSOLIDATING BALANCE SHEETS

	December 31, 2011
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Reclassifications/ Eliminations			Consolidated
	(Dollars in millions)
Assets
Current assets
Cash and cash equivalents	$	283.2		$	0.8		$	515.1		$	—		$	799.1
Accounts receivable, net	5.3			100.8			816.4			—			922.5
Inventories	—			220.0			226.3			—			446.3
Assets from coal trading activities, net	—			14.9			29.7			—			44.6
Deferred income taxes	—			48.0			—			(20.7		)	27.3
Other current assets	305.1			98.8			362.2			—			766.1
Total current assets	593.6			483.3			1,949.7			(20.7		)	3,005.9
Property, plant, equipment and mine development
Land and coal interests	—			5,061.8			5,719.2			—			10,781.0
Buildings and improvements	—			962.8			168.6			—			1,131.4
Plant and equipment	—			1,507.3			1,355.1			—			2,862.4
Less: accumulated depreciation, depletion and amortization	—			(2,623.1		)	(789.0		)	—			(3,412.1		)
Property, plant, equipment and mine development, net	—			4,908.8			6,453.9			—			11,362.7
Investments and other assets	10,300.8			199.7			1,496.1			(9,632.2		)	2,364.4
Total assets	$	10,894.4		$	5,591.8		$	9,899.7		$	(9,652.9	)	$	16,733.0
Liabilities and Stockholders’ Equity
Current liabilities
Current maturities of long-term debt	$	62.5		$	—		$	38.6		$	—		$	101.1
Payables to (receivables from) affiliates, net	2,417.8			(2,529.1		)	111.3			—			—
Liabilities from coal trading activities, net	—			4.2			6.1			—			10.3
Deferred income taxes	11.6			—			9.1			(20.7		)	—
Accounts payable and accrued expenses	69.4			868.8			774.1			—			1,712.3
Total current liabilities	2,561.3			(1,656.1		)	939.2			(20.7		)	1,823.7
Long-term debt, less current maturities	6,428.8			—			127.6			—			6,556.4
Deferred income taxes	76.0			126.3			351.9			—			554.2
Notes payable to (receivables from) affiliates, net	(3,720.0		)	(981.5		)	4,701.5			—			—
Other noncurrent liabilities	63.2			1,892.6			327.1			—			2,282.9
Total liabilities	5,409.3			(618.7		)	6,447.3			(20.7		)	11,217.2
Peabody Energy Corporation’s stockholders’ equity	5,485.1			6,210.5			3,421.7			(9,632.2		)	5,485.1
Noncontrolling interests	—			—			30.7			—			30.7
Total stockholders’ equity	5,485.1			6,210.5			3,452.4			(9,632.2		)	5,515.8
Total liabilities and stockholders’ equity	$	10,894.4		$	5,591.8		$	9,899.7		$	(9,652.9	)	$	16,733.0

F - 66

PEABODY ENERGY CORPORATION

SUPPLEMENTAL CONDENSED CONSOLIDATING BALANCE SHEETS

	December 31, 2010
	Parent Company		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Reclassifications/ Eliminations			Consolidated
			(Dollars in millions)
Assets
Current assets
Cash and cash equivalents	$	903.8	$	5.2		$	386.2		$	—		$	1,295.2
Accounts receivable, net	2.1		5.5			548.2			—			555.8
Inventories	—		168.0			159.2			—			327.2
Assets from coal trading activities, net	—		23.8			168.7			—			192.5
Deferred income taxes	—		78.6			47.9			(6.1		)	120.4
Other current assets	307.9		30.7			128.5			—			467.1
Total current assets	1,213.8		311.8			1,438.7			(6.1		)	2,958.2
Property, plant, equipment and mine development
Land and coal interests	—		4,860.7			2,773.1			—			7,633.8
Buildings and improvements	—		945.8			121.6			—			1,067.4
Plant and equipment	—		1,300.6			363.9			—			1,664.5
Less: accumulated depreciation, depletion and amortization	—		(2,374.4		)	(613.2		)	—			(2,987.6		)
Property, plant, equipment and mine development, net	—		4,732.7			2,645.4			—			7,378.1
Investments and other assets	9,331.0		179.8			147.1			(8,631.1		)	1,026.8
Total assets	$	10,544.8	$	5,224.3		$	4,231.2		$	(8,637.2	)	$	11,363.1
Liabilities and Stockholders’ Equity
Current liabilities
Current maturities of long-term debt	$	25.0	$	—		$	18.2		$	—		$	43.2
Payables to (receivables from) affiliates, net	2,225.3		(2,528.3		)	303.0			—			—
Liabilities from coal trading activities, net	—		29.5			152.2			—			181.7
Deferred income taxes	6.1		—			—			(6.1		)	—
Accounts payable and accrued expenses	47.4		777.2			464.2			—			1,288.8
Total current liabilities	2,303.8		(1,721.6		)	937.6			(6.1		)	1,513.7
Long-term debt, less current maturities	2,609.6		0.1			97.1			—			2,706.8
Deferred income taxes	93.2		135.4			316.5			—			545.1
Notes payable to (receivables from) affiliates, net	818.9		(825.3		)	6.4			—			—
Other noncurrent liabilities	58.6		1,652.8			196.8			—			1,908.2
Total liabilities	5,884.1		(758.6		)	1,554.4			(6.1		)	6,673.8
Peabody Energy Corporation’s stockholders’ equity	4,660.7		5,982.9			2,648.2			(8,631.1		)	4,660.7
Noncontrolling interests	—		—			28.6			—			28.6
Total stockholders’ equity	4,660.7		5,982.9			2,676.8			(8,631.1		)	4,689.3
Total liabilities and stockholders’ equity	$	10,544.8	$	5,224.3		$	4,231.2		$	(8,637.2	)	$	11,363.1

F - 67

PEABODY ENERGY CORPORATION

SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

	Year Ended December 31, 2011
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidated
				(Dollars in millions)
Cash Flows From Operating Activities
Net cash provided by continuing operations	$	28.9		$	1,519.7		$	109.5		$	1,658.1
Net cash provided by (used in) discontinued operations	4.4			(6.8		)	(22.5		)	(24.9		)
Net cash provided by operating activities	33.3			1,512.9			87.0			1,633.2
Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development	—			(401.1		)	(445.8		)	(846.9		)
Investment in Prairie State Energy Campus	—			(36.2		)	—			(36.2		)
Proceeds from disposal of assets, net of notes receivable	—			34.1			6.0			40.1
Investments in equity affiliates and joint ventures	—			(2.0		)	(37.7		)	(39.7		)
Proceeds from sales of debt and equity securities	—			47.0			57.6			104.6
Purchases of debt and equity securities	—			(103.6		)	(44.1		)	(147.7		)
Purchases of short-term investments	(75.0		)	—			(25.0		)	(100.0		)
Maturity of short-term investments	75.0			—			25.0			100.0
Acquisition of Macarthur Coal Limited	—			—			(2,756.7		)	(2,756.7		)
Contributions to joint ventures	—			(145.4		)	—			(145.4		)
Distributions from joint ventures	—			128.6			—			128.6
Repayment of loans from related parties	—			331.7			—			331.7
Advances to related parties	—			(371.3		)	—			(371.3		)
Other, net	—			(6.5		)	(0.1		)	(6.6		)
Net cash used in continuing operations	—			(524.7		)	(3,220.8		)	(3,745.5		)
Net cash used in discontinued operations	—			—			(62.3		)	(62.3		)
Net cash used in investing activities	—			(524.7		)	(3,283.1		)	(3,807.8		)
Cash Flows From Financing Activities
Proceeds from long-term debt	4,100.0			—			1.4			4,101.4
Acquisition of noncontrolling interests	(11.1		)	11.1			(1,994.8		)	(1,994.8		)
Payments of long-term debt	(243.1		)	—			(20.8		)	(263.9		)
Dividends paid	(92.1		)	—			—			(92.1		)
Repurchase of employee common stock relinquished for tax withholding	(18.7		)	—			—			(18.7		)
Payment of debt issuance costs	(61.5		)	—			—			(61.5		)
Excess tax benefits related to share-based compensation	8.1			—			—			8.1
Other, net	11.1			(12.0		)	0.9			—
Transactions with affiliates, net	(4,346.6		)	(991.7		)	5,338.3			—
Net cash (used in) provided by financing activities	(653.9		)	(992.6		)	3,325.0			1,678.5
Net change in cash and cash equivalents	(620.6		)	(4.4		)	128.9			(496.1		)
Cash and cash equivalents at beginning of year	903.8			5.2			386.2			1,295.2
Cash and cash equivalents at end of year	$	283.2		$	0.8		$	515.1		$	799.1

F - 68

PEABODY ENERGY CORPORATION

SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

	Year Ended December 31, 2010
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidated
				(Dollars in millions)
Cash Flows From Operating Activities
Net cash (used in) provided by continuing operations	$	(126.4	)	$	1,090.6		$	152.5		$	1,116.7
Net cash used in discontinued operations	(14.2		)	(2.4		)	(13.0		)	(29.6		)
Net cash (used in) provided by operating activities	(140.6		)	1,088.2			139.5			1,087.1
Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development	—			(404.5		)	(143.4		)	(547.9		)
Investment in Prairie State Energy Campus	—			(76.0		)	—			(76.0		)
Proceeds from disposal of assets, net of notes receivable	—			14.1			5.1			19.2
Investments in equity affiliates and joint ventures	—			(15.0		)	(3.8		)	(18.8		)
Proceeds from sales of debt and equity securities	—			—			12.4			12.4
Purchases of debt and equity securities	—			—			(74.6		)	(74.6		)
Other, net	—			(8.7		)	(0.1		)	(8.8		)
Net cash used in continuing operations	—			(490.1		)	(204.4		)	(694.5		)
Net cash used in discontinued operations	—			—			(9.1		)	(9.1		)
Net cash used in investing activities	—			(490.1		)	(213.5		)	(703.6		)
Cash Flows From Financing Activities
Proceeds from long-term debt	1,150.0			—			—			1,150.0
Payments of long-term debt	(1,146.8		)	—			(20.5		)	(1,167.3		)
Dividends paid	(79.4		)	—			—			(79.4		)
Repurchase of employee common stock relinquished for tax withholding	(13.5		)	—			—			(13.5		)
Payment of debt issuance costs	(32.2		)	—			—			(32.2		)
Excess tax benefits related to share-based compensation	51.0			—			—			51.0
Other, net	22.3			(5.9		)	(2.1		)	14.3
Transactions with affiliates, net	724.6			(587.2		)	(137.4		)	—
Net cash provided by (used in) financing activities	676.0			(593.1		)	(160.0		)	(77.1		)
Net change in cash and cash equivalents	535.4			5.0			(234.0		)	306.4
Cash and cash equivalents at beginning of year	368.4			0.2			620.2			988.8
Cash and cash equivalents at end of year	$	903.8		$	5.2		$	386.2		$	1,295.2

F - 69

PEABODY ENERGY CORPORATION

SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

	Year Ended December 31, 2009
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidated
				(Dollars in millions)
Cash Flows From Operating Activities
Net cash (used in) provided by continuing operations	$	(213.7	)	$	792.7		$	465.9		$	1,044.9
Net cash provided by (used in) discontinued operations	7.4			(5.3		)	3.2			5.3
Net cash (used in) provided by operating activities	(206.3		)	787.4			469.1			1,050.2
Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development	—			(313.3		)	(70.1		)	(383.4		)
Investment in Prairie State Energy Campus	—			(56.8		)	—			(56.8		)
Proceeds from disposal of assets, net of notes receivable	—			43.8			10.1			53.9
Investments in equity affiliates and joint ventures	—			(5.0		)	(10.0		)	(15.0		)
Other, net	—			(5.8		)	(0.3		)	(6.1		)
Net cash used in continuing operations	—			(337.1		)	(70.3		)	(407.4		)
Net cash provided by discontinued operations	—			—			0.9			0.9
Net cash used in investing activities	—			(337.1		)	(69.4		)	(406.5		)
Cash Flows From Financing Activities
Payments of long-term debt	—			—			(37.1		)	(37.1		)
Dividends paid	(66.8		)	—			—			(66.8		)
Repurchase of employee common stock relinquished for tax withholding	(2.3		)	—			—			(2.3		)
Other, net	8.7			—			(7.1		)	1.6
Transactions with affiliates, net	473.9			(454.6		)	(19.3		)	—
Net cash provided by (used in) financing activities	413.5			(454.6		)	(63.5		)	(104.6		)
Net change in cash and cash equivalents	207.2			(4.3		)	336.2			539.1
Cash and cash equivalents at beginning of year	161.2			4.5			284.0			449.7
Cash and cash equivalents at end of year	$	368.4		$	0.2		$	620.2		$	988.8

F - 70

PEABODY ENERGY CORPORATION

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

Description	Balance at Beginning of Period		Charged to Costs and Expenses			Deductions(1)			Other				Balance at End of Period
	(Dollars in millions)
Year Ended December 31, 2011
Reserves deducted from asset accounts:
Advance royalty recoupment reserve	$	19.9	$	1.8		$	(0.1	)	$	(0.3	)	(2)	$	21.3
Reserve for materials and supplies	6.2		3.7			(3.4		)	—				6.5
Allowance for doubtful accounts	30.3		(3.7		)	(0.4		)	(9.2		)	(3)	17.0
Year Ended December 31, 2010
Reserves deducted from asset accounts:
Advance royalty recoupment reserve	$	17.2	$	1.9		$	(0.2	)	$	1.0		(2)	$	19.9
Reserve for materials and supplies	6.2		0.9			(0.9		)	—				6.2
Allowance for doubtful accounts	18.3		26.7			(6.9		)	(7.8		)	(3)	30.3
Year Ended December 31, 2009
Reserves deducted from asset accounts:
Advance royalty recoupment reserve	$	17.2	$	1.6		$	(2.2	)	$	0.6		(2)	$	17.2
Reserve for materials and supplies	4.9		3.6			(2.3		)	—				6.2
Allowance for doubtful accounts	24.8		7.7			(3.6		)	(10.6		)	(3)	18.3

⁽¹⁾  Reserves utilized, unless otherwise indicated.

⁽²⁾  Balances transferred (to) from other accounts or reserves recorded as part of a property transaction or acquisition.

⁽³⁾  Reflects subsequent recovery of amounts previously reserved.

F - 71

EXHIBIT INDEX

The exhibits below are numbered in accordance with the Exhibit Table of Item 601 of Regulation S-K.

Exhibit No.	Description of Exhibit
3.1 †	Third Amended and Restated Certificate of Incorporation of the Registrant, as amended.
3.2	Amended and Restated By-Laws of the Registrant (Incorporated by reference to Exhibit 3.1 of the Registrant’s Current Report on Form 8-K, filed September 16, 2008).
4.1	Rights Agreement, dated as of July 24, 2002, between the Registrant and EquiServe Trust Company, N.A., as Rights Agent (which includes the form of Certificate of Designations of Series A Junior Preferred Stock of the Registrant as Exhibit A, the form of Right Certificate as Exhibit B and the Summary of Rights to Purchase Preferred Shares as Exhibit C) (Incorporated herein by reference to Exhibit 4.1 to the Registrant’s Registration Statement on Form 8-A, filed July 24, 2002).
4.2	Certificate of Designations of Series A Junior Participating Preferred Stock of the Registrant, filed with the Secretary of State of the State of Delaware on July 24, 2002 (Incorporated herein by reference to Exhibit 3.1 to the Registrant’s Registration Statement on Form 8-A, filed July 24, 2002).
4.3	Certificate of Adjustment delivered by the Registrant to Equiserve Trust Company, N.A., as Rights Agent, on March 29, 2005 (Incorporated by reference to Exhibit 4.2 to Amendment No. 1 to the Registrant’s Registration Statement on Form 8-A/A, filed March 29, 2005).
4.4	Certificate of Adjustment delivered by the Registrant to American Stock Transfer & Trust Company, as Rights Agent, on February 22, 2006 (Incorporated by reference to Exhibit 4.2 to Amendment No. 2 to the Registrant’s Registration Statement on Form 8-A/A, filed February 22, 2006).
4.5	Specimen of stock certificate representing the Registrant’s common stock, $.01 par value (Incorporated by reference to Exhibit 4.13 to Amendment No. 4 to the Registrant’s Form S-1 Registration Statement No. 333-55412, filed May 1, 2001).
4.6	Indenture, dated as of March 19, 2004, between the Registrant and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.12 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
4.7	73/8% Senior Notes Due 2016 Tenth Supplemental Indenture, dated as of October 12, 2006 among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.1 of the Registrant’s Current Report on Form 8-K, filed October 13, 2006).
4.8	73/8% Senior Notes Due 2016 Thirteenth Supplemental Indenture, dated as of November 10, 2006 among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.33 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2006).
4.9	73/8% Senior Notes Due 2016 Sixteenth Supplemental Indenture, dated as of January 31, 2007, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.34 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2006).
4.10	73/8% Senior Notes Due 2016 Nineteenth Supplemental Indenture, dated as of June 14, 2007, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.3 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007).
4.11	73/8% Senior Notes Due 2016 Twenty-Second Supplemental Indenture, dated as of November 14, 2007, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.40 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2007).
4.12	73/8% Senior Notes Due 2016 Thirty-First Supplemental Indenture, dated as of March 13, 2009, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.2 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009).

Exhibit No.	Description of Exhibit
4.13	7 3/8% Senior Notes Due 2016 Thirty-Sixth Supplemental Indenture dated as of April 21, 2011, among Peabody Energy Corporation, the guarantors named therein and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.1 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2011).
4.14	77/8% Senior Notes Due 2026 Eleventh Supplemental Indenture, dated as of October 12, 2006, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.2 of the Registrant’s Current Report on Form 8-K, filed October 13, 2006).
4.15	77/8% Senior Notes Due 2026 Fourteenth Supplemental Indenture, dated as of November 10, 2006, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.36 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2006).
4.16	77/8% Senior Notes Due 2026 Seventeenth Supplemental Indenture, dated as of January 31, 2007, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.37 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2006).
4.17	77/8% Senior Notes Due 2026 Twentieth Supplemental Indenture, dated as of June 14, 2007, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.4 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007).
4.18	77/8% Senior Notes Due 2026 Twenty-Third Supplemental Indenture, dated as of November 14, 2007, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.45 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2007).
4.19	77/8% Senior Notes Due 2026 Thirty-Second Supplemental Indenture, dated as of March 13, 2009, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.3 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009).
4.20	77/8% Senior Notes Due 2026 Thirty-Seventh Supplemental Indenture, dated as of April 21, 2011, among Peabody Energy Corporation, the guarantors named therein and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.2 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2011).
4.21	6.500% Senior Notes due 2020 Thirty-Third Supplemental Indenture, dated as of August 25, 2010, among Peabody Energy Corporation, the guarantors named therein and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.1 of the Registrant's Current Report on Form 8-K, filed August 27, 2010).
4.22	6.500% Senior Notes due 2020 Thirty-Eighth Supplemental Indenture, dated as of April 21, 2011, among Peabody Energy Corporation, the guarantors named therein and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.3 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2011).
4.23	Subordinated Indenture, dated as of December 20, 2006, between the Registrant and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.1 of the Registrant’s Current Report on Form 8-K, filed December 20, 2006).
4.24	4.75% Convertible Junior Subordinated Debentures Due 2066 First Supplemental Indenture, dated as of December 20, 2006, among the Registrant and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.2 of the Registrant’s Current Report on Form 8-K, filed December 20, 2006).
4.25	Capital Replacement Covenant dated December 19, 2006 (Incorporated by reference to Exhibit 99.1 of the Registrant’s Current Report on Form 8-K, filed December 20, 2006).
4.26	Notice of Adjustment of Conversion Rate of 4.75% Convertible Junior Subordinated Debentures Due 2066, dated November 26, 2007 (Incorporated by reference to Exhibit 4.49 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2007).
4.27	Notice of Adjustment of Conversion Rate of 4.75% Convertible Junior Subordinated Debentures Due 2066, dated February 8, 2009 (Incorporated by reference to Exhibit 4.5 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009).

Exhibit No.	Description of Exhibit
4.28	Notice of Adjustment of Conversion Rate of 4.75% Convertible Junior Subordinated Debentures due 2066, dated February 8, 2010 (Incorporated by reference to Exhibit 4.1 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010).
4.29	Notice of Adjustment of Conversion Rate of 4.75% Convertible Junior Subordinated Debentures due 2066, dated February 7, 2011 (Incorporated by reference to Exhibit 4.4 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2011).
4.30	Indenture, dated as of November 15, 2011, among Peabody, the Guarantors named therein and U.S. Bank National Association, as trustee, governing the 6.00% Senior Notes Due 2018 and 6.25% Senior Notes Due 2021 (Incorporated by reference to Exhibit 4.1 of the Registrant's Current Report on Form 8-K, filed November 17, 2011).
10.1	Credit Agreement, dated as of June 18, 2010, by and among the Company, Bank of America, N.A., as administrative agent, swing line lender and L/C issuer, and Banc of America Securities LLC, Citigroup Global Markets, Inc. and HSBC Securities (USA) Inc., as joint lead arrangers and joint book managers, and the lenders named therein (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed on June 24, 2010).
10.2†	Amendment No. 1 to Credit Agreement, dated as of October 20, 2011, made by and among the Registrant, Peabody Holland B.V., the lenders named therein and Bank of America, N.A., as administrative agent.
10.3	Credit Agreement, dated as of October 24, 2011, among the Registrant, as borrower, Bank of America, N.A., as administrative agent, Merrill Lynch, Pierce, Fenner & Smith Incorporated, UBS Securities LLC, Morgan Stanley Senior Funding, Inc., Citigroup Global Markets Inc., HSBC Bank (USA) N.A. and RBS Securities Inc., as joint lead arrangers and joint book managers, and the other lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K, filed October 27, 2011).
10.4	Credit Agreement, dated as of October 28, 2011, among Peabody Energy Corporation, as borrower, Bank of America, N.A., as administrative agent, Merrill Lynch, Pierce, Fenner & Smith Incorporated, UBS Securities LLC, Morgan Stanley Senior Funding, Inc., Citigroup Global Markets Inc., HSBC Bank (USA) N.A. and RBS Securities Inc., as joint lead arrangers and joint book managers, and the other lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K, filed November 2, 2011).
10.5	Third Amended and Restated Receivables Purchase Agreement, dated as of January 25, 2010, by and among P&L Receivables Company, LLC, Peabody Energy Corporation, the various Sub-Servicers listed on the signature pages thereto, all Conduit Purchasers listed on the signature pages thereto, all Related Committed Purchasers listed on the signature pages thereto, all Purchaser Agents listed on the signature pages thereto, all LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator and as LC Bank (Incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K, filed January 27, 2010).
10.6	First Amendment to Third Amended and Restated Receivables Purchase Agreement, dated as of March 1, 2010, by and among P&L Receivables Company, LLC, Peabody Energy Corporation, the various Sub-Servicers listed on the signature pages thereto, all Conduit Purchasers listed on the signature pages thereto, all Related Committed Purchasers listed on the signature pages thereto, all Purchaser Agents listed on the signature pages thereto, all LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator and as LC Bank (Incorporated by reference to Exhibit 10.2 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010).
10.7	Second Amendment to Third Amended and Restated Receivables Purchase Agreement, dated as of May 11, 2010, by and among P&L Receivables Company, LLC, Peabody Energy Corporation, the various Sub-Servicers listed on the signature pages thereto, all Conduit Purchasers listed on the signature pages thereto, all Related Committed Purchasers listed on the signature pages thereto, all Purchaser Agents listed on the signature pages thereto, all LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator and as LC Bank (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed May 17, 2010).
10.8	Third Amendment to Third Amended and Restated Receivables Purchase Agreement, dated as of September 16, 2010, by and among P&L Receivables Company, LLC, Peabody Energy Corporation, the various Sub-Servicers listed on the signature pages thereto, all Conduit Purchasers listed on the signature pages thereto, all Related Committed Purchasers listed on the signature pages thereto, all Purchaser Agents listed on the signature pages thereto, all LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator and as LC Bank (Incorporated by reference to Exhibit 10.1 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010).

Exhibit No.	Description of Exhibit
10.9	Fourth Amendment to Third Amended and Restated Receivables Purchase Agreement, dated as of May 10, 2011, by and among P&L Receivables Company, LLC, Peabody Energy Corporation, the various Sub-Servicers listed on the signature pages thereto, all Conduit Purchasers listed on the signature pages thereto, all Related Committed Purchasers listed on the signature pages thereto, all Purchaser Agents listed on the signature pages thereto, all LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator and as LC Bank (Incorporated by reference to Exhibit 10.2 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2011).
10.10	Registration Rights Agreement, dated as of November 15, 2011, among Peabody, the Guarantors named therein, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Morgan Stanley & Co. LLC, UBS Securities LLC, Citigroup Global Markets Inc., HSBC Securities (USA) Inc., RBS Securities Inc., Banco Bilbao Vizcaya Argentaria, S.A., Mitsubishi UFJ Securities (USA), Inc., PNC Capital Markets LLC, Santander Investment Securities Inc., U.S. Bancorp Investments, Inc., Wells Fargo Securities, LLC, ANZ Securities, Inc., Fifth Third Securities, Inc., nabSecurities, LLC, SMBC Nikko Capital Markets Limited, Standard Chartered Bank and Westpac Banking Corporation (Incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K, filed November 17, 2011).
10.11	Federal Coal Lease WYW0321779: North Antelope/Rochelle Mine (Incorporated by reference to Exhibit 10.3 of the Registrant’s Form S-4 Registration Statement No. 333-59073).
10.12	Federal Coal Lease WYW119554: North Antelope/Rochelle Mine (Incorporated by reference to Exhibit 10.4 of the Registrant’s Form S-4 Registration Statement No. 333-59073, filed July 14, 1998).
10.13	Federal Coal Lease WYW5036: Rawhide Mine (Incorporated by reference to Exhibit 10.5 of the Registrant’s Form S-4 Registration Statement No. 333-59073, filed July 14, 1998).
10.14	Federal Coal Lease WYW3397: Caballo Mine (Incorporated by reference to Exhibit 10.6 of the Registrant’s Form S-4 Registration Statement No. 333-59073, filed July 14, 1998).
10.15	Federal Coal Lease WYW83394: Caballo Mine (Incorporated by reference to Exhibit 10.7 of the Registrant’s Form S-4 Registration Statement No. 333-59073, filed July 14, 1998).
10.16	Federal Coal Lease WYW136142 (Incorporated by reference to Exhibit 10.8 of Amendment No. 1 to the Registrant’s Form S-4 Registration Statement No. 333-59073, filed September 8, 1998).
10.17	Royalty Prepayment Agreement by and among Peabody Natural Resources Company, Gallo Finance Company and Chaco Energy Company, dated September 30, 1998 (Incorporated by reference to Exhibit 10.9 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1998).
10.18	Federal Coal Lease WYW154001: North Antelope Rochelle South (Incorporated by reference to Exhibit 10.68 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2004).
10.19	Federal Coal Lease WYW150210: North Antelope Rochelle Mine (Incorporated by reference to Exhibit 10.8 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005).
10.20	Federal Coal Lease WYW151134 effective May 1, 2005: West Roundup (Incorporated by reference to Exhibit 10.1 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005).
10.21	Separation Agreement, Plan of Reorganization and Distribution, dated October 22, 2007, between the Registrant and Patriot Coal Corporation (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed October 25, 2007).
10.22	Tax Separation Agreement, dated October 22, 2007, between the Registrant and Patriot Coal Corporation (Incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K, filed October 25, 2007).
10.23	Coal Act Liabilities Assumption Agreement, dated October 22, 2007, among Patriot Coal Corporation, Peabody Holding Company, LLC and the Registrant (Incorporated by reference to Exhibit 10.3 of the Registrant’s Current Report on Form 8-K, filed October 25, 2007).
10.24	NBCWA Liabilities Assumption Agreement, dated October 22, 2007, among Patriot Coal Corporation, Peabody Holding Company, LLC, Peabody Coal Company, LLC and the Registrant (Incorporated by reference to Exhibit 10.4 of the Registrant’s Current Report on Form 8-K, filed October 25, 2007).
10.25	Salaried Employee Liabilities Assumption Agreement, dated October 22, 2007, among Patriot Coal Corporation, Peabody Holding Company, LLC, Peabody Coal Company, LLC and the Registrant (Incorporated by reference to Exhibit 10.5 of the Registrant’s Current Report on Form 8-K, filed October 25, 2007).

Exhibit No.	Description of Exhibit
10.26	Coal Supply Agreement, dated October 22, 2007, between Patriot Coal Sales LLC and COALSALES II, LLC (Incorporated by reference to Exhibit 10.6 of the Registrant’s Current Report on Form 8-K, filed October 25, 2007).
10.27	Implementation Deed, dated as of August 30, 2011, between PEAMCoal Pty Ltd and Macarthur Coal Limited (Incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K, filed September 2, 2011).
10.28	Amended and Restated Co-Operation and Contribution Agreement, dated as of September 13, 2011, among Peabody Acquisition Co. No. 2 Pty Ltd, ArcelorMittal Netherlands B.V., ArcelorMittal Mining Australasia B.V., PEAMCoal Holdings Pty Ltd and PEAMCoal Pty Ltd. (Incorporated by reference to Exhibit 10.2 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2011).
10.29	Pre-Bid Acceptance Deed, dated as of July 29, 2011, between ArcelorMittal Netherlands B.V. and Peabody Acquisition Co. No.4 Pty Ltd (Incorporated by reference to Exhibit 10.2 of the Registrant's Current Report on Form 8-K, filed August 4, 2011).
10.30	Amended and Restated Deed of Guarantee, dated as of September 13, 2011, among Peabody Energy Corporation, ArcelorMittal S.A., Peabody Acquisition Co. No. 2 Pty Ltd, ArcelorMittal Netherlands B.V., ArcelorMittal Mining Australasia B.V. and PEAMCoal Holdings Pty Ltd. (Incorporated by reference to Exhibit 10.4 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2011).
10.31	CCA Acknowledgement, dated as of August 2, 2011, among Peabody Acquisition Co. No. 2 Pty Ltd, Peabody Acquisition Co. No. 3 Pty Ltd and Peabody Acquisition Co. No. 2 Pty Ltd, ArcelorMittal Netherlands B.V. and ArcelorMittal Mining Australasia B.V. (Incorporated by reference to Exhibit 10.4 of the Registrant's Current Report on Form 8-K, filed August 4, 2011).
10.32*	1998 Stock Purchase and Option Plan for Key Employees of the Registrant (Incorporated by reference to Exhibit 4.9 of the Registrant’s Form S-8 Registration Statement No. 333-105456, filed May 21, 2003).
10.33*	Amendment to the 1998 Stock Purchase and Option Plan for Key Employees of the Registrant (Incorporated by reference to Exhibit 10.4 of the Registrant’s Current Report on Form 8-K, filed October 17, 2007).
10.34*	Amendment No. 2 to the 1998 Stock Purchase and Option Plan for Key Employees of the Registrant (Incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K, filed December 11, 2007).
10.35*	Form of Non-Qualified Stock Option Agreement under the Registrant’s 1998 Stock Purchase and Option Plan for Key Employees (Incorporated by reference to Exhibit 10.15 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2003).
10.36*	Form of Amendment to Non-Qualified Stock Option Agreement under the Registrant’s 1998 Stock Purchase and Option Plan for Key Employees (Incorporated by reference to Exhibit 10.16 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2003).
10.37*	Form of Amendment, dated as of June 15, 2004, to Non-Qualified Stock Option Agreement under the Registrant’s 1998 Stock Purchase and Option Plan for Key Employees (Incorporated by reference to Exhibit 10.65 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004).
10.38*	Form of Incentive Stock Option Agreement under the Registrant’s 1998 Stock Purchase and Option Plan for Key Employees (Incorporated by reference to Exhibit 10.17 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2003).
10.39*	Long-Term Equity Incentive Plan of the Registrant (Incorporated by reference to Exhibit 99.2 of the Registrant’s Form S-8 Registration Statement No. 333-61406, filed May 22, 2001).
10.40*	Amendment to the Registrant's 2001 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.3 of the Registrant's Current Report on Form 8-K, filed October 17, 2007).
10.41*	Form of Non-Qualified Stock Option Agreement under the Registrant’s 2001 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.18 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2003).
10.42*	Form of Performance Unit Award Agreement under the Registrant's 2001 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.19 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 2003).

Exhibit No.	Description of Exhibit
10.43*	Form of Non-Qualified Stock Option Agreement for Outside Directors under the Registrant's 2001 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K, filed December 14, 2005).
10.44*	Form of Restricted Stock Award Agreement for Outside Directors under the Registrant's 2001 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K, filed December 14, 2005).
10.45*	Equity Incentive Plan for Non-Employee Directors of the Registrant (Incorporated by reference to Exhibit 99.3 of the Registrant’s Form S-8 Registration Statement No. 333-61406, filed May 22, 2001).
10.46*	Form of Non-Qualified Stock Option Agreement under the Registrant's Equity Incentive Plan for Non-Employee Directors (Incorporated by reference to Exhibit 10.20 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 2003).
10.47*	Form of Restricted Stock Agreement under the Registrant's Equity Incentive Plan for Non-Employee Directors (Incorporated by reference to Exhibit 10.21 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 2003).
10.48*	The Registrant’s 2004 Long-Term Equity Incentive Plan (Incorporated by reference to Annex A to the Registrant’s Proxy Statement for the 2004 Annual Meeting of Stockholders, filed April 2, 2004).
10.49*	Amendment No. 1 to the Registrant’s 2004 Long Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.67 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2004).
10.50*	Amendment No. 2 to the Registrant’s 2004 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed October 17, 2007).
10.51*	Amendment No. 3 to the Registrant’s 2004 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K, filed October 17, 2007).
10.52*	Amendment No. 4 to the Registrant’s 2004 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed December 11, 2007).
10.53*	Form of Non-Qualified Stock Option Agreement under the Registrant’s 2004 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, filed January 7, 2005).
10.54*	Form of Performance Units Agreement under the Registrant’s 2004 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K, filed January 7, 2005).
10.55*	Form of Performance Units Agreement under the Registrant’s 2004 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.36 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2007).
10.56*	Form of Performance Unit Award Agreement under the Registrant's 2004 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.2 of the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2009).
10.57*	Form of Deferred Stock Units Agreement for Non-Employee Directors (Incorporated by reference to Exhibit 10.43 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 2010).
10.58*	Peabody Energy Corporation 2011 Long-Term Equity Incentive Plan (incorporated by reference to Appendix A of the Registrant's Proxy Statement, filed March 22, 2011).
10.59*†	Form of Non-Qualified Stock Option Agreement under the Registrant's 2011 Long-Term Equity Incentive Plan.
10.60*†	Form of Performance Units Agreement under the Registrant's 2011 Long-Term Equity Incentive Plan.
10.61*†	Form of Restricted Stock Award Agreement under the Registrant's 2011 Long-Term Equity Incentive Plan.
10.62*†	Form of Deferred Stock Unit Agreement under the Registrant's 2011 Long-Term Equity Incentive Plan
10.63*	2009 Amendment entered into effective December 31, 2009 to the Stock Grant Agreement dated as of October 1, 2003 between the Registrant and Gregory H. Boyce (Incorporated by reference to Exhibit 10.45 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2009).
10.64*	2009 Amendment entered into effective December 31, 2009 to the Non-Qualified Stock Option Agreement dated January 2, 2008 between the Registrant and Gregory H. Boyce (Incorporated by reference to Exhibit 10.46 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2009).

Exhibit No.	Description of Exhibit
10.65*	2009 Amendment entered into effective December 31, 2009 to the Non-Qualified Stock Option Agreement dated January 5, 2009 between the Registrant and Gregory H. Boyce (Incorporated by reference to Exhibit 10.47 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2009).
10.66*	2009 Amendment entered into effective December 31, 2009 to the Performance Units Agreement dated January 2, 2008 between the Registrant and Gregory H. Boyce (Incorporated by reference to Exhibit 10.48 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2009).
10.67*	2009 Amendment entered into effective December 31, 2009 to the Performance Units Agreement dated January 5, 2009 between the Registrant and Gregory H. Boyce (Incorporated by reference to Exhibit 10.49 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2009).
10.68*	2010 Amendment entered into effective March 17, 2010, to the 2008 Performance Units Award Agreement dated January 2, 2008 between the Registrant and Gregory H. Boyce (Incorporated by reference to Exhibit 10.3 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010).
10.69*	2010 Amendment entered into effective March 17, 2010, to the 2009 Performance Units Award Agreement dated January 5, 2009 between the Registrant and Gregory H. Boyce (Incorporated by reference to Exhibit 10.4 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010).
10.70*	Amended and Restated Employee Stock Purchase Plan of the Registrant (Incorporated by reference to Exhibit 10.44 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2008).
10.71*	Amendment to the Amended and Restated Employee Stock Purchase Plan of the Registrant (Incorporated by reference to Exhibit 10.51 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2009).
10.72*	Amended and Restated Australian Employee Stock Purchase Plan of the Registrant (Incorporated by reference to Exhibit 10.45 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2008).
10.73*	Amendment to the Amended and Restated Australian Employee Stock Purchase Plan of the Registrant (Incorporated by reference to Exhibit 10.53 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2009).
10.74*	Management Annual Incentive Compensation Plan (Incorporated by reference to Exhibit 10.61 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2007).
10.75*	2008 Management Annual Incentive Compensation Plan (Incorporated by reference to Appendix B to the Registrant’s Proxy Statement for the 2008 Annual Meeting of Shareholders, filed March 27, 2008).
10.76*	The Registrant’s Deferred Compensation Plan (Incorporated by reference to Exhibit 10.30 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2001).
10.77*	First Amendment to the Registrant’s Deferred Compensation Plan (Incorporated by reference to Exhibit 10.49 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2004).
10.78*	Letter Agreement, dated as of March 1, 2005, by and between the Registrant and Gregory H. Boyce (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed March 4, 2005).
10.79*	Restated Employment Agreement effective December 31, 2009 by and between the Registrant and Gregory H. Boyce (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed December 24, 2009).
10.80*	Restated Employment Agreement entered into as of December 31, 2008 by and between the Registrant and Richard A. Navarre (Incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K, filed December 31, 2008).
10.81*	Employment Agreement entered into as of December 31, 2008 by and between the Registrant and Michael C. Crews (Incorporated by reference to Exhibit 10.3 of the Registrant’s Current Report on Form 8-K, filed December 31, 2008).

Exhibit No.	Description of Exhibit
10.82*	Letter Agreement, dated as of December 22, 2006, by and between the Registrant and Eric Ford (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed December 29, 2006).
10.83*	Form of Restricted Stock Agreement -- Exhibit A (Incorporated by reference to Exhibit 10.3 of the Registrant’s Current Report on Form 8-K, filed December 29, 2006).
10.84*	Form of Restricted Stock Agreement -- Exhibit B (Incorporated by reference to Exhibit 10.4 of the Registrant’s Current Report on Form 8-K, filed December 29, 2006).
10.85*	Restated Employment Agreement entered into as of December 31, 2008 by and between the Registrant and Eric Ford (Incorporated by reference to Exhibit 10.5 of the Registrant’s Current Report on Form 8-K, filed December 31, 2008).
10.86*†	Employment Agreement entered into as of March 17, 2011 by and between the Registrant and Jeane L. Hull.
10.87*	Indemnification Agreement, dated as of December 5, 2002, by and between Registrant and William E. James (Incorporated by reference to Exhibit 10.34 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2002).
10.88*	Indemnification Agreement dated as of December 5, 2002, by and between Registrant and Henry E. Lentz (Incorporated by reference to Exhibit 10.35 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2002).
10.89*	Indemnification Agreement dated as of December 5, 2002, by and between Registrant and William C. Rusnack (Incorporated by reference to Exhibit 10.36 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2002).
10.90*	Indemnification Agreement dated as of December 5, 2002, by and between Registrant and Alan H. Washkowitz (Incorporated by reference to Exhibit 10.39 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2002).
10.91*	Indemnification Agreement dated as of December 5, 2002, by and between Registrant and Richard A. Navarre (Incorporated by reference to Exhibit 10.40 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2002).
10.92*	Indemnification Agreement dated as of January 16, 2003, by and between Registrant and Robert B. Karn III (Incorporated by reference to Exhibit 10.41 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2002).
10.93*	Indemnification Agreement dated as of January 16, 2003, by and between Registrant and Sandra A. Van Trease (Incorporated by reference to Exhibit 10.42 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2002).
10.94*	Indemnification Agreement dated as of March 22, 2004, by and between Registrant and William A. Coley (Incorporated by reference to Exhibit 10.53 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
10.95*	Indemnification Agreement dated as of April 8, 2005, by and between the Registrant and Gregory H. Boyce (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed April 14, 2005).
10.96*	Indemnification Agreement dated July 21, 2005, by and between the Registrant and John F. Turner (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed August 5, 2005).
10.97*	Indemnification Agreement dated as of March 2, 2009 by and between the Registrant and M. Frances Keeth (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed on March 2, 2009).
10.98*	Indemnification Agreement dated as of July 23, 2009 by and between Peabody Energy Corporation and Robert A. Malone (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed on July 23, 2009).
10.99*	Indemnification Agreement dated as of June 19, 2008, by and between the Registrant and Michael C. Crews (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, filed July 29, 2008).
10.100*	Indemnification Agreement dated as of October 22, 2008, by and between the Registrant and Eric Ford (Incorporated by reference to Exhibit 10.73 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2008).

Exhibit No.	Description of Exhibit
10.101*†	Indemnification Agreement dated as of March 16, 2011, by and between the Registrant and Jeane L. Hull
10.102*	Peabody Investments Corp. Supplemental Employee Retirement Account (Incorporated by reference to Exhibit 10.1 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007).
21†	List of Subsidiaries.
23†	Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm.
31.1†	Certification of periodic financial report by the Registrant’s Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as amended pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2†	Certification of periodic financial report by the Registrant’s Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as amended pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1†	Certification of periodic financial report pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by the Registrant’s Chief Executive Officer.
32.2†	Certification of periodic financial report pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by the Registrant’s Chief Financial Officer.
95†	Mine Safety Disclosure required by Item 104 of Regulation S-K.
101†	Interactive Data File (Form 10-K for the year ended December 31, 2011 filed in XBRL). The financial information contained in the XBRL-related documents is “unaudited” and “unreviewed.”

*	These exhibits constitute all management contracts, compensatory plans and arrangements required to be filed as an exhibit to this form pursuant to Item 15(a)(3) and 15(b) of this report.
†	Filed herewith.

EX-3.1

Exhibit 3.1

THIRD AMENDED AND RESTATED CERTIFICATE OF INCORPORATION

OF

PEABODY ENERGY CORPORATION

Adopted May 21, 2001

(As Amended Through March 8, 2010)

FIRST: The name of the corporation is Peabody Energy Corporation.

SECOND: The registered office and registered agent of the Corporation in the State of Delaware is Corporation Service Company, 2711 Centerville Road, Suite 400, Wilmington, New Castle County, Delaware 19808.

THIRD: The purposes of the Corporation are to engage in any lawful act or activity for which corporations may be organized under the General Corporation Law of the State of Delaware.

FOURTH: (1) The total number of shares of all classes of stock that the Corporation shall have the authority to issue is 850,000,000 shares, consisting of 800,000,000 shares of Common Stock, par value $0.01 per share (the "Common Stock"), 10,000,000 shares of Preferred Stock, par value $0.01 per share (the "Preferred Stock") and 40,000,000 shares of Series Common Stock, par value $0.01 per share ("Series Common Stock"). The number of authorized shares of any of the Preferred Stock, the Common Stock or the Series Common Stock may be increased or decreased (but not below the number of shares thereof then outstanding) by the affirmative vote of the holders of a majority in voting power of the stock of the Corporation entitled to vote thereon irrespective of the provisions of Section 242(b)(2) of the General Corporation Law of the State of Delaware (or any successor provision thereto), and no vote of the holders of any of the Preferred Stock, the Common Stock or the Series Common Stock voting separately as a class shall be required therefor.

(2) The Board of Directors is hereby expressly authorized, by resolution or resolutions, to provide, out of the unissued shares of Preferred Stock, for series of Preferred Stock and, with respect to each such series, to fix the number of shares constituting such series and the designation of such series, the voting powers (if any) of the shares of such series, and the preferences and relative, participating, optional or other special rights, if any, and any qualifications, limitations or restrictions thereof, of the shares of such series. The powers, preferences and relative, participating, optional and other special rights of each series of Preferred Stock, and the qualifications, limitations or restrictions thereof, if any, may differ from those of any and all other series at any time outstanding.

(3) The Board of Directors is hereby expressly authorized, by resolution or resolutions, to provide, out of the unissued shares of Series Common Stock, for series of Series Common Stock and, with respect to each such series, to fix the number of shares constituting such series and the designation of such series, the voting powers (if any) of the shares of such series, and the preferences and relative, participating, optional or other special rights, if any, and any qualifications, limitations or restrictions thereof, of the shares of such series. The powers, preferences and relative, participating, optional and other special rights of each series of Series Common Stock, and the qualifications, limitations or restrictions thereof, if any, may differ from those of any and all other series at any time outstanding.

(4) (a) Each holder of Common Stock, as such, shall be entitled to one vote for each share of Common Stock held of record by such holder on all matters on which stockholders generally are entitled to vote; provided, however, that, except as otherwise required by law, holders of Common Stock, as such, shall not be entitled to vote on any amendment to this Restated Certificate of Incorporation (including any certificate of designations relating to any series of Preferred Stock or Series Common Stock) that relates solely to the terms of one or more outstanding series of Preferred Stock or Series Common Stock if the holders of such affected series are entitled, either separately or together with the holders of one or more other such series, to vote thereon pursuant to this Certificate of Incorporation (including any certificate of designations relating to any series of Preferred Stock or Series Common Stock) or pursuant to the General Corporation Law of the State of Delaware.

(b) Except as otherwise required by law, holders of any series of Preferred Stock or Series Common Stock, as such, shall be entitled only to such voting rights, if any, as shall expressly be granted thereto by this Certificate of Incorporation (including any certificate of designations relating to such series).

(c) Subject to applicable law and the rights, if any, of the holders of any outstanding series of Preferred Stock or Series Common Stock or any class or series of stock having a preference over or the right to participate with the Common Stock with respect to the payment of dividends, dividends may be declared and paid on the Common Stock at such times and in such amounts as the Board of Directors in its discretion shall determine.

(d) Upon the dissolution, liquidation or winding up of the Corporation, subject to the rights, if any, of the holders of any outstanding series of Preferred Stock or Series Common Stock or any class or series of stock having a preference over or the right to participate with the Common Stock with respect to the distribution of assets of the Corporation upon such dissolution, liquidation or winding up of the Corporation, the holders of the Common Stock, as such, shall be entitled to receive the assets of the Corporation available for distribution to its stockholders ratably in proportion to the number of shares held by them.

FIFTH: The Board of Directors shall be authorized to make, amend, alter, change, add to or repeal the By-Laws of the Corporation in any manner not inconsistent with the laws of the State of Delaware, subject to the power of the stockholders to amend, alter, change, add to or repeal the By-Laws made by the Board of Directors. Notwithstanding anything contained in this Certificate of Incorporation to the contrary, the affirmative vote of the holders of at least 75 percent in voting power of all the shares of the Corporation entitled to vote generally in the election of directors, voting together as a single class, shall be required in order for the stockholders to alter, amend or repeal any provision of the By-Laws which is to the same effect as Article Fifth, Article Seventh, and Article Eighth of this Certificate of Incorporation or to adopt any provision inconsistent therewith.

SIXTH: To the fullest extent permitted by the laws of the State of Delaware:

(1) The Corporation shall indemnify any person (and such person's heirs, executors or administrators) who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding (brought in the right of the Corporation or otherwise), whether civil, criminal, administrative or investigative, and whether formal or informal, including appeals, by reason of the fact that such person is or was a director or officer of the Corporation or, while a director or officer of the Corporation, is or was serving at the request of the Corporation as a director, officer, partner, trustee, employee or agent of another corporation, partnership, joint venture, trust, limited liability company or other enterprise, for and against all expenses (including attorneys' fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by such person or such heirs, executors or administrators in connection with such action, suit or proceeding, including appeals. Notwithstanding the preceding sentence, the Corporation shall be

required to indemnify a person described in such sentence in connection with any action, suit or proceeding (or part thereof) commenced by such person only if the commencement of such action, suit or proceeding (or part thereof) by such person was authorized by the Board of Directors of the Corporation. The Corporation may indemnify any person (and such person's heirs, executors or administrators) who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding (brought in the right of the Corporation or otherwise), whether civil, criminal, administrative or investigative, and whether formal or informal, including appeals, by reason of the fact that such person is or was an employee or agent of the Corporation or is or was serving at the request of the Corporation as a director, officer, partner, trustee, employee or agent of another corporation, partnership, joint venture, trust, limited liability company or other enterprise, for and against all expenses (including attorneys' fees), judgments, fines and amounts

paid in settlement actually and reasonably incurred by such person or such heirs, executors or administrators in connection with such action, suit or proceeding, including appeals.

(2) The Corporation shall promptly pay expenses incurred by any person described in the first sentence of Section (1) of this Article SIXTH in defending any action, suit or proceeding in advance of the final disposition of such action, suit or proceeding, including appeals, upon presentation of appropriate documentation.

(3) The Corporation may purchase and maintain insurance on behalf of any person described in Section (1) of this Article SIXTH against any liability asserted against such person, whether or not the Corporation would have the power to indemnify such person against such liability under the provisions of this Article SIXTH or otherwise.

(4) The provisions of this Article SIXTH shall be applicable to all actions, claims, suits or proceedings made or commenced after the adoption hereof, whether arising from acts or omissions to act occurring before or after its adoption. The provisions of this Article SIXTH shall be deemed to be a contract between the Corporation and each director or officer who serves in such capacity at any time while this Article SIXTH and the relevant provisions of the laws of the State of Delaware and other applicable law, if any, are in effect, and any repeal or modification hereof shall not affect any rights or obligations then existing with respect to any state of facts or any action, suit or proceeding then or theretofore existing, or any action, suit or proceeding thereafter brought or threatened based in whole or in part on any such state of facts. If any provision of this Article SIXTH shall be found to be invalid or limited in application by reason of any law or regulation, it shall not affect the validity of the remaining provisions hereof. The rights of indemnification provided in this Article SIXTH shall neither be exclusive of, nor be deemed in limitation of, any rights to which an officer, director, employee or agent may otherwise be entitled or permitted by contract, this Third Amended and Restated Certificate of Incorporation, vote of stockholders or directors or otherwise, or as a matter of law, both as to actions in such person's official capacity and actions in any other capacity while holding such office, it being the policy of the Corporation that indemnification of any person whom the Corporation is obligated to indemnify pursuant to the first sentence of Section (1) of this Article SIXTH shall be made to the fullest extent permitted by law.

(5) For purposes of this Article SIXTH, references to "other enterprises" shall include employee benefit plans; references to "fines" shall include any excise taxes assessed on a person with respect to an employee benefit plan; and references to "serving at the request of the Corporation" shall include any service as a director, officer, employee or agent of the Corporation which imposes duties on, or involves services by, such director, officer, employee, or agent with respect to an employee benefit plan, its participants, or beneficiaries.

(6) A director of the Corporation shall not be liable to the Corporation or its stockholders for monetary damages for breach of fiduciary duty as a director, except to the extent such exemption from liability or limitation thereof is not permitted under the General Corporation Law of the State of Delaware as the same exists or may hereafter be amended. Any amendment, modification or repeal of the foregoing sentence shall not adversely affect any right or protection of a director of the Corporation hereunder in respect of any act or omission occurring prior to the time of such amendment, modification or repeal.

SEVENTH: (1) The business and affairs of the Corporation shall be managed by or under the direction of a Board of Directors consisting of not less than three directors, the exact number of directors to be determined from time to time by resolution adopted by a majority of the Board of Directors.

At the 2009 annual meeting of stockholders, the successors of the directors whose terms expire at that meeting shall be elected for a term expiring at the 2010 annual meeting of stockholders and shall hold office until the next succeeding annual meeting and until his or her successor shall be elected and shall qualify, but subject to prior death, resignation, retirement, disqualification or removal from office; at the 2010 annual meeting of stockholders, the successors of the directors whose terms expire at that meeting shall be elected for a term expiring at the 2011 annual meeting of stockholders and shall hold office until the next succeeding annual meeting and until his or her successor shall be elected and shall qualify, but subject to prior death, resignation, retirement, disqualification or removal from office; and at each annual meeting of stockholders thereafter, the directors shall be elected for terms expiring at the next annual meeting of stockholders and shall hold office until the next succeeding annual meeting and until his or her successor shall be elected and shall qualify, but subject to prior death, resignation, retirement, disqualification or removal from office.

Any newly created directorship on the Board of Directors that results from an increase in the number of directors and any vacancy occurring in the Board of Directors shall be filled only by a majority of the directors then in office, although less than a quorum, or by a sole remaining director. If any applicable provision of the General Corporation Law of the State of Delaware expressly confers power on stockholders to fill such a directorship at a special meeting of stockholders, such a directorship may be filled at such meeting only by the affirmative vote of at least 75 percent of the voting power of all shares of the Corporation entitled to vote generally in the election of directors voting as a single class. Any director elected to fill a vacancy not resulting from an increase in the number of directors shall have the remaining term as that of his or her predecessor. Directors may be removed only for cause, and only by the affirmative vote of at least 75 percent in voting power of all shares of the Corporation entitled to vote generally in the election of directors, voting as a single class.

(2) Notwithstanding the foregoing, whenever the holders of any one or more series of Preferred Stock or Series Common Stock issued by the Corporation shall have the right, voting separately as a series or separately as a class with one or more such other series, to elect directors at an annual or special meeting of stockholders, the election, term of office, removal, filling of vacancies and other features of such directorships shall be governed by the terms of this Certificate of Incorporation (including any certificate of designations relating to any series of Preferred Stock or Series Common Stock) applicable thereto.

(3) Unless and except to the extent that the By-Laws of the Corporation shall so require, the election of the directors of the Corporation need not be by written ballot.

EIGHTH: Any action required or permitted to be taken by the holders of the Common Stock of the Corporation must be effected at a duly called annual or special meeting of such holders and may not be effected by any consent in writing by such holders. Except as otherwise required by law and subject to the rights of the holders of any series of Preferred Stock or Series Common Stock, special meetings of stockholders of the Corporation may be called only by the Chief Executive Officer of the Corporation or by the Board of Directors pursuant to a resolution approved by the Board of Directors. Meetings of stockholders may be held within or without the State of Delaware, as the By-Laws of the Corporation may provide. The books of the Corporation may be kept outside the State of Delaware at such place or places as may be designated by the Board of Directors or in the By-Laws of the Corporation.

NINTH: Notwithstanding anything contained in this Certificate of Incorporation to the contrary, the affirmative vote of the holders of at least 75 percent in voting power of all the shares of the Corporation entitled to vote generally in the election of directors, voting together as a single class, shall be required to alter, amend or repeal Article Fifth, Article Seventh, Article Eighth or this Article Ninth or to adopt any provision inconsistent therewith.

EX-10.2

Exhibit 10.2

AMENDMENT NO. 1 TO CREDIT AGREEMENT

Dated as of October 20, 2011

This AMENDMENT NO. 1 TO CREDIT AGREEMENT (this “Amendment No. 1”) is made by and among PEABODY ENERGY CORPORATION, a Delaware corporation (the “US Borrower”), PEABODY HOLLAND B.V., a private company organized under the laws of the Netherlands (the “Dutch Borrower” and together with the US Borrower, the “Borrowers”), the Lenders (as defined below) and BANK OF AMERICA, N.A., as Administrative Agent (the “Administrative Agent”).

PRELIMINARY STATEMENTS:

1.        The Borrowers, each lender from time to time party thereto (collectively, the “Lenders” and individually, a “Lender”) and the Administrative Agent have entered into that certain Credit Agreement, dated as of June 18, 2010 (the “Credit Agreement”); capitalized terms used and not otherwise defined herein have the meanings assigned to such terms in the Credit Agreement.

2.        The Borrowers have requested that the Lenders amend the Credit Agreement to, among other things, modify certain negative covenants.

3.        Subject to the terms and conditions set forth below, and in consideration of certain agreements of the Borrowers set forth herein and of the Loan Parties in the accompanying Consent, the requisite Lenders are willing to agree to this Amendment No. 1.

NOW, THEREFORE, in consideration of the premises and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

SECTION 1 Amendments to the Credit Agreement. Upon the satisfaction of the applicable conditions precedent set forth in Section 2, the Credit Agreement is hereby amended as follows:

(a)    Section 1.01 is hereby amended by inserting the following sentence immediately after the last sentence of the definition of “Indebtedness” as follows:

“The amount of any indebtedness of a Joint Venture secured by a Lien on property owned or being purchased by the US Borrower or its Restricted Subsidiaries as of any date shall be deemed to be the lower of (a) an amount equal to the stated or determinable amount of the indebtedness that is secured by such Lien and (b) the maximum amount for which the US Borrower or its Restricted Subsidiaries may be liable (which may be determined with reference to the fair market value of the property securing such indebtedness as reasonably determined by the US Borrower in good faith) pursuant to the terms of such indebtedness.”

(b)    Section 1.01 is hereby further amended by inserting the following phrase immediately prior to the period “.” at the end of the first sentence in the definition of “Subsidiary” as follows:

“(it being understood that Middlemount Coal Pty Ltd shall not constitute a Subsidiary of the Borrower or its Subsidiaries hereunder unless the Borrower shall elect in a writing delivered to the Administrative Agent, based on a change in the voting powers of the joint venture partners of Middlemount Coal Pty Ltd, that Middlemount Coal Pty Ltd shall constitute a Subsidiary of the Borrower or its Subsidiaries hereunder)”

(c)    Section 1.01 is hereby further amended by inserting the following phrase immediately prior to the period “.” at the end of the definition of “Swap Termination Value” as follows:

“(it being understood that any such termination values and mark-to-market values shall take into account any assets posted as collateral or security for the benefit of a party to the Swap Contract)”

(c)    Section 2.10 is hereby amended by inserting the following text immediately following the phrase “All computations of interest for Base Rate Loans” and immediately prior to the phrase “and of Fronting Fees” at the beginning of Section 2.10 as follows:

“, where the rate of interest is calculated on the basis of the prime rate,”

(d)    Sections5.17 and 6.09 are hereby amended by (i) replacing the word “Subsidiaries” with the words “Restricted Subsidiaries” and (ii) replacing the word “Subsidiary” with the words “Restricted Subsidiary”.

(e)    Section 7.01(n) is hereby amended and restated in its entirety as follows:

“(n)    (1) Production Payments, royalties, dedication of reserves under supply agreements or similar rights or interests granted, taken subject to, or otherwise imposed on properties or (2) cross charges, Liens or security arrangements entered into in respect of a Joint Venture for the benefit of a participant, manager or operator of such Joint Venture, in each case, consistent with normal practices in the mining industry;”

(f)    Section 7.01(t) is hereby amended and restated in its entirety as follows:

“(t)    Liens on assets of the US Borrower and its Restricted Subsidiaries so long as the aggregate amount of Indebtedness and other obligations secured thereby does not exceed, at the time any such Liens are assumed or incurred by the US Borrower or one of its Restricted Subsidiaries and thereafter, 10% of Tangible Assets of the US Borrower and its Restricted Subsidiaries (including, for avoidance of doubt, any Tangible Assets acquired by the US Borrower or its Restricted Subsidiaries at such time).”

(g)    Section 7.02(e) is hereby amended and restated in its entirety as follows:

“(e)    (1) Investments in the nature of Production Payments, royalties, dedication of reserves under supply agreements or similar rights or interests granted, taken subject to, or otherwise imposed on properties or (2) cross charges, Liens or security arrangements entered into in respect of a Joint Venture for the benefit of a participant, manager or operator of such Joint Venture, in each case, consistent with normal practices in the mining industry;”

(h)    Section 7.02(l) is hereby amended by replacing the words “Section 7.03(l)” in the penultimate line thereof with the words “Section 7.02(l)”.

(i)    Section 8.01(e) is hereby amended by inserting the following text immediately following the phrase “in excess of 10 days;” and immediately prior to the word “or” at the end of Section 8.01(e) as follows:

“and, provided, further, that no Default or Event of Default shall exist under this paragraph as a result of a default, review event or other event arising from a change of control, delisting or similar event under any Indebtedness of Macarthur Coal Ltd. or any of its Subsidiaries until 30 days (which 30 day period shall be inclusive of, and not in addition to, the 10-day period referred to in the immediately preceding proviso) have elapsed following the close of the offer period for the takeover bid for Macarthur Coal Ltd;”

(j)    Section 9.01 is hereby amended and restated in its entirety as follows:

“9.01.    Appointment and Authority. Each of the Lenders and the L/C Issuer hereby irrevocably appoints Bank of America to act on its behalf as the Administrative Agent hereunder and under the other Loan Documents and authorizes the Administrative Agent to take such actions on its behalf and to exercise such powers as are delegated to the Administrative Agent by the terms hereof or thereof, together with such actions and powers as are reasonably incidental thereto. Except with respect to Section 9.06 and Section 9.10, the provisions of this Article are solely for the benefit of the Administrative Agent, the Lenders and the

L/C Issuer, and neither the US Borrower, the Dutch Borrower nor any other Loan Party shall have rights as a third party beneficiary of any of such provisions.”

(k)    Schedule 7.01 of the Credit Agreement is hereby amended and restated in its entirety by substituting in lieu thereof the schedule attached hereto as Exhibit A and the Liens set forth therein shall be deemed to be existing as of June 18, 2010 for purposes of Section 7.01(b).

(l)    Schedule 7.02 of the Credit Agreement is hereby amended and restated in its entirety by substituting in lieu thereof the schedule attached hereto as Exhibit B and the Investments set forth therein shall be deemed to be outstanding as of June 18, 2010 for purposes of Section 7.02(f).

(m)    Schedule 7.03 of the Credit Agreement is hereby amended and restated in its entirety by substituting in lieu thereof the schedule attached hereto as Exhibit C and the Indebtedness set forth therein shall be deemed to be outstanding as of June 18, 2010 for purposes of Section 7.03(b).

SECTION 2 Conditions to Effectiveness of Amendment. The effectiveness of the amendments contained in Section 1 of this Amendment No. 1 is conditioned upon satisfaction of the following conditions precedent:

(a)The Administrative Agent shall have (i) received counterparts of this Amendment No. 1 signed by the Borrowers and the Required Lenders and counterparts of the Consent of Loan Parties attached hereto (the “Consent”) signed by the Loan Parties party thereto and (ii) acknowledged this Amendment No. 1 in writing; and

(b)Each of the representations and warranties in Section 3 below shall be true and correct in all material respects as of the date on which this Amendment No. 1 becomes effective, except to the extent that such representations and warranties specifically refer to an earlier date, in which case they shall be true and correct in all material respects as of such earlier date.

SECTION 3 Representations and Warranties. The US Borrower and the Dutch Borrower each represents and warrants to the Administrative Agent and the Lenders as follows:

(a)    Authority. Each of the Borrowers and the Loan Parties party to the Consent has the requisite corporate, limited liability or other such power and authority to execute and deliver this Amendment No. 1 and the Consent, as applicable, and to perform its obligations hereunder and under the Loan Documents (as modified hereby). The execution, delivery and performance by the Borrowers and each other Loan Party party to the Consent of this Amendment No. 1 (as applicable), the Consent (as applicable), the Loan Documents (as modified hereby) and the transactions contemplated hereby and thereby have been duly approved by all necessary corporate action of such Person and no other corporate proceedings on the part of such Person are necessary to consummate such transactions.

(b)    No Legal Bar. The execution and delivery of this Amendment No. 1 by the Borrowers and of the Consent by each Loan Party party thereto, and the performance of the Credit Agreement and each other Loan Document, as amended hereby, by the Borrowers and each other Loan Party party thereto will not violate any Requirement of Law or any Contractual Obligation applicable to or binding on the Borrowers, any Restricted Subsidiary or any of their respective properties or assets, except to the extent that such violation could not reasonably be expected to have a Material Adverse Effect.

(c)Enforceability. This Amendment No. 1 has been duly executed and delivered by the Borrowers. The Consent has been duly executed and delivered by each Loan Party party thereto. This Amendment No. 1 and the Consent is the legal, valid and binding obligation of each such Loan Party party thereto, enforceable against each Loan Party that is party thereto in accordance with its terms, subject to applicable bankruptcy, insolvency, fraudulent conveyance, reorganization, moratorium and other Laws relating to or affecting creditors' rights generally, general principles of equity, regardless of whether considered in a proceeding in equity or at law and an implied covenant of good faith and fair dealing.

(d)Representations and Warranties. The representations and warranties contained in each Loan Document (other than any such representations and warranties that, by their terms, are specifically made as of a date other than the date hereof) are true and correct in all material respects on and as of the date hereof as though made on and as of the date hereof.

(e)No Default. Both immediately before and after giving effect to the amendments set forth in Section 1 hereof no event has occurred and is continuing that constitutes a Default or Event of Default.

SECTION 4 Reference to and Effect on Credit Agreement.

(a)    Upon and after the effectiveness of this Amendment No. 1, each reference in the Credit Agreement to “this Agreement”, “hereunder”, “hereof” or words of like import referring to the Credit Agreement, and each reference in the other Loan Documents to “the Credit Agreement”, “thereunder”, “thereof” or words of like import referring to the Credit Agreement, shall mean and be a reference to the Credit Agreement as modified hereby.

(b)    Except as specifically modified above, the Credit Agreement and the other Loan Documents are and shall continue to be in full force and effect and are hereby in all respects ratified and confirmed.

(c)    The execution, delivery and effectiveness of this Amendment No. 1 shall not operate as a waiver of any right, power or remedy of the Administrative Agent or any Lender under any of the Loan Documents, nor, except as expressly provided herein, constitute a waiver or amendment of any provision of any of the Loan Documents. On and after the effectiveness of this Amendment No. 1, this Amendment No. 1 shall for all purposes constitute a Loan Document.

SECTION 5 Counterparts.This Amendment No. 1 may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed and delivered shall be deemed to be an original and all of which taken together shall constitute one and the same agreement. Delivery of an executed counterpart of a signature page to this Amendment No. 1 or such Consent by facsimile or other electronic imaging means shall be effective as delivery of a manually executed counterpart of this Amendment No. 1 or such Consent, as applicable.

SECTION 6 Severability. Any provision of this Amendment No. 1 that is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.

SECTION 7 Governing Law.This Amendment No. 1 shall be governed by, and construed in accordance with, the laws of the State of New York.

SECTION 8 Waiver of Jury Trial. EACH OF THE PARTIES HERETO IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, TRIAL BY JURY IN ANY ACTION OR PROCEEDING WITH RESPECT TO THIS AMENDMENT NO. 1 OR ANY OTHER LOAN DOCUMENT.

[Signature Page to Follow]

IN WITNESS WHEREOF, the parties hereto have caused this Amendment No. 1 to be executed by their respective officers thereunto duly authorized, as of the date first written above.

PEABODY ENERGY CORPORATION,

a Delaware corporation

/s/ Carey J. Dubois

By:        

Name: Carey J. Dubois

Title: Vice President and Treasurer

PEABODY HOLLAND B.V.,

a private company organized under the law of the Netherlands

/s/ Kenneth L. Wagner

By:        

Name: Kenneth L. Wagner

Title: Authorized Signer Pursuant to Power

of Attorney

BANK OF AMERICA, N.A.,

as Administrative Agent

/s/ Matthew S. Hichborn

By:        

Name: Matthew S. Hichborn

Title: Assistant Vice President

CONSENT OF LOAN PARTIES

Dated as of October 20, 2011

The undersigned, as US Subsidiary Guarantors under the “US Subsidiary Guaranty” (as such term is defined in and under the Credit Agreement referred to in the foregoing Amendment No. 1), each hereby consents and agrees to the foregoing Amendment No. 1 and hereby confirms and agrees that (i) the US Subsidiary Guaranty is, and shall continue to be, in full force and effect and is hereby ratified and confirmed in all respects except that, upon the effectiveness of said Amendment No. 1, the reference in the US Subsidiary Guaranty to the “Credit Agreement,” “thereunder,” “thereof” and words of like import referring to the Credit Agreement, shall mean and be a reference to the Credit Agreement as modified by said Amendment No. 1, and (ii) the US Subsidiary Guaranty does, and shall continue to, constitute a guaranty of the US Borrower Obligations as defined in the US Subsidiary Guaranty.

[Signature Page to Follow]

IN WITNESS WHEREOF, the parties hereto have caused this Consent of Loan Parties to be executed by their respective officers thereunto duly authorized, as of the date first written above.

EACH OF THE US GUARANTORS LISTED

ON SCHEDULE I HERETO

/s/ Carey J. Dubois

By:    ____________________________

Name: Carey J. Dubois

Title: Vice President and Treasurer

SCHEDULE I

LIST OF US GUARANTORS

American Land Development, LLC

American Land Holdings of Colorado, LLC

American Land Holdings of Illinois, LLC

American Land Holdings of Indiana, LLC

American Land Holdings of Kentucky, LLC

American Land Holdings of West Virginia, LLC

Arid Operations Inc.

Big Ridge, Inc.

Big Sky Coal Company

Black Hills Mining Company, LLC

BTU Western Resources, Inc.

Caballo Grande, LLC

Caseyville Dock Company, LLC

Central States Coal Reserves of Illinois, LLC

Central States Coal Reserves of Indiana, LLC

Century Mineral Resources, Inc.

Coal Reserve Holding Limited Liability Company No. 1

COALSALES II, LLC

Colorado Yampa Coal Company

Conservancy Resources, LLC

Cottonwood Land Company

Cyprus Creek Land Company

Cyprus Creek Land Resources, LLC

Dyson Creek Coal Company, LLC

Dyson Creek Mining Company, LLC

El Segundo Coal Company, LLC

Elkland Holdings, LLC

Falcon Coal Company, LLC

Gallo Finance Company

Gold Fields Chile, LLC

Gold Fields Mining, LLC

Gold Fields Ortiz, LLC

Hayden Gulch Terminal, LLC

Highwall Mining Services Company

Hillside Recreational Lands, LLC

HMC Mining, LLC

Illinois Land Holdings, LLC

Independence Material Handling, LLC

James River Coal Terminal, LLC

Juniper Coal Company

Kayenta Mobile Home Park, Inc.

Kentucky Syngas, LLC

Lively Grove Energy, LLC

Lively Grove Energy Partners, LLC

Marigold Electricity, LLC

Midco Supply and Equipment Corporation

Midwest Coal Acquisition Corp.

Midwest Coal Reserves of Illinois, LLC

Midwest Coal Reserves of Indiana, LLC

Moffat County Mining, LLC

Mustang Energy Company, L.L.C.

New Mexico Coal Resources, LLC

Pacific Export Resources, LLC

Peabody America, Inc.

Peabody Archveyor, L.L.C.

Peabody Arclar Mining, LLC

Peabody Bear Run Mining, LLC

Peabody Bear Run Services, LLC

Peabody Caballo Mining, LLC

Peabody Cardinal Gasification, LLC

Peabody COALSALES, LLC

Peabody COALTRADE, LLC

Peabody COALTRADE International (CTI), LLC

Peabody Colorado Operations, LLC

Peabody Colorado Services, LLC

Peabody Coulterville Mining, LLC

Peabody Development Company, LLC

Peabody Electricity, LLC

Peabody Employment Services, LLC

Peabody Energy Generation Holding Company

Peabody Energy Investments, Inc.

Peabody Energy Solutions, Inc.

Peabody Gateway North Mining, LLC

Peabody Gateway Services, LLC

Peabody Holding Company, LLC

Peabody Illinois Services, LLC

Peabody Indiana Services, LLC

Peabody International Investments, Inc.

Peabody International Services, Inc.

Peabody Investments Corp.

Peabody Midwest Management Services, LLC

Peabody Midwest Mining, LLC

Peabody Midwest Operations, LLC

Peabody Midwest Services, LLC

Peabody Natural Gas, LLC

Peabody Natural Resources Company

Peabody New Mexico Services, LLC

Peabody Operations Holding, LLC

Peabody Powder River Mining, LLC

Peabody Powder River Operations, LLC

Peabody Powder River Services, LLC

Peabody PowerTree Investments, LLC

Peabody Recreational Lands, L.L.C.

Peabody Rocky Mountain Management Services, LLC

Peabody Rocky Mountain Services, LLC

Peabody Sage Creek Mining, LLC

Peabody School Creek Mining, LLC

Peabody Services Holdings, LLC

Peabody Southwest, LLC

Peabody Southwestern Coal Company

Peabody Terminal Holding Company, Inc.

Peabody Terminals, LLC

Peabody Twentymile Mining, LLC

Peabody Venezuela Coal Corp.

Peabody Venture Fund, LLC

Peabody-Waterside Development, L.L.C.

Peabody Western Coal Company

Peabody Wild Boar Mining, LLC

Peabody Wild Boar Services, LLC

Peabody Williams Fork Mining, LLC

Peabody Wyoming Gas, LLC

Peabody Wyoming Services, LLC

PEC Equipment Company, LLC

Point Pleasant Dock Company, LLC

Pond River Land Company

Porcupine Production, LLC

Porcupine Transportation, LLC

Riverview Terminal Company

Sage Creek Holdings, LLC

School Creek Coal Resources, LLC

Seneca Coal Company, LLC

Shoshone Coal Corporation

Star Lake Energy Company, L.L.C.

Sugar Camp Properties, LLC

Thoroughbred Generating Company, LLC

Thoroughbred Mining Company, LLC

Twentymile Coal, LLC

West Roundup Resources, LLC

EX-10.59

Exhibit 10.59

____ Award 2011 Plan

NON-QUALIFIED STOCK OPTION AGREEMENT

THIS AGREEMENT (the “Agreement”), dated ____________ (the “Grant Date”), is made by and between PEABODY ENERGY CORPORATION, a Delaware corporation (the “Company”), and the undersigned employee of the Company or a Subsidiary (as defined below) or an Affiliate (as defined below) of the Company (“Optionee”).

WHEREAS, the Company wishes to afford the Optionee the opportunity to purchase shares of its $0.01 par value Common Stock (“Common Stock”);

WHEREAS, the Company wishes to carry out the Plan (as hereinafter defined), the terms of which are hereby incorporated by reference and made a part of this Agreement; and

WHEREAS, the Committee (as hereinafter defined) appointed to administer the Plan, has determined that it would be to the advantage and best interest of the Company and its stockholders to grant the non-qualified stock option provided for herein to the Optionee as an incentive for increased efforts during his or her term of office with the Company or its Subsidiaries or Affiliates, and has advised the Company thereof and instructed the undersigned officers to issue said Options;

NOW, THEREFORE, in consideration of the mutual covenants herein contained and other good and valuable consideration, receipt of which is hereby acknowledged, the parties hereto agree as follows:

ARTICLE I

DEFINITIONS

Whenever the following terms are used in this Agreement, they shall have the meaning specified below. Capitalized terms not otherwise defined in this Agreement shall have the meanings specified in the Plan.

Section 1.1 - “Affiliate” shall mean any Person that (i) is directly or indirectly controlling, controlled by, or under common control with, the Company and (ii) would, together with the Company, be classified as the “service recipient” (as defined in the regulations under Code Section 409A) with respect to the Optionee. For the purposes of this definition, the term “control” (including, with correlative meanings, the terms “controlling”, “controlled by” and “under common control with”), as applied to any Person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of that Person, whether through the ownership of voting securities, by contract or otherwise.

Section 1.2 - “Cause” shall mean “Cause” as defined in the Optionee's employment agreement with the Company.

Section 1.3 - “Change of Control” shall have meaning given to such term in Section 17(m) of the Plan.

Section 1.4 - “Change of Control Price” means the lower of (i) the Fair Market Value of a share of Common Stock as of the date of the Change in Control, or (ii) the price paid per share of Common Stock as part of the transaction which constitutes the Change of Control.

Section 1.5 - “Code” shall mean the Internal Revenue Code of 1986, as amended.

Section 1.6 - “Committee” shall mean the Administrator.

Section 1.7 - “Disability” shall have the meaning given to such term in Section 17(n) of the Plan.

Sections 1.8 - “Good Reason” shall mean “Good Reason” as defined in the Optionee's employment agreement with the Company.

Section 1.9 - “Option” shall mean the non-qualified stock option to purchase Common Stock granted under this Agreement.

Section 1.10 - “Permitted Transferee” shall mean any child, stepchild, grandchild, parent, stepparent, grandparent, spouse, former spouse, sibling, niece, nephew, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law of the Optionee (including adoptive relationships); any person sharing the Optionee's household (other than a tenant or employee); any trust in which the Optionee and any of these persons have all of the beneficial interest; any foundation in which the Optionee and any of these persons control the management of the assets; any corporation, partnership, limited liability company or other entity in which the Optionee or any of these persons are the direct and beneficial owners of all of the equity interests (provided that the Optionee and these other persons agree in writing to remain the direct and beneficial owners of all such equity interests); and any personal representative of the Optionee upon the Optionee's death for purposes of administration of the Optionee's estate or upon the Optionee's incompetence for purposes of the protection and management of the assets of the Optionee.

Section 1.11 - “Person” shall mean an individual, partnership, corporation, business trust, joint stock company, trust, unincorporated association, joint venture, governmental authority or other entity of whatever nature.

Section 1.12 - “Plan” shall mean the Peabody Energy Corporation 2011 Long-Term Equity Incentive Plan, as from time to time amended.

Section 1.13 - Pronouns ‑ The masculine pronoun shall include the feminine and neuter, and the singular the plural, where the context so indicates.

Section 1.14 - “Retirement” shall mean a Termination of Employment on or after age 55 with at least ten (10) years of service with the Company.

Section 1.15 - “Subsidiary” shall mean any corporation that (i) is in an unbroken chain of corporations beginning with the Company if each of the corporations, or group of commonly controlled corporations, other than the last corporation in the unbroken chain, then owns stock possessing 50% or more of the total combined voting power of all classes of stock in one of the other corporations in such chain and (ii) would, together with the Company, be classified as the “service recipient” (as defined in the regulations under Code Section 409A) with respect to the Optionee.

Section 1.16 - “Termination of Employment” shall mean a termination of the Optionee's employment with the Company, a Subsidiary or an Affiliate (regardless of the reason therefor).

ARTICLE II

GRANT OF OPTIONS

Section 2.1 - Grant of Options. For good and valuable consideration, the Company hereby grants to the Optionee an option to purchase any part or all of the number of shares of Common Stock set forth on the signature page hereof upon the terms and subject to the conditions set forth in this Agreement.

Section 2.2 - Exercise Price. The exercise price of the shares of Common Stock covered by the Option shall be such amount per share as set forth on the signature page hereof (which shall not be less than the Fair Market Value (as determined in accordance with guidance issued under Code Section 409A) of a share of Common Stock on the Grant Date), subject to adjustment pursuant to Section 2.4 herein without commission or other charge.

Section 2.3 - No Obligation of Employment. Nothing in this Agreement or in the Plan shall confer upon the Optionee any right to continue in the employ of the Company or any Subsidiary or Affiliate, or interfere with or restrict in any way the rights of the Company and its Subsidiaries or Affiliates, which are hereby expressly reserved, to terminate the employment of the Optionee at any time for any reason whatsoever, with or without Cause.

Section 2.4 - Adjustments in Options. In the event of the occurrence of one of the corporate transactions or other events listed in Section 12(a) of the Plan, the Committee shall make such substitution or adjustment as provided in Section 12(a) in order to equitably reflect such corporate transaction or other event. Any such adjustment made by the Committee shall be final and binding upon the Optionee, the Company and all other interested persons.

ARTICLE III

EXERCISABILITY OF OPTIONS

Section 3.1 - Options. Unless otherwise provided in this Agreement, this Option shall become exercisable as follows:

Date Option Becomes Exercisable	Percentage of shares of Common Stock as to which Option Is Exercisable
First anniversary of Grant Date	33.33%
Second anniversary of Grant Date	66.67%
Third anniversary of Grant Date	100%

This Option shall become exercisable, pursuant to the schedule above, with respect to the nearest whole number of shares of Common Stock, as determined by the Committee in its sole discretion.

Section 3.2 - Acceleration Events. Notwithstanding anything in this Article III to the contrary, this Option shall become exercisable with respect to 100% of the shares of Common Stock early (but only to the extent such Option has not otherwise terminated or become exercisable) upon (i) a Termination of Employment on account of death or Disability of the Optionee, or (ii) a Change of Control.

Section 3.3 - Effect of Termination of Employment. Except as otherwise provided in Section 3.2, the Option shall not become exercisable as to any additional shares of Common Stock following a Termination of Employment, and the portion of the Option which is then unexercisable shall terminate immediately.

Section 3.4 - Expiration of Options. This Option may not be exercised to any extent by the Optionee after the first to occur of the following events:

(a) The tenth anniversary of the date hereof; or

(b) The first anniversary of the date of Termination of Employment (i) by reason of death or Disability, (ii) by the Company without Cause, or (iii) by the Optionee for Good Reason; or

(c) The fifth anniversary of the date of Termination of Employment by reason of Retirement; or

(d) The date of a Termination of Employment by the Company for Cause or by the Optionee without Good Reason; or

(e) The date of a Termination of Employment for any reason if the Option exercise price per share of Common Stock, as set forth on the signature page hereof, is higher than the Fair Market Value per share of Common Stock on the date of the Termination of Employment; or

(f) Upon a Change of Control, if either

(i)     the Committee terminates this Option by paying the Optionee an amount equal to the product of (x) the difference between the Change of Control Price and the Exercise Price (unless the Exercise Price is greater than the Change of Control Price, in which case this Option shall be terminated) and (y) the aggregate number of shares of Common Stock for which the Option is exercisable, or

(ii)     the Optionee is permitted to exercise his or her Option prior to the Change of Control.

ARTICLE IV

EXERCISE OF OPTION

Section 4.1 - Person Eligible to Exercise. During the lifetime of the Optionee, only he or she, or a Permitted Transferee, or in the event of Disability his or her committee or conservator, may exercise this Option or any portion thereof. After the death of the Optionee, the Option may, prior to the time when the Option becomes unexercisable under Section 3.4, be exercised by his or her beneficiary or estate or Permitted Transferee.

Section 4.2 - Partial Exercise. Any exercisable portion of this Option or the entire Option, if then wholly exercisable, may be exercised in whole or in part at any time prior to the time when the Option or portion thereof becomes unexercisable under Section 3.4; provided, however, that any partial exercise shall be for whole shares of Common Stock only.

Section 4.3 - Manner of Exercise. The Option, or any exercisable portion thereof, may be exercised solely by delivery to the Secretary of the Company or designee or his or her office (or any third party designated by the Secretary of the Company to that effect) of all of the following prior to the time when the Option or such portion becomes unexercisable under Section 3.4:

(a) Notice in writing signed by the Optionee or another person then entitled to exercise the Option or portion thereof, stating that the Option or portion thereof is thereby exercised, such notice complying with all applicable rules established by the Committee;

(b) Full payment (in cash, in shares of Common Stock, by check or by a combination thereof) for the shares with respect to which such Option or portion thereof is exercised;

(c) Full payment to the Company of all amounts which, under federal, state or local law, it is required to withhold upon exercise of the Option; and

(d) In the event the Option or portion thereof is exercised pursuant to Section 4.1 by any person or persons other than the Optionee, appropriate proof of the right of such person or persons to exercise the Option.

Section 4.4 - Conditions to Issuance of Stock Certificates. The shares of Common Stock deliverable upon the exercise of an Option, or any portion thereof, may be either previously authorized but unissued shares or issued shares that have been reacquired by the Company. Such shares shall be fully paid and nonassessable. The Company shall not be required to issue or deliver any certificate or certificates for shares of Common Stock purchased upon the exercise of an Option or portion thereof prior to fulfillment of all of the following conditions:

(a) The obtaining of approval or other clearance from any state or federal governmental agency that the Committee, in its absolute discretion, determines to be necessary or advisable; and

(b) The lapse of such reasonable period of time following the exercise of the Option as the Committee may from time to time establish for reasons of administrative convenience.

Section 4.5 - Rights as Stockholder. The holder of an Option shall not be, and shall not have any of the rights or privileges of, a stockholder of the Company in respect of any shares purchasable upon the exercise of the Option or any portion thereof unless and until certificates representing such shares shall have been issued by the Company to such holder.

ARTICLE V

MISCELLANEOUS

Section 5.1 - Administration. The Committee has the power to interpret the Plan and this Agreement and to adopt such rules for the administration, interpretation and application of the Plan as are consistent therewith and to interpret or revoke any such rules. All actions taken and all interpretations and determinations made by the Committee shall be final and binding upon the Optionee, the Company and all other interested persons. No member of the Committee shall be personally liable for any action, determination or interpretation made in good faith with respect to the Plan or the Options. In its absolute discretion, the Board may at any time and from time to time exercise any and all rights and duties of the Committee under the Plan and this Agreement.

Section 5.2 - Options Not Transferable. Neither the Option nor any interest or right therein or part thereof shall be liable for the debts, contracts or engagements of the Optionee or his or her successors in interest or shall be subject to disposition by transfer, alienation, anticipation, pledge, encumbrance, assignment or any other means whether such disposition be voluntary or involuntary or by operation of law by judgment, levy, attachment, garnishment or any other legal or equitable proceedings (including bankruptcy), and any attempted disposition thereof shall be null and void and of no effect; provided, however, that this Section 5.2 shall not prevent transfers by will or by the applicable laws of descent and distribution or transfers without consideration to a Permitted Transferee to the extent permitted by the Plan.

Section 5.3 - Shares to Be Reserved. The Company shall at all times during the term of the Option reserve and keep available such number of shares of Common Stock as will be sufficient to satisfy the requirements of this Agreement.

Section 5.4 - Notices. Any notice to be given under the terms of this Agreement to the Company shall be addressed to the Company in care of its Secretary, and any notice to be given to the Optionee shall be addressed to him or her at the address given beneath his or her signature hereto. By a notice given pursuant to this Section 5.4, either party may hereafter designate a different address for notices to be given to him or her. Any notice which is required to be given to the Optionee shall, if the Optionee is then deceased, be given to the Optionee's personal representative if such representative has previously informed the Company of his or her status and address by written notice under this Section 5.4. Any notice shall be deemed duly given when enclosed in a properly sealed envelope or wrapper addressed as aforesaid, deposited (with postage prepaid) in a post office or branch post office regularly maintained by the United States Postal Service. Notwithstanding the foregoing, any notice required or permitted hereunder from the Company to the Optionee may be made by electronic means, including by electronic mail to the Company-maintained electronic mailbox of the Optionee, and the Optionee hereby consents to receive such notice by electronic delivery. To the extent permitted in an electronically delivered notice described in the previous sentence, the Optionee shall be permitted to respond to such notice or communication by way of a responsive electronic communication, including by electronic mail.

Section 5.5 - Titles. Titles are provided herein for convenience only and are not to serve as a basis for interpretation or construction of this Agreement.

Section 5.6 - Applicability of Plan. The Option and the shares of Common Stock issued to the Optionee upon exercise of the Option shall be subject to all of the terms and provisions of the Plan, to the extent applicable to the Option and such shares. In the event of any conflict between this Agreement and the Plan, the terms of the Plan shall control.

Section 5.7 - Amendment.

(a) This Agreement may be amended only by a writing executed by the parties hereto that specifically states that it is amending this Agreement.

(b) This Agreement is intended to be exempt from the application of Code Section 409A and shall, to the extent practicable, be construed accordingly. If either party to this Agreement reasonably determines that any amount payable pursuant to this Agreement would result in adverse tax consequences under Code Section 409A, then such party shall deliver written notice of such determination to the other party, and the parties hereby agree to work in good faith to amend this Agreement so it complies with the requirements of Code Section 409A and preserves as nearly as possible the original intent and economic effect of the affected provisions.

Section 5.8 - Dispute Resolution. Any dispute or controversy arising under or in connection with this Agreement shall be resolved by arbitration in St. Louis, Missouri. Arbitrators shall be selected, and arbitration shall be conducted, in accordance with the rules of the American Arbitration Association. The Company shall pay or reimburse any legal fees in connection with such arbitration in the event that the Optionee prevails on a material element of his or her claim or defense. Payments or reimbursements of legal fees made under this Section 5.8 that are provided during one calendar year shall not affect the amount of such payments or reimbursements provided during a subsequent calendar year, payments or reimbursements under this Section 5.8 may not be exchanged or substituted for another form of compensation to the Optionee, and any such reimbursement or payment will be paid within sixty (60) days after the Optionee prevails, but in no event later than the last day of the Optionee's taxable year following the taxable year in which he incurred the expense giving rise to such reimbursement or payment. This Section 5.8 shall remain in effect throughout the Optionee's employment with the Company and for a period of five (5) years following the Optionee's Termination of Employment.

Section 5.9 - Governing Law. The laws of the State of Delaware shall govern the interpretation, validity and performance of the terms of this Agreement regardless of the law that might be applied under principles of conflicts of laws.

[SIGNATURE PAGE FOLLOWS]

IN WITNESS WHEREOF, this Agreement has been executed and delivered by the parties hereto.

OPTIONEE	PEABODY ENERGY CORPORATION
	By
[Optionee Name]	Its
	Aggregate number of shares of Common Stock for which the Option granted hereunder is exercisable: ________
	Exercise Price per share of Common Stock: $____

EX-10.60

Exhibit 10.60

___ Award 2011 Plan

PERFORMANCE UNITS AGREEMENT

THIS AGREEMENT (the “Agreement”), effective ___________ (the “Grant Date”), is made by and between PEABODY ENERGY CORPORATION, a Delaware corporation (the “Company”), and the undersigned employee of the Company or a Subsidiary (as defined below) or an Affiliate (as defined below) of the Company (the “Grantee”).

WHEREAS, the Company wishes to afford the Grantee the opportunity to participate in future increases in Company value;

WHEREAS, the Company wishes to carry out the Plan (as hereinafter defined), the terms of which are hereby incorporated by reference and made a part of this Agreement; and

WHEREAS, the Committee (as hereinafter defined) appointed to administer the Plan has determined that it would be to the advantage and best interest of the Company and its stockholders to grant the Performance Units provided for herein to the Grantee as an incentive for increased efforts during his or her term of office with the Company or its Subsidiaries or Affiliates, and has advised the Company thereof and instructed the undersigned officer to issue said Performance Units;

NOW, THEREFORE, in consideration of the mutual covenants herein contained and other good and valuable consideration, receipt of which is hereby acknowledged, the parties hereby agree as follows:

ARTICLE I

DEFINITIONS

Whenever the following terms are used in this Agreement, they shall have the meanings specified below. Capitalized terms not otherwise defined in this Agreement shall have the meanings specified in the Plan.

Section 1.1 - “Affiliate” shall mean any other Person directly or indirectly controlling, controlled by, or under common control with the Company. For the purposes of this definition, the term “control” (including, with correlative meanings, the terms “controlling”, “controlled by” and “under common control with”), as applied to any Person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of that Person, whether through the ownership of voting securities, by contract or otherwise.

Section 1.2 - “Cause” shall mean

(a) “Cause” as defined in the Grantee's employment agreement with the Company, if any; or

(b) if the Grantee does not have an employment agreement with the Company:

(i) any material and uncorrected breach by the Grantee of the terms of his or her employment with the Company, including, but not limited to, engaging in action in violation of any restrictive covenants applicable to him or her;

(ii) any willful fraud or dishonesty of the Grantee that has a material detrimental effect on (A) the reputation or business of the Company or any of its subsidiaries or affiliates or (B) the Grantee's reputation or performance of his or her duties to the Company or any of its subsidiaries or affiliates;

(iii) a deliberate or willful refusal or failure of the Grantee to comply with any major corporate policy of the Company which is communicated to the Grantee in writing; or

(iv) the Grantee's conviction of, or plea of nolo contendere to, any felony if such conviction results in his or her imprisonment or has a material detrimental effect on the reputation or business of the Company or any of its subsidiaries or affiliates;

provided that with respect to clause (i) or (iii) above, the Grantee shall have ten (10) days following written notice of the conduct which is the basis for the potential termination for Cause within which to cure such conduct to prevent termination for Cause by the Company. If the Grantee cures the conduct that is the basis for the potential termination for Cause within such ten (10)-day period, the Company's notice of termination shall be deemed withdrawn. Except for violations of the Company's restrictive covenants or termination under paragraph (iv) above, only actions, conduct and events occurring during the Grantee's term of employment with the Company shall be the subject of a termination for Cause. In the event that the Grantee is terminated for failure to meet performance goals, such termination shall be considered a termination for Cause for all purposes relating to these Performance Units.

Section 1.3 - “Change of Control” shall have meaning given to such term in Section 17(m) of the Plan.

Section 1.4 - “Committee” shall mean the Compensation Committee of the Company, duly appointed by the Board as the Administrator under Section 2 of the Plan.

Section 1.5 - “Common Stock” shall mean the common stock of the Company, par value $0.01.

Section 1.6 - “Determination Date” shall mean the earliest to occur of the following events: (i) December 31, ___; (ii) a Termination of Employment on account of death or Disability; or (iii) a Change of Control.

Section 1.7 - “Disability” shall have the meaning given to such term in Section 17(n) of the Plan.

Section 1.8 - “FMV per Share” shall mean the average of the closing prices of the shares of Common Stock for the four (4) weeks immediately preceding the Determination Date. Notwithstanding the foregoing, in the event of a Change of Control, “FMV per Share” shall mean the per share value of equity based on amounts paid in the Change of Control.

Section 1.9 - “Good Reason” shall mean:

(a) “Good Reason” as defined in the Grantee's employment agreement with the Company, if any; or

(b) if the Grantee does not have an employment agreement with the Company:

(i)     a reduction, other than a reduction that generally affects all similarly-situated executives and does not exceed ten percent (10%) in one year or fifteen percent (15%) in the aggregate over three (3) consecutive years,* by the Company in the Grantee's base salary from that in effect immediately prior to the reduction;

(ii)     a reduction, other than a reduction that generally affects all similarly-situated executives, by the Company in the Grantee's bonus opportunity, maximum bonus opportunity and long-term incentive award grant date value used to establish bonus or long-term incentive awards, respectively, from time to time, from those in effect immediately prior to any such reduction;

(iii)    a material reduction in the aggregate program of employee benefits and perquisites to which the Grantee is entitled (other than a reduction that generally affects all executives);

(iv)     relocation of the Grantee's primary office by more than 50 miles from the location of the Grantee's primary office as of the date of this Agreement; or

(v)     any material diminution or material adverse change in the Grantee's duties or responsibilities.

Section 1.10 - “Incentive Amount” shall mean the amount payable to the Grantee hereunder with respect to the Performance Units, if any, as calculated under Article IV.

Section 1.11 - “Performance Units” shall mean the stock units granted on a performance basis under this Agreement. The value of each Performance Unit shall be equal to the FMV per Share as of the relevant Determination Date.

Section 1.12 - “Person” shall mean an individual, partnership, corporation, business trust, joint stock company, trust, unincorporated association, joint venture, governmental authority or other entity of whatever nature.

Section 1.13 - “Plan” shall mean the Peabody Energy Corporation 2011 Long-Term Equity Incentive Plan, as amended from time to time.

Section 1.14 - Pronouns ‑ The masculine pronoun shall include the feminine and neuter, and the singular the plural, where the context so indicates.

Section 1.15 - “Retirement” shall mean the Grantee's retirement from the Company on or after age fifty-five (55) with at least ten (10) years of service with the Company.

Section 1.16 - “Subsidiary” shall mean any corporation in an unbroken chain of corporations beginning with the Company, if each of the corporations, or group of commonly controlled corporations, other than the last corporation in the unbroken chain then owns stock possessing fifty percent (50%) or more of the total combined voting power of all classes of stock in one of the other corporations below it in such chain.

Section 1.17 - “Termination of Employment” shall mean a termination of the Grantee's employment with the Company, a Subsidiary or an Affiliate (regardless of the reason therefor) that constitutes a “separation from service” as defined in Section 409A of the Internal Revenue Code of 1986, as amended, or applicable regulations or other guidance issued thereunder (“Section 409A”).

ARTICLE II

GRANT OF PERFORMANCE UNITS

Section 2.1 - Grant of Performance Units. For good and valuable consideration, the Company hereby grants to the Grantee the number of Performance Units set forth on the signature page hereof upon the terms and subject to the conditions set forth in this Agreement.

Section 2.2 - No Obligation of Employment. Nothing in this Agreement or in the Plan shall confer upon the Grantee any right to continue in the employ of the Company or any Subsidiary or Affiliate or interfere with or restrict in any way the rights of the Company and its Subsidiaries or Affiliates, which are hereby expressly reserved, to terminate the employment of the Grantee at any time for any reason whatsoever, with or without Cause.

Section 2.3 - Adjustments in Performance Units. In the event of the occurrence of one of the corporate transactions or other events listed in Section 12(a) of the Plan, the Committee shall make such substitution or adjustment as provided in Section 12(a) in order to equitably reflect such corporate transaction or other event. Any such adjustment made by the Committee shall be final and binding upon the Grantee, the Company and all other interested persons.

ARTICLE III

VESTING AND FORFEITURE OF PERFORMANCE UNITS

Section 3.1 - Performance Units. Unless otherwise provided in this Article III, the Performance Units shall vest on the fifteenth (15^th) day of each calendar month, in equal monthly increments, during the period beginning on the Grant Date and ending on December 31, ____ (the “Performance Cycle”).

Section 3.2 - Effect of Certain Events. Notwithstanding the foregoing Section 3.1, during the Performance Cycle:

(a)upon a Termination of Employment on account of the Grantee's death or Disability, all of the Performance Units shall become immediately vested and the Grantee shall become entitled to the Incentive Amount calculated and payable pursuant to Article IV hereof with respect to the Performance Units that are vested as of the date of Termination of Employment;

(b)upon the earliest of (i) a Termination of Employment on account of Retirement, (ii) a Termination of Employment by the Company without Cause, or by the Grantee for Good Reason, or (iii) a Change of Control, the Performance Units shall cease to vest, any and all Performance Units that remain unvested on the date of such Termination of Employment or Change of Control shall terminate immediately, and the Grantee shall become entitled to the Incentive Amount calculated and payable pursuant to Article IV hereof with respect to the Performance Units that are vested as of the date of such Termination of Employment or Change of Control, as applicable; and

(c)upon the earlier of (i) a Termination of Employment by the Company for Cause, and (ii) a Termination of Employment by the Grantee without Good Reason, all Performance Units (whether or not they are vested) shall terminate and the Grantee shall not be entitled to any Incentive Amount hereunder.

ARTICLE IV

CALCULATION AND PAYMENT OF INCENTIVE AMOUNT

Section 4.1 - Calculation of Incentive Amount. The Incentive Amount, if any, payable to the Grantee hereunder shall be calculated as of the Determination Date in accordance with paragraph (a) below.

(a) Calculation Formula. The Incentive Amount shall equal the sum of (i) and (ii) below.

(i)Fifty percent (50%) times the number of Performance Units that are vested as of the Determination Date pursuant to Article III hereof, multiplied by the FMV per Share as of the Determination Date, and further multiplied by the Percentage of Award Earned specified in Exhibit A hereto that correlates with the applicable Return on Capital percentage set forth in Exhibit A hereto as of the last day of the calendar quarter that ends on or immediately precedes the Determination Date.

(ii)Fifty percent (50%) times the number of Performance Units that are vested as of the Determination Date pursuant to Article III hereof, multiplied by the FMV per Share as of the Determination Date, and further multiplied by the composite total shareholder return percentage determined under paragraph (b) below (the “Composite TSR Percentage”) as of the Determination Date.

(b) Composite TSR Percentage. The Composite TSR Percentage equals the sum of the weighted payout percentages derived under paragraphs (i) and (ii) below as of the Determination Date.

(i) 3 Year Cumulative TSR - Peer Group Weighted Payout Percentage. The 3 Year Cumulative TSR - Peer Group measure represents the Company's average total shareholder return (based on the average of the closing prices of the shares of Common Stock for the four (4) weeks immediately preceding the Determination Date compared to the average of the closing prices of the shares of Common Stock for the four (4) weeks immediately following the Grant Date), expressed as a percentile ranking in an industry peer group (which peer group shall include such companies as shall be selected by the Committee in its sole discretion before the awards to which the 3 Year Cumulative TSR - Peer Group applies are granted) that corresponds with a specified payout percentage.

The table below is used to determine the applicable payout percentage, which is then multiplied by 25% to determine the 3 Year Cumulative TSR - Peer Group weighted payout percentage for purposes of the Composite TSR Percentage.

3 Year Cumulative TSR - Peer Group

Total Shareholder Return Percentile Ranking	<35th	35th	42.5th	50th	62.5th	≥ 75th
Payout Percentage	—%	40%	70%	100%	150%	200%

Notwithstanding the foregoing, if the Company's average total shareholder return as of the Determination Date (based on the average of the closing prices of the shares of Common Stock for the four (4) weeks immediately preceding the Determination Date compared to the average of the closing prices of the shares of Common Stock for the four (4) weeks immediately following the Grant Date) is negative, the following shall apply:

(A)    If the Company's total shareholder return percentile ranking is at or above the 50th percentile of the peer group, then the applicable payout percentage used to determine the 3 Year Cumulative TSR - Peer Group weighted payout percentage for purposes of the Composite TSR Percentage shall not exceed 150% and shall be determined by reference to the table below.

Negative Return / 3 Year Cumulative TSR - Peer Group

Total Shareholder Return Percentile Ranking	<50th	50th	≥ 62.5th
Payout Percentage	—%	100%	150%

(B)    If the Company's total shareholder return percentile ranking is below the 50th percentile of the peer group, then the 3 Year Cumulative TSR - Peer Group weighted payout percentage shall be 0%.

(ii) 3 Year Cumulative TSR - S&P 500 Index Weighted Payout Percentage. The 3 Year Cumulative TSR - S&P 500 Index measure represents the Company's average total shareholder return (based on the average of the closing prices of the shares of Common Stock for the four (4) weeks immediately preceding the Determination Date compared to the average of the closing prices of the shares of Common Stock for the four (4) weeks immediately following the Grant Date), expressed as a percentile ranking in the Standard & Poor's 500 Index that corresponds with a specified payout percentage.

The table below is used to determine the applicable payout percentage, which is then multiplied by 75% to determine the 3 Year Cumulative TSR - S&P 500 Index weighted payout percentage for purposes of the Composite TSR Percentage.

3 Year Cumulative TSR - S&P 500 Index

Total Shareholder Return Percentile Ranking	<35th	35th	42.5th	50th	62.5th	≥ 75th
Payout Percentage	—%	40%	70%	100%	150%	200%

Notwithstanding the foregoing, if the Company's average total shareholder return as of the Determination Date (based on the average of the closing prices of the shares of Common Stock for the four (4) weeks immediately preceding the Determination Date compared to the average of the closing prices of the shares of Common Stock for the four (4) weeks immediately following the Grant Date) is negative, the following shall apply:

(A)    If the Company's total shareholder return percentile ranking is at or above the 50th percentile of the Standard & Poor's 500 Index, then the applicable payout percentage used to determine the 3 Year Cumulative TSR - S&P 500 Index weighted payout percentage for purposes of the Composite TSR Percentage shall not exceed 150% and shall be determined by reference to the table below.

Negative Return / 3 Year Cumulative TSR - S&P 500 Index

Total Shareholder Return Percentile Ranking	<50th	50th	≥ 62.5th
Payout Percentage	—	100%	150%

(B)    If the Company's total shareholder return percentile ranking is below the 50th percentile of the Standard & Poor's 500 Index, then the 3 Year Cumulative TSR - S&P 500 Index weighted payout percentage shall be 0%.

(iii)    For purposes of this Section 4.1, references to the S&P 500 Index shall be deemed to be references to such index, but in all cases excluding the financial services companies that would otherwise be included in such index.

Section 4.2 - Form and Time of Payment.

(a) General. Subject to Section 4.3, the Incentive Amount shall be paid to the Grantee in Common Stock (except as otherwise provided below in this Section 4.2) as soon as administratively feasible but not later than the ninetieth (90th) day following the Determination Date. The number of shares of Common Stock to be distributed to the Grantee shall equal the quotient of (i) the Incentive Amount, divided by (ii) the Fair Market Value of one share of Common Stock on the payment date. Notwithstanding the foregoing, if the Determination Date is triggered by a Change of Control, the Incentive Amount (calculated in accordance with Section 4.1 using the per share value of equity based on amounts paid in the Change of Control) shall be paid to the Grantee in cash as soon as administratively feasible but not later than the ninetieth (90th) day following the Determination Date.

(b) Specified Employee. If the Determination Date is triggered by a Termination of Employment other than due to death and the Grantee is a “specified employee” (as such term is defined in Section 409A, but generally meaning one of the Company's key employees within the meaning of Code Section 416(i)), the Incentive Amount shall be paid to the Grantee on the first day of the seventh month after the Determination Date.

Section 4.3 - Conditions to Issuance of Stock Certificates. If the Incentive Amount is to be distributed in shares of Common Stock as provided in Section 4.2 and the Committee reasonably anticipates, in accordance with Treasury Regulation Section 1.409A-2(b)(7)(ii)), that issuing Common Stock within the 90-day period following the Determination Date will violate federal securities laws or other applicable laws, the Company may delay issuing such Common Stock, provided that the Company issues such Common Stock on the earliest date on which the Committee reasonably anticipates that such issuance will not violate federal securities laws or other applicable laws.

Section 4.4 - Stockholder Rights. The Grantee shall not be, or have any of the rights or privileges of, a stockholder of the Company in respect of any shares of Common Stock deliverable hereunder unless and until certificates representing such shares shall have been issued by the Company to the Grantee.

ARTICLE V

MISCELLANEOUS

Section 5.1 - Administration. The Committee has the power to interpret the Plan and this Agreement and to adopt such rules for the administration, interpretation and application of the Plan as are consistent therewith and to interpret or revoke any such rules. All actions taken and all interpretations and determinations made by the Committee shall be final and binding upon the Grantee, the Company and all other interested persons. No member of the Committee shall be personally liable for any action, determination or interpretation made in good faith with respect to the Plan or the Performance Units. In its absolute discretion, the Board may at any time and from time to time exercise any and all rights and duties of the Committee under the Plan and this Agreement.

Section 5.2 - Performance Units Not Transferable. Neither the Performance Units nor any interest or right therein or part thereof shall be liable for the debts, contracts or engagements of the Grantee or his or her successors in interest or shall be subject to disposition by transfer, alienation, anticipation, pledge, encumbrance, assignment or any other means whether such disposition is voluntary or involuntary or by operation of law by judgment, levy, attachment, garnishment or any other legal or equitable proceedings (including bankruptcy), and any attempted disposition thereof shall be null and void and of no effect; provided, however, that this Section 5.2 shall not prevent transfers by will or by the applicable laws of descent and distribution.

Section 5.3 - Withholding. In connection with the payment of the Incentive Amount, unless the Grantee makes alternative arrangements satisfactory to the Company to personally remit required withholding amounts, then as of the date that all or a portion of the Incentive Amount is paid, the Company will withhold a portion of such Incentive Amount with a fair market value as of such date equal to the aggregate amount required by law to be withheld by the Company in connection with such payment for applicable federal, state, local and foreign taxes of any kind.

Section 5.4 - Notices. Any notice to be given under the terms of this Agreement to the Company shall be addressed to the Company in care of its Secretary, and any notice to be given to the Grantee shall be addressed to him or her at the address given beneath his or her signature hereto. By a notice given pursuant to this Section 5.4, either party may hereafter designate a different address for notices to be given to him, her or it. Any notice which is required to be given to the Grantee shall, if the Grantee is then deceased, be given to the Grantee's personal representative if such representative has previously informed the Company of his, her or its status and address by written notice under this Section 5.4. Any notice shall be deemed duly given when enclosed in a properly sealed envelope or wrapper addressed as aforesaid, deposited (with postage prepaid) in a post office or branch post office regularly maintained by the United States Postal Service. Notwithstanding the foregoing, any notice required or permitted hereunder from the Company to the Grantee may be made by electronic means, including by electronic mail to the Company-maintained electronic mailbox of the Grantee, and the Grantee hereby consents to receive such notice by electronic delivery. To the extent permitted in an electronically delivered notice described in the previous sentence, the Grantee shall be permitted to respond to such notice or communication by way of a responsive electronic communication, including by electronic mail.

Section 5.5 - Titles. Titles are provided herein for convenience only and are not to serve as a basis for interpretation or construction of this Agreement.

Section 5.6 - Applicability of Plan. The Performance Units and the shares of Common Stock issued to the Grantee, if any, shall be subject to all of the terms and provisions of the Plan, to the extent applicable to the Performance Units and such shares. In the event of any conflict between this Agreement and the Plan, the terms of the Plan shall control.

Section 5.7 - Amendment.

(a) This Agreement may be amended only by a writing executed by the parties hereto that specifically states that it is amending this Agreement.

(b) This Agreement is intended to comply with Section 409A and shall, to the extent practicable, be construed in accordance therewith. If either party to this Agreement reasonably determines that any amount payable pursuant to this Agreement would result in adverse tax consequences under Section 409A, then such party shall deliver written notice of such determination to the other party, and the parties hereby agree to work in good faith to amend this Agreement so it complies with the requirements of Section 409A and preserves as nearly as possible the original intent and economic effect of the affected provisions.

Section 5.8 - Dispute Resolution. Any dispute or controversy arising under or in connection with this Agreement shall be resolved by arbitration in St. Louis, Missouri. Arbitrators shall be selected, and arbitration shall be conducted, in accordance with the rules of the American Arbitration Association. The Company shall pay or reimburse any legal fees in connection with such arbitration in the event that the Grantee prevails on a material element of his or her claim or defense. Payments or reimbursements of legal fees made under this Section 5.8 that are provided during one calendar year shall not affect the amount of such payments or reimbursements provided during a subsequent calendar year, payments or reimbursements under this Section 5.8 may not be exchanged or substituted for another form of compensation to the Grantee, and any such reimbursement or payment will be paid within sixty (60) days after the Grantee prevails, but in no event later than the last day of the Grantee's taxable year following the taxable year in which he incurred the expense giving rise to such reimbursement or payment. This Section 5.8 shall remain in effect throughout the Grantee's employment with the Company and for a period of five (5) years following the Grantee's Termination of Employment.

Section 5.9 - Governing Law. The laws of the State of Delaware shall govern the interpretation, validity and performance of the terms of this Agreement regardless of the law that might be applied under principles of conflicts of laws.

[SIGNATURE PAGE FOLLOWS]

IN WITNESSWHEREOF, this Agreement has been executed and delivered by the parties hereto.

GRANTEE	PEABODY ENERGY CORPORATION
	By
[Grantee]	Its
	Aggregate number of Performance Units granted hereunder: ____________

___ Award 2011 Plan

EXHIBIT A

RETURN ON CAPITAL TARGETS

For purposes of calculating the portion of the Incentive Amount described in Section 4.1(a)(i), the following percentages shall apply:

	Below Entry	Entry	Target	Maximum
Return on Capital	Less than ____%	____%	____%	____%
Percentage of Award Earned	—%	___%	___%	___%

For purposes of the chart above:

Return on Capital shall be determined by taking the average annual operating profit for the Performance Cycle or, in the event of a Determination Date that precedes the end of the Performance Cycle, the portion of the Performance Cycle that has been completed as of the last day of the calendar quarter that ends on or immediately precedes the Determination Date, before taxes and dividing such number by the average total capital. The average total capital is determined using total debt plus total equity for the thirty-seven (37) month-end periods from December ____ through December ____ or, if earlier, the calendar quarter ending coincident with or immediately prior to the Determination Date.

EX-10.61

Exhibit 10.61

___ Award 2011 Plan

RESTRICTED STOCK AGREEMENT

THIS AGREEMENT, dated __________ (the “Grant Date”), is made by and between PEABODY ENERGY CORPORATION, a Delaware corporation (the “Company”), and the undersigned employee of the Company or a Subsidiary (as defined below) or an Affiliate (as defined below) of the Company (“Grantee”).

WHEREAS, the Company wishes to afford the Grantee the opportunity to own shares of its $0.01 par value Common Stock (“Common Stock”);

WHEREAS, the Company wishes to carry out the Plan (as hereinafter defined), the terms of which are hereby incorporated by reference and made a part of this Agreement; and

WHEREAS, the Committee (as hereinafter defined) appointed to administer the Plan has determined that it would be to the advantage and best interest of the Company and its stockholders to grant the shares of Common Stock provided for herein to the Grantee, on a restricted basis, as an incentive for increased efforts during his or her term of office with the Company or its Subsidiaries or Affiliates, and has advised the Company thereof and instructed the undersigned officers to so grant;

NOW, THEREFORE, in consideration of the mutual covenants herein contained and other good and valuable consideration, receipt of which is hereby acknowledged, the parties hereto agree as follows:

ARTICLE I

DEFINITIONS

Whenever the following terms are used in this Agreement, they shall have the meaning specified below. Capitalized terms not otherwise defined in this Agreement shall have the meanings specified in the Plan.

Section 1.1 - “Affiliate” shall mean any other Person directly or indirectly controlling, controlled by, or under common control with the Company. For the purposes of this definition, the term “control” (including, with correlative meanings, the terms “controlling”, “controlled by” and “under common control with”), as applied to any Person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of that Person, whether through the ownership of voting securities, by contract or otherwise.

Section 1.2 - “Board of Directors” or “Board” shall mean the Board of Directors of the Company.

Section 1.3 - “Committee” shall mean the Compensation Committee of the Company, duly appointed by the Board as the Administrator under Section 2 of the Plan.

Section 1.4 - “Person” shall mean an individual, partnership, corporation, business trust, joint stock company, trust, unincorporated association, joint venture, governmental authority or other entity of whatever nature.

Section 1.5 - “Plan” shall mean the Peabody Energy Corporation 2011 Long-Term Equity Incentive Plan, as from time to time amended.

Section 1.6 - Pronouns ‑ The masculine pronoun shall include the feminine and neuter, and the singular the plural, where the context so indicates.

Section 1.7 - “Subsidiary” shall mean any corporation in an unbroken chain of corporations beginning with the Company if each of the corporations, or group of commonly controlled corporations, other than the last corporation in the unbroken chain then owns stock possessing 50% or more of the total combined voting power of all classes of stock in one of the other corporations in such chain.

Section 1.8 - “Termination of Employment” shall mean a termination of the Grantee's employment with the Company, a Subsidiary or an Affiliate (regardless of the reason therefor).

ARTICLE II

GRANT OF RESTRICTED STOCK

Section 2.1 - Grant of Restricted Stock. For good and valuable consideration, the Company shall grant to the Grantee the number of shares set forth on the signature page hereof of its Common Stock (the “Restricted Stock”) upon the terms and subject to the conditions set forth in this Agreement.

Section 2.2 - Transfer Restrictions. At any time prior to vesting in accordance with Article III, the shares of Restricted Stock or any interest therein cannot be directly or indirectly transferred, sold, assigned, pledged, hypothecated or otherwise disposed of. Upon vesting in accordance with Article III, the shares of Restricted Stock shall cease to be restricted and shall become non-forfeitable, and the Grantee shall own such shares free of all restrictions otherwise imposed by this Agreement.

Section 2.3 - No Obligation of Employment. Nothing in this Agreement or in the Plan shall confer upon the Grantee any right to continue in the employ of the Company or any Subsidiary or Affiliate or interfere with or restrict in any way the rights of the Company and its Subsidiaries or Affiliates, which are hereby expressly reserved, to terminate the employment of the Grantee at any time for any reason whatsoever.

Section 2.4 - Adjustments in Restricted Shares. In the event of the occurrence of one of the corporate transactions or other events listed in Section 12(a) of the Plan, the Committee shall make such substitution or adjustment as provided in Section 12(a) in order to equitably reflect such corporate transaction or other event. Any such adjustment made by the Committee shall be final and binding upon the Grantee, the Company and all other interested persons.

ARTICLE III

VESTING OF RESTRICTED STOCK

Section 3.1 - Restricted Stock. Unless otherwise provided in this Agreement, the shares of Restricted Stock shall become vested and non-forfeitable on the third anniversary of the Grant Date.

Section 3.2 - Acceleration Events. Notwithstanding anything in this Article III to the contrary, the shares of Restricted Stock shall become fully vested and non-forfeitable upon (i) a Change of Control or (ii) a Termination of Employment due to the death or Disability of the Grantee.

Section 3.3 - Effect of Termination of Employment. Except as provided in Section 3.2, no share of Restricted Stock shall become vested and non-forfeitable following Termination of Employment, and any such non-vested and forfeitable share of Restricted Stock shall be immediately and automatically forfeited upon Termination of Employment.

ARTICLE IV

RECEIPT OF STOCK

Section 4.1 - Conditions to Issuance of Stock Certificates. The shares of Common Stock deliverable hereunder may be either previously authorized but unissued shares or issued shares that have been reacquired by the Company. Such shares shall be fully paid and nonassessable. The Company shall not be required to issue or deliver any certificate or certificates for shares of Common Stock granted hereunder prior to fulfillment of both of the following conditions:

(a) The obtaining of approval or other clearance from any state or federal governmental agency that the Committee, in its absolute discretion, determines to be necessary or advisable; and

(b) The lapse of such reasonable period of time following the grant as the Committee may establish from time to time for administrative convenience.

Section 4.2 - Escrow. Upon issuance, the certificates for the shares of Restricted Stock shall be held in escrow by the Company until, and to the extent, the shares of Restricted Stock cease to be restricted and become non-forfeitable, and the Grantee shall own such shares free of all restrictions otherwise imposed by this Agreement. Any new, substituted or additional securities or other property described in Section 2.4 shall immediately be delivered to the Company to be held in such escrow. Shares of Restricted Stock, together with any other assets or securities held in escrow hereunder, shall be (i) surrendered to the Company for cancellation upon forfeiture, if any, of such shares of Restricted Stock by the Grantee hereunder, or (ii) subject to the provisions of Section 5.1, released to the Grantee to the extent the shares of Restricted Stock are no longer subject to any of the restrictions otherwise imposed by this Agreement.

Section 4.3 - Rights as Stockholder. The Grantee shall not be, and shall not have any of the rights or privileges of, a stockholder of the Company in respect of any shares granted hereunder unless and until the date on which certificates representing such shares shall have been issued by the Company to such Grantee (the “Issuance Date”). The Grantee shall be entitled to receive any dividends paid with respect to the shares of Restricted Stock that become payable on or after the Issuance Date; provided, however, that no dividends shall be payable to or for the benefit of the Grantee for shares of Restricted Stock with respect to record dates occurring prior to the Issuance Date, or with respect to record dates occurring on or after the date, if any, on which the Grantee has forfeited those shares of Restricted Stock. The Grantee shall be entitled to vote the shares of Restricted Stock on or after the Issuance Date to the same extent as would have been applicable to the Grantee if the shares of Restricted Stock had then become fully vested and non-forfeitable; provided, however, that the Grantee shall not be entitled to vote the shares of Restricted Stock with respect to record dates for such voting rights occurring prior to the Issuance Date, or with respect to record dates occurring on or after the date, if any, on which the Grantee has forfeited those shares of Restricted Stock.

ARTICLE V

MISCELLANEOUS

Section 5.1 - Tax Withholding. Unless either (a) the election described in Section 5.2 hereof is made by the Grantee, or (b) the Grantee makes alternative arrangements satisfactory to the Company to personally remit required withholding amounts, then, as of the date that all or a portion of the shares of Restricted Stock become vested pursuant to Section 3.1 or 3.2 hereof, the Company shall withhold a number of shares of the then vesting shares of Restricted Stock with a fair market value as of such vesting date equal to the aggregate amount required by law to be withheld by the Company in connection with such vesting for applicable federal, state, local and foreign taxes of any kind. For all purposes, the amount withheld by the Company pursuant to this Section 5.1 shall be deemed to have first been paid to the Grantee.

Section 5.2 - Section 83(b) Election. The Grantee understands that Section 83 of the Code may tax as compensation income the difference between the amount paid for the shares of Restricted Stock, if any, and the fair market value of the shares of Restricted Stock as of the date any restrictions on the shares of Restricted Stock lapse in the absence of an election under Section 83(b) of the Code. In this context, “restriction” means the forfeitability of the shares of Restricted Stock pursuant to the terms of this Agreement. To the extent that the Company has registered under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), “restriction” with respect to officers, directors, and ten percent (10%) shareholders may also mean the six-month period after the acquisition of the shares of Restricted Stock during which sales of certain securities by such officers, directors, and ten percent (10%) shareholders would give rise to liability under Section 16(b) of the Exchange Act.

The Grantee understands that he or she may elect to be taxed at the time he or she receives the shares of Restricted Stock and while the shares of Restricted Stock are subject to restrictions rather than waiting to be taxed on the shares of Restricted Stock when and as the restrictions lapse. The Grantee realizes that he or she may choose this tax treatment by filing an election under Section 83(b) of the Code with the Internal Revenue Service within thirty (30) days after the Grant Date and by filing a copy of such election with his or her tax return for the tax year in which the Restricted Shares were subjected to the restrictions. The Grantee understands that failure to make this filing in a timely manner may result in the recognition of compensation by the Grantee, as the restrictions lapse, on any difference between the purchase price, if any, and the fair market value of the shares of Restricted Stock at the time such restrictions lapse. The Grantee acknowledges that it is the Grantee's sole responsibility and not the Company's to timely file the election under Section 83(b) of the Code. The Grantee acknowledges that he or she shall consult his or her own tax advisers regarding the advisability or non-advisability of making the election under Section 83(b) of the Code and acknowledges that he or she shall not rely on the Company or its advisers for such advice.

If the Grantee makes the election under Section 83(b) of the Code, then the Company shall not be liable or responsible in any way for any tax (including withholding tax) consequences relating to the shares of Restricted Stock, and the Grantee agrees to undertake to determine, and be responsible for, any and all tax (including any withholding tax) consequence to himself or herself with respect to the shares of Restricted Stock.

Section 5.3 - Administration. The Committee has the power to interpret the Plan and this Agreement and to adopt such rules for the administration, interpretation and application of the Plan as are consistent therewith and to interpret or revoke any such rules. All actions taken and all interpretations and determinations made by the Committee shall be final and binding upon the Grantee, the Company and all other interested persons. No member of the Committee shall be personally liable for any action, determination or interpretation made in good faith with respect to the Plan or the shares of Restricted Stock. In its absolute discretion, the Board of Directors may at any time and from time to time exercise any and all rights and duties of the Committee under the Plan and this Agreement.

Section 5.4 - Notices. Any notice to be given under the terms of this Agreement to the Company shall be addressed to the Company in care of its Secretary, and any notice to be given to the Grantee shall be addressed to him or her at the address given beneath his or her signature hereto. By a notice given pursuant to this Section 5.4, either party may hereafter designate a different address for notices to be given to him, her or it. Any notice which is required to be given to the Grantee shall, if the Grantee is then deceased, be given to the Grantee's personal representative if such representative has previously informed the Company of his, her or its status and address by written notice under this Section 5.4. Any notice shall be deemed duly given when enclosed in a properly sealed envelope or wrapper addressed as aforesaid, deposited (with postage prepaid) in a post office or branch post office regularly maintained by the United States Postal Service. Notwithstanding the foregoing, any notice required or permitted hereunder from the Company to the Grantee may be made by electronic means, including by electronic mail to the Company-maintained electronic mailbox of the Grantee, and the Grantee hereby consents to receive such notice by electronic delivery. To the extent permitted in an electronically delivered notice described in the previous sentence, the Grantee shall be permitted to respond to such notice or communication by way of a responsive electronic communication, including by electronic mail.

Section 5.5 - Titles. Titles are provided herein for convenience only and are not to serve as a basis for interpretation or construction of this Agreement.

Section 5.6 - Applicability of Plan. The shares of Common Stock issued to the Grantee hereunder shall be subject to all of the terms and provisions of the Plan, to the extent applicable to such shares. In the event of any conflict between this Agreement and the Plan, the terms of the Plan shall control.

Section 5.7 - Amendment.

(a) The Administrator may amend this Agreement as it determines in good faith to be necessary or desirable to comply with applicable law, but no such amendment shall adversely affect the Grantee's rights without his or her written consent. To incorporate other modifications, this Agreement may be amended by a writing executed by the parties hereto.

(b) This Agreement is intended to be exempt from the application of Code Section 409A and shall, to the extent practicable, be construed accordingly. If either party to this Agreement reasonably determines that any amount payable pursuant to this Agreement would result in adverse tax consequences under Code Section 409A, then such party shall deliver written notice of such determination to the other party, and the parties hereby agree to work in good faith to amend this Agreement so it complies with the requirements of Code Section 409A and preserves as nearly as possible the original intent and economic effect of the affected provisions.

Section 5.8 - Dispute Resolution. Any dispute or controversy arising under or in connection with this Agreement shall be resolved by arbitration in St. Louis, Missouri. Arbitrators shall be selected, and arbitration shall be conducted, in accordance with the rules of the American Arbitration Association. The Company shall pay or reimburse any legal fees in connection with such arbitration in the event that the Grantee prevails on a material element of his or her claim or defense. Payments or reimbursements of legal fees made under this Section 5.8 that are provided during one calendar year shall not affect the amount of such payments or reimbursements provided during a subsequent calendar year, payments or reimbursements under this Section 5.8 may not be exchanged or substituted for another form of compensation to the Grantee, and any such reimbursement or payment will be paid within sixty (60) days after the Grantee prevails, but in no event later than the last day of the Grantee's taxable year following the taxable year in which he incurred the expense giving rise to such reimbursement or payment. This Section 5.8 shall remain in effect throughout the Grantee's employment with the Company and for a period of five (5) years following the Grantee's Termination of Employment.

Section 5.9 - Governing Law. The laws of the State of Delaware shall govern the interpretation, validity and performance of the terms of this Agreement regardless of the law that might be applied under principles of conflicts of laws.

[SIGNATURE PAGE FOLLOWS]

IN WITNESS WHEREOF, this Agreement has been executed and delivered by the parties hereto.

	PEABODY ENERGY CORPORATION
	By:
	Its:
Note: The Grantee is deemed to have executed this Agreement upon clicking “Accept” in the Plan's online administration site.

EX-10.62

Exhibit 10.62

___ Non-Employee Director Award Retainer Grant 2011 Plan

DEFERRED STOCK UNITS AGREEMENT

THIS AGREEMENT, dated __________ (the “Grant Date”), is made by and between PEABODY ENERGY CORPORATION, a Delaware corporation (the “Company”), and the undersigned non-employee director of the Company (the “Grantee”).

WHEREAS, the Company wishes to afford the Grantee the opportunity to own shares of Common Stock;

WHEREAS, the Company wishes to carry out the Plan, the terms of which are hereby incorporated by reference and made a part of this Agreement; and

WHEREAS, the Administrator of the Plan has determined that it would be to the advantage, and in the best interest, of the Company and its stockholders to grant Deferred Stock Units to the Grantee as an incentive for increased efforts during his or her term of office with the Company, and has advised the Company to grant Deferred Stock Units to the Grantee;

NOW, THEREFORE, in consideration of the mutual covenants herein contained and other good and valuable consideration, receipt of which is hereby acknowledged, the parties hereto agree as follows:

ARTICLE 1

DEFINITIONS

The following terms as used in this Agreement shall have the meanings specified below. Capitalized terms that are not defined in this Agreement shall have the meanings specified in the Plan.

Section 1.1 - “Change of Control” shall have meaning given to such term in Section 17(m) of the Plan.

Section 1.2 - “Code” means the Internal Revenue Code of 1986, as amended.

Section 1.3 - “Common Stock” means common stock, $0.01 par value, of the Company.

Section 1.4 - “Disability” shall have the meaning given to such term in Section 17(n) of the Plan.

Section 1.5 - “Payment Date” means, as used with respect to a Deferred Stock Unit, the earlier of (i) the Specified Distribution Date and (ii) the date that is the thirtieth day following the date of Grantee's Separation from Service.

Section 1.6 - “Plan” means the Peabody Energy Corporation 2011 Long-Term Equity Incentive Plan, as it may be amended from time to time.

Section 1.7 - “Specified Distribution Date” means, as used with respect to a Deferred Stock Unit granted hereunder, the date that is the third anniversary of the Grant Date; provided that, as used with respect to a Deferred Stock Unit granted hereunder which the Grantee has elected to defer in accordance with a properly and timely completed deferral election form, the date specified as the “Specified Distribution Date” on such deferral election form shall be the Specified Distribution Date for purposes of this Agreement.

Section 1.8 - “Separation from Service” means a termination of the Grantee's employment or service with the Company or its subsidiary or affiliate (regardless of the reason therefor) that constitutes a “separation from service” as defined in Code Section 409A or applicable regulations or other guidance in effect thereunder.

ARTICLE 2

GRANT OF DEFERRED STOCK UNITS

Section 2.1 - Grant of Deferred Stock Units. For good and valuable consideration, the Company hereby grants to the Grantee a number of deferred stock units (each, a “Deferred Stock Unit”) set forth on the signature page hereof. Each Deferred Stock Unit granted hereunder constitutes a hypothetical share of Common Stock of the Company with a value on any given date equal to the Fair Market Value of a share of Common Stock on such date. Each Deferred Stock Unit granted hereunder represents an unfunded and unsecured promise of the Company to issue, in accordance with Article 4 below, a share of Common Stock for each vested Deferred Stock Unit.

Section 2.2 - Transfer Restrictions. Prior to the issuance of Common Stock in accordance with Article 4, a Deferred Stock Unit or any interest therein cannot be directly or indirectly transferred, sold, assigned, pledged, hypothecated or otherwise disposed of, and any such attempt to do so shall be null and void.

Section 2.3 - No Obligation of Service. Nothing in this Agreement or in the Plan shall confer upon the Grantee any right to continue in the service of the Company or interfere with or restrict in any way the rights of the Company to terminate the service of the Grantee.

ARTICLE 3

VESTING OF DEFERRED STOCK UNITS

Section 3.1 - Deferred Stock Unit Vesting. Subject to Sections 3.2 and 3.3, the Deferred Stock Units shall become vested ratably, on a monthly basis, over the 12-month period beginning on the Grant Date; provided, that, with respect to the portion of the Deferred Stock Units that are to vest in any given month, such vesting shall only occur to the extent that the Grantee remains in the service of the Company during the entire period commencing on the Grant Date and ending on the date during that month that such Deferred Stock Units are to become vested. For the purpose of clarity, the vesting of Deferred Stock Units in each month shall occur on the monthly anniversary of the Grant Date.

Section 3.2 - Acceleration Events. Notwithstanding the provisions of Section 3.1, the Deferred Stock Units shall become fully vested upon the earliest to occur of: (i) the Grantee's Separation from Service due to death or Disability; (ii) a Change of Control; or (iii) the Grantee's Separation from Service due to the Grantee reaching the end of his or her elected term and either (A) being ineligible to run for an additional term on the Board as a result of reaching age seventy-five (75) or (B) having completed at least three years of service as a director.

Section 3.3 - Effect of Separation from Service. Except as otherwise provided in Section 3.2, no unvested Deferred Stock Unit shall become vested following the Grantee's Separation from Service, and unvested Deferred Stock Units shall be immediately and automatically forfeited upon the Grantee's Separation from Service.

ARTICLE 4

ISSUANCE OF STOCK

Section 4.1 - Payment Following Vesting of Deferred Stock Units. Subject to the terms of this Agreement, the Company shall issue to the Grantee (or, in the event of the Grantee's death, to his or her beneficiary or estate) a number of shares of Common Stock equal to the number of vested Deferred Stock Units granted hereunder. Subject to Section 4.2, such shares of Common Stock shall be issued to the Grantee on the Payment Date.

Section 4.2 - Conditions to Issuance of Stock Certificates. Shares of Common Stock that may be issued in accordance with Section 4.1 may be either previously authorized but unissued shares or issued shares that have been reacquired by the Company. In accordance with Treasury Regulation Section 1.409A-2(b)(7)(ii), if the Administrator reasonably anticipates that issuing Common Stock on the Payment Date will violate federal securities laws or other applicable laws, the Company may delay issuing such Common Stock, provided that the Company issues such Common Stock on the earliest date at which the Administrator reasonably anticipates that such issuance will not violate federal securities laws or other applicable laws.

Section 4.3 - Rights as Stockholder. The Grantee shall not be, and shall not have any of the rights or privileges of, a stockholder of the Company in respect of any shares of Common Stock corresponding to Deferred Stock Units granted hereunder unless and until the date (the “Issuance Date”) on which certificates representing such shares have been issued by the Company to or in the name of such Grantee. The Grantee shall not be entitled to receive any dividends paid with respect to the shares of Common Stock with respect to record dates occurring prior to the Issuance Date, and the Grantee shall not be entitled to vote the shares of Common Stock with respect to record dates for such voting rights occurring prior to the Issuance Date.

ARTICLE 5

MISCELLANEOUS

Section 5.1 - Tax Consequences. Unless otherwise specifically provided in another agreement between the Company and the Grantee, the Company shall not be liable or responsible for any tax of the Grantee relating to the Deferred Stock Units, and the Grantee agrees to be responsible for, any and all such taxes with respect to the Deferred Stock Units.

Section 5.2 - Administration. The Administrator has the power to interpret the Plan and this Agreement and to adopt such rules for the administration, interpretation and application of the Plan as are consistent therewith and to interpret or revoke any such rules. All actions taken and all interpretations and determinations made by the Administrator in good faith shall be final and binding upon the Grantee, the Company and all other interested persons. No member of the Administrator shall be personally liable for any action, determination or interpretation made good faith with respect to the Plan or the Deferred Stock Units.

Section 5.3 - Notices. Any notice to be given under the terms of this Agreement to the Company shall be addressed to the Company in care of its Secretary, and any notice to be given to the Grantee shall be addressed to him or her at the address given beneath his or her signature hereto. By a notice given pursuant to this Section 5.3, either party may hereafter designate a different address for notices to be given to him, her or it. Any notice that is required to be given to the Grantee shall, if the Grantee is then deceased, be given to the Grantee's personal representative if such representative has previously informed the Company of his, her or its status and address by written notice under this Section 5.3. Any notice shall be deemed duly given when enclosed in a properly sealed envelope or wrapper addressed as aforesaid, deposited (with postage prepaid) in a post office or branch post office regularly maintained by the United States Postal Service. Notwithstanding the foregoing, any notice required or permitted hereunder from the Company to the Grantee may be made by electronic means, including by electronic mail to the Company-maintained electronic mailbox of the Grantee, and the Grantee hereby consents to receive such notice by electronic delivery. To the extent permitted in an electronically delivered notice described in the previous sentence, the Grantee shall be permitted to respond to such notice or communication by way of a responsive electronic communication, including by electronic mail.

Section 5.4 - Titles. Titles and headings are provided herein for convenience only and are not to serve as a basis for interpretation or construction of this Agreement.

Section 5.5 - Pronouns. The masculine pronoun shall include the feminine and neuter, and the singular the plural, where the context so indicates.

Section 5.6 - Applicability of Plan. The shares of Common Stock issued to the Grantee hereunder shall be subject to all of the terms and provisions of the Plan, to the extent applicable to such shares. In the event of any conflict between this Agreement and the Plan, the terms of the Plan shall control.

Section 5.7 - Amendment.

(a) The Administrator may amend this Agreement as it determines in good faith to be necessary or desirable to comply with applicable law, but no such amendment shall adversely affect the Grantee's rights without his or her written consent. To incorporate other modifications, this Agreement may be amended by a writing executed by the parties hereto.

(b) This Agreement is intended to comply with Code Section 409A and shall, to the extent practicable, be construed in accordance therewith. If either party to this Agreement reasonably determines that any amount payable pursuant to this Agreement would result in adverse tax consequences under Code Section 409A, then such party shall deliver written notice of such determination to the other party, and the parties hereby agree to work in good faith to amend this Agreement so it complies with the requirements of Code Section 409A and preserves as nearly as possible the original intent and economic effect of the affected provisions.

Section 5.8 - Dispute Resolution. Any dispute or controversy arising under or in connection with this Agreement shall be resolved by arbitration in St. Louis, Missouri. Arbitrators shall be selected, and arbitration shall be conducted, in accordance with the rules of the American Arbitration Association.

Section 5.9 - Governing Law. The laws of the State of Delaware shall govern the interpretation, validity and performance of the terms of this Agreement regardless of the law that might be applied under principles of conflicts of laws.

[SIGNATURE PAGE FOLLOWS]

IN WITNESS WHEREOF, this Agreement has been executed and delivered by the parties hereto, effective on the Grant Date.

GRANTEE	PEABODY ENERGY CORPORATION
[Grantee]	By
	Its
Address
Grantee's Taxpayer Identification Number: ________-______-__________	Aggregate number of Deferred Stock Units granted hereunder: ________________

EX-10.86

Exhibit 10.86

EMPLOYMENT AGREEMENT

This AGREEMENT (the “Agreement”) is entered into as of March 17, 2011 (the “Commencement Date”) by and between Peabody Energy Corporation, a Delaware corporation (the “Company”), and Jeane L. Hull (“Executive”).

RECITALS

To induce Executive to serve as the Company's Executive Vice President Technical Services, the Company desires to provide Executive with compensation and other benefits on the terms and subject to the conditions set forth in this Agreement.

Executive is willing to accept such employment and perform services for the Company, on the terms and subject to the conditions hereinafter set forth.

It is therefore hereby agreed by and between the parties as follows:

1. Employment.

1.1 Subject to the terms and conditions of this Agreement, the Company agrees to employ Executive during the term hereof as Executive Vice President Technical Services. In such capacity, Executive shall report to the Chairman and Chief Executive Officer (the “Chairman and CEO”) and shall have the customary powers, responsibilities and authority of executives holding such positions in corporations of the size, type and nature of the Company, as it exists from time to time, and as are assigned by the Chairman and CEO or other senior executive of the Company.

1.2 Subject to the terms and conditions of this Agreement, Executive hereby accepts employment as Executive Vice President Technical Services commencing as of the Commencement Date and agrees, subject to any period of vacation or other approved leave, to devote his or her full business time and efforts to the performance of services, duties and responsibilities in connection therewith, subject at all times to review and control of the Chairman and CEO.

1.3 Subject to Executive's compliance with all of the provisions of the Company's code of conduct and other policies, nothing in this Agreement shall preclude Executive from engaging in charitable work and community affairs, from delivering lectures, fulfilling speaking engagements or teaching at educational institutions, from managing any investment made by him or her or his or her immediate family with respect to which Executive is not substantially involved with the management or operation of the entity in which Executive has invested (provided that no such investment in publicly traded equity securities may exceed five percent (5%) of the equity of any entity without the prior written approval of the Chairman and CEO) or from serving, subject to the prior written approval of the Chairman and CEO, as a member of boards of directors or as a trustee of any other corporation, association or entity, to the extent that any of the above activities do not materially interfere with the performance of his or her duties hereunder. For purposes of the preceding sentence, any approval by the Chairman and CEO required therein shall not be unreasonably withheld.

2. Term of Employment. Executive's term of employment under this Agreement shall commence on the Commencement Date and continue for three (3) years, subject to earlier termination as provided in the Agreement (the “Term of Employment”). The Agreement automatically will renew for a one (1)-year period at the end of the initial Term of Employment and, if applicable, any renewal period, unless either the Company or Executive notifies the other party of the intention not to renew the Agreement in writing at least ninety (90) days before the end of the applicable period.

3. Compensation.

3.1 Salary. During the Term of Employment, the Company shall pay Executive a base salary (“Base Salary”) at the initial rate of $460,000. Such Base Salary shall be payable in accordance with the ordinary payroll practices of the Company. During the Term of Employment, the Compensation Committee of the Company's Board of Directors (the “Compensation Committee”) and/or the Chairman and CEO shall review Executive's Base Salary in good faith, at least annually, in accordance with the Company's customary procedures and practices regarding the salaries of senior executives, and may adjustExecutive's Base Salary following such review. “Base Salary” for all purposes herein shall be deemed to be a reference to the Base Salary in effect as of any date that requires the determination of Executive's Base Salary hereunder.

3.2 Annual Bonus.

(a)In addition to Base Salary, Executive shall, commencing in 2011 and continuing for each calendar year thereafter during the Term of Employment, be eligible to receive an annual cash bonus (the “Bonus”) in accordance with a program developed by the Compensation Committee and/or the Chairman and CEO, based on achievement of performance targets established by the Compensation Committee and/or the Chairman and CEO as soon as practicable at or after the beginning of the calendar year to which the performance targets relate. The performance targets for the 2011 Bonus shall be determined before or as soon as practicable after the Commencement Date. Executive's Bonus opportunity for the 2011 fiscal year is 80% of his or her Base Salary. The Compensation Committee and/or the Chairman and CEO shall review Executive's Bonus opportunity in good faith from time to time in accordance with the Company's customary procedures and practices regarding the bonus opportunities of senior executives, and may adjust Executive's Bonus opportunity following such review. “Bonus” for all purposes herein, except as otherwise specifically stated, shall be deemed to be a reference to the Bonus opportunity in effect as of any date that requires the determination of Executive's Bonus hereunder.

(b)A Bonus award for any calendar year shall be payable to Executive at the time bonuses are paid to executive officers for such calendar year in accordance with the Company's policies and practices, but in no event later than March 15 of the calendar year following the later of (i) the calendar year in which the Bonus is earned or (ii) the calendar year in which the Bonus is no longer subject to a substantial risk of forfeiture within the meaning of Section 409A of the Internal Revenue Code of 1986, as amended (the “Code”), and the Treasury regulations and other guidance in effect thereunder (collectively, “Section 409A”).

3.3 Equity-Based Compensation.

(a)Periodic Awards. Executive shall be eligible to receive, from time to time during the Term of Employment, equity-based compensation awards under the Company's equity incentive plan(s) (the “Long-Term Incentive Awards”). Any such Long-Term Incentive Awards shall be governed by separate grant agreements. The grant date value for Executive's Long-Term Incentive Awards for the 2011 fiscal year is 200% of his or her Base Salary. The Compensation Committee and/or the Chairman and CEO shall review the grant date value of Executive's Long-Term Incentive Awards in good faith from time to time in accordance with the Company's customary procedures and practices regarding the long-term incentive awards of senior executives, and may adjust the grant date value of future Long-Term Incentive Awards to Executive following such review. “Long-Term Incentive Award” for all purposes herein, except as otherwise specifically stated, shall be deemed to be a reference to the grant date Long-Term Incentive Award value in effect as of any date that requires the determination of Executive's Long-Term Incentive Award value hereunder or under any grant agreement.

(b)Inducement Award. In conjunction with the execution of this Agreement, the Company and Executive expect to enter into a Restricted Stock Agreement in substantially the form attached hereto as Exhibit A.

4. Employee Benefits.

4.1 Employee Benefit Programs, Plans and Practices; Perquisites. The Company shall provide Executive with employee benefits and perquisites at a level (a) commensurate with his or her position in the Company and (b) at least as favorable to Executive as the arrangements the Company provides to its other senior executives that are in effect and open to new participants on the Commencement Date, including retirement benefits, health and welfare benefits, the Continuation Benefits (as defined in Section 6.2(b)(ii)(B)(II)), directors and officers insurance and/or an indemnification agreement that covers claims arising out of actions or inactions occurring during the Term of Employment, and other employee benefits and perquisites which the Company may make available to its senior executives from time to time in its discretion on and after the Commencement Date. Executive's rights, if any, under any employee benefit plans or programs of the Company as of the Commencement Date shall continue in accordance with plan or program terms as in effect at any given time.

4.2 Vacation. Executive shall be entitled to the number of business days paid vacation in each calendar year as determined in accordance with the Company's applicable vacation policies, which shall be taken at such times as are consistent with Executive's responsibilities hereunder.

5. Expenses. Subject to prevailing Company policy or guidelines, the Company will reimburse Executive for all reasonable expenses incurred by Executive in carrying out his or her duties on behalf of the Company, provided that payment or reimbursement of expenses shall be made promptly and in no event later than December 31 of the year following the year in which such expenses were incurred, the amount of such expenses eligible for payment or reimbursement in any year shall not affect the amount of such expenses eligible for payment or reimbursement in any other year and no such right to payment or reimbursement shall be subject to liquidation or exchange for another benefit.

6. Termination of Employment.

6.1 Termination of Employment for Any Reason. Except as otherwise specifically provided in this Agreement, the Company or Executive may terminate Executive's Term of Employment at any time for any reason by written notice to the other party at least thirty (30) days in advance of the date of termination of Executive's employment. In the event of a termination of Executive's employment for any reason during the Term of Employment, the Company shall pay to Executive:

(a) within five (5) business days following the date of termination of Executive's employment, a lump sum that includes: (i) Executive's Base Salary earned on or prior to the date of such termination but not yet paid to Executive in accordance with the Company's customary procedures and practices for the payment of executive salaries; (ii) any business expenses incurred by Executive and properly submitted for reimbursement, but not yet reimbursed by the Company under Section 5 above as of the date of such termination; and (iii) any vacation time accrued but unused as of the date of such termination;

(b) any benefits accrued and vested under any of the Company's employee benefit programs, plans and practices on or prior to the date of termination of Executive's employment; and

(c)if Executive's employment terminates due to retirement (as defined in the applicable plan), a prorated bonus for the calendar year of termination of Executive's employment, calculated as the Bonus Executive would have received in such year based on actual performance multiplied by a fraction, the numerator of which is the number of business days during the calendar year of termination that Executive was employed and the denominator of which is the total number of business days during the calendar year of termination. Such bonus shall be payable when annual Bonuses are paid to other senior executives of the Company, but in no event later than March 15 of the calendar year following the later of (i) the calendar year in which the Bonus is earned or (ii) the calendar year in which the bonus is no longer subject to a substantial risk of forfeiture within the meaning of Section 409A.

The amounts described in (a) and (b) above are collectively referred to herein as the “Accrued Obligations” and shall be paid in accordance with the terms of such Company programs, plans and practices. The Accrued Obligations shall be paid in addition to any amounts payable under any other provision of this Section 6 due to the termination of Executive's employment. Any business expenses incurred by Executive before his or her employment termination date and properly submitted for reimbursement before or within ninety (90) days after the employment termination date shall be processed and paid in accordance with Section 5.

6.2 Termination by the Company without Cause or Termination by Executive for Good Reason.

(a) Notice Requirements.

(i)General. Except as otherwise provided in paragraph (ii) below with respect to a Good Reason termination, the Company or Executive may terminate Executive's Term of Employment at any time for any reason by written notice to the other party at least thirty (30) days in advance of the date of termination of Executive's employment.

(ii)Good Reason Notice Requirements and Cure Period. If Executive terminates his or her employment during the Term of Employment for Good Reason (as defined in Section 6.2(d) hereof), Executive shall provide written notice to the Company at least forty-five (45)

days in advance of the date of termination, such notice shall describe the conduct Executive believes to constitute Good Reason and the Company shall have the opportunity to cure the Good Reason within thirty (30) days after receiving such notice. If the Company cures the conduct that is the basis for the potential termination for Good Reason within such thirty (30)-day period, Executive's notice of termination shall be deemed withdrawn. If Executive does not give notice to the Company as described in this Section 6.2(a)(ii) within ninety (90) days after an event giving rise to Good Reason, Executive's right to claim Good Reason termination on the basis of such event shall be deemed waived.

(b)Severance Benefits.

(i)Severance Payment. If Executive's employment is terminated during the Term of Employment (for the avoidance of doubt, the term “terminated” does not include non-renewal of this Agreement):

(A) by the Company for a reason other than Cause (as defined in Section 6.3(b) hereof), Disability (as defined in Section 6.4 hereof) or death, or

(B) by Executive for Good Reason (as defined in Section 6.2(d) hereof),

and such termination constitutes a Separation from Service (as defined in Section 6.2(c) hereof), the Company, as severance, shall pay to Executive an amount (the “Severance Payment”) equal to the total of:

(I)two (2) times Executive's Base Salary; plus

(II)an additional amount equal to two (2) times the annual average of the actual Bonus awards paid to Executive by the Company for the three (3) calendar years preceding the date of Executive's employment termination (or, if Executive has not been employed by the Company for three (3) full calendar years as of the date his or her employment is terminated, for the two (2) calendar years or one (1) calendar year, as applicable, for which he or she has been so employed and eligible to receive a Bonus); plus

(III)two (2) times six percent (6%) of Executive's Base Salary (to compensate Executive for Company contributions he or she otherwise might have received under the Company's retirement plan).

The Company shall pay to Executive (x) one-half (½) of such Severance Payment in a lump sum payment on the earlier to occur of Executive's death or the first business day immediately following the six (6)-month anniversary of Executive's Separation from Service and (y) the remaining one-half (½) of the Severance Payment in six (6) substantially equal monthly payments beginning on the first day of the month next following the initial lump sum payment.

(ii)Prorated Bonus and Continuation Benefits. In addition, if Executive's employment is terminated:

(A) by the Company for a reason other than Cause (as defined in Section 6.3(b) hereof), Disability (as defined in Section 6.4 hereof) or death, or

(B) by Executive for Good Reason (as defined in Section 6.2(d) hereof),

and such termination constitutes a Separation from Service, the following provisions shall apply:

(I)Prorated Bonus. The Company shall pay to Executive a prorated bonus (the “Prorated Bonus”) for the calendar year of termination of Executive's employment, calculated as the Bonus Executive would have received in such year based on actual performance multiplied by a fraction, the numerator of which is the number of business days during the calendar year of termination that Executive was employed and the denominator of which is the total number of business days during the calendar year of termination. The Prorated Bonus shall be payable when annual bonuses are paid to other senior executives of the Company, but in no event later than March 15 of the calendar year following the later of (aa) the calendar year in which the Bonus is earned or (bb) the calendar year in which the Bonus is no longer subject to a substantial risk of forfeiture within the meaning of Section 409A.

(II)Continuation Benefits. Executive shall be entitled to continuation of group health coverage (including medical, dental, and vision benefits, to the extent permitted under the applicable plan) and the health care flexible spending account (to the extent required to comply with COBRA continuation coverage requirements) (collectively, the “Continuation Benefits”) in accordance with the applicable plan terms for a period of up to eighteen (18) months following the date of Executive's Separation from Service (the “Benefit Continuation Period”); provided, however, that Executive pays the full cost of his or her coverage under such plans, except that Executive shall pay only the required contributions for any health care continuation coverage required to be provided to or on behalf of Executive under the Consolidated Omnibus Budget Reconciliation Act of 1985, as amended (“COBRA”), on the same basis as any other plan participant electing similar COBRA continuation coverage under the Company health plan; and provided, further, that any such coverage shall terminate to the extent that Executive is offered or obtains comparable benefits from any other employer during the Benefit Continuation Period. Executive shall be reimbursed by the Company, on an after-tax basis, for his or her cost of the Continuation Benefits (except that the reimbursement for his or her required contributions for COBRA health care continuation coverage shall be reduced by an amount equal to the cost paid by an active employee for similar coverage under the Company health plan). The amount of expenses eligible for reimbursement or Continuation Benefits provided during one calendar year shall not affect the expenses eligible for reimbursement or amount of Continuation Benefits provided during a subsequent calendar year (except with respect to health plan maximums imposed on the reimbursement of expenses referred to in Code Section 105(b)), the right to reimbursement or Continuation Benefits may not be exchanged or substituted for other forms of compensation to Executive, and any reimbursement or payment under the Continuation Benefits arrangements will be paid in accordance with applicable plan terms and no later than the last day of the calendar year following the calendar year in which Executive incurred the expense giving rise to such reimbursement or payment.

(iii)Forfeiture. Notwithstanding the foregoing, if Executive breaches any provision of Section 12 hereof, the remaining balances of the Severance Payment, the Prorated Bonus, and any Continuation Benefits shall be forfeited.

(c)“Separation from Service.” For purposes of this Agreement, the term “Separation from Service” means a “separation from service” as such term is defined under Section 409A. The terms “terminate,” “termination,” “termination of employment,” and variations thereof, when used in this Agreement in connection with Executive's employment, are intended to mean a termination of employment that constitutes a Separation from Service. For purposes of the determination of whether Executive has had a “separation from service” as described under Section 409A, the terms “Company,” “employer” and “service recipient” mean Peabody Energy Corporation and any affiliate with which Peabody Energy Corporation would be considered a single employer under Code Section 414(b) or (c), provided that, in applying Code Section 1563(a)(1), (2), and (3) for purposes of determining a controlled group of corporations under Code Section 414(b), the language “at least 50 percent” is used instead of “at least 80 percent” each place it appears in Code Section 1563(a)(1), (2), and (3), and in applying Treasury Regulation Section 1.414(c)-2 for purposes of determining trades or businesses (whether or not incorporated) that are under common control for purposes of Code Section 414(c), “at least 50 percent” is used instead of “at least 80 percent” each place it appears in Treasury Regulation Section 1.414(c)-2. In addition, where the use of a definition of “Company,” “employer” or “service recipient” for purposes of determining a “separation from service” is based upon legitimate business criteria, in applying Code Section 1563(a)(1), (2), and (3) for purposes of determining a controlled group of corporations under Code Section 414(b), the language “at least 20 percent” is used instead of “at least 80 percent” each place it appears in Code Section 1563(a)(1), (2), and (3), and in applying Treasury Regulation Section 1.414(c)-2 for purposes of determining trades or businesses (whether or not incorporated) that are under common control for purposes of Code Section 414(c), the language “at least 20 percent” is used instead of “at least 80 percent” each place it appears in Treasury Regulation Section 1.414(c)-2.

(d)“Good Reason.” For purposes of this Agreement, the term “Good Reason” means:

(i) a reduction, other than a reduction that generally affects all similarly-situated executives and does not exceed ten percent (10%) in one year or fifteen percent (15%) in the aggregate over three (3) consecutive years, by the Company in Executive's Base Salary from that in effect immediately prior to the reduction (in which event the Severance Payment shall be calculated based on Executive's Base Salary in effect immediately prior to any such reduction);

(ii) a reduction, other than a reduction that generally affects all similarly-situated executives, by the Company in Executive's Bonus opportunity and Long-Term Incentive Award grant date value used to establish Bonus opportunities or Long-Term Incentive Awards, respectively, from time to time, from those in effect immediately prior to any such reduction (in which event any portion of the Severance Payment that relates to Bonus or Long-Term Incentive Awards shall be calculated based on the Bonus opportunity or Long-Term Incentive Award grant date value, as applicable, in effect immediately prior to any such reduction);

(iii)a material reduction in the aggregate program of employee benefits and perquisites to which Executive is entitled (other than a reduction that generally affects all executives);

(iv) relocation of Executive's primary office by more than 50 miles from the

location of Executive's primary office as of the date of this Agreement;

(v) any material diminution or material adverse change in Executive's duties or responsibilities;

(vi)a breach by the Company of a material provision of this Agreement; or

(vii)a failure on the part of the Company to obtain a written assumption of its obligations under this Agreement by a successor owner of substantially all of the Company's assets in connection with a merger, consolidation, asset sale, liquidation, combination or other similar transaction.

Any amounts due to Executive in connection with a termination of employment shall be computed without giving effect to any changes that give rise to Good Reason.

6.3    Voluntary Termination by Executive; Discharge for Cause.

(a) In the event that Executive's employment is terminated (i) by the Company for Cause, as hereinafter defined, in which event no advance written notice is required, or (ii) by Executive for a reason other than Good Reason, Disability or death, the Company shall pay to Executive only the Accrued Obligations.

(b)As used herein, the term “Cause” means:

(i) any material and uncorrected breach by Executive of the terms of this Agreement, including, but not limited to, engaging in action in violation of Section 12 hereof;

(ii) any willful fraud or dishonesty of Executive that has a material detrimental effect on (a) the reputation or business of the Company or any of its subsidiaries or affiliates or (b) Executive's reputation or performance of his or her duties to the Company or any of its subsidiaries or affiliates;

(iii) a deliberate or willful refusal or failure of Executive to comply with any major corporate policy of the Company which is communicated to Executive in writing; or

(iv) Executive's conviction of, or plea of nolo contendere to, any felony if such conviction results in his or her imprisonment or has a material detrimental effect on the reputation or business of the Company or any of its subsidiaries or affiliates;

provided that with respect to clause (i) or (iii) above, Executive shall have ten (10) days following written notice of the conduct which is the basis for the potential termination for Cause within which to cure such conduct to prevent termination for Cause by the Company. If Executive cures the conduct that is the basis for the potential termination for Cause within such ten (10)-day period, the Company's notice of termination shall be deemed withdrawn. Except for violations of Section 12 hereof or termination under Section 6.3(b)(iv) above, only actions, conduct and events occurring during the Term of Employment with the Company shall be the subject of a termination for Cause. In the event that Executive is terminated for failure to meet performance goals, such termination shall be considered a termination without Cause for purposes of his or her right to receive the Severance Payment, the Prorated Bonus and the Continuation Benefits.

6.4    Disability.

(a)In the event of the Disability (as defined in (b) below) of Executive during the Term of Employment, the Company may terminate Executive's Term of Employment upon written notice to Executive (or Executive's personal representative, if applicable) effective upon the date of receipt thereof (the “Disability Commencement Date”). The Company shall pay to Executive the Accrued Obligations as provided in Section 6.1 hereof, and the Prorated Bonus when such bonuses are paid to other senior executives of the Company, but in no event later than March 15 of the calendar year following the calendar year in which Executive's employment terminated.

(b)The term “Disability,” for purposes of this Agreement, generally shall mean Executive's absence from the full-time performance of Executive's duties pursuant to a reasonable determination made in accordance with the Company's long-term disability plan that Executive is disabled and entitled to long-term disability benefits as a result of incapacity due to physical or mental illness that lasts, or is reasonably expected to last, for at least six (6) months.

6.5     Death. In the event of Executive's death during the Term of Employment or at any time thereafter while payments are still owing to Executive under the terms of this Agreement, the Company shall pay to Executive's beneficiary(ies) (to the extent so designated by Executive) or his or her estate (to the extent that no such beneficiary has been designated) the Accrued Obligations as provided in Section 6.1 hereof, and the Prorated Bonus when such bonuses are paid to other senior executives of the Company, but in no event later than March 15 of the calendar year following the calendar year in which Executive's employment terminated.

6.6     No Further Notice or Compensation or Damages. Executive understands and agrees that he or she shall not be entitled to any further notice, compensation or damages upon termination of employment under this Agreement, other than amounts specified in Section 4, this Section 6, any ancillary documents or any plan, program or arrangement of the Company.

6.7     Executive's Duty to Provide Materials. Upon the termination of Executive's employment for any reason, Executive or his or her estate shall surrender to the Company all correspondence, letters, files, contracts, mailing lists, customer lists, advertising materials, ledgers, supplies, equipment, checks, and all other materials and records of any kind that are the property of the Company or any of its subsidiaries or affiliates, that may be in Executive's possession or under his or her control, including, without limitation, any “soft” copies or computerized or electronic versions thereof.

7.     Notices. All notices or communications hereunder shall be in writing, addressed as follows:

To the Company:

Chairman and Chief Executive Officer

Peabody Energy Corporation

701 Market Street, Suite 900

St. Louis, Missouri 63101-1826

To Executive at the most recent address set forth in the Company's personnel records.

Any such notice or communication shall be delivered by hand or by courier or sent certified or registered mail, return receipt requested, postage prepaid, addressed as above (or to such other address as such party may designate in a notice duly delivered as described above), and the third business day after the actual date of sending shall constitute the time at which notice was given.

8. Severability. If any provision of this Agreement is declared to be invalid or unenforceable, in whole or in part, such invalidity or unenforceability shall not affect the remaining provisions hereof, which shall remain in full force and effect.

9. Assignment. Neither this Agreement nor any rights or obligations hereunder shall be assignable or otherwise subject to hypothecation by Executive (except by will or by operation of the laws of intestate succession) or by the Company, except that the Company may assign this Agreement, in writing, to any successor (whether by merger, purchase, spin-off or otherwise) to all or substantially all of the stock, assets or businesses of the Company. This Agreement shall be binding upon, inure to the benefit of and be enforceable by the heirs and representatives of Executive and the permitted assigns and successors of the Company.

10. Amendment. This Agreement may be amended only by written agreement of the parties hereto.

11. Code Section 409A Compliance.

(a)This Agreement is intended to comply with Section 409A and shall, to the extent practicable, be construed in accordance therewith. Accordingly, notwithstanding anything in this Agreement to the contrary, if the Company determines that Executive is a “specified employee” (as defined in Code Section 409A(a)(2)(B)(i)) at the time of his or her Separation from Service and any amount payable to Executive under this Agreement is a deferral of compensation subject to the additional tax described in Code Section 409A(a)(1)(B) and would be considered a payment upon Executive's Separation from Service, then such amount shall not be paid before the date that is the earlier of (i) six (6) months and one (1) day after Executive's Separation from Service or (ii) Executive's death (the “Delay Period”). Upon the expiration of the Delay Period, the initial payment following the Delay Period shall include a lump sum payment equal to those payments that otherwise would have been paid if the delay had not applied, and any remaining payments due shall be payable in accordance with their original payment schedule.

(b)If either party to this Agreement reasonably determines that any amount payable pursuant to this Agreement would result in adverse tax consequences under Section 409A (including, but not limited to, the additional tax described in Code Section 409A(a)(1)(B)), then such party shall deliver written notice of such determination to the other party, and the parties hereby agree to work in good faith to amend this Agreement so it (i) is exempt from, or compliant with, the requirements of Section 409A and (ii) preserves as nearly as possible the original intent and economic effect of the affected provisions.

12. Nondisclosure of Confidential Information; Non-Competition; Non-Solicitation.

(a) Executive, during the Term of Employment and thereafter, will not, directly or indirectly, use for himself or herself or use for, or disclose to, any party other than the Company, or any subsidiary of the Company (other than in the ordinary course of Executive's duties for the benefit of the Company or any subsidiary of the Company), any secret or confidential information regarding the business or property of the Company or its subsidiaries or regarding any secret or confidential apparatus, process, system, or other method at any time used, developed, acquired, discovered or investigated by or for the Company or its subsidiaries, whether or not developed, acquired, discovered

or investigated by Executive. At the termination of Executive's employment or at any other time the Company or any of its subsidiaries may request, Executive shall promptly deliver to the Company all memoranda, notes, records, plats, sketches, plans or other documents (including, without limitation, any “soft” copies or computerized or electronic versions thereof) made by, compiled by, delivered to, or otherwise acquired by Executive concerning the business or properties of the Company or its subsidiaries or any secret or confidential product, apparatus or process used developed, acquired or investigated by the Company or its subsidiaries.

(b)In consideration of the Company's obligations under this Agreement, Executive agrees that, during his or her employment with the Company and:

(i) for a period of one (1) year thereafter, without the prior written consent of the Chairman and CEO, he or she shall not, directly or indirectly, as principal, manager, agent, consultant, officer, stockholder, partner, investor, lender or employee or in any other capacity, carry on, be engaged in or have any financial interest in, any entity which is in competition with the business of the Company or its subsidiaries; provided, however, that this paragraph (i) shall not apply if the Company does not renew this Agreement and terminates Executive's employment and Executive does not receive severance benefits from the Company; and

(ii) for a period of two (2) years thereafter, without the prior written consent of the Chairman and CEO, he or she shall not, on his or her own behalf or on behalf of any person, firm or company, directly or indirectly, solicit or offer employment to any person who is or has been employed by the Company or its subsidiaries at any time during the twelve (12) months immediately preceding such solicitation.

(c)For purposes of this Section 12, an entity shall be deemed to be in competition with the Company if it is principally involved in the purchase, sale or other dealing in any property or the rendering of any service purchased, sold, dealt in or rendered by the Company as a part of the business of the Company within the same geographic area in which the Company effects such sales or dealings or renders such services. Notwithstanding this Section 12(c) or Section 12(b), nothing herein shall be construed so as to preclude Executive from investing in any publicly or privately held company, provided that Executive's beneficial ownership of any class of securities of an entity in competition with the Company does not exceed five percent (5%) (or such higher percentage approved in writing by the Chairman and CEO) of the outstanding securities of such class.

(d)Executive agrees that the covenant not to compete and the covenant not to solicit are reasonable under the circumstances and will not interfere with his or her ability to earn a living or otherwise to meet his or her financial obligations. Executive and the Company agree that if in the opinion of any court of competent jurisdiction such restraint is not reasonable in any respect, such court shall have the right, power and authority to excise or modify such provision or provisions of this covenant which appear unreasonable and to enforce the remainder of the covenant as so amended. Executive agrees that any breach of the covenants contained in this Section 12 would irreparably injure the Company. Accordingly, Executive agrees that, in the event that a court enjoins Executive from any activity prohibited by this Section 12, the Company may, in addition to pursuing any other remedies it may have in law or in equity, cease making any payments otherwise required by this Agreement and obtain an injunction against Executive from any court having jurisdiction over the matter restraining any further violation of this Agreement by Executive.

13. Beneficiaries; References. Executive shall be entitled to select (and change, to the extent permitted under any applicable law) a beneficiary or beneficiaries to receive any compensation or benefit payable hereunder following Executive's death, and may change such election, in either case by giving the Company written notice thereof. In the event of Executive's death or a judicial determination of his or her incompetence, reference in this Agreement to Executive shall be deemed, where appropriate, to refer to his or her beneficiary, estate or other legal representative. Any reference to the masculine gender in this Agreement shall include, where appropriate, the feminine.

14. Dispute Resolution. Any dispute or controversy arising under or in connection with this Agreement (other than an action to enforce the covenants in Section 12 hereof) or any ancillary documents shall be resolved by arbitration in St. Louis, Missouri. Three arbitrators shall be selected, and arbitration shall be conducted, in accordance with the rules of the American Arbitration Association. The arbitrators shall have the discretion to award the cost of arbitration, arbitrators' fees and the respective attorneys' fees of each party between the parties as they see fit. Notwithstanding anything in this Section 14 to the contrary, payments made under this Section 14 that are provided during one calendar year shall not affect the amount of such payments provided during a subsequent calendar year, payments under this Section 14 may not be exchanged or substituted for other forms of compensation to Executive, and any such payment will be paid within sixty (60) days after Executive prevails, but in no event later than the last day of Executive's taxable year following the taxable year in which he or she incurred the expense giving rise to such payment.

15. Governing Law. This Agreement shall be construed, interpreted and governed in accordance with the laws of the State of Missouri, without reference to rules relating to conflicts of law.

16. Effect on Prior Agreements. This Agreement and any ancillary documents contain the entire understanding between the parties hereto and this Agreement, except as provided in an ancillary document, supersedes in all respects any prior or other agreement or understanding, written or oral, between the Company, any affiliate of the Company or any predecessor of the Company or affiliate of the Company and Executive.

17. Withholding. The Company shall be entitled to withhold from payments to or on behalf of Executive any amount of tax withholding required by law.

18. Currency. All dollar amounts or references contained in this Agreement and any ancillary document refer to the United States dollar.

19. Survival. Notwithstanding the expiration of the term of this Agreement, the applicable provisions of this Agreement (such as Sections 5 through 20) shall remain in effect as long as is reasonably necessary to give effect thereto in accordance with the terms hereof.

20. Counterparts. This Agreement may be executed in two or more counterparts, each of which will be deemed an original.

[SIGNATURE PAGE FOLLOWS]

PEABODY ENERGY CORPORATION
By	/s/ Sharon D. Fiehler
	Sharon D. Fiehler
	Executive Vice President and Chief Administrative Officer
EXECUTIVE
	/s/ Jeane L. Hull
	Jeane L. Hull

EXHIBIT A

RESTRICTED STOCK AGREEMENT

[ATTACHED]

EX-10.101

Exhibit 10.101

INDEMNIFICATION AGREEMENT

This Indemnification Agreement, dated as of March 16, 2011, is made by and between PEABODY ENERGY CORPORATION, a Delaware corporation (the “Corporation”) and JEANE L. HULL (the “Indemnitee”).

RECITALS

A.    The Corporation recognizes that competent and experienced persons are increasingly reluctant to serve or to continue to serve as directors or officers of corporations unless they are protected by comprehensive liability insurance or indemnification, or both, due to increased exposure to litigation costs and risks resulting from their service to such corporations, and due to the fact that the exposure frequently bears no reasonable relationship to the compensation of such directors and officers;

B.    The statutes and judicial decisions regarding the duties of directors and officers are often difficult to apply, ambiguous, or conflicting, and therefore fail to provide such directors and officers with adequate, reliable knowledge of legal risks to which they are exposed or information regarding the proper course of action to take;

C.    The Corporation and Indemnitee recognize that plaintiffs often seek damages in such large amounts and the costs of litigation may be so enormous (whether or not the case is meritorious), that the defense and/or settlement of such litigation is often beyond the personal resources of directors and officers;

D.    The Corporation believes that it is unfair for its directors and officers to assume the risk of huge judgments and other expenses which may occur in cases in which the director or officer received no personal profit and in cases where the director or officer was not culpable;

E.    The Corporation, after reasonable investigation, has determined that the liability insurance coverage presently available to the Corporation may be inadequate in certain circumstances to cover all possible exposure for which Indemnitee should be protected. The Corporation believes that the interests of the Corporation and its stockholders would best be served by a combination of such insurance and the indemnification by the Corporation of the directors and officers of the Corporation;

F.    The Corporation's Amended and Restated Certificate of Incorporation (the “Certificate of Incorporation”) and Amended and Restated By-Laws require the Corporation to indemnify its directors and officers to the fullest extent permitted by the Delaware General Corporation Law (the “DGCL”). The Certificate of Incorporation expressly provides that the indemnification provisions set forth therein are not exclusive, and contemplates that contracts may be entered into between the Corporation and its directors and officers with respect to indemnification;

G.    Section 145 of the DGCL (“Section 145”), under which the Corporation is organized, empowers the Corporation to indemnify its officers, directors, employees and agents by agreement and to indemnify persons who serve, at the request of the Corporation, as the directors, officers, employees or agents of other corporations or enterprises, and expressly provides that the indemnification provided by Section 145 is not exclusive;

H.    The Board of Directors has determined that contractual indemnification as set forth herein is not only reasonable and prudent but also promotes the best interests of the Corporation and its stockholders;

I.    The Corporation desires and has requested Indemnitee to serve or continue to serve as a director or officer of the Corporation free from undue concern for unwarranted claims for damages arising out of or related to such services to the Corporation; and

J.    Indemnitee is willing to serve, continue to serve or to provide additional service for or on behalf of the Corporation on the condition that he is furnished the indemnity provided for herein.

AGREEMENT

NOW, THEREFORE, in consideration of the mutual covenants and agreements set forth below, and other good and valuable consideration, the receipt and adequacy of which are hereby acknowledged, the parties hereto, intending to be legally bound, hereby agree as follows:

Section 1. Generally.

To the fullest extent permitted by the laws of the State of Delaware:

(a) The Corporation shall indemnify Indemnitee if Indemnitee was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative, by reason of the fact that Indemnitee is or was or has agreed to serve at the request of the Corporation as a director, officer, employee or agent of the Corporation, or while serving as a director or officer of the Corporation, is or was serving or has agreed to serve at the request of the Corporation as a director, officer, employee or agent (which, for purposes hereof, shall include a trustee, partner or manager or similar capacity) of another corporation, partnership, joint venture, trust, employee benefit plan or other enterprise, or by reason of any action alleged to have been taken or omitted in such capacity.

(b) The indemnification provided by this Section 1 shall be from and against expenses (including attorneys' fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by Indemnitee or on Indemnitee's behalf in connection with such action, suit or proceeding and any appeal therefrom, but shall only be provided if Indemnitee acted in good faith and in a manner Indemnitee reasonably believed to be in or not opposed to the best interests of the Corporation, and, with respect to any criminal action, suit or proceeding, had no reasonable cause to believe Indemnitee's conduct was unlawful.

(c) Notwithstanding the foregoing provisions of this Section 1, in the case of any threatened, pending or completed action or suit by or in the right of the Corporation to procure a judgment in its favor by reason of the fact that Indemnitee is or was a director, officer, employee or agent of the Corporation, or while serving as a director or officer of the Corporation, is or was serving or has agreed to serve at the request of the Corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust, employee benefit plan or other enterprise, no indemnification shall be made in respect of any claim, issue or matter as to which Indemnitee shall have been adjudged to be liable to the Corporation unless, and only to the extent that, the Delaware Court of Chancery or the court in which such action or suit was brought shall determine upon application that, despite the adjudication of liability but in view of all the circumstances of the case, Indemnitee is fairly and reasonably entitled to indemnity for such expenses which the Delaware Court of Chancery or such other court shall deem proper.

(d) The termination of any action, suit or proceeding by judgment, order, settlement, conviction, or upon a plea of nolo contendere or its equivalent, shall not, of itself, create a presumption that Indemnitee did not act in good faith and in a manner which Indemnitee reasonably believed to be in or not opposed to the best interests of the Corporation, and, with respect to any criminal action or proceeding, had reasonable cause to believe that Indemnitee's conduct was unlawful.

Section 2. Successful Defense; Partial Indemnification. To the extent that Indemnitee has been successful on the merits or otherwise in defense of any action, suit or proceeding referred to in Section 1 hereof or in defense of any claim, issue or matter therein, Indemnitee shall be indemnified against expenses (including attorneys' fees) actually and reasonably incurred in connection therewith. For purposes of this Agreement and without limiting the foregoing, if any action, suit or proceeding is disposed of, on the merits or otherwise (including a disposition without prejudice), without (i) the disposition being adverse to Indemnitee, (ii) an adjudication that Indemnitee was liable to the Corporation, (iii) a plea of guilty or nolo contendere by Indemnitee, (iv) an adjudication that Indemnitee did not act in good faith and in a manner Indemnitee reasonably believed to be in or not opposed to the best interests of the Corporation, and (v) with respect to any criminal proceeding, an adjudication that Indemnitee had reasonable cause to believe Indemnitee's conduct was unlawful, Indemnitee shall be considered for the purposes hereof to have been wholly successful with respect thereto.

If Indemnitee is entitled under any provision of this Agreement to indemnification by the Corporation for some or a portion of the expenses (including attorneys' fees), judgments, fines or amounts paid in settlement actually and reasonably incurred by Indemnitee or on Indemnitee's behalf in connection with any action, suit, proceeding or investigation, or in defense of any claim, issue or matter therein, and any appeal therefrom but not, however, for the total amount thereof, the Corporation shall nevertheless indemnify Indemnitee for the portion of such expenses (including attorneys' fees), judgments, fines or amounts paid in settlement to which Indemnitee is entitled.

Section 3. Determination That Indemnification Is Proper. Any indemnification hereunder shall (unless otherwise ordered by a court) be made by the Corporation unless a determination is made that indemnification of such person is not proper in the circumstances because he or she has not met the applicable standard of conduct set forth in Section 1(b) hereof. Any such determination shall be made (i) by a majority vote of the directors who are not parties to the action, suit or proceeding in question (“disinterested directors”), even if less than a quorum, (ii) by a majority vote of a committee of disinterested directors designated by majority vote of disinterested directors, even if less than a quorum, (iii) by a majority vote of a quorum of the outstanding shares of stock of all classes entitled to vote on the matter, voting as a single class, which quorum shall consist of stockholders who are not at that time parties to the action, suit or proceeding in question, (iv) by independent legal counsel, or (v) by a court of competent jurisdiction.

Section 4. Advance Payment of Expenses; Notification and Defense of Claim.

(a) Expenses (including attorneys' fees) incurred by Indemnitee in defending a threatened or pending civil, criminal, administrative or investigative action, suit or proceeding shall be paid by the Corporation in advance of the final disposition of such action, suit or proceeding within twenty (20) days after receipt by the Corporation of (i) a statement or

statements from Indemnitee requesting such advance or advances from time to time, and (ii) an undertaking by or on behalf of Indemnitee to repay such amount or amounts, only if, and to the extent that, it shall ultimately be determined that Indemnitee is not entitled to be indemnified by the Corporation as authorized by this Agreement or otherwise. Such undertaking shall be accepted without reference to the financial ability of Indemnitee to make such repayment. Advances shall be unsecured and interest-free.

(b) Promptly after receipt by Indemnitee of notice of the commencement of any action, suit or proceeding, Indemnitee shall, if a claim thereof is to be made against the Corporation hereunder, notify the Corporation of the commencement thereof. The failure to promptly notify the Corporation of the commencement of the action, suit or proceeding, or Indemnitee's request for indemnification, will not relieve the Corporation from any liability that it may have to Indemnitee hereunder, except to the extent the Corporation is prejudiced in its defense of such action, suit or proceeding as a result of such failure.

(c) In the event the Corporation shall be obligated to pay the expenses of Indemnitee with respect to an action, suit or proceeding, as provided in this Agreement, the Corporation, if appropriate, shall be entitled to assume the defense of such action, suit or proceeding, with counsel reasonably acceptable to Indemnitee, upon the delivery to Indemnitee of written notice of its election to do so. After delivery of such notice, approval of such counsel by Indemnitee and the retention of such counsel by the Corporation, the Corporation will not be liable to Indemnitee under this Agreement for any fees of counsel subsequently incurred by Indemnitee with respect to the same action, suit or proceeding, provided that (1) Indemnitee shall have the right to employ Indemnitee's own counsel in such action, suit or proceeding at Indemnitee's expense and (2) if (i) the employment of counsel by Indemnitee has been previously authorized in writing by the Corporation, (ii) counsel to the Corporation or Indemnitee shall have reasonably concluded that there may be a conflict of interest or position, or reasonably believes that a conflict is likely to arise, on any significant issue between the Corporation and Indemnitee in the conduct of any such defense or (iii) the Corporation shall not, in fact, have employed counsel to assume the defense of such action, suit or proceeding, then the fees and expenses of Indemnitee's counsel shall be at the expense of the Corporation, except as otherwise expressly provided by this Agreement. The Corporation shall not be entitled, without the consent of Indemnitee, to assume the defense of any claim brought by or in the right of the Corporation or as to which counsel for the Corporation shall have reasonably made the conclusion provided for in clause (ii) above.

(d) Notwithstanding any other provision of this Agreement to the contrary, to the extent that Indemnitee is, by reason of Indemnitee's corporate status with respect to the Corporation or any corporation, partnership, joint venture, trust, employee benefit plan or other enterprise which Indemnitee is or was serving or has agreed to serve at the request of the Corporation, a witness or otherwise participates in any action, suit or proceeding at a time when Indemnitee is not a party in the action, suit or proceeding, the Corporation shall indemnify Indemnitee against all expenses (including attorneys' fees) actually and reasonably incurred by Indemnitee or on Indemnitee's behalf in connection therewith.

Section 5. Procedure for Indemnification

(a) To obtain indemnification, Indemnitee shall promptly submit to the Corporation a written request, including therein or therewith such documentation and information as is reasonably available to Indemnitee and is reasonably necessary to determine whether and to what extent Indemnitee is entitled to indemnification. The Corporation shall, promptly upon receipt of such a request for indemnification, advise the Board of Directors in writing that Indemnitee has requested indemnification.

(b) The Corporation's determination whether to grant Indemnitee's indemnification request shall be made promptly, and in any event within 60 days following receipt of a request for indemnification pursuant to Section 5(a). The right to indemnification as granted by Section 1 of this Agreement shall be enforceable by Indemnitee in any court of competent jurisdiction if the Corporation denies such request, in whole or in part, or fails to respond within such 60-day period. It shall be a defense to any such action (other than an action brought to enforce a claim for the advance of costs, charges and expenses under Section 4 hereof where the required undertaking, if any, has been received by the Corporation) that Indemnitee has not met the standard of conduct set forth in Section 1 hereof, but the burden of proving such defense by clear and convincing evidence shall be on the Corporation. Neither the failure of the Corporation (including its Board of Directors or one of its committees, its independent legal counsel, and its stockholders) to have made a determination prior to the commencement of such action that indemnification of Indemnitee is proper in the circumstances because Indemnitee has met the applicable standard of conduct set forth in Section 1 hereof, nor the fact that there has been an actual determination by the Corporation (including its Board of Directors or one of its committees, its independent legal counsel, and its stockholders) that Indemnitee has not met such applicable standard of conduct, shall be a defense to the action or create a presumption that Indemnitee has or has not met the applicable standard of conduct. The Indemnitee's expenses (including attorneys' fees) incurred in connection with successfully establishing Indemnitee's right to indemnification, in whole or in part, in any such proceeding or otherwise shall also be indemnified by the Corporation.

(c) The Indemnitee shall be presumed to be entitled to indemnification under this Agreement upon submission of a request for indemnification pursuant to this Section 5, and the Corporation shall have the burden of proof in overcoming that

presumption in reaching a determination contrary to that presumption. Such presumption shall be used as a basis for a determination of entitlement to indemnification unless the Corporation overcomes such presumption by clear and convincing evidence.

Section 6. Insurance and Subrogation.

(a) The Corporation may purchase and maintain insurance on behalf of Indemnitee who is or was or has agreed to serve at the request of the Corporation as a director or officer of the Corporation, or is or was serving at the request of the Corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust, employee benefit plan or other enterprise against any liability asserted against, and incurred by, Indemnitee or on Indemnitee's behalf in any such capacity, or arising out of Indemnitee's status as such, whether or not the Corporation would have the power to indemnify Indemnitee against such liability under the provisions of this Agreement. If the Corporation has such insurance in effect at the time the Corporation receives from Indemnitee any notice of the commencement of a proceeding, the Corporation shall give prompt notice of the commencement of such proceeding to the insurers in accordance with the procedures set forth in the policy. The Corporation shall thereafter take all necessary or desirable action to cause such insurers to pay, on behalf of the Indemnitee, all amounts payable as a result of such proceeding in accordance with the terms of such policy.

(b) In the event of any payment by the Corporation under this Agreement, the Corporation shall be subrogated to the extent of such payment to all of the rights of recovery of Indemnitee with respect to any insurance policy, who shall execute all papers required and take all action necessary to secure such rights, including execution of such documents as are necessary to enable the Corporation to bring suit to enforce such rights in accordance with the terms of such insurance policy. The Corporation shall pay or reimburse all expenses actually and reasonably incurred by Indemnitee in connection with such subrogation.

(c) The Corporation shall not be liable under this Agreement to make any payment of amounts otherwise indemnifiable hereunder (including, but not limited to, judgments, fines, ERISA excise taxes or penalties, and amounts paid in settlement) if and to the extent that Indemnitee has otherwise actually received such payment under this Agreement or any insurance policy, contract, agreement or otherwise.

Section 7. Certain Definitions. For purposes of this Agreement, the following definitions shall apply:

(a) The term “action, suit or proceeding” shall be broadly construed and shall include, without limitation, the investigation, preparation, prosecution, defense, settlement, arbitration and appeal of, and the giving of testimony in, any threatened, pending or completed claim, action, suit or proceeding, whether civil, criminal, administrative or investigative.

(b) The term “by reason of the fact that Indemnitee is or was a director, officer, employee or agent of the Corporation, or while serving as a director or officer of the Corporation, is or was serving or has agreed to serve at the request of the Corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust, employee benefit plan or other enterprise” shall be broadly construed and shall include, without limitation, any actual or alleged act or omission to act.

(c) The term “expenses” shall be broadly and reasonably construed and shall include, without limitation, all direct and indirect costs of any type or nature whatsoever (including, without limitation, all attorneys' fees and related disbursements, appeal bonds, other out-of-pocket costs and reasonable compensation for time spent by Indemnitee for which Indemnitee is not otherwise compensated by the Corporation or any third party, provided that the rate of compensation and estimated time involved is approved by the Board, which approval shall not be unreasonably withheld), actually and reasonably incurred by Indemnitee in connection with either the investigation, defense or appeal of a proceeding or establishing or enforcing a right to indemnification under this Agreement, Section 145 of the General Corporation Law of the State of Delaware or otherwise.

(d) The term “judgments, fines and amounts paid in settlement” shall be broadly construed and shall include, without limitation, all direct and indirect payments of any type or nature whatsoever (including, without limitation, all penalties and amounts required to be forfeited or reimbursed to the Corporation, as well as any penalties or excise taxes assessed on a person with respect to an employee benefit plan).

(e) The term “Corporation” shall include, without limitation and in addition to the resulting corporation, any constituent corporation (including any constituent of a constituent) absorbed in a consolidation or merger which, if its separate existence had continued, would have had power and authority to indemnify its directors, officers, and employees or agents, so that any person who is or was a director, officer, employee or agent of such constituent corporation, or is or was serving at the request of such constituent corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust, employee benefit plan or other enterprise, shall stand in the same position under the provisions of this Agreement with respect to the resulting or surviving corporation as he or she would have with respect to such constituent corporation if its separate existence had continued.

(f) The term “other enterprises” shall include, without limitation, employee benefit plans.

(g) The term “serving at the request of the Corporation” shall include, without limitation, any service as a director,

officer, employee or agent of the Corporation which imposes duties on, or involves services by, such director, officer, employee or agent with respect to an employee benefit plan, its participants or beneficiaries.

(h) A person who acted in good faith and in a manner such person reasonably believed to be in the interest of the participants and beneficiaries of an employee benefit plan shall be deemed to have acted in a manner “not opposed to the best interests of the Corporation” as referred to in this Agreement.

Section 8. Limitation on Indemnification. Notwithstanding any other provision herein to the contrary, the Corporation shall not be obligated pursuant to this Agreement:

(a) Claims Initiated by Indemnitee. To indemnify or advance expenses to Indemnitee with respect to an action, suit or proceeding (or part thereof) initiated by Indemnitee, except with respect to an action, suit or proceeding brought to establish or enforce a right to indemnification (which shall be governed by the provisions of Section 8(b) of this Agreement), unless such action, suit or proceeding (or part thereof) was authorized or consented to by the Board of Directors of the Corporation.

(b) Action for Indemnification. To indemnify Indemnitee for any expenses incurred by Indemnitee with respect to any action, suit or proceeding instituted by Indemnitee to enforce or interpret this Agreement, unless Indemnitee is successful in establishing Indemnitee's right to indemnification in such action, suit or proceeding, in whole or in part, or unless and to the extent that the court in such action, suit or proceeding shall determine that, despite Indemnitee's failure to establish their right to indemnification, Indemnitee is entitled to indemnity for such expenses; provided, however, that nothing in this Section 8(b) is intended to limit the Corporation's obligation with respect to the advancement of expenses to Indemnitee in connection with any such action, suit or proceeding instituted by Indemnitee to enforce or interpret this Agreement, as provided in Section 4 hereof.

(c) Section 16 Violations. To indemnify Indemnitee on account of any proceeding with respect to which final judgment is rendered against Indemnitee for payment or an accounting of profits arising from the purchase or sale by Indemnitee of securities in violation of Section 16(b) of the Securities Exchange Act of 1934, as amended, or any similar successor statute.

(d) Non-compete and Non-disclosure. To indemnify Indemnitee in connection with proceedings or claims involving the enforcement of non-compete and/or non-disclosure agreements or the non-compete and/or non-disclosure provisions of employment, consulting or similar agreements the Indemnitee may be a party to with the Corporation, or any subsidiary of the Corporation or any other applicable foreign or domestic corporation, partnership, joint venture, trust or other enterprise, if any.

Section 9. Certain Settlement Provisions. The Corporation shall have no obligation to indemnify Indemnitee under this Agreement for amounts paid in settlement of any action, suit or proceeding without the Corporation's prior written consent, which shall not be unreasonably withheld. The Corporation shall not settle any action, suit or proceeding in any manner that would impose any fine or other obligation on Indemnitee without Indemnitee's prior written consent, which shall not be unreasonably withheld.

Section 10. Savings Clause. If any provision or provisions of this Agreement shall be invalidated on any ground by any court of competent jurisdiction, then the Corporation shall nevertheless indemnify Indemnitee as to costs, charges and expenses (including attorneys' fees), judgments, fines and amounts paid in settlement with respect to any action, suit or proceeding, whether civil, criminal, administrative or investigative, including an action by or in the right of the Corporation, to the full extent permitted by any applicable portion of this Agreement that shall not have been invalidated and to the full extent permitted by applicable law.

Section 11. Contribution. In order to provide for just and equitable contribution in circumstances in which the indemnification provided for herein is held by a court of competent jurisdiction to be unavailable to Indemnitee in whole or in part, it is agreed that, in such event, the Corporation shall, to the fullest extent permitted by law, contribute to the payment of Indemnitee's costs, charges and expenses (including attorneys' fees), judgments, fines and amounts paid in settlement with respect to any action, suit or proceeding, whether civil, criminal, administrative or investigative, in an amount that is just and equitable in the circumstances, taking into account, among other things, contributions by other directors and officers of the Corporation or others pursuant to indemnification agreements or otherwise; provided, that, without limiting the generality of the foregoing, such contribution shall not be required where such holding by the court is due to (i) the failure of Indemnitee to meet the standard of conduct set forth in Section 1 hereof, or (ii) any limitation on indemnification set forth in Section 6(c), 8 or 9 hereof.

Section 12. Form and Delivery of Communications. Any notice, request or other communication required or permitted to be given to the parties under this Agreement shall be in writing and either delivered in person or sent by telecopy, telex, telegram, overnight mail or courier service, or certified or registered mail, return receipt requested, postage prepaid, to the parties at the following addresses (or at such other addresses for a party as shall be specified by like notice):

If to the Corporation:

Peabody Energy Corporation

701 Market Street

St. Louis, MO 63101

Attn: Executive Vice President and Chief Legal Officer

Facsimile: (314) 342-3419

If to Indemnitee:

Jeane L. Hull

155 Carondelet Plaza, Apt. 401

Clayton, MO 63105

Facsimile:

Section 13. Subsequent Legislation. If the General Corporation Law of Delaware is amended after adoption of this Agreement to expand further the indemnification permitted to directors or officers, then the Corporation shall indemnify Indemnitee to the fullest extent permitted by the General Corporation Law of Delaware, as so amended.

Section 14. Nonexclusivity. The provisions for indemnification and advancement of expenses set forth in this Agreement shall not be deemed exclusive of any other rights which Indemnitee may have under any provision of law, the Corporation's Certificate of Incorporation or By-Laws, in any court in which a proceeding is brought, the vote of the Corporation's stockholders or disinterested directors, other agreements or otherwise, and Indemnitee's rights hereunder shall continue after Indemnitee has ceased acting as an agent of the Corporation and shall inure to the benefit of the heirs, executors and administrators of Indemnitee. However, no amendment or alteration of the Corporation's Certificate of Incorporation or By-Laws or any other agreement shall adversely affect the rights provided to Indemnitee under this Agreement

Section 15. Enforcement. The Corporation shall be precluded from asserting in any judicial proceeding that the procedures and presumptions of this Agreement are not valid, binding and enforceable. The Corporation agrees that its execution of this Agreement shall constitute a stipulation by which it shall be irrevocably bound in any court of competent jurisdiction in which a proceeding by Indemnitee for enforcement of his rights hereunder shall have been commenced, continued or appealed, that its obligations set forth in this Agreement are unique and special, and that failure of the Corporation to comply with the provisions of this Agreement will cause irreparable and irremediable injury to Indemnitee, for which a remedy at law will be inadequate. As a result, in addition to any other right or remedy Indemnitee may have at law or in equity with respect to breach of this Agreement, Indemnitee shall be entitled to injunctive or mandatory relief directing specific performance by the Corporation of its obligations under this Agreement.

Section 16. Interpretation of Agreement. It is understood that the parties hereto intend this Agreement to be interpreted and enforced so as to provide indemnification to Indemnitee to the fullest extent now or hereafter permitted by law.

Section 17. Entire Agreement. This Agreement and the documents expressly referred to herein constitute the entire agreement between the parties hereto with respect to the matters covered hereby, and any other prior or contemporaneous oral or written understandings or agreements with respect to the matters covered hereby are expressly superceded by this Agreement.

Section 18. Modification and Waiver. No supplement, modification or amendment of this Agreement shall be binding unless executed in writing by both of the parties hereto. No waiver of any of the provisions of this Agreement shall be deemed or shall constitute a waiver of any other provision hereof (whether or not similar) nor shall such waiver constitute a continuing waiver.

Section 19. Successor and Assigns. All of the terms and provisions of this Agreement shall be binding upon, shall inure to the benefit of and shall be enforceable by the parties hereto and their respective successors, assigns, heirs, executors, administrators and legal representatives. The Corporation shall require and cause any direct or indirect successor (whether by purchase, merger, consolidation or otherwise) to all or substantially all of the business or assets of the Corporation, by written agreement in form and substance reasonably satisfactory to Indemnitee, expressly to assume and agree to perform this Agreement in the same manner and to the same extent that the Corporation would be required to perform if no such succession had taken place.

Section 20. Service of Process and Venue. For purposes of any claims or proceedings to enforce this agreement, the

Corporation consents to the jurisdiction and venue of any federal or state court of competent jurisdiction in the states of Delaware and Missouri, and waives and agrees not to raise any defense that any such court is an inconvenient forum or any similar claim.

Section 21. Governing Law. This Agreement shall be governed exclusively by and construed according to the laws of the State of Delaware, as applied to contracts between Delaware residents entered into and to be performed entirely within Delaware. If a court of competent jurisdiction shall make a final determination that the provisions of the law of any state other than Delaware govern indemnification by the Corporation of its officers and directors, then the indemnification provided under this Agreement shall in all instances be enforceable to the fullest extent permitted under such law, notwithstanding any provision of this Agreement to the contrary.

Section 22. Employment Rights. Nothing in this Agreement is intended to create in Indemnitee any right to employment or continued employment.

Section 23. Counterparts. This Agreement may be executed in two or more counterparts, each of which shall be deemed to be an original and all of which together shall be deemed to be one and the same instrument, notwithstanding that both parties are not signatories to the original or same counterpart.

Section 24. Headings. The section and subsection headings contained in this Agreement are for reference purposes only and shall not affect in any way the meaning or interpretation of this Agreement.

[signatures on following page]

IN WITNESS WHEREOF, this Agreement has been duly executed and delivered to be effective as of the date first above written.

PEABODY ENERGY CORPORATION
By:	/s/ Alexander C. Schoch
	Alexander C. Schoch
	Executive Vice President Law, Chief Legal Officer and Secretary
INDEMNITEE:
By:	/s/ Jeane L. Hull
	Jeane L. Hull

EX-21

Exhibit 21

LIST OF SUBSIDIARIES

Name of Subsidiary	Jurisdiction of Formation
9 East Shipping Limited	U.K.
American Land Development, LLC	Delaware
American Land Holdings of Colorado, LLC	Delaware
American Land Holdings of Illinois, LLC	Delaware
American Land Holdings of Indiana, LLC	Delaware
American Land Holdings of Kentucky, LLC	Delaware
American Land Holdings of West Virginia, LLC	Delaware
Antrim Coal Company Limited	U.K.
Arid Operations Inc.	Delaware
BB Interests Pty Ltd	Australia
Big Ridge, Inc.	Illinois
Big Sky Coal Company	Delaware
Bistrotel Pty Ltd	Australia
Black Hills Mining Company, LLC	Illinois
BTU International B.V.	Holland
BTU Western Resources, Inc.	Delaware
Burton Coal Pty Ltd	Queensland
Caballo Grande, LLC	Delaware
Calera Corporation	Delaware
Capricorn Coal Pty Ltd	Australia
Carbones Del Guasare, S.A.	Venezuela
Carbones Peabody de Venezuela, S.A.	Venezuela
Cardinal Gasification Center LLC	Illinois
Caseyville Dock Company, LLC	Delaware
Central States Coal Reserves of Illinois, LLC	Delaware
Central States Coal Reserves of Indiana, LLC	Delaware
Century Mineral Resources, Inc.	Illinois
CL Power Sales Eight, L.L.C.	Delaware
Coal Reserve Holding Limited Liability Company No. 1	Delaware
COALSALES II, LLC	Delaware
Colorado Yampa Coal Company	Delaware
Complejo Siderurgico Del Lago Cosila, SA	Venezuela
Conexcel 1 Pty Ltd	N.S.W.
Conservancy Resources, LLC	Delaware
Coppabella Coal Pty Ltd	Australia
Cottonwood Land Company	Delaware
Custom Management Services Pty Ltd	Australia
Custom Mining (Monto) Pty Ltd	Australia
Custom Mining Dingo Pty Ltd	Australia
Custom Mining Management Pty Ltd	Australia
Custom Mining Pty Ltd	Australia
Cyprus Creek Land Company	Delaware
Cyprus Creek Land Resources, LLC	Delaware
Dalrymple Bay Coal Terminal Pty Ltd	Queensland
Desarrollos Venshelf IV, CA	Venezuela
Dominion Terminal Associates	Virginia
Dyson Creek Coal Company, LLC	Delaware
Dyson Creek Mining Company, LLC	Delaware
Econo-Power International Corporation	Nevada
El Segundo Coal Company, LLC	Delaware
Elkland Holdings, LLC	Delaware
Excel Equities International Pty Ltd	Australia
Excelven Pty Ltd	British V.I.

Falcon Coal Company, LLC	Delaware
FutureGen Industrial Alliance, Inc.	Delaware
Gallo Finance Company	Delaware
Gold Fields Chile, LLC	Delaware
Gold Fields Mining, LLC	Delaware
Gold Fields Ortiz, LLC	Delaware
Gravi Mag LLC	Mongolia
GreatPoint Energy, Inc.	Delaware
Green Gen Company Limited	China
GTN Copper Technology Pty Limited	Australia
Guaniamo Mining Corporation	Venezuela
Half-Tide Marine Pty Ltd	Queensland
Hayden Gulch Terminal, LLC	Delaware
Helensburgh Coal Pty Ltd	Australia
Highwall Mining Services Company	Delaware
Hillside Recreational Lands, LLC	Delaware
HMC Mining, LLC	Delaware
Illinois Land Holdings, LLC	Illinois
Independence Material Handling, LLC	Delaware
Islands of Waterside Homebuilding, LLC	Delaware
Islands of Waterside, LLC	Delaware
James River Coal Terminal, LLC	Delaware
Juniper Coal Company	Delaware
Kayenta Mobile Home Park, Inc.	Delaware
Kentucky Syngas, LLC	Delaware
Kentucky United Coal, LLC	Indiana
Lively Grove Energy Partners, LLC	Delaware
Lively Grove Energy, LLC	Delaware
LRCS Limited Partnership	New Mexico
Macarthur Berrigurra Pty Ltd	Australia
Macarthur Coal (C&M Equipment) Pty Ltd	Australia
Macarthur Coal (C&M Management) Pty Ltd	Australia
Macarthur Coal (Equipment) Pty Ltd	Australia
Macarthur Coal Exploration Pty Ltd	Australia
Macarthur Coal Financing Pty Ltd	Australia
Macarthur Coal Limited	Australia
Macarthur Coal Management Pty Ltd	Australia
Macarthur Coal Mine Management Pty Ltd	Australia
Macarthur Rush Pty Ltd	Australia
Marigold Electricity, LLC	Delaware
MCG Coal Holdings Pty Ltd	Australia
MCG Coal Pty Ltd	Australia
Mega Uranium Ltd	Canada
Metropolitan Collieries Pty Ltd	Australia
Midco Supply and Equipment Corporation	Illinois
Middlemount Coal Pty Ltd	Australia
Middlemount Mine Management Pty Ltd	Australia
Midwest Coal Acquisition Corp.	Delaware
Midwest Coal Reserves of Illinois, LLC	Delaware
Midwest Coal Reserves of Indiana, LLC	Delaware
Midwest Coal Reserves of Kentucky, LLC	Delaware
Millennium Coal Pty Ltd	Australia
Moffat County Mining, LLC	Delaware
Monto Coal 2 Pty Ltd	Australia
Monto Coal Pty Ltd	Australia
Moorvale Coal Pty Ltd	Australia
Moorvale West Coal Pty Ltd	Australia
Mount Thorley Coal Loading Ltd	Australia

MUC Resources LLC	Mongolia
Mustang Clean Energy, LLC	Delaware
Mustang Energy Company, L.L.C.	Delaware
New Mexico Coal Resources, LLC	Delaware
Newcastle Coal Infrastructure Group Pty Ltd	Australia
Newcastle Coal Shippers Pty Ltd	N.S.W.
Newhall Funding Company	Massachusetts
North Bowen Basin Coal Exploration JV	Australia
North Goonyella Coal Mines Pty Ltd	Queensland
North Wambo Pty Ltd	Australia
Olive Downs Coal Pty Ltd	Australia
P&L Receivables Company, LLC	Delaware
Pacific Export Resources, LLC	Delaware
Peabody (Bowen) Pty Ltd	Queensland
Peabody (Burton Coal) Pty Ltd	Queensland
Peabody (Horse Creek) Pty Ltd	Australia
Peabody (Kogan Creek) Pty Ltd.	Queensland
Peabody (Wilkie Creek) Pty Ltd.	South Australia
Peabody Acquisition Co. No. 2 Pty Ltd.	Australia
Peabody Acquisition Cooperatie B.V.	Netherlands
Peabody Acquisition Cooperatie U.A.	Australia
Peabody AMBV2 B.V.	Netherlands
Peabody America, Inc.	Delaware
Peabody Archveyor, L.L.C.	Delaware
Peabody Arclar Mining, LLC	Indiana
Peabody Australia Holdco Pty Ltd	Australia
Peabody Australia Mining Pty Ltd.	N.S.W.
Peabody Bear Run Mining, LLC	Delaware
Peabody Bear Run Services, LLC	Delaware
Peabody Caballo Mining, LLC	Delaware
Peabody Cardinal Gasification, LLC	Delaware
Peabody China, LLC	Delaware
Peabody Coal Venezuela Ltd.	Bermuda
Peabody Coalsales Australia Pty Ltd.	Australia
Peabody COALSALES, LLC	Delaware
Peabody COALTRADE Asia Private Ltd	Singapore
Peabody Coaltrade Australia Pty Limited	N.S.W.
Peabody Coaltrade GmbH	Germany
Peabody COALTRADE International (CTI), LLC	Delaware
Peabody COALTRADE International Limited	England
Peabody COALTRADE, LLC	Delaware
Peabody Colorado Operations, LLC	Delaware
Peabody Colorado Services, LLC	Delaware
Peabody Coulterville Mining, LLC	Delaware
Peabody Development Company, LLC	Delaware
Peabody Electricity, LLC	Delaware
Peabody Employment Services, LLC	Delaware
Peabody Energy (Botswana) (Proprietary) Limited	Botswana
Peabody Energy (Gibraltar) Limited	Gibraltar
Peabody Energy (Gibraltar) Limited and Co SCS	Luxembourg
Peabody Energy Australia Coal Pty Limited	N.S.W.
Peabody Energy Australia Pty Ltd	N.S.W.
Peabody Energy Corporation	Delaware
Peabody Energy Finance Pty Ltd	Australia
Peabody Energy Generation Holding Company	Delaware
Peabody Energy Investments, Inc.	Delaware
Peabody Energy Solutions, Inc.	Delaware
Peabody Gateway North Mining, LLC	Delaware

Peabody Gateway Services, LLC	Delaware
Peabody Global Services Pte Ltd.	Singapore
Peabody Gobi LLC	Mongolia
Peabody Holding Company, LLC	Delaware
Peabody Holdings (Gibraltar) Ltd.	Gibraltar
Peabody Holland B.V.	Netherlands
Peabody Illinois Services, LLC	Delaware
Peabody Indiana Services, LLC	Delaware
Peabody International Investments, Inc.	Delaware
Peabody International Services, Inc.	Delaware
Peabody Investment & Development Business Services Beijing Co., Ltd.	China
Peabody Investments (Australia) B.V.	Netherlands
Peabody Investments (Gibraltar) Ltd.	Gibraltar
Peabody Investments Corp.	Delaware
Peabody Investments Pte Ltd.	Singapore
Peabody MCC (Gibraltar) Limited	Gibraltar
Peabody MCC Holdco Pty Ltd	Australia
Peabody Midwest Management Services, LLC	Delaware
Peabody Midwest Mining, LLC	Delaware
Peabody Midwest Operations, LLC	Delaware
Peabody Midwest Services, LLC	Delaware
Peabody Mongolia, LLC	Delaware
Peabody Mozambique, Limitada	Mozambique
Peabody Natural Gas, LLC	Delaware
Peabody Natural Resources Company	Delaware
Peabody New Mexico Services, LLC	Delaware
Peabody Operations Holding, LLC	Delaware
Peabody Pastoral Holdings Pty Ltd	Australia
Peabody Powder River Mining, LLC	Delaware
Peabody Powder River Operations, LLC	Delaware
Peabody Powder River Services, LLC	Delaware
Peabody PowerTree Investments, LLC	Delaware
Peabody Recreational Lands, L.L.C.	Delaware
Peabody Rocky Mountain Management Services, LLC	Delaware
Peabody Rocky Mountain Services, LLC	Delaware
Peabody Sage Creek Mining, LLC	Delaware
Peabody School Creek Mining, LLC	Delaware
Peabody Services Holding, LLC	Delaware
Peabody Southwest, LLC	Delaware
Peabody Southwestern Coal Company	Delaware
Peabody Terminal Holding Company, Inc.	Delaware
Peabody Terminals, LLC	Delaware
Peabody Twentymile Mining, LLC	Delaware
Peabody Venezuela Coal Corporation	Delaware
Peabody Venture Fund, LLC	Delaware
Peabody Western Coal Company	Delaware
Peabody Wild Boar Mining, LLC	Delaware
Peabody Wild Boar Services, LLC	Delaware
Peabody Williams Fork Mining, LLC	Delaware
Peabody Wyoming Gas, LLC	Delaware
Peabody Wyoming Services, LLC	Delaware
Peabody-Waterside Development, L.L.C.	Delaware
Peabody-Winsway Resources BV	Netherlands
Peabody-Winsway Resources LLC	Mongolia
PEAMCoal Holdings Pty Ltd.	Australia
PEAMCoal Pty Ltd	Australia
PEC Equipment Company, LLC	Delaware
PG INVESTMENTS SIX, L.L.C.	Delaware

Point Pleasant Dock Company, LLC	Delaware
Pond River Land Company	Delaware
Porcupine Production, LLC	Delaware
Porcupine Transportation, LLC	Delaware
Port Kembla Coal Terminal Ltd	N.S.W.
PowerTree Carbon Company, LLC	Delaware
Prairie State Energy Campus Management, Inc.	Indiana
PT Peabody Coaltrade Indonesia	Indonesia
Red Mountain Infrastructure Pty Ltd	Australia
Red Mountain JV	Australia
Ribfield Pty Ltd	Australia
Riverview Terminal Company	Delaware
Sage Creek Holdings, LLC	Delaware
School Creek Coal Resources, LLC	Delaware
Seaham No. 4 Colliery Pty Ltd	Australia
Seneca Coal Company, LLC	Delaware
Shoshone Coal Corporation	Delaware
Star Lake Energy Company, L.L.C.	Delaware
Sterling Centennial Insurance Corp.	Virginia
Sterling Centennial Missouri Insurance Corporation	Missouri
Sugar Camp Properties, LLC	Delaware
Thoroughbred Generating Company, LLC	Delaware
Thoroughbred Mining Company, L.L.C.	Delaware
Transportes Coal Sea de Venezuela, CA	Venezuela
Twentymile Coal, LLC	Delaware
United Minerals Company, LLC	Indiana
Wambo Coal Pty Ltd	Australia
Wambo Coal Terminal Pty Ltd	Australia
West Burton Coal Pty Ltd	Australia
West Rolleston Coal Pty	Australia
West Roundup Resources, LLC	Delaware
West Walker Coal Pty	Australia
Wilpinjong Coal Pty Ltd	Australia
Winsway Coking Coal Holdings Limited	BVI
Wyoming Quality Healthcare Coalition, LLC	Delaware

EX-23

Exhibit 23

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the following Registration Statements:

1. Registration Statement (Form S-8 No. 333-61406) pertaining to the Peabody Energy Corporation Employee Stock Purchase Plan (as amended), Long-Term Equity Incentive Plan, and Equity Incentive Plan for Nonemployee Directors,

2. Registration Statement (Form S-8 No. 333-70910) pertaining to the Peabody Holding Company, Inc., Employee Retirement Account, Lee Ranch Coal Company Retirement and Savings Plan for Salaried Employees, Lee Ranch Coal Company Retirement and Savings Plan for Hourly Employees, and Western Surface Agreement - UMWA 401(k) Plan,

3. Registration Statement (Form S-8 No. 333-75058) pertaining to the Peabody Energy Corporation Deferred Compensation Plan;

4. Registration Statement (Form S-8 No. 333-109305) pertaining to the Black Beauty Coal Company 401(k) Plan,

5. Registration Statement (Form S-8 No. 333-105455) pertaining to the 1998 Stock Purchase and Option Plan for Key Employees of Peabody Energy Corporation,

6. Registration Statement (Form S-8 No. 333-105456) pertaining to the 1998 Stock Purchase and Option Plan for Key Employees of Peabody Energy Corporation

7. Registration Statement (Form S-8 No. 333-117767) pertaining to the Peabody Energy Corporation 2004 Long-Term Equity Incentive Plan,

8. Registration Statement (Form S-8 No. 333-136443) pertaining to the Big Ridge, Inc. 401(k) Profit Sharing Plan and Trust,

9. Registration Statement (Form S-8 No. 333-140218) pertaining to the Peabody Investments Corporation Employee Retirement Account and the Peabody Western - UMWA 401(k) Plan,

10. Registration Statement (Form S-8 No. 333-147507) pertaining to the Peabody Energy Corporation Australian Employee Stock Purchase Plan,

11. Registration Statement (Form S-8 No. 333-176129) pertaining to the Peabody Energy Corporation 2011 Long-Term Equity Incentive Plan, and

12. Registration Statement (Form S-3 No. 333-161179) of Peabody Energy Corporation;

of our reports dated February 27, 2012, with respect to the consolidated financial statements and schedule of Peabody Energy Corporation, and the effectiveness of internal control over financial reporting of Peabody Energy Corporation, included in this Annual Report (Form 10-K) of Peabody Energy Corporation for the year ended December 31, 2011.

/s/  Ernst & Young LLP

St. Louis, Missouri

February 27, 2012

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Gregory H. Boyce, certify that:

1. I have reviewed this annual report on Form 10-K of Peabody Energy Corporation (“the registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 27, 2012

/s/ Gregory H. Boyce  

Gregory H. Boyce 

Chairman and Chief Executive Officer 

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Michael C. Crews, certify that:

1. I have reviewed this annual report on Form 10-K of Peabody Energy Corporation (“the registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 27, 2012

/s/ Michael C. Crews 

Michael C. Crews

Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

(18 U.S.C. SECTION 1350)

I, Gregory H. Boyce, Chairman and Chief Executive Officer of Peabody Energy Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) the Annual Report on Form 10-K for the annual period ended December 31, 2011 (the “Periodic Report”) which this statement accompanies fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) information contained in the Periodic Report fairly presents, in all material respects, the financial condition and results of operations of Peabody Energy Corporation.

Dated: February 27, 2012

/s/ Gregory H. Boyce  

Gregory H. Boyce 

Chairman and Chief Executive Officer 

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

(18 U.S.C. SECTION 1350)

I, Michael C. Crews, Executive Vice President and Chief Financial Officer of Peabody Energy Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) the Annual Report on Form 10-K for the annual period ended December 31, 2011 (the “Periodic Report”) which this statement accompanies fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) information contained in the Periodic Report fairly presents, in all material respects, the financial condition and results of operations of Peabody Energy Corporation.

Dated: February 27, 2012

/s/ Michael C. Crews  

Michael C. Crews

Executive Vice President and Chief Financial Officer

EX-95

Exhibit 95

Mine Safety Disclosures

The following disclosures are provided pursuant to Section 1503 of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) and Item 104 of Regulation S-K, which require certain disclosures by companies required to file periodic reports under the Securities Exchange Act of 1934, as amended, that operate coal mines regulated under the Federal Mine Safety and Health Act of 1977 (the Mine Act). The disclosures reflect United States (U.S.) mining operations only as the requirements of the Dodd-Frank Act and Item 104 of Regulation S-K do not apply to our mines operated outside the U.S. 

Mine Safety Information.  Whenever the Mine Safety and Health Administration (MSHA) believes that a violation of the Mine Act, any health or safety standard, or any regulation has occurred, it may issue a citation which describes the violation and fixes a time within which the operator must abate the violation. In some situations, such as when MSHA believes that conditions pose a hazard to miners, MSHA may issue an order removing miners from the area of the mine affected by the condition until hazards are corrected. Whenever MSHA issues a citation or order, it generally proposes a civil penalty, or fine, as a result of the violation that the operator is ordered to pay. Citations and orders can be contested and appealed, and as part of that process, are often reduced in severity and amount, and are sometimes dismissed. The number of citations, orders and proposed assessments vary depending on the size and type (underground or surface) of the mine as well as by the MSHA inspector(s) assigned to that mine. Since MSHA is a branch of the U.S. Department of Labor, its jurisdiction applies only to our U.S. mines. As such, the mine safety disclosures that follow contain no information for our Australian mines.

The table that follows reflects citations and orders issued to us by MSHA during the year ended December 31, 2011, as reflected in our systems. Due to timing and other factors, our data may not agree with the mine data retrieval system maintained by MSHA. The proposed assessments for the year ended December 31, 2011 were taken from the MSHA system as of February 23, 2012.

Additional information follows about MSHA references used in the table.

• Section 104 Citations: The total number of violations received from MSHA under section 104 of the Mine Act, which includes citations for health or safety standards that could significantly and substantially contribute to a serious injury if left unabated.

• Section 104(b)Orders: The total number of orders issued by MSHA under section 104(b) of the Mine Act, which represents a failure to abate a citation under section 104(a) within the period of time prescribed by MSHA. This results in an order of immediate withdrawal from the area of the mine affected by the condition until MSHA determines that the violation has been abated.

• Section 104(d)Citations and Orders: The total number of citations and orders issued by MSHA under section 104(d) of the Mine Act for unwarrantable failure to comply with mandatory health or safety standards.

• Section 104(e) Notices: The total number of notices issued by MSHA under Section 104(e) of the Mine Act for a pattern of violations that could contribute to mine health or safety hazards.

• Section 110(b)(2)Violations: The total number of flagrant violations issued by MSHA under section 110(b)(2) of the Mine Act.

• Section 107(a)Orders: The total number of orders issued by MSHA under section 107(a) of the Mine Act for situations in which MSHA determined an imminent danger existed.

• Proposed MSHA Assessments: The total dollar value of proposed assessments from MSHA.

• Fatalities: The total number of related fatalities.

Year Ended December 31, 2011

	Section 104 Citations	Section 104(b) Orders	Section 104(d) Citations and Orders	Section 104(e) Potential Pattern of Violations	Section 110(b)(2) Violations	Section 107(a) Orders	($) Proposed MSHA Assessments
Mine(1)								Fatalities
							(In thousands)
Western U.S. Mining
Caballo	17	—	—	—	—	—	7.4	—
El Segundo	38	—	—	—	—	—	16.7	—
Kayenta	74	—	4	—	—	—	60.8	1
Lee Ranch	23	—	—	—	—	—	12.8	—
North Antelope Rochelle	36	—	—	—	—	—	166.8	—
Rawhide	4	—	—	—	—	—	3.1	—
Twentymile (Foidel Creek)	217	—	2	—	—	—	289.2	—
Midwestern U.S. Mining
Air Quality	536	1	12	—	—	2	693.2	—
Air Quality South Wash Plant	2	—	—	—	—	—	0.5	—
Bear Run	29	—	—	—	—	—	11.6	—
Cottage Grove (Wildcat Hills-Cottage Grove Pit)	16	—	—	—	—	—	10.0	—
Farmersburg(2)	4	—	—	—	—	—	0.3	—
Francisco Surface(2)	11	—	—	—	—	—	9.0	—
Francisco Underground	477	1	5	—	—	1	463.2	—
Gateway	347	—	5	—	—	—	285.0	—
Gateway Prep Plant	10	—	—	—	—	—	1.1	—
Midwest Repair Facility (Columbia Maintenance Services)	4	—	—	—	—	1	1.0	—
Sage Creek(3)	3	—	—	—	—	—	0.3	—
Somerville Central	19	—	1	—	—	—	16.5	—
Viking - Corning	22	—	—	—	—	—	17.4	—
Viking - Knot Pit	3	—	—	—	—	—	5.6	—
Wild Boar	9	—	—	—	—	—	0.9	—
Wildcat Hills Underground	225	—	—	—	—	—	264.5	—
Willow Lake Central Preparation Plant	2	—	—	—	—	—	0.4	—
Willow Lake Portal	849	2	32	1	—	—	1,933.0	—

⁽¹⁾  The definition of mine under section 3 of the Mine Act includes the mine, as well as other items used in, or to be used in, or resulting from, the work of extracting coal, such as land, structures, facilities, equipment, machines, tools and coal preparation facilities. Also, there are instances where the mine name per the MSHA system differs from the mine name utilized by us. Where applicable, we have parenthetically listed the name of the mine per the MSHA system. Also, all mines are listed alphabetically within each of our U.S. mining segments.

⁽²⁾  Mine was closed as of January 1, 2011.

⁽³⁾  Mine has yet to commence operations.

On November 19, 2010, we received a written notice from MSHA that a potential pattern of violations existed at our Willow Lake Mine. On March 15, 2011, the Willow Lake Mine was notified by MSHA that it will not be considered for a Pattern of Violation notice pursuant to section 104(e)(1) of the Mine Act as a result of the mine’s progress during the evaluation period. On November 30, 2011, Willow Lake received a written notice from MSHA that a potential pattern of violations exists. In January 2012, MSHA began a complete review of the mine, which continues as of February 23, 2012.

Pending Legal Actions. The Federal Mine Safety and Health Review Commission (the Commission) is an independent adjudicative agency that provides administrative trial and appellate review of legal disputes arising under the Mine Act. These cases may involve, among other questions, challenges by operators to citations, orders and penalties they have received from MSHA, or complaints of discrimination by miners under Section 105 of the Mine Act. The following is a brief description of the types of legal actions that may be brought before the Commission.

• Contests of Citations and Orders — A contest proceeding may be filed with the Commission by operators, miners or miners’ representatives to challenge the issuance of a citation or order issued by MSHA.

• Contests of Proposed Penalties (Petitions for Assessment of Penalties) — A contest of a proposed penalty is an administrative proceeding before the Commission challenging a civil penalty that MSHA has proposed for the violation contained in a citation or order.

• Complaints for Compensation — A complaint for compensation may be filed with the Commission by miners entitled to compensation when a mine is closed by certain withdrawal orders issued by MSHA. The purpose of the proceeding is to determine the amount of compensation, if any, due miners idled by the orders.

• Complaints of Discharge, Discrimination or Interference — A discrimination proceeding is a case that involves a miner’s allegation that he or she has suffered a wrong by the operator because he or she engaged in some type of activity protected under the Mine Act, such as making a safety complaint.

• Temporary Reinstatement Proceedings — Temporary reinstatement proceedings involve cases in which a miner has filed a complaint with MSHA stating he or she has suffered discrimination and the miner has lost his or her position.

• Emergency Response Plan (ERP) Dispute Proceedings — ERP dispute proceedings are cases brought before the Commission when an operator is issued a citation because it has not agreed to include a certain provision in its ERP.

The table that follows presents information by mine regarding pending legal actions before the Commission at December 31, 2011. Each legal action is assigned a docket number by the Commission and may have as its subject matter one or more citations, orders, penalties or complaints.

	Pending Legal Actions
	Number of Pending Legal Actions as of December 31, 2011			Legal Actions Initiated in 2011	Legal Actions Resolved in 2011
		Pre-Penalty Contests of Citations/Orders	Contests of Penalty Assessment
Mine(1)
Western U.S. Mining
Kayenta	6	3	3	3	3
Lee Ranch	—	—	—	1	1
North Antelope Rochelle	8	3	5	1	5
Rawhide	4	3	1	—	—
Twentymile (Foidel Creek)	30	—	30	13	20
Midwestern U.S. Mining
Air Quality	22	4	18	6	15
Air Quality South Wash Plant	1	—	1	—	—
Cottage Grove (Wildcat Hills-Cottage Grove Pit)	2	—	2	—	—
Francisco Surface	2	—	2	—	1
Francisco Underground	6	1	5	3	2
Gateway	24	15	9	15	7
Midwest Repair Facility (Columbia Maintenance Services)	2	2	—	2	—
Somerville Central	2	—	2	1	1
Vermilion Grove (Riola Complex Vermilion Grove Portal)	1	—	1	—	1
Viking - Corning	1	—	1	—	—
Wildcat Hills Underground	2	—	2	1	—
Willow Lake Portal	76	40	36	41	10

⁽¹⁾  The definition of mine under section 3 of the Mine Act includes the mine, as well as other items used in, or to be used in, or resulting from, the work of extracting coal, such as land, structures, facilities, equipment, machines, tools and coal preparation facilities. Also, there are instances where the mine name per the MSHA system differs from the mine name utilized by us. Where applicable, we have parenthetically listed the name of the mine per the MSHA system. Also, all mines are listed alphabetically within each of our U.S. mining segments.

XML

Inventories (Tables)

12 Months Ended

Dec. 31, 2011

Inventory Disclosure [Abstract]

Inventories

Inventories consisted of the following:

	December 31,
	2011		2010
	(Dollars in millions)
Materials and supplies	$	124.9	$	94.5
Raw coal	95.0		55.4
Saleable coal	226.4		177.3
Total	$	446.3	$	327.2

XML

Share-Based Compensation (Details 5)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Risk-free interest rate	2.00%	2.80%	1.50%
Expected volatility	64.00%	64.00%	60.00%
Dividend yield	0.60%	0.60%	0.90%
Performance unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]
Risk-free interest rate	1.00%	1.70%	1.30%
Expected volatility	64.00%	64.00%	60.00%
Dividend yield	0.60%	0.60%	0.90%

XML

Management - Labor Relations Risk Management - Labor Relations (Tables)

12 Months Ended

Dec. 31, 2011

Risk Management Labor Relations [Abstract]

Schedule of operations with employees represented by labor unions

The following table below presents the Company's operations in which the employees are represented by organized labor unions.

Mine	Current Agreement Expiration Date
U. S.
Willow Lake (1)	-
Kayenta (2)	September 2013
Australia
Owner-operated mines:
North Goonyella (3)	March 2012
North Wambo Underground (3)	April 2012
Wilkie Creek (4)	March 2013
Metropolitan	June 2013
Coppabella	July 2013
Wambo Coal Handling Plant	October 2014
Contractor-operated mines:
Burton (3)	February 2012
Wilpinjong	August 2012
Millennium	September 2012
Moorvale	October 2012
Eaglefield	June 2014
Wambo Open-Cut	August 2014

⁽¹⁾ The labor agreement for the hourly workers at the Company’s Willow Lake Mine in Illinois expired in April 2011. The mine continues to operate without a contract. This agreement covers approximately 9% of the Company’s U.S. subsidiaries’ hourly employees, who generated approximately 1% of the Company’s U.S. production during the year ended December 31, 2011.

⁽²⁾ Hourly workers at the Company’s 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 the Company’s U.S. subsidiaries’ hourly employees, who generated 4% of the Company’s U.S. production during the year ended December 31, 2011.

⁽³⁾ Negotiations for the North Goonyella, North Wambo Underground and Burton mines are underway.

⁽⁴⁾ The Wilkie Creek Mine was held for sale as of December 31, 2011.

XML

Postretirement Health Care and Life Insurance Benefits (Tables) (Postretirement Health Care and Life Insurance Benefits [Member])

12 Months Ended

Dec. 31, 2011

Postretirement Health Care and Life Insurance Benefits [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Components of net periodic postretirement benefit cost

Net periodic postretirement benefit cost included the following components:

	Year Ended December 31,
	2011		2010		2009
	(Dollars in millions)
Service cost for benefits earned	$	13.9	$	12.9	$	10.5
Interest cost on accumulated postretirement benefit obligation	57.9		58.2		55.2
Amortization of prior service cost	2.8		2.6		1.5
Amortization of actuarial loss	26.9		24.9		14.5
Net periodic postretirement benefit cost	$	101.5	$	98.6	$	81.7

Amounts recognized in accumulated other comprehensive loss

The following includes amounts recognized in accumulated other comprehensive loss:

	Year Ended December 31,
	2011			2010			2009
	(Dollars in millions)
Net actuarial loss arising during year	$	86.0		$	45.3		$	165.2
Prior service cost arising during year	(1.4		)	7.9			(10.5		)
Amortization:
Actuarial loss	(26.9		)	(24.9		)	(14.5		)
Prior service cost	(2.8		)	(2.6		)	(1.5		)
Total recognized in other comprehensive loss	54.9			25.7			138.7
Net periodic postretirement benefit cost	101.5			98.6			81.7
Total recognized in net periodic postretirement benefit cost and other comprehensive loss	$	156.4		$	124.3		$	220.4

Reconciled amount of plan's funded status

The following table sets forth the plan’s funded status reconciled with the amounts shown in the consolidated balance sheets:

	December 31,
	2011			2010
	(Dollars in millions)
Change in benefit obligation:
Accumulated postretirement benefit obligation at beginning of period	$	1,031.2		$	982.2
Service cost	13.9			12.9
Interest cost	57.9			58.2
Participant contributions	1.9			2.1
Plan amendments(1)	(1.4		)	7.9
Benefits paid	(68.0		)	(77.4		)
Actuarial loss	86.0			45.3
Accumulated postretirement benefit obligation at end of period	1,121.5			1,031.2
Change in plan assets:
Fair value of plan assets at beginning of period	—			—
Employer contributions	66.1			75.3
Participant contributions	1.9			2.1
Benefits paid and administrative fees (net of Medicare Part D reimbursements)	(68.0		)	(77.4		)
Fair value of plan assets at end of period	—			—
Funded status at end of year	(1,121.5		)	(1,031.2		)
Less current portion (included in Accounts payable and accrued expenses)	68.4			67.3
Noncurrent obligation (included in Accrued postretirement benefit costs)	$	(1,053.1	)	$	(963.9	)

⁽¹⁾  Effective January 1, 2011, certain plans were modified to ensure consistency of benefits across the Company, the impact of which is reflected in the December 31, 2010 figures above.

Weighted-average assumptions used to determine the benefit obligations

The weighted-average assumptions used to determine the benefit obligations as of the end of each year were as follows:

	December 31,
	2011		2010
Discount rate	5.05	%	5.81	%
Rate of compensation increase	N/A		3.50	%
Measurement date	December 31, 2011		December 31, 2010

Weighted-average assumptions used to determine net periodic benefit cost

The weighted-average assumptions used to determine net periodic benefit cost during each year were as follows:

	Year Ended December 31,
	2011		2010		2009
Discount rate	5.81	%	6.14	%	6.85	%
Rate of compensation increase	3.50	%	3.50	%	3.50	%
Measurement date	December 31, 2010		December 31, 2009		December 31, 2008

Assumed health care cost trend rate

The following presents information about the assumed health care cost trend rate:

	Year Ended December 31,
	2011		2010
Health care cost trend rate assumed for next year	9.00	%	9.00	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	5.00	%	5.00	%
Year that the rate reaches the ultimate trend rate	2018		2017

Assumed health care cost trend rates, one percentage point increase

A one-percentage-point change in the assumed health care cost trend would have the following effects:

	One Percentage- Point Increase		One Percentage- Point Decrease
	(Dollars in millions)
Effect on total service and interest cost components	$	8.2	$	(6.9	)
Effect on total postretirement benefit obligation	$	121.8	$	(104.6	)

Summary of estimated future benefit payments

The following benefit payments (net of retiree contributions), which reflect expected future service, as appropriate, are expected to be paid by the Company:

	Postretirement
	Benefits
	(Dollars in millions)
2012	$	68.4
2013	72.9
2014	75.6
2015	77.8
2016	79.9
Years 2017-2021	410.3

XML

Summary Quarterly Financial Information (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended																12 Months Ended
	Dec. 31, 2011		Sep. 30, 2011		Jun. 30, 2011		Mar. 31, 2011		Dec. 31, 2010		Sep. 30, 2010		Jun. 30, 2010		Mar. 31, 2010		Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Summary of the unaudited quarterly results of operations
Revenues	$ 2,253.6		$ 1,997.2		$ 1,980.5		$ 1,743.1		$ 1,792.7		$ 1,826.7		$ 1,629.9		$ 1,490.6		$ 7,974.4	$ 6,739.9	$ 5,847.0
Operating profit	418.3		381.5		479.3		314.3		326.3		447.3		325.7		255.1		1,593.4	1,354.4	822.4
Income from continuing operations, net of income taxes	222.5		285.6		307.8		194.6		223.8		239.3		215.7		147.8		1,010.5	826.6	443.2
Net income	194.0		281.4		292.2		178.7		215.0		236.3		214.2		136.7		946.3	802.2	463.0
Net Income attributable to common stockholders	222.4		274.0		284.8		176.5		210.0		224.1		206.2		133.7		957.7	774.0	448.2
Basic earnings per share - continuing operations	$ 0.93	[1]	$ 1.03	[1]	$ 1.11	[1]	$ 0.71	[1]	$ 0.81	[2]	$ 0.84	[2]	$ 0.77	[2]	$ 0.54	[2]	$ 3.77	$ 2.97	$ 1.60
Diluted earnings per share - continuing operations	$ 0.92		$ 1.02	[1]	$ 1.10	[1]	$ 0.70	[1]	$ 0.80	[2]	$ 0.84	[2]	$ 0.77	[2]	$ 0.54	[2]	$ 3.76	$ 2.93	$ 1.59
Weighted average shares used in calculating basic earnings per share	269.3		269.2		269.0		268.9		267.7		267.1		266.6		266.5		269.1	267.0	265.5
Weighted average shares used in calculating diluted earnings per share	270.2		270.6		270.5		272.8		270.3		268.6		268.3		268.2		270.3	269.9	267.5
Summary Quarterly Financial Information (Textuals) [Abstract]
Acquisition costs	76.1		9.1														85.2	0	0
Adverse impact costs	111.8		122.9
Non cash Expense from the remeasurement of Foreign income tax accounts	16.0				15.4		6.4
Non cash benefit from the remeasurement of Foreign income tax accounts			38.7
Non-cash benefit from the remeasurement of non-U.S income tax accounts									$ (18.9)		$ (43.0)		$ 19.5		$ (5.5)		$ 0.9	$ (47.9)	$ (74.4)

[1] (1) EPS for the quarters may not sum to the amounts for the year as each period is computed on a discrete basis.

[2] EPS for the quarters may not sum to the amounts for the year as each period is computed on a discrete basis

XML

Derivatives and Fair Value Measurements (Details 1) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) recognized in other comprehensive income on derivative (effective portion)	$ 223.6		$ 652.9		$ 523.7
Gain (loss) reclassified from other comprehensive income into income (effective portion)	384.9		151.5		(134.6)
Gain (loss) reclassified from other comprehensive income into income (ineffective portion)	4.8		(1.1)		0.7
Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) recognized in income on non-designated derivatives	(32.8)	[1]	(8.5)	[2]	(2.7)	[3]
Interest rate swaps [Member] | Interest expense [Member] | Cash flow hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) recognized in other comprehensive income on derivative (effective portion)			0.8		0.2
Gain (loss) reclassified from other comprehensive income into income (effective portion)			(0.5)		(5.5)
Gain (loss) reclassified from other comprehensive income into income (ineffective portion)			0		0
Interest rate swaps [Member] | Interest expense [Member] | Cash flow hedges [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) recognized in income on non-designated derivatives			(8.5)	[2]	0
Commodity swaps and options [Member] | Operating costs and expenses [Member] | Cash flow hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) recognized in other comprehensive income on derivative (effective portion)	30.7		29.9		65.5
Gain (loss) reclassified from other comprehensive income into income (effective portion)	42.7		(36.2)		(98.3)
Gain (loss) reclassified from other comprehensive income into income (ineffective portion)	4.8		(1.1)		0.7
Commodity swaps and options [Member] | Operating costs and expenses [Member] | Cash flow hedges [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) recognized in income on non-designated derivatives	0		0		0
Commodity swaps and options [Member] | Operating costs and expenses [Member] | Economic hedge [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) recognized in other comprehensive income on derivative (effective portion)					0
Gain (loss) reclassified from other comprehensive income into income (effective portion)					0
Gain (loss) reclassified from other comprehensive income into income (ineffective portion)					0
Commodity swaps and options [Member] | Operating costs and expenses [Member] | Economic hedge [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) recognized in income on non-designated derivatives					(2.7)	[3]
Diesel fuel hedge contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gains (losses) to be reclassified from comprehensive income to earnings within twelve months	43
U.S. explosives hedge contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gains (losses) to be reclassified from comprehensive income to earnings within twelve months	(6)
Foreign currency contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gains (losses) to be reclassified from comprehensive income to earnings within twelve months	(266)
Foreign currency contracts [Member] | Operating costs and expenses [Member] | Cash flow hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) recognized in other comprehensive income on derivative (effective portion)			622.2		458.0
Gain (loss) reclassified from other comprehensive income into income (effective portion)			188.2		(30.8)
Gain (loss) reclassified from other comprehensive income into income (ineffective portion)			0		0
Foreign currency contracts [Member] | Operating costs and expenses [Member] | Cash flow hedges [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) recognized in income on non-designated derivatives			0		0
Foreign currency contracts [Member] | Acquisition costs related to Macarthur Coal Limited [Member] | Economic hedge [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) recognized in other comprehensive income on derivative (effective portion)	0
Gain (loss) reclassified from other comprehensive income into income (effective portion)	0
Gain (loss) reclassified from other comprehensive income into income (ineffective portion)	0
Foreign currency contracts [Member] | Acquisition costs related to Macarthur Coal Limited [Member] | Economic hedge [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) recognized in income on non-designated derivatives	(32.8)	[1]
Operating Costs [Member] | Operating costs and expenses [Member] | Cash flow hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) recognized in other comprehensive income on derivative (effective portion)	193.4
Gain (loss) reclassified from other comprehensive income into income (effective portion)	342.2
Gain (loss) reclassified from other comprehensive income into income (ineffective portion)	0
Operating Costs [Member] | Operating costs and expenses [Member] | Cash flow hedges [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) recognized in income on non-designated derivatives	0
Capital Expenditures [Member] | Depreciation, depletion and amortization [Member] | Cash flow hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) recognized in other comprehensive income on derivative (effective portion)	(0.5)
Gain (loss) reclassified from other comprehensive income into income (effective portion)	0
Gain (loss) reclassified from other comprehensive income into income (ineffective portion)	0
Capital Expenditures [Member] | Depreciation, depletion and amortization [Member] | Cash flow hedges [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) recognized in income on non-designated derivatives	$ 0

[1] Relates to foreign currency contracts associated with the acquisition of Macarthur shares under the takeover process.

[2] Amounts relate to swaps that were de-designated and terminated in conjunction with the refinancing of the Company's previous credit facility.

[3] Amounts relate to diesel fuel and explosives hedge derivatives that were de-designated in 2009.

XML

Supplemental Guarantor/Non-Guarantor Financial Information (Details 1) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Current assets
Cash and cash equivalents	$ 799.1	$ 1,295.2	$ 988.8	$ 449.7
Accounts receivable, net	922.5	555.8
Inventories	446.3	327.2
Assets from coal trading activities, net	44.6	192.5
Deferred income taxes	27.3	120.4
Other current assets	766.1	467.1
Total current assets	3,005.9	2,958.2
Land and coal interests	10,781.0	7,633.8
Buildings and improvements	1,131.4	1,067.4
Machinery and equipment	2,862.4	1,664.5
Less: accumulated depreciation, depletion and amortization	(3,412.1)	(2,987.6)
Property, plant, equipment and mine development, net	11,362.7	7,378.1
Investments and other assets	2,364.4	1,026.8
Total assets	16,733.0	11,363.1	9,955.3
Current liabilities
Current maturities of long-term debt	101.1	43.2
Payables to (receivables from) affiliates, net	0	0
Liabilities from coal trading activities, net	10.3	181.7
Deferred income taxes	0	0
Accounts payable and accrued expenses	1,712.3	1,288.8
Total current liabilities	1,823.7	1,513.7
Long-term debt, less current maturities	6,556.4	2,706.8
Deferred income taxes	554.2	545.1
Notes payable to (receivables from) affiliates, net	0	0
Other noncurrent liabilities	2,282.9	1,908.2
Total liabilities	11,217.2	6,673.8
Peabody Energy Corporation's stockholders' equity	5,485.1	4,660.7
Noncontrolling interests	30.7	28.6
Total stockholders' equity	5,515.8	4,689.3	3,755.9	3,119.5
Total liabilities and stockholders' equity	16,733.0	11,363.1
Parent Company [Member]
Current assets
Cash and cash equivalents	283.2	903.8	368.4	161.2
Accounts receivable, net	5.3	2.1
Inventories	0	0
Assets from coal trading activities, net	0	0
Deferred income taxes	0	0
Other current assets	305.1	307.9
Total current assets	593.6	1,213.8
Land and coal interests	0	0
Buildings and improvements	0	0
Machinery and equipment	0	0
Less: accumulated depreciation, depletion and amortization	0	0
Property, plant, equipment and mine development, net	0	0
Investments and other assets	10,300.8	9,331.0
Total assets	10,894.4	10,544.8
Current liabilities
Current maturities of long-term debt	62.5	25.0
Payables to (receivables from) affiliates, net	2,417.8	2,225.3
Liabilities from coal trading activities, net	0	0
Deferred income taxes	11.6	6.1
Accounts payable and accrued expenses	69.4	47.4
Total current liabilities	2,561.3	2,303.8
Long-term debt, less current maturities	6,428.8	2,609.6
Deferred income taxes	76.0	93.2
Notes payable to (receivables from) affiliates, net	(3,720.0)	818.9
Other noncurrent liabilities	63.2	58.6
Total liabilities	5,409.3	5,884.1
Peabody Energy Corporation's stockholders' equity	5,485.1	4,660.7
Noncontrolling interests	0	0
Total stockholders' equity	5,485.1	4,660.7
Total liabilities and stockholders' equity	10,894.4	10,544.8
Guarantor Subsidiaries [Member]
Current assets
Cash and cash equivalents	0.8	5.2	0.2	4.5
Accounts receivable, net	100.8	5.5
Inventories	220.0	168.0
Assets from coal trading activities, net	14.9	23.8
Deferred income taxes	48.0	78.6
Other current assets	98.8	30.7
Total current assets	483.3	311.8
Land and coal interests	5,061.8	4,860.7
Buildings and improvements	962.8	945.8
Machinery and equipment	1,507.3	1,300.6
Less: accumulated depreciation, depletion and amortization	(2,623.1)	(2,374.4)
Property, plant, equipment and mine development, net	4,908.8	4,732.7
Investments and other assets	199.7	179.8
Total assets	5,591.8	5,224.3
Current liabilities
Current maturities of long-term debt	0	0
Payables to (receivables from) affiliates, net	(2,529.1)	(2,528.3)
Liabilities from coal trading activities, net	4.2	29.5
Deferred income taxes	0	0
Accounts payable and accrued expenses	868.8	777.2
Total current liabilities	(1,656.1)	(1,721.6)
Long-term debt, less current maturities	0	0.1
Deferred income taxes	126.3	135.4
Notes payable to (receivables from) affiliates, net	(981.5)	(825.3)
Other noncurrent liabilities	1,892.6	1,652.8
Total liabilities	(618.7)	(758.6)
Peabody Energy Corporation's stockholders' equity	6,210.5	5,982.9
Noncontrolling interests	0	0
Total stockholders' equity	6,210.5	5,982.9
Total liabilities and stockholders' equity	5,591.8	5,224.3
Non-Guarantor Subsidiaries [Member]
Current assets
Cash and cash equivalents	515.1	386.2	620.2	284.0
Accounts receivable, net	816.4	548.2
Inventories	226.3	159.2
Assets from coal trading activities, net	29.7	168.7
Deferred income taxes	0	47.9
Other current assets	362.2	128.5
Total current assets	1,949.7	1,438.7
Land and coal interests	5,719.2	2,773.1
Buildings and improvements	168.6	121.6
Machinery and equipment	1,355.1	363.9
Less: accumulated depreciation, depletion and amortization	(789.0)	(613.2)
Property, plant, equipment and mine development, net	6,453.9	2,645.4
Investments and other assets	1,496.1	147.1
Total assets	9,899.7	4,231.2
Current liabilities
Current maturities of long-term debt	38.6	18.2
Payables to (receivables from) affiliates, net	111.3	303.0
Liabilities from coal trading activities, net	6.1	152.2
Deferred income taxes	9.1	0
Accounts payable and accrued expenses	774.1	464.2
Total current liabilities	939.2	937.6
Long-term debt, less current maturities	127.6	97.1
Deferred income taxes	351.9	316.5
Notes payable to (receivables from) affiliates, net	4,701.5	6.4
Other noncurrent liabilities	327.1	196.8
Total liabilities	6,447.3	1,554.4
Peabody Energy Corporation's stockholders' equity	3,421.7	2,648.2
Noncontrolling interests	30.7	28.6
Total stockholders' equity	3,452.4	2,676.8
Total liabilities and stockholders' equity	9,899.7	4,231.2
Eliminations [Member]
Current assets
Cash and cash equivalents	0	0
Accounts receivable, net	0	0
Inventories	0	0
Assets from coal trading activities, net	0	0
Deferred income taxes	(20.7)	(6.1)
Other current assets	0	0
Total current assets	(20.7)	(6.1)
Land and coal interests	0	0
Buildings and improvements	0	0
Machinery and equipment	0	0
Less: accumulated depreciation, depletion and amortization	0	0
Property, plant, equipment and mine development, net	0	0
Investments and other assets	(9,632.2)	(8,631.1)
Total assets	(9,652.9)	(8,637.2)
Current liabilities
Current maturities of long-term debt	0	0
Payables to (receivables from) affiliates, net	0	0
Liabilities from coal trading activities, net	0	0
Deferred income taxes	(20.7)	(6.1)
Accounts payable and accrued expenses	0	0
Total current liabilities	(20.7)	(6.1)
Long-term debt, less current maturities	0	0
Deferred income taxes	0	0
Notes payable to (receivables from) affiliates, net	0	0
Other noncurrent liabilities	0	0
Total liabilities	(20.7)	(6.1)
Peabody Energy Corporation's stockholders' equity	(9,632.2)	(8,631.1)
Noncontrolling interests	0	0
Total stockholders' equity	(9,632.2)	(8,631.1)
Total liabilities and stockholders' equity	$ (9,652.9)	$ (8,637.2)

XML

Financial Instruments and Guarantees with Off-Balance-Sheet Risk (Tables)

12 Months Ended

Dec. 31, 2011

Financial Instruments And Guarantees With Off Balance Sheet Risk Disclosure [Abstract]

Letters of credit, bank guarantees, surety bonds and corporate guarantees

As of December 31, 2011, the Company had the following financial instruments with off-balance sheet risk:

	Reclamation Obligations		Lease Obligations		Workers’ Compensation Obligations		Other(1)		Total
	(Dollars in millions)
Self bonding	$	929.6	$	—	$	—	$	—	$	929.6
Surety bonds	613.2		104.7		13.5		11.0		742.4
Bank guarantees	178.4		—		—		211.2		389.6
Letters of credit	—		—		62.6		20.0		82.6
Bilateral cash collateralization agreements	—		—		—		79.7		79.7
	$	1,721.2	$	104.7	$	76.1	$	321.9	$	2,223.9

⁽¹⁾  Other includes bilateral cash collateralization agreement obligations described below and an additional $242.2 million in bank guarantees, letters of credit and surety bonds related to collateral for surety companies, road maintenance, performance guarantees and other operations.

XML

Income Taxes (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Income from continuing operations before income taxes
U.S.	$ 815.7	$ 535.5	$ 281.4
Non U.S.	558.0	606.5	348.0
Income from continuing operations before income taxes	$ 1,373.7	$ 1,142.0	$ 629.4

XML

Pension and Savings Plans (Details Textuals) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011 years	Dec. 31, 2010	Dec. 31, 2009
Defined Benefit Plan Disclosure [Line Items]
Actuarial gains and losses amortization corridor, percentage		0.00%
Percentage of target allocations for plan assets in equity securities		60.00%
Percentage of target allocations for plan assets in fixed income assets		40.00%
Percentage of target allocations for plan assets in real estate investments		3.00%
Minimum funded status percentage required to prevent benefit restriction and at-risk penalties		80.00%
Defined Contribution Plans [Abstract]
Number of 401(k) plans		3
Paid discretionary contributions to defined contribution pension plans, company match		$ 54.5	$ 51.3	47.9
Additional discretionary contributions to defined contribution pension plans, performance feature		22.5	20.6	20.3
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Actuarial gains and losses amortization corridor, percentage		5.00%
Period of amortization (in years)		5
Estimated net actuarial loss that will be amortized from accumulated other comprehensive loss		48.6
Estimated prior service cost that will be amortized from accumulated other comprehensive loss		1.0
Expected rate of return on plan assets	8.00%	8.25%	8.25%	8.75%
Accumulated benefit obligation for pension plans		$ 963.6	$ 881.0

XML

Leases (Tables)

12 Months Ended

Dec. 31, 2011

Leases [Abstract]

Future minimum lease and royalty payments

Future minimum lease and royalty payments as of December 31, 2011 are as follows:

	Capital Leases		Operating Leases		Coal Lease and Royalty Obligations
Year Ending December 31,
	(Dollars in millions)
2012	$	32.3	$	123.1	$	50.7
2013	41.3		106.2		50.0
2014	25.9		90.6		48.8
2015	10.5		76.4		46.6
2016	10.3		63.5		3.8
2017 and thereafter	21.7		151.1		27.9
Total minimum lease payments	142.0		$	610.9	$	227.8
Less interest	19.5
Present value of minimum capital lease payments	$	122.5

XML

Segment Information

12 Months Ended

Dec. 31, 2011

Segment Reporting [Abstract]

Segment Information

Segment Information

The Company reports its operations primarily through the following reportable operating segments: “Western U.S. Mining,” “Midwestern U.S. Mining,” “Australian Mining,” “Trading and Brokerage” and “Corporate and Other.” The Company's Western U.S. Mining operations reflect the aggregation of the Powder River Basin, Southwest and Colorado mining operations. The mines in that segment are characterized by predominantly surface mining extraction processes, coal with a lower sulfur content and Btu and higher customer transportation costs (due to longer shipping distances). The Company's Midwestern U.S. Mining operations reflect the Company’s Illinois and Indiana mining operations, which are characterized by a mix of surface and underground mining extraction processes, coal with a higher sulfur content and Btu and lower customer transportation costs (due to shorter shipping distances). Geologically, Western operations mine bituminous and subbituminous coal deposits, and Midwestern operations mine bituminous coal deposits. The principal business of the Western and Midwestern U.S. Mining segments is the mining, preparation and sale of thermal coal, sold primarily to electric utilities in the U.S., with a portion sold into the seaborne markets.

The Company’s Australian Mining operations consist of its mines in Queensland and New South Wales, Australia. The mines in that segment are characterized by both surface and underground extraction processes, mining various qualities of metallurgical (low-sulfur, high Btu coal) and thermal coal. The metallurgical coal qualities include hard coking coal, semi-hard coking coal, semi-soft coal and pulverized coal injection coal. The business of the Company's Australian Mining operations are primarily export focused with customers spread across several countries, while a portion of the coal is sold to Australian steel producers and power generators. Generally, revenues from individual countries vary year by year based on the demand for electricity, the demand for steel, the strength of the global economy and several other factors including those specific to each country.

The Company’s Trading and Brokerage segment brokers coal sales of other coal producers both as principal and agent, and trades coal, freight and freight-related contracts. Corporate and Other includes selling and administrative expenses, equity income (loss) from the Company's joint ventures, certain asset sales, resource management costs and revenues, coal royalty expense, costs associated with past mining obligations, expenses related to the Company’s other commercial activities such as generation development and Btu Conversion costs and provisions for certain litigation.

The Company’s chief operating decision maker uses Adjusted EBITDA as the primary measure of segment profit and loss. The Company defines Adjusted EBITDA as income from continuing operations before deducting net interest expense, income taxes, asset retirement obligation expense and depreciation, depletion and amortization.

Operating segment results for the year ended December 31, 2011 were as follows (total assets as of December 31, 2011):

	Western U.S. Mining		Midwestern U.S. Mining		Australian Mining		Trading and Brokerage		Corporate and Other			Consolidated
	(Dollars in millions)
Revenues	$	2,900.4	$	1,481.1	$	3,080.7	$	475.1	$	37.1		$	7,974.4
Adjusted EBITDA	766.0		408.9		1,194.3		197.0		(437.5		)	2,128.7
Total assets	3,095.8		672.5		8,568.9		633.3		3,762.5			16,733.0
Additions to property, plant, equipment and mine development	228.5		108.2		439.6		0.9		69.7			846.9
Loss from equity affiliates	—		—		—		—		19.2			19.2

Operating segment results for the year ended December 31, 2010 were as follows (total assets as of December 31, 2010):

	Western U.S. Mining		Midwestern U.S. Mining		Australian Mining		Trading and Brokerage		Corporate and Other			Consolidated
	(Dollars in millions)
Revenues	$	2,706.3	$	1,320.6	$	2,399.9	$	291.1	$	22.0		$	6,739.9
Adjusted EBITDA	816.7		322.1		977.4		77.2		(354.7		)	1,838.7
Total assets	3,008.4		608.0		3,603.4		398.2		3,745.1			11,363.1
Additions to property, plant, equipment and mine development	143.3		224.9		138.7		0.9		40.1			547.9
Loss from equity affiliates	—		—		—		—		1.7			1.7

Operating segment results for the year ended December 31, 2009 were as follows (total assets as of December 31, 2009):

	Western U.S. Mining		Midwestern U.S. Mining		Australian Mining		Trading and Brokerage		Corporate and Other			Consolidated
	(Dollars in millions)
Revenues	$	2,612.6	$	1,303.8	$	1,512.6	$	391.0	$	27.0		$	5,847.0
Adjusted EBITDA	721.5		281.9		410.5		193.4		(344.5		)	1,262.8
Total assets	3,087.6		444.4		3,386.8		673.0		2,363.5			9,955.3
Additions to property, plant, equipment and mine development	201.9		104.2		69.3		1.8		6.2			383.4
Loss from equity affiliates	—		—		—		—		69.1			69.1

A reconciliation of adjusted EBITDA to consolidated income from continuing operations, net of income taxes follows:

	Year Ended December 31,
	2011			2010			2009
	(Dollars in millions)
Total adjusted EBITDA	$	2,128.7		$	1,838.7		$	1,262.8
Depreciation, depletion and amortization	(482.2		)	(437.1		)	(400.5		)
Asset retirement obligation expense	(53.1		)	(47.2		)	(39.9		)
Interest expense	(238.6		)	(222.0		)	(201.1		)
Interest income	18.9			9.6			8.1
Income tax provision	(363.2		)	(315.4		)	(186.2		)
Income from continuing operations, net of income taxes	$	1,010.5		$	826.6		$	443.2

The following table presents revenues as a percent of total revenue from external customers by geographic region:

	Year Ended December 31,
	2011		2010		2009
U.S.	62.0	%	64.6	%	73.2	%
Japan	10.2	%	9.1	%	7.1	%
South Korea	5.5	%	3.7	%	2.2	%
India	5.2	%	4.9	%	3.8	%
Other	17.1	%	17.7	%	13.7	%
Total	100	%	100	%	100	%

The Company attributes revenue to individual countries based on the location of the physical delivery of the coal.

XML

Income Taxes (Details 1) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Current
U.S. federal	$ 103.4	$ 113.9	$ (0.7)
Non U.S.	58.9	78.8	50.0
State	12.2	1.0	1.7
Total current	174.5	193.7	51.0
Deferred
U.S. Federal	138.0	47.9	56.0
Non U.S.	42.8	68.1	78.5
State	7.9	5.7	0.7
Total deferred	188.7	121.7	135.2
Total provision	$ 363.2	$ 315.4	$ 186.2

XML

Financial Instruments and Guarantees with Off-Balance-Sheet Risk (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011 mW		Dec. 31, 2010	Dec. 31, 2009
Guarantee Obligations [Line Items]
Cash up front from sale of receivables	$ 3,462.7
Guarantor Obligations, Current Carrying Value	2,223.9
Financial Instruments and Guarantees with Off-Balance-Sheet Risk (Textuals) [Abstract]
Amount in bank guarantees, letters of credit and surety bonds related to collateral for surety companies, road maintenance, performance guarantees and other operations	242.2
Time Period Of Lease That Permits The Partnership To Purchase The Terminal	30 years
Maximum capacity of the securitization program	275.0
Amount available under the securitization program	41.7
Total consideration received by Company related to accounts receivable sold under securitization program	4,633.4
Additional cash upon collection of underlying receivables	1,004.8
Non collected receivables	165.9
Reduction in accounts receivable as a result of securitization	150.0		150.0
Expense associated with securitization transactions	2.0		2.4	4.0
Capacity of new electricity generation project, Megawatts	1,600
The Company's undivided interest percentage in the Prairie State Energy Campus	5.06%
Dominion Terminal Associates Partnership [Member]
Financial Instruments and Guarantees with Off-Balance-Sheet Risk (Textuals) [Abstract]
Equity Method Investment, Ownership Percentage	37.50%
Number of Letters of Credit Supporting Reimbursement Obligation	4
Maximum reimbursement obligation to commercial bank related to Dominion Terminals	42.7
Pension Plans Agreement With PBG and TXU Europe [Member]
Financial Instruments and Guarantees with Off-Balance-Sheet Risk (Textuals) [Abstract]
Letter of credit maintained by the Company in favor of the PBGC	37.0
Number of benefit pension plans	2
Guarantee in place from TXU Europe Limited	110.0
Reclamation Obligations [Member]
Guarantee Obligations [Line Items]
Guarantor Obligations, Current Carrying Value	1,721.2
Lease Obligations [Member]
Guarantee Obligations [Line Items]
Guarantor Obligations, Current Carrying Value	104.7
Workers' Compensation Obligations [Member]
Guarantee Obligations [Line Items]
Guarantor Obligations, Current Carrying Value	76.1
Guarantee Type, Other [Member]
Guarantee Obligations [Line Items]
Guarantor Obligations, Current Carrying Value	321.9	[1]
Self bonding [Member]
Guarantee Obligations [Line Items]
Guarantor Obligations, Current Carrying Value	929.6
Self bonding [Member] | Reclamation Obligations [Member]
Guarantee Obligations [Line Items]
Guarantor Obligations, Current Carrying Value	929.6
Self bonding [Member] | Lease Obligations [Member]
Guarantee Obligations [Line Items]
Guarantor Obligations, Current Carrying Value	0
Self bonding [Member] | Workers' Compensation Obligations [Member]
Guarantee Obligations [Line Items]
Guarantor Obligations, Current Carrying Value	0
Self bonding [Member] | Guarantee Type, Other [Member]
Guarantee Obligations [Line Items]
Guarantor Obligations, Current Carrying Value	0	[1]
Surety bonds [Member]
Guarantee Obligations [Line Items]
Guarantor Obligations, Current Carrying Value	742.4
Surety bonds [Member] | Reclamation Obligations [Member]
Guarantee Obligations [Line Items]
Guarantor Obligations, Current Carrying Value	613.2
Surety bonds [Member] | Lease Obligations [Member]
Guarantee Obligations [Line Items]
Guarantor Obligations, Current Carrying Value	104.7
Surety bonds [Member] | Workers' Compensation Obligations [Member]
Guarantee Obligations [Line Items]
Guarantor Obligations, Current Carrying Value	13.5
Surety bonds [Member] | Guarantee Type, Other [Member]
Guarantee Obligations [Line Items]
Guarantor Obligations, Current Carrying Value	11.0	[1]
Bank guarantees [Member]
Guarantee Obligations [Line Items]
Guarantor Obligations, Current Carrying Value	389.6
Bank guarantees [Member] | Reclamation Obligations [Member]
Guarantee Obligations [Line Items]
Guarantor Obligations, Current Carrying Value	178.4
Bank guarantees [Member] | Lease Obligations [Member]
Guarantee Obligations [Line Items]
Guarantor Obligations, Current Carrying Value	0
Bank guarantees [Member] | Workers' Compensation Obligations [Member]
Guarantee Obligations [Line Items]
Guarantor Obligations, Current Carrying Value	0
Bank guarantees [Member] | Guarantee Type, Other [Member]
Guarantee Obligations [Line Items]
Guarantor Obligations, Current Carrying Value	211.2	[1]
Letters of credit [Member]
Guarantee Obligations [Line Items]
Guarantor Obligations, Current Carrying Value	82.6
Letters of credit [Member] | Reclamation Obligations [Member]
Guarantee Obligations [Line Items]
Guarantor Obligations, Current Carrying Value	0
Letters of credit [Member] | Lease Obligations [Member]
Guarantee Obligations [Line Items]
Guarantor Obligations, Current Carrying Value	0
Letters of credit [Member] | Workers' Compensation Obligations [Member]
Guarantee Obligations [Line Items]
Guarantor Obligations, Current Carrying Value	62.6
Letters of credit [Member] | Guarantee Type, Other [Member]
Guarantee Obligations [Line Items]
Guarantor Obligations, Current Carrying Value	20.0	[1]
Bilateral cash collateralization agreements [Member]
Guarantee Obligations [Line Items]
Guarantor Obligations, Current Carrying Value	79.7
Bilateral cash collateralization agreements [Member] | Reclamation Obligations [Member]
Guarantee Obligations [Line Items]
Guarantor Obligations, Current Carrying Value	0
Bilateral cash collateralization agreements [Member] | Lease Obligations [Member]
Guarantee Obligations [Line Items]
Guarantor Obligations, Current Carrying Value	0
Bilateral cash collateralization agreements [Member] | Workers' Compensation Obligations [Member]
Guarantee Obligations [Line Items]
Guarantor Obligations, Current Carrying Value	0
Bilateral cash collateralization agreements [Member] | Guarantee Type, Other [Member]
Guarantee Obligations [Line Items]
Guarantor Obligations, Current Carrying Value	$ 79.7	[1]

[1] Other includes bilateral cash collateralization agreement obligations described below and an additional $242.2 million in bank guarantees, letters of credit and surety bonds related to collateral for surety companies, road maintenance, performance guarantees and other operations.

XML

Derivatives and Fair Value Measurements (Details 4) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 6,657.5	$ 2,750.0
Carrying amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	6,657.5	2,750.0
Estimated fair value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 6,922.7	$ 2,960.0
7.875% Senior Notes due November 2026 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rates on Senior Notes	7.875%

XML

Leases (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Future minimum lease and royalty payments
Capital Leases, 2012	$ 32.3
Capital Leases, 2013	41.3
Capital Leases, 2014	25.9
Capital Leases, 2015	10.5
Capital Leases, 2016	10.3
Capital Leases, 2017 and Thereafter	21.7
Capital Leases, Total minimum lease payments	142.0
Capital Leases, Less interest	19.5
Capital Leases, Present value of minimum capital lease payments	122.5
Operating Leases, 2012	123.1
Operating Leases, 2013	106.2
Operating Leases, 2014	90.6
Operating Leases, 2015	76.4
Operating Leases, 2016	63.5
Operating Leases, 2017 and thereafter	151.1
Operating Leases, Total minimum lease payments	610.9
Coal Lease and Royalty Obligation, 2012	50.7
Coal Lease and Royalty Obligation, 2013	50.0
Coal Lease and Royalty Obligation, 2014	48.8
Coal Lease and Royalty Obligation, 2015	46.6
Coal Lease and Royalty Obligation, 2016	3.8
Coal Lease and Royalty Obligation, 2017 and Thereafter	27.9
Coal Lease and Royalty Obligation, Total minimum lease payments	227.8
Leases (Textuals)
Rental expense under operating leases	170.6	129.5	116.6
Property, plant, equipment and mine development assets, gross value under capital leases	297.0	109.5
Accumulated depreciation of property, plant, equipment and mine development assets under capital leases	58.9	39.5
Total royalty expenses on coal reserve leases	610.6	540.6	428.6
Initial lease term for federal leases	ten years
Minimum annual production on federal leases	1.00%
Monthly royalty percentage on federal leases for coal sales using surface mining methods	12.50%
Monthly royalty percentage on federal leases for coal production using underground mining methods	8.00%
Initial term of mining leases in Australia	up to 21 years
Company's lease obligations secured by outstanding surety bonds	$ 104.7
Period to redetermine royalty rates on leased coal reserves in Arizona	every ten years

XML

Segment Information (Tables)

12 Months Ended

Dec. 31, 2011

Segment Reporting [Abstract]

Operating segment results

Operating segment results for the year ended December 31, 2011 were as follows (total assets as of December 31, 2011):

	Western U.S. Mining		Midwestern U.S. Mining		Australian Mining		Trading and Brokerage		Corporate and Other			Consolidated
	(Dollars in millions)
Revenues	$	2,900.4	$	1,481.1	$	3,080.7	$	475.1	$	37.1		$	7,974.4
Adjusted EBITDA	766.0		408.9		1,194.3		197.0		(437.5		)	2,128.7
Total assets	3,095.8		672.5		8,568.9		633.3		3,762.5			16,733.0
Additions to property, plant, equipment and mine development	228.5		108.2		439.6		0.9		69.7			846.9
Loss from equity affiliates	—		—		—		—		19.2			19.2

Operating segment results for the year ended December 31, 2010 were as follows (total assets as of December 31, 2010):

	Western U.S. Mining		Midwestern U.S. Mining		Australian Mining		Trading and Brokerage		Corporate and Other			Consolidated
	(Dollars in millions)
Revenues	$	2,706.3	$	1,320.6	$	2,399.9	$	291.1	$	22.0		$	6,739.9
Adjusted EBITDA	816.7		322.1		977.4		77.2		(354.7		)	1,838.7
Total assets	3,008.4		608.0		3,603.4		398.2		3,745.1			11,363.1
Additions to property, plant, equipment and mine development	143.3		224.9		138.7		0.9		40.1			547.9
Loss from equity affiliates	—		—		—		—		1.7			1.7

Operating segment results for the year ended December 31, 2009 were as follows (total assets as of December 31, 2009):

	Western U.S. Mining		Midwestern U.S. Mining		Australian Mining		Trading and Brokerage		Corporate and Other			Consolidated
	(Dollars in millions)
Revenues	$	2,612.6	$	1,303.8	$	1,512.6	$	391.0	$	27.0		$	5,847.0
Adjusted EBITDA	721.5		281.9		410.5		193.4		(344.5		)	1,262.8
Total assets	3,087.6		444.4		3,386.8		673.0		2,363.5			9,955.3
Additions to property, plant, equipment and mine development	201.9		104.2		69.3		1.8		6.2			383.4
Loss from equity affiliates	—		—		—		—		69.1			69.1

Reconciliation of Adjusted EBITDA to consolidated income from continuing operations

A reconciliation of adjusted EBITDA to consolidated income from continuing operations, net of income taxes follows:

	Year Ended December 31,
	2011			2010			2009
	(Dollars in millions)
Total adjusted EBITDA	$	2,128.7		$	1,838.7		$	1,262.8
Depreciation, depletion and amortization	(482.2		)	(437.1		)	(400.5		)
Asset retirement obligation expense	(53.1		)	(47.2		)	(39.9		)
Interest expense	(238.6		)	(222.0		)	(201.1		)
Interest income	18.9			9.6			8.1
Income tax provision	(363.2		)	(315.4		)	(186.2		)
Income from continuing operations, net of income taxes	$	1,010.5		$	826.6		$	443.2

Revenue as a percent of total revenue from external customers by geographic region

The following table presents revenues as a percent of total revenue from external customers by geographic region:

	Year Ended December 31,
	2011		2010		2009
U.S.	62.0	%	64.6	%	73.2	%
Japan	10.2	%	9.1	%	7.1	%
South Korea	5.5	%	3.7	%	2.2	%
India	5.2	%	4.9	%	3.8	%
Other	17.1	%	17.7	%	13.7	%
Total	100	%	100	%	100	%

XML

Share-Based Compensation (Details 2) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Schedule of Share-based Compensation, Stock Options, Activity
Granted	700,000	600,000	800,000
Exercised	(300,000)	(1,500,000)	(500,000)
Stock Options [Member]
Schedule of Share-based Compensation, Stock Options, Activity
Options outstanding, Beginning Balance	1,916,301
Granted	223,307
Exercised	(254,828)
Forfeited	0
Options outstanding, Ending Balance	1,884,780
Options Vested and Exercisable	1,301,607
Weighted Average Exercise Price, Beginning of Period	32.25
Weighted Average Exercise Price, Granted	64.52
Weighted Average Exercise Price, Exercised	18.57
Weighted Average Exercise Price, Forfeited	0.00
Weighted Average Exercise Price, End of Period	37.92
Options Vested and Exercisable, Weighted Average Exercise Price	32.53
Weighted Average Remaining Contractual Life, Beginning of Period	5.9
Weighted Average Remaining Contractual Life, End of Period	5.6
Options Vested and Exercisable, Weighted Average Remaining Contractual Life	4.5
Aggregate Intrinsic Value, Beginning of Period	61.2
Aggregate Intrinsic Value, End of Period	11.0
Options Vested and Exercisable, Aggregate Intrinsic Value	10.0

XML

Coal Trading (Details 2) (Credit Concentration Risk [Member], Coal Trading Positions [Member], Coal Trading [Member])	Dec. 31, 2011
External Credit Rating, Investment Grade [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	78.00%
External Credit Rating, Non Investment Grade [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	21.00%
Non Rated [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	1.00%

XML

Debt (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Oct. 28, 2011	Dec. 31, 2010
Carrying amount of the Company's debt
Capital lease obligations	$ 122.8		$ 69.6
Fair value hedge adjustment	0		2.2
Other	43.4		45.8
Total	6,657.5		2,750.0
Term Loan [Member]
Carrying amount of the Company's debt
Long-term debt	468.8		493.8
2011 Term Loan Facility [Member]
Carrying amount of the Company's debt
Long-term debt	1,000.0	1,000.0	0
5.875% Senior Notes due April 2016 [Member]
Carrying amount of the Company's debt
Long-term debt	0		218.1
7.375% Senior Notes due November 2016 [Member]
Carrying amount of the Company's debt
Long-term debt	650.0		650.0
6.00% Senior Notes due November 2018 [Member]
Carrying amount of the Company's debt
Long-term debt	1,600.0		0
6.5% Senior Notes due September 2020 [Member]
Carrying amount of the Company's debt
Long-term debt	650.0		650.0
6.25% Senior Notes due November 2021 [Member]
Carrying amount of the Company's debt
Long-term debt	1,500.0		0
7.875% Senior Notes due November 2026 [Member]
Carrying amount of the Company's debt
Long-term debt	247.3		247.2
Convertible Junior Subordinated Debentures due 2066 [Member]
Carrying amount of the Company's debt
Long-term debt	$ 375.2		$ 373.3

XML

Income Taxes (Details 3) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Deferred tax assets:
Tax credits and loss carryforwards	$ 432.8	$ 425.2
Postretirement benefit obligations	485.4	427.7
Intangible tax asset and purchased contract rights	10.6	15.1
Accrued reclamation and mine closing liabilities	114.6	97.8
Accrued long-term workers’ compensation liabilities	15.6	15.5
Employee benefits	53.3	53.5
Hedge activities	0	30.6
Financial guarantee	18.5	18.8
Others	57.9	45.4
Total gross deferred tax assets	1,188.7	1,129.6
Deferred tax liabilities:
Property, plant, equipment and mine development, leased coal interests and advance royalties, principally due to differences in depreciation, depletion and asset writedowns	1,348.0	1,246.8
Unamortized discount on Convertible Junior Subordinated Debentures	132.5	135.5
Hedge activities	45.5	0
Investments and other assets	109.8	107.0
Total gross deferred tax liabilities	1,635.8	1,489.3
Valuation allowance	(79.8)	(65.0)
Net deferred tax liability	(526.9)	(424.7)
Deferred taxes are classified as follows:
Current deferred income taxes	27.3	120.4
Noncurrent deferred income taxes	(554.2)	(545.1)
Net deferred tax liability	$ (526.9)	$ (424.7)

XML

Debt (Details 1) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Carrying amount of the equity and debt components of the Debentures
Principal amount of the liability component	$ 732.5
Effective Interest Rate And The Interest Expense Related To The Debentures Abstract
Effective interest rate	4.90%	4.90%	4.90%
Interest expense - contractual interest coupon	34.8	34.8	34.8
Interest expense - amortization of debt discount	1.9	1.8	1.6
Aggregate amounts of Long term debt maturities
2012	101.1
2013	121.9
2014	107.8
2015	458.5
2016	1,475.7
2017 and thereafter	4,392.5
Total	6,657.5	2,750.0
Junior Subordinated Debt [Member]
Carrying amount of the equity and debt components of the Debentures
Carrying amount of the equity component	215.4	215.4
Principal amount of the liability component	732.5	732.5
Unamortized discount	(357.3)	(359.2)
Net carrying amount	$ 375.2	$ 373.3

XML

Financing Receivables (Details) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011 AUD	Dec. 31, 2010 USD ($)	Dec. 31, 2011 USD ($)	Oct. 23, 2011 Coppabella, Moorvale, and Codrilla Mines [Member]	Dec. 31, 2011 Codrilla Mine Project [Member] USD ($)	Dec. 31, 2011 Middlemount Mine [Member] USD ($)	Oct. 23, 2011 Middlemount Mine [Member]	Dec. 31, 2011 Financing Receivable [Member] USD ($)
Accounts, Notes, Loans and Financing Receivable [Line Items]
Financing receivables			$ 376.1
Accounts receivable, net			51.3		34.2
Other current assets		467.1	766.1			65.0		65.0
Investments and other assets			259.8		35.6	224.2
Consideration received by company upon completion of sell down	15.0
Percentage of agreed sale price as consideration		20.00%
Percentage of agreed sale price as installment payment		40.00%
Percentage of agreed sale price as final installment payment		40.00%
Percentage of ownership before transaction	85.00%
Percentage of undivided interests acquired				73.30%			50.00%

XML

Derivatives and Fair Value Measurements (Details 2) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Derivatives, Fair Value [Line Items]
Current Assets	$ 313.8	$ 299.3
Noncurrent Assets	240.7	393.6
Current Liabilities	11.4	12.0
Noncurrent Liabilities	19.5	0.6
Commodity swaps and options [Member] | Cash flow hedges [Member]
Derivatives, Fair Value [Line Items]
Current Assets	43.4	25.8
Noncurrent Assets	11.7	27.0
Current Liabilities	7.1	12.0
Noncurrent Liabilities	15.0	0.6
Foreign currency contracts [Member] | Cash flow hedges [Member]
Derivatives, Fair Value [Line Items]
Current Assets	270.4	273.5
Noncurrent Assets	229.0	366.6
Current Liabilities	4.3	0
Noncurrent Liabilities	$ 4.5	$ 0

XML

Share-Based Compensation

12 Months Ended

Dec. 31, 2011

Share-based Compensation [Abstract]

Share-Based Compensation

Share-Based Compensation

The Company has an equity incentive plan for employees and non-employee directors that allows for the issuance of share-based compensation in the form of stock appreciation rights, restricted stock, performance awards, incentive stock options, nonqualified stock options and deferred stock units. The plan made 14.0 million shares of the Company’s common stock available for grant, with 13.8 million shares available for grant as of December 31, 2011. The Company has two employee stock purchase plans that provide for the purchase of up to 6.0 million shares of the Company’s common stock, with 5.0 million shares authorized for purchase by U.S. employees and 1.0 million shares authorized for purchase by Australian employees.

Share-Based Compensation Expense and Cash Flows

The Company’s share-based compensation expense is recorded in “Selling and administrative expenses” in the consolidated statements of income. The cash received by the Company upon the exercise of stock options and when employees purchase stock under the employee stock purchase plans is reflected as a financing activity in the consolidated statements of cash flows. Share-based compensation expense and cash flow amounts were as follows:

	Year Ended December 31,
	2011		2010		2009
	(Dollars in millions)
Share-based compensation expense	$	43.9	$	41.1	$	38.8
Tax benefit	16.3		15.4		15.0
Share-based compensation expense, net of tax benefit	27.6		25.7		23.8
Cash received upon the exercise of stock options and from employee stock purchases	11.1		22.2		8.7
Excess tax benefits related to share-based compensation	8.1		51.0		—

As of December 31, 2011, the total unrecognized compensation cost related to nonvested awards was $30.3 million, net of taxes, which is expected to be recognized over 3.0 years with a weighted-average period of 0.8 years.

Deferred Stock Units

In 2011, 2010 and 2009, the Company granted deferred stock units to each of its non-employee directors. The fair value of these units is equal to the market price of the Company’s common stock at the date of grant. These deferred stock units generally vest after one year and are settled in common stock on the specified distribution date elected by each non-employee director. Beginning in 2011, non-employee directors were also given the option to receive their total annual cash retainer in the form of additional deferred stock units (based on the fair market value of the Company's common stock on the date of grant). The additional grant of deferred stock units is subject to the same grant timing, vesting and distribution date elections as the annual equity compensation grant.

Restricted Stock Awards

The primary share-based compensation tool used by the Company for its employee base is through awards of restricted stock. The majority of restricted stock awards are granted in January of each year with a lesser portion granted in the first month of the subsequent three quarters. Awards generally cliff vest after three years of service and only contain a service condition, with compensation cost recognized on a straight-line basis over the requisite service period, net of estimated forfeitures. For awards with service and performance conditions, the Company recognizes compensation cost using the graded-vesting method, net of estimated forfeitures. The fair value of restricted stock is equal to the market price of the Company’s common stock at the date of grant.

A summary of restricted stock award activity is as follows:

	Year Ended December 31, 2011		Weighted Average Grant-Date Fair Value
Nonvested at December 31, 2010	1,894,299		$	39.32
Granted	618,124		59.63
Vested	(849,464	)	42.38
Forfeited	(131,867	)	47.10
Nonvested at December 31, 2011	1,531,092		$	45.16

The total fair value of restricted stock awards granted during the years ended December 31, 2011, 2010 and 2009, was $36.9 million, $23.3 million and $23.1 million, respectively. The total fair value of restricted stock awards vested during the years ended December 31, 2011, 2010 and 2009, was $50.0 million, $20.5 million and $11.2 million, respectively.

Stock Options

Over the past few years, the Company’s stock option awards have been primarily limited to senior management personnel. All stock options are granted at an exercise price equal to the market price of the Company’s common stock at the date of grant. Stock options generally vest in one-third increments over a period of three years or cliff vest after three years, and expire after 10 years from the date of grant. Expense is recognized ratably over the vesting period, net of estimated forfeitures. Option grants are typically made in January of each year or upon hire for eligible plan participants.

The Company used the Black-Scholes option pricing model to determine the fair value of stock options. The Company utilized U.S. Treasury yields as of the grant date for its risk-free interest rate assumption, matching the U.S. Treasury yield terms to the expected life of the option. The Company utilized historical company data to develop its dividend yield, expected volatility and expected option life assumptions.

A summary of outstanding option activity under the plans is as follows:

	Year Ended December 31, 2011		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life	Aggregate Intrinsic Value (in millions)
Options Outstanding at December 31, 2010	1,916,301		$	32.25	5.9	$	61.2
Granted	223,307		64.52
Exercised	(254,828	)	18.57
Forfeited	—		—
Options Outstanding at December 31, 2011	1,884,780		$	37.92	5.6	$	11.0
Vested and Exercisable	1,301,607		$	32.53	4.5	$	10.0

During the years ended December 31, 2011, 2010 and 2009, the total intrinsic value of options exercised, defined as the excess fair value of the underlying stock over the exercise price of the options, was $10.3 million, $53.7 million and $14.7 million, respectively. The weighted-average fair values of the Company’s stock options and the assumptions used in applying the Black-Scholes option pricing model were as follows:

	Year Ended December 31,
	2011			2010			2009
Weighted-average fair value	$	33.92		$	25.70		$	26.84
Risk-free interest rate	2.0		%	2.8		%	1.5		%
Expected option life	5.0 years			5.0 years			5.0 years
Expected volatility	64		%	64		%	60		%
Dividend yield	0.6		%	0.6		%	0.9		%

Performance Units

Performance units are typically granted annually in January and vest over a three-year measurement period and are primarily limited to senior management personnel. The performance units are usually subject to the achievement of two goals, 50% based on three-year stock price performance compared to both an industry peer group and a S&P index (market condition) and 50% based on a three-year return on capital target (performance condition). The performance units granted in 2011 are subject to the achievement of the performance and market conditions, while the 2010 and 2009 units granted are only subject to the achievement of the market condition. Three performance unit grants are outstanding for any given year. The payouts related to all active grants will be settled in the Company’s common stock.

A summary of performance unit activity is as follows:

	Year Ended December 31, 2011		Weighted Average Remaining Contractual Life
Nonvested at December 31, 2010	386,662		1.5
Granted	122,590
Forfeited	—
Vested	(248,263	)
Nonvested at December 31, 2011	260,989		1.5

As of December 31, 2011, there were 248,263 performance units vested that had an aggregate intrinsic value of $12.4 million and a conversion price per share of $34.37.

The performance condition awards were valued utilizing the grant date fair values of the Company’s stock adjusted for dividends foregone during the vesting period. The market condition awards were valued utilizing a Monte Carlo simulation which incorporates the total stockholder return hurdles set for each grant. The assumptions used in the valuations for grants were as follows:

	Year Ended December 31,
	2011		2010		2009
Risk-free interest rate	1.0	%	1.7	%	1.3	%
Expected volatility	64	%	64	%	60	%
Dividend yield	0.6	%	0.6	%	0.9	%

Employee Stock Purchase Plans

The Company’s eligible full-time and part-time employees are able to contribute up to 15% of their base compensation into the employee stock purchase plans, subject to a limit of $25,000 per person per year. Employees are able to purchase Company common stock at a 15% discount to the lower of the fair market value of the Company’s common stock on the initial or final trading dates of each six-month offering period. Offering periods begin on January 1 and July 1 of each year. The Company uses the Black-Scholes option pricing model to determine the fair value of employee stock purchase plan share-based payments. The fair value of the six-month “look-back” option in the Company’s employee stock purchase plans is estimated by adding the fair value of 0.15 of one share of stock to the fair value of 0.85 of an option on one share of stock. The Company utilized U.S. Treasury yields as of the grant date for its risk-free interest rate assumption, matching the Treasury yield terms to the six-month offering period. The Company utilized historical company data to develop its dividend yield and expected volatility assumptions.

Shares purchased under the plans were 0.2 million for the year ended December 31, 2011, 0.2 million for the year ended December 31, 2010 and 0.4 million for the year ended December 31, 2009.

XML

Stockholders' Equity (Tables)

12 Months Ended

Dec. 31, 2011

Stockholders' Equity (Tables) [Abstract]

Summary of common stock activity

The following table summarizes common stock activity from January 1, 2009 to December 31, 2011:

	2011		2010		2009
Shares outstanding at the beginning of the year	270.2		268.2		266.6
Stock options exercised	0.3		1.5		0.5
Stock grants to employees	0.7		0.6		0.8
Employee stock purchases	0.2		0.2		0.4
Shares relinquished	(0.3	)	(0.3	)	(0.1	)
Shares outstanding at the end of the year	271.1		270.2		268.2

XML

Coal Trading (Tables)

12 Months Ended

Dec. 31, 2011

Coal Trading [Line Items]

Fair value coal trading net assets (liabilities) measured on recurring basis

The following tables set forth the hierarchy of the Company’s net financial asset (liability) positions for which fair value is measured on a recurring basis:

	December 31, 2011
	Level 1		Level 2		Level 3		Total
			(Dollars in millions)
Investment in debt and equity securities	$	83.5	$	—	$	—	$	83.5
Commodity swaps and options	—		33.0		—		33.0
Foreign currency cash flow hedge contracts	—		490.6		—		490.6
Total net financial assets	$	83.5	$	523.6	$	—	$	607.1

	December 31, 2010
	Level 1		Level 2		Level 3		Total
			(Dollars in millions)
Investment in debt securities	$	17.9	$	—	$	—	$	17.9
Commodity swaps and options	—		40.2		—		40.2
Foreign currency cash flow hedge contracts	—		640.1		—		640.1
Total net financial assets	$	17.9	$	680.3	$	—	$	698.2

Coal Trading [Member]

Coal Trading [Line Items]

Trading revenue by type of instrument

	Year Ended December 31,
Trading Revenue by Type of Instrument	2011			2010		2009
	(Dollars in millions)
Commodity swaps and options	$	(41.4	)	$	23.2	$	176.5
Physical commodity purchase / sale contracts	187.0			135.5		85.0
Total trading revenue	$	145.6		$	158.7	$	261.5

Fair value of assets and liabilities from coal trading activities

The fair value of assets and liabilities from coal trading activities is set forth below:

	December 31,
	2011						2010
	Gross Basis			Net Basis			Gross Basis			Net Basis
	(Dollars in millions)
Assets from coal trading activities	$	170.4		$	44.6		$	1,706.2		$	192.5
Liabilities from coal trading activities	(84.0		)	(10.3		)	(1,843.5		)	(181.7		)
Subtotal	86.4			34.3			(137.3		)	10.8
Net margin posted (held)(1)	(52.1		)	—			148.1			—
Net value of coal trading positions	$	34.3		$	34.3		$	10.8		$	10.8

⁽¹⁾  Represents margin held from exchanges of $52.1 million at December 31, 2011; and margin posted with counterparties and exchanges of $148.2 million, net of margin held of $0.1 million at December 31, 2010. In addition, at December 31, 2010, the Company held letters of credit of $5.0 million from counterparties in lieu of margin posted. Of the margin held at December 31, 2011, approximately $23.4 million related to cash flow hedges.

Fair value coal trading net assets (liabilities) measured on recurring basis

The following tables set forth the hierarchy of the Company’s net financial asset (liability) trading positions for which fair value is measured on a recurring basis:

	December 31, 2011
	Level 1		Level 2			Level 3		Total
	(Dollars in millions)
Commodity swaps and options	$	21.2	$	(1.9	)	$	—	$	19.3
Physical commodity purchase/sale contracts	—		6.3			8.7		15.0
Total net financial assets	$	21.2	$	4.4		$	8.7	$	34.3

	December 31, 2010
	Level 1		Level 2			Level 3		Total
			(Dollars in millions)
Commodity swaps and options	$	10.7	$	(76.2	)	$	—	$	(65.5	)
Physical commodity purchase/sale contracts	—		57.7			18.6		76.3
Total net financial assets (liabilities)	$	10.7	$	(18.5	)	$	18.6	$	10.8

Change in the Company's recurring Level 3 net financial assets

The following table summarizes the changes in the Company’s recurring Level 3 net financial assets:

	Year Ended December 31,
	2011				2010			2009
	(Dollars in millions)
Beginning of year	$	18.6			$	17.0		$	37.8
Total gains (losses) realized/unrealized:
Included in earnings	8.9				2.1			(2.9		)
Included in other comprehensive income	—				(0.5		)	(1.6		)
Settlements	(2.1		)		(0.1		)	(20.5		)
Transfers in	1.0			—	—			—
Transfers out	(17.7		)		0.1			4.2
End of year	$	8.7			$	18.6		$	17.0

Changes in unrealized gains (losses) relating to Level 3 net financial assets

The following table summarizes the changes in unrealized gains relating to Level 3 net financial assets held both as of the beginning and the end of the year:

	Year Ended December 31,
	2011		2010		2009
	(Dollars in millions)
Changes in unrealized gains (1)	$	8.7	$	6.7	$	15.6

⁽¹⁾  Within the consolidated statements of income and consolidated statements of comprehensive income for the periods presented, unrealized gains and losses from Level 3 items are combined with unrealized gains and losses on positions classified in Level 1 or 2, as well as other positions that have been realized during the applicable periods.

Schedule of future realization of the Company's trading portfolio

As of December 31, 2011, the timing of the estimated future realization of the value of the Company’s trading portfolio was as follows:

Year of	Percentage of
Expiration	Portfolio Total
2012	65	%
2013	29	%
2014	4	%
2015	2	%
	100	%

XML

Coal Trading (Details 1) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Coal Trading (Textuals) [Abstract]
Funds remaining with MF Global	$ 53
Coal Trading [Member]
Changes in the Company's recurring Level 3 net financial assets (liabilities)
Beginning of period	18.6		17.0		37.8
Total gains or losses (realized/unrealized):
Included in earnings	8.9		2.1		(2.9)
Included in other comprehensive income	0		(0.5)		(1.6)
Settlements	(2.1)		(0.1)		(20.5)
Transfers in	1.0		0		0
Transfers out	(17.7)		0.1		4.2
End of period	8.7		18.6		17.0
Changes in unrealized gains (losses) relating to Level 3 net financial assets held both at the beginning and the end of the period
Changes in unrealized gains (losses)	8.7	[1]	6.7	[1]	15.6	[1]
Schedule of future realization of trading portfolio
2012	65.00%
2013	29.00%
2014	4.00%
2015	2.00%
Percentage of trading portfolio expiration, total	100.00%
Coal Trading (Textuals) [Abstract]
Losses reclassified to earnings as forecasted transactions no longer probable	10.0
Margin held from counterparties and exchanges	52.1		0.1
Margin posted with counterparties and exchanges			148.2
Letters of credit held in lieu of margin posted by the counterparties	5.0
Net margin held	0	[2]	0	[2]
Cash flow hedges of anticipated future sales of coal (net liability)	22.4		174.2
Estimated time of transfer	12 months
Expected amount of losses to be realized over the next 12 months in accumulated other comprehensive income	2
Potential collateralization that may be requested by counterparties related to material adverse event	11		160
Margin posted to counterparties related to material adverse event			5.8
Additional potential collateral requirements for a credit downgrade	0		0
Margin posted with a counterparty due to timing and market fluctuations			5.0
Variation Margin Held	52.1
Variation margin posted			137.4
Initial margin posted	34.0		39.5
Margin in excess of the exchange-required variation and initial margin			4.4
Fair Value, Measurements, Recurring [Member] | Coal Trading [Member]
Fair value coal trading net assets (liabilities) measured on recurring basis
Commodity swaps and options	19.3		(65.5)
Physical commodity purchase/sale contracts	15.0		76.3
Total net financial assets (liabilities)	34.3		10.8
Fair Value, Measurements, Recurring [Member] | Level 1 [Member] | Coal Trading [Member]
Fair value coal trading net assets (liabilities) measured on recurring basis
Commodity swaps and options	21.2		10.7
Physical commodity purchase/sale contracts	0		0
Total net financial assets (liabilities)	21.2		10.7
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Coal Trading [Member]
Fair value coal trading net assets (liabilities) measured on recurring basis
Commodity swaps and options	(1.9)		(76.2)
Physical commodity purchase/sale contracts	6.3		57.7
Total net financial assets (liabilities)	4.4		(18.5)
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Coal Trading [Member]
Fair value coal trading net assets (liabilities) measured on recurring basis
Commodity swaps and options	0		0
Physical commodity purchase/sale contracts	8.7		18.6
Total net financial assets (liabilities)	8.7		18.6
Cash Flow Hedging [Member] | Coal Trading [Member]
Coal Trading (Textuals) [Abstract]
Net margin held	$ 23.4

[1] Within the consolidated statements of income and consolidated statements of comprehensive income for the periods presented, unrealized gains and losses from Level 3 items are combined with unrealized gains and losses on positions classified in Level 1 or 2, as well as other positions that have been realized during the applicable periods.

[2] Represents margin held from exchanges of $52.1 million at December 31, 2011; and margin posted with counterparties and exchanges of $148.2 million, net of margin held of $0.1 million at December 31, 2010. In addition, at December 31, 2010, the Company held letters of credit of $5.0 million from counterparties in lieu of margin posted. Of the margin held at December 31, 2011, approximately $23.4 million related to cash flow hedges.

XML

Pension and Savings Plans (Details) (Pension Plans, Defined Benefit [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Pension Plans, Defined Benefit [Member]
Components of net periodic pension costs
Service cost for benefits earned	$ 1.7	$ 1.5	$ 1.4
Interest cost on projected benefit obligation	49.8	50.5	51.3
Expected return on plan assets	(64.4)	(58.3)	(60.9)
Amortization of prior service cost	1.0	1.4	1.4
Amortization of actuarial loss	30.1	21.9	1.9
Net periodic (benefit) cost	$ 18.2	$ 17.0	$ (4.9)

XML

Summary of Significant Accounting Policies Discussion (Tables)

12 Months Ended

Dec. 31, 2011

Accounting Policies [Abstract]

Depreciation of plant and equipment (excluding life of mine assets)

The estimated useful lives by category of assets are as follows:

	Years
Building and improvements	10 to 20
Plant and equipment	3 to 33
Leasehold improvements	Life of Lease

Schedule of equity method investments

The table below summarizes the book value of the Company’s equity method investments, which is reported in “Investments and other assets” in the consolidated balance sheets, and the (loss) income from its equity affiliates:

	Book Value at December 31,				(Loss) Income from Equity Affiliates for the Year Ended December 31,
	2011		2010		2011			2010			2009
	(Dollars in millions)
Interest in Middlemount Coal Pty Ltd.	$	449.7	$	—	$	(7.3	)	$	—		$	—
Interest in Monto Coal Pty Ltd.	73.1		—		—			—			—
Interest in Carbones del Guasare	—		—		—			—			(54.6		)
Interest in Peabody-Winsway Resources B.V.	—		—		(3.4		)	5.4			(8.2		)
Other equity method investments	3.8		2.7		(8.5		)	(7.1		)	(6.3		)
Total equity method investments	$	526.6	$	2.7	$	(19.2	)	$	(1.7	)	$	(69.1	)

XML

Accumulated Other Comprehensive Income (Loss) (Tables)

12 Months Ended

Dec. 31, 2011

Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]

After-tax components of comprehensive income (loss)

The following table sets forth the after-tax components of comprehensive income (loss):

	Foreign Currency Translation Adjustment		Net Actuarial Loss Associated with Postretirement Plans and Workers’ Compensation Obligations			Prior Service Cost Associated with Postretirement Plans			Cash Flow Hedges			Available-For-Sale Securities			Total Accumulated Other Comprehensive Loss
	(Dollars in millions)
December 31, 2008	$	3.1	$	(220.4	)	$	(18.7	)	$	(152.5	)	$	—		$	(388.5	)
Net change in fair value	—		—			—			235.2			—			235.2
Reclassification from other comprehensive income to earnings	—		11.8			1.8			84.6			—			98.2
Current period change	—		(134.9		)	6.5			—			—			(128.4		)
December 31, 2009	3.1		(343.5		)	(10.4		)	167.3			—			(183.5		)
Net change in fair value	—		—			—			229.9			—			229.9
Reclassification from other comprehensive income to earnings	—		31.8			2.5			(102.4		)	—			(68.1		)
Current period change	—		(41.3		)	(4.9		)	—			—			(46.2		)
December 31, 2010	3.1		(353.0		)	(12.8		)	294.8			—			(67.9		)
Net change in fair value	—		—			—			291.9			(5.8		)	286.1
Reclassification from other comprehensive income to earnings	—		38.2			2.3			(251.0		)	(0.9		)	(211.4		)
Current period change	—		(150.1		)	0.9			—			—			(149.2		)
December 31, 2011	$	3.1	$	(464.9	)	$	(9.6	)	$	335.7		$	(6.7	)	$	(142.4	)

XML

Investments (Details 1) (Debt Securities [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2011
Debt Securities [Member]
Contractual maturities for available-for-sale maturities
Due in one year or less, Cost	$ 7.2
Due in one to five years, Cost	19.0
Total Cost	26.2
Due in one year or less, Fair Value	7.2
Due in one to five years, Fair Value	19.3
Total Fair Value	$ 26.5

XML

Share-Based Compensation (Details 4)	12 Months Ended
	Dec. 31, 2011
Summary of performance unit activity
Nonvested, Beginning of Period	1,894,299
Granted	618,124
Forfeited	(131,867)
Vested	(849,464)
Nonvested, End of Period	1,531,092
Performance unit [Member]
Summary of performance unit activity
Nonvested, Beginning of Period	386,662
Granted	122,590
Forfeited	0
Vested	(248,263)
Nonvested, End of Period	260,989
Weighted Average Remaining Contractual Life, Beginning of Period	1.5
Weighted Average Remaining Contractual Life, End of Period	1.5

XML

Acquisition of Macarthur Coal Limited (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		12 Months Ended										1 Months Ended	12 Months Ended				1 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	May 31, 2011	Dec. 31, 2011 2011 Term Loan Facility [Member]	Oct. 28, 2011 2011 Term Loan Facility [Member]	Dec. 31, 2010 2011 Term Loan Facility [Member]	Dec. 31, 2011 6.00% and 6.25% Senior Notes [Member]	Dec. 31, 2011 MCGH Loan Facility [Member]	Dec. 21, 2011 ArcelorMittal Mining Australasia B.V. [Member]	Dec. 20, 2011 Macarthur [Member]	Dec. 31, 2011 Macarthur [Member]	Dec. 21, 2011 Macarthur [Member]	Oct. 26, 2011 Macarthur [Member]	Oct. 23, 2011 Macarthur [Member]	Dec. 20, 2011 Macarthur [Member] PEAMCoal [Member]	Oct. 23, 2011 Coppabella, Moorvale, and Codrilla Mines [Member]	Oct. 23, 2011 Middlemount Mine [Member]
Business Acquisition [Line Items]
Ownership percentage of the Company in the newly formed company															100.00%		60.00%
Ownership percentage of the joint owner in the newly formed company												40.00%					40.00%
Other acquisitions												$ 2,000.0
Payments to acquire businesses, net of cash acquired			2,756.7	0	0								2,800.0					4,800.0
Cash acquired from acquisition																		261.2
Acquisition of noncontrolling interests			(1,994.8)	0	0
Percentage of undivided interests acquired																			73.30%	50.00%
Acquired amortizable intangible assets														30.5
Companys purchase price share of acquisition																2,756.7
Long-term debt used to fund acquisition							1,000.0	1,000.0	0	3,100.0
Deferred financing costs	55.6		55.6
Accounts receivable, net														34.5
Other current assets														66.6		137.5
Investments and other assets											368.9			234.9		1,275.1
Equity interest, converted from receivable, per agreement						90.00%
Equity interest, converted from receivable, per court ruling	90.00%		90.00%
Revenues from the acquisition date, actual	152.9
Loss from the acquisition date, actual	47.9
Acquisition costs	76.1	9.1	85.2	0	0									85.2
Interest costs														$ 16.2

XML

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2011

Asset Retirement Obligation Disclosure [Abstract]

Reconciliations of the Company's ARO liability

Reconciliations of the Company’s ARO liability are as follows:

	December 31,
	2011			2010
	(Dollars in millions)
Balance at beginning of year	$	490.7		$	447.6
Liabilities incurred or acquired	43.0			8.2
Liabilities settled or disposed	(8.8		)	(8.7		)
Accretion expense	28.7			26.4
Revisions to estimates	67.7			17.2
Balance at end of year	$	621.3		$	490.7
Balance at end of year — active locations	$	574.0		$	438.2
Balance at end of year — closed or inactive locations	$	47.3		$	52.5

XML

Summary of Significant Accounting Policies Discussion

12 Months Ended

Dec. 31, 2011

Accounting Policies [Abstract]

Summary of Significant Accounting Policies Discussion

Summary of Significant Accounting Policies Discussion

Basis of Presentation

The consolidated financial statements include the accounts of Peabody Energy Corporation (the Company) and its affiliates. All intercompany transactions, profits and balances have been eliminated in consolidation.

Description of Business

The Company is engaged in the mining of thermal coal for sale primarily to electric utilities and metallurgical coal for sale to industrial customers. The Company’s mining operations are located in the United States (U.S.) and Australia, and include equity-affiliate mining operations in Australia and Venezuela. The Company also markets, brokers coal sales of other coal producers both as principal and agent, and trades coal, freight and freight-related contracts. The Company’s other energy related commercial activities include participating in the development of a mine-mouth coal-fueled generating plant, the management of its coal reserve and real estate holdings, and the development of Btu Conversion and clean coal technologies.

Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented

In June 2011, the Financial Accounting Standards Board (FASB) issued guidance eliminating the option to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity. Instead, an entity will be required to present the components of net income, the components of other comprehensive income and the total of comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The guidance will become effective for interim and annual periods beginning after December 15, 2011 (January 1, 2012 for the Company), with the exception of disclosing reclassifications of items out of accumulated other comprehensive income, which is effective for interim and annual periods beginning after December 15, 2012 (January 1, 2013 for the Company). The Company has reflected the new presentation in its consolidated statements of comprehensive income with no impact on its results of operations, financial condition or cash flows.

In December 2010, the FASB issued guidance on accounting for business combinations that clarified a public entity’s disclosure requirements for pro forma presentation of revenue and earnings. If comparative statements are presented, the public entity should disclose revenue and earnings of the combined entity as though the business combination occurred as of the beginning of the comparable prior annual reporting period only. The guidance also requires the supplemental pro forma disclosures to include a description of the nature and amount of material nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. The guidance was effective for business combinations for which the acquisition date was on or after the beginning of the first annual reporting period that began on or after December 15, 2010 (January 1, 2011 for the Company). The guidance impacted the Company’s disclosures with no impact on the Company’s results of operations, financial condition or cash flows.

In July 2010, the FASB issued accounting guidance to improve disclosures about the credit quality of an entity's financing receivables and the reserves held against them. End of reporting period disclosures became effective for reporting periods ended on or after December 15, 2010. Disclosures about activity that occurred during a reporting period became effective for interim and annual periods that began on or after December 15, 2010. While the guidance impacted the Company's disclosures related to credit quality of financing receivables and the allowance for credit losses, the adoption of this guidance had no impact on its results of operations, financial condition or cash flows.

In January 2010, the FASB issued accounting guidance that required new fair value disclosures, including disclosures about significant transfers into and out of Level 1 and Level 2 fair value measurements and a description of the reasons for the transfers. In addition, the guidance required new disclosures regarding activity in Level 3 fair value measurements, including a gross basis reconciliation. The Company began complying with the new fair value disclosure requirements beginning January 1, 2010, except for the disclosure of activity within Level 3 fair value measurements, which became effective January 1, 2011. While the adoption of this guidance had an impact on the Company's disclosures, it did not affect the Company's results of operations, financial condition or cash flows. In May 2011, the FASB issued additional fair value measurement disclosure requirements that were intended to provide a consistent definition of fair value and ensure that the fair value measurement and disclosure requirements are similar between U.S. generally accepted accounting principles (GAAP) and International Financial Reporting Standards. That update required the categorization by level for financial instruments not measured at fair value but for which disclosure of fair value is required, disclosure of all transfers between Level 1 and Level 2, and additional disclosures for Level 3 measurements regarding the sensitivity of fair value to changes in unobservable inputs and any interrelationships between those inputs. The guidance will become effective for interim and annual periods beginning after December 15, 2011 (January 1, 2012 for the Company). The guidance issued in May 2011 will impact the Company's disclosures, but it is not expected to impact the Company's results of operations, financial condition or cash flows.

In June 2009, the FASB issued accounting guidance on consolidations which clarifies that the determination of whether a company is required to consolidate an entity is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly impact the entity’s economic performance. Also required is an ongoing reassessment of whether a company is the primary beneficiary of a variable interest entity, and additional disclosures about a company’s involvement in variable interest entities and any associated changes in risk exposure. The guidance became effective January 1, 2010, at which time there was no impact on the Company’s results of operations, financial condition or cash flows. The Company will continue monitoring and assessing its business ventures in accordance with the guidance.

In June 2009, the FASB issued guidance seeking to improve the relevance, representational faithfulness and comparability of the information a reporting entity provides in its financial statements about a transfer of financial assets; the effects of a transfer on its financial position, financial performance and cash flows; and a transferor’s continuing involvement, if any, in transferred financial assets. The guidance, which became effective January 1, 2010, had an impact on the Company’s disclosures for its accounts receivable securitization program, but did not affect the Company’s results of operations, financial condition or cash flows.

Sales

The Company’s revenue from coal sales is realized and earned when risk of loss passes to the customer. Under the typical terms of the Company’s coal supply agreements, title and risk of loss transfer to the customer at the mine or port, where coal is loaded to the transportation source(s) that serves each of the Company’s mines. The Company incurs certain “add-on” taxes and fees on coal sales. Reported coal sales include taxes and fees charged by various federal and state governmental bodies and the freight charges on destination customer contracts.

Other Revenues

Other revenues include net revenues from coal trading activities as discussed in Note 7 and coal revenues that were derived from the Company’s mining operations and sold through the Company’s coal trading business. Also included are revenues from contract termination or restructuring payments, royalties related to coal lease agreements, sales agency commissions, farm income, property and facility rentals and generation development activities. Royalty income generally results from the lease or sublease of mineral rights to third parties, with payments based upon a percentage of the selling price or an amount per ton of coal produced.

Discontinued Operations and Assets Held for Sale

The Company classifies items within discontinued operations in the consolidated financial statements when the operations and cash flows of a particular component (defined as operations and cash flows that can be clearly distinguished, operationally and for financial reporting purposes, from the rest of the entity) of the Company have been (or will be) eliminated from the ongoing operations of the Company as a result of a disposal transaction, and the Company will no longer have any significant continuing involvement in the operations of that component. See Note 3 for additional details related to discontinued operations and assets held for sale.

Cash and Cash Equivalents

Cash and cash equivalents are stated at cost, which approximates fair value. Cash equivalents consist of highly liquid investments with original maturities of three months or less.

Inventories

Materials and supplies and coal inventory are valued at the lower of average cost or market. Raw coal represents coal stockpiles that may be sold in current condition or may be further processed prior to shipment to a customer. Coal inventory costs include labor, supplies, equipment, operating overhead and other related costs.

Property, Plant, Equipment and Mine Development

Property, plant, equipment and mine development are recorded at cost. Interest costs applicable to major asset additions are capitalized during the construction period. Capitalized interest in 2011, 2010 and 2009 was immaterial. Expenditures which extend the useful lives of existing plant and equipment assets are capitalized. Maintenance and repairs are charged to operating costs as incurred. Costs incurred to develop coal mines or to expand the capacity of operating mines are capitalized. Costs incurred to maintain current production capacity at a mine are charged to operating costs as incurred. Costs to acquire computer hardware and the development and/or purchase of software for internal use are capitalized and depreciated over the estimated useful lives.

Coal reserves are recorded at cost, or at fair value in the case of nonmonetary exchanges of reserves or business acquisitions. The net book value of coal reserves totaled $7.7 billion as of December 31, 2011 and $5.0 billion as of December 31, 2010. These coal reserves include mineral rights for leased coal interests and advance royalties that had a net book value of $6.4 billion as of December 31, 2011 and $3.7 billion as of December 31, 2010. The remaining net book value of coal reserves of $1.3 billion at December 31, 2011 and $1.3 billion at December 31, 2010 relates to coal reserves held by fee ownership. Amounts attributable to properties where the Company was not currently engaged in mining operations or leasing to third parties and, therefore, the coal reserves were not currently being depleted was $2.7 billion as of December 31, 2011 and $1.3 billion as of December 31, 2010.

Depletion of coal reserves and amortization of advance royalties is computed using the units-of-production method utilizing only proven and probable reserves (as adjusted for recoverability factors) in the depletion base. Mine development costs are principally amortized over the estimated lives of the mines using the straight-line method. Depreciation of plant and equipment is computed using the straight-line method over the shorter of the asset's estimated useful life or the life of the mine. The estimated useful lives by category of assets are as follows:

	Years
Building and improvements	10 to 20
Plant and equipment	3 to 33
Leasehold improvements	Life of Lease

Depreciation and depletion expense associated with property, plant, equipment and mine development was $473.7 million, $424.8 million and $388.0 million for December 31, 2011, 2010, and 2009, respectively.

Investments in Joint Ventures

The Company accounts for its investments in less than majority owned corporate joint ventures under either the equity or cost method. The Company applies the equity method to investments in joint ventures when it has the ability to exercise significant influence over the operating and financial policies of the joint venture. Investments accounted for under the equity method are initially recorded at cost, and any difference between the cost of the Company’s investment and the underlying equity in the net assets of the joint venture at the investment date is amortized over the lives of the related assets that gave rise to the difference. The Company’s pro rata share of earnings from joint ventures and basis difference amortization is reported in the consolidated statements of income in “Loss from equity affiliates.” Included in the Company’s equity method investments is its joint venture interest in the Middlemount Mine in Australia, which was acquired as a part of the acquisition of Macarthur Coal Limited (see Note 2 for additional details). The Company also has an interest in Carbones del Guasare, which owns and operates the Paso Diablo Mine in Venezuela. In 2009, the Company recognized an impairment loss of $34.7 million million related to its interest in Carbones del Guasare based on the joint venture’s deteriorating operating results, ongoing cash flow issues resulting in no dividend payments since January 2008, the Company’s expectations concerning ongoing operating and cash flow issues for the joint venture and uncertainty impacting recoverability of this investment. The table below summarizes the book value of the Company’s equity method investments, which is reported in “Investments and other assets” in the consolidated balance sheets, and the (loss) income from its equity affiliates:

	Book Value at December 31,				(Loss) Income from Equity Affiliates for the Year Ended December 31,
	2011		2010		2011			2010			2009
	(Dollars in millions)
Interest in Middlemount Coal Pty Ltd.	$	449.7	$	—	$	(7.3	)	$	—		$	—
Interest in Monto Coal Pty Ltd.	73.1		—		—			—			—
Interest in Carbones del Guasare	—		—		—			—			(54.6		)
Interest in Peabody-Winsway Resources B.V.	—		—		(3.4		)	5.4			(8.2		)
Other equity method investments	3.8		2.7		(8.5		)	(7.1		)	(6.3		)
Total equity method investments	$	526.6	$	2.7	$	(19.2	)	$	(1.7	)	$	(69.1	)

Asset Retirement Obligations

The Company’s asset retirement obligation (ARO) liabilities primarily consist of spending estimates for surface land reclamation and support facilities at both surface and underground mines in accordance with applicable reclamation laws in the U.S. and Australia as defined by each mining permit.

The Company estimates its ARO liabilities for final reclamation and mine closure based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at the credit-adjusted, risk-free rate. The Company records an ARO asset associated with the discounted liability for final reclamation and mine closure. The obligation and corresponding asset are recognized in the period in which the liability is incurred. The ARO asset is amortized on the units-of-production method over its expected life and the ARO liability is accreted to the projected spending date. As changes in estimates occur (such as mine plan revisions, changes in estimated costs or changes in timing of the performance of reclamation activities), the revisions to the obligation and asset are recognized at the appropriate historical credit-adjusted, risk-free rate. The Company also recognizes an obligation for contemporaneous reclamation liabilities incurred as a result of surface mining. Contemporaneous reclamation consists primarily of grading, topsoil replacement and re-vegetation of backfilled pit areas.

Environmental Liabilities

Accruals for other environmental matters are recorded in operating expenses when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Accrued liabilities are exclusive of claims against third parties and are not discounted. In general, costs related to environmental remediation are charged to expense. The current portion of these accruals is included in “Accounts payables and accrued expenses” and the long-term portion is included in “Other noncurrent liabilities” in the consolidated balance sheets.

Income Taxes

Income taxes are accounted for using a balance sheet approach. The Company accounts for deferred income taxes by applying statutory tax rates in effect at the reporting date of the balance sheet to differences between the book and tax basis of assets and liabilities. A valuation allowance is established if it is “more likely than not” that the related tax benefits will not be realized. In determining the appropriate valuation allowance, the Company considers projected realization of tax benefits based on expected levels of future taxable income, available tax planning strategies and the overall deferred tax position.

The Company recognizes the tax benefit from uncertain tax positions only if it is “more likely than not” the tax position will be sustained on examination by the taxing authorities. The tax benefits recognized from such a position are measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. To the extent the Company’s assessment of such tax positions changes, the change in estimate will be recorded in the period in which the determination is made. Tax-related interest and penalties are classified as a component of income tax expense.

Postretirement Health Care and Life Insurance Benefits

The Company accounts for postretirement benefits other than pensions by accruing the costs of benefits to be provided over the employees’ period of active service. These costs are determined on an actuarial basis. The Company’s consolidated balance sheets reflect the funded status of postretirement benefits. See Note 14 for information related to postretirement benefits.

Pension Plans

The Company sponsors non-contributory defined benefit pension plans accounted for by accruing the cost to provide the benefits over the employees’ period of active service. These costs are determined on an actuarial basis. The Company’s consolidated balance sheets reflect the funded status of the defined benefit pension plans. See Note 15 for information related to pension plans.

Derivatives

The Company recognizes at fair value all derivatives as assets or liabilities in the consolidated balance sheets. Gains or losses from derivative financial instruments designated as fair value hedges are recognized immediately in earnings, along with the offsetting gain or loss related to the underlying hedged item.

Gains or losses on derivative financial instruments designated as cash flow hedges are recorded as a separate component of stockholders’ equity until the hedged transaction occurs (or until hedge ineffectiveness is determined), at which time gains or losses are reclassified to earnings in conjunction with the recognition of the underlying hedged item. To the extent that the periodic changes in the fair value of the derivatives exceed the changes in the hedged item, the ineffective portion of the periodic non-cash changes are recorded in earnings in the period of the change. If the hedge ceases to qualify for hedge accounting, the Company prospectively recognizes the mark-to-market movements in earnings in the period of the change. The potential for hedge ineffectiveness is present in the design of the Company’s cash flow hedge relationships and is discussed in detail in Notes 6 and 7.

Non-derivative contracts and derivative contracts for which the Company has elected to apply the normal purchases and normal sales exception are accounted for on an accrual basis.

Business Combinations

The Company accounts for business combinations using the purchase method of accounting. The purchase method requires the Company to determine the fair value of all acquired assets, including identifiable intangible assets, and all assumed liabilities. The total cost of acquisitions is allocated to the underlying identifiable net assets, based on their respective estimated fair values. Determining the fair value of assets acquired and liabilities assumed requires management's judgment, and the utilization of independent valuation experts, and often involves the use of significant estimates and assumptions, including assumptions with respect to future cash inflows and outflows, discount rates, and asset lives, among other items.

Use of Estimates in the Preparation of the Consolidated Financial Statements

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Impairment of Long-Lived Assets

The Company records impairment losses on long-lived assets used in operations when events and circumstances indicate that assets might be impaired and the undiscounted cash flows estimated to be generated by those assets under various assumptions are less than their carrying amounts. Impairment losses are measured by comparing the estimated fair value of the impaired asset to its carrying amount. There were no impairment losses recorded during the years ended December 31, 2011, 2010 or 2009.

Fair Value

For assets and liabilities that are recognized or disclosed at fair value in the consolidated financial statements, the Company defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The Company’s asset and liability derivative positions are offset on a counterparty-by-counterparty basis if the contractual agreement provides for the net settlement of contracts with the counterparty in the event of default or termination of any one contract.

Foreign Currency

Substantially all of the Company’s foreign subsidiaries utilize the U.S. dollar as their functional currency. As such, monetary assets and liabilities are remeasured at year-end exchange rates while non-monetary items are remeasured at historical rates. Income and expense accounts are remeasured at the average rates in effect during the year, except for those expenses related to balance sheet amounts that are remeasured at historical exchange rates. Gains and losses from foreign currency remeasurement related to tax balances are included as a component of "Income tax provision" while all other remeasurement gains and losses are included in "Operating costs and expenses." The total foreign currency remeasurement losses for the years ended December 31, 2011, 2010 and 2009 were $0.9 million, $38.5 million and $55.4 million, respectively.

Share-Based Compensation

The Company accounts for share-based compensation at the grant date fair value of awards and recognizes the related expense over the vesting period of the award. See Note 17 for information related to share-based compensation.

Exploration and Drilling Costs

Exploration expenditures are charged to operating costs as incurred, including costs related to drilling and study costs incurred to convert or upgrade mineral resources to reserves.

Advance Stripping Costs

Pre-production:  At existing surface operations, additional pits may be added to increase production capacity in order to meet customer requirements. These expansions may require significant capital to purchase additional equipment, expand the workforce, build or improve existing haul roads and create the initial pre-production box cut to remove overburden (i.e., advance stripping costs) for new pits at existing operations. If these pits operate in a separate and distinct area of the mine, the costs associated with initially uncovering coal (i.e., advance stripping costs incurred for the initial box cuts) for production are capitalized and amortized over the life of the developed pit consistent with coal industry practices.

Post-production:  Advance stripping costs related to post-production are expensed as incurred. Where new pits are routinely developed as part of a contiguous mining sequence, the Company expenses such costs as incurred. The development of a contiguous pit typically reflects the planned progression of an existing pit, thus maintaining production levels from the same mining area utilizing the same employee group and equipment.

XML

Earnings per Share (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended																12 Months Ended
	Dec. 31, 2011		Sep. 30, 2011		Jun. 30, 2011		Mar. 31, 2011		Dec. 31, 2010		Sep. 30, 2010		Jun. 30, 2010		Mar. 31, 2010		Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
EPS numerator:
Income from continuing operations, net of income taxes	$ 222.5		$ 285.6		$ 307.8		$ 194.6		$ 223.8		$ 239.3		$ 215.7		$ 147.8		$ 1,010.5		$ 826.6		$ 443.2
Less: Net (loss) income attributable to noncontrolling interests																	(11.4)		28.2		14.8
Income from continuing operations attributable to common stockholders, before allocation of earnings to participating securities																	1,021.9		798.4		428.4
Less: Earnings allocated to participating securities																	(5.3)		(5.6)		(2.9)
Income from continuing operations attributable to common stockholders, after earnings allocated to participating securities																	1,016.6	[1]	792.8	[1]	425.5	[1]
Income (loss) from discontinued operations, net of income taxes																	(64.2)		(24.4)		19.8
Net income attributable to common stockholders, after earnings allocated to participating securities																	952.4	[1]	768.4	[1]	445.3	[1]
EPS denominator:
Weighted average shares outstanding - basic	269.3		269.2		269.0		268.9		267.7		267.1		266.6		266.5		269.1		267.0		265.5
Impact of dilutive securities																	1.2		2.9		2.0
Weighted average shares outstanding - diluted	270.2		270.6		270.5		272.8		270.3		268.6		268.3		268.2		270.3		269.9		267.5
Basic EPS attributable to common stockholders:
Income from continuing operations	$ 0.93	[2]	$ 1.03	[2]	$ 1.11	[2]	$ 0.71	[2]	$ 0.81	[3]	$ 0.84	[3]	$ 0.77	[3]	$ 0.54	[3]	$ 3.77		$ 2.97		$ 1.60
Income (loss) from discontinued operations																	$ (0.24)		$ (0.09)		$ 0.08
Net income																	$ 3.53		$ 2.88		$ 1.68
Diluted EPS attributable to common stockholders:
Income from continuing operations	$ 0.92		$ 1.02	[2]	$ 1.10	[2]	$ 0.70	[2]	$ 0.80	[3]	$ 0.84	[3]	$ 0.77	[3]	$ 0.54	[3]	$ 3.76		$ 2.93		$ 1.59
Income (loss) from discontinued operations																	$ (0.24)		$ (0.09)		$ 0.07
Net income																	$ 3.52		$ 2.84		$ 1.66
Earnings per Share (EPS) (Textuals) [Abstract]
Anti-dilutive shares, in millions																	0.2
Adjustment for participating securities used to calculate diluted EPS was less than																	$ 0.1

[1] The reallocation adjustment for participating securities to arrive at the numerator used to calculate diluted EPS was less than $0.1 million for the periods presented.

[2] (1) EPS for the quarters may not sum to the amounts for the year as each period is computed on a discrete basis.

[3] EPS for the quarters may not sum to the amounts for the year as each period is computed on a discrete basis

XML

Acquisition of Macarthur Coal Limited (Fair Values of Assets Acquired and Liabilities Assumed) (Details 2) (Macarthur [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Oct. 26, 2011
Macarthur [Member]
Business Acquisition [Line Items]
Accounts receivable, net		$ 106.6
Inventories		67.1
Other current assets	66.6	137.5
Property, plant, equipment and mine development, net		3,457.0
Investments and other assets	234.9	1,275.1
Current maturities of long-term debt		(11.0)
Accounts payable and accrued expenses		(133.8)
Long-term debt, less current maturities		(59.2)
Asset retirement obligations		(39.3)
Other noncurrent liabilities		(31.4)
Noncontrolling interests		(2,011.9)
Total purchase price, net of cash received of $261.2		$ 2,756.7

XML

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2011

Income Tax Disclosure [Abstract]

Income from continuing operations before income taxes

Income from continuing operations before income taxes consisted of the following:

	Year Ended December 31,
	2011		2010		2009
	(Dollars in millions)
U.S.	$	815.7	$	535.5	$	281.4
Non-U.S.	558.0		606.5		348.0
Total	$	1,373.7	$	1,142.0	$	629.4

Components of income tax provision (benefit)

Total income tax provision consisted of the following:

	Year Ended December 31,
	2011		2010		2009
	(Dollars in millions)
Current:
U.S. federal	$	103.4	$	113.9	$	(0.7	)
Non-U.S.	58.9		78.8		50.0
State	12.2		1.0		1.7
Total current	174.5		193.7		51.0
Deferred:
U.S. federal	138.0		47.9		56.0
Non-U.S.	42.8		68.1		78.5
State	7.9		5.7		0.7
Total deferred	188.7		121.7		135.2
Total provision	$	363.2	$	315.4	$	186.2

Reconciliation of the expected statutory federal income tax provision to the Company's actual income tax provision

The following is a reconciliation of the expected statutory federal income tax provision to the Company’s actual income tax provision:

	Year Ended December 31,
	2011			2010			2009
	(Dollars in millions)
Expected income tax provision at federal statutory rate	$	480.8		$	399.7		$	220.3
Excess depletion	(70.8		)	(53.5		)	(44.0		)
Foreign earnings provision differential	(99.2		)	(124.5		)	(83.4		)
Foreign earnings repatriation	7.6			84.5			—
Remeasurement of foreign income tax accounts	(0.9		)	47.9			74.4
State income taxes, net of U.S. federal tax benefit	12.3			(4.8		)	3.4
General business tax credits	(17.8		)	(17.0		)	(12.2		)
Changes in valuation allowance	15.4			(28.7		)	17.3
Changes in tax reserves	14.7			—			5.9
Other, net	21.1			11.8			4.5
Total provision	$	363.2		$	315.4		$	186.2

Tax effects of temporary differences that give rise to significant portions of the deferred tax assets And liabilities

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities consisted of the following:

	December 31,
	2011			2010
	(Dollars in millions)
Deferred tax assets:
Tax credits and loss carryforwards	$	432.8		$	425.2
Postretirement benefit obligations	485.4			427.7
Intangible tax asset and purchased contract rights	10.6			15.1
Accrued reclamation and mine closing liabilities	114.6			97.8
Accrued long-term workers’ compensation liabilities	15.6			15.5
Employee benefits	53.3			53.5
Hedge activities	—			30.6
Financial guarantee	18.5			18.8
Others	57.9			45.4
Total gross deferred tax assets	1,188.7			1,129.6
Deferred tax liabilities:
Property, plant, equipment and mine development, leased coal interests and advance royalties, principally due to differences in depreciation, depletion and asset writedowns	1,348.0			1,246.8
Unamortized discount on Convertible Junior Subordinated Debentures	132.5			135.5
Hedge activities	45.5			—
Investments and other assets	109.8			107.0
Total gross deferred tax liabilities	1,635.8			1,489.3
Valuation allowance	(79.8		)	(65.0		)
Net deferred tax liability	$	(526.9	)	$	(424.7	)
Deferred taxes are classified as follows:
Current deferred income taxes	$	27.3		$	120.4
Noncurrent deferred income taxes	(554.2		)	(545.1		)
Net deferred tax liability	$	(526.9	)	$	(424.7	)

Reconciliation of the beginning and ending amount of gross unrecognized tax benefits

A reconciliation of the beginning and ending amount of gross unrecognized tax benefits is as follows (dollars in millions):

	Year Ended December 31,
	2011		2010			2009
Balance at beginning of period	$	111.0	$	113.2		$	186.3
Additions for current year tax positions	5.2		3.4			2.7
Additions for prior year positions	3.4		13.8			15.7
Reductions for settlements with tax authorities	—		(19.4		)	(88.5		)
Reductions for expirations of statute of limitations	—		—			(3.0		)
Balance at end of period	$	119.6	$	111.0		$	113.2

Summary of Companys tax payments

The following table summarizes the Company’s tax payments:

	Year Ended December 31,
	2011		2010		2009
	(Dollars in millions)
U.S. — federal	$	200.0	$	65.0	$	—
U.S. — state and local	13.2		0.4		0.9
Non-U.S.	61.9		83.0		169.7
Total tax payments	$	275.1	$	148.4	$	170.6

XML

Management - Labor Relations

12 Months Ended

Dec. 31, 2011

Risk Management Labor Relations [Abstract]

Management - Labor Relations

Management — Labor Relations

As of December 31, 2011, the Company had approximately 8,300 employees, which included approximately 5,600 hourly employees. As of December 31, 2011, approximately 24% of the Company’s hourly employees were represented by organized labor unions and generated 7% of its 2011 coal production.  In the U.S., two of the Company's mines were represented by organized labor unions. In Australia, the coal mining industry is unionized and the majority of workers employed at the Company’s Australian Mining operations are members of trade unions. The Construction Forestry Mining and Energy Union represents the Company’s Australian subsidiaries’ hourly production and engineering employees, including those employed through contract mining relationships. The Company could experience labor disputes, work stoppages or other disruptions in production that could negatively impact the Company’s profitability. The following table below presents the Company's operations in which the employees are represented by organized labor unions.

Mine	Current Agreement Expiration Date
U. S.
Willow Lake (1)	-
Kayenta (2)	September 2013
Australia
Owner-operated mines:
North Goonyella (3)	March 2012
North Wambo Underground (3)	April 2012
Wilkie Creek (4)	March 2013
Metropolitan	June 2013
Coppabella	July 2013
Wambo Coal Handling Plant	October 2014
Contractor-operated mines:
Burton (3)	February 2012
Wilpinjong	August 2012
Millennium	September 2012
Moorvale	October 2012
Eaglefield	June 2014
Wambo Open-Cut	August 2014

⁽¹⁾ The labor agreement for the hourly workers at the Company’s Willow Lake Mine in Illinois expired in April 2011. The mine continues to operate without a contract. This agreement covers approximately 9% of the Company’s U.S. subsidiaries’ hourly employees, who generated approximately 1% of the Company’s U.S. production during the year ended December 31, 2011.

⁽²⁾ Hourly workers at the Company’s 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 the Company’s U.S. subsidiaries’ hourly employees, who generated 4% of the Company’s U.S. production during the year ended December 31, 2011.

⁽³⁾ Negotiations for the North Goonyella, North Wambo Underground and Burton mines are underway.

⁽⁴⁾ The Wilkie Creek Mine was held for sale as of December 31, 2011.

XML

Earnings per Share

12 Months Ended

Dec. 31, 2011

Earnings Per Share [Abstract]

Earnings per Share

Earnings per Share (EPS)

Basic and diluted EPS are computed using the two-class method, which is an earnings allocation that determines EPS for each class of common stock and participating securities according to dividends declared and participation rights in undistributed earnings. The Company’s restricted stock awards are considered participating securities because holders are entitled to receive non-forfeitable dividends during the vesting term. Diluted EPS includes securities that could potentially dilute basic EPS during a reporting period, for which the Company includes the Debentures and share-based compensation awards.

A conversion of the Debentures may result in payment for any conversion value in excess of the principal amount of the Debentures in the Company’s common stock. For diluted EPS purposes, potential common stock is calculated based on whether the market price of the Company’s common stock at the end of each reporting period is in excess of the conversion price of the Debentures. For a full discussion of the conditions under which the Debentures may be converted, the conversion rate to common stock and the conversion price, see Note 11.

For all but the performance units, the potentially dilutive impact of the Company’s share-based compensation awards is determined using the treasury stock method. Under the treasury stock method, awards are treated as if they had been exercised with any proceeds used to repurchase common stock at the average market price during the period. Any incremental difference between the assumed number of shares issued and purchased is included in the diluted share computation. For the Company’s other share-based compensation awards, performance units, their contingent features result in an assessment for any potentially dilutive common stock by using the end of the reporting period as if it were the end of the contingency period for all units granted. For a full discussion of the Company’s share-based compensation awards, see Note 17.

The computation of diluted EPS excludes anti-dilutive shares of approximately 0.2 million for the years ended December 31, 2011, 2010 and 2009. These anti-dilutive shares were due to certain share-based compensation awards calculated under the treasury stock method. This anti-dilution generally occurs where the exercise prices are higher than the average market value of the Company’s stock price during the applicable period.

The following illustrates the earnings allocation method utilized in the calculation of basic and diluted EPS.

	Year Ended December 31,
	2011			2010			2009
	(In millions, except per share amounts)
EPS numerator:
Income from continuing operations, net of income taxes	$	1,010.5		$	826.6		$	443.2
Less: Net (loss) income attributable to noncontrolling interests	(11.4		)	28.2			14.8
Income from continuing operations attributable to common stockholders before allocation of earnings to participating securities	1,021.9			798.4			428.4
Less: Earnings allocated to participating securities	(5.3		)	(5.6		)	(2.9		)
Income from continuing operations attributable to common stockholders, after earnings allocated to participating securities(1)	1,016.6			792.8			425.5
(Loss) income from discontinued operations, net of income taxes	(64.2		)	(24.4		)	19.8
Net income attributable to common stockholders, after earnings allocated to participating securities(1)	$	952.4		$	768.4		$	445.3
EPS denominator:
Weighted average shares outstanding — basic	269.1			267.0			265.5
Impact of dilutive securities	1.2			2.9			2.0
Weighted average shares outstanding — diluted	270.3			269.9			267.5
Basic EPS attributable to common stockholders:
Income from continuing operations	$	3.77		$	2.97		$	1.60
(Loss) income from discontinued operations	(0.24		)	(0.09		)	0.08
Net income attributable to common stockholders	$	3.53		$	2.88		$	1.68
Diluted EPS attributable to common stockholders:
Income from continuing operations	$	3.76		$	2.93		$	1.59
(Loss) income from discontinued operations	(0.24		)	(0.09		)	0.07
Net income attributable to common stockholders	$	3.52		$	2.84		$	1.66

⁽¹⁾  The reallocation adjustment for participating securities to arrive at the numerator used to calculate diluted EPS was less than $0.1 million for the periods presented.

XML

Pension and Savings Plans (Details 3) (Pension Plans, Defined Benefit [Member])	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Pension Plans, Defined Benefit [Member]
Weighted average assumptions used to determine benefit obligations
Discount rate		5.00%	5.84%
Measurement date		Dec. 31, 2011	Dec. 31, 2010
Weighted-average assumptions used to determine net periodic benefit cost
Discount rate		5.84%	6.19%	6.90%
Expected long-term return on plan assets	8.00%	8.25%	8.25%	8.75%
Measurement date		December 31, 2010	December 31, 2009	December 31, 2008

XML

Summary Quarterly Financial Information (Tables)

12 Months Ended

Dec. 31, 2011

Summary Quarterly Financial Information (Tables) [Abstract]

Summary of the unaudited quarterly results of operations

	Year Ended December 31, 2010
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(In millions, except per share data)
Revenues	$	1,490.6	$	1,629.9	$	1,826.7	$	1,792.7
Operating profit	255.1		325.7		447.3		326.3
Income from continuing operations, net of income taxes	147.8		215.7		239.3		223.8
Net income	136.7		214.2		236.3		215.0
Net income attributable to common stockholders	133.7		206.2		224.1		210.0
Basic EPS — continuing operations(1)	0.54		0.77		0.84		0.81
Diluted EPS — continuing operations(1)	$	0.54	$	0.77	$	0.84	$	0.80
Weighted average shares used in calculating basic EPS	266.5		266.6		267.1		267.7
Weighted average shares used in calculating diluted EPS	268.2		268.3		268.6		270.3

⁽¹⁾  EPS for the quarters may not sum to the amounts for the year as each period is computed on a discrete basis

	Year Ended December 31, 2011
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(In millions, except per share data)
Revenues	$	1,743.1	$	1,980.5	$	1,997.2	$	2,253.6
Operating profit	314.3		479.3		381.5		418.3
Income from continuing operations, net of income taxes	194.6		307.8		285.6		222.5
Net income	178.7		292.2		281.4		194.0
Net income attributable to common stockholders	176.5		284.8		274.0		222.4
Basic EPS — continuing operations(1)	0.71		1.11		1.03		0.93
Diluted EPS — continuing operations(1)	$	0.70	$	1.10	$	1.02	$	0.92
Weighted average shares used in calculating basic EPS	268.9		269.0		269.2		269.3
Weighted average shares used in calculating diluted EPS	272.8		270.5		270.6		270.2

⁽¹⁾  EPS for the quarters may not sum to the amounts for the year as each period is computed on a discrete basis.

XML

Accounts Payable and Accrued Expenses (Tables)

12 Months Ended

Dec. 31, 2011

Payables and Accruals [Abstract]

Accounts payable and accrued expenses

Accounts payable and accrued expenses consisted of the following:

	December 31,
	2011		2010
	(Dollars in millions)
Trade accounts payable	$	735.6	$	465.5
Other accrued expenses	286.7		179.9
Accrued taxes other than income	196.8		185.3
Accrued payroll and related benefits	183.3		152.1
Accrued health care	77.8		85.9
Accrued royalties	77.8		72.6
Accrued interest	49.5		30.5
Workers’ compensation obligations	17.3		14.6
Accrued environmental	11.6		6.3
Commodity and foreign currency hedge contracts	7.9		2.9
Other accrued benefits	4.1		4.2
Income taxes payable	—		59.6
Liabilities associated with discontinued operations	63.9		29.4
Total accounts payable and accrued expenses	$	1,712.3	$	1,288.8

XML

Financial Instruments and Guarantees with Off-Balance-Sheet Risk

12 Months Ended

Dec. 31, 2011

Financial Instruments And Guarantees With Off Balance Sheet Risk Disclosure [Abstract]

Financial Instruments and Guarantees with Off-Balance-Sheet Risk

Financial Instruments and Guarantees With Off-Balance-Sheet Risk

In the normal course of business, the Company is a party to guarantees and financial instruments with off-balance-sheet risk, which are not reflected in the accompanying consolidated balance sheets. Such financial instruments are valued based on the amount of exposure under the instrument and the likelihood of required performance. In the Company’s past experience, virtually no claims have been made against these financial instruments. Management does not expect any material losses to result from these guarantees or off-balance-sheet instruments.

Financial Instruments with Off-Balance Sheet Risk

As of December 31, 2011, the Company had the following financial instruments with off-balance sheet risk:

	Reclamation Obligations		Lease Obligations		Workers’ Compensation Obligations		Other(1)		Total
	(Dollars in millions)
Self bonding	$	929.6	$	—	$	—	$	—	$	929.6
Surety bonds	613.2		104.7		13.5		11.0		742.4
Bank guarantees	178.4		—		—		211.2		389.6
Letters of credit	—		—		62.6		20.0		82.6
Bilateral cash collateralization agreements	—		—		—		79.7		79.7
	$	1,721.2	$	104.7	$	76.1	$	321.9	$	2,223.9

⁽¹⁾  Other includes bilateral cash collateralization agreement obligations described below and an additional $242.2 million in bank guarantees, letters of credit and surety bonds related to collateral for surety companies, road maintenance, performance guarantees and other operations.

The Company owns a 37.5% interest in Dominion Terminal Associates, a partnership that operates a coal export terminal in Newport News, Virginia under a 30-year lease that permits the partnership to purchase the terminal at the end of the lease term for a nominal amount. The partners have severally (but not jointly) agreed to make payments under various agreements which in the aggregate provide the partnership with sufficient funds to pay rents and to cover the principal and interest payments on the floating-rate industrial revenue bonds issued by the Peninsula Ports Authority, and which are supported by letters of credit from a commercial bank. As of December 31, 2011, the Company’s maximum reimbursement obligation to the commercial bank was in turn supported by four letters of credit totaling $42.7 million. The Company has a bilateral cash collateralization agreement for these letters of credit whereby the Company posted cash collateral in lieu of utilizing its Credit Facility. Such cash collateral is classified within "Cash and cash equivalents" given the Company has the ability to substitute letters of credit at any time for this cash collateral and it is, therefore, readily available to the Company.

The Company is party to an agreement with the PBGC and TXU Europe Limited, an affiliate of the Company’s former parent corporation, under which the Company is required to make special contributions to two of the Company’s defined benefit pension plans and to maintain a $37.0 million letter of credit in favor of the PBGC. If the Company or the PBGC gives notice of an intent to terminate one or more of the covered pension plans in which liabilities are not fully funded, or if the Company fails to maintain the letter of credit, the PBGC may draw down on the letter of credit and use the proceeds to satisfy liabilities under the Employee Retirement Income Security Act of 1974, as amended. The PBGC, however, is required to first apply amounts received from a $110.0 million guarantee in place from TXU Europe Limited in favor of the PBGC before it draws on the Company’s letter of credit. The Company has a bilateral cash collateralization agreement for this letter of credit whereby the Company posted cash collateral in lieu of utilizing its Credit Facility. Such cash collateral is classified within "Cash and cash equivalents" given the Company has the ability to substitute letters of credit at any time for this cash collateral and it is therefore readily available to the Company. On November 19, 2002, TXU Europe Limited was placed under the administration process in the United Kingdom (a process similar to bankruptcy proceedings in the U.S.) and continues under this process as of December 31, 2011. As a result of these proceedings, TXU Europe Limited may be liquidated or otherwise reorganized in such a way as to relieve it of its obligations under its guarantee.

Accounts Receivable Securitization

The Company has an accounts receivable securitization program (securitization program) with a maximum capacity of $275.0 million through its wholly-owned, bankruptcy-remote subsidiary (Seller). At December 31, 2011, the Company had $41.7 million available under the securitization program, net of outstanding letters of credit and amounts drawn. Under the securitization program, the Company contributes, on a revolving basis, trade receivables of most of the Company’s U.S. subsidiaries to the Seller, which then sells the receivables in their entirety to a consortium of unaffiliated asset-backed commercial paper conduits (the Conduits). After the sale, the Company, as servicer of the assets, collects the receivables on behalf of the Conduits for a nominal servicing fee. The Company utilizes proceeds from the sale of its accounts receivable as an alternative to short-term borrowings under its Credit Facility, effectively managing its overall borrowing costs and providing an additional source for working capital. The current securitization program extends to May 2012, while the letter of credit commitment that supports the commercial paper facility underlying the securitization program must be renewed annually.

The Seller is a separate legal entity whose assets are available first and foremost to satisfy the claims of its creditors. Of the receivables sold to the Conduits, a portion of the amount due to the Seller is deferred until the ultimate collection of the underlying receivables. During the year ended December 31, 2011, the Company received total consideration of $4,633.4 million related to accounts receivable sold under the securitization program, including $3,462.7 million of cash up front from the sale of the receivables, an additional $1,004.8 million of cash upon the collection of the underlying receivables, and $165.9 million that had not been collected at December 31, 2011 and was recorded at fair value which approximates carrying value. The reduction in accounts receivable as a result of securitization activity with the Conduits was $150.0 million at December 31, 2011 and $150.0 million at December 31, 2010.

The securitization activity has been reflected in the consolidated statements of cash flows as operating activity because both the cash received from the Conduits upon sale of receivables as well as the cash received from the Conduits upon the ultimate collection of receivables are not subject to significantly different risks given the short-term nature of the Company’s trade receivables. The Company recorded expense associated with securitization transactions of $2.0 million, $2.4 million and $4.0 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Other

The Company is the lessee under numerous equipment and property leases. It is common in such commercial lease transactions for the Company, as the lessee, to agree to indemnify the lessor for the value of the property or equipment leased, should the property be damaged or lost during the course of the Company’s operations. The Company expects that losses with respect to leased property would be covered by insurance (subject to deductibles). The Company and certain of its subsidiaries have guaranteed other subsidiaries’ performance under their various lease obligations. Aside from indemnification of the lessor for the value of the property leased, the Company’s maximum potential obligations under its leases are equal to the respective future minimum lease payments, and the Company assumes that no amounts could be recovered from third parties.

In connection with the development of Prairie State, each owner, including one of the Company’s subsidiaries, has issued a guarantee for its proportionate share (5.06% for the Company) of the construction costs under an agreement with Bechtel Power Corporation.

The Company has provided financial guarantees under certain long-term debt agreements entered into by its subsidiaries, and substantially all of the Company’s subsidiaries provide financial guarantees under long-term debt agreements entered into by the Company. The maximum amounts payable under the Company’s debt agreements are equal to the respective principal and interest payments.

XML

Commitments and Contingencies

12 Months Ended

Dec. 31, 2011

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Commitments

As of December 31, 2011, purchase commitments for capital expenditures were $1,313.0 million, all of which is obligated within the next three years, with $743.6 million obligated in the next year. The purchase commitments for capital expenditures represent an increase of $854.8 million over amounts committed as of December 31, 2010 and primarily relate to new mines and expansion and extension projects in Australia and the U.S. Commitments made for expenditures under coal leases are reflected in Note 12. The Company also has various long- and short-term take or pay arrangements associated with rail and port commitments in Australia for the delivery of coal including amounts relating to export facilities. As of December 31, 2011, these commitments totaled $4,547.6 million with $1,644.0 million obligated within the next four years, of which $443.1 million was obligated within the next year. During 2011, the Company recognized approximately $284 million of expense, reflected in “Operating costs and expenses” in the consolidated statements of income, related to these take or pay arrangements.

A subsidiary of the Company owns a 5.06% undivided interest in Prairie State. The Company invested $36.2 million, $76.0 million and $56.8 million during the years ended December 31, 2011, 2010 and 2009, respectively, representing its 5.06% share of the construction costs for those periods. Included in “Investments and other assets” in the consolidated balance sheets as of December 31, 2011 and December 31, 2010, are costs of $238.7 million and $202.5 million, respectively. The Company’s share of total construction costs for Prairie State is expected to be approximately $250 million with the remaining funding expected in 2012.

Contingencies

From time to time, the Company or its subsidiaries are involved in legal proceedings arising in the ordinary course of business or related to indemnities or historical operations. The Company believes it has recorded adequate reserves for these liabilities and that there is no individual case pending that is likely to have a material adverse effect on the Company’s financial condition, results of operations or cash flows. The Company discusses its significant legal proceedings below.

Litigation Relating to Continuing Operations

Navajo Nation Litigation.  On June 18, 1999, the Navajo Nation served three of the Company’s 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 which alleged that the defendants jointly participated in unlawful activity to obtain favorable coal lease amendments. The plaintiff sought actual and punitive damages and the termination and reformation of two coal leases. The court allowed the Hopi Tribe to intervene in this lawsuit, and the Hopi Tribe sought unspecified actual and punitive damages and reformation of its coal lease. One of the Company’s subsidiaries named as a defendant is now a subsidiary of Patriot. However, the Company is responsible for this litigation under the Separation Agreement entered into with Patriot in connection with the spin-off.

In October 2010, the Company's subsidiaries and the other defendants settled the Hopi claims, and the court dismissed those claims. In August 2011, the Company's subsidiaries and other defendants settled the Navajo claims, and agreed to dismiss all of the pending litigation with prejudice. In connection with this settlement, the Company recorded a provision totaling $24.5 million in 2011. The court has dismissed this lawsuit, and this matter has concluded.

Gulf Power Company Litigation.  On June 22, 2006, Gulf Power Company (Gulf Power) filed a breach of contract lawsuit against a Company subsidiary in the U.S. District Court, Northern District of Florida, contesting the force majeure declaration by the Company’s subsidiary under a coal supply agreement with Gulf Power and seeking damages for alleged past and future tonnage shortfalls of nearly five million tons under the agreement, which expired on December 31, 2007. On June 30, 2009, the court granted Gulf Power’s motion for partial summary judgment on liability and denied the Company subsidiary’s motion for summary judgment. On September 30, 2010, the court entered its order on damages, awarding Gulf Power zero dollars in damages and the Company subsidiary its costs to defend the lawsuit. On November 1, 2010, Gulf Power filed a motion to alter or amend the judgment, contesting the trial court’s damages order, to which the Company subsidiary objected. The court entered an order on July 29, 2011 that affirmed its September 30, 2010 decision in all respects except for 2007 cover coal purchases and granted in part Gulf Power's motion to alter judgment with respect to 2007 cover coal purchases. On September 30, 2011, the court entered an order awarding Gulf Power damages in the the amount of $20.5 million for its 2007 cover coal purchases. On January 19, 2012, the court entered its order awarding Gulf Power prejudgment interest in the amount of $6.9 million plus post-judgment interest. The Company's subsidiary has filed its notice of appeal. Based on the Company's evaluation of information currently available concerning the issues and their potential impact, the Company believes that its subsidiary will be successful in the liability appeals process and, therefore, no liability has been recorded at this time.

Monto Coal Pty Limited, Monto Coal 2 Pty Ltd Limited and Macarthur Coal Limited. In October 2007, a statement of claim was delivered to Monto Coal Pty Ltd, a wholly owned subsidiary of Macarthur, and Monto Coal 2 Pty Ltd, an equity accounted investee, from the minority interest holders in the Monto Coal joint venture, alleging that Monto Coal 2 Pty Ltd breached the Monto Coal Joint Venture Agreement and Monto Coal Pty Ltd breached the Monto Coal Management Agreement. Monto Coal Pty Ltd is the manager of the Monto Coal joint venture pursuant to the Management Agreement. Monto Coal 2 Pty Ltd holds a 51% interest in the Monto Coal Joint Venture. The plaintiffs are Sanrus Pty ltd, Edge Developments Pty Ltd and H&J Enterprises (Qld) Pty Ltd. An additional statement of claim was delivered to Macarthur in November 2010 from the same minority interest holders in the Monto Coal Joint Venture, alleging that Macarthur induced Monto Coal 2 Pty Ltd and Monto Coal Pty Ltd to breach the Monto Coal Joint Venture Agreement and the Monto Coal Management Agreement, respectively. These actions, which are pending before the Supreme Court of Queensland, Australia, seek damages from the three defendants collectively of no less than $1,193.2 million Australian dollars plus interest and costs. The defendants dispute the claims and are vigorously defending their positions. Based on the Company's evaluation of the issues and their potential impact, the amount of any future loss cannot be reasonably estimated. However, based on current information, the Company believes these claims are likely to be finalized without a material adverse effect on its financial condition, results of operations or cash flows.

MCG Coal Holdings Pty Ltd. In 2010, Macarthur loaned $360.0 million (Australian dollars) to MCG Coal Holdings Pty Ltd (MCG). The loan from Macarthur was based on an entitlement for Macarthur to convert the loan into a 90% interest in MCG, the indirect holder of a mineral development licence (MDL 162) that was acquired with the proceeds of the loan. MCG and two associated companies (MCG Coal Pty Ltd and Fortrus Resources Pty Ltd) refused to take the steps necessary to enable Macarthur to convert the loan into equity. Macarthur and its nominee, Macarthur Berrigurra Pty Ltd, commenced an action on May 24, 2011 in the Supreme Court of Queensland, Australia, to require MCG and the two associated companies to complete the conversion. On January 30, 2012, the court ordered that all parties perform the steps required to enable Macarthur to convert the loan to equity and that Macarthur's court costs be paid. Macarthur, through its nominee Macarthur Berrigurra, now holds its equity interest in MCG.

Claims and Litigation Relating to Indemnities or Historical Operations

Oklahoma Lead Litigation.  Gold Fields Mining, LLC (Gold Fields) is a dormant, non-coal producing entity that was previously managed and owned by Hanson PLC, the Company’s predecessor owner. In a February 1997 spin-off, Hanson PLC transferred ownership of Gold Fields to the Company, despite the fact that Gold Fields had no ongoing operations and the Company had no prior involvement in its past operations. Gold Fields is currently one of the Company’s subsidiaries. The Company 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 several other companies are defendants in a property damage lawsuit pending in the U.S. District Court for the Northern District of Oklahoma arising from past operations near Picher, Oklahoma. The plaintiffs are seeking compensatory damages for diminution in property values and punitive damages. Gold Fields has entered into a settlement with plaintiffs and the case has been stayed pending receipt of releases from all plaintiffs. Gold Fields was also a defendant in another case alleging property damage and pending in the U.S. District Court for the Northern District of Oklahoma arising out of past operations near Picher, Oklahoma, but the court granted summary judgment in Gold Field's favor in that case.

Gold Fields and several other companies are also defendants in a personal injury lawsuit pending in the U.S. District Court for the Northern District of Oklahoma arising from past operations near Picher, Oklahoma. The four plaintiffs are seeking compensatory damages for cognitive impairments allegedly caused by exposure to lead and punitive damages. Gold Fields has entered into a settlement with plaintiffs and other potential personal injury claimants. The case has been stayed pending receipt of releases from all plaintiffs/claimants and court approval of the settlement on behalf of minor plaintiffs/claimants.

In June 2005, Gold Fields and other potentially responsible parties (PRPs) received a letter from the U. S. Department of Justice alleging that the potentially responsible parties' mining operations caused the U.S. Environmental Protection Agency (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 June 2008, Gold Fields and other PRPs received letters from the U.S. Department of Justice and the EPA re-initiating settlement negotiations. Gold Fields continues to participate in the settlement discussions. Gold Fields believes it has meritorious defense to these claims.

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. The state of Oklahoma has also indicated that it seeks to recover remediation costs from these parties.

The outcome of litigation and these claims are subject to numerous uncertainties. Based on the Company’s evaluation of the issues and their potential impact, the amount of any future loss cannot be reasonably estimated. However, based on current information, the Company believes these claims are likely to be resolved without a material adverse effect on its 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 13 additional sites, bringing the total to 18, which have since been reduced to 11 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 $52.5 million as of December 31, 2011 and $51.1 million as of December 31, 2010, $11.6 million and $6.3 million of which was reflected as a current liability, respectively. These amounts represent those costs that the Company believes are probable and reasonably estimable.

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 the Company’s evaluation of the issues and their potential impact, the total amount of any future loss cannot be reasonably estimated. However, based on current information, the Company believes these claims and litigation are likely to be resolved without a material adverse effect on its financial condition, results of operations or cash flows.

Native Village of Kivalina and City of Kivalina v. ExxonMobil Corporation, et al.  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 the Company, 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. The defendants filed motions to dismiss on the grounds of lack of personal and subject matter jurisdiction. In June 2009, the court granted defendants’ motion to dismiss for lack of subject matter jurisdiction finding that plaintiffs’ federal claim for nuisance is barred by the political question doctrine and for lack of standing. The plaintiffs appealed the court’s dismissal to the U.S. Court of Appeals for the Ninth Circuit, which heard oral arguments on November 28, 2011.

Other

In addition, at times the Company becomes 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 the Company does business.

In June 2007, the New York Office of the Attorney General served a letter and subpoena on the Company, seeking information and documents relating to the Company's disclosure to investors of risks associated with possible climate change and related legislation and regulations. The Company believes it has made full and proper disclosure of these potential risks. Based on current information, the Company believes that the ultimate resolution of such other pending or threatened proceedings is not reasonably likely to have a material adverse effect on its financial position, results of operations or liquidity.

XML

Consolidated Statements of Changes in Stockholders' Equity (Parenthetical) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Comprehensive income:
Net unrealized holding losses on available-for-sale securities, tax benefit	$ 3.9
Increase in fair value of cash flow hedges, tax benefit (provision)	6.2	(129.5)	(220.9)
Postretirement plans and workers' compensation obligations, tax benefit	$ 63.4	$ 2.1	$ 71.8

XML

Summary Quarterly Financial Information

12 Months Ended

Dec. 31, 2011

Quarterly Financial Data [Abstract]

Summary Quarterly Financial Information (Unaudited)

Summary Quarterly Financial Information (Unaudited)

A summary of the unaudited quarterly results of operations for the years ended December 31, 2011 and 2010 is presented below.

	Year Ended December 31, 2011
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(In millions, except per share data)
Revenues	$	1,743.1	$	1,980.5	$	1,997.2	$	2,253.6
Operating profit	314.3		479.3		381.5		418.3
Income from continuing operations, net of income taxes	194.6		307.8		285.6		222.5
Net income	178.7		292.2		281.4		194.0
Net income attributable to common stockholders	176.5		284.8		274.0		222.4
Basic EPS — continuing operations(1)	0.71		1.11		1.03		0.93
Diluted EPS — continuing operations(1)	$	0.70	$	1.10	$	1.02	$	0.92
Weighted average shares used in calculating basic EPS	268.9		269.0		269.2		269.3
Weighted average shares used in calculating diluted EPS	272.8		270.5		270.6		270.2

⁽¹⁾  EPS for the quarters may not sum to the amounts for the year as each period is computed on a discrete basis.

The fourth quarter results of operations include Macarthur’s results of operations from the date of acquisition. The third and fourth quarters operating profit reflects $9.1 million and $76.1 million, respectively, of acquisition costs related to the Macarthur acquisition and an adverse impact of a third quarter roof fall and recovery of longwall operations at the Company's North Goonyella Mine in Australia, impacting the third and fourth quarters by $122.9 million and $111.8 million, respectively. Income from continuing operations, net of income taxes in the first, second and fourth quarters included non-cash tax expense of $6.4 million, $15.4 million and $16.0 million, respectively, from the remeasurement of non-U.S. income tax accounts, while the third quarter included a non-cash tax benefit of $38.7 million.

	Year Ended December 31, 2010
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(In millions, except per share data)
Revenues	$	1,490.6	$	1,629.9	$	1,826.7	$	1,792.7
Operating profit	255.1		325.7		447.3		326.3
Income from continuing operations, net of income taxes	147.8		215.7		239.3		223.8
Net income	136.7		214.2		236.3		215.0
Net income attributable to common stockholders	133.7		206.2		224.1		210.0
Basic EPS — continuing operations(1)	0.54		0.77		0.84		0.81
Diluted EPS — continuing operations(1)	$	0.54	$	0.77	$	0.84	$	0.80
Weighted average shares used in calculating basic EPS	266.5		266.6		267.1		267.7
Weighted average shares used in calculating diluted EPS	268.2		268.3		268.6		270.3

⁽¹⁾  EPS for the quarters may not sum to the amounts for the year as each period is computed on a discrete basis.

Operating profit in the second, third and fourth quarters of 2010 reflects higher contract pricing in Australia. Operating profit for the fourth quarter also includes an adverse impact related to flooding in Queensland, Australia and lower results from the Company’s Trading and Brokerage operations. Income from continuing operations, net of income taxes in the first, third and fourth quarters included non-cash tax expense of $5.5 million, $43.0 million and $18.9 million, respectively, from the remeasurement of non-U.S. income tax accounts, while the second quarter included a non-cash tax benefit of $19.5 million.

XML

Income Taxes (Details 5) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Summary of Company's tax payments
Tax payments	$ 275.1	$ 148.4	$ 170.6
Domestic Country [Member]
Summary of Company's tax payments
Tax payments	200.0	65.0	0
State and Local Jurisdiction [Member]
Summary of Company's tax payments
Tax payments	13.2	0.4	0.9
Foreign Country [Member]
Summary of Company's tax payments
Tax payments	$ 61.9	$ 83.0	$ 169.7

XML

Accumulated Other Comprehensive Income (Loss) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
After-tax components of comprehensive income (loss)
Foreign Currency Translation Adjustment, Beginning Balance	$ 3.1	$ 3.1	$ 3.1
Foreign Currency Translation Adjustment, Ending Balance	3.1	3.1	3.1
Net Actuarial Loss Associated with Postretirement Plans and Workers' Compensation Obligations, Beginning Balance	(353.0)	(343.5)	(220.4)
Net Actuarial Loss Associated with Postretirement Plans and Workers' Compensation Obligations, Reclassifications	(38.2)	(31.8)	(11.8)
Net Actuarial Loss Associated with Postretirement Plans and Workers' Compensation Obligations, Current period change	(150.1)	(41.3)	(134.9)
Net Actuarial Loss Associated with Postretirement Plans and Workers' Compensation Obligations, Ending Balance	(464.9)	(353.0)	(343.5)
Prior Service Cost Associated with Postretirement Plans, Beginning Balance	(12.8)	(10.4)	(18.7)
Prior Service Cost Associated with Postretirement Plans, Reclassification	(2.3)	(2.5)	(1.8)
Prior Service Cost Associated with Postretirement Plans, Current period change	0.9	(4.9)	6.5
Prior Service Cost Associated with Postretirement Plans, Ending Balance	(9.6)	(12.8)	(10.4)
Cash Flow Hedges, Beginning Balance	294.8	167.3	(152.5)
Cash Flow Hedges, Net change in fair value	291.9	229.9	235.2
Cash Flow Hedges, Reclassification	(251.0)	(102.4)	84.6
Cash Flow Hedges, Ending Balance	335.7	294.8	167.3
Available-For-Sale Securities Adjustment, Beginning Balance	0	0	0
Available-For-Sale Securities Adjustment, Net change in fair value	(5.8)	0	0
Available-For-Sale Securities Adjustment, Reclassification	0.9	0	0
Available-For-Sale Securities Adjustment, Ending Balance	(6.7)	0	0
Total Accumulated Other Comprehensive Loss, Beginning Balance	(67.9)	(183.5)	(388.5)
Total Accumulated Other Comprehensive Loss, Net change in fair value	286.1	229.9	235.2
Total Accumulated Other Comprehensive Loss, Reclassification	(211.4)	(68.1)	98.2
Total Accumulated Other Comprehensive Loss, Current period change net of tax	(149.2)	(46.2)	(128.4)
Total Accumulated Other Comprehensive Loss, Ending Balance	$ (142.4)	$ (67.9)	$ (183.5)

XML

Investments (Tables)

12 Months Ended

Dec. 31, 2011

Investments, Debt and Equity Securities [Abstract]

Investments in available-for-sale securities

Investments in available-for-sale securities at December 31, 2011 were as follows:

Available-for-sale securities	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	(Dollars in millions)
Current:
Federal government securities	$	3.3	$	—	$	—		$	3.3
U.S. corporate bonds	3.9		—		—			3.9
Noncurrent:
Marketable equity securities	66.5		—		(9.5		)	57.0
Federal government securities	11.3		0.2		—			11.5
U.S. corporate bonds	7.7		0.1		—			7.8
Total	$	92.7	$	0.3	$	(9.5	)	$	83.5

Investments in available-for-sale securities at December 31, 2010 were as follows:

Available-for-sale securities	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
			(Dollars in millions)
Current:
Federal government securities	$	0.5	$	—	$	—	$	0.5
U.S. corporate bonds	1.9		—		—		1.9
Noncurrent:
Federal government securities	9.2		—		—		9.2
U.S. corporate bonds	6.3		—		—		6.3
Total	$	17.9	$	—	$	—	$	17.9

Contractual maturities for available for sale investment in debt securities

Contractual maturities for available-for-sale investments in debt securities at December 31, 2011 were as shown below. Expected maturities will differ from contractual maturities because borrowers may have the right to call or prepay obligations with or without call or prepayment penalties.

Contractual maturities for available-for-sale securities	Cost		Fair Value
	(Dollars in millions)
Due in one year or less	$	7.2	$	7.2
Due in one to five years	19.0		19.3
Total	$	26.2	$	26.5

XML

Earnings per Share (Tables)

12 Months Ended

Dec. 31, 2011

Earnings Per Share [Abstract]

Earnings allocation method utilized in the calculation of basic and diluted EPS

The following illustrates the earnings allocation method utilized in the calculation of basic and diluted EPS.

	Year Ended December 31,
	2011			2010			2009
	(In millions, except per share amounts)
EPS numerator:
Income from continuing operations, net of income taxes	$	1,010.5		$	826.6		$	443.2
Less: Net (loss) income attributable to noncontrolling interests	(11.4		)	28.2			14.8
Income from continuing operations attributable to common stockholders before allocation of earnings to participating securities	1,021.9			798.4			428.4
Less: Earnings allocated to participating securities	(5.3		)	(5.6		)	(2.9		)
Income from continuing operations attributable to common stockholders, after earnings allocated to participating securities(1)	1,016.6			792.8			425.5
(Loss) income from discontinued operations, net of income taxes	(64.2		)	(24.4		)	19.8
Net income attributable to common stockholders, after earnings allocated to participating securities(1)	$	952.4		$	768.4		$	445.3
EPS denominator:
Weighted average shares outstanding — basic	269.1			267.0			265.5
Impact of dilutive securities	1.2			2.9			2.0
Weighted average shares outstanding — diluted	270.3			269.9			267.5
Basic EPS attributable to common stockholders:
Income from continuing operations	$	3.77		$	2.97		$	1.60
(Loss) income from discontinued operations	(0.24		)	(0.09		)	0.08
Net income attributable to common stockholders	$	3.53		$	2.88		$	1.68
Diluted EPS attributable to common stockholders:
Income from continuing operations	$	3.76		$	2.93		$	1.59
(Loss) income from discontinued operations	(0.24		)	(0.09		)	0.07
Net income attributable to common stockholders	$	3.52		$	2.84		$	1.66

⁽¹⁾  The reallocation adjustment for participating securities to arrive at the numerator used to calculate diluted EPS was less than $0.1 million for the periods presented.

XML

Derivatives and Fair Value Measurements (Details 3) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Available-for-sale Securities	$ 83.5	$ 17.9
Fair value of financial asset (liability) positions measured on a recurring basis
Investment in debt and equity securities	29.4
Fair Value, Measurements, Recurring [Member]
Fair value of financial asset (liability) positions measured on a recurring basis
Investment in debt and equity securities	83.5	17.9
Total net financial assets	607.1	698.2
Fair Value, Measurements, Recurring [Member] | Commodity swaps and options [Member]
Fair value of financial asset (liability) positions measured on a recurring basis
Derivative assets (liabilities), at fair value, net	33.0	40.2
Fair Value, Measurements, Recurring [Member] | Foreign currency contracts [Member]
Fair value of financial asset (liability) positions measured on a recurring basis
Derivative assets (liabilities), at fair value, net	490.6	640.1
Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Fair value of financial asset (liability) positions measured on a recurring basis
Investment in debt and equity securities	83.5	17.9
Total net financial assets	83.5	17.9
Fair Value, Measurements, Recurring [Member] | Level 1 [Member] | Commodity swaps and options [Member]
Fair value of financial asset (liability) positions measured on a recurring basis
Derivative assets (liabilities), at fair value, net	0	0
Fair Value, Measurements, Recurring [Member] | Level 1 [Member] | Foreign currency contracts [Member]
Fair value of financial asset (liability) positions measured on a recurring basis
Derivative assets (liabilities), at fair value, net	0	0
Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Fair value of financial asset (liability) positions measured on a recurring basis
Investment in debt and equity securities	0	0
Total net financial assets	523.6	680.3
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Commodity swaps and options [Member]
Fair value of financial asset (liability) positions measured on a recurring basis
Derivative assets (liabilities), at fair value, net	33.0	40.2
Fair Value, Measurements, Recurring [Member] | Level 2 [Member] | Foreign currency contracts [Member]
Fair value of financial asset (liability) positions measured on a recurring basis
Derivative assets (liabilities), at fair value, net	490.6	640.1
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Fair value of financial asset (liability) positions measured on a recurring basis
Investment in debt and equity securities	0	0
Total net financial assets	0	0
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Commodity swaps and options [Member]
Fair value of financial asset (liability) positions measured on a recurring basis
Derivative assets (liabilities), at fair value, net	0	0
Fair Value, Measurements, Recurring [Member] | Level 3 [Member] | Foreign currency contracts [Member]
Fair value of financial asset (liability) positions measured on a recurring basis
Derivative assets (liabilities), at fair value, net	$ 0	$ 0

XML

Consolidated Statements of Income (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Revenues
Sales	$ 7,091.3	$ 6,211.2	$ 5,303.1
Other revenues	883.1	528.7	543.9
Total revenues	7,974.4	6,739.9	5,847.0
Costs and expenses
Operating costs and expenses	5,550.0	4,697.3	4,339.2
Depreciation, depletion and amortization	482.2	437.1	400.5
Asset retirement obligation expense	53.1	47.2	39.9
Selling and administrative expenses	268.2	232.2	199.1
Acquisition costs related to Macarthur Coal Limited	85.2	0	0
Other operating (income) loss:
Net gain on disposal or exchange of assets	(76.9)	(30.0)	(23.2)
Loss from equity affiliates	19.2	1.7	69.1
Operating profit	1,593.4	1,354.4	822.4
Interest expense	238.6	222.0	201.1
Interest income	(18.9)	(9.6)	(8.1)
Income from continuing operations before income taxes	1,373.7	1,142.0	629.4
Income tax provision	363.2	315.4	186.2
Income from continuing operations, net of income taxes	1,010.5	826.6	443.2
Loss (income) from discontinued operations, net of income taxes	(64.2)	(24.4)	19.8
Net income	946.3	802.2	463.0
Less: Net (loss) income attributable to noncontrolling interests	(11.4)	28.2	14.8
Net income attributable to common stockholders	$ 957.7	$ 774.0	$ 448.2
Income From Continuing Operations
Basic earnings per share	$ 3.77	$ 2.97	$ 1.60
Diluted earnings per share	$ 3.76	$ 2.93	$ 1.59
Net Income Attributable to Common Stockholders
Basic earnings per share	$ 3.53	$ 2.88	$ 1.68
Diluted earnings per share	$ 3.52	$ 2.84	$ 1.66
Dividends declared per share	$ 0.340	$ 0.295	$ 0.250

XML

Debt (Tables)

12 Months Ended

Dec. 31, 2011

Debt Disclosure [Abstract]

Long-Term Debt

The Company’s total indebtedness as of December 31, 2011 and 2010 consisted of the following:

	December 31,
	2011		2010
	(Dollars in millions)
Term Loan	$	468.8	$	493.8
2011 Term Loan Facility	1,000.0		—
5.875% Senior Notes due April 2016	—		218.1
7.375% Senior Notes due November 2016	650.0		650.0
6.00% Senior Notes due November 2018	1,600.0		—
6.50% Senior Notes due September 2020	650.0		650.0
6.25% Senior Notes due November 2021	1,500.0		—
7.875% Senior Notes due November 2026	247.3		247.2
Convertible Junior Subordinated Debentures due 2066	375.2		373.3
Capital lease obligations	122.8		69.6
Fair value hedge adjustment	—		2.2
Other	43.4		45.8
Total	$	6,657.5	$	2,750.0

Schedule of Interest Payments

Interest payments on the Senior Notes are scheduled to occur each year as follows:

Senior Notes	Interest Payment Dates
6.00% Senior Notes	May 15 and November 15
6.25% Senior Notes	May 15 and November 15
6.50% Senior Notes	March 15 and September 15
7.375% Senior Notes	May 1 and November 1
7.875% Senior Notes	May 1 and November 1

Carrying amount of the equity and debt components of the Debentures

The following table illustrates the carrying amount of the equity and debt components of the Debentures:

	December 31,
	2011			2010
	(Dollars in millions)
Carrying amount of the equity component	$	215.4		$	215.4
Principal amount of the liability component	$	732.5		$	732.5
Unamortized discount	(357.3		)	(359.2		)
Net carrying amount	$	375.2		$	373.3

Effective interest rate and the interest expense related to the Debentures

The following table illustrates the effective interest rate and the interest expense related to the Debentures:

	Year Ended December 31,
	2011			2010			2009
	(Dollars in millions)
Effective interest rate	4.9		%	4.9		%	4.9		%
Interest expense — contractual interest coupon	$	34.8		$	34.8		$	34.8
Interest expense — amortization of debt discount	1.9			1.8			1.6

Aggregate amounts of Long term debt maturities

The aggregate amounts of long-term debt maturities (including unamortized debt discounts) subsequent to December 31, 2011, including capital lease obligations, were as follows:

Year of Maturity	(Dollars in millions)
2012	$	101.1
2013	121.9
2014	107.8
2015	458.5
2016	1,475.7
2017 and thereafter	4,392.5
Total	$	6,657.5

XML

Postretirement Health Care and Life Insurance Benefits (Details Textuals) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011 years	Dec. 31, 2010 years
Defined Benefit Plan Disclosure [Line Items]
Actuarial gains and losses amortization corridor, percentage	0.00%
Postretirement Health Care and Life Insurance Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Average remaining service period of active employees (in years)	11.70	12.06
Estimated net actuarial loss that will be amortized from accumulated other comprehensive loss	$ 32.8
Estimated prior service cost that will be amortized from accumulated other comprehensive loss	$ 2.5

XML

Share-Based Compensation (Details Textuals) (USD $)	12 Months Ended
	Dec. 31, 2011 years	Dec. 31, 2010	Dec. 31, 2009
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee stock purchase plan, Shares	6,000,000
Shares purchased under the ESPP plans	200,000	200,000	400,000
Share-Based Compensation Textuals [Abstract]
Total shares of common stock available for grant	14,000,000
Common stock available for grant	13,800,000
Unrecognized compensation cost related to nonvested awards net of tax Total	$ 30,300,000
Unrecognized compensation cost period for recognition, years	3.0
Unrecognized compensation cost period for recognition, weighted-average, years	0.8
Total intrinsic value of options exercised	10,300,000	53,700,000	14,700,000
Goals to be achieved under Performance units awards based on stock price performance, percentage	50.00%
Goals to be achieved under Performance units awards based on a return on capital target, percentage	50.00%
Maximum employee Contribution to employee stock purchase plans based on compensation, percentage	15.00%
Maximum employee Contribution to employee stock purchase plans based on compensation, amount	25,000
Common stock discount under employee stock purchase plans	15.00%
Employee Stock Purchase Plans,Fair value estimation	estimated by adding the fair value of 0.15 of one share of stock to the fair value of 0.85 of an option on one share of stock
Total fair value of restricted stock awards granted	36,900,000	23,300,000	23,100,000
Total fair value of restricted stock awards vested	50,000,000	20,500,000	11,200,000
U.S Employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee stock purchase plan, Shares	5,000,000
Australian Employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee stock purchase plan, Shares	1,000,000
Deferred Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period of deferred stock units	after one year
Restricted Stock Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period of performance units	after three years of service
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period of performance units	Stock options generally vest in one-third increments over a period of three years or cliff vest after three years, and expire after 10 years from the date of grant
Performance unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period of performance units	3 years
Number of outstanding units vested	248,263
Aggregate intrinsic value	$ 12,400,000
Conversion price per share	$ 34.37

XML

Consolidated Statements of Cash Flows (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Cash Flows From Operating Activities
Net income	$ 946.3	$ 802.2	$ 463.0
Loss (income) from discontinued operations, net of income taxes	64.2	24.4	(19.8)
Income from continuing operations, net of income taxes	1,010.5	826.6	443.2
Adjustments to reconcile income from continuing operations, net of income taxes to net cash provided by operating activities:
Depreciation, depletion and amortization	482.2	437.1	400.5
Deferred income taxes	180.6	70.7	135.2
Share-based compensation	43.9	41.1	38.8
Net gain on disposal or exchange of assets	(76.9)	(30.0)	(23.2)
Loss from equity affiliates	19.2	1.7	69.1
Changes in current assets and liabilities:
Accounts receivable	(221.0)	(149.4)	102.5
Change in receivable from accounts receivable securitization program	0	(104.6)	(20.4)
Inventories	(50.4)	(8.5)	(46.8)
Net assets from coal trading activities	172.4	(109.6)	70.9
Other current assets	(27.4)	(28.5)	(1.9)
Accounts payable and accrued expenses	83.3	222.9	(120.4)
Asset retirement obligations	30.9	31.2	27.5
Workers' compensation obligations	10.4	(8.9)	3.0
Accrued postretirement benefit costs	35.4	23.1	7.2
Pension costs	31.1	23.3	3.3
Contributions to pension plans	(46.7)	(112.6)	(38.7)
Other, net	(19.4)	(8.9)	(4.9)
Net cash provided by continuing operations	1,658.1	1,116.7	1,044.9
Net cash (used in) provided by discontinued operations	(24.9)	(29.6)	5.3
Net cash provided by operating activities	1,633.2	1,087.1	1,050.2
Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development	(846.9)	(547.9)	(383.4)
Investment in Prairie State Energy Campus	(36.2)	(76.0)	(56.8)
Proceeds from disposal of assets, net of notes receivable	40.1	19.2	53.9
Investments in equity affiliates and joint ventures	(39.7)	(18.8)	(15.0)
Proceeds from sales of debt and equity securities	104.6	12.4	0
Purchases of debt and equity securities	(147.7)	(74.6)	0
Purchases of short-term investments	(100.0)	0	0
Maturity of short-term investments	100.0	0	0
Acquisition of Macarthur Coal Limited, net of cash acquired	(2,756.7)	0	0
Contributions to joint ventures	(145.4)	0	0
Distributions from joint ventures	128.6	0	0
Repayment of loans from related parties	331.7	0	0
Advances to related parties	(371.3)	0	0
Other, net	(6.6)	(8.8)	(6.1)
Net cash used in continuing operations	(3,745.5)	(694.5)	(407.4)
Net cash (used in) provided by discontinued operations	(62.3)	(9.1)	0.9
Net cash used in investing activities	(3,807.8)	(703.6)	(406.5)
Cash Flows From Financing Activities
Proceeds from long-term debt	4,101.4	1,150.0	0
Acquisition of noncontrolling interests	(1,994.8)	0	0
Payments of long-term debt	(263.9)	(1,167.3)	(37.1)
Dividends paid	(92.1)	(79.4)	(66.8)
Repurchase of employee common stock relinquished for tax withholding	(18.7)	(13.5)	(2.3)
Payment of debt issuance costs	(61.5)	(32.2)	0
Excess tax benefits related to share-based compensation	8.1	51.0	0
Other, net	0	14.3	1.6
Net cash provided by (used in) financing activities	1,678.5	(77.1)	(104.6)
Net change in cash and cash equivalents	(496.1)	306.4	539.1
Cash and cash equivalents at beginning of year	1,295.2	988.8	449.7
Cash and cash equivalents at end of year	$ 799.1	$ 1,295.2	$ 988.8

XML

Postretirement Health Care and Life Insurance Benefits (Details 3) (Postretirement Health Care and Life Insurance Benefits [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Postretirement Health Care and Life Insurance Benefits [Member]
Weighted average assumptions used to determine benefit obligations
Discount rate	5.05%	5.81%
Rate of compensation increase		3.50%
Measurement date	Dec. 31, 2011	Dec. 31, 2010
Weighted-average assumptions used to determine net periodic benefit cost
Discount rate	5.81%	6.14%	6.85%
Rate of compensation increase	3.50%	3.50%	3.50%
Measurement date	December 31, 2010	December 31, 2009	December 31, 2008
Assumed health care cost trend rate
Health care cost trend rate assumed for next year	9.00%	9.00%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	5.00%	5.00%
Year that the rate reaches the ultimate trend rate	2018	2017
Assumed health care cost trend rates, One percentage point increase
One Percentage-Point Increase Effect on total service and interest cost components	$ 8.2
One Percentage-Point Decrease Effect on total service and interest cost component	(6.9)
One Percentage-Point Increase Effect on total postretirement benefit obligation	121.8
One Percentage-Point Decrease Effect on total postretirement benefit obligation	$ (104.6)

XML

Summary of Significant Accounting Policies Discussion (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Equity method investments
Book Value	$ 526.6	$ 2.7
Income (Loss) from Equity Affiliates	(19.2)	(1.7)	(69.1)
Interest In Middlemount Coal Pty Limited [Member]
Equity method investments
Book Value	449.7	0
Income (Loss) from Equity Affiliates	(7.3)	0	0
Monto Coal Pty Limited [Member]
Equity method investments
Book Value	73.1	0
Income (Loss) from Equity Affiliates	0	0	0
Interest In Carbones Del Guasare [Member]
Schedule of Equity Method Investments [Line Items]
Impairment loss related to interest in Carbones del Guasare			34.7
Equity method investments
Book Value	0	0
Income (Loss) from Equity Affiliates	0	0	(54.6)
Interest In Peabody-Winsway Resources B.V. [Member]
Equity method investments
Book Value	0	0
Income (Loss) from Equity Affiliates	(3.4)	5.4	(8.2)
Other Equity Method Investments [Member]
Equity method investments
Book Value	3.8	2.7
Income (Loss) from Equity Affiliates	$ (8.5)	$ (7.1)	$ (6.3)

XML

Pension and Savings Plans (Details 2) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Change in benefit obligation:
Fair value of plan assets at end of period	$ 769.6	$ 771.6
Pension Plans, Defined Benefit [Member]
Change in benefit obligation:
Projected benefit obligation at beginning of period	881.0	844.9
Service cost	1.7	1.5	1.4
Interest cost	49.8	50.5	51.3
Benefits paid	(52.8)	(50.4)
Actuarial loss	83.9	34.5
Projected benefit obligation at end of period	963.6	881.0	844.9
Fair value of plan assets at beginning of period	771.6	629.6
Actual return on plan assets	4.1	79.8
Employer contributions	46.7	112.6
Benefits paid	(52.8)	(50.4)
Fair value of plan assets at end of period	769.6	771.6	629.6
Funded status at end of year	(194.0)	(109.4)
Amounts recognized in the consolidated balance sheets:
Current obligation (included in Accounts payable and accrued expenses)	(1.7)	(1.8)
Noncurrent obligation (included in Other noncurrent liabilities)	(192.3)	(107.6)
Net amount recognized	$ (194.0)	$ (109.4)

XML

Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2011

Valuation and Qualifying Accounts [Abstract]

VALUATION AND QUALIFYING ACCOUNTS

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

Description	Balance at Beginning of Period		Charged to Costs and Expenses			Deductions(1)			Other				Balance at End of Period
	(Dollars in millions)
Year Ended December 31, 2011
Reserves deducted from asset accounts:
Advance royalty recoupment reserve	$	19.9	$	1.8		$	(0.1	)	$	(0.3	)	(2)	$	21.3
Reserve for materials and supplies	6.2		3.7			(3.4		)	—				6.5
Allowance for doubtful accounts	30.3		(3.7		)	(0.4		)	(9.2		)	(3)	17.0
Year Ended December 31, 2010
Reserves deducted from asset accounts:
Advance royalty recoupment reserve	$	17.2	$	1.9		$	(0.2	)	$	1.0		(2)	$	19.9
Reserve for materials and supplies	6.2		0.9			(0.9		)	—				6.2
Allowance for doubtful accounts	18.3		26.7			(6.9		)	(7.8		)	(3)	30.3
Year Ended December 31, 2009
Reserves deducted from asset accounts:
Advance royalty recoupment reserve	$	17.2	$	1.6		$	(2.2	)	$	0.6		(2)	$	17.2
Reserve for materials and supplies	4.9		3.6			(2.3		)	—				6.2
Allowance for doubtful accounts	24.8		7.7			(3.6		)	(10.6		)	(3)	18.3

⁽¹⁾  Reserves utilized, unless otherwise indicated.

⁽²⁾  Balances transferred (to) from other accounts or reserves recorded as part of a property transaction or acquisition.

⁽³⁾  Reflects subsequent recovery of amounts previously reserved.

XML

Inventories (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Inventories
Materials and supplies	$ 124.9	$ 94.5
Raw coal	95.0	55.4
Saleable coal	226.4	177.3
Total	$ 446.3	$ 327.2

XML

Postretirement Health Care and Life Insurance Benefits

12 Months Ended

Dec. 31, 2011

Postretirement Health Care and LIfe Insurance Benefits [Abstract]

Postretirement Health Care and Life Insurance Benefits

Postretirement Health Care and Life Insurance Benefits

The Company currently provides health care and life insurance benefits to qualifying salaried and hourly retirees and their dependents from benefit plans established by the Company.  Plan coverage for health benefits is provided to future hourly and salaried retirees in accordance with the applicable plan document.  Life insurance benefits are provided to future hourly retirees in accordance with the applicable labor agreement.

Net periodic postretirement benefit cost included the following components:

	Year Ended December 31,
	2011		2010		2009
	(Dollars in millions)
Service cost for benefits earned	$	13.9	$	12.9	$	10.5
Interest cost on accumulated postretirement benefit obligation	57.9		58.2		55.2
Amortization of prior service cost	2.8		2.6		1.5
Amortization of actuarial loss	26.9		24.9		14.5
Net periodic postretirement benefit cost	$	101.5	$	98.6	$	81.7

The following includes amounts recognized in accumulated other comprehensive loss:

	Year Ended December 31,
	2011			2010			2009
	(Dollars in millions)
Net actuarial loss arising during year	$	86.0		$	45.3		$	165.2
Prior service cost arising during year	(1.4		)	7.9			(10.5		)
Amortization:
Actuarial loss	(26.9		)	(24.9		)	(14.5		)
Prior service cost	(2.8		)	(2.6		)	(1.5		)
Total recognized in other comprehensive loss	54.9			25.7			138.7
Net periodic postretirement benefit cost	101.5			98.6			81.7
Total recognized in net periodic postretirement benefit cost and other comprehensive loss	$	156.4		$	124.3		$	220.4

The Company amortizes actuarial gain and loss using a 0% corridor with an amortization period that covers the average future working lifetime of active employees (11.70 years and 12.06 years at January 1, 2012 and 2011, respectively). The estimated net actuarial loss and prior service cost that will be amortized from accumulated other comprehensive loss into net periodic postretirement benefit cost during the year ended December 31, 2012 are $32.8 million and $2.5 million, respectively.

The following table sets forth the plan’s funded status reconciled with the amounts shown in the consolidated balance sheets:

	December 31,
	2011			2010
	(Dollars in millions)
Change in benefit obligation:
Accumulated postretirement benefit obligation at beginning of period	$	1,031.2		$	982.2
Service cost	13.9			12.9
Interest cost	57.9			58.2
Participant contributions	1.9			2.1
Plan amendments(1)	(1.4		)	7.9
Benefits paid	(68.0		)	(77.4		)
Actuarial loss	86.0			45.3
Accumulated postretirement benefit obligation at end of period	1,121.5			1,031.2
Change in plan assets:
Fair value of plan assets at beginning of period	—			—
Employer contributions	66.1			75.3
Participant contributions	1.9			2.1
Benefits paid and administrative fees (net of Medicare Part D reimbursements)	(68.0		)	(77.4		)
Fair value of plan assets at end of period	—			—
Funded status at end of year	(1,121.5		)	(1,031.2		)
Less current portion (included in Accounts payable and accrued expenses)	68.4			67.3
Noncurrent obligation (included in Accrued postretirement benefit costs)	$	(1,053.1	)	$	(963.9	)

⁽¹⁾  Effective January 1, 2011, certain plans were modified to ensure consistency of benefits across the Company, the impact of which is reflected in the December 31, 2010 figures above.

The weighted-average assumptions used to determine the benefit obligations as of the end of each year were as follows:

	December 31,
	2011		2010
Discount rate	5.05	%	5.81	%
Rate of compensation increase	N/A		3.50	%
Measurement date	December 31, 2011		December 31, 2010

The weighted-average assumptions used to determine net periodic benefit cost during each year were as follows:

	Year Ended December 31,
	2011		2010		2009
Discount rate	5.81	%	6.14	%	6.85	%
Rate of compensation increase	3.50	%	3.50	%	3.50	%
Measurement date	December 31, 2010		December 31, 2009		December 31, 2008

The following presents information about the assumed health care cost trend rate:

	Year Ended December 31,
	2011		2010
Health care cost trend rate assumed for next year	9.00	%	9.00	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	5.00	%	5.00	%
Year that the rate reaches the ultimate trend rate	2018		2017

Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. A one-percentage-point change in the assumed health care cost trend would have the following effects:

	One Percentage- Point Increase		One Percentage- Point Decrease
	(Dollars in millions)
Effect on total service and interest cost components	$	8.2	$	(6.9	)
Effect on total postretirement benefit obligation	$	121.8	$	(104.6	)

Plan Assets

The Company’s postretirement benefit plans are unfunded.

Estimated Future Benefit Payments

The following benefit payments (net of retiree contributions), which reflect expected future service, as appropriate, are expected to be paid by the Company:

	Postretirement
	Benefits
	(Dollars in millions)
2012	$	68.4
2013	72.9
2014	75.6
2015	77.8
2016	79.9
Years 2017-2021	410.3

XML

Summary of Significant Accounting Policies Discussion (Policies)

12 Months Ended

Dec. 31, 2011

Accounting Policies [Abstract]

Basis of Presentation

The consolidated financial statements include the accounts of Peabody Energy Corporation (the Company) and its affiliates. All intercompany transactions, profits and balances have been eliminated in consolidation.

Description of Business

The Company is engaged in the mining of thermal coal for sale primarily to electric utilities and metallurgical coal for sale to industrial customers. The Company’s mining operations are located in the United States (U.S.) and Australia, and include equity-affiliate mining operations in Australia and Venezuela. The Company also markets, brokers coal sales of other coal producers both as principal and agent, and trades coal, freight and freight-related contracts. The Company’s other energy related commercial activities include participating in the development of a mine-mouth coal-fueled generating plant, the management of its coal reserve and real estate holdings, and the development of Btu Conversion and clean coal technologies.

Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented

In June 2011, the Financial Accounting Standards Board (FASB) issued guidance eliminating the option to present the components of other comprehensive income as part of the statement of changes in stockholders’ equity. Instead, an entity will be required to present the components of net income, the components of other comprehensive income and the total of comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The guidance will become effective for interim and annual periods beginning after December 15, 2011 (January 1, 2012 for the Company), with the exception of disclosing reclassifications of items out of accumulated other comprehensive income, which is effective for interim and annual periods beginning after December 15, 2012 (January 1, 2013 for the Company). The Company has reflected the new presentation in its consolidated statements of comprehensive income with no impact on its results of operations, financial condition or cash flows.

In December 2010, the FASB issued guidance on accounting for business combinations that clarified a public entity’s disclosure requirements for pro forma presentation of revenue and earnings. If comparative statements are presented, the public entity should disclose revenue and earnings of the combined entity as though the business combination occurred as of the beginning of the comparable prior annual reporting period only. The guidance also requires the supplemental pro forma disclosures to include a description of the nature and amount of material nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. The guidance was effective for business combinations for which the acquisition date was on or after the beginning of the first annual reporting period that began on or after December 15, 2010 (January 1, 2011 for the Company). The guidance impacted the Company’s disclosures with no impact on the Company’s results of operations, financial condition or cash flows.

In July 2010, the FASB issued accounting guidance to improve disclosures about the credit quality of an entity's financing receivables and the reserves held against them. End of reporting period disclosures became effective for reporting periods ended on or after December 15, 2010. Disclosures about activity that occurred during a reporting period became effective for interim and annual periods that began on or after December 15, 2010. While the guidance impacted the Company's disclosures related to credit quality of financing receivables and the allowance for credit losses, the adoption of this guidance had no impact on its results of operations, financial condition or cash flows.

In January 2010, the FASB issued accounting guidance that required new fair value disclosures, including disclosures about significant transfers into and out of Level 1 and Level 2 fair value measurements and a description of the reasons for the transfers. In addition, the guidance required new disclosures regarding activity in Level 3 fair value measurements, including a gross basis reconciliation. The Company began complying with the new fair value disclosure requirements beginning January 1, 2010, except for the disclosure of activity within Level 3 fair value measurements, which became effective January 1, 2011. While the adoption of this guidance had an impact on the Company's disclosures, it did not affect the Company's results of operations, financial condition or cash flows. In May 2011, the FASB issued additional fair value measurement disclosure requirements that were intended to provide a consistent definition of fair value and ensure that the fair value measurement and disclosure requirements are similar between U.S. generally accepted accounting principles (GAAP) and International Financial Reporting Standards. That update required the categorization by level for financial instruments not measured at fair value but for which disclosure of fair value is required, disclosure of all transfers between Level 1 and Level 2, and additional disclosures for Level 3 measurements regarding the sensitivity of fair value to changes in unobservable inputs and any interrelationships between those inputs. The guidance will become effective for interim and annual periods beginning after December 15, 2011 (January 1, 2012 for the Company). The guidance issued in May 2011 will impact the Company's disclosures, but it is not expected to impact the Company's results of operations, financial condition or cash flows.

In June 2009, the FASB issued accounting guidance on consolidations which clarifies that the determination of whether a company is required to consolidate an entity is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly impact the entity’s economic performance. Also required is an ongoing reassessment of whether a company is the primary beneficiary of a variable interest entity, and additional disclosures about a company’s involvement in variable interest entities and any associated changes in risk exposure. The guidance became effective January 1, 2010, at which time there was no impact on the Company’s results of operations, financial condition or cash flows. The Company will continue monitoring and assessing its business ventures in accordance with the guidance.

In June 2009, the FASB issued guidance seeking to improve the relevance, representational faithfulness and comparability of the information a reporting entity provides in its financial statements about a transfer of financial assets; the effects of a transfer on its financial position, financial performance and cash flows; and a transferor’s continuing involvement, if any, in transferred financial assets. The guidance, which became effective January 1, 2010, had an impact on the Company’s disclosures for its accounts receivable securitization program, but did not affect the Company’s results of operations, financial condition or cash flows.

Sales and Other Revenues

Sales

The Company’s revenue from coal sales is realized and earned when risk of loss passes to the customer. Under the typical terms of the Company’s coal supply agreements, title and risk of loss transfer to the customer at the mine or port, where coal is loaded to the transportation source(s) that serves each of the Company’s mines. The Company incurs certain “add-on” taxes and fees on coal sales. Reported coal sales include taxes and fees charged by various federal and state governmental bodies and the freight charges on destination customer contracts.

Other Revenues

Other revenues include net revenues from coal trading activities as discussed in Note 7 and coal revenues that were derived from the Company’s mining operations and sold through the Company’s coal trading business. Also included are revenues from contract termination or restructuring payments, royalties related to coal lease agreements, sales agency commissions, farm income, property and facility rentals and generation development activities. Royalty income generally results from the lease or sublease of mineral rights to third parties, with payments based upon a percentage of the selling price or an amount per ton of coal produced.

Discontinued Operations and Assets Held for Sale

The Company classifies items within discontinued operations in the consolidated financial statements when the operations and cash flows of a particular component (defined as operations and cash flows that can be clearly distinguished, operationally and for financial reporting purposes, from the rest of the entity) of the Company have been (or will be) eliminated from the ongoing operations of the Company as a result of a disposal transaction, and the Company will no longer have any significant continuing involvement in the operations of that component. See Note 3 for additional details related to discontinued operations and assets held for sale.

Cash and Cash Equivalents

Cash and cash equivalents are stated at cost, which approximates fair value. Cash equivalents consist of highly liquid investments with original maturities of three months or less.

Inventories

Materials and supplies and coal inventory are valued at the lower of average cost or market. Raw coal represents coal stockpiles that may be sold in current condition or may be further processed prior to shipment to a customer. Coal inventory costs include labor, supplies, equipment, operating overhead and other related costs.

Property, Plant, Equipment and Mine Development

Property, plant, equipment and mine development are recorded at cost. Interest costs applicable to major asset additions are capitalized during the construction period. Capitalized interest in 2011, 2010 and 2009 was immaterial. Expenditures which extend the useful lives of existing plant and equipment assets are capitalized. Maintenance and repairs are charged to operating costs as incurred. Costs incurred to develop coal mines or to expand the capacity of operating mines are capitalized. Costs incurred to maintain current production capacity at a mine are charged to operating costs as incurred. Costs to acquire computer hardware and the development and/or purchase of software for internal use are capitalized and depreciated over the estimated useful lives.

Coal reserves are recorded at cost, or at fair value in the case of nonmonetary exchanges of reserves or business acquisitions. The net book value of coal reserves totaled $7.7 billion as of December 31, 2011 and $5.0 billion as of December 31, 2010. These coal reserves include mineral rights for leased coal interests and advance royalties that had a net book value of $6.4 billion as of December 31, 2011 and $3.7 billion as of December 31, 2010. The remaining net book value of coal reserves of $1.3 billion at December 31, 2011 and $1.3 billion at December 31, 2010 relates to coal reserves held by fee ownership. Amounts attributable to properties where the Company was not currently engaged in mining operations or leasing to third parties and, therefore, the coal reserves were not currently being depleted was $2.7 billion as of December 31, 2011 and $1.3 billion as of December 31, 2010.

Depletion of coal reserves and amortization of advance royalties is computed using the units-of-production method utilizing only proven and probable reserves (as adjusted for recoverability factors) in the depletion base. Mine development costs are principally amortized over the estimated lives of the mines using the straight-line method. Depreciation of plant and equipment is computed using the straight-line method over the shorter of the asset's estimated useful life or the life of the mine. The estimated useful lives by category of assets are as follows:

	Years
Building and improvements	10 to 20
Plant and equipment	3 to 33
Leasehold improvements	Life of Lease

Depreciation and depletion expense associated with property, plant, equipment and mine development was $473.7 million, $424.8 million and $388.0 million for December 31, 2011, 2010, and 2009, respectively.

Investments in Joint Ventures

The Company accounts for its investments in less than majority owned corporate joint ventures under either the equity or cost method. The Company applies the equity method to investments in joint ventures when it has the ability to exercise significant influence over the operating and financial policies of the joint venture. Investments accounted for under the equity method are initially recorded at cost, and any difference between the cost of the Company’s investment and the underlying equity in the net assets of the joint venture at the investment date is amortized over the lives of the related assets that gave rise to the difference. The Company’s pro rata share of earnings from joint ventures and basis difference amortization is reported in the consolidated statements of income in “Loss from equity affiliates.” Included in the Company’s equity method investments is its joint venture interest in the Middlemount Mine in Australia, which was acquired as a part of the acquisition of Macarthur Coal Limited (see Note 2 for additional details). The Company also has an interest in Carbones del Guasare, which owns and operates the Paso Diablo Mine in Venezuela. In 2009, the Company recognized an impairment loss of $34.7 million million related to its interest in Carbones del Guasare based on the joint venture’s deteriorating operating results, ongoing cash flow issues resulting in no dividend payments since January 2008, the Company’s expectations concerning ongoing operating and cash flow issues for the joint venture and uncertainty impacting recoverability of this investment.

Asset Retirement Obligations and Environmental Liabilities

Asset Retirement Obligations

The Company’s asset retirement obligation (ARO) liabilities primarily consist of spending estimates for surface land reclamation and support facilities at both surface and underground mines in accordance with applicable reclamation laws in the U.S. and Australia as defined by each mining permit.

The Company estimates its ARO liabilities for final reclamation and mine closure based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at the credit-adjusted, risk-free rate. The Company records an ARO asset associated with the discounted liability for final reclamation and mine closure. The obligation and corresponding asset are recognized in the period in which the liability is incurred. The ARO asset is amortized on the units-of-production method over its expected life and the ARO liability is accreted to the projected spending date. As changes in estimates occur (such as mine plan revisions, changes in estimated costs or changes in timing of the performance of reclamation activities), the revisions to the obligation and asset are recognized at the appropriate historical credit-adjusted, risk-free rate. The Company also recognizes an obligation for contemporaneous reclamation liabilities incurred as a result of surface mining. Contemporaneous reclamation consists primarily of grading, topsoil replacement and re-vegetation of backfilled pit areas.

Environmental Liabilities

Accruals for other environmental matters are recorded in operating expenses when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Accrued liabilities are exclusive of claims against third parties and are not discounted. In general, costs related to environmental remediation are charged to expense. The current portion of these accruals is included in “Accounts payables and accrued expenses” and the long-term portion is included in “Other noncurrent liabilities” in the consolidated balance sheets.

Income Taxes

Income taxes are accounted for using a balance sheet approach. The Company accounts for deferred income taxes by applying statutory tax rates in effect at the reporting date of the balance sheet to differences between the book and tax basis of assets and liabilities. A valuation allowance is established if it is “more likely than not” that the related tax benefits will not be realized. In determining the appropriate valuation allowance, the Company considers projected realization of tax benefits based on expected levels of future taxable income, available tax planning strategies and the overall deferred tax position.

The Company recognizes the tax benefit from uncertain tax positions only if it is “more likely than not” the tax position will be sustained on examination by the taxing authorities. The tax benefits recognized from such a position are measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. To the extent the Company’s assessment of such tax positions changes, the change in estimate will be recorded in the period in which the determination is made. Tax-related interest and penalties are classified as a component of income tax expense.

Postretirement Health Care and Life Insurance Benefits and Pension Plans

Postretirement Health Care and Life Insurance Benefits

The Company accounts for postretirement benefits other than pensions by accruing the costs of benefits to be provided over the employees’ period of active service. These costs are determined on an actuarial basis. The Company’s consolidated balance sheets reflect the funded status of postretirement benefits. See Note 14 for information related to postretirement benefits.

Pension Plans

The Company sponsors non-contributory defined benefit pension plans accounted for by accruing the cost to provide the benefits over the employees’ period of active service. These costs are determined on an actuarial basis. The Company’s consolidated balance sheets reflect the funded status of the defined benefit pension plans. See Note 15 for information related to pension plans.

Derivatives

The Company recognizes at fair value all derivatives as assets or liabilities in the consolidated balance sheets. Gains or losses from derivative financial instruments designated as fair value hedges are recognized immediately in earnings, along with the offsetting gain or loss related to the underlying hedged item.

Gains or losses on derivative financial instruments designated as cash flow hedges are recorded as a separate component of stockholders’ equity until the hedged transaction occurs (or until hedge ineffectiveness is determined), at which time gains or losses are reclassified to earnings in conjunction with the recognition of the underlying hedged item. To the extent that the periodic changes in the fair value of the derivatives exceed the changes in the hedged item, the ineffective portion of the periodic non-cash changes are recorded in earnings in the period of the change. If the hedge ceases to qualify for hedge accounting, the Company prospectively recognizes the mark-to-market movements in earnings in the period of the change. The potential for hedge ineffectiveness is present in the design of the Company’s cash flow hedge relationships and is discussed in detail in Notes 6 and 7.

Non-derivative contracts and derivative contracts for which the Company has elected to apply the normal purchases and normal sales exception are accounted for on an accrual basis.

Business Combinations

The Company accounts for business combinations using the purchase method of accounting. The purchase method requires the Company to determine the fair value of all acquired assets, including identifiable intangible assets, and all assumed liabilities. The total cost of acquisitions is allocated to the underlying identifiable net assets, based on their respective estimated fair values. Determining the fair value of assets acquired and liabilities assumed requires management's judgment, and the utilization of independent valuation experts, and often involves the use of significant estimates and assumptions, including assumptions with respect to future cash inflows and outflows, discount rates, and asset lives, among other items.

Use of Estimates in the Preparation of the Consolidated Financial Statements

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Impairment of Long-Lived Assets

The Company records impairment losses on long-lived assets used in operations when events and circumstances indicate that assets might be impaired and the undiscounted cash flows estimated to be generated by those assets under various assumptions are less than their carrying amounts. Impairment losses are measured by comparing the estimated fair value of the impaired asset to its carrying amount. There were no impairment losses recorded during the years ended December 31, 2011, 2010 or 2009.

Fair Value

For assets and liabilities that are recognized or disclosed at fair value in the consolidated financial statements, the Company defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The Company’s asset and liability derivative positions are offset on a counterparty-by-counterparty basis if the contractual agreement provides for the net settlement of contracts with the counterparty in the event of default or termination of any one contract.

Foreign Currency

Substantially all of the Company’s foreign subsidiaries utilize the U.S. dollar as their functional currency. As such, monetary assets and liabilities are remeasured at year-end exchange rates while non-monetary items are remeasured at historical rates. Income and expense accounts are remeasured at the average rates in effect during the year, except for those expenses related to balance sheet amounts that are remeasured at historical exchange rates. Gains and losses from foreign currency remeasurement related to tax balances are included as a component of "Income tax provision" while all other remeasurement gains and losses are included in "Operating costs and expenses." The total foreign currency remeasurement losses for the years ended December 31, 2011, 2010 and 2009 were $0.9 million, $38.5 million and $55.4 million, respectively.

Share Based Compensation

The Company accounts for share-based compensation at the grant date fair value of awards and recognizes the related expense over the vesting period of the award.

Exploration and Drilling Costs

Exploration expenditures are charged to operating costs as incurred, including costs related to drilling and study costs incurred to convert or upgrade mineral resources to reserves.

Advance Stripping Costs

Pre-production:  At existing surface operations, additional pits may be added to increase production capacity in order to meet customer requirements. These expansions may require significant capital to purchase additional equipment, expand the workforce, build or improve existing haul roads and create the initial pre-production box cut to remove overburden (i.e., advance stripping costs) for new pits at existing operations. If these pits operate in a separate and distinct area of the mine, the costs associated with initially uncovering coal (i.e., advance stripping costs incurred for the initial box cuts) for production are capitalized and amortized over the life of the developed pit consistent with coal industry practices.

Post-production:  Advance stripping costs related to post-production are expensed as incurred. Where new pits are routinely developed as part of a contiguous mining sequence, the Company expenses such costs as incurred. The development of a contiguous pit typically reflects the planned progression of an existing pit, thus maintaining production levels from the same mining area utilizing the same employee group and equipment.

XML

Pension and Savings Plans (Details 1) (Pension Plans, Defined Benefit [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Pension Plans, Defined Benefit [Member]
Amounts recognized in accumulated other comprehensive loss
Net actuarial loss arising during year	$ 144.2	$ 13.1	$ 46.1
Amortizations:
Actuarial gain (loss)	(30.1)	(21.9)	(1.9)
Prior service cost	(1.0)	(1.4)	(1.4)
Total recognized in other comprehensive loss	113.1	(10.2)	42.8
Net periodic pension (benefit) cost	18.2	17.0	(4.9)
Total recognized in net periodic benefit cost and other comprehensive loss	$ 131.3	$ 6.8	$ 37.9

XML

Supplemental Guarantor/Non-Guarantor Financial Information (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Unaudited Supplemental Condensed Consolidated Statements of Operations
Total revenues	$ 2,253.6	$ 1,997.2	$ 1,980.5	$ 1,743.1	$ 1,792.7	$ 1,826.7	$ 1,629.9	$ 1,490.6	$ 7,974.4	$ 6,739.9	$ 5,847.0
Costs and expenses
Operating costs and expenses									5,550.0	4,697.3	4,339.2
Depreciation, depletion and amortization									482.2	437.1	400.5
Asset retirement obligation expense									53.1	47.2	39.9
Selling and administrative expenses									268.2	232.2	199.1
Acquisition costs related to Macarthur Coal Limited	76.1	9.1							85.2	0	0
Other operating (income) loss:
Net (gain) loss on disposal or exchange of assets									(76.9)	(30.0)	(23.2)
(Income) loss from equity affiliates									19.2	1.7	69.1
Interest expense									238.6	222.0	201.1
Interest income									(18.9)	(9.6)	(8.1)
Unrealized (gain) loss on derivatives									0
Income from continuing operations before income taxes									1,373.7	1,142.0	629.4
Income tax provision (benefit)									363.2	315.4	186.2
Income from continuing operations, net of income taxes	222.5	285.6	307.8	194.6	223.8	239.3	215.7	147.8	1,010.5	826.6	443.2
Income (loss) from discontinued operations, net of income taxes									(64.2)	(24.4)	19.8
Net income	194.0	281.4	292.2	178.7	215.0	236.3	214.2	136.7	946.3	802.2	463.0
Less: Net (loss) income attributable to noncontrolling interests									(11.4)	28.2	14.8
Net income attributable to common stockholders	222.4	274.0	284.8	176.5	210.0	224.1	206.2	133.7	957.7	774.0	448.2
Parent Company [Member]
Unaudited Supplemental Condensed Consolidated Statements of Operations
Total revenues									0	0	0
Costs and expenses
Operating costs and expenses									(386.3)	(145.1)	104.4
Depreciation, depletion and amortization									0	0	0
Asset retirement obligation expense									0	0	0
Selling and administrative expenses									34.0	31.6	29.3
Acquisition costs related to Macarthur Coal Limited									32.8
Other operating (income) loss:
Net (gain) loss on disposal or exchange of assets									0	0	0
(Income) loss from equity affiliates									(881.5)	(838.4)	(620.9)
Interest expense									243.1	219.7	198.4
Interest income									(50.9)	(18.8)	(15.3)
Unrealized (gain) loss on derivatives									0
Income from continuing operations before income taxes									1,008.8	751.0	304.1
Income tax provision (benefit)									46.5	(24.2)	(122.3)
Income from continuing operations, net of income taxes									962.3	775.2	426.4
Income (loss) from discontinued operations, net of income taxes									(4.6)	(1.2)	21.8
Net income									957.7	774.0	448.2
Less: Net (loss) income attributable to noncontrolling interests									0	0	0
Net income attributable to common stockholders									957.7	774.0	448.2
Guarantor Subsidiaries [Member]
Unaudited Supplemental Condensed Consolidated Statements of Operations
Total revenues									4,758.4	3,596.1	4,283.9
Costs and expenses
Operating costs and expenses									3,598.6	2,472.7	3,250.4
Depreciation, depletion and amortization									297.4	294.1	282.9
Asset retirement obligation expense									36.2	31.9	33.1
Selling and administrative expenses									215.0	194.3	164.2
Acquisition costs related to Macarthur Coal Limited									31.2
Other operating (income) loss:
Net (gain) loss on disposal or exchange of assets									(73.2)	(34.5)	(17.1)
(Income) loss from equity affiliates									8.6	7.1	6.3
Interest expense									47.3	52.7	52.5
Interest income									(31.1)	(21.8)	(28.9)
Unrealized (gain) loss on derivatives									(1.3)
Income from continuing operations before income taxes									629.7	599.6	540.5
Income tax provision (benefit)									172.0	183.3	176.5
Income from continuing operations, net of income taxes									457.7	416.3	364.0
Income (loss) from discontinued operations, net of income taxes									(3.1)	(23.2)	12.0
Net income									454.6	393.1	376.0
Less: Net (loss) income attributable to noncontrolling interests									0	0	0
Net income attributable to common stockholders									454.6	393.1	376.0
Non-Guarantor Subsidiaries [Member]
Unaudited Supplemental Condensed Consolidated Statements of Operations
Total revenues									3,509.4	3,916.9	2,312.5
Costs and expenses
Operating costs and expenses									2,631.1	3,142.8	1,733.8
Depreciation, depletion and amortization									184.8	143.0	117.6
Asset retirement obligation expense									16.9	15.3	6.8
Selling and administrative expenses									19.2	6.3	5.6
Acquisition costs related to Macarthur Coal Limited									21.2
Other operating (income) loss:
Net (gain) loss on disposal or exchange of assets									(3.7)	4.5	(6.1)
(Income) loss from equity affiliates									10.6	6.0	62.8
Interest expense									67.2	17.9	16.2
Interest income									(55.9)	(37.3)	(29.9)
Unrealized (gain) loss on derivatives									1.3
Income from continuing operations before income taxes									616.7	618.4	405.7
Income tax provision (benefit)									144.7	156.3	132.0
Income from continuing operations, net of income taxes									472.0	462.1	273.7
Income (loss) from discontinued operations, net of income taxes									(56.5)	0	(14.0)
Net income									415.5	462.1	259.7
Less: Net (loss) income attributable to noncontrolling interests									(11.4)	28.2	14.8
Net income attributable to common stockholders									426.9	433.9	244.9
Eliminations [Member]
Unaudited Supplemental Condensed Consolidated Statements of Operations
Total revenues									(293.4)	(773.1)	(749.4)
Costs and expenses
Operating costs and expenses									(293.4)	(773.1)	(749.4)
Depreciation, depletion and amortization									0	0	0
Asset retirement obligation expense									0	0	0
Selling and administrative expenses									0	0	0
Acquisition costs related to Macarthur Coal Limited									0
Other operating (income) loss:
Net (gain) loss on disposal or exchange of assets									0	0	0
(Income) loss from equity affiliates									881.5	827.0	620.9
Interest expense									(119.0)	(68.3)	(66.0)
Interest income									119.0	68.3	66.0
Unrealized (gain) loss on derivatives									0
Income from continuing operations before income taxes									(881.5)	(827.0)	(620.9)
Income tax provision (benefit)									0	0	0
Income from continuing operations, net of income taxes									(881.5)	(827.0)	(620.9)
Income (loss) from discontinued operations, net of income taxes									0	0	0
Net income									(881.5)	(827.0)	(620.9)
Less: Net (loss) income attributable to noncontrolling interests									0	0	0
Net income attributable to common stockholders									$ (881.5)	$ (827.0)	$ (620.9)

XML

Stockholders' Equity

12 Months Ended

Dec. 31, 2011

Stockholders' Equity Attributable to Parent [Abstract]

Stockholders' Equity

Stockholders’ Equity

Common Stock

The Company has 800.0 million authorized shares of $0.01 par value common stock. Holders of common stock are entitled to one vote per share on all matters to be voted upon by the stockholders and vote together, as one class, with the holders of the Company’s Series A Junior Participating Preferred Stock, if any such shares were issued and outstanding. The holders of common stock do not have cumulative voting rights in the election of directors. Holders of common stock are entitled to ratably receive dividends if, as and when dividends are declared from time to time by the Company’s Board of Directors out of funds legally available for that purpose, after payment of dividends required to be paid on outstanding preferred stock or series common stock, as described below. Upon liquidation, dissolution or winding up, any business combination or a sale or disposition of all or substantially all of the assets, the holders of common stock are entitled to ratably receive the assets available for distribution to the stockholders after payment of liabilities and accrued but unpaid dividends and liquidation preferences on any outstanding preferred stock or series common stock. The common stock has no preemptive or conversion rights and is not subject to further calls or assessment by the Company. There are no redemption or sinking fund provisions applicable to the common stock.

The following table summarizes common stock activity from January 1, 2009 to December 31, 2011:

	2011		2010		2009
Shares outstanding at the beginning of the year	270.2		268.2		266.6
Stock options exercised	0.3		1.5		0.5
Stock grants to employees	0.7		0.6		0.8
Employee stock purchases	0.2		0.2		0.4
Shares relinquished	(0.3	)	(0.3	)	(0.1	)
Shares outstanding at the end of the year	271.1		270.2		268.2

Preferred Stock and Series Common Stock

The Board of Directors is authorized to issue up to 10.0 million shares of preferred stock and up to 40.0 million shares of series common stock, both with a $0.01 per share par value. The Board of Directors can determine the terms and rights of each series, whether dividends (if any) will be cumulative or non-cumulative and the dividend rate of the series, redemption or sinking fund provisions, conversion terms, prices and rates, and amounts payable on shares of the series in the event of any voluntary or involuntary liquidation, dissolution or winding up of the affairs of the Company. The Board of Directors may also determine restrictions on the issuance of shares of the same series or of any other class or series, and the voting rights (if any) of the holders of the series. There were no outstanding shares of preferred stock or series common stock as of December 31, 2011.

Perpetual Preferred Stock

As discussed in Note 11, the Company had $732.5 million aggregate principal amount of Debentures outstanding as of December 31, 2011. Perpetual preferred stock issued upon a conversion of the Debentures will be fully paid and non-assessable, and holders will have no preemptive or preferential right to purchase any of the Company’s other securities. The perpetual preferred stock has a liquidation preference of $1,000 per share, is not convertible and is redeemable at the Company’s option at any time at a cash redemption price per share equal to the liquidation preference plus any accumulated dividends. Holders are entitled to receive cumulative dividends at an annual rate of 3.0875% if and when declared by the Company’s Board of Directors. If the Company fails to pay dividends on the perpetual preferred stock for five years, or upon the occurrence of a mandatory trigger event, as defined in the certificate of designations governing the perpetual preferred stock, the Company generally must sell warrants or preferred stock with specified characteristics and use the funds from that sale to pay accumulated dividends after the payment in full of any deferred interest on the Debentures, subject to certain limitations. In the event of a mandatory trigger event, the Company may not declare dividends on the perpetual preferred stock other than those funded through the sale of warrants or preferred stock as described above. Any deferred interest on the Debentures at the time of notice of conversion will be reflected as accumulated dividends on the perpetual preferred stock at issuance. Additionally, holders of the perpetual preferred stock are entitled to elect two additional members to serve on the Company’s Board of Directors if (i) prior to any remarketing of the perpetual preferred stock, the Company fails to declare and pay dividends with respect to the perpetual stock for 10 consecutive years or (ii) after any successful remarketing or any final failed remarketing of the perpetual preferred stock, the Company fails to declare and pay six dividends thereon, whether or not consecutive. The perpetual preferred stock may be remarketed at the holder’s election after December 15, 2046 or earlier, upon the first occurrence of a change of control if the Company does not redeem the perpetual preferred stock. There were no outstanding shares of perpetual preferred stock as of December 31, 2011.

Preferred Share Purchase Rights Plan and Series A Junior Participating Preferred Stock

Each outstanding share of common stock, par value $0.01 per share, of the Company carries one preferred share purchase right (a Right). The Rights are governed by a plan that expires in August 2012.

The Rights have certain anti-takeover effects. The Rights will cause substantial dilution to a person or group that attempts to acquire the Company on terms not approved by the Company’s Board of Directors, except pursuant to any offer conditioned on a substantial number of Rights being acquired. The Rights should not interfere with any merger or other business combination approved by the Board of Directors since the Rights may be redeemed by the Company at a redemption price of $0.001 per Right prior to the time that a person or group has acquired beneficial ownership of 15% or more of the common stock of the Company. In addition, the Board of Directors is authorized to reduce the 15% threshold to not less than 10%.

Each Right entitles the holder to purchase one quarter of one-hundredth of a share of Series A Junior Participating Preferred Stock from the Company at an exercise price of $27.50, which in turn provides rights to receive the number of common stock shares having a market value of two times the exercise price of the Right. The Right is exercisable only if a person or group acquires 15% or more of the Company’s common stock. The Board of Directors is authorized to issue up to 1.5 million shares of Series A Junior Participating Preferred Stock. There were no outstanding shares of Series A Junior Participating Preferred Stock as of December 31, 2011.

Treasury Stock

Share repurchase program.  The Company has a share repurchase program for its common stock with an authorized amount of $1.0 billion in which repurchases may be made from time to time based on an evaluation of the Company’s outlook and general business conditions, as well as alternative investment and debt repayment options. The Company’s Chairman and Chief Executive Officer also has authority to direct the Company to repurchase up to $100.0 million of common stock outside the share repurchase program. The share repurchase program does not have an expiration date and may be discontinued at any time. Through December 31, 2011, the Company made repurchases of 7.7 million shares at a cost of $299.6 million ($199.8 million in 2008 and $99.8 million in 2006), leaving $700.4 million available under the share repurchase program.

Shares relinquished.  The Company allows employees to relinquish common stock to pay estimated taxes upon the payout of performance units that are settled in common stock and the vesting of restricted stock. The amount of common stock shares relinquished were 311,709 for the year ended December 31, 2011 and 268,308 for the year ended December 31, 2010. The value of the common stock tendered by employees was based upon the closing price on the dates of the respective transactions.

XML

Investments (Details Textuals) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Investments, Debt and Equity Securities [Abstract]
Short-term investments maturity period	greater than three months and up to one year
Long-term investments maturity period	greater than 12 months
Other than temporary losses on investments	$ 0
Held-to-maturity Securities	0	0
Investments (Textuals) [Abstract]
Fair Value of securities	29,400,000
Proceeds from Sale of Available-for-sale Securities	52,800,000
Realized gains from sale of available-for-sale securities	1,600,000
Securities in an unrealized loss position for greater than 12 months	$ 0

XML

Share-Based Compensation (Details 1) (USD $)	12 Months Ended
	Dec. 31, 2011
Summary of restricted stock award activity
Nonvested, Beginning of Period	1,894,299
Granted	618,124
Vested	(849,464)
Forfeited	(131,867)
Nonvested, End of Period	1,531,092
Weighted Average Grant-Date Fair Value, Beginning of Period	$ 39.32
Weighted Average Grant-Date Fair Value, Granted	$ 59.63
Weighted Average Grant Date Fair Value, Vested	$ 42.38
Weighted Average Grant Date Fair Value, Forfeited	$ 47.10
Weighted Average Grant-Date Fair Value, End of Period	$ 45.16

XML

Consolidated Statements of Changes in Stockholders' Equity (USD $) In Millions	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Treasury Stock [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Loss [Member]	Noncontrolling Interests [Member]
Beginning Balance at Dec. 31, 2008	$ 3,119.5	$ 2.8	$ 2,020.2	$ (318.8)	$ 1,802.4	$ (388.5)	$ 1.4
Net income	463.0				448.2		14.8
Increase in fair value of cash flow hedges, net of tax	319.8					319.8
Postretirement plans and workers' compensation obligations, net of tax	(114.8)					(114.8)
Dividends paid	(66.8)				(66.8)
Share-based compensation	38.8		38.8
Stock options exercised	3.6		3.6
Employee stock purchases	5.1		5.1
Repurchase of employee common stock relinquished for tax withholding	(2.3)			(2.3)
Distributions to noncontrolling interests	(10.0)						(10.0)
Ending Balance at Dec. 31, 2009	3,755.9	2.8	2,067.7	(321.1)	2,183.8	(183.5)	6.2
Net income	802.2				774.0		28.2
Increase in fair value of cash flow hedges, net of tax	127.5					127.5
Postretirement plans and workers' compensation obligations, net of tax	(11.9)					(11.9)
Dividends paid	(79.4)				(79.4)
Share-based compensation	41.1		41.1
Excess tax benefits related to share based compensation	51.0		51.0
Stock options exercised	16.4		16.4
Employee stock purchases	5.8		5.8
Repurchase of employee common stock relinquished for tax withholding	(13.5)			(13.5)
Distributions to noncontrolling interests	(5.8)						(5.8)
Ending Balance at Dec. 31, 2010	4,689.3	2.8	2,182.0	(334.6)	2,878.4	(67.9)	28.6
Net income	946.3				957.7		(11.4)
Net unrealized losses on available-for-sale securities, net of tax	(6.7)					(6.7)
Increase in fair value of cash flow hedges, net of tax	40.9					40.9
Postretirement plans and workers' compensation obligations, net of tax	(108.7)					(108.7)
Dividends paid	(92.1)				(92.1)
Share-based compensation	43.9		43.9
Excess tax benefits related to share based compensation	8.1		8.1
Stock options exercised	4.8		4.8
Employee stock purchases	6.3		6.3
Repurchase of employee common stock relinquished for tax withholding	(18.7)			(18.7)
Macarthur Coal Limited noncontrolling interest at control date	2,011.9						2,011.9
Acquisitions of noncontrolling interests	(1,994.8)		(11.1)				(1,983.7)
Distributions to noncontrolling interests	(15.9)						(15.9)
Contributions from noncontrolling interests	1.2						1.2
Ending Balance at Dec. 31, 2011	$ 5,515.8	$ 2.8	$ 2,234.0	$ (353.3)	$ 3,744.0	$ (142.4)	$ 30.7

XML

Consolidated Statements of Comprehensive Income (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Net income	$ 946.3	$ 802.2	$ 463.0
Net unrealized losses on available-for-sale securities (net of $3.9 tax benefit for 2011)
Unrealized holding losses on available-for-sale securities	(5.8)	0	0
Less: Reclassification for realized gains included in net income	(0.9)	0	0
Unrealized losses on available-for-sale securities	(6.7)	0	0
Unrealized gains on cash flow hedges (net of $6.2 tax benefit for 2011 and $129.5 and $220.9 tax provision for 2010 and 2009, respectively)
Increase in fair value of cash flow hedges, net of tax	291.9	229.9	235.2
Less: Reclassification for realized (gains) losses included in net income	(251.0)	(102.4)	84.6
Unrealized gains on cash flow hedges	40.9	127.5	319.8
Postretirement plans and workers' compensation obligations (net of $63.4, $2.1 and $71.8 tax benefit for 2011, 2010, and 2009, respectively)
Net actuarial loss for the period	(149.2)	(46.2)	(128.4)
Amortization of actuarial loss and prior service cost	40.5	34.3	13.6
Postretirement plan and worker's compensation obligations	(108.7)	(11.9)	(114.8)
Other comprehensive (loss) income	(74.5)	115.6	205.0
Comprehensive income	871.8	917.8	668.0
Less: Comprehensive (loss) income attributable to noncontrolling interests	(11.4)	28.2	14.8
Comprehensive income attributable to common stockholders	$ 883.2	$ 889.6	$ 653.2

XML

Income Taxes

12 Months Ended

Dec. 31, 2011

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

Income from continuing operations before income taxes consisted of the following:

	Year Ended December 31,
	2011		2010		2009
	(Dollars in millions)
U.S.	$	815.7	$	535.5	$	281.4
Non-U.S.	558.0		606.5		348.0
Total	$	1,373.7	$	1,142.0	$	629.4

Total income tax provision consisted of the following:

	Year Ended December 31,
	2011		2010		2009
	(Dollars in millions)
Current:
U.S. federal	$	103.4	$	113.9	$	(0.7	)
Non-U.S.	58.9		78.8		50.0
State	12.2		1.0		1.7
Total current	174.5		193.7		51.0
Deferred:
U.S. federal	138.0		47.9		56.0
Non-U.S.	42.8		68.1		78.5
State	7.9		5.7		0.7
Total deferred	188.7		121.7		135.2
Total provision	$	363.2	$	315.4	$	186.2

The following is a reconciliation of the expected statutory federal income tax provision to the Company’s actual income tax provision:

	Year Ended December 31,
	2011			2010			2009
	(Dollars in millions)
Expected income tax provision at federal statutory rate	$	480.8		$	399.7		$	220.3
Excess depletion	(70.8		)	(53.5		)	(44.0		)
Foreign earnings provision differential	(99.2		)	(124.5		)	(83.4		)
Foreign earnings repatriation	7.6			84.5			—
Remeasurement of foreign income tax accounts	(0.9		)	47.9			74.4
State income taxes, net of U.S. federal tax benefit	12.3			(4.8		)	3.4
General business tax credits	(17.8		)	(17.0		)	(12.2		)
Changes in valuation allowance	15.4			(28.7		)	17.3
Changes in tax reserves	14.7			—			5.9
Other, net	21.1			11.8			4.5
Total provision	$	363.2		$	315.4		$	186.2

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities consisted of the following:

	December 31,
	2011			2010
	(Dollars in millions)
Deferred tax assets:
Tax credits and loss carryforwards	$	432.8		$	425.2
Postretirement benefit obligations	485.4			427.7
Intangible tax asset and purchased contract rights	10.6			15.1
Accrued reclamation and mine closing liabilities	114.6			97.8
Accrued long-term workers’ compensation liabilities	15.6			15.5
Employee benefits	53.3			53.5
Hedge activities	—			30.6
Financial guarantee	18.5			18.8
Others	57.9			45.4
Total gross deferred tax assets	1,188.7			1,129.6
Deferred tax liabilities:
Property, plant, equipment and mine development, leased coal interests and advance royalties, principally due to differences in depreciation, depletion and asset writedowns	1,348.0			1,246.8
Unamortized discount on Convertible Junior Subordinated Debentures	132.5			135.5
Hedge activities	45.5			—
Investments and other assets	109.8			107.0
Total gross deferred tax liabilities	1,635.8			1,489.3
Valuation allowance	(79.8		)	(65.0		)
Net deferred tax liability	$	(526.9	)	$	(424.7	)
Deferred taxes are classified as follows:
Current deferred income taxes	$	27.3		$	120.4
Noncurrent deferred income taxes	(554.2		)	(545.1		)
Net deferred tax liability	$	(526.9	)	$	(424.7	)

The Company’s tax credits and loss carryforwards included alternative minimum tax (AMT), foreign tax and general business credits of $300.0 million, state net operating loss (NOL) carryforwards of $23.5 million and foreign loss carryforwards of $109.3 million as of December 31, 2011. The AMT credits, foreign NOL, and capital loss carryforwards have no expiration date. The foreign tax and general business credits begin to expire in 2020 and 2027, respectively. The state NOL carryforwards begin to expire in the year 2012. In assessing the near term use of NOLs and tax credits and corresponding valuation allowance adjustments, the Company evaluated the overall deferred tax position, available tax strategies and future taxable income. The $15.4 million change in the valuation allowance was due to an increase on foreign deferred tax assets. The remaining valuation allowance at December 31, 2011 of $79.8 million represents a reserve for state NOLs and certain foreign deferred tax assets.

Unrecognized Tax Benefits

The total amount of the net unrecognized tax benefits was $114.7 million ($119.6 million gross) at December 31, 2011 and was $107.9 million ($111.0 million gross) at December 31, 2010. The amount of the Company’s gross unrecognized tax benefits has increased by $8.6 million since January 1, 2011 due to additions for current and prior year positions. The amount of the net unrecognized tax benefits that, if recognized, would directly affect the effective tax rate is $114.7 million at December 31, 2011 and $107.9 million at December 31, 2010. A reconciliation of the beginning and ending amount of gross unrecognized tax benefits is as follows (dollars in millions):

	Year Ended December 31,
	2011		2010			2009
Balance at beginning of period	$	111.0	$	113.2		$	186.3
Additions for current year tax positions	5.2		3.4			2.7
Additions for prior year positions	3.4		13.8			15.7
Reductions for settlements with tax authorities	—		(19.4		)	(88.5		)
Reductions for expirations of statute of limitations	—		—			(3.0		)
Balance at end of period	$	119.6	$	111.0		$	113.2

The Company recognizes interest and penalties accrued related to unrecognized tax benefits in its income tax provision. The Company has recognized $11.4 million of interest for the year ended December 31, 2011. The Company had $26.0 million and $14.6 million of accrued interest related to uncertain tax positions at December 31, 2011 and 2010, respectively. The Company has considered the application of penalties on its unrecognized tax benefits and determined, based upon several factors, that no accrual of penalties is required.

Tax Returns Subject to Examination

The Company's federal income tax returns are under examination by the Internal Revenue Service (IRS) for the 2006 through 2008 income tax years. The Company's Australian income tax returns for the tax years 2004 through 2010 are under examination by the Australian Tax Office (ATO). The 2006 IRS audit remains open awaiting the IRS appeals decision for the 2006 proposed adjustment of interest income accrued by a foreign subsidiary. Should the IRS position ultimately be sustained at the conclusion of the appeals process, additional income tax charges would be required to the extent the Company's NOL carryforwards are reduced.The 2007-2008 IRS audit was substantially complete at December 31, 2011 with no significant adjustments proposed by the IRS. The ATO is reviewing a transaction resulting in a foreign currency loss, interest rates on intercompany loans and certain intercompany charges. No formal adjustments have been proposed as of December 31, 2011. The Company believes it is reasonably possible one or both of these audits will be completed or settled during the next 12 months resulting in a potential decrease to its net unrecognized tax benefits of up to $30 million.

Notwithstanding these audit cycles, the years 1999-2001, 2003 through 2004, 2009 and 2010 remain potentially subject to examination due to NOL carryforwards. The Company's state income tax returns for the tax years 1996 and beyond remain potentially subject to examination by various state taxing authorities due to NOL carryforwards.

Foreign Earnings

The total amount of undistributed earnings of foreign subsidiaries for income tax purposes was $1.3 billion at December 31, 2011 and $1.1 billion at December 31, 2010. The Company has not provided deferred taxes on foreign earnings of $1.3 billion for 2011 and $1.1 billion for 2010 because such earnings are considered to be indefinitely reinvested outside the U.S. Should the Company repatriate all of these earnings, a one-time income tax charge of up to $450.7 million could occur.

Tax Payments

The following table summarizes the Company’s tax payments:

	Year Ended December 31,
	2011		2010		2009
	(Dollars in millions)
U.S. — federal	$	200.0	$	65.0	$	—
U.S. — state and local	13.2		0.4		0.9
Non-U.S.	61.9		83.0		169.7
Total tax payments	$	275.1	$	148.4	$	170.6

XML

Pension and Savings Plans (Details 6) (Pension Plans, Defined Benefit [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2011
Pension Plans, Defined Benefit [Member]
Estimated Future Benefit Payments
2012	$ 56.7
2013	58.0
2014	59.8
2015	61.8
2016	63.6
Years 2017-2021	$ 333.3

XML

Postretirement Health Care and Life Insurance Benefits (Details 2) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Reconciled amount of plans funded status
Fair value of plan assets at end of period	$ 769.6		$ 771.6
Postretirement Health Care and Life Insurance Benefits [Member]
Reconciled amount of plans funded status
Projected benefit obligation at beginning of period	1,031.2		982.2
Service cost	13.9		12.9		10.5
Interest cost	57.9		58.2		55.2
Participant Contributions	1.9		2.1
Plan Amendments (1)	(1.4)	[1]	7.9	[1]
Benefits paid	(68.0)		(77.4)
Actuarial (gain) loss	86.0		45.3
Projected benefit obligation at end of period	1,121.5		1,031.2		982.2
Fair value of plan assets at beginning of period	0		0
Employer contributions	66.1		75.3
Participant Contributions	1.9		2.1
Benefits paid	(68.0)		(77.4)
Fair value of plan assets at end of period	0		0		0
Funded status at end of year	(1,121.5)		(1,031.2)
Less current portion (included in Accounts payable and accrued expenses)	68.4		67.3
Noncurrent obligation (included in Accrued postretirement benefit costs)	$ (1,053.1)		$ (963.9)

[1] Effective January 1, 2011, certain plans were modified to ensure consistency of benefits across the Company, the impact of which is reflected in the December 31, 2010 figures above.

XML

Postretirement Health Care and Life Insurance Benefits (Details) (Postretirement Health Care and Life Insurance Benefits [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Postretirement Health Care and Life Insurance Benefits [Member]
Components of net periodic postretirement benefit cost
Service cost for benefits earned	$ 13.9	$ 12.9	$ 10.5
Interest cost on accumulated postretirement benefit obligation	57.9	58.2	55.2
Amortization of prior service cost	2.8	2.6	1.5
Amortization of actuarial loss	26.9	24.9	14.5
Net periodic (benefit) cost	$ 101.5	$ 98.6	$ 81.7

XML

Segment Information (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Operating segment results
Revenues	$ 2,253.6	$ 1,997.2	$ 1,980.5	$ 1,743.1	$ 1,792.7	$ 1,826.7	$ 1,629.9	$ 1,490.6	$ 7,974.4	$ 6,739.9	$ 5,847.0
Adjusted EBITDA									2,128.7	1,838.7	1,262.8
Total assets	16,733.0				11,363.1				16,733.0	11,363.1	9,955.3
Additions to property, plant, equipment, and mine development									846.9	547.9	383.4
Income (loss) from equity affiliates									(19.2)	(1.7)	(69.1)
Reconciliation Of Adjusted EBITDA To Consolidated Income From Continuing Operations [Abstract]
Adjusted EBITDA									2,128.7	1,838.7	1,262.8
Depreciation, depletion and amortization									(482.2)	(437.1)	(400.5)
Asset retirement obligation expense									(53.1)	(47.2)	(39.9)
Interest expense									(238.6)	(222.0)	(201.1)
Interest income									18.9	9.6	8.1
Income tax provision									(363.2)	(315.4)	(186.2)
Income from continuing operations, net of income taxes	222.5	285.6	307.8	194.6	223.8	239.3	215.7	147.8	1,010.5	826.6	443.2
Revenue from external customers by geographic region
Revenue percentage									100.00%	100.00%	100.00%
Western U.S. Mining [Member]
Operating segment results
Revenues									2,900.4	2,706.3	2,612.6
Adjusted EBITDA									766.0	816.7	721.5
Total assets	3,095.8				3,008.4				3,095.8	3,008.4	3,087.6
Additions to property, plant, equipment, and mine development									228.5	143.3	201.9
Income (loss) from equity affiliates									0	0	0
Reconciliation Of Adjusted EBITDA To Consolidated Income From Continuing Operations [Abstract]
Adjusted EBITDA									766.0	816.7	721.5
Midwestern U.S. Mining [Member]
Operating segment results
Revenues									1,481.1	1,320.6	1,303.8
Adjusted EBITDA									408.9	322.1	281.9
Total assets	672.5				608.0				672.5	608.0	444.4
Additions to property, plant, equipment, and mine development									108.2	224.9	104.2
Income (loss) from equity affiliates									0	0	0
Reconciliation Of Adjusted EBITDA To Consolidated Income From Continuing Operations [Abstract]
Adjusted EBITDA									408.9	322.1	281.9
Australian Mining [Member]
Operating segment results
Revenues									3,080.7	2,399.9	1,512.6
Adjusted EBITDA									1,194.3	977.4	410.5
Total assets	8,568.9				3,603.4				8,568.9	3,603.4	3,386.8
Additions to property, plant, equipment, and mine development									439.6	138.7	69.3
Income (loss) from equity affiliates									0	0	0
Reconciliation Of Adjusted EBITDA To Consolidated Income From Continuing Operations [Abstract]
Adjusted EBITDA									1,194.3	977.4	410.5
Trading and Brokerage [Member]
Operating segment results
Revenues									475.1	291.1	391.0
Adjusted EBITDA									197.0	77.2	193.4
Total assets	633.3				398.2				633.3	398.2	673.0
Additions to property, plant, equipment, and mine development									0.9	0.9	1.8
Income (loss) from equity affiliates									0	0	0
Reconciliation Of Adjusted EBITDA To Consolidated Income From Continuing Operations [Abstract]
Adjusted EBITDA									197.0	77.2	193.4
Corporate and Other [Member]
Operating segment results
Revenues									37.1	22.0	27.0
Adjusted EBITDA									(437.5)	(354.7)	(344.5)
Total assets	3,762.5				3,745.1				3,762.5	3,745.1	2,363.5
Additions to property, plant, equipment, and mine development									69.7	40.1	6.2
Income (loss) from equity affiliates									19.2	1.7	69.1
Reconciliation Of Adjusted EBITDA To Consolidated Income From Continuing Operations [Abstract]
Adjusted EBITDA									$ (437.5)	$ (354.7)	$ (344.5)
U.S. [Member]
Revenue from external customers by geographic region
Revenue percentage									62.00%	64.60%	73.20%
Japan [Member]
Revenue from external customers by geographic region
Revenue percentage									10.20%	9.10%	7.10%
South Korea [Member]
Revenue from external customers by geographic region
Revenue percentage									5.50%	3.70%	2.20%
India [Member]
Revenue from external customers by geographic region
Revenue percentage									5.20%	4.90%	3.80%
Other [Member]
Revenue from external customers by geographic region
Revenue percentage									17.10%	17.70%	13.70%

XML

Commitments and Contingencies (Details 1) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011 USD ($)	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)	Dec. 31, 2010 AUD	Dec. 31, 2011 Capital Additions [Member] USD ($)	Dec. 31, 2011 Prarie State Energy Campus [Member] USD ($)	Dec. 31, 2010 Prarie State Energy Campus [Member] USD ($)	Jan. 19, 2012 Pending or Threatened Litigation [Member] Gulf Power Company Litigation [Member] USD ($)
Long-term Purchase Commitment [Line Items]
Previous term loan facility balance				360.0
Litigation Settlement, Prejudgement Interest								6.9
Commitments outstanding for capital expenditures, Current					1,313.0
Commitments outstanding for capital expenditures next year					743.6
Current year increase in purchase commitments over amounts committed in prior year					854.8
Total take or pay commitments	4,547.6
Take or pay commitments due within the next 4 years	1,644.0
Take or pay commitments due within the next year	443.1
Expenses related to take or pay arrangements	284.2
Expenditures for construction of Prairie State Energy Campus	36.2	76.0	56.8
Investment in Prairie State Energy Campus included in Investments and Other Assets						238.7	202.5
Company's estimated share of total construction costs						$ 250
The Company's undivided interest percentage in the Prairie State Energy Campus	5.06%					5.06%

XML

Document and Entity Information (USD $) In Billions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Feb. 17, 2012	Jun. 30, 2011
Document and Entity Information [Abstract]
Entity Registrant Name	PEABODY ENERGY CORP
Entity Central Index Key	0001064728
Document Type	10-K
Document Period End Date	Dec. 31, 2011
Amendment Flag	false
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 15.9
Entity Common Stock, Shares Outstanding		272,259,729

XML

Supplemental Guarantor/Non-Guarantor Financial Information (Details 2) (USD $) In Millions, unless otherwise specified	12 Months Ended					12 Months Ended			12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2011 5.875% Senior Notes due April 2016 [Member]	Apr. 15, 2011 5.875% Senior Notes due April 2016 [Member]	Dec. 31, 2011 6.5% Senior Notes due September 2020 [Member]	Dec. 31, 2011 7.875% Senior Notes due November 2026 [Member]	Dec. 31, 2011 6.875% Senior Notes due March 2013 [Member]	Dec. 31, 2011 Parent Company [Member]	Dec. 31, 2010 Parent Company [Member]	Dec. 31, 2009 Parent Company [Member]	Dec. 31, 2011 Guarantor Subsidiaries [Member]	Dec. 31, 2010 Guarantor Subsidiaries [Member]	Dec. 31, 2009 Guarantor Subsidiaries [Member]	Dec. 31, 2011 Non-Guarantor Subsidiaries [Member]	Dec. 31, 2010 Non-Guarantor Subsidiaries [Member]	Dec. 31, 2009 Non-Guarantor Subsidiaries [Member]
Cash Flows From Operating Activities
Net cash provided by continuing operations	$ 1,658.1	$ 1,116.7	$ 1,044.9						$ 28.9	$ (126.4)	$ (213.7)	$ 1,519.7	$ 1,090.6	$ 792.7	$ 109.5	$ 152.5	$ 465.9
Net cash used in discontinued operations	(24.9)	(29.6)	5.3						4.4	(14.2)	7.4	(6.8)	(2.4)	(5.3)	(22.5)	(13.0)	3.2
Net cash provided by operating activities	1,633.2	1,087.1	1,050.2						33.3	(140.6)	(206.3)	1,512.9	1,088.2	787.4	87.0	139.5	469.1
Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development	(846.9)	(547.9)	(383.4)						0	0	0	(401.1)	(404.5)	(313.3)	(445.8)	(143.4)	(70.1)
Investment in Prairie State Energy Campus	(36.2)	(76.0)	(56.8)						0	0	0	(36.2)	(76.0)	(56.8)	0	0	0
Proceeds from disposal of assets, net of notes receivable	40.1	19.2	53.9						0	0	0	34.1	14.1	43.8	6.0	5.1	10.1
Investments in equity affiliates and joint ventures	(39.7)	(18.8)	(15.0)						0	0	0	(2.0)	(15.0)	(5.0)	(37.7)	(3.8)	(10.0)
Investments in debt and equity securities	(147.7)	(74.6)	0						0	0		(103.6)	0		(44.1)	(74.6)
Payments to Acquire Short-term Investments	(100.0)	0	0						(75.0)			0			(25.0)
Proceeds from Maturities, Prepayments and Calls of Short-term Investments	100.0	0	0						75.0			0			25.0
Payments to Acquire Businesses, Net of Cash Acquired	(2,756.7)	0	0						0			0			(2,756.7)
Investments in and Advances to Affiliates, at Fair Value, Gross Additions	(145.4)	0	0						0			(145.4)			0
Equity Method Investment, Dividends or Distributions	128.6	0	0						0			128.6			0
Repayment of Notes Receivable from Related Parties	331.7	0	0						0			331.7			0
Increase (Decrease) in Due to Related Parties	(371.3)	0	0						0			(371.3)			0
Proceeds from sales of debt and equity securities	104.6	12.4	0						0	0		47.0	0		57.6	12.4
Other, net	(6.6)	(8.8)	(6.1)						0	0	0	(6.5)	(8.7)	(5.8)	(0.1)	(0.1)	(0.3)
Net cash used in continuing operations	(3,745.5)	(694.5)	(407.4)						0	0	0	(524.7)	(490.1)	(337.1)	(3,220.8)	(204.4)	(70.3)
Net cash provided by discontinued operations	(62.3)	(9.1)	0.9						0	0	0	0	0	0	(62.3)	(9.1)	0.9
Net cash used in investing activities	(3,807.8)	(703.6)	(406.5)						0	0	0	(524.7)	(490.1)	(337.1)	(3,283.1)	(213.5)	(69.4)
Cash Flows From Financing Activities
Proceeds from long-term debt	4,101.4	1,150.0	0			641.9			4,100.0	1,150.0		0	0		1.4	0
Acquisition of noncontrolling interests	(1,994.8)	0	0						(11.1)			11.1			(1,994.8)
Payments of long-term debt	(263.9)	(1,167.3)	(37.1)						(243.1)	(1,146.8)	0	0	0	0	(20.8)	(20.5)	(37.1)
Dividends paid	(92.1)	(79.4)	(66.8)						(92.1)	(79.4)	(66.8)	0	0	0	0	0	0
Repurchase of employee common stock relinquished for tax withholding	(18.7)	(13.5)	(2.3)						(18.7)	(13.5)	(2.3)	0	0	0	0	0	0
Payment of debt issuance costs	(61.5)	(32.2)	0						(61.5)	(32.2)		0	0		0	0
Excess tax benefits related to share-based compensation	8.1	51.0	0						8.1	51.0		0	0		0	0
Other, net	0	14.3	1.6						11.1	22.3	8.7	(12.0)	(5.9)	0	0.9	(2.1)	(7.1)
Transactions with affiliates, net	0	0	0						(4,346.6)	724.6	473.9	(991.7)	(587.2)	(454.6)	5,338.3	(137.4)	(19.3)
Net cash used in financing activities	1,678.5	(77.1)	(104.6)						(653.9)	676.0	413.5	(992.6)	(593.1)	(454.6)	3,325.0	(160.0)	(63.5)
Net change in cash and cash equivalents	(496.1)	306.4	539.1						(620.6)	535.4	207.2	(4.4)	5.0	(4.3)	128.9	(234.0)	336.2
Cash and cash equivalents at beginning of year	1,295.2	988.8	449.7						903.8	368.4	161.2	5.2	0.2	4.5	386.2	620.2	284.0
Cash and cash equivalents at end of year	$ 799.1	$ 1,295.2	$ 988.8						$ 283.2	$ 903.8	$ 368.4	$ 0.8	$ 5.2	$ 0.2	$ 515.1	$ 386.2	$ 620.2
Supplemental Guarantor/Non-Guarantor Financial Information (Textuals)
Interest rates on Senior Notes				5.875%	5.875%	6.50%	7.875%	6.875%

XML

Accounts Payable and Accrued Expenses

12 Months Ended

Dec. 31, 2011

Payables and Accruals [Abstract]

Accounts Payable and Accrued Expenses

Accounts Payable and Accrued Expenses

Accounts payable and accrued expenses consisted of the following:

	December 31,
	2011		2010
	(Dollars in millions)
Trade accounts payable	$	735.6	$	465.5
Other accrued expenses	286.7		179.9
Accrued taxes other than income	196.8		185.3
Accrued payroll and related benefits	183.3		152.1
Accrued health care	77.8		85.9
Accrued royalties	77.8		72.6
Accrued interest	49.5		30.5
Workers’ compensation obligations	17.3		14.6
Accrued environmental	11.6		6.3
Commodity and foreign currency hedge contracts	7.9		2.9
Other accrued benefits	4.1		4.2
Income taxes payable	—		59.6
Liabilities associated with discontinued operations	63.9		29.4
Total accounts payable and accrued expenses	$	1,712.3	$	1,288.8

XML

Income Taxes (Details 2) (USD $) In Millions, unless otherwise specified	3 Months Ended				12 Months Ended
	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Reconciliation of the expected statutory federal income tax provision to the Company's actual income tax provision
Expected income tax provision at federal statutory rate					$ 480.8	$ 399.7	$ 220.3
Excess depletion					(70.8)	(53.5)	(44.0)
Foreign earnings provision differential					(99.2)	(124.5)	(83.4)
Foreign earnings repatriation					7.6	84.5	0
Remeasurement of foreign income tax accounts	18.9	43.0	(19.5)	5.5	(0.9)	47.9	74.4
State income taxes, net of U.S. federal tax benefit					12.3	(4.8)	3.4
General business tax credits					(17.8)	(17.0)	(12.2)
Changes in valuation allowance					15.4	(28.7)	17.3
Changes in tax reserves					14.7	0	5.9
Other, net					21.1	11.8	4.5
Total provision					$ 363.2	$ 315.4	$ 186.2

XML

Asset Retirement Obligations (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Asset Retirement Obligation Disclosure [Abstract]
Credit adjusted, risk-free interest rates	5.76%	6.37%	7.92%
Surety bonds and bank guarantees outstanding to secure reclamation obligations or activities	$ 791.6	$ 704.4
Amount of reclamation self-bonding in certain states in which the company qualifies	929.6	920.3
Letters of credit in support of reclamation obligations or activities		0.1
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at beginning of year	490.7	447.6
Liabilities incurred or acquired	43.0	8.2
Liabilities settled or disposed	(8.8)	(8.7)
Accretion expense	28.7	26.4
Revision of estimates	67.7	17.2
Mine Reclamation and Closing Liability, Noncurrent	621.3	490.7
Balance at end of year		490.7
Balance at end of year- active locations	574.0	438.2
Balace at end of year- closed or inactive locations	$ 47.3	$ 52.5

XML

Consolidated Balance Sheets (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Current assets
Cash and cash equivalents	$ 799.1	$ 1,295.2
Accounts receivable, net of allowance for doubtful accounts of $17.0 at December 31, 2011 and $30.3 at December 31, 2010	922.5	555.8
Inventories	446.3	327.2
Assets from coal trading activities, net	44.6	192.5
Deferred income taxes	27.3	120.4
Other current assets	766.1	467.1
Total current assets	3,005.9	2,958.2
Property, plant, equipment and mine development
Land and coal interests	10,781.0	7,633.8
Buildings and improvements	1,131.4	1,067.4
Plant and equipment	2,862.4	1,664.5
Less: accumulated depreciation, depletion and amortization	(3,412.1)	(2,987.6)
Property, plant, equipment and mine development, net	11,362.7	7,378.1
Investments and other assets	2,364.4	1,026.8
Total assets	16,733.0	11,363.1
Current liabilities
Current maturities of long-term debt	101.1	43.2
Liabilities from coal trading activities, net	10.3	181.7
Accounts payable and accrued expenses	1,712.3	1,288.8
Total current liabilities	1,823.7	1,513.7
Long-term debt, less current maturities	6,556.4	2,706.8
Deferred income taxes	554.2	545.1
Asset retirement obligations	621.3	490.7
Accrued postretirement benefit costs	1,053.1	963.9
Other noncurrent liabilities	608.5	453.6
Total liabilities	11,217.2	6,673.8
Stockholders' equity
Additional paid-in capital	2,234.0	2,182.0
Retained earnings	3,744.0	2,878.4
Accumulated other comprehensive loss	(142.4)	(67.9)
Treasury shares, at cost: 9.2 shares as of December 31, 2011 and 8.9 shares as of December 31, 2010	(353.3)	(334.6)
Peabody Energy Corporation's stockholders' equity	5,485.1	4,660.7
Noncontrolling interests	30.7	28.6
Total stockholders' equity	5,515.8	4,689.3
Total liabilities and stockholders' equity	16,733.0	11,363.1
Preferred Stock [Member]
Stockholders' equity
Preferred Stock	0	0
Series A Junior Participating Preferred Stock [Member]
Stockholders' equity
Preferred Stock	0	0
Perpetual Preferred Stock [Member]
Stockholders' equity
Preferred Stock	0	0
Series Common Stock [Member]
Stockholders' equity
Common Stock	0	0
Common Stock [Member]
Stockholders' equity
Common Stock	$ 2.8	$ 2.8

XML

Inventories

12 Months Ended

Dec. 31, 2011

Inventory Disclosure [Abstract]

Inventories

Inventories

Inventories consisted of the following:

	December 31,
	2011		2010
	(Dollars in millions)
Materials and supplies	$	124.9	$	94.5
Raw coal	95.0		55.4
Saleable coal	226.4		177.3
Total	$	446.3	$	327.2

XML

Discontinued Operations

12 Months Ended

Dec. 31, 2011

Discontinued Operations and Disposal Groups [Abstract]

Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]

Discontinued Operations

Discontinued operations include certain non-strategic Midwestern and Australian mining assets held for sale where the Company has committed to the divestiture of such assets and other operations recently divested.

Revenues resulting from discontinued operations (including assets held for sale) were $121.6 million, $205.8 million and $466.9 million for the years ended December 31, 2011, 2010 and 2009, respectively. (Loss) income before income taxes from discontinued operations reflects a loss of $86.5 million and $33.5 million for the years ended December 31, 2011 and December 31, 2010, respectively, and income of $36.8 million for the year ended December 31, 2009. The income tax adjustment resulting from discontinued operations reflects a benefit of $22.3 million and $9.1 million for the years ended December 31, 2011 and December 31, 2010, respectively, and a provision of $17.0 million for the year ended December 31, 2009.

Total assets related to discontinued operations were $143.7 million and $77.6 million as of December 31, 2011 and 2010, respectively. Total liabilities associated with discontinued operations were $86.3 million and $43.3 million as of December 31, 2011 and 2010, respectively.

XML

Pension and Savings Plans

12 Months Ended

Dec. 31, 2011

Pension and Savings Plans [Abstract]

Pension and Savings Plans

Pension and Savings Plans

One of the Company’s subsidiaries, Peabody Investments Corp. (PIC), sponsors a defined benefit pension plan covering certain U.S. salaried employees and eligible hourly employees at certain PIC subsidiaries (the Peabody Plan). A PIC subsidiary also has a defined benefit pension plan covering eligible employees who are represented by the United Mine Workers of America (UMWA) under the Western Surface Agreement (the Western Plan). PIC also sponsors an unfunded supplemental retirement plan to provide senior management with benefits in excess of limits under the federal tax law (collectively, the Plans).

Effective May 31, 2008, the Peabody Plan was frozen in its entirety for both participation and benefit accrual purposes. The Company adopted an enhanced savings plan contribution structure in lieu of benefits formerly accrued under the Peabody Plan.

Net periodic pension cost included the following components:

	Year Ended December 31,
	2011			2010			2009
	(Dollars in millions)
Service cost for benefits earned	$	1.7		$	1.5		$	1.4
Interest cost on projected benefit obligation	49.8			50.5			51.3
Expected return on plan assets	(64.4		)	(58.3		)	(60.9		)
Amortization of prior service cost	1.0			1.4			1.4
Amortization of actuarial losses	30.1			21.9			1.9
Total net periodic pension (benefit) cost	$	18.2		$	17.0		$	(4.9	)

The following includes amounts recognized in accumulated other comprehensive loss:

	Year Ended December 31,
	2011			2010			2009
	(Dollars in millions)
Net actuarial loss arising during year	$	144.2		$	13.1		$	46.1
Amortization:
Actuarial loss	(30.1		)	(21.9		)	(1.9		)
Prior service cost	(1.0		)	(1.4		)	(1.4		)
Total recognized in other comprehensive loss	113.1			(10.2		)	42.8
Net periodic pension (benefit) cost	18.2			17.0			(4.9		)
Total recognized in net periodic pension cost and other comprehensive loss	$	131.3		$	6.8		$	37.9

The Company amortizes actuarial gain and loss using a 5% corridor with a five-year amortization period. The estimated net actuarial loss and prior service cost that will be amortized from accumulated other comprehensive loss into net periodic pension cost during the year ended December 31, 2012 are $48.6 million and $1.0 million, respectively.

The following summarizes the change in benefit obligation, change in plan assets and funded status of the Company’s plans:

	December 31,
	2011			2010
	(Dollars in millions)
Change in benefit obligation:
Projected benefit obligation at beginning of period	$	881.0		$	844.9
Service cost	1.7			1.5
Interest cost	49.8			50.5
Benefits paid	(52.8		)	(50.4		)
Actuarial loss	83.9			34.5
Projected benefit obligation at end of period	963.6			881.0
Change in plan assets:
Fair value of plan assets at beginning of period	771.6			629.6
Actual return on plan assets	4.1			79.8
Employer contributions	46.7			112.6
Benefits paid	(52.8		)	(50.4		)
Fair value of plan assets at end of period	769.6			771.6
Funded status at end of year	$	(194.0	)	$	(109.4	)
Amounts recognized in the consolidated balance sheets:
Current obligation (included in Accounts payable and accrued expenses)	$	(1.7	)	$	(1.8	)
Noncurrent obligation (included in Other noncurrent liabilities)	(192.3		)	(107.6		)
Net amount recognized	$	(194.0	)	$	(109.4	)

The weighted-average assumptions used to determine the benefit obligations as of the end of each year were as follows:

	December 31,
	2011		2010
Discount rate	5.00	%	5.84	%
Measurement date	December 31, 2011		December 31, 2010

The weighted-average assumptions used to determine net periodic benefit cost during each year were as follows:

	Year Ended December 31,
	2011		2010		2009
Discount rate	5.84	%	6.19	%	6.90	%
Expected long-term return on plan assets	8.25	%	8.25	%	8.75	%
Measurement date	December 31, 2010		December 31, 2009		December 31, 2008

The expected rate of return on plan assets is determined by taking into consideration expected long-term returns associated with each major asset class (net of inflation) based on long-term historical ranges, inflation assumptions and the expected net value from active management of the assets based on actual results. Effective January 1, 2012, the Company lowered its expected rate of return on plan assets from 8.25% to 8.0% given the decline in asset performance due to the continued global recession and disruption in the financial markets.

The projected benefit obligation and the accumulated benefit obligation exceeded plan assets for all plans as of December 31, 2011 and 2010. The accumulated benefit obligation for all pension plans was $963.6 million and $881.0 million as of December 31, 2011 and 2010, respectively.

Assets of the Plans

Assets of the Peabody Plan and the Western Plan are commingled in the PIC Master Trust (the Master Trust) and are invested in accordance with investment guidelines that have been established by each Plan's respective Retirement Committee (collectively, the Retirement Committees) after consultation with outside investment advisors and actuaries.

The asset allocation targets have been set with the expectation that the Plans’ assets will be managed with an appropriate level of risk so that they can fund each Plan’s expected liabilities. To determine the appropriate target asset allocations, the Retirement Committees consider the demographics of each Plan’s participants, the funding status of each Plan, the business and financial profile of the Company and other associated risk preferences. These allocation targets are reviewed by the Retirement Committees on a regular basis and revised as necessary. The current target allocations for plan assets are 60% equity securities and 40% fixed income investments. Plan assets currently include real estate investments representing approximately 3% of total plan assets. The Company is in the process of liquidating these real estate holdings.

Assets of the Plans are either under active management by third-party investment advisors or in index funds, all selected and monitored by the Retirement Committees. The Retirement Committees have established specific investment guidelines for each major asset class including performance benchmarks, allowable and prohibited investment types and concentration limits. In general, the Plans’ investment guidelines do not permit leveraging the assets held in the Master Trust. The investment managers in the Master Trust, however, may employ various strategies and derivative instruments in establishing overall portfolio characteristics consistent with the guidelines and investment objectives for their portfolios. Equity investment guidelines do not permit entering into put or call options (except as deemed appropriate to manage currency risk), and futures contracts are permitted only to the extent necessary to equitize cash holdings.

A financial instrument’s level within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. Following is a description of the valuation methodologies used for investments measured at fair value, including the general classification of such investments pursuant to the valuation hierarchy.

U.S. equity securities.  As of December 31, 2011, investment vehicles include an institutional mutual fund that holds various small-cap publicly traded common stocks and an institutional mutual fund that invests in large-cap stocks. These institutional mutual funds are classified within the Level 2 valuation hierarchy since fair value inputs are derived prices in active markets and the institutional mutual funds are not publicly traded on a national securities exchange. Prior to December 31, 2011, investment vehicles included various small-cap publicly traded common stocks, an exchange-traded fund and a common/collective trust. Publicly traded common stocks and the exchange-traded fund were traded on a national securities exchange and were valued at quoted market prices in active markets and were classified within Level 1 of the valuation hierarchy. While the common/collective trust invested in various large-cap publicly traded common stocks that were traded on a national securities exchange, it was classified within Level 2 of the valuation hierarchy since the net asset value (NAV) was based on a derived price in an active market and it was not publicly traded on a national securities exchange. U.S. equity securities are not subject to liquidity redemption restrictions.

International equity securities.  Investment vehicles include a common/collective trust and an institutional mutual fund that primarily invest in various large-cap international equity securities that are valued on the basis of quotations from the primary market in which they are traded and translated at each valuation date from the local currency into U.S. dollars using the mean between the bid and asked market rates for such currencies. The NAV of the fund and the calculation of the NAV of each underlying investment are determined in U.S. dollars by the custodial trustee or at the direction of the investment manager as of the end of each month. These investments are classified within the Level 2 valuation hierarchy since the NAV is based on a derived price in an active market and neither the common/collective trust nor the mutual fund are publicly traded on a national securities exchange. Redemptions can only occur as of the last business day of the month subject to each funds respective notification period.

Debt securities.  Investment vehicles include various institutional mutual funds that hold mortgage-backed debt securities, international debt securities and corporate debt securities. Institutional mutual funds are invested in various diversified portfolios of fixed-income instruments, and the NAV for each institutional mutual fund is calculated daily in actively traded markets by an independent custodian for the investment manager. The institutional mutual funds are classified within the Level 2 valuation hierarchy since fair value inputs are derived prices in active markets and the institutional mutual funds are not publicly traded on a national securities exchange. Debt securities are not subject to liquidity redemption restrictions.

Short-term investments.  Investment vehicles primarily include institutional mutual funds. Short-term investments include a diversified portfolio of liquid, short-term instruments of varying maturities. The institutional mutual funds are classified within the Level 2 valuation hierarchy since fair value inputs are derived prices in active markets and the institutional mutual funds are not publicly traded on a national securities exchange. Short-term investments are not subject to liquidity redemption restrictions.

Interests in real estate.  Investments in real estate represent interests in several limited partnerships, which invest in various real estate properties. They are valued using various methodologies including independent third party appraisals. For some investments, little market activity may exist and determination of fair value is then based on the best information available in the circumstances. This involves a significant degree of judgment by taking into consideration a combination of internal and external factors. Based on the above factors, interests in real estate are classified within the Level 3 valuation hierarchy. Certain interests in real estate are subject to liquidity redemption restrictions.

The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. Furthermore, while the Company believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date. The inputs or methodologies used for valuing investments are not necessarily an indication of the risk associated with investing in those investments.

The following tables present the fair value of assets in the Master Trust by asset category and by fair value hierarchy:

	December 31, 2011
	Level 1		Level 2		Level 3		Total
	(Dollars in millions)
U.S. equity securities	$	—	$	340.4	$	—	$	340.4
International equity securities	—		107.8		—		107.8
Mortgage-backed debt securities	—		98.9		—		98.9
U.S. debt securities	—		83.3		—		83.3
International debt securities	—		32.0		—		32.0
Corporate debt securities	—		45.8		—		45.8
Short-term investments	—		36.1		—		36.1
Interests in real estate	—		—		25.3		25.3
Total assets at fair value	$	—	$	744.3	$	25.3	$	769.6

	December 31, 2010
	Level 1		Level 2		Level 3		Total
	(Dollars in millions)
U.S. equity securities	$	82.6	$	250.5	$	—	$	333.1
International equity securities	—		118.9		—		118.9
Mortgage-backed debt securities	—		108.8		—		108.8
U.S. debt securities	—		60.2		—		60.2
International debt securities	—		25.7		—		25.7
Corporate debt securities	—		46.1		—		46.1
Short-term investments	—		31.1		—		31.1
Interests in real estate	—		—		47.7		47.7
Total assets at fair value	$	82.6	$	641.3	$	47.7	$	771.6

The table below sets forth a summary of changes in the fair value of the Master Trust’s Level 3 investments:

	Year Ended December 31,
	2011			2010
	(Dollars in millions)
Beginning of year	$	47.7		$	47.4
Assets held at the reporting date:
Realized losses	(8.9		)	(0.1		)
Unrealized gains, net	11.4			1.3
Purchases, sales and settlements, net	(24.9		)	(0.9		)
End of year	$	25.3		$	47.7

Contributions

Annual contributions to the qualified plans are made in accordance with minimum funding standards and the Company's agreement with the Pension Benefit Guaranty Corporation (PBGC). Funding decisions also consider certain funded status thresholds defined by the Pension Protection Act of 2006 (generally 80%). As of December 31, 2011, the Company’s qualified plans are expected to be at or above the Pension Protection Act thresholds and will therefore avoid benefit restrictions and at-risk penalties for 2012. The Company intends to contribute the necessary amount needed to maintain these funded status thresholds during 2012.

Estimated Future Benefit Payments

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid by the Master Trust:

	Pension Benefits
	(Dollars in millions)
2012	$	56.7
2013	58.0
2014	59.8
2015	61.8
2016	63.6
Years 2017-2021	333.3

Defined Contribution Plans

The Company sponsors employee retirement accounts under three 401(k) plans for eligible U.S. employees. The Company matches voluntary contributions to each plan up to specified levels. The expense for these plans was $54.5 million, $51.3 million and $47.9 million for the years ended December 31, 2011, 2010 and 2009, respectively. A performance contribution feature in one of the plans allows for additional contributions from the Company based upon meeting specified Company performance targets. Performance contributions related to the years ended December 31, 2011, 2010 and 2009 were $22.5 million, $20.6 million and $20.3 million, respectively.

XML

Debt

12 Months Ended

Dec. 31, 2011

Debt Disclosure [Abstract]

Long-Term Debt

Debt

The Company’s total indebtedness as of December 31, 2011 and 2010 consisted of the following:

	December 31,
	2011		2010
	(Dollars in millions)
Term Loan	$	468.8	$	493.8
2011 Term Loan Facility	1,000.0		—
5.875% Senior Notes due April 2016	—		218.1
7.375% Senior Notes due November 2016	650.0		650.0
6.00% Senior Notes due November 2018	1,600.0		—
6.50% Senior Notes due September 2020	650.0		650.0
6.25% Senior Notes due November 2021	1,500.0		—
7.875% Senior Notes due November 2026	247.3		247.2
Convertible Junior Subordinated Debentures due 2066	375.2		373.3
Capital lease obligations	122.8		69.6
Fair value hedge adjustment	—		2.2
Other	43.4		45.8
Total	$	6,657.5	$	2,750.0

Credit Facility

On June 18, 2010, the Company entered into an unsecured credit agreement (the Credit Agreement) which established a $2.0 billion credit facility (the Credit Facility) and replaced the Company’s third amended and restated credit agreement dated as of September 15, 2006. The Credit Agreement provides for a $1.5 billion revolving credit facility (the Revolver) and a $500.0 million term loan facility (the Term Loan). The Company has the option to request an increase in the capacity of the Credit Facility, provided the aggregate increase for the Revolver and Term Loan does not exceed $250.0 million, the minimum amount of the increase is $25.0 million, and certain other conditions are met under the Credit Agreement. The Revolver also includes a swingline sub-facility under which up to $50.0 million is available for same-day borrowings. The Revolver commitments and the Term Loan under the Credit Facility will mature on June 18, 2015.

The Revolver replaced the Company’s previous $1.8 billion revolving credit facility and the Term Loan replaced the Company’s previous term loan facility (the previous term loan had a balance of $490.3 million at the time of replacement). The Company recorded $21.9 million in deferred financing costs, which are being amortized to interest expense over the five-year term of the Credit Facility. The Company also recorded refinancing charges of $9.3 million, which was recorded in “Interest expense” in the 2010 consolidated statements of income. The $500.0 million of proceeds from the Term Loan was used to repay the balance due on the Company’s previous term loan facility.

All borrowings under the Credit Agreement (other than swingline borrowings and borrowings denominated in currencies other than U.S. dollars) bear interest, at the Company’s option, at either a “base rate” or a “eurocurrency rate”, as defined in the Credit Agreement, plus in each case, a rate adjustment based on the Company’s leverage ratio, as defined in the Credit Agreement, ranging from 2.50% to 1.30% per year for borrowings bearing interest at the “base rate” and from 3.50% to 2.25% per year for borrowings bearing interest at the “eurocurrency rate” (such rate added to the “eurocurrency rate,” the “Eurocurrency Margin”). Swingline borrowings bear interest at a “BBA LIBOR” rate equal to the rate at which deposits in U.S. dollars for a one month term are offered in the interbank eurodollar market, as determined by the administrative agent, plus the Eurocurrency Margin. Borrowings denominated in currencies other than U.S. dollars will bear interest at the “eurocurrency rate” plus the Eurocurrency Margin.

The Company pays a usage-dependent commitment fee under the Revolver, which is dependent upon the Company’s leverage ratio, as defined in the Credit Agreement, and ranges from 0.500% to 0.375% of the available unused commitment. Swingline loans are not considered usage of the revolving credit facility for purposes of calculating the commitment fee. The fee accrues quarterly in arrears.

In addition, the Company pays a letter of credit fee calculated at a rate dependent on the Company’s leverage ratio, as defined in the Credit Agreement, ranging from 3.50% to 2.25% per year of the undrawn amount of each letter of credit and a fronting fee equal to 0.125% per year of the face amount of each letter of credit. These fees are payable quarterly in arrears.

The Term Loan is voluntarily prepayable from time to time without any premium or penalty, subject to certain customary reimbursements of the lenders' costs. The Term Loan, which is subject to quarterly repayment of 1.25% per quarter, commenced on December 31, 2010, with the final payment of all amounts outstanding (including accrued interest) being due on June 18, 2015.

Under the Credit Agreement, the Company must comply with certain financial covenants on a quarterly basis including a minimum interest coverage ratio and a maximum leverage ratio. The Credit Agreement also includes various affirmative and negative covenants that place limitations on the Company’s ability to, among other things, incur debt; make loans, investments, advances and acquisitions; sell assets; make redemptions and repurchases of capital stock; engage in mergers or consolidations; engage in affiliate transactions and restrict distributions from subsidiaries. When in compliance with the financial covenants and customary default provisions, the Company is not restricted in its ability to pay dividends, sell assets and make redemptions or repurchase capital stock provided that the Company may only redeem and repurchase capital stock with the proceeds received from the concurrent issue of capital stock or indebtedness permitted under the Credit Agreement.

Nearly all of the Company’s direct and indirect domestic subsidiaries guarantee all loans under the Credit Agreement. Certain of the Company’s foreign subsidiaries also, to the extent permitted by applicable law and existing contractual obligations, would be guarantors of loans made to one of the Company’s Dutch subsidiaries.

As of December 31, 2011, the Company had no borrowings on the Revolver, but had $21.0 million of letters of credit outstanding. The remaining capacity on the Revolver at December 31, 2011 was $1.5 billion.

The interest rate payable on the Revolver and the Term Loan was LIBOR plus 2.25%, or 2.51% at December 31, 2011.

2011 Term Loan Facility

On October 28, 2011, the Company entered into the 2011 Term Loan Facility that provides for borrowings up to $1.0 billion. The Company borrowed $1.0 billion under the 2011 Term Loan Facility to finance, in part, the acquisition of Macarthur. Borrowings under the 2011 Term Loan Facility bear interest, at the Company's option, at a rate equal to (i) LIBOR plus an applicable margin or (ii) a base rate (defined as the highest of (a) the Bank of America prime rate, (b) the Federal Funds rate plus 0.50% and (c) one month LIBOR plus 1.00%) plus an applicable margin. The applicable margin depends on the ratio of the Company's consolidated debt to its adjusted consolidated EBITDA, and may range from 1.75% to 3.00% per year for borrowings bearing interest at LIBOR and from 0.75% to 2.00% per year for borrowings bearing interest at the base rate, as defined in the 2011 Term Loan Facility.

The obligations under the 2011 Term Loan Facility are unsecured and are guaranteed by the Company's direct and indirect domestic subsidiaries that guarantee the Credit Facility. The 2011 Term Loan Facility contains covenants, including financial covenants, and events of default substantially the same as those set forth in the Credit Facility.

The 2011 Term Loan Facility is voluntarily prepayable from time to time without premium or penalty, subject to certain customary reimbursements of the lenders’ costs. The 2011 Term Loan Facility will be subject to quarterly repayment of 1.25% commencing April 28, 2012, with the final payment of all amounts outstanding due October 28, 2016.

As of December 31, 2011, the Company had $1.0 billion outstanding on the 2011 Term Loan Facility with an interest rate payable of LIBOR plus 2.0%, or 2.26%.

5.875% Senior Notes

On April 15, 2011, the Company used cash on hand to redeem its 5.875% Senior Notes due in April 2016 (the 5.875% Notes) in the aggregate principal amount of $218.1 million. In compliance with the terms of the indenture governing the 5.875% Notes, the redemption price was equal to 100.979% of the aggregate principal amount of the 5.875% Notes plus accrued and unpaid interest to April 15, 2011. The Company recognized costs of $1.7 million associated with the redemption.

6.00%, 6.25%, 6.50%, 7.375% and 7.875% Senior Notes (collectively the Senior Notes)

The Senior Notes are senior unsecured obligations and rank senior in right of payment to any subordinated indebtedness; equally in right of payment with any senior indebtedness; are effectively junior in right of payment to the Company’s future secured indebtedness, to the extent of the value of the collateral securing that indebtedness; and effectively junior to all the indebtedness and other liabilities of its subsidiaries that do not guarantee the notes.

The Senior Notes are jointly and severally guaranteed by nearly all of the Company’s domestic subsidiaries, as defined in the note indentures. The note indentures contain covenants that, among other things, limit the Company’s ability to create liens and enter into sale and lease-back transactions. The Senior Notes are redeemable at a redemption price equal to 100% of the principal amount of the notes being redeemed plus a make-whole premium and any accrued unpaid interest to the redemption date. If the Company experiences specific kinds of changes in control and the credit rating assigned to the Senior Notes declines below specified levels within 90 days of that time, holders of such notes have the right to require the Company to repurchase their notes at a repurchase price equal to 101% of their principal amount, plus accrued and unpaid interest, if any, to the date of repurchase.

Interest payments on the Senior Notes are scheduled to occur each year as follows:

Senior Notes	Interest Payment Dates
6.00% Senior Notes	May 15 and November 15
6.25% Senior Notes	May 15 and November 15
6.50% Senior Notes	March 15 and September 15
7.375% Senior Notes	May 1 and November 1
7.875% Senior Notes	May 1 and November 1

On November 15, 2011, the Company completed a $1.6 billion offering of 6.00% Senior Notes due November 2018 (the 6.00% Senior Notes) and a $1.5 billion offering of 6.25% Senior Notes due November 2021 (the 6.25% Senior Notes), with the proceeds of the offering used, in part, to finance the acquisition of Macarthur. On the same date, the Company, the Guarantors and the initial purchasers of the 6.00% Senior Notes and the 6.25% Senior Notes entered into a registration rights agreement (the Registration Rights Agreement). Subject to the terms of the Registration Rights Agreement, the Company will use its reasonable best efforts to register with the Securities and Exchange Commission exchange notes having substantially identical terms as the 6.00% Senior Notes and the 6.25% Senior Notes and to exchange freely tradeable exchange notes for such notes within 365 days after the issue date of the 6.00% Senior Notes and the 6.25% Senior Notes (effectiveness target date). If the Company fails to meet the effectiveness target date (a registration default), the annual interest rate on the 6.00% Senior Notes and the 6.25% Senior Notes will increase by 0.25% for each 90-day period during which the default continues, up to a maximum additional interest rate of 1.0% until the registration default is cured.

On August 25, 2010, the Company completed a $650.0 million offering of 6.50% Senior Notes due September 2020 (the 6.50% Senior Notes). The Company used the net proceeds of $641.9 million from the issuance of the 6.50% Senior Notes, after deducting underwriting discounts and expenses, and cash on hand to extinguish its previously outstanding $650.0 million aggregate principal 6.875% Senior Notes formerly due in March 2013 (the 2013 Notes). All of the 2013 Notes were either tendered or redeemed during 2010. The Company recognized debt extinguishment costs of $8.4 million, which was recorded in “Interest expense” in the consolidated statements of income. The issuance of the 6.50% Senior Notes and the extinguishment of the 2013 Notes allowed the Company to extend the maturity of its senior indebtedness and lower the coupon rate.

Convertible Junior Subordinated Debentures

As of December 31, 2011, the Company had $732.5 million aggregate principal outstanding of Debentures that generally require interest to be paid semiannually at a rate of 4.75% per year. The Company may elect to, and to the extent that a mandatory trigger event (as defined in the indenture governing the Debentures) has occurred and is continuing will be required to, defer interest payments on the Debentures. After five years of deferral at the Company’s option, or upon the occurrence of a mandatory trigger event, the Company generally must sell warrants or preferred stock with specified characteristics and use the funds from that sale to pay deferred interest, subject to certain limitations. In no event may the Company defer payments of interest on the Debentures for more than 10 years.

The Debentures are convertible at any time on or prior to December 15, 2036 if any of the following conditions occur: (i) the Company’s closing common stock price exceeds 140% of the then applicable conversion price for the Debentures (currently $81.47 per share) for at least 20 of the final 30 trading days in any quarter; (ii) a notice of redemption is issued with respect to the Debentures; (iii) a change of control, as defined in the indenture governing the Debentures; (iv) satisfaction of certain trading price conditions; and (v) other specified corporate transactions described in the indenture governing the Debentures. In addition, the Debentures are convertible at any time after December 15, 2036 to December 15, 2041, the scheduled maturity date. In the case of conversion following a notice of redemption or upon a non-stock change of control, as defined in the indenture governing the Debentures, holders may convert their Debentures into cash in the amount of the principal amount of their Debentures and shares of the Company’s common stock for any conversion value in excess of the principal amount. In all other conversion circumstances, holders will receive perpetual preferred stock (see Note 16) with a liquidation preference equal to the principal amount of their Debentures, and any conversion value in excess of the principal amount will be settled with the Company’s common stock. As a result of the Patriot Coal Corp. (Patriot) spin-off, the conversion rate was adjusted. The conversion rate has also been adjusted when there has been a change in the Company’s dividend distribution rate. The current conversion rate is 17.1846 shares of common stock per $1,000 principal amount of Debentures effective February 7, 2012. This adjusted conversion rate represents a conversion price of $58.19.

The Debentures are not subject to redemption prior to December 20, 2011. Between December 20, 2011 and December 19, 2036, the Company may redeem the Debentures, in whole or in part, if for at least 20 out of the 30 consecutive trading days immediately prior to the date on which notice of redemption is given, the Company’s closing common stock price has exceeded 130% of the then applicable conversion price for the Debentures (currently $75.65 per share). On or after December 20, 2036, whether or not the redemption condition is satisfied, the Company may redeem the Debentures, in whole or in part. The Company may not redeem any Debentures unless (i) all accrued and unpaid interest on the Debentures has been paid in full on or prior to the redemption date and (ii) if any perpetual preferred stock is outstanding, the Company has first given notice to redeem the perpetual preferred stock in the same proportion as the redemption of the Debentures. Any redemption of the Debentures will be at a cash redemption price of 100% of the principal amount of the Debentures to be redeemed, plus accrued and unpaid interest to the date of redemption.

On December 15, 2041, the scheduled maturity date, the Company will use commercially reasonable efforts, subject to the occurrence of a market disruption event, as defined in the indenture governing the Debentures, to issue securities of equivalent equity content in an amount sufficient to pay the principal amount of the Debentures, together with accrued and unpaid interest. At the final maturity date of the Debentures on December 15, 2066, the entire principal amount will become due and payable, together with accrued and unpaid interest.

In connection with the issuance of the Debentures, the Company entered into a Capital Replacement Covenant (the CRC). Pursuant to the CRC, the Company covenanted for the benefit of holders of covered debt, as defined in the CRC (currently the Company’s 7.875% Senior Notes, issued in the aggregate principal amount of $250.0 million), that neither the Company nor any of its subsidiaries shall repay, redeem or repurchase all or any part of the Debentures on or after December 15, 2041 and prior to December 15, 2046, except to the extent that the total repayment, redemption or repurchase price does not exceed the sum of: (i) 400% of the Company’s net cash proceeds from the sale of its common stock and rights to acquire its common stock (including common stock issued pursuant to the Company’s dividend reinvestment plan or employee benefit plans); (ii) the Company’s net cash proceeds from the sale of its mandatorily convertible preferred stock, as defined in the CRC, or debt exchangeable for equity, as defined in the CRC; and (iii) the Company’s net cash proceeds from the sale of other replacement capital securities, as defined in the CRC, in each case, during the six months prior to the notice date for the relevant payment, redemption or repurchase.

The Debentures are unsecured obligations of the Company, ranking junior to all existing and future senior and subordinated debt (excluding trade accounts payable or accrued liabilities arising in the ordinary course of business) except for any future debt that ranks equal to or junior to the Debentures. The Debentures will rank equal in right of payment with the Company’s obligations to trade creditors. Substantially all of the Company’s existing indebtedness is senior to the Debentures. In addition, the Debentures will be effectively subordinated to all indebtedness of the Company’s subsidiaries. The indenture governing the Debentures places no limitation on the amount of additional indebtedness that the Company or any of the Company’s subsidiaries may incur.

The Company accounts for the liability and equity components of the Debentures in a manner that reflects the nonconvertible debt borrowing rate when recognizing interest cost in subsequent periods. The following table illustrates the carrying amount of the equity and debt components of the Debentures:

	December 31,
	2011			2010
	(Dollars in millions)
Carrying amount of the equity component	$	215.4		$	215.4
Principal amount of the liability component	$	732.5		$	732.5
Unamortized discount	(357.3		)	(359.2		)
Net carrying amount	$	375.2		$	373.3

The following table illustrates the effective interest rate and the interest expense related to the Debentures:

	Year Ended December 31,
	2011			2010			2009
	(Dollars in millions)
Effective interest rate	4.9		%	4.9		%	4.9		%
Interest expense — contractual interest coupon	$	34.8		$	34.8		$	34.8
Interest expense — amortization of debt discount	1.9			1.8			1.6

The remaining period over which the discount will be amortized is 30 years as of December 31, 2011.

Macarthur Corporate Funding Facility

With the acquisition of Macarthur, the Company assumed Macarthur's three year $330.0 million (Australian dollar) Corporate Funding Facility that has a maturity date of November 30, 2013. As of December 31, 2011, the Company had no borrowings under the Macarthur Corporate Funding Facility. The Macarthur Corporate Funding Facility has a $130.0 million (Australian dollar) sub-limit for bank guarantees, leaving an available capacity of $200.0 million (Australian dollars) at December 31, 2011. Letters of credit and cash backed bank guarantees totaling $65.0 million (Australian dollars) were outstanding as of December 31, 2011. The Company plans to terminate the Macarthur Corporate Funding Facility in 2012.

Capital Lease Obligations

Capital lease obligations are for mining equipment (see Note 12 for additional information).

Debt Maturities, Interest Paid, and Financing Costs

The aggregate amounts of long-term debt maturities (including unamortized debt discounts) subsequent to December 31, 2011, including capital lease obligations, were as follows:

Year of Maturity	(Dollars in millions)
2012	$	101.1
2013	121.9
2014	107.8
2015	458.5
2016	1,475.7
2017 and thereafter	4,392.5
Total	$	6,657.5

Interest paid on long-term debt was $205.3 million, $197.9 million and $201.6 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Financing costs incurred with the issuance of the Company’s debt are being amortized to interest expense over the remaining term of the associated debt. The remaining balance at December 31, 2011 was $99.9 million, of which $69.2 million will be amortized to interest expense over the next five years.

XML

Income Taxes (Details Textuals) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Income Taxes (Textuals) [Abstract]
Alternative minimum tax, foreign tax and general business credits included in Company's tax credits and loss carryforwards	$ 300,000,000
State net operating loss carryforwards included in Company's tax credits and loss carryforwards	23,500,000
Foreign loss carryforwards included in Company's tax credits and loss carryforwards	109,300,000
Changes in valuation allowance	15,400,000	(28,700,000)	17,300,000
Valuation allowance reserve for state NOLs and certain foreign deferred tax assets	79,800,000	65,000,000
Total net unrecognized tax benefits	114,700,000	107,900,000
Total gross unrecognized tax benefits	119,600,000	111,000,000	113,200,000	186,300,000
Reduction in the amount of gross unrecognized tax benefits	8,600,000
Accrued interest related to unrecognized tax benefits included in income tax provision	11,400,000
Accrued interest related to uncertain tax positions	26,000,000	14,600,000
Potential decrease to net unrecognized tax benefits	30,000,000
Undistributed earnings of foreign subsidiaries for income tax purposes	1,300,000,000	1,100,000,000
Foreign earnings on which deferred taxes were not provided by the Company	1,300,000,000	1,100,000,000
One-time income tax charge if Company repatriates foreign earnings	$ 450,700,000

XML

Coal Trading

12 Months Ended

Dec. 31, 2011

Coal Trading [Abstract]

Coal Trading

Coal Trading

Risk Management 

The Company engages in direct and brokered trading of coal, ocean freight and fuel-related commodities in over-the-counter markets (coal trading), some of which is subsequently exchange-cleared and some of which is bilaterally-settled. Except those for which the Company has elected to apply a normal purchases and normal sales exception, all derivative coal trading contracts are accounted for on a fair value basis.

The Company’s policy is to include instruments associated with coal trading transactions as a part of its trading book. Trading revenues are recorded in “Other revenues” in the consolidated statements of income and include realized and unrealized gains and losses on derivative instruments, including coal deliveries related to contracts accounted for under the normal purchases and normal sales exception. Therefore, the Company has elected the trading exemption to reflect the disclosures for its coal trading activities.

	Year Ended December 31,
Trading Revenue by Type of Instrument	2011			2010		2009
	(Dollars in millions)
Commodity swaps and options	$	(41.4	)	$	23.2	$	176.5
Physical commodity purchase / sale contracts	187.0			135.5		85.0
Total trading revenue	$	145.6		$	158.7	$	261.5

Hedge Ineffectiveness. The Company assesses, both at inception and at least quarterly thereafter, whether the derivatives used in hedging activities are highly effective at offsetting the changes in the anticipated cash flows of the hedged item. The effective portion of the change in the fair value is recorded in “Accumulated other comprehensive loss” until the hedged transaction impacts reported earnings, at which time gains and losses are also reclassified to earnings. To the extent that the periodic changes in the fair value of the derivatives exceed the changes in the hedged item, the ineffective portion of the periodic non-cash changes are recorded in earnings in the period of the change. If the hedge ceases to qualify for hedge accounting, the Company prospectively recognizes the mark-to-market movements in earnings in the period of the change.

In some instances, the Company has designated an existing coal trading derivative as a hedge and, thus, the derivative has a non-zero fair value at hedge inception. The “off-market” nature of these derivatives, which is best described as an embedded financing element within the derivative, is a source of ineffectiveness. In other instances, the Company uses a coal trading derivative that settles at a different time, has different quality specifications, or has a different location basis than the occurrence of the cash flow being hedged. These collectively yield ineffectiveness to the extent that the derivative hedge contract does not exactly offset changes in the fair value or expected cash flows of the hedged item.

Forecasted Transactions No Longer Probable. During 2011, the Company reclassified losses of $10.0 million out of “Accumulated other comprehensive loss” to earnings as the underlying forecasted transactions were deemed no longer probable of occurring.

Fair Value Measurements

The fair value of assets and liabilities from coal trading activities is set forth below:

	December 31,
	2011						2010
	Gross Basis			Net Basis			Gross Basis			Net Basis
	(Dollars in millions)
Assets from coal trading activities	$	170.4		$	44.6		$	1,706.2		$	192.5
Liabilities from coal trading activities	(84.0		)	(10.3		)	(1,843.5		)	(181.7		)
Subtotal	86.4			34.3			(137.3		)	10.8
Net margin posted (held)(1)	(52.1		)	—			148.1			—
Net value of coal trading positions	$	34.3		$	34.3		$	10.8		$	10.8

⁽¹⁾  Represents margin held from exchanges of $52.1 million at December 31, 2011; and margin posted with counterparties and exchanges of $148.2 million, net of margin held of $0.1 million at December 31, 2010. In addition, at December 31, 2010, the Company held letters of credit of $5.0 million from counterparties in lieu of margin posted. Of the margin held at December 31, 2011, approximately $23.4 million related to cash flow hedges.

The Company’s trading assets and liabilities are generally made up of forward contracts, financial swaps and margin. The fair value of coal trading positions designated as cash flow hedges of forecasted sales was a liability of $22.4 million and $174.2 million as of December 31, 2011 and December 31, 2010, respectively. The decreases in the gross basis amounts were primarily due to positions being realized during the year, as well as the premature settlement of trades that were brokered by MF Global UK Limited (MF Global UK) due to it being placed into the United Kingdom's administration process (a process similar to bankruptcy proceedings in the U.S.). The Company subsequently entered into similar positions with a new broker. The settlements did not have a material impact on the Company's consolidated statements of income. For additional information regarding MF Global UK, see the "MF Global UK Limited" disclosure at the end of this note.

The following tables set forth the hierarchy of the Company’s net financial asset (liability) trading positions for which fair value is measured on a recurring basis:

	December 31, 2011
	Level 1		Level 2			Level 3		Total
	(Dollars in millions)
Commodity swaps and options	$	21.2	$	(1.9	)	$	—	$	19.3
Physical commodity purchase/sale contracts	—		6.3			8.7		15.0
Total net financial assets	$	21.2	$	4.4		$	8.7	$	34.3

	December 31, 2010
	Level 1		Level 2			Level 3		Total
			(Dollars in millions)
Commodity swaps and options	$	10.7	$	(76.2	)	$	—	$	(65.5	)
Physical commodity purchase/sale contracts	—		57.7			18.6		76.3
Total net financial assets (liabilities)	$	10.7	$	(18.5	)	$	18.6	$	10.8

For Level 1 and 2 financial assets and liabilities, the Company utilizes both direct and indirect observable price quotes, including U.S. interest rate curves, LIBOR yield curves, Chicago Mercantile Exchange (CME), New York Mercantile Exchange (NYMEX), Intercontinental Exchange indices (ICE), NOS Clearing ASA, LCH.Clearnet (formerly known as the London Clearing House), Singapore Exchange (SGX), broker quotes, published indices and other market quotes. Below is a summary of the Company’s valuation techniques for Level 1 and 2 financial assets and liabilities:

• Commodity swaps and options — generally valued based on unadjusted quoted prices in active markets (Level 1) or a valuation that is corroborated by the use of market-based pricing (Level 2).

• Physical commodity purchase/sale contracts — purchases and sales at locations with significant market activity corroborated by market-based information (Level 2).

Commodity swaps and options and physical commodity purchase/sale contracts transacted in less liquid markets or contracts, such as long-term arrangements with limited price availability, are classified in Level 3. Indicators of less liquid markets are those with periods of low trade activity or when broker quotes reflect wide pricing spreads. Generally, the Company’s Level 3 instruments or contracts are valued using internally generated models that include bid/ask price quotations, other market assessments obtained from multiple, independent third-party brokers or other transactional data. While the Company does not anticipate any decrease in the number of third-party brokers or market liquidity, such events could erode the quality of market information and therefore the valuing of its market positions should the number of third-party brokers decrease or if market liquidity is reduced. The Company’s valuation techniques also include basis adjustments for heat rate, sulfur and ash content, port and freight costs and credit and nonperformance risk. The Company validates its valuation inputs with third-party information and settlement prices from other sources where available. The Company has consistently applied these valuation techniques in all periods presented, and believes it has obtained the most accurate information available for the types of derivative contracts held.

The following table summarizes the changes in the Company’s recurring Level 3 net financial assets:

	Year Ended December 31,
	2011				2010			2009
	(Dollars in millions)
Beginning of year	$	18.6			$	17.0		$	37.8
Total gains (losses) realized/unrealized:
Included in earnings	8.9				2.1			(2.9		)
Included in other comprehensive income	—				(0.5		)	(1.6		)
Settlements	(2.1		)		(0.1		)	(20.5		)
Transfers in	1.0			—	—			—
Transfers out	(17.7		)		0.1			4.2
End of year	$	8.7			$	18.6		$	17.0

The following table summarizes the changes in unrealized gains relating to Level 3 net financial assets held both as of the beginning and the end of the year:

	Year Ended December 31,
	2011		2010		2009
	(Dollars in millions)
Changes in unrealized gains (1)	$	8.7	$	6.7	$	15.6

⁽¹⁾  Within the consolidated statements of income and consolidated statements of comprehensive income for the periods presented, unrealized gains and losses from Level 3 items are combined with unrealized gains and losses on positions classified in Level 1 or 2, as well as other positions that have been realized during the applicable periods.

The Company did not have any significant transfers between Level 1 and Level 2 during 2011, 2010 or 2009. Certain of the Company’s physical commodity purchase/sale contracts were transferred from Level 3 to Level 2 as the settlement dates entered a more liquid market. The Company’s policy is to value all transfers between levels using the beginning of period valuation.

Based on the net fair value of the Company’s coal trading positions held in “Accumulated other comprehensive loss” at December 31, 2011, unrealized losses to be reclassified from comprehensive income to earnings over the next 12 months are expected to be approximately $2 million. As these unrealized losses are associated with derivative instruments that represent hedges of forecasted transactions, the amounts reclassified to earnings may partially offset the realized transactions in the consolidated statements of income.

As of December 31, 2011, the timing of the estimated future realization of the value of the Company’s trading portfolio was as follows:

Year of	Percentage of
Expiration	Portfolio Total
2012	65	%
2013	29	%
2014	4	%
2015	2	%
	100	%

Nonperformance and Credit Risk. The fair value of the Company’s coal derivative assets and liabilities reflects adjustments for nonperformance and credit risk. The Company’s exposure is substantially with electric utilities, steel producers, energy marketers and energy producers. The Company’s policy is to independently evaluate each customer’s creditworthiness prior to entering into transactions and to regularly monitor the credit extended. If the Company engages in a transaction with a counterparty that does not meet its credit standards, the Company seeks to protect its position by requiring the counterparty to provide an appropriate credit enhancement. Also, when appropriate (as determined by its credit management function), the Company has taken steps to reduce its exposure to customers or counterparties whose credit has deteriorated and who may pose a higher risk of failure to perform under their contractual obligations. These steps include obtaining letters of credit or cash collateral (margin), requiring prepayments for shipments or the creation of customer trust accounts held for the Company’s benefit to serve as collateral in the event of a failure to pay or perform. To reduce its credit exposure related to trading and brokerage activities, the Company seeks to enter into netting agreements with counterparties that permit the Company to offset asset and liability positions with such counterparties and, to the extent required, will post or receive margin amounts associated with exchange-cleared positions.

At December 31, 2011, 78% of the Company’s credit exposure related to coal trading activities with investment grade counterparties while 21% with non-investment grade counterparties and 1% was with counterparties that are not rated.

Performance Assurances and Collateral.  Certain of the Company’s derivative trading instruments require the parties to provide additional performance assurances whenever a material adverse event jeopardizes one party’s ability to perform under the instrument. If the Company were to sustain a material adverse event (using commercially reasonable standards), the counterparties could request collateralization on derivative trading instruments in net liability positions which, based on an aggregate fair value at December 31, 2011 and 2010, would have amounted to collateral postings of approximately $11 million and $160 million, respectively, to its counterparties. As of December 31, 2011, zero collateral was posted to counterparties for such positions while $5.8 million was posted at December 31, 2010 (reflected in “Liabilities from coal trading activities, net”).

Certain of the Company’s other derivative trading instruments require the parties to provide additional performance assurances whenever a credit downgrade occurs below a certain level as specified in each underlying contract. The terms of such derivative trading instruments typically require additional collateralization, which is commensurate with the severity of the credit downgrade. If a credit downgrade were to have occurred below contractually specified levels, the Company’s additional collateral requirement owed to its counterparties would have been zero at December 31, 2011 and December 31, 2010 based on the aggregate fair value of all derivative trading instruments with such features that are in a net liability position. As such, the Company had no posting requirements for such instruments as of December 31, 2011. As of December 31, 2010, $5.0 million of margin was posted with a counterparty due to timing and market fluctuations (reflected in “Liabilities from coal trading activities, net”).

The Company is required to post collateral on positions that are in a net liability position with an exchange and is entitled to receive collateral on positions that are in a net asset position. This collateral is known as variation margin. At December 31, 2011, the Company was in a net asset position of $52.1 million as compared to a net liability position of $137.4 million at December 31, 2010. The margin held at December 31, 2011 is reflected in "Assets from coal trading activities, net" and the margin posted at December 31, 2010 is reflected in “Liabilities from coal trading activities, net.”

In addition, the Company is required by the exchange to post certain additional collateral, known as initial margin, which represents an estimate of potential future adverse price movements across the Company’s portfolio under normal market conditions. As of December 31, 2011 and 2010, the Company had posted initial margin of $34.0 million and $39.5 million, respectively (reflected in “Other current assets”). In addition, the Company posted $4.4 million of margin in excess of the exchange-required variation and initial margin discussed above as of December 31, 2010 (also reflected in “Other current assets”).

MF Global UK Limited

In October 2011, MF Global UK, a United Kingdom (U.K.) based broker-dealer, was placed into the U.K.'s administration process (a process similar to bankruptcy proceedings in the U.S.) by the Financial Services Authority following the Chapter 11 bankruptcy filing of its U.S. parent, MF Global Holdings Ltd. The Company had used MF Global UK to broker certain of its coal trading transactions. The interruption of the Company's trading operations was limited as the Company opened new accounts with different brokerage firms and transferred its open trading positions formerly held with MF Global UK to those new accounts. While the open trading positions were transferred from MF Global UK successfully, the related margin posted by the Company has been retained by MF Global UK pending resolution of the Company's claims with the special administrators. The Company had funds remaining with MF Global UK totaling approximately $53 million as of December 31, 2011, which is included in "Accounts receivable, net" in the consolidated balance sheets. The Company is pursuing collection and, due to the numerous uncertainties related to the claim, cannot reasonably estimate a potential reserve based upon information available as of the date of filing.

XML

Summary of Significant Accounting Policies Discussion (Details Textuals) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Property, Plant and Equipment [Line Items]
Net book value of coal reserves	$ 7,700,000,000	$ 5,000,000,000
Depreciation and depletion expense	473,700,000	424,800,000	388,000,000
Summary of Significant Accounting Policies Discussion (Textuals) [Abstract]
Coal reserves not subject to depletion	2,700,000,000	1,300,000,000
Recognition of tax benefits from uncertain tax positions	greater than fifty percent likelihood of being realized upon ultimate settlement
Impairment losses recorded	0	0	0
Foreign currency remeasurement gains (losses)	(900,000)	(38,500,000)	(55,400,000)
Period considered to treat short-term, highly liquid investments as cash equivalents	three months or less
Coal Reserves Held By Fee Ownership [Member]
Property, Plant and Equipment [Line Items]
Net book value of coal reserves	1,300,000,000	1,300,000,000
Building and Improvements [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, estimated useful lives, minimum (in years)	10
Property, Plant and Equipment, estimated useful lives, maximum (in years)	20
Plant and Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, estimated useful lives, minimum (in years)	3
Property, Plant and Equipment, estimated useful lives, maximum (in years)	33
Mining Properties and Mineral Rights [Member]
Property, Plant and Equipment [Line Items]
Net book value of coal reserves	$ 6,400,000,000	$ 3,700,000,000
Leasehold Improvements [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, estimated useful lives	Life of Lease

XML

Share-Based Compensation (Details 3) (USD $)	12 Months Ended
	Dec. 31, 2011 years	Dec. 31, 2010 years	Dec. 31, 2009 years
Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions
Weighted-average fair value	$ 33.92	$ 25.70	$ 26.84
Risk-free interest rate	2.00%	2.80%	1.50%
Expected option life	5.0	5.0	5.0
Expected volatility	64.00%	64.00%	60.00%
Dividend yield	0.60%	0.60%	0.90%

XML

Investments

12 Months Ended

Dec. 31, 2011

Investments, Debt and Equity Securities [Abstract]

Investments

Investments

The Company’s short-term investments are defined as those investments with original maturities of greater than three months and up to one year, and long-term investments are defined as those investments with original maturities greater than one year.

The Company classifies its investments as either held-to-maturity or available-for-sale at the time of purchase and reevaluates such designation periodically. Investments are classified as held-to-maturity when the Company has the intent and ability to hold the securities to maturity.

Investments in securities not classified as held-to-maturity are classified as available-for-sale. Available-for-sale securities are carried at fair value, with unrealized gains and losses, net of income taxes, reported in “Accumulated other comprehensive loss” in the consolidated balance sheets. Realized gains and losses, determined on a specific identification method, are included in “Interest income” in the consolidated statements of income.

The Company did not have any held-to-maturity securities as of December 31, 2011 or December 31, 2010.

Investments in available-for-sale securities at December 31, 2011 were as follows:

Available-for-sale securities	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	(Dollars in millions)
Current:
Federal government securities	$	3.3	$	—	$	—		$	3.3
U.S. corporate bonds	3.9		—		—			3.9
Noncurrent:
Marketable equity securities	66.5		—		(9.5		)	57.0
Federal government securities	11.3		0.2		—			11.5
U.S. corporate bonds	7.7		0.1		—			7.8
Total	$	92.7	$	0.3	$	(9.5	)	$	83.5

Investments in available-for-sale securities at December 31, 2010 were as follows:

Available-for-sale securities	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
			(Dollars in millions)
Current:
Federal government securities	$	0.5	$	—	$	—	$	0.5
U.S. corporate bonds	1.9		—		—		1.9
Noncurrent:
Federal government securities	9.2		—		—		9.2
U.S. corporate bonds	6.3		—		—		6.3
Total	$	17.9	$	—	$	—	$	17.9

Contractual maturities for available-for-sale investments in debt securities at December 31, 2011 were as shown below. Expected maturities will differ from contractual maturities because borrowers may have the right to call or prepay obligations with or without call or prepayment penalties.

Contractual maturities for available-for-sale securities	Cost		Fair Value
	(Dollars in millions)
Due in one year or less	$	7.2	$	7.2
Due in one to five years	19.0		19.3
Total	$	26.2	$	26.5

The Company’s investments in marketable equity securities consist of an investment in Winsway Coking Coal Holdings Limited.

Proceeds from sales of securities amounted to $52.8 million and realized gains on the sales amounted to $1.6 million for the year ended December 31, 2011.

In addition to the securities described above, the Company held investments in debt and equity securities related to the Company's pro-rata share of funding in the Newcastle Coal Infrastructure Group (NCIG).  During the year ended December 31, 2011, the Company sold all of its previously held interests in these debt and equity securities. New debt securities were purchased for the funding of the next phase of NCIG's port expansion during the year ended December 31, 2011. These debt securities are recorded at cost, which approximates fair value, and are denominated in U.S. dollars. The fair value of these securities was $29.4 million at December 31, 2011.

At each reporting date, the Company performs separate evaluations of debt and equity securities to determine if any unrealized losses are other-than-temporary. None of the securities that were in an unrealized loss position at December 31, 2011 has been so for greater than 12 months. The Company did not recognize any other-than-temporary losses on any of its investments during the year ended December 31, 2011.

XML

Derivatives and Fair Value Measurements

12 Months Ended

Dec. 31, 2011

Derivatives and Fair Value Measurements [Abstract]

Derivatives and Fair Value Measurements

Derivatives and Fair Value Measurements

Risk Management — Non Coal Trading Activities

The Company is exposed to various types of risk in the normal course of business, including price risk on commodities utilized in the Company's operations, interest rate risk on long-term debt, and foreign currency exchange rate risk for non-U.S. dollar expenditures. In most cases, commodity price risk (excluding coal trading activities) related to the sale of coal is mitigated through the use of long-term, fixed-price contracts rather than through the use of financial instruments. For the price risk exposure on other commodities, as well as for the interest rate risk and foreign currency exchange rate risk, the Company utilizes financial derivative instruments to manage the risks related to these fluctuations. All of these risks are actively monitored in an effort to ensure compliance with the risk management policies of the Company.

Interest Rate Swaps. The Company is exposed to interest rate risk on its fixed rate and variable rate long-term debt. From time to time, the Company manages the interest rate risk associated with the fair value of its fixed rate borrowings using fixed-to-floating interest rate swaps to effectively convert a portion of the underlying cash flows on the debt into variable rate cash flows. The Company designates these swaps as fair value hedges, with the objective of hedging against changes in the fair value of the fixed rate debt that results from market interest rate changes. From time to time, the interest rate risk associated with the Company’s variable rate borrowings is managed using floating-to-fixed interest rate swaps. The Company designates these swaps as cash flow hedges, with the objective of reducing the variability of cash flows associated with market interest rate changes. As of December 31, 2011, the Company had no interest rate swaps in place.

Foreign Currency Hedges. The Company is exposed to foreign currency exchange rate risk, primarily on Australian dollar expenditures made in its Australian Mining segment. This risk is managed by entering into forward contracts and options that the Company designates as cash flow hedges, with the objective of reducing the variability of cash flows associated with forecasted foreign currency expenditures.

Diesel Fuel and Explosives Hedges. The Company is exposed to commodity price risk associated with diesel fuel and explosives in the U.S. and Australia. This risk is managed through the use of cost pass-through contracts and derivatives, primarily swaps. The Company generally designates the swap contracts as cash flow hedges, with the objective of reducing the variability of cash flows associated with forecasted diesel fuel and explosives purchases. In Australia, the explosives costs and a portion of the diesel fuel costs are not hedged as they are usually included in the fees paid to the Company’s contract miners.

Notional Amounts and Fair Value.  The following summarizes the Company’s foreign currency and commodity positions at December 31, 2011:

	Notional Amount by Year of Maturity
	Total		2012		2013		2014		2015		2016		2017 and thereafter
Foreign Currency
A$:US$ hedge contracts (A$ millions)	$	3,910.6	$	1,750.5	$	1,309.6	$	850.5	$	—	$	—	$	—
GBP:US$ hedge contracts (GBP millions)	6.5		6.5		—		—		—		—		—
Commodity Contracts
Diesel fuel hedge contracts (million gallons)	189.6		86.0		68.0		35.6		—		—		—
U.S. explosives hedge contracts (million MMBtu)	7.7		3.9		2.6		1.2		—		—		—

	Account Classification by
	Cash Flow Hedge		Fair Value Hedge		Economic Hedge		Fair Value Asset (Liability)
							(Dollars in millions)
Foreign Currency
A$:US$ hedge contracts (A$ millions)	$	3,910.6	$	—	$	—	$	491.3
GBP:US$ hedge contracts (GBP millions)	6.5		—		—		(0.7		)
Commodity Contracts
Diesel fuel hedge contracts (million gallons)	189.6		—		—		$	43.7
U.S. explosives hedge contracts (million MMBtu)	7.7		—		—		$	(10.7	)

Hedge Ineffectiveness. The Company assesses, both at inception and at least quarterly thereafter, whether the derivatives used in hedging activities are highly effective at offsetting the changes in the anticipated cash flows of the hedged item. The effective portion of the change in the fair value is recorded in “Accumulated other comprehensive loss” until the hedged transaction impacts reported earnings, at which time any gain or loss is also reclassified to earnings. To the extent that the periodic changes in the fair value of the derivatives exceed the changes in the hedged item, the ineffective portion of the periodic non-cash changes are recorded in earnings in the period of the change. If the hedge ceases to qualify for hedge accounting, the Company prospectively recognizes the mark-to-market movements in earnings in the period of the change.

A measure of ineffectiveness is inherent in hedging future diesel fuel purchases with derivative positions based on crude oil and refined petroleum products as a result of location and product differences.

The Company’s derivative positions for the hedging of future explosives purchases are based on natural gas, which is the primary price component of explosives. However, a small measure of ineffectiveness exists as the contractual purchase price includes manufacturing fees that are subject to periodic adjustments. In addition, other fees, such as transportation surcharges, can result in ineffectiveness, but have historically changed infrequently and comprise a small portion of the total explosives cost.

The Company’s derivative positions for the hedging of forecasted foreign currency expenditures contain a small measure of ineffectiveness due to timing differences between the hedge settlement and the purchase transaction, which could differ by less than a day and up to a maximum of 30 days.

The tables below show the classification and amounts of pre-tax gains and losses related to the Company’s non-trading hedges during the years ended December 31, 2011, 2010 and 2009:

		Year Ended December 31, 2011
	Income Statement Classification Gains (Losses) - Realized	Gain (loss) recognized in income on non- designated derivatives(1)			Gain (loss) recognized in other comprehensive income on derivative (effective portion)			Gain (loss) reclassified from other comprehensive income into income (effective portion)		Gain (loss) reclassified from other comprehensive income into income (ineffective portion)
Financial Instrument
		(Dollars in millions)
Commodity swaps and options	Operating costs and expenses	$	—		$	30.7		$	42.7	$	4.8
Foreign currency cash flow hedge contracts:
- Operating costs	Operating costs and expenses	—			193.4			342.2		—
- Capital expenditures	Depreciation, depletion and amortization	—			(0.5		)	—		—
Foreign currency economic hedge contracts	Acquisition costs related to Macarthur Coal Limited	$	(32.8	)	$	—		$	—	$	—
Total		$	(32.8	)	$	223.6		$	384.9	$	4.8

⁽¹⁾  Relates to foreign currency contracts associated with the acquisition of Macarthur shares under the takeover process.

		Year Ended December 31, 2010
	Income Statement Classification Gains (Losses) - Realized	Gain (loss) recognized in income on non- designated derivatives(2)			Gain (loss) recognized in other comprehensive income on derivative (effective portion)		Gain (loss) reclassified from other comprehensive income into income (effective portion)			Gain (loss) reclassified from other comprehensive income into income (ineffective portion)
Financial Instrument
		(Dollars in millions)
Interest rate swaps cash flow hedge contracts	Interest expense	$	(8.5	)	$	0.8	$	(0.5	)	$	—
Commodity swaps and options	Operating costs and expenses	—			29.9		(36.2		)	(1.1		)
Foreign currency cash flow hedge contracts	Operating costs and expenses	—			622.2		188.2			—
Total		$	(8.5	)	$	652.9	$	151.5		$	(1.1	)

⁽²⁾  Amounts relate to swaps that were de-designated and terminated in conjunction with the refinancing of the Company's previous credit facility.

		Year Ended December 31, 2009
	Income Statement Classification Gains (Losses) - Realized	Gain (loss) recognized in income on non- designated derivatives(3)			Gain (loss) recognized in other comprehensive income on derivative (effective portion)		Gain (loss) reclassified from other comprehensive income into income (effective portion)			Gain (loss) reclassified from other comprehensive income into income (ineffective portion)
Financial Instrument
		(Dollars in millions)
Interest rate swaps cash flow hedge contracts	Interest expense	$	—		$	0.2	$	(5.5	)	$	—
Commodity swaps and options:
- Cash flow hedges	Operating costs and expenses	—			65.5		(98.3		)	0.7
- Economic hedges	Operating costs and expenses	(2.7		)	—		—			—
Foreign currency cash flow hedge contracts	Operating costs and expenses	—			458.0		(30.8		)	—
Total		$	(2.7	)	$	523.7	$	(134.6	)	$	0.7

⁽³⁾  Amounts relate to diesel fuel and explosives hedge derivatives that were de-designated in 2009.

Based on the net fair value of the Company’s non-coal trading positions held in “Accumulated other comprehensive loss” at December 31, 2011, unrealized gains to be reclassified from comprehensive income to earnings over the next 12 months associated with the Company’s foreign currency and diesel fuel hedge programs are expected to be approximately $266 million and $43 million, respectively. The unrealized losses to be realized under the explosives hedge program are expected to be approximately $6 million. As these unrealized gains are associated with derivative instruments that represent hedges of forecasted transactions, the amounts reclassified to earnings will partially offset the realized transactions, while the unrealized losses will add incremental expense to the consolidated statements of income.

The classification and amount of derivatives presented on a gross basis as of December 31, 2011 and 2010 are as follows:

	Fair Value as of December 31, 2011
	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
Financial Instrument
	(Dollars in millions)
Commodity swaps and options	$	43.4	$	11.7	$	7.1	$	15.0
Foreign currency cash flow hedge contracts	270.4		229.0		4.3		4.5
Total	$	313.8	$	240.7	$	11.4	$	19.5

	Fair Value as of December 31, 2010
	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
Financial Instrument
	(Dollars in millions)
Commodity swaps and options	25.8		27.0		12.0		0.6
Foreign currency cash flow hedge contracts	273.5		366.6		—		—
Total	$	299.3	$	393.6	$	12.0	$	0.6

After netting by counterparty where permitted, the fair values of the respective derivatives are reflected in “Other current assets,” “Investments and other assets,” “Accounts payable and accrued expenses” and “Other noncurrent liabilities” in the consolidated balance sheets.

See Note 7 for information related to the Company’s coal trading activities.

Fair Value Measurements

The Company uses a three-level fair value hierarchy that categorizes assets and liabilities measured at fair value based on the observability of the inputs utilized in the valuation. These levels include: Level 1, inputs are quoted prices in active markets for the identical assets or liabilities; Level 2, inputs other than quoted prices included in Level 1 that are directly or indirectly observable through market-corroborated inputs; and Level 3, inputs are unobservable, or observable but cannot be market-corroborated, requiring the Company to make assumptions about pricing by market participants.

Financial Instruments Measured on a Recurring Basis. The following tables set forth the hierarchy of the Company’s net financial asset (liability) positions for which fair value is measured on a recurring basis:

	December 31, 2011
	Level 1		Level 2		Level 3		Total
			(Dollars in millions)
Investment in debt and equity securities	$	83.5	$	—	$	—	$	83.5
Commodity swaps and options	—		33.0		—		33.0
Foreign currency cash flow hedge contracts	—		490.6		—		490.6
Total net financial assets	$	83.5	$	523.6	$	—	$	607.1

	December 31, 2010
	Level 1		Level 2		Level 3		Total
			(Dollars in millions)
Investment in debt securities	$	17.9	$	—	$	—	$	17.9
Commodity swaps and options	—		40.2		—		40.2
Foreign currency cash flow hedge contracts	—		640.1		—		640.1
Total net financial assets	$	17.9	$	680.3	$	—	$	698.2

For Level 1 and 2 financial assets and liabilities, the Company utilizes both direct and indirect observable price quotes, including interest rate yield curves, exchange indices, broker quotes, published indices and other market quotes. Below is a summary of the Company’s valuation techniques for Level 1 and 2 financial assets and liabilities:

• Investment in debt and equity securities: valued based on quoted prices in active markets (Level 1).

• Commodity swaps and options — diesel fuel and explosives: generally valued based on a valuation that is corroborated by the use of market-based pricing (Level 2).

• Foreign currency hedge contracts: valued utilizing inputs obtained in quoted public markets (Level 2).

The Company did not have any transfers between levels during 2011, 2010 or 2009 for its non-coal trading positions. The Company’s policy is to value all transfers between levels using the beginning of period valuation.

Other Financial Instruments. The following methods and assumptions were used by the Company in estimating fair values for other financial instruments as of December 31, 2011 and 2010:

• Cash and cash equivalents, accounts receivable, including those within the Company’s accounts receivable securitization program, and accounts payable and accrued expenses have carrying values which approximate fair value due to the short maturity or the liquid nature of these instruments.

• Investments in debt and equity securities related to the Company’s pro-rata share of funding in NCIG are included in “Investments and other assets” in the consolidated balance sheets. The debt securities are recorded at cost, which approximates fair value.

• Long-term debt fair value estimates are based on observed prices for securities with an active trading market when available, and otherwise on estimated borrowing rates to discount the cash flows to their present value. The carrying amounts of the 7.875% Senior Notes due 2026 and the Convertible Junior Subordinated Debentures due 2066 (the Debentures) are net of the respective unamortized note discounts.

The carrying amounts and estimated fair values of the Company’s debt are summarized as follows:

	December 31, 2011				December 31, 2010
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
			(Dollars in millions)
Long-term debt	$	6,657.5	$	6,922.7	$	2,750.0	$	2,960.0

Nonperformance and Credit Risk

The fair value of the Company’s non-coal trading derivative assets and liabilities reflects adjustments for nonperformance and credit risk. The Company manages its counterparty risk through established credit standards, diversification of counterparties, utilizing investment grade commercial banks and continuous monitoring of counterparty creditworthiness. To reduce its credit exposure for these hedging activities, the Company seeks to enter into netting agreements with counterparties that permit the Company to offset asset and liability positions with such counterparties.

XML

Financing Receivables

12 Months Ended

Dec. 31, 2011

Receivables [Abstract]

Financing Receivables

Financing Receivables

At December 31, 2011, the Company had total financing receivables of $376.1 million, of which $51.3 million was included in "Accounts receivable, net", $65.0 million was included in "Other current assets" and $259.8 million was included in "Investments and other assets" in the consolidated balance sheets. The Company periodically assesses the collectability of accounts and loans receivable by considering factors such as specific evaluation of collectability, historical collection experience, the age of the receivable and other available evidence. Below is a description of the Company's financing receivables at December 31, 2011.

Codrilla Mine Project. In 2011, a wholly owned subsidiary of Macarthur completed the sale of its 85% interest in the Codrilla Mine Project to participants of the Coppabella Moorvale Joint Venture (CMJV) where Macarthur sold down its interest in the Codrilla project to the CMJV (Codrilla sell down) so that following completion of the sale, ownership of the Codrilla Mine Project reflected the existing ownership of the Coppabella and Moorvale mines, with Macarthur retaining a 73.3% ownership. Prior to the Company's acquisition of Macarthur, consideration of $15.0 million (Australian dollars) was received by Macarthur upon completion of the Codrilla sell down, representing 20% of the agreed price. Two remaining installments are due on the completion of certain milestones, with 40% due on granting of the related mining lease and the final 40% due upon the mine's first coal shipment. There are currently no indications of impairment and the Company expects to receive full payment of amounts currently due. At December 31, 2011, $34.2 million was included in "Accounts receivable, net" and $35.6 million was included in "Investments and other assets" in the consolidated balance sheets.

Middlemount Mine. A wholly owned subsidiary of Macarthur periodically makes contributions to the Middlemount Mine joint venture for the purposes of funding capital expenditures and working capital, in line with the related shareholders’ agreement. Middlemount intends to pay down the loans as excess cash is generated as required by the related shareholders' agreement. There are currently no indications of impairment and the Company expects to receive full payment of amounts currently due. At December 31, 2011, $65.0 million was included in "Other current assets" and $224.2 million was included in "Investments and other assets" in the consolidated balance sheets.

Other Financing Receivables. From time to time, the Company may enter into transactions resulting in accounts or notes receivable held by the Company. These notes are generally short term in nature with positive historical collection experience and do not represent a material credit risk to the Company.

XML

Discontinued Operations (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Discontinued Operations and Disposal Groups [Abstract]
Revenues from discontinued operations (including assets held for sale)	$ 121.6	$ 205.8	$ 466.9
Income (loss) before income taxes from discontinued operations	86.5	33.5	36.8
Income tax provision (benefit) from discontinued operations	22.3	9.1	17.0
Total assets related to discontinued operations	143.7	77.6
Total liabilities associated with discontinued operations	$ 86.3	$ 43.3

XML

Commitments and Contingencies (Details 2) In Millions, unless otherwise specified			9 Months Ended		12 Months Ended			1 Months Ended	12 Months Ended		12 Months Ended
	Dec. 31, 2011 USD ($)	Dec. 31, 2010 USD ($)	Sep. 30, 2010 Navajo Nation Litigation [Member] USD ($)	Jun. 18, 1999 Navajo Nation Litigation [Member] subsidiaries	Dec. 31, 2011 Gulf Power Company Litigation [Member] T	Sep. 30, 2011 Gulf Power Company Litigation [Member] USD ($)	Sep. 30, 2010 Gulf Power Company Litigation [Member] USD ($)	Jun. 30, 2005 Oklahoma Lead Litigation [Member] USD ($)	Dec. 31, 2011 Oklahoma Lead Litigation [Member] USD ($) sites leadmills	Dec. 31, 2010 Oklahoma Lead Litigation [Member] USD ($)	Dec. 31, 2011 Monto Coal Pty Limited [Member] AUD
Loss Contingency [Abstract]
Number of subsidiaries served by plaintiff				3
Number of lease contract terminated				2
Settlement of Navajo claims			$ 24.5
Alleged shortage of past and future coal shipments under a coal supply agreement, tons					5,000,000
Litigation Settlement Damages Awarded to Plaintiff						20.5	0
Ownership Percentage In Subsidiaries											51.00%
Minimum actual damages sought by plaintiff											1,193.2
Number of lead mills formerly operated by predecessor of subsidiary									2
Percentage of total amount of crude ore mined in Picher, Oklahoma									0.15%
Alleged residential yard remediation costs incurred by the EPA due to potentially responsible parties' activities								125
Number of national priority list sites based on the Superfund Amendments and Reauthorization Act of 1986 at which Gold Fields or the former affiliate, has been named a potentially responsible party (PRP)									5
Number of additional national priority list sites in which claims were asserted									13
Total number of national priority list sites									18
Reduced number of national priority list sites due to completion of work, transfer or regulatory inactivity									11
Undiscounted environmental clean-up liabilities, total									52.5	51.1
Accrued environmental	$ 11.6	$ 6.3							$ 11.6	$ 6.3

XML

Accounts Payable and Accrued Expenses (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Accounts payable and accrued expenses
Trade accounts payable	$ 735.6	$ 465.5
Other accrued expenses	286.7	179.9
Accrued taxes other than income	196.8	185.3
Accrued payroll and related benefits	183.3	152.1
Accrued health care	77.8	85.9
Accrued royalties	77.8	72.6
Income taxes payable	0	59.6
Accrued interest	49.5	30.5
Workers’ compensation obligations	17.3	14.6
Accrued environmental	11.6	6.3
Other accrued benefits	4.1	4.2
Commodity hedge contracts	7.9	2.9
Liabilities associated with discontinued operations	63.9	29.4
Accounts payable and accrued expenses	$ 1,712.3	$ 1,288.8

XML

Investments (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Investments in available-for-sale securities
Available-for-sale securities, Cost	$ 92.7	$ 17.9
Available-for-sale Securities, Gross Unrealized Gains	0.3	0
Available-for-sale Securities, Gross Unrealized Losses	(9.5)	0
Available-for-sale securities, Fair Value	83.5	17.9
Current [Member] | Federal government securities [Member]
Investments in available-for-sale securities
Available-for-sale securities, Cost	3.3	0.5
Available-for-sale Securities, Gross Unrealized Gains	0	0
Available-for-sale Securities, Gross Unrealized Losses	0	0
Available-for-sale securities, Fair Value	3.3	0.5
Current [Member] | U.S. corporate bonds [Member]
Investments in available-for-sale securities
Available-for-sale securities, Cost	3.9	1.9
Available-for-sale Securities, Gross Unrealized Gains	0	0
Available-for-sale Securities, Gross Unrealized Losses	0	0
Available-for-sale securities, Fair Value	3.9	1.9
Noncurrent [Member] | Marketable equity securities [Member]
Investments in available-for-sale securities
Available-for-sale securities, Cost	66.5
Available-for-sale Securities, Gross Unrealized Gains	0
Available-for-sale Securities, Gross Unrealized Losses	(9.5)
Available-for-sale securities, Fair Value	57.0
Noncurrent [Member] | Federal government securities [Member]
Investments in available-for-sale securities
Available-for-sale securities, Cost	11.3	9.2
Available-for-sale Securities, Gross Unrealized Gains	0.2	0
Available-for-sale Securities, Gross Unrealized Losses	0	0
Available-for-sale securities, Fair Value	11.5	9.2
Noncurrent [Member] | U.S. corporate bonds [Member]
Investments in available-for-sale securities
Available-for-sale securities, Cost	7.7	6.3
Available-for-sale Securities, Gross Unrealized Gains	0.1	0
Available-for-sale Securities, Gross Unrealized Losses	0	0
Available-for-sale securities, Fair Value	$ 7.8	$ 6.3

XML

Pension and Savings Plans (Details 5) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Assets Held At Reporting Date:
Fair value of plan assets at end of period	$ 769.6	$ 771.6
Real Estate Investment [Member]
Assets Held At Reporting Date:
Fair value of plan assets at end of period	25.3	47.7
Level 3 [Member]
Assets Held At Reporting Date:
Fair value of plan assets at end of period	25.3	47.7
Level 3 [Member] | Real Estate Investment [Member]
Summary of changes in the fair value of the Master Trust's investments
Fair value of plan assets at beginning of period	47.7	47.4
Assets Held At Reporting Date:
Realized losses	(8.9)	(0.1)
Unrealized gains, net	11.4	1.3
Purchases, sales and settlements, net	(24.9)	(0.9)
Fair value of plan assets at end of period	$ 25.3	$ 47.7

XML

Acquisition of Macarthur Coal Limited (Pro Forma Information) (Details 3) (Macarthur [Member], USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Macarthur [Member]
Business Acquisition [Line Items]
Revenue	$ 8,696.5	$ 7,579.5
Income from continuing operations, net of income taxes	$ 1,046.7	$ 781.5
Basic earnings per share	$ 3.67	$ 2.80
Diluted earnings per share	$ 3.65	$ 2.77

XML

Postretirement Health Care and Life Insurance Benefits (Details 1) (Postretirement Health Care and Life Insurance Benefits [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Postretirement Health Care and Life Insurance Benefits [Member]
Amounts recognized in accumulated other comprehensive loss
Net actuarial (gain) loss arising during year	$ 86.0	$ 45.3	$ 165.2
Prior service cost arising during year	(1.4)	7.9	(10.5)
Amortizations:
Actuarial loss	(26.9)	(24.9)	(14.5)
Prior service cost	(2.8)	(2.6)	(1.5)
Total recognized in other comprehensive loss	54.9	25.7	138.7
Net periodic postretirement (benefit) cost	101.5	98.6	81.7
Total recognized in net periodic benefit cost and other comprehensive loss	$ 156.4	$ 124.3	$ 220.4

XML

Supplemental Guarantor/Non-Guarantor Financial Information

12 Months Ended

Dec. 31, 2011

Supplemental Guarantor Non Guarantor Financial Information [Abstract]

Supplemental Guarantor/Non-Guarantor Financial Information

Supplemental Guarantor/Non-Guarantor Financial Information

In accordance with the indentures governing the Senior Notes, including the 5.875% Senior Notes due April 2016 and the 6.875% Senior Notes due March 2013 extinguished in 2011 and 2010, respectively, certain wholly-owned U.S. subsidiaries of the Company have fully and unconditionally guaranteed these Senior Notes, on a joint and several basis. Separate financial statements and other disclosures concerning the Guarantor Subsidiaries are not presented because management believes that such information is not material to the holders of the Senior Notes. The following historical financial statement information is provided for the Guarantor/Non-Guarantor Subsidiaries.

PEABODY ENERGY CORPORATION

SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF INCOME

	Year Ended December 31, 2011
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(Dollars in millions)
Total revenues	$	—		$	4,758.4		$	3,509.4		$	(293.4	)	$	7,974.4
Costs and expenses
Operating costs and expenses	(386.3		)	3,598.6			2,631.1			(293.4		)	5,550.0
Depreciation, depletion and amortization	—			297.4			184.8			—			482.2
Asset retirement obligation expense	—			36.2			16.9			—			53.1
Selling and administrative expenses	34.0			215.0			19.2			—			268.2
Acquisition costs related to Macarthur Coal Limited	32.8			31.2			21.2			—			85.2
Other operating (income) loss:
Net gain on disposal or exchange of assets	—			(73.2		)	(3.7		)	—			(76.9		)
(Income) loss from equity affiliates	(881.5		)	8.6			10.6			881.5			19.2
Interest expense	243.1			47.3			67.2			(119.0		)	238.6
Interest income	(50.9		)	(31.1		)	(55.9		)	119.0			(18.9		)
Unrealized (gain) loss on derivatives	—			(1.3		)	1.3			—			—
Income from continuing operations before income taxes	1,008.8			629.7			616.7			(881.5		)	1,373.7
Income tax provision	46.5			172.0			144.7			—			363.2
Income from continuing operations, net of income taxes	962.3			457.7			472.0			(881.5		)	1,010.5
Loss from discontinued operations, net of income taxes	(4.6		)	(3.1		)	(56.5		)	—			(64.2		)
Net income	957.7			454.6			415.5			(881.5		)	946.3
Less: Net loss attributable to noncontrolling interests	—			—			(11.4		)	—			(11.4		)
Net income attributable to common stockholders	$	957.7		$	454.6		$	426.9		$	(881.5	)	$	957.7

PEABODY ENERGY CORPORATION

SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF INCOME

	Year Ended December 31, 2010
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(Dollars in millions)
Total revenues	$	—		$	3,596.1		$	3,916.9		$	(773.1	)	$	6,739.9
Costs and expenses
Operating costs and expenses	(145.1		)	2,472.7			3,142.8			(773.1		)	4,697.3
Depreciation, depletion and amortization	—			294.1			143.0			—			437.1
Asset retirement obligation expense	—			31.9			15.3			—			47.2
Selling and administrative expenses	31.6			194.3			6.3			—			232.2
Other operating (income) loss:
Net (gain) loss on disposal or exchange of assets	—			(34.5		)	4.5			—			(30.0		)
(Income) loss from equity affiliates	(838.4		)	7.1			6.0			827.0			1.7
Interest expense	219.7			52.7			17.9			(68.3		)	222.0
Interest income	(18.8		)	(21.8		)	(37.3		)	68.3			(9.6		)
Income from continuing operations before income taxes	751.0			599.6			618.4			(827.0		)	1,142.0
Income tax (benefit) provision	(24.2		)	183.3			156.3			—			315.4
Income from continuing operations, net of income taxes	775.2			416.3			462.1			(827.0		)	826.6
Loss from discontinued operations, net of income taxes	(1.2		)	(23.2		)	—			—			(24.4		)
Net income	774.0			393.1			462.1			(827.0		)	802.2
Less: Net income attributable to noncontrolling interests	—			—			28.2			—			28.2
Net income attributable to common stockholders	$	774.0		$	393.1		$	433.9		$	(827.0	)	$	774.0

PEABODY ENERGY CORPORATION

SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF INCOME

	Year Ended December 31, 2009
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(Dollars in millions)
Total revenues	$	—		$	4,283.9		$	2,312.5		$	(749.4	)	$	5,847.0
Costs and expenses
Operating costs and expenses	104.4			3,250.4			1,733.8			(749.4		)	4,339.2
Depreciation, depletion and amortization	—			282.9			117.6			—			400.5
Asset retirement obligation expense	—			33.1			6.8			—			39.9
Selling and administrative expenses	29.3			164.2			5.6			—			199.1
Other operating (income) loss:
Net gain on disposal or exchange of assets	—			(17.1		)	(6.1		)	—			(23.2		)
(Income) loss from equity affiliates	(620.9		)	6.3			62.8			620.9			69.1
Interest expense	198.4			52.5			16.2			(66.0		)	201.1
Interest income	(15.3		)	(28.9		)	(29.9		)	66.0			(8.1		)
Income from continuing operations before income taxes	304.1			540.5			405.7			(620.9		)	629.4
Income tax (benefit) provision	(122.3		)	176.5			132.0			—			186.2
Income from continuing operations, net of income taxes	426.4			364.0			273.7			(620.9		)	443.2
Income (loss) from discontinued operations, net of income taxes	21.8			12.0			(14.0		)	—			19.8
Net income	448.2			376.0			259.7			(620.9		)	463.0
Less: Net income attributable to noncontrolling interests	—			—			14.8			—			14.8
Net income attributable to common stockholders	$	448.2		$	376.0		$	244.9		$	(620.9	)	$	448.2

PEABODY ENERGY CORPORATION

SUPPLEMENTAL CONDENSED CONSOLIDATING BALANCE SHEETS

	December 31, 2011
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Reclassifications/ Eliminations			Consolidated
	(Dollars in millions)
Assets
Current assets
Cash and cash equivalents	$	283.2		$	0.8		$	515.1		$	—		$	799.1
Accounts receivable, net	5.3			100.8			816.4			—			922.5
Inventories	—			220.0			226.3			—			446.3
Assets from coal trading activities, net	—			14.9			29.7			—			44.6
Deferred income taxes	—			48.0			—			(20.7		)	27.3
Other current assets	305.1			98.8			362.2			—			766.1
Total current assets	593.6			483.3			1,949.7			(20.7		)	3,005.9
Property, plant, equipment and mine development
Land and coal interests	—			5,061.8			5,719.2			—			10,781.0
Buildings and improvements	—			962.8			168.6			—			1,131.4
Plant and equipment	—			1,507.3			1,355.1			—			2,862.4
Less: accumulated depreciation, depletion and amortization	—			(2,623.1		)	(789.0		)	—			(3,412.1		)
Property, plant, equipment and mine development, net	—			4,908.8			6,453.9			—			11,362.7
Investments and other assets	10,300.8			199.7			1,496.1			(9,632.2		)	2,364.4
Total assets	$	10,894.4		$	5,591.8		$	9,899.7		$	(9,652.9	)	$	16,733.0
Liabilities and Stockholders’ Equity
Current liabilities
Current maturities of long-term debt	$	62.5		$	—		$	38.6		$	—		$	101.1
Payables to (receivables from) affiliates, net	2,417.8			(2,529.1		)	111.3			—			—
Liabilities from coal trading activities, net	—			4.2			6.1			—			10.3
Deferred income taxes	11.6			—			9.1			(20.7		)	—
Accounts payable and accrued expenses	69.4			868.8			774.1			—			1,712.3
Total current liabilities	2,561.3			(1,656.1		)	939.2			(20.7		)	1,823.7
Long-term debt, less current maturities	6,428.8			—			127.6			—			6,556.4
Deferred income taxes	76.0			126.3			351.9			—			554.2
Notes payable to (receivables from) affiliates, net	(3,720.0		)	(981.5		)	4,701.5			—			—
Other noncurrent liabilities	63.2			1,892.6			327.1			—			2,282.9
Total liabilities	5,409.3			(618.7		)	6,447.3			(20.7		)	11,217.2
Peabody Energy Corporation’s stockholders’ equity	5,485.1			6,210.5			3,421.7			(9,632.2		)	5,485.1
Noncontrolling interests	—			—			30.7			—			30.7
Total stockholders’ equity	5,485.1			6,210.5			3,452.4			(9,632.2		)	5,515.8
Total liabilities and stockholders’ equity	$	10,894.4		$	5,591.8		$	9,899.7		$	(9,652.9	)	$	16,733.0

PEABODY ENERGY CORPORATION

SUPPLEMENTAL CONDENSED CONSOLIDATING BALANCE SHEETS

	December 31, 2010
	Parent Company		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Reclassifications/ Eliminations			Consolidated
			(Dollars in millions)
Assets
Current assets
Cash and cash equivalents	$	903.8	$	5.2		$	386.2		$	—		$	1,295.2
Accounts receivable, net	2.1		5.5			548.2			—			555.8
Inventories	—		168.0			159.2			—			327.2
Assets from coal trading activities, net	—		23.8			168.7			—			192.5
Deferred income taxes	—		78.6			47.9			(6.1		)	120.4
Other current assets	307.9		30.7			128.5			—			467.1
Total current assets	1,213.8		311.8			1,438.7			(6.1		)	2,958.2
Property, plant, equipment and mine development
Land and coal interests	—		4,860.7			2,773.1			—			7,633.8
Buildings and improvements	—		945.8			121.6			—			1,067.4
Plant and equipment	—		1,300.6			363.9			—			1,664.5
Less: accumulated depreciation, depletion and amortization	—		(2,374.4		)	(613.2		)	—			(2,987.6		)
Property, plant, equipment and mine development, net	—		4,732.7			2,645.4			—			7,378.1
Investments and other assets	9,331.0		179.8			147.1			(8,631.1		)	1,026.8
Total assets	$	10,544.8	$	5,224.3		$	4,231.2		$	(8,637.2	)	$	11,363.1
Liabilities and Stockholders’ Equity
Current liabilities
Current maturities of long-term debt	$	25.0	$	—		$	18.2		$	—		$	43.2
Payables to (receivables from) affiliates, net	2,225.3		(2,528.3		)	303.0			—			—
Liabilities from coal trading activities, net	—		29.5			152.2			—			181.7
Deferred income taxes	6.1		—			—			(6.1		)	—
Accounts payable and accrued expenses	47.4		777.2			464.2			—			1,288.8
Total current liabilities	2,303.8		(1,721.6		)	937.6			(6.1		)	1,513.7
Long-term debt, less current maturities	2,609.6		0.1			97.1			—			2,706.8
Deferred income taxes	93.2		135.4			316.5			—			545.1
Notes payable to (receivables from) affiliates, net	818.9		(825.3		)	6.4			—			—
Other noncurrent liabilities	58.6		1,652.8			196.8			—			1,908.2
Total liabilities	5,884.1		(758.6		)	1,554.4			(6.1		)	6,673.8
Peabody Energy Corporation’s stockholders’ equity	4,660.7		5,982.9			2,648.2			(8,631.1		)	4,660.7
Noncontrolling interests	—		—			28.6			—			28.6
Total stockholders’ equity	4,660.7		5,982.9			2,676.8			(8,631.1		)	4,689.3
Total liabilities and stockholders’ equity	$	10,544.8	$	5,224.3		$	4,231.2		$	(8,637.2	)	$	11,363.1

PEABODY ENERGY CORPORATION

SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

	Year Ended December 31, 2011
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidated
				(Dollars in millions)
Cash Flows From Operating Activities
Net cash provided by continuing operations	$	28.9		$	1,519.7		$	109.5		$	1,658.1
Net cash provided by (used in) discontinued operations	4.4			(6.8		)	(22.5		)	(24.9		)
Net cash provided by operating activities	33.3			1,512.9			87.0			1,633.2
Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development	—			(401.1		)	(445.8		)	(846.9		)
Investment in Prairie State Energy Campus	—			(36.2		)	—			(36.2		)
Proceeds from disposal of assets, net of notes receivable	—			34.1			6.0			40.1
Investments in equity affiliates and joint ventures	—			(2.0		)	(37.7		)	(39.7		)
Proceeds from sales of debt and equity securities	—			47.0			57.6			104.6
Purchases of debt and equity securities	—			(103.6		)	(44.1		)	(147.7		)
Purchases of short-term investments	(75.0		)	—			(25.0		)	(100.0		)
Maturity of short-term investments	75.0			—			25.0			100.0
Acquisition of Macarthur Coal Limited	—			—			(2,756.7		)	(2,756.7		)
Contributions to joint ventures	—			(145.4		)	—			(145.4		)
Distributions from joint ventures	—			128.6			—			128.6
Repayment of loans from related parties	—			331.7			—			331.7
Advances to related parties	—			(371.3		)	—			(371.3		)
Other, net	—			(6.5		)	(0.1		)	(6.6		)
Net cash used in continuing operations	—			(524.7		)	(3,220.8		)	(3,745.5		)
Net cash used in discontinued operations	—			—			(62.3		)	(62.3		)
Net cash used in investing activities	—			(524.7		)	(3,283.1		)	(3,807.8		)
Cash Flows From Financing Activities
Proceeds from long-term debt	4,100.0			—			1.4			4,101.4
Acquisition of noncontrolling interests	(11.1		)	11.1			(1,994.8		)	(1,994.8		)
Payments of long-term debt	(243.1		)	—			(20.8		)	(263.9		)
Dividends paid	(92.1		)	—			—			(92.1		)
Repurchase of employee common stock relinquished for tax withholding	(18.7		)	—			—			(18.7		)
Payment of debt issuance costs	(61.5		)	—			—			(61.5		)
Excess tax benefits related to share-based compensation	8.1			—			—			8.1
Other, net	11.1			(12.0		)	0.9			—
Transactions with affiliates, net	(4,346.6		)	(991.7		)	5,338.3			—
Net cash (used in) provided by financing activities	(653.9		)	(992.6		)	3,325.0			1,678.5
Net change in cash and cash equivalents	(620.6		)	(4.4		)	128.9			(496.1		)
Cash and cash equivalents at beginning of year	903.8			5.2			386.2			1,295.2
Cash and cash equivalents at end of year	$	283.2		$	0.8		$	515.1		$	799.1

PEABODY ENERGY CORPORATION

SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

	Year Ended December 31, 2010
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidated
				(Dollars in millions)
Cash Flows From Operating Activities
Net cash (used in) provided by continuing operations	$	(126.4	)	$	1,090.6		$	152.5		$	1,116.7
Net cash used in discontinued operations	(14.2		)	(2.4		)	(13.0		)	(29.6		)
Net cash (used in) provided by operating activities	(140.6		)	1,088.2			139.5			1,087.1
Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development	—			(404.5		)	(143.4		)	(547.9		)
Investment in Prairie State Energy Campus	—			(76.0		)	—			(76.0		)
Proceeds from disposal of assets, net of notes receivable	—			14.1			5.1			19.2
Investments in equity affiliates and joint ventures	—			(15.0		)	(3.8		)	(18.8		)
Proceeds from sales of debt and equity securities	—			—			12.4			12.4
Purchases of debt and equity securities	—			—			(74.6		)	(74.6		)
Other, net	—			(8.7		)	(0.1		)	(8.8		)
Net cash used in continuing operations	—			(490.1		)	(204.4		)	(694.5		)
Net cash used in discontinued operations	—			—			(9.1		)	(9.1		)
Net cash used in investing activities	—			(490.1		)	(213.5		)	(703.6		)
Cash Flows From Financing Activities
Proceeds from long-term debt	1,150.0			—			—			1,150.0
Payments of long-term debt	(1,146.8		)	—			(20.5		)	(1,167.3		)
Dividends paid	(79.4		)	—			—			(79.4		)
Repurchase of employee common stock relinquished for tax withholding	(13.5		)	—			—			(13.5		)
Payment of debt issuance costs	(32.2		)	—			—			(32.2		)
Excess tax benefits related to share-based compensation	51.0			—			—			51.0
Other, net	22.3			(5.9		)	(2.1		)	14.3
Transactions with affiliates, net	724.6			(587.2		)	(137.4		)	—
Net cash provided by (used in) financing activities	676.0			(593.1		)	(160.0		)	(77.1		)
Net change in cash and cash equivalents	535.4			5.0			(234.0		)	306.4
Cash and cash equivalents at beginning of year	368.4			0.2			620.2			988.8
Cash and cash equivalents at end of year	$	903.8		$	5.2		$	386.2		$	1,295.2

PEABODY ENERGY CORPORATION

SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

	Year Ended December 31, 2009
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidated
				(Dollars in millions)
Cash Flows From Operating Activities
Net cash (used in) provided by continuing operations	$	(213.7	)	$	792.7		$	465.9		$	1,044.9
Net cash provided by (used in) discontinued operations	7.4			(5.3		)	3.2			5.3
Net cash (used in) provided by operating activities	(206.3		)	787.4			469.1			1,050.2
Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development	—			(313.3		)	(70.1		)	(383.4		)
Investment in Prairie State Energy Campus	—			(56.8		)	—			(56.8		)
Proceeds from disposal of assets, net of notes receivable	—			43.8			10.1			53.9
Investments in equity affiliates and joint ventures	—			(5.0		)	(10.0		)	(15.0		)
Other, net	—			(5.8		)	(0.3		)	(6.1		)
Net cash used in continuing operations	—			(337.1		)	(70.3		)	(407.4		)
Net cash provided by discontinued operations	—			—			0.9			0.9
Net cash used in investing activities	—			(337.1		)	(69.4		)	(406.5		)
Cash Flows From Financing Activities
Payments of long-term debt	—			—			(37.1		)	(37.1		)
Dividends paid	(66.8		)	—			—			(66.8		)
Repurchase of employee common stock relinquished for tax withholding	(2.3		)	—			—			(2.3		)
Other, net	8.7			—			(7.1		)	1.6
Transactions with affiliates, net	473.9			(454.6		)	(19.3		)	—
Net cash provided by (used in) financing activities	413.5			(454.6		)	(63.5		)	(104.6		)
Net change in cash and cash equivalents	207.2			(4.3		)	336.2			539.1
Cash and cash equivalents at beginning of year	161.2			4.5			284.0			449.7
Cash and cash equivalents at end of year	$	368.4		$	0.2		$	620.2		$	988.8

XML

Share-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2011

Share-Based Compensation (Tables) [Abstract]

Share-based compensation expense recorded in 'Selling and administrative expenses'

Share-based compensation expense and cash flow amounts were as follows:

	Year Ended December 31,
	2011		2010		2009
	(Dollars in millions)
Share-based compensation expense	$	43.9	$	41.1	$	38.8
Tax benefit	16.3		15.4		15.0
Share-based compensation expense, net of tax benefit	27.6		25.7		23.8
Cash received upon the exercise of stock options and from employee stock purchases	11.1		22.2		8.7
Excess tax benefits related to share-based compensation	8.1		51.0		—

Summary of restricted stock award activity

A summary of restricted stock award activity is as follows:

	Year Ended December 31, 2011		Weighted Average Grant-Date Fair Value
Nonvested at December 31, 2010	1,894,299		$	39.32
Granted	618,124		59.63
Vested	(849,464	)	42.38
Forfeited	(131,867	)	47.10
Nonvested at December 31, 2011	1,531,092		$	45.16

Schedule of Share-based Compensation, Stock Options, Activity

A summary of outstanding option activity under the plans is as follows:

	Year Ended December 31, 2011		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life	Aggregate Intrinsic Value (in millions)
Options Outstanding at December 31, 2010	1,916,301		$	32.25	5.9	$	61.2
Granted	223,307		64.52
Exercised	(254,828	)	18.57
Forfeited	—		—
Options Outstanding at December 31, 2011	1,884,780		$	37.92	5.6	$	11.0
Vested and Exercisable	1,301,607		$	32.53	4.5	$	10.0

Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions

The weighted-average fair values of the Company’s stock options and the assumptions used in applying the Black-Scholes option pricing model were as follows:

	Year Ended December 31,
	2011			2010			2009
Weighted-average fair value	$	33.92		$	25.70		$	26.84
Risk-free interest rate	2.0		%	2.8		%	1.5		%
Expected option life	5.0 years			5.0 years			5.0 years
Expected volatility	64		%	64		%	60		%
Dividend yield	0.6		%	0.6		%	0.9		%

Summary of performance unit activity

A summary of performance unit activity is as follows:

	Year Ended December 31, 2011		Weighted Average Remaining Contractual Life
Nonvested at December 31, 2010	386,662		1.5
Granted	122,590
Forfeited	—
Vested	(248,263	)
Nonvested at December 31, 2011	260,989		1.5

Assumptions used in the valuations for grants

The market condition awards were valued utilizing a Monte Carlo simulation which incorporates the total stockholder return hurdles set for each grant. The assumptions used in the valuations for grants were as follows:

	Year Ended December 31,
	2011		2010		2009
Risk-free interest rate	1.0	%	1.7	%	1.3	%
Expected volatility	64	%	64	%	60	%
Dividend yield	0.6	%	0.6	%	0.9	%

XML

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2011

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Asset Retirement Obligations

Reconciliations of the Company’s ARO liability are as follows:

	December 31,
	2011			2010
	(Dollars in millions)
Balance at beginning of year	$	490.7		$	447.6
Liabilities incurred or acquired	43.0			8.2
Liabilities settled or disposed	(8.8		)	(8.7		)
Accretion expense	28.7			26.4
Revisions to estimates	67.7			17.2
Balance at end of year	$	621.3		$	490.7
Balance at end of year — active locations	$	574.0		$	438.2
Balance at end of year — closed or inactive locations	$	47.3		$	52.5

The credit-adjusted, risk-free interest rates were 5.76%, 6.37%, and 7.92% at December 31, 2011, 2010 and 2009, respectively.

As of December 31, 2011 and 2010, the Company had $791.6 million and $704.4 million, respectively, in surety bonds and bank guarantees outstanding to secure reclamation obligations or activities. The amount of reclamation self-bonding in certain states in which the Company qualifies was $929.6 million and $920.3 million as of December 31, 2011 and 2010, respectively. Additionally, the Company had $0.1 million of letters of credit in support of reclamation obligations or activities as of December 31, 2010.

XML

Resource Management and Other Commercial Events (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011 mW	Dec. 31, 2010
Resource Management and Other Commercial Events (Textuals) [Abstract]
Recognized gain on coal reserves exchange	$ 37.7	$ 23.7
Project development fee received	14.6
Capacity of new electricity generation project, Megawatts	1,600
Cash proceeds from sale of non-strategic coal reserves	24.9
Notes receivables from sale of nonstrategic coal reserves	17.4
Gain recognized	$ 31.7

XML

Accumulated Other Comprehensive Income (Loss)

12 Months Ended

Dec. 31, 2011

Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]

Accumulated Other Comprehensive Income (Loss)

Accumulated Other Comprehensive Income (Loss)

The following table sets forth the after-tax components of comprehensive income (loss):

	Foreign Currency Translation Adjustment		Net Actuarial Loss Associated with Postretirement Plans and Workers’ Compensation Obligations			Prior Service Cost Associated with Postretirement Plans			Cash Flow Hedges			Available-For-Sale Securities			Total Accumulated Other Comprehensive Loss
	(Dollars in millions)
December 31, 2008	$	3.1	$	(220.4	)	$	(18.7	)	$	(152.5	)	$	—		$	(388.5	)
Net change in fair value	—		—			—			235.2			—			235.2
Reclassification from other comprehensive income to earnings	—		11.8			1.8			84.6			—			98.2
Current period change	—		(134.9		)	6.5			—			—			(128.4		)
December 31, 2009	3.1		(343.5		)	(10.4		)	167.3			—			(183.5		)
Net change in fair value	—		—			—			229.9			—			229.9
Reclassification from other comprehensive income to earnings	—		31.8			2.5			(102.4		)	—			(68.1		)
Current period change	—		(41.3		)	(4.9		)	—			—			(46.2		)
December 31, 2010	3.1		(353.0		)	(12.8		)	294.8			—			(67.9		)
Net change in fair value	—		—			—			291.9			(5.8		)	286.1
Reclassification from other comprehensive income to earnings	—		38.2			2.3			(251.0		)	(0.9		)	(211.4		)
Current period change	—		(150.1		)	0.9			—			—			(149.2		)
December 31, 2011	$	3.1	$	(464.9	)	$	(9.6	)	$	335.7		$	(6.7	)	$	(142.4	)

Comprehensive income (loss) differs from net income by the amount of unrealized gain or loss resulting from valuation changes of the Company’s cash flow hedges (see Note 6 and Note 7 for information related to the Company’s cash flow hedges), changes in the fair value of available-for-sale securities (see Note 5 for information related to the Company's investments in available-for-sale securities) and the change in actuarial loss and prior service cost during the periods. The values of the Company’s cash flow hedging instruments are primarily affected by changes in diesel fuel and coal prices, and the U.S. dollar/Australian dollar exchange rate.

XML

Postretirement Health Care and Life Insurance Benefits (Details 4) (Postretirement Health Care and Life Insurance Benefits [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2011
Postretirement Health Care and Life Insurance Benefits [Member]
Estimated Future Benefit Payments
Postretirement Benefits, 2012	$ 68.4
Postretirement Benefits, 2013	72.9
Postretirement Benefits, 2014	75.6
Postretirement Benefits, 2015	77.8
Postretirement Benefits, 2016	79.9
Postretirement Benefits, Years 2017-2021	$ 410.3

XML

Pension and Savings Plans (Tables) (Pension Plans, Defined Benefit [Member])

12 Months Ended

Dec. 31, 2011

Pension Plans, Defined Benefit [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Net periodic pension cost

Net periodic pension cost included the following components:

	Year Ended December 31,
	2011			2010			2009
	(Dollars in millions)
Service cost for benefits earned	$	1.7		$	1.5		$	1.4
Interest cost on projected benefit obligation	49.8			50.5			51.3
Expected return on plan assets	(64.4		)	(58.3		)	(60.9		)
Amortization of prior service cost	1.0			1.4			1.4
Amortization of actuarial losses	30.1			21.9			1.9
Total net periodic pension (benefit) cost	$	18.2		$	17.0		$	(4.9	)

Amounts recognized in accumulated other comprehensive loss

The following includes amounts recognized in accumulated other comprehensive loss:

	Year Ended December 31,
	2011			2010			2009
	(Dollars in millions)
Net actuarial loss arising during year	$	144.2		$	13.1		$	46.1
Amortization:
Actuarial loss	(30.1		)	(21.9		)	(1.9		)
Prior service cost	(1.0		)	(1.4		)	(1.4		)
Total recognized in other comprehensive loss	113.1			(10.2		)	42.8
Net periodic pension (benefit) cost	18.2			17.0			(4.9		)
Total recognized in net periodic pension cost and other comprehensive loss	$	131.3		$	6.8		$	37.9

Summary of change in benefit obligation, change in plan assets and funded status

The following summarizes the change in benefit obligation, change in plan assets and funded status of the Company’s plans:

	December 31,
	2011			2010
	(Dollars in millions)
Change in benefit obligation:
Projected benefit obligation at beginning of period	$	881.0		$	844.9
Service cost	1.7			1.5
Interest cost	49.8			50.5
Benefits paid	(52.8		)	(50.4		)
Actuarial loss	83.9			34.5
Projected benefit obligation at end of period	963.6			881.0
Change in plan assets:
Fair value of plan assets at beginning of period	771.6			629.6
Actual return on plan assets	4.1			79.8
Employer contributions	46.7			112.6
Benefits paid	(52.8		)	(50.4		)
Fair value of plan assets at end of period	769.6			771.6
Funded status at end of year	$	(194.0	)	$	(109.4	)
Amounts recognized in the consolidated balance sheets:
Current obligation (included in Accounts payable and accrued expenses)	$	(1.7	)	$	(1.8	)
Noncurrent obligation (included in Other noncurrent liabilities)	(192.3		)	(107.6		)
Net amount recognized	$	(194.0	)	$	(109.4	)

Weighted-average assumptions used to determine benefit obligations

The weighted-average assumptions used to determine the benefit obligations as of the end of each year were as follows:

	December 31,
	2011		2010
Discount rate	5.00	%	5.84	%
Measurement date	December 31, 2011		December 31, 2010

Weighted-average assumptions used to determine net periodic benefit cost

The weighted-average assumptions used to determine net periodic benefit cost during each year were as follows:

	Year Ended December 31,
	2011		2010		2009
Discount rate	5.84	%	6.19	%	6.90	%
Expected long-term return on plan assets	8.25	%	8.25	%	8.75	%
Measurement date	December 31, 2010		December 31, 2009		December 31, 2008

Fair value of assets in the Master Trust by category and by fair value valuation hierarchy

The following tables present the fair value of assets in the Master Trust by asset category and by fair value hierarchy:

	December 31, 2011
	Level 1		Level 2		Level 3		Total
	(Dollars in millions)
U.S. equity securities	$	—	$	340.4	$	—	$	340.4
International equity securities	—		107.8		—		107.8
Mortgage-backed debt securities	—		98.9		—		98.9
U.S. debt securities	—		83.3		—		83.3
International debt securities	—		32.0		—		32.0
Corporate debt securities	—		45.8		—		45.8
Short-term investments	—		36.1		—		36.1
Interests in real estate	—		—		25.3		25.3
Total assets at fair value	$	—	$	744.3	$	25.3	$	769.6

	December 31, 2010
	Level 1		Level 2		Level 3		Total
	(Dollars in millions)
U.S. equity securities	$	82.6	$	250.5	$	—	$	333.1
International equity securities	—		118.9		—		118.9
Mortgage-backed debt securities	—		108.8		—		108.8
U.S. debt securities	—		60.2		—		60.2
International debt securities	—		25.7		—		25.7
Corporate debt securities	—		46.1		—		46.1
Short-term investments	—		31.1		—		31.1
Interests in real estate	—		—		47.7		47.7
Total assets at fair value	$	82.6	$	641.3	$	47.7	$	771.6

Summary of changes in the fair value of the Master Trust's Level 3 investments

The table below sets forth a summary of changes in the fair value of the Master Trust’s Level 3 investments:

	Year Ended December 31,
	2011			2010
	(Dollars in millions)
Beginning of year	$	47.7		$	47.4
Assets held at the reporting date:
Realized losses	(8.9		)	(0.1		)
Unrealized gains, net	11.4			1.3
Purchases, sales and settlements, net	(24.9		)	(0.9		)
End of year	$	25.3		$	47.7

Summary of estimated future benefit payments

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid by the Master Trust:

	Pension Benefits
	(Dollars in millions)
2012	$	56.7
2013	58.0
2014	59.8
2015	61.8
2016	63.6
Years 2017-2021	333.3

XML

Stockholders' Equity (Details) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Summary of common stock activity
Shares outstanding at the beginning of the year	270.2	268.2	266.6
Stock options exercised	0.3	1.5	0.5
Stock grants to employees	0.7	0.6	0.8
Employee stock purchases	0.2	0.2	0.4
Shares relinquished	(0.3)	(0.3)	(0.1)
Shares outstanding at the end of the year	271.1	270.2	268.2

XML

Derivatives and Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2011

Derivative [Line Items]

Fair value measured on recurring basis of financial assets and liabilities

The following tables set forth the hierarchy of the Company’s net financial asset (liability) positions for which fair value is measured on a recurring basis:

	December 31, 2011
	Level 1		Level 2		Level 3		Total
			(Dollars in millions)
Investment in debt and equity securities	$	83.5	$	—	$	—	$	83.5
Commodity swaps and options	—		33.0		—		33.0
Foreign currency cash flow hedge contracts	—		490.6		—		490.6
Total net financial assets	$	83.5	$	523.6	$	—	$	607.1

	December 31, 2010
	Level 1		Level 2		Level 3		Total
			(Dollars in millions)
Investment in debt securities	$	17.9	$	—	$	—	$	17.9
Commodity swaps and options	—		40.2		—		40.2
Foreign currency cash flow hedge contracts	—		640.1		—		640.1
Total net financial assets	$	17.9	$	680.3	$	—	$	698.2

Carrying amounts and estimated fair values of the Company's debt

The carrying amounts and estimated fair values of the Company’s debt are summarized as follows:

	December 31, 2011				December 31, 2010
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
			(Dollars in millions)
Long-term debt	$	6,657.5	$	6,922.7	$	2,750.0	$	2,960.0

Non Coal Trading [Member]

Derivative [Line Items]

Company's foreign currency and commodity positions

Notional Amounts and Fair Value.  The following summarizes the Company’s foreign currency and commodity positions at December 31, 2011:

	Notional Amount by Year of Maturity
	Total		2012		2013		2014		2015		2016		2017 and thereafter
Foreign Currency
A$:US$ hedge contracts (A$ millions)	$	3,910.6	$	1,750.5	$	1,309.6	$	850.5	$	—	$	—	$	—
GBP:US$ hedge contracts (GBP millions)	6.5		6.5		—		—		—		—		—
Commodity Contracts
Diesel fuel hedge contracts (million gallons)	189.6		86.0		68.0		35.6		—		—		—
U.S. explosives hedge contracts (million MMBtu)	7.7		3.9		2.6		1.2		—		—		—

	Account Classification by
	Cash Flow Hedge		Fair Value Hedge		Economic Hedge		Fair Value Asset (Liability)
							(Dollars in millions)
Foreign Currency
A$:US$ hedge contracts (A$ millions)	$	3,910.6	$	—	$	—	$	491.3
GBP:US$ hedge contracts (GBP millions)	6.5		—		—		(0.7		)
Commodity Contracts
Diesel fuel hedge contracts (million gallons)	189.6		—		—		$	43.7
U.S. explosives hedge contracts (million MMBtu)	7.7		—		—		$	(10.7	)

Classification and amounts of pre-tax gains and losses related to the Company's non-trading hedges

The tables below show the classification and amounts of pre-tax gains and losses related to the Company’s non-trading hedges during the years ended December 31, 2011, 2010 and 2009:

		Year Ended December 31, 2011
	Income Statement Classification Gains (Losses) - Realized	Gain (loss) recognized in income on non- designated derivatives(1)			Gain (loss) recognized in other comprehensive income on derivative (effective portion)			Gain (loss) reclassified from other comprehensive income into income (effective portion)		Gain (loss) reclassified from other comprehensive income into income (ineffective portion)
Financial Instrument
		(Dollars in millions)
Commodity swaps and options	Operating costs and expenses	$	—		$	30.7		$	42.7	$	4.8
Foreign currency cash flow hedge contracts:
- Operating costs	Operating costs and expenses	—			193.4			342.2		—
- Capital expenditures	Depreciation, depletion and amortization	—			(0.5		)	—		—
Foreign currency economic hedge contracts	Acquisition costs related to Macarthur Coal Limited	$	(32.8	)	$	—		$	—	$	—
Total		$	(32.8	)	$	223.6		$	384.9	$	4.8

⁽¹⁾  Relates to foreign currency contracts associated with the acquisition of Macarthur shares under the takeover process.

		Year Ended December 31, 2010
	Income Statement Classification Gains (Losses) - Realized	Gain (loss) recognized in income on non- designated derivatives(2)			Gain (loss) recognized in other comprehensive income on derivative (effective portion)		Gain (loss) reclassified from other comprehensive income into income (effective portion)			Gain (loss) reclassified from other comprehensive income into income (ineffective portion)
Financial Instrument
		(Dollars in millions)
Interest rate swaps cash flow hedge contracts	Interest expense	$	(8.5	)	$	0.8	$	(0.5	)	$	—
Commodity swaps and options	Operating costs and expenses	—			29.9		(36.2		)	(1.1		)
Foreign currency cash flow hedge contracts	Operating costs and expenses	—			622.2		188.2			—
Total		$	(8.5	)	$	652.9	$	151.5		$	(1.1	)

⁽²⁾  Amounts relate to swaps that were de-designated and terminated in conjunction with the refinancing of the Company's previous credit facility.

		Year Ended December 31, 2009
	Income Statement Classification Gains (Losses) - Realized	Gain (loss) recognized in income on non- designated derivatives(3)			Gain (loss) recognized in other comprehensive income on derivative (effective portion)		Gain (loss) reclassified from other comprehensive income into income (effective portion)			Gain (loss) reclassified from other comprehensive income into income (ineffective portion)
Financial Instrument
		(Dollars in millions)
Interest rate swaps cash flow hedge contracts	Interest expense	$	—		$	0.2	$	(5.5	)	$	—
Commodity swaps and options:
- Cash flow hedges	Operating costs and expenses	—			65.5		(98.3		)	0.7
- Economic hedges	Operating costs and expenses	(2.7		)	—		—			—
Foreign currency cash flow hedge contracts	Operating costs and expenses	—			458.0		(30.8		)	—
Total		$	(2.7	)	$	523.7	$	(134.6	)	$	0.7

⁽³⁾  Amounts relate to diesel fuel and explosives hedge derivatives that were de-designated in 2009.

Classification and amount of derivatives, gross

The classification and amount of derivatives presented on a gross basis as of December 31, 2011 and 2010 are as follows:

	Fair Value as of December 31, 2011
	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
Financial Instrument
	(Dollars in millions)
Commodity swaps and options	$	43.4	$	11.7	$	7.1	$	15.0
Foreign currency cash flow hedge contracts	270.4		229.0		4.3		4.5
Total	$	313.8	$	240.7	$	11.4	$	19.5

	Fair Value as of December 31, 2010
	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
Financial Instrument
	(Dollars in millions)
Commodity swaps and options	25.8		27.0		12.0		0.6
Foreign currency cash flow hedge contracts	273.5		366.6		—		—
Total	$	299.3	$	393.6	$	12.0	$	0.6

XML

Share-Based Compensation (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Share-Based Compensation (Details) [Abstract]
Share-based compensation expense	$ 43.9	$ 41.1	$ 38.8
Tax benefit	16.3	15.4	15.0
Share-based compensation expense, net of tax benefit	27.6	25.7	23.8
Cash received upon the exercise of stock options and from employee stock purchases	11.1	22.2	8.7
Excess tax benefits related to share-based compensation	$ 8.1	$ 51.0	$ 0

XML

Consolidated Balance Sheets (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Current assets
Allowance for doubtful accounts receivable, current	$ 17.0	$ 30.3
Stockholders' equity
Common Stock, par value	$ 0.01
Common Stock, shares authorized	800,000,000
Common Stock, shares outstanding	271,100,000	270,200,000
Treasury Stock, shares	9,200,000	8,900,000
Preferred Stock [Member]
Stockholders' equity
Preferred Stock, par value	$ 0.01	$ 0.01
Preferred Stock, shares authorized	10,000,000	10,000,000
Preferred Stock, shares issued	0	0
Preferred Stock, shares outstanding	0	0
Series A Junior Participating Preferred Stock [Member]
Stockholders' equity
Preferred Stock, par value	$ 0.01	$ 0.01
Preferred Stock, shares authorized	1,500,000	1,500,000
Preferred Stock, shares issued	0	0
Preferred Stock, shares outstanding	0	0
Perpetual Preferred Stock Member
Stockholders' equity
Preferred Stock, shares authorized	800,000	800,000
Preferred Stock, shares issued	0	0
Preferred Stock, shares outstanding	0	0
Series Common Stock Member
Stockholders' equity
Common Stock, par value	$ 0.01	$ 0.01
Common Stock, shares authorized	40,000,000	40,000,000
Common Stock, shares issued	0	0
Common Stock, shares outstanding	0	0
Common Stock [Member]
Stockholders' equity
Common Stock, par value	$ 0.01	$ 0.01
Common Stock, shares authorized	800,000,000	800,000,000
Common Stock, shares issued	280,300,000	279,100,000
Common Stock, shares outstanding	271,100,000	270,200,000

XML

Debt (Details Textuals)	12 Months Ended						12 Months Ended						12 Months Ended								12 Months Ended			12 Months Ended			12 Months Ended									12 Months Ended
	Dec. 31, 2011 USD ($) years	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)	Feb. 07, 2011 USD ($)	Dec. 31, 2010 AUD	Jun. 18, 2010 USD ($)	Dec. 31, 2011 Minimum [Member] days	Dec. 31, 2011 Maximum [Member] days	Dec. 31, 2011 Convertible Debt [Member]	Dec. 31, 2011 2011 Term Loan Facility [Member] USD ($)	Oct. 28, 2011 2011 Term Loan Facility [Member] USD ($)	Dec. 31, 2010 2011 Term Loan Facility [Member] USD ($)	Dec. 31, 2011 5.875% Senior Notes due April 2016 [Member] USD ($)	Apr. 15, 2011 5.875% Senior Notes due April 2016 [Member] USD ($)	Dec. 31, 2010 5.875% Senior Notes due April 2016 [Member] USD ($)	Dec. 31, 2011 6.875% Senior Notes due March 2013 [Member] USD ($)	Dec. 31, 2011 6.00% Senior Notes due November 2018 [Member] USD ($)	Dec. 31, 2010 6.00% Senior Notes due November 2018 [Member] USD ($)	Dec. 31, 2011 6.25% Senior Notes due November 2021 [Member] USD ($)	Dec. 31, 2010 6.25% Senior Notes due November 2021 [Member] USD ($)	Dec. 31, 2011 6.5% Senior Notes due September 2020 [Member] USD ($)	Dec. 31, 2010 6.5% Senior Notes due September 2020 [Member] USD ($)	Aug. 25, 2010 6.5% Senior Notes due September 2020 [Member] USD ($)	Dec. 31, 2011 7.875% Senior Notes due November 2026 [Member] USD ($)	Dec. 31, 2010 7.875% Senior Notes due November 2026 [Member] USD ($)	Dec. 31, 2011 Federal Funds Rate [Member]	Dec. 31, 2011 Libor Rate [Member]	Dec. 31, 2011 Revolving Credit Facility [Member] USD ($)	Jun. 18, 2010 Revolving Credit Facility [Member] USD ($)	Dec. 31, 2009 Revolving Credit Facility [Member] USD ($)	Jun. 18, 2010 Term Loan Facility [Member] USD ($)	Dec. 31, 2009 Term Loan Facility [Member] USD ($)	Jun. 18, 2010 Swingline Sub-facility [Member] USD ($)	Dec. 31, 2011 Corporate Funding Facility [Member] AUD	Jun. 18, 2010 Corporate Funding Facility [Member] AUD	Dec. 31, 2011 Base Rate [Member]	Dec. 31, 2011 Base Rate [Member] Term Loan Facility [Member]	Dec. 31, 2011 Eurocurrency Rate [Member]
Line of Credit Facility [Line Items]
Long-term debt	$ 6,556,400,000	$ 2,706,800,000
Corporate Funding Facility, maximum borrowing capacity						2,000,000,000																							1,500,000,000	1,800,000,000	500,000,000		50,000,000	330,000,000
Long-term debt										1,000,000,000	1,000,000,000	0	0		218,100,000		1,600,000,000	0	1,500,000,000	0	650,000,000	650,000,000		247,300,000	247,200,000
Applicable margin added to rate																										0.50%	1.00%
Letters of credit outstanding																												21,000,000
Leverage ratio rate adjustment for borrowing under credit facility, minimum rate																											1.75%									1.30%	0.75%	2.25%
Previous term loan facility balance					360,000,000																											490,300,000
Unamortized debt issuance expense which will be amortized to interest expense over the next five years	69,200,000
Maximum borrowing capacity under credit facility											1,000,000,000
Leverage ratio rate adjustment for borrowing under credit facility, maximum rate																											3.00%									2.50%	2.00%	3.50%
Term loan, quarterly amortization percentage	1.25%
Interest Rate													5.875%	5.875%		6.875%	6.00%		6.25%		6.50%			7.875%
Extinguishment of Series Bonds																650,000,000
Optional Additional Borrowing capacity under revolving credit facility	250,000,000
Minimum amount of revolving credit facility increase	25,000,000																							250,000,000
Deferred financing costs recorded by the Company	99,900,000																												21,900,000
Proceeds from issuance of senior notes																							650,000,000
Refinancing charges classified as interest expense	9,300,000
Letter of credit fee as a percentage of the undrawn amount of each letter of credit, Higher range	3.50%
Letter of credit fee as a percentage of the undrawn amount of each letter of credit, Lower range	2.25%
Fronting fee as a percentage of the face amount of each letter of credit	0.125%
Term loan facility											1,000,000,000
Term loan facility percentage of quarterly repayment	1.25%
Commitment fee as a percent of the available unused commitment, maximum	0.50%
Commitment fee as a percent of the available unused commitment, minimum	0.375%
Remaining borrowing capacity under revolving credit facility																												1,500,000,000						200,000,000
Interest rate over and above LIBOR rate under the credit facility for the Revolver and Term - Loan	2.00%																											2.25%
Effective Interest Rate under the credit facility for the Revolver and Term - Loan	2.26%																											2.51%
Net proceeds from the issuance of the Notes	4,101,400,000	1,150,000,000	0																		641,900,000
Extinguishment of debt	8,400,000												1,700,000
Redemption price of notes as percentage of principal amount plus a make-whole premium and any accrued unpaid interest to the redemption date														100.979%
Redemption price of bonds as percentage of principal amount plus a make-whole premium and any accrued unpaid interest to the redemption date	100.00%
Aggregate principal outstanding of Convertible Junior Subordinated Debentures	732,500,000													218,100,000
Semiannual interest rate of Convertible Junior Subordinated Debentures	4.75%
Events triggering payment of deferred interest on debentures	After five years of deferral at the Company’s option, or upon the occurrence of a mandatory trigger event
Interest payments on debentures, maximum deferral period (years)	10
Debt Instrument Convertible Conversion Rate Per Share				$ 17.1846
130% Current conversion price of debentures (per share)	$ 75.65
Period of redemption of debentures	at least 20 out of the 30 consecutive trading days immediately prior to the date on which notice of redemption is given
Condition to convert debentures - percentage closing common stock price exceeds conversion price	140.00%
140% Current conversion price of debentures (per share)	$ 81.47
Number of days percentage closing common stock price exceeds conversion price							20	30
Adjusted conversion rate of debentures (per principal amount of debentures)				1,000
Adjusted Conversion Price Of Debentures Per Share				$ 58.19
Condition to convert debentures - percentage closing common stock price exceeds conversion price from Dec. 20, 2011 to Dec. 19, 2036	130.00%
Redemption price of debt as percentage of the principal amount of the debentures	101.00%								100.00%
Maximum percentage of the company's net cash proceeds from the sale of its common stock and rights to acquire common stock which can be used for repayment of debt	400.00%
Interest paid on long-term debt	205,300,000	197,900,000	201,600,000
Line of Credit Facility, Amount Outstanding																																			0
Sub-limit for bank guarantees																																		130,000,000
Letters of credit and cash backed bank guarantees																																		65,000,000
Remaining period of discount amortization	30
Debt Instrument, Default Periodic Rate Change	0.25%
Debt Instrument, Default Rate Change, Maximum	1.00%

XML

Acquisition of Macarthur Coal Limited

12 Months Ended

Dec. 31, 2011

Business Combinations [Abstract]

Acquisition of Macarthur Coal Limited

Acquisition of Macarthur Coal Limited

On October 23, 2011, PEAMCoal Pty Ltd (PEAMCoal), an Australian company that was then indirectly owned 60% by the Company and 40% by ArcelorMittal, acquired a majority interest in Macarthur Coal Limited (Macarthur) through an all cash off-market takeover offer. On October 26, 2011 (the acquisition and control date), the Company appointed its nominees to the Macarthur Board of Directors and executive management team. The acquisition was completed on December 20, 2011 as PEAMCoal acquired all of Macarthur's remaining outstanding shares of common stock for $4.8 billion, net of $261.2 million of acquired cash, of which the Company's share was $2.8 billion. PEAMCoal accounted for share acceptances under the takeover process as a single transaction occurring on October 26, 2011. On December 21, 2011, the Company acquired ArcelorMittal Mining Australasia B.V., an indirect subsidiary of ArcelorMittal that indirectly owned 40% of PEAMCoal, for $2.0 billion resulting in the Company's 100% ownership of Macarthur.

The Macarthur acquisition includes a 73.3% undivided interest in the assets and liabilities of Coppabella and Moorvale operating mines and the Codrilla Mine Project. It also includes a 50% interest in the Middlemount Mine and a prospective portfolio of coal mining assets at various stages of development and exploration. The acquisition expands the Company's Australian mining platform to serve the seaborne coal markets.

The Company funded the acquisition and purchase of noncontrolling interests using available cash on hand, cash proceeds from a new term loan facility of $1.0 billion and proceeds from the issuance of $3.1 billion aggregate principal amount of senior notes. The Company recorded $55.6 million in deferred financing costs associated with this debt, which are being amortized over the remaining term of the related debt. See Note 11 for information related to the Company's long-term debt.

The preliminary purchase accounting allocations have been recorded in the accompanying consolidated financial statements as of, and for the period subsequent to the acquisition and control date. The final valuation of the net assets acquired is expected to be finalized once third-party valuation appraisals are completed. The following table summarizes the preliminary estimated fair values of assets acquired and liabilities assumed that were recognized at the acquisition and control date (Dollars in millions):

Accounts receivable, net	$	106.6
Inventories	67.1
Other current assets	137.5
Property, plant, equipment and mine development	3,457.0
Investments and other assets	1,275.1
Current maturities of long-term debt	(11.0		)
Accounts payable and accrued expenses	(133.8		)
Long-term debt, less current maturities	(59.2		)
Asset retirement obligations	(39.3		)
Other noncurrent liabilities	(31.4		)
Noncontrolling interests	(2,011.9		)
Total purchase price, net of cash acquired of $261.2	$	2,756.7

Cash, accounts receivables, accounts payable and other current assets and liabilities were stated at their historical carrying values, which approximated fair value given their short-term nature. The Company is evaluating mine lives and reviewing coal reserve studies on the acquired properties, the outcome of which will determine the fair value allocated to coal reserve assets. In connection with acquisition of Macarthur, the Company acquired contract based intangibles consisting of port, rail and water take-or-pay obligations and recorded a liability of $30.5 million, net of tax. The liability is being amortized based on unutilized capacity over the terms of the applicable agreements, which extend to 2018.

Included in "Accounts receivable, net," "Other current assets" and "Investments and other assets" above are $34.5 million, $66.6 million and $234.9 million, respectively, of certain financing receivables that were acquired as part of the acquisition of Macarthur. For further discussion of these financing receivables, see Note 8.

Included in "Investments and other assets" is $368.9 million representing the balance of a loan facility agreement with MCG Coal Holdings Pty Ltd (MCGH). Macarthur had previously agreed to convert its receivable for a 90% equity interest in MCGH. The transaction was expected to be completed in May 2011. However, non-performance by a third party to the transaction resulted in Macarthur commencing litigation. The original loan balance was classified as a receivable pending the outcome of the legal proceedings. Subsequent to December 31, 2011, the court ruled that the outstanding loan balance is to be converted to a 90% equity interest. For further discussion of contingencies assumed as part of the acquisition of Macarthur, see Note 23.

Macarthur contributed revenues of $152.9 million and a loss net of income taxes of $47.9 million from the acquisition and control date to December 31, 2011, excluding the acquisition costs noted below and the interest expense associated with the debt secured to finance the acquisition. The results of Macarthur for the period from the acquisition and control date are included in the consolidated statements of income and are reported in the Australian Mining segment in Note 25, except for the activity associated with certain equity affiliate investments, which is reflected in the Corporate and Other segment.

In 2011, the Company recorded acquisition costs of $85.2 million, which primarily consisted of professional fees, losses on derivatives associated with the acquisition of Macarthur shares and Australian stamp duty associated with the acquisition. These acquisition costs are recorded in the “Acquisition Costs Related to Macarthur Coal Limited” line item in the consolidated statements of income. The Company also recognized $16.2 million of interest expense associated with bridge financing for the Macarthur acquisition.

The following unaudited pro forma financial information presents the combined results of operations of the Company and Macarthur, on a pro forma basis, as though the companies had been combined as of January 1, 2010. The pro forma financial information does not necessarily reflect the results of operations that would have occurred had the Company and Macarthur constituted a single entity during those periods or that may be attained in the future.

	Year Ended December 31,
	2011		2010
	(Dollars in millions, except earnings per share)
Revenue	$	8,696.5	$	7,579.5
Income from continuing operations, net of income taxes	1,046.7		781.5
Basic earnings per share	3.67		2.80
Diluted earnings per share	3.65		2.77

The pro forma income from continuing operations, net of income taxes includes adjustments to operating costs to reflect the additional expense for the estimated impact of the fair value adjustment for coal inventory, the estimated impact on depreciation, depletion and amortization for the fair value adjustment for property, plant and equipment (including mineral rights) and additional expense for the estimated impact of reflecting the equity affiliate interest at its estimated fair value.

XML

Supplemental Guarantor/Non-Guarantor Financial Information (Tables)

12 Months Ended

Dec. 31, 2011

Supplemental Guarantor Non Guarantor Financial Information [Abstract]

Unaudited Supplemental Condensed Consolidating Statements of Operations

SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF INCOME

	Year Ended December 31, 2011
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(Dollars in millions)
Total revenues	$	—		$	4,758.4		$	3,509.4		$	(293.4	)	$	7,974.4
Costs and expenses
Operating costs and expenses	(386.3		)	3,598.6			2,631.1			(293.4		)	5,550.0
Depreciation, depletion and amortization	—			297.4			184.8			—			482.2
Asset retirement obligation expense	—			36.2			16.9			—			53.1
Selling and administrative expenses	34.0			215.0			19.2			—			268.2
Acquisition costs related to Macarthur Coal Limited	32.8			31.2			21.2			—			85.2
Other operating (income) loss:
Net gain on disposal or exchange of assets	—			(73.2		)	(3.7		)	—			(76.9		)
(Income) loss from equity affiliates	(881.5		)	8.6			10.6			881.5			19.2
Interest expense	243.1			47.3			67.2			(119.0		)	238.6
Interest income	(50.9		)	(31.1		)	(55.9		)	119.0			(18.9		)
Unrealized (gain) loss on derivatives	—			(1.3		)	1.3			—			—
Income from continuing operations before income taxes	1,008.8			629.7			616.7			(881.5		)	1,373.7
Income tax provision	46.5			172.0			144.7			—			363.2
Income from continuing operations, net of income taxes	962.3			457.7			472.0			(881.5		)	1,010.5
Loss from discontinued operations, net of income taxes	(4.6		)	(3.1		)	(56.5		)	—			(64.2		)
Net income	957.7			454.6			415.5			(881.5		)	946.3
Less: Net loss attributable to noncontrolling interests	—			—			(11.4		)	—			(11.4		)
Net income attributable to common stockholders	$	957.7		$	454.6		$	426.9		$	(881.5	)	$	957.7

PEABODY ENERGY CORPORATION

SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF INCOME

	Year Ended December 31, 2010
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(Dollars in millions)
Total revenues	$	—		$	3,596.1		$	3,916.9		$	(773.1	)	$	6,739.9
Costs and expenses
Operating costs and expenses	(145.1		)	2,472.7			3,142.8			(773.1		)	4,697.3
Depreciation, depletion and amortization	—			294.1			143.0			—			437.1
Asset retirement obligation expense	—			31.9			15.3			—			47.2
Selling and administrative expenses	31.6			194.3			6.3			—			232.2
Other operating (income) loss:
Net (gain) loss on disposal or exchange of assets	—			(34.5		)	4.5			—			(30.0		)
(Income) loss from equity affiliates	(838.4		)	7.1			6.0			827.0			1.7
Interest expense	219.7			52.7			17.9			(68.3		)	222.0
Interest income	(18.8		)	(21.8		)	(37.3		)	68.3			(9.6		)
Income from continuing operations before income taxes	751.0			599.6			618.4			(827.0		)	1,142.0
Income tax (benefit) provision	(24.2		)	183.3			156.3			—			315.4
Income from continuing operations, net of income taxes	775.2			416.3			462.1			(827.0		)	826.6
Loss from discontinued operations, net of income taxes	(1.2		)	(23.2		)	—			—			(24.4		)
Net income	774.0			393.1			462.1			(827.0		)	802.2
Less: Net income attributable to noncontrolling interests	—			—			28.2			—			28.2
Net income attributable to common stockholders	$	774.0		$	393.1		$	433.9		$	(827.0	)	$	774.0

PEABODY ENERGY CORPORATION

SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF INCOME

	Year Ended December 31, 2009
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(Dollars in millions)
Total revenues	$	—		$	4,283.9		$	2,312.5		$	(749.4	)	$	5,847.0
Costs and expenses
Operating costs and expenses	104.4			3,250.4			1,733.8			(749.4		)	4,339.2
Depreciation, depletion and amortization	—			282.9			117.6			—			400.5
Asset retirement obligation expense	—			33.1			6.8			—			39.9
Selling and administrative expenses	29.3			164.2			5.6			—			199.1
Other operating (income) loss:
Net gain on disposal or exchange of assets	—			(17.1		)	(6.1		)	—			(23.2		)
(Income) loss from equity affiliates	(620.9		)	6.3			62.8			620.9			69.1
Interest expense	198.4			52.5			16.2			(66.0		)	201.1
Interest income	(15.3		)	(28.9		)	(29.9		)	66.0			(8.1		)
Income from continuing operations before income taxes	304.1			540.5			405.7			(620.9		)	629.4
Income tax (benefit) provision	(122.3		)	176.5			132.0			—			186.2
Income from continuing operations, net of income taxes	426.4			364.0			273.7			(620.9		)	443.2
Income (loss) from discontinued operations, net of income taxes	21.8			12.0			(14.0		)	—			19.8
Net income	448.2			376.0			259.7			(620.9		)	463.0
Less: Net income attributable to noncontrolling interests	—			—			14.8			—			14.8
Net income attributable to common stockholders	$	448.2		$	376.0		$	244.9		$	(620.9	)	$	448.2

Unaudited Supplemental Condensed Consolidating Balance Sheet

SUPPLEMENTAL CONDENSED CONSOLIDATING BALANCE SHEETS

	December 31, 2011
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Reclassifications/ Eliminations			Consolidated
	(Dollars in millions)
Assets
Current assets
Cash and cash equivalents	$	283.2		$	0.8		$	515.1		$	—		$	799.1
Accounts receivable, net	5.3			100.8			816.4			—			922.5
Inventories	—			220.0			226.3			—			446.3
Assets from coal trading activities, net	—			14.9			29.7			—			44.6
Deferred income taxes	—			48.0			—			(20.7		)	27.3
Other current assets	305.1			98.8			362.2			—			766.1
Total current assets	593.6			483.3			1,949.7			(20.7		)	3,005.9
Property, plant, equipment and mine development
Land and coal interests	—			5,061.8			5,719.2			—			10,781.0
Buildings and improvements	—			962.8			168.6			—			1,131.4
Plant and equipment	—			1,507.3			1,355.1			—			2,862.4
Less: accumulated depreciation, depletion and amortization	—			(2,623.1		)	(789.0		)	—			(3,412.1		)
Property, plant, equipment and mine development, net	—			4,908.8			6,453.9			—			11,362.7
Investments and other assets	10,300.8			199.7			1,496.1			(9,632.2		)	2,364.4
Total assets	$	10,894.4		$	5,591.8		$	9,899.7		$	(9,652.9	)	$	16,733.0
Liabilities and Stockholders’ Equity
Current liabilities
Current maturities of long-term debt	$	62.5		$	—		$	38.6		$	—		$	101.1
Payables to (receivables from) affiliates, net	2,417.8			(2,529.1		)	111.3			—			—
Liabilities from coal trading activities, net	—			4.2			6.1			—			10.3
Deferred income taxes	11.6			—			9.1			(20.7		)	—
Accounts payable and accrued expenses	69.4			868.8			774.1			—			1,712.3
Total current liabilities	2,561.3			(1,656.1		)	939.2			(20.7		)	1,823.7
Long-term debt, less current maturities	6,428.8			—			127.6			—			6,556.4
Deferred income taxes	76.0			126.3			351.9			—			554.2
Notes payable to (receivables from) affiliates, net	(3,720.0		)	(981.5		)	4,701.5			—			—
Other noncurrent liabilities	63.2			1,892.6			327.1			—			2,282.9
Total liabilities	5,409.3			(618.7		)	6,447.3			(20.7		)	11,217.2
Peabody Energy Corporation’s stockholders’ equity	5,485.1			6,210.5			3,421.7			(9,632.2		)	5,485.1
Noncontrolling interests	—			—			30.7			—			30.7
Total stockholders’ equity	5,485.1			6,210.5			3,452.4			(9,632.2		)	5,515.8
Total liabilities and stockholders’ equity	$	10,894.4		$	5,591.8		$	9,899.7		$	(9,652.9	)	$	16,733.0

PEABODY ENERGY CORPORATION

SUPPLEMENTAL CONDENSED CONSOLIDATING BALANCE SHEETS

	December 31, 2010
	Parent Company		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Reclassifications/ Eliminations			Consolidated
			(Dollars in millions)
Assets
Current assets
Cash and cash equivalents	$	903.8	$	5.2		$	386.2		$	—		$	1,295.2
Accounts receivable, net	2.1		5.5			548.2			—			555.8
Inventories	—		168.0			159.2			—			327.2
Assets from coal trading activities, net	—		23.8			168.7			—			192.5
Deferred income taxes	—		78.6			47.9			(6.1		)	120.4
Other current assets	307.9		30.7			128.5			—			467.1
Total current assets	1,213.8		311.8			1,438.7			(6.1		)	2,958.2
Property, plant, equipment and mine development
Land and coal interests	—		4,860.7			2,773.1			—			7,633.8
Buildings and improvements	—		945.8			121.6			—			1,067.4
Plant and equipment	—		1,300.6			363.9			—			1,664.5
Less: accumulated depreciation, depletion and amortization	—		(2,374.4		)	(613.2		)	—			(2,987.6		)
Property, plant, equipment and mine development, net	—		4,732.7			2,645.4			—			7,378.1
Investments and other assets	9,331.0		179.8			147.1			(8,631.1		)	1,026.8
Total assets	$	10,544.8	$	5,224.3		$	4,231.2		$	(8,637.2	)	$	11,363.1
Liabilities and Stockholders’ Equity
Current liabilities
Current maturities of long-term debt	$	25.0	$	—		$	18.2		$	—		$	43.2
Payables to (receivables from) affiliates, net	2,225.3		(2,528.3		)	303.0			—			—
Liabilities from coal trading activities, net	—		29.5			152.2			—			181.7
Deferred income taxes	6.1		—			—			(6.1		)	—
Accounts payable and accrued expenses	47.4		777.2			464.2			—			1,288.8
Total current liabilities	2,303.8		(1,721.6		)	937.6			(6.1		)	1,513.7
Long-term debt, less current maturities	2,609.6		0.1			97.1			—			2,706.8
Deferred income taxes	93.2		135.4			316.5			—			545.1
Notes payable to (receivables from) affiliates, net	818.9		(825.3		)	6.4			—			—
Other noncurrent liabilities	58.6		1,652.8			196.8			—			1,908.2
Total liabilities	5,884.1		(758.6		)	1,554.4			(6.1		)	6,673.8
Peabody Energy Corporation’s stockholders’ equity	4,660.7		5,982.9			2,648.2			(8,631.1		)	4,660.7
Noncontrolling interests	—		—			28.6			—			28.6
Total stockholders’ equity	4,660.7		5,982.9			2,676.8			(8,631.1		)	4,689.3
Total liabilities and stockholders’ equity	$	10,544.8	$	5,224.3		$	4,231.2		$	(8,637.2	)	$	11,363.1

Unaudited Supplemental Condensed Consolidating Statements of Cash Flows

SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

	Year Ended December 31, 2011
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidated
				(Dollars in millions)
Cash Flows From Operating Activities
Net cash provided by continuing operations	$	28.9		$	1,519.7		$	109.5		$	1,658.1
Net cash provided by (used in) discontinued operations	4.4			(6.8		)	(22.5		)	(24.9		)
Net cash provided by operating activities	33.3			1,512.9			87.0			1,633.2
Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development	—			(401.1		)	(445.8		)	(846.9		)
Investment in Prairie State Energy Campus	—			(36.2		)	—			(36.2		)
Proceeds from disposal of assets, net of notes receivable	—			34.1			6.0			40.1
Investments in equity affiliates and joint ventures	—			(2.0		)	(37.7		)	(39.7		)
Proceeds from sales of debt and equity securities	—			47.0			57.6			104.6
Purchases of debt and equity securities	—			(103.6		)	(44.1		)	(147.7		)
Purchases of short-term investments	(75.0		)	—			(25.0		)	(100.0		)
Maturity of short-term investments	75.0			—			25.0			100.0
Acquisition of Macarthur Coal Limited	—			—			(2,756.7		)	(2,756.7		)
Contributions to joint ventures	—			(145.4		)	—			(145.4		)
Distributions from joint ventures	—			128.6			—			128.6
Repayment of loans from related parties	—			331.7			—			331.7
Advances to related parties	—			(371.3		)	—			(371.3		)
Other, net	—			(6.5		)	(0.1		)	(6.6		)
Net cash used in continuing operations	—			(524.7		)	(3,220.8		)	(3,745.5		)
Net cash used in discontinued operations	—			—			(62.3		)	(62.3		)
Net cash used in investing activities	—			(524.7		)	(3,283.1		)	(3,807.8		)
Cash Flows From Financing Activities
Proceeds from long-term debt	4,100.0			—			1.4			4,101.4
Acquisition of noncontrolling interests	(11.1		)	11.1			(1,994.8		)	(1,994.8		)
Payments of long-term debt	(243.1		)	—			(20.8		)	(263.9		)
Dividends paid	(92.1		)	—			—			(92.1		)
Repurchase of employee common stock relinquished for tax withholding	(18.7		)	—			—			(18.7		)
Payment of debt issuance costs	(61.5		)	—			—			(61.5		)
Excess tax benefits related to share-based compensation	8.1			—			—			8.1
Other, net	11.1			(12.0		)	0.9			—
Transactions with affiliates, net	(4,346.6		)	(991.7		)	5,338.3			—
Net cash (used in) provided by financing activities	(653.9		)	(992.6		)	3,325.0			1,678.5
Net change in cash and cash equivalents	(620.6		)	(4.4		)	128.9			(496.1		)
Cash and cash equivalents at beginning of year	903.8			5.2			386.2			1,295.2
Cash and cash equivalents at end of year	$	283.2		$	0.8		$	515.1		$	799.1

PEABODY ENERGY CORPORATION

SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

	Year Ended December 31, 2010
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidated
				(Dollars in millions)
Cash Flows From Operating Activities
Net cash (used in) provided by continuing operations	$	(126.4	)	$	1,090.6		$	152.5		$	1,116.7
Net cash used in discontinued operations	(14.2		)	(2.4		)	(13.0		)	(29.6		)
Net cash (used in) provided by operating activities	(140.6		)	1,088.2			139.5			1,087.1
Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development	—			(404.5		)	(143.4		)	(547.9		)
Investment in Prairie State Energy Campus	—			(76.0		)	—			(76.0		)
Proceeds from disposal of assets, net of notes receivable	—			14.1			5.1			19.2
Investments in equity affiliates and joint ventures	—			(15.0		)	(3.8		)	(18.8		)
Proceeds from sales of debt and equity securities	—			—			12.4			12.4
Purchases of debt and equity securities	—			—			(74.6		)	(74.6		)
Other, net	—			(8.7		)	(0.1		)	(8.8		)
Net cash used in continuing operations	—			(490.1		)	(204.4		)	(694.5		)
Net cash used in discontinued operations	—			—			(9.1		)	(9.1		)
Net cash used in investing activities	—			(490.1		)	(213.5		)	(703.6		)
Cash Flows From Financing Activities
Proceeds from long-term debt	1,150.0			—			—			1,150.0
Payments of long-term debt	(1,146.8		)	—			(20.5		)	(1,167.3		)
Dividends paid	(79.4		)	—			—			(79.4		)
Repurchase of employee common stock relinquished for tax withholding	(13.5		)	—			—			(13.5		)
Payment of debt issuance costs	(32.2		)	—			—			(32.2		)
Excess tax benefits related to share-based compensation	51.0			—			—			51.0
Other, net	22.3			(5.9		)	(2.1		)	14.3
Transactions with affiliates, net	724.6			(587.2		)	(137.4		)	—
Net cash provided by (used in) financing activities	676.0			(593.1		)	(160.0		)	(77.1		)
Net change in cash and cash equivalents	535.4			5.0			(234.0		)	306.4
Cash and cash equivalents at beginning of year	368.4			0.2			620.2			988.8
Cash and cash equivalents at end of year	$	903.8		$	5.2		$	386.2		$	1,295.2

PEABODY ENERGY CORPORATION

SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

	Year Ended December 31, 2009
	Parent Company			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidated
				(Dollars in millions)
Cash Flows From Operating Activities
Net cash (used in) provided by continuing operations	$	(213.7	)	$	792.7		$	465.9		$	1,044.9
Net cash provided by (used in) discontinued operations	7.4			(5.3		)	3.2			5.3
Net cash (used in) provided by operating activities	(206.3		)	787.4			469.1			1,050.2
Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development	—			(313.3		)	(70.1		)	(383.4		)
Investment in Prairie State Energy Campus	—			(56.8		)	—			(56.8		)
Proceeds from disposal of assets, net of notes receivable	—			43.8			10.1			53.9
Investments in equity affiliates and joint ventures	—			(5.0		)	(10.0		)	(15.0		)
Other, net	—			(5.8		)	(0.3		)	(6.1		)
Net cash used in continuing operations	—			(337.1		)	(70.3		)	(407.4		)
Net cash provided by discontinued operations	—			—			0.9			0.9
Net cash used in investing activities	—			(337.1		)	(69.4		)	(406.5		)
Cash Flows From Financing Activities
Payments of long-term debt	—			—			(37.1		)	(37.1		)
Dividends paid	(66.8		)	—			—			(66.8		)
Repurchase of employee common stock relinquished for tax withholding	(2.3		)	—			—			(2.3		)
Other, net	8.7			—			(7.1		)	1.6
Transactions with affiliates, net	473.9			(454.6		)	(19.3		)	—
Net cash provided by (used in) financing activities	413.5			(454.6		)	(63.5		)	(104.6		)
Net change in cash and cash equivalents	207.2			(4.3		)	336.2			539.1
Cash and cash equivalents at beginning of year	161.2			4.5			284.0			449.7
Cash and cash equivalents at end of year	$	368.4		$	0.2		$	620.2		$	988.8

XML

Income Taxes (Details 4) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Reconciliation of the beginning and ending amount of gross unrecognized tax benefits
Balance at beginning of period	$ 111.0	$ 113.2	$ 186.3
Additions for current year tax positions	5.2	3.4	2.7
Additions for prior year positions	3.4	13.8	15.7
Reductions for settlements with tax authorities	0	(19.4)	(88.5)
Reductions for expirations of statute of limitations	0	0	(3.0)
Balance at end of period	$ 119.6	$ 111.0	$ 113.2

XML

Stockholders' Equity (Details Textuals) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2008	Dec. 31, 2006	Dec. 31, 2009
Stockholders Equity Textuals Abstract
Common Stock, par value	$ 0.01
Aggregate principal amount of debentures outstanding	$ 732,500,000
Liquidation preference of perpetual preferred stock, per share	$ 1,000
Perpetual Preferred Stock annual cumulative dividend rate	3.0875%
Period for payment of dividend on perpetual preferred stock	10
Redemption price of preferred share purchase right	$ 0.001
Preferred stock right, exercise terms	The Right is exercisable only if a person or group acquires 15% or more of the Company’s common stock
Authorized amount for common stock repurchase	1,000,000,000
Maximum amount that can be authorized for repurchase of common stock outside the share repurchase program	100,000,000
Number of shares repurchased	7,700,000
Cost of shares repurchased	299,600,000		199,800,000	99,800,000
Amount available for repurchase of shares under share repurchase program	$ 700,400,000
Number of common stock shares received to pay estimated taxes as consideration for exercise of stock options	311,709	268,308
Schedule Of Stock By Class (Textuals) [Abstract]
Number of votes entitled for common stock holders	one vote per share
Common Stock, shares authorized	800,000,000
Common Stock, shares outstanding	271,100,000	270,200,000	266,600,000		268,200,000
Perpetual Preferred Stock [Member]
Schedule Of Stock By Class (Textuals) [Abstract]
Preferred Stock, shares authorized	800,000	800,000
Preferred Stock, shares outstanding	0	0
Series Common Stock [Member]
Stockholders Equity Textuals Abstract
Common Stock, par value	$ 0.01	0.01
Schedule Of Stock By Class (Textuals) [Abstract]
Common Stock, shares authorized	40,000,000	40,000,000
Common Stock, shares outstanding	0	0
Series-A Junior Participating Preferred Stock [Member]
Schedule Of Stock By Class (Textuals) [Abstract]
Preferred Stock, shares authorized	1,500,000	1,500,000
Preferred Stock, shares outstanding	0	0
Preferred Stock Exercise Price Per Share	$ 27.50

XML

Derivatives and Fair Value Measurements (Details) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011 Foreign currency contracts [Member]	Dec. 31, 2011 A$:US$ hedge contracts [Member] AUD	Dec. 31, 2011 A$:US$ hedge contracts [Member] Cash flow hedges [Member] AUD	Dec. 31, 2011 A$:US$ hedge contracts [Member] Fair value hedge [Member] AUD	Dec. 31, 2011 A$:US$ hedge contracts [Member] Economic hedge [Member] AUD	Dec. 31, 2011 GBP:US$ Hedge Contracts [Member] GBP (£)	Dec. 31, 2011 GBP:US$ Hedge Contracts [Member] Cash flow hedges [Member] GBP (£)	Dec. 31, 2011 GBP:US$ Hedge Contracts [Member] Fair value hedge [Member] GBP (£)	Dec. 31, 2011 GBP:US$ Hedge Contracts [Member] Economic hedge [Member] GBP (£)	Dec. 31, 2011 Diesel fuel hedge contracts [Member] gal	Dec. 31, 2011 Diesel fuel hedge contracts [Member] Cash flow hedges [Member] gal	Dec. 31, 2011 Diesel fuel hedge contracts [Member] Fair value hedge [Member] gal	Dec. 31, 2011 Diesel fuel hedge contracts [Member] Economic hedge [Member] gal	Dec. 31, 2011 U.S. explosives hedge contracts [Member] MMbtu	Dec. 31, 2011 U.S. explosives hedge contracts [Member] Cash flow hedges [Member] MMbtu	Dec. 31, 2011 U.S. explosives hedge contracts [Member] Fair value hedge [Member] MMbtu	Dec. 31, 2011 U.S. explosives hedge contracts [Member] Economic hedge [Member] MMbtu
Company's foreign currency and commodity positions by Year of Maturity and Account Classification
Total		3,910.6	3,910.6	0	0	£ 6.5	£ 6.5	£ 0	£ 0
2012		1,750.5				6.5
2013		1,309.6				0
2014		850.5				0
2015		0				0
2016		0				0
2017 and thereafter		0				0
Total (gallons/MMbtu)										189,600,000	189,600,000	0	0	7,700,000	7,700,000	0	0
2012 (gallons/MMbtu)										86,000,000				3,900,000
2013 (gallons/MMbtu)										68,000,000				2,600,000
2014 (gallons/MMbtu)										35,600,000				1,200,000
2015 (gallons/MMbtu)										0				0
2016 (gallons/MMbtu)										0				0
2017 and thereafter (gallons/MMbtu)										0				0
Fair Value Asset (Liability)		491.3				£ (0.7)
Fair Value Asset (Liability) (gallons/MMbtu)										43,700,000				(10,700,000)
Timing differences between the hedge settlement and the purchase transaction	Less than a day and up to a maximum of 30 days

XML

Resource Management and Other Commercial Events

12 Months Ended

Dec. 31, 2011

Resource Management and Other Commercial Events [Abstract]

Resource Management and Other Commercial Events

Resource Management and Other Commercial Events

In 2011, the Company exchanged coal reserves in Kentucky and coal reserves and surface lands in Illinois for coal reserves in West Virginia. Based on the fair value of the coal reserves received, the Company recognized a $37.7 million gain on the exchange. Fair value was determined by using a discounted cash flow model that included assumptions for future coal sales prices, operating costs and the discount rate. This non-cash transaction was excluded from the investing section of the condensed consolidated statement of cash flows. In 2010, the Company recognized gains of $23.7 million on similar transactions.

In 2011, the Company recognized income associated with the receipt of a $14.6 million project development fee related to its involvement in the Prairie State Energy Campus (Prairie State), a 1,600 megawatt coal-fueled electricity generation project.

In 2011, the Company sold non-strategic coal reserves and surface lands located in Kentucky and Illinois for $24.9 million of cash proceeds and notes receivable totaling $17.4 million and recognized a gain of $31.7 million. The non-cash portion of these transactions were excluded from the investing section of the consolidated statement of cash flows.

XML

Management - Labor Relations (Details)	Dec. 31, 2011
Risk Management-Labor Relations (Textuals) [Abstract]
Total number of employees	8,300
Hourly Employees	5,600
Percentage of employees represented by organized labor unions	24.00%
Percentage of coal production generated by hourly employees represented by organized labor unions	7.00%
United Mine Workers of America [Member]
Risk Management-Labor Relations (Textuals) [Abstract]
Percentage of employees represented by organized labor unions	7.00%
Percentage of U.S. coal production generated by hourly employees under the agreement	4.00%
International Brotherhood of Boilermakers [Member]
Risk Management-Labor Relations (Textuals) [Abstract]
Percentage of employees represented by organized labor unions	9.00%
Percentage of U.S. coal production generated by hourly employees under the agreement	1.00%

XML

Valuation and Qualifying Accounts (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Advance royalty recoupment reserve [Member]
Valuation and Qualifying Accounts
Balance at Beginning of Period	$ 19.9		$ 17.2		$ 17.2
Charged to Costs and Expenses	1.8		1.9		1.6
Deductions	(0.1)	[1]	(0.2)	[1]	(2.2)	[1]
Other	(0.3)	[2]	1.0	[2]	0.6	[2]
Balance at End of Period	21.3		19.9		17.2
Reserve for materials and supplies [Member]
Valuation and Qualifying Accounts
Balance at Beginning of Period	6.2		6.2		4.9
Charged to Costs and Expenses	3.7		0.9		3.6
Deductions	(3.4)	[1]	(0.9)	[1]	(2.3)	[1]
Other	0		0		0
Balance at End of Period	6.5		6.2		6.2
Allowance for doubtful accounts [Member]
Valuation and Qualifying Accounts
Balance at Beginning of Period	30.3		18.3		24.8
Charged to Costs and Expenses	(3.7)		26.7		7.7
Deductions	(0.4)	[1]	(6.9)	[1]	(3.6)	[1]
Other	(9.2)	[3]	(7.8)	[3]	(10.6)	[3]
Balance at End of Period	$ 17.0		$ 30.3		$ 18.3

[1] Reserves utilized, unless otherwise indicated.

[2] Balances transferred (to) from other accounts or reserves recorded as part of a property transaction or acquisition.

[3] Reflects subsequent recovery of amounts previously reserved.

XML

Coal Trading (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Fair value of financial asset (liability) positions measured on a recurring basis
Assets from coal trading activities, Net Basis	$ 44.6		$ 192.5
Liabilities from coal trading activities, Net Basis	(10.3)		(181.7)
Coal Trading [Member]
Trading revenue
Trading revenue	145.6		158.7		261.5
Fair value of financial asset (liability) positions measured on a recurring basis
Assets from coal trading activities, Gross Basis	170.4		1,706.2
Assets from coal trading activities, Net Basis	44.6		192.5
Liabilities from coal trading activities, Gross Basis	(84.0)		(1,843.5)
Liabilities from coal trading activities, Net Basis	(10.3)		(181.7)
Subtotal, Gross Basis	86.4		(137.3)
Subtotal, Net Basis	34.3		10.8
Net margin held, Gross Basis	(52.1)	[1]	148.1	[1]
Net margin posted, Net Basis	0	[1]	0	[1]
Net value of coal trading positions, Gross Basis	34.3		10.8
Net value of coal trading positions, Net Basis	34.3		10.8
Commodity swaps and options [Member] | Coal Trading [Member]
Trading revenue
Trading revenue	(41.4)		23.2		176.5
Physical commodity purchase / sale contracts [Member] | Coal Trading [Member]
Trading revenue
Trading revenue	$ 187.0		$ 135.5		$ 85.0

[1] Represents margin held from exchanges of $52.1 million at December 31, 2011; and margin posted with counterparties and exchanges of $148.2 million, net of margin held of $0.1 million at December 31, 2010. In addition, at December 31, 2010, the Company held letters of credit of $5.0 million from counterparties in lieu of margin posted. Of the margin held at December 31, 2011, approximately $23.4 million related to cash flow hedges.

XML

Acquisition of Macarthur Coal Limited (Tables)

12 Months Ended

Dec. 31, 2011

Business Combinations [Abstract]

Schedule of recognized identified assets acquired and liabilities assumed

The following table summarizes the preliminary estimated fair values of assets acquired and liabilities assumed that were recognized at the acquisition and control date (Dollars in millions):

Accounts receivable, net	$	106.6
Inventories	67.1
Other current assets	137.5
Property, plant, equipment and mine development	3,457.0
Investments and other assets	1,275.1
Current maturities of long-term debt	(11.0		)
Accounts payable and accrued expenses	(133.8		)
Long-term debt, less current maturities	(59.2		)
Asset retirement obligations	(39.3		)
Other noncurrent liabilities	(31.4		)
Noncontrolling interests	(2,011.9		)
Total purchase price, net of cash acquired of $261.2	$	2,756.7

Pro forma information

The pro forma financial information does not necessarily reflect the results of operations that would have occurred had the Company and Macarthur constituted a single entity during those periods or that may be attained in the future.

	Year Ended December 31,
	2011		2010
	(Dollars in millions, except earnings per share)
Revenue	$	8,696.5	$	7,579.5
Income from continuing operations, net of income taxes	1,046.7		781.5
Basic earnings per share	3.67		2.80
Diluted earnings per share	3.65		2.77

XML

Leases

12 Months Ended

Dec. 31, 2011

Leases [Abstract]

Leases

Leases

The Company leases equipment and facilities under various noncancelable lease agreements. Certain lease agreements require the maintenance of specified ratios and contain restrictive covenants which limit indebtedness, subsidiary dividends, investments, asset sales and other Company actions. Rental expense under operating leases was $170.6 million, $129.5 million and $116.6 million for the years ended December 31, 2011, 2010 and 2009, respectively. The gross value of property, plant, equipment and mine development assets under capital leases was $297.0 million as of December 31, 2011 and $109.5 million as of December 31, 2010, related primarily to the leasing of mining equipment. The accumulated depreciation for these items was $58.9 million and $39.5 million at December 31, 2011 and 2010, respectively.

The Company also leases coal reserves under agreements that require royalties to be paid as the coal is mined. Certain agreements also require minimum annual royalties to be paid regardless of the amount of coal mined during the year. Total royalty expense was $610.6 million, $540.6 million and $428.6 million for the years ended December 31, 2011, 2010 and 2009, respectively.

A substantial amount of the coal mined by the Company is produced from mineral reserves leased from the owner. One of the major lessors is the U.S. government, from which the Company leases substantially all of the coal it mines in Wyoming under terms set by Congress and administered by the U.S. Bureau of Land Management. These leases are generally for an initial term of ten years but may be extended by diligent development and mining of the reserves until all economically recoverable reserves are depleted. The Company has met the diligent development requirements for substantially all of these federal leases either directly through production, by including the lease as a part of a logical mining unit with other leases upon which development has occurred, or by paying an advance royalty in lieu of continued operations. Annual production on these federal leases must total at least 1.0% of the original amount of coal in the entire logical mining unit. In addition, royalties are payable monthly at a rate of 12.5% of the gross realization from the sale of the coal mined using surface mining methods and at a rate of 8.0% of the gross realization for coal produced using underground mining methods. The Company also leases coal reserves in Arizona from The Navajo Nation and the Hopi Tribe under leases that are administered by the U.S. Department of the Interior. These leases expire upon exhaustion of the leased reserves or upon the permanent ceasing of all mining activities on the related reserves as a whole. The royalty rates are also generally based upon a percentage of the gross realization from the sale of coal. These rates are subject to redetermination every ten years under the terms of the leases. The remainder of the leased coal is generally leased from state governments, land holding companies and various individuals. The duration of these leases varies greatly. Typically, the lease terms are automatically extended as long as active mining continues. Royalty payments are generally based upon a specified rate per ton or a percentage of the gross realization from the sale of the coal.

Mining and exploration in Australia is generally executed 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 the sales price. 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 the loss of access to the land where the landowner retains the surface rights, and the amount and type of compensation can be determined by agreement or arbitration as provided in the mining law. Surface rights are typically acquired directly from landowners by mutual agreement.

Future minimum lease and royalty payments as of December 31, 2011 are as follows:

	Capital Leases		Operating Leases		Coal Lease and Royalty Obligations
Year Ending December 31,
	(Dollars in millions)
2012	$	32.3	$	123.1	$	50.7
2013	41.3		106.2		50.0
2014	25.9		90.6		48.8
2015	10.5		76.4		46.6
2016	10.3		63.5		3.8
2017 and thereafter	21.7		151.1		27.9
Total minimum lease payments	142.0		$	610.9	$	227.8
Less interest	19.5
Present value of minimum capital lease payments	$	122.5

As of December 31, 2011, certain of the Company’s lease obligations were secured by outstanding surety bonds totaling $104.7 million.

XML

Pension and Savings Plans (Details 4) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Fair value of assets in the Master Trust by category and by fair value valuation hierarchy
Total assets at fair value	$ 769.6	$ 771.6
Level 1 [Member]
Fair value of assets in the Master Trust by category and by fair value valuation hierarchy
Total assets at fair value	0	82.6
Level 2 [Member]
Fair value of assets in the Master Trust by category and by fair value valuation hierarchy
Total assets at fair value	744.3	641.3
Level 3 [Member]
Fair value of assets in the Master Trust by category and by fair value valuation hierarchy
Total assets at fair value	25.3	47.7
U.S. equity securities
Fair value of assets in the Master Trust by category and by fair value valuation hierarchy
Total assets at fair value	340.4	333.1
U.S. equity securities | Level 1 [Member]
Fair value of assets in the Master Trust by category and by fair value valuation hierarchy
Total assets at fair value	0	82.6
U.S. equity securities | Level 2 [Member]
Fair value of assets in the Master Trust by category and by fair value valuation hierarchy
Total assets at fair value	340.4	250.5
U.S. equity securities | Level 3 [Member]
Fair value of assets in the Master Trust by category and by fair value valuation hierarchy
Total assets at fair value	0	0
International equity securities
Fair value of assets in the Master Trust by category and by fair value valuation hierarchy
Total assets at fair value	107.8	118.9
International equity securities | Level 1 [Member]
Fair value of assets in the Master Trust by category and by fair value valuation hierarchy
Total assets at fair value	0	0
International equity securities | Level 2 [Member]
Fair value of assets in the Master Trust by category and by fair value valuation hierarchy
Total assets at fair value	107.8	118.9
International equity securities | Level 3 [Member]
Fair value of assets in the Master Trust by category and by fair value valuation hierarchy
Total assets at fair value	0	0
Collateralized Mortgage Backed Securities [Member]
Fair value of assets in the Master Trust by category and by fair value valuation hierarchy
Total assets at fair value	98.9	108.8
Collateralized Mortgage Backed Securities [Member] | Level 1 [Member]
Fair value of assets in the Master Trust by category and by fair value valuation hierarchy
Total assets at fair value	0	0
Collateralized Mortgage Backed Securities [Member] | Level 2 [Member]
Fair value of assets in the Master Trust by category and by fair value valuation hierarchy
Total assets at fair value	98.9	108.8
Collateralized Mortgage Backed Securities [Member] | Level 3 [Member]
Fair value of assets in the Master Trust by category and by fair value valuation hierarchy
Total assets at fair value	0	0
U.S. debt securities
Fair value of assets in the Master Trust by category and by fair value valuation hierarchy
Total assets at fair value	83.3	60.2
U.S. debt securities | Level 1 [Member]
Fair value of assets in the Master Trust by category and by fair value valuation hierarchy
Total assets at fair value	0	0
U.S. debt securities | Level 2 [Member]
Fair value of assets in the Master Trust by category and by fair value valuation hierarchy
Total assets at fair value	83.3	60.2
U.S. debt securities | Level 3 [Member]
Fair value of assets in the Master Trust by category and by fair value valuation hierarchy
Total assets at fair value	0	0
International debt securities
Fair value of assets in the Master Trust by category and by fair value valuation hierarchy
Total assets at fair value	32.0	25.7
International debt securities | Level 1 [Member]
Fair value of assets in the Master Trust by category and by fair value valuation hierarchy
Total assets at fair value	0	0
International debt securities | Level 2 [Member]
Fair value of assets in the Master Trust by category and by fair value valuation hierarchy
Total assets at fair value	32.0	25.7
International debt securities | Level 3 [Member]
Fair value of assets in the Master Trust by category and by fair value valuation hierarchy
Total assets at fair value	0	0
Corporate debt securities
Fair value of assets in the Master Trust by category and by fair value valuation hierarchy
Total assets at fair value	45.8	46.1
Corporate debt securities | Level 1 [Member]
Fair value of assets in the Master Trust by category and by fair value valuation hierarchy
Total assets at fair value	0	0
Corporate debt securities | Level 2 [Member]
Fair value of assets in the Master Trust by category and by fair value valuation hierarchy
Total assets at fair value	45.8	46.1
Corporate debt securities | Level 3 [Member]
Fair value of assets in the Master Trust by category and by fair value valuation hierarchy
Total assets at fair value	0	0
Short-term investments
Fair value of assets in the Master Trust by category and by fair value valuation hierarchy
Total assets at fair value	36.1	31.1
Short-term investments | Level 1 [Member]
Fair value of assets in the Master Trust by category and by fair value valuation hierarchy
Total assets at fair value	0	0
Short-term investments | Level 2 [Member]
Fair value of assets in the Master Trust by category and by fair value valuation hierarchy
Total assets at fair value	36.1	31.1
Short-term investments | Level 3 [Member]
Fair value of assets in the Master Trust by category and by fair value valuation hierarchy
Total assets at fair value	0	0
Interests in real estate
Fair value of assets in the Master Trust by category and by fair value valuation hierarchy
Total assets at fair value	25.3	47.7
Interests in real estate | Level 1 [Member]
Fair value of assets in the Master Trust by category and by fair value valuation hierarchy
Total assets at fair value	0	0
Interests in real estate | Level 2 [Member]
Fair value of assets in the Master Trust by category and by fair value valuation hierarchy
Total assets at fair value	0	0
Interests in real estate | Level 3 [Member]
Fair value of assets in the Master Trust by category and by fair value valuation hierarchy
Total assets at fair value	$ 25.3	$ 47.7	$ 47.4