BTU 10-Q Quarterly Report June 30, 2011

PEABODY ENERGY CORP

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10-Q 1 c64710e10vq.htm FORM 10-Q e10vq

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)


þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2011


o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 1-16463

PEABODY ENERGY CORPORATION

(Exact name of registrant as specified in its charter)


Delaware		13-4004153

(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)


701 Market Street, St. Louis, Missouri		63101-1826

(Address of principal executive offices)		(Zip Code)

(314) 342-3400

(Registrant’s telephone number, including area code)

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

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

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


Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

There were 270,824,096 shares of common stock with a par value of $0.01 per share outstanding at July 29, 2011.

INDEX


	Page
PART I — FINANCIAL INFORMATION

Item 1. Financial Statements.

Unaudited Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2011 and 2010		1

Condensed Consolidated Balance Sheets as of June 30, 2011 (Unaudited) and December 31, 2010		2

Unaudited Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2011 and 2010		3

Unaudited Consolidated Statement of Changes in Stockholders’ Equity for the Six Months Ended June 30, 2011		4

Notes to Unaudited Condensed Consolidated Financial Statements		5

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		35

Item 3. Quantitative and Qualitative Disclosures About Market Risk		49

Item 4. Controls and Procedures		50

PART II — OTHER INFORMATION

Item 1. Legal Proceedings		50

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		50

Item 5. Other Information		51

Item 6. Exhibits		55

SIGNATURE		56

EXHIBIT INDEX		57
EX-4.1
EX-4.2
EX-4.3
EX-4.4
EX-10.2
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

PEABODY ENERGY CORPORATION
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS


	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(Dollars in millions, except per share data)
Revenues
Sales	$	1,800.8		$	1,569.8		$	3,414.5		$	2,954.9
Other revenues		207.2			91.6			338.4			222.1

Total revenues		2,008.0			1,661.4			3,752.9			3,177.0
Costs and expenses
Operating costs and expenses		1,392.8			1,174.7			2,660.9			2,283.4
Depreciation, depletion and amortization		105.3			105.1			214.1			210.6
Asset retirement obligation expense		15.8			10.9			28.9			20.4
Selling and administrative expenses		58.6			54.1			120.2			109.5
Other operating (income) loss:
Net gain on disposal or exchange of assets		(25.7	)		(1.4	)		(29.7	)		(8.7	)
Loss (income) from equity affiliates		2.8			(6.4	)		5.8			(4.8	)

Operating profit		458.4			324.4			752.7			566.6
Interest expense		49.1			57.9			100.1			107.9
Interest income		(3.5	)		(1.6	)		(7.6	)		(2.6	)

Income from continuing operations before income taxes		412.8			268.1			660.2			461.3
Income tax provision		119.8			53.4			187.6			109.5

Income from continuing operations, net of income taxes		293.0			214.7			472.6			351.8
Loss from discontinued operations, net of income taxes		(0.8	)		(0.5	)		(1.7	)		(0.9	)

Net income		292.2			214.2			470.9			350.9
Less: Net income attributable to noncontrolling interests		7.4			8.0			9.6			11.0

Net income attributable to common stockholders	$	284.8		$	206.2		$	461.3		$	339.9


Income From Continuing Operations
Basic earnings per share	$	1.05		$	0.77		$	1.71		$	1.27

Diluted earnings per share	$	1.05		$	0.76		$	1.70		$	1.26


Net Income Attributable to Common Stockholders
Basic earnings per share	$	1.05		$	0.77		$	1.70		$	1.27

Diluted earnings per share	$	1.05		$	0.76		$	1.69		$	1.26


Dividends declared per share	$	0.085		$	0.070		$	0.170		$	0.140

See accompanying notes to unaudited condensed consolidated financial statements.

PEABODY ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS


	(Unaudited)
	June 30, 2011			December 31, 2010
	(Amounts in millions, except share and
	per share data)
ASSETS
Current assets
Cash and cash equivalents	$	1,176.9		$	1,295.2
Short-term investments		75.0			—
Accounts receivable, net of allowance for doubtful accounts of $22.7 at June 30, 2011 and $30.3 at December 31, 2010		644.8			558.2
Inventories		374.0			332.9
Assets from coal trading activities, net		109.2			192.5
Deferred income taxes		103.5			120.4
Other current assets		627.0			459.0

Total current assets		3,110.4			2,958.2
Property, plant, equipment and mine development
Land and coal interests		7,729.7			7,657.0
Buildings and improvements		1,090.0			1,079.8
Machinery and equipment		1,952.9			1,699.3
Less: accumulated depreciation, depletion and amortization		(3,188.6	)		(3,010.0	)

Property, plant, equipment and mine development, net		7,584.0			7,426.1
Investments and other assets		1,051.2			978.8

Total assets	$	11,745.6		$	11,363.1


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	43.8		$	43.2
Liabilities from coal trading activities, net		106.1			181.7
Accounts payable and accrued expenses		1,335.6			1,288.8

Total current liabilities		1,485.5			1,513.7

Long-term debt, less current maturities		2,468.2			2,706.8
Deferred income taxes		597.8			539.8
Asset retirement obligations		520.4			501.3
Accrued postretirement benefit costs		965.5			963.9
Other noncurrent liabilities		462.9			448.3

Total liabilities		6,500.3			6,673.8

Stockholders’ equity
Preferred Stock — $0.01 per share par value; 10,000,000 shares authorized, no shares issued or outstanding as of June 30, 2011 or December 31, 2010		—			—
Series A Junior Participating Preferred Stock — $0.01 per share par value; 1,500,000 shares authorized, no shares issued or outstanding as of June 30, 2011 or December 31, 2010		—			—
Perpetual Preferred Stock — 800,000 shares authorized, no shares issued or outstanding as of June 30, 2011 or December 31, 2010		—			—
Series Common Stock — $0.01 per share par value; 40,000,000 shares authorized, no shares issued or outstanding as of June 30, 2011 or December 31, 2010		—			—
Common Stock — $0.01 per share par value; 800,000,000 shares authorized, 279,981,794 shares issued and 270,829,764 shares outstanding as of June 30, 2011 and 279,149,028 shares issued and 270,236,256 shares outstanding as of December 31, 2010		2.8			2.8
Additional paid-in capital		2,217.1			2,182.0
Retained earnings		3,292.9			2,878.4
Accumulated other comprehensive income (loss)		52.6			(67.9	)
Treasury shares, at cost: 9,152,030 shares as of June 30, 2011 and 8,912,772 shares as of December 31, 2010		(350.0	)		(334.6	)

Peabody Energy Corporation’s stockholders’ equity		5,215.4			4,660.7
Noncontrolling interests		29.9			28.6

Total stockholders’ equity		5,245.3			4,689.3

Total liabilities and stockholders’ equity	$	11,745.6		$	11,363.1

See accompanying notes to unaudited condensed consolidated financial statements.

PEABODY ENERGY CORPORATION

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	Six Months Ended June 30,
	2011			2010
	(Dollars in millions)
Cash Flows From Operating Activities
Net income	$	470.9		$	350.9
Loss from discontinued operations, net of income taxes		1.7			0.9

Income from continuing operations, net of income taxes		472.6			351.8
Adjustments to reconcile income from continuing operations, net of income taxes to net cash provided by operating activities:
Depreciation, depletion and amortization		214.1			210.6
Deferred income taxes		22.0			69.7
Share-based compensation		21.9			22.3
Net gain on disposal or exchange of assets		(29.7	)		(8.7	)
Loss (income) from equity affiliates		5.8			(4.8	)
Changes in current assets and liabilities:
Accounts receivable		(80.7	)		(51.1	)
Accounts receivable securitization program		—			(38.2	)
Inventories		(41.1	)		(38.3	)
Net assets from coal trading activities		(19.6	)		(5.2	)
Other current assets		(18.2	)		19.6
Accounts payable and accrued expenses		11.8			(55.5	)
Asset retirement obligations		20.5			14.4
Workers’ compensation obligations		(1.6	)		3.9
Accrued postretirement benefit costs		19.0			13.2
Contributions to pension plans		(0.9	)		(20.1	)
Other, net		22.3			(9.3	)

Net cash provided by continuing operations		618.2			474.3
Net cash used in discontinued operations		(2.6	)		(9.9	)

Net cash provided by operating activities		615.6			464.4

Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development		(354.8	)		(187.5	)
Investment in Prairie State Energy Campus		(21.5	)		(30.5	)
Proceeds from disposal of assets		9.6			6.1
Investments in equity affiliates and joint ventures		(2.4	)		(17.4	)
Proceeds from sale of debt securities		21.0			—
Purchases of debt securities		(14.6	)		—
Purchases of short-term investments		(100.0	)		—
Maturity of short-term investments		25.0			—
Other, net		(2.1	)		(4.4	)

Net cash used in investing activities		(439.8	)		(233.7	)

Cash Flows From Financing Activities
Proceeds from long-term debt		1.4			500.0
Payments of long-term debt		(238.2	)		(495.7	)
Dividends paid		(46.8	)		(37.6	)
Repurchase of employee common stock relinquished for tax withholding		(15.4	)		(8.0	)
Payment of debt issuance costs		—			(21.9	)
Excess tax benefits related to share-based compensation		5.8			—
Proceeds from stock options exercised		4.4			2.4
Other, net		(5.3	)		(1.7	)

Net cash used in financing activities		(294.1	)		(62.5	)

Net change in cash and cash equivalents		(118.3	)		168.2
Cash and cash equivalents at beginning of period		1,295.2			988.8

Cash and cash equivalents at end of period	$	1,176.9		$	1,157.0

See accompanying notes to unaudited condensed consolidated financial statements.

PEABODY ENERGY CORPORATION

UNAUDITED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY


	Peabody Energy Corporation’s Stockholders’ Equity
			Additional								Accumulated						Total
			Paid-in					Retained			Other Comprehensive			Noncontrolling			Stockholders’
	Common Stock		Capital		Treasury Stock			Earnings			Income (Loss)			Interests			Equity
	(Dollars in millions)
December 31, 2010	$	2.8	$	2,182.0	$	(334.6	)	$	2,878.4		$	(67.9	)	$	28.6		$	4,689.3
Comprehensive income:
Net income		—		—		—			461.3			—			9.6			470.9
Net unrealized gains on available-for-sale securities (net of $0.3 tax benefit)		—		—		—			—			0.2			—			0.2
Increase in fair value of cash flow hedges (net of $73.6 tax provision)		—		—		—			—			96.8			—			96.8
Postretirement plans and workers’ compensation obligations (net of $6.5 tax provision)		—		—		—			—			23.5			—			23.5

Comprehensive income									461.3			120.5			9.6			591.4

Dividends paid		—		—		—			(46.8	)		—			—			(46.8	)
Share-based compensation		—		21.9		—			—			—			—			21.9
Excess tax benefits related to share-based compensation		—		5.8		—			—			—			—			5.8
Stock options exercised		—		4.4		—			—			—			—			4.4
Employee stock purchases		—		3.0		—			—			—			—			3.0
Repurchase of employee common stock relinquished for tax withholding		—		—		(15.4	)		—			—			—			(15.4	)
Distributions to noncontrolling interests		—		—		—			—			—			(8.3	)		(8.3	)

June 30, 2011	$	2.8	$	2,217.1	$	(350.0	)	$	3,292.9		$	52.6		$	29.9		$	5,245.3

See accompanying notes to unaudited condensed consolidated financial statements.

PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(1) Basis of Presentation

The condensed 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.

The accompanying condensed consolidated financial statements as of June 30, 2011 and for the three and six months ended June 30, 2011 and 2010, and the notes thereto, are unaudited. However, in the opinion of management, these financial statements reflect all normal, recurring adjustments necessary for a fair presentation of the results of the periods presented. The balance sheet information as of December 31, 2010 has been derived from the Company’s audited consolidated balance sheet. The results of operations for the three and six months ended June 30, 2011 are not necessarily indicative of the results to be expected for future quarters or for the year ending December 31, 2011.

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

Certain amounts in prior periods have been reclassified to conform with the current year presentations with no effect on previously reported net income or stockholders’ equity.

(2) Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented

In June 2011, the Financial Accounting Standards Board (FASB) issued an accounting update which amends current comprehensive income guidance. The update eliminates the option to present the components of other comprehensive income as part of the statement of shareholders’ equity. Instead, an entity will be required to present the total of comprehensive income, the components of net income, and the components of other 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, or on January 1, 2012 for the Company. Because the update only impacts presentation, the guidance will not impact the Company’s results of operations, financial condition or cash flows.

In May 2011, the FASB issued an accounting update which amends current fair value measurement disclosure requirements to provide a consistent definition of fair value and ensure that the fair value measurement and disclosure requirements are similar between United States (U.S.) generally accepted accounting principles (GAAP) and International Financial Reporting Standards. This update requires 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, or on January 1, 2012 for the Company. The guidance will impact the Company’s disclosures, but it will not impact the Company’s results of operations, financial condition or cash flows.

In December 2010, the FASB issued an update to guidance on accounting for business combinations that clarified a public entity’s disclosure requirements for pro forma presentation of revenue and earnings related to a business combination. The new guidance, which became effective on January 1, 2011, requires that if comparative statements are presented, the public entity should disclose revenue and earnings of the combined entity as though the business combination had 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 will impact the Company’s disclosures related to business combination transactions but it will not impact the Company’s results of operations, financial condition or cash flows.

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In January 2010, the FASB issued accounting guidance that requires 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 requires new disclosures regarding activity in Level 3 fair value measurements, including a gross basis reconciliation. The new disclosure requirements became effective for interim and annual periods 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 the guidance had an impact on the Company’s disclosures, it did not affect the Company’s results of operations, financial condition or cash flows.

(3) 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’s short-term investments consist of time deposits with highly-rated financial institutions, while its long-term portfolio primarily consists of investments in debt securities.

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. Held-to-maturity securities, which consisted of time deposits, are stated at amortized cost. Interest earned on the time deposits is reported as “Interest income” in the unaudited condensed consolidated statements of operations.

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 income (loss)” in the condensed consolidated balance sheets. Realized gains and losses, determined on a specific identification method, are included in “Interest income” in the unaudited condensed consolidated statements of operations.

Investments in available-for-sale and held-to-maturity securities at June 30, 2011 were as follows:


			Gross		Gross
			Unrealized		Unrealized
Available-for-sale securities	Cost		Gains		Losses		Fair Value
	(Dollars in millions)
Current:
Federal government securities	$	5.2	$	—	$	—	$	5.2
U.S. corporate bonds		4.6		—		—		4.6

Noncurrent:
Marketable equity security		10.0		—		1.0		9.0
Federal government securities		12.9		0.2		—		13.1
U.S. corporate bonds		9.5		—		—		9.5


Total	$	42.2	$	0.2	$	1.0	$	41.4


			Gross		Gross
			Unrealized		Unrealized
Held-to-maturity securities	Cost		Gains		Losses		Fair Value
	(Dollars in millions)
Time deposits	$	75.0	$	—	$	—	$	75.0

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


			Gross		Gross
			Unrealized		Unrealized
Available-for-sale securities	Cost		Gains		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 June 30, 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	$	9.8	$	9.8
Due in one to five years		22.4		22.6


Total	$	32.2	$	32.4

Contractual maturities for held-to-maturity investments were all less than one year at June 30, 2011.

The Company’s investment in a marketable equity security consists of an investment in Winsway Coking Coal Holdings Limited.

The Company did not sell any of its long-term investments described above during the three months ended June 30, 2011 and, thus, had no proceeds, realized gains or realized losses related to these securities.

In addition to the securities described above, the Company holds investments in debt and equity securities related to the Company’s pro-rata share of funding in the Newcastle Coal Infrastructure Group (NCIG). The debt securities are recorded at cost, which approximates fair value, in Australian dollars adjusted for changes in the U.S. dollar to Australian dollar exchange rates. The equity securities are recorded at cost, which approximates fair value. During the six months ended June 30, 2011, the Company sold $21.0 million of the debt securities related to NCIG. In July 2011, the Company sold its remaining interest in the debt securities of NCIG.

At each reporting date, the Company performs separate evaluations of debt and equity securities to determine if the unrealized losses are other-than-temporary. None of the securities that were in an unrealized loss position at June 30, 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 six months ended June 30, 2011.

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(4) Inventories

Inventories consisted of the following:


	June 30,		December 31,
	2011		2010
	(Dollars in millions)
Materials and supplies	$	109.7	$	97.1
Raw coal		72.7		55.4
Saleable coal		191.6		180.4

Total	$	374.0	$	332.9

(5) 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 fluctuations in commodity prices, interest rates and foreign currency exchange rates. These risks are actively monitored in an effort to ensure compliance with the risk management policies of the Company. 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 financial instruments.

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 result 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 June 30, 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 Australian dollar 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.

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Notional Amounts and Fair Value. The following summarizes the Company’s foreign currency and commodity positions at June 30, 2011:


	Notional Amount by Year of Maturity
													2016 and
	Total		2011		2012		2013		2014		2015		thereafter
Foreign Currency
A$:US$ hedge contracts (A $ millions)	$	3,902.7	$	755.6	$	1,485.0	$	1,083.6	$	578.5	$	—	$	—

Commodity Contracts
Diesel fuel hedge contracts (million gallons)		187.0		43.8		78.1		49.8		15.3		—		—
U.S. explosives hedge contracts (million MMBtu)		7.9		2.0		3.5		2.1		0.3		—		—


	Account Classification by
	Cash Flow		Fair Value		Economic		Fair Value Asset
	Hedge		Hedge		Hedge		(Liability)
							(Dollars in millions)
Foreign Currency
A$:US$ hedge contracts (A $ millions)	$	3,902.7	$	—	$	—	$	773.6

Commodity Contracts
Diesel fuel hedge contracts (million gallons)		187.0		—		—	$	95.3
U.S. explosives hedge contracts (million MMBtu)		7.9		—		—	$	(1.3	)

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 income (loss)” until the hedged transaction impacts reported earnings, at which time gains and losses are reclassified to the consolidated statements of operations at the time of 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 the consolidated statements of operations 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 the consolidated statements of operations 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 relating to 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.

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The tables below show the classification and amounts of pre-tax gains and losses related to the Company’s non-trading hedges during the three and six months ended June 30, 2011 and 2010:


		Three Months Ended June 30, 2011
				Gain (loss)			Gain (loss)			Gain (loss)
		Gain (loss)		recognized in other			reclassified from			reclassified from
	Statement of Operations	recognized in income		comprehensive			other comprehensive			other comprehensive
	Classification Gains (Losses) -	on non-designated		income on derivative			income into income			income into income
Financial Instrument	Realized	derivatives		(effective portion)			(effective portion)			(ineffective portion)
		(Dollars in millions)
Diesel fuel hedge contracts:
— Cash flow hedges	Operating costs and expenses	$	—	$	(26.0	)	$	11.9		$	(0.3	)
Explosives cash flow hedge contracts:
— Cash flow hedges	Operating costs and expenses		—		(0.9	)		(0.1	)		(0.4	)
Foreign currency cash flow hedge contracts:
— Operating costs	Operating costs and expenses		—		183.1			96.2			—
— Capital expenditures	Depreciation, depletion and amortization		—		(0.2	)		—			—

Total		$	—	$	156.0		$	108.0		$	(0.7	)


		Three Months Ended June 30, 2010
					Gain (loss)			Gain (loss)			Gain (loss)
		Gain (loss)			recognized in other			reclassified from			reclassified from
	Statement of Operations	recognized in income			comprehensive			other comprehensive			other comprehensive
	Classification Gains (Losses) -	on non-designated			income on derivative			income into income			income into income
Financial Instrument	Realized	derivatives ⁽¹⁾			(effective portion)			(effective portion)			(ineffective portion)
					(Dollars in millions)
Interest rate swaps:
— Cash flow hedges	Interest expense	$	(8.5	)	$	(0.1	)	$	0.7		$	—
Diesel fuel hedge contracts:
— Cash flow hedges	Operating costs and expenses		—			(40.2	)		(9.3	)		(1.7	)
Explosives cash flow hedge contracts:
— Cash flow hedges	Operating costs and expenses		—			0.2			(2.6	)		—
Foreign currency cash flow hedge contracts	Operating costs and expenses		—			(161.4	)		27.1			—

Total		$	(8.5	)	$	(201.5	)	$	15.9		$	(1.7	)


⁽¹⁾		Amounts relate to swaps that were de-designated and terminated in conjunction with the refinancing of the Company’s previous credit facility.


		Six Months Ended June 30, 2011
				Gain (loss)			Gain (loss)			Gain (loss)
		Gain (loss)		recognized in other			reclassified from			reclassified from
	Statement of Operations	recognized in income		comprehensive			other comprehensive			other comprehensive
	Classification Gains (Losses) -	on non-designated		income on derivative			income into income			income into income
Financial Instrument	Realized	derivatives		(effective portion)			(effective portion)			(ineffective portion)
				(Dollars in millions)
Diesel fuel hedge contracts:
— Cash flow hedges	Operating costs and expenses	$	—	$	72.9		$	20.0		$	2.1
Explosives cash flow hedge contracts:
— Cash flow hedges	Operating costs and expenses		—		(0.8	)		(0.1	)		(0.5	)
Foreign currency cash flow hedge contracts:
— Operating costs	Operating costs and expenses		—		302.9			168.9			—
— Capital expenditures	Depreciation, depletion and amortization		—		(0.2	)		—			—

Total		$	—	$	374.8		$	188.8		$	1.6

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


		Six Months Ended June 30, 2010
					Gain (loss)			Gain (loss)			Gain (loss)
		Gain (loss)			recognized in other			reclassified from			reclassified from
	Statement of Operations	recognized in income			comprehensive			other comprehensive			other comprehensive
	Classification Gains (Losses) -	on non-designated			income on derivative			income into income			income into income
Financial Instrument	Realized	derivatives ⁽¹⁾			(effective portion)			(effective portion)			(ineffective portion)
					(Dollars in millions)
Interest rate swaps:
— Cash flow hedges	Interest expense	$	(8.5	)	$	0.8		$	(0.5	)	$	—
Diesel fuel hedge contracts:
— Cash flow hedges	Operating costs and expenses		—			(29.8	)		(16.4	)		(0.7	)
Explosives cash flow hedge contracts:
— Cash flow hedges	Operating costs and expenses		—			(3.6	)		(4.9	)		—
Foreign currency cash flow hedge contracts	Operating costs and expenses		—			(79.4	)		65.9			—

Total		$	(8.5	)	$	(112.0	)	$	44.1		$	(0.7	)


⁽¹⁾		Amounts relate to swaps that were de-designated and terminated in conjunction with the refinancing of the Company’s previous credit facility.

Based on the net fair value of the Company’s non-coal trading positions held in “Accumulated other comprehensive income (loss)” at June 30, 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 $387 million and $55 million, respectively. The unrealized losses to be realized under the explosives hedge program are expected to be less than $1 million. As these unrealized gains and 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 condensed consolidated statements of operations.

The classification and amount of derivatives presented on a gross basis as of June 30, 2011 and December 31, 2010 are as follows:


	Fair Value as of June 30, 2011
	Current		Noncurrent		Current		Noncurrent
Financial Instrument	Assets		Assets		Liabilities		Liabilities
	(Dollars in millions)
Diesel fuel cash flow hedge contracts	$	58.8	$	42.7	$	4.3	$	1.9
Explosives cash flow hedge contracts		0.3		—		0.7		0.9
Foreign currency cash flow hedge contracts		387.7		386.4		0.4		0.1

Total	$	446.8	$	429.1	$	5.4	$	2.9


	Fair Value as of December 31, 2010
	Current		Noncurrent		Current		Noncurrent
Financial Instrument	Assets		Assets		Liabilities		Liabilities
	(Dollars in millions)
Diesel fuel cash flow hedge contracts	$	25.3	$	26.9	$	11.9	$	—
Explosives cash flow hedge contracts		0.5		0.1		0.1		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 condensed consolidated balance sheets.

See Note 6 for information related to the Company’s coal trading activities.

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Fair Value Measurements

Fair Value Measured on a Recurring Basis. 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.

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:


	June 30, 2011
	Level 1		Level 2			Level 3		Total
	(Dollars in millions)
Investment in debt and equity securities	$	41.4	$	—		$	—	$	41.4
Commodity swaps and options — diesel fuel		—		95.3			—		95.3
Commodity swaps and options — explosives		—		(1.3	)		—		(1.3	)
Foreign currency hedge contracts		—		773.6			—		773.6

Total net financial assets	$	41.4	$	867.6		$	—	$	909.0


	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 — diesel fuel		—		40.3			—		40.3
Commodity swaps and options — explosives		—		(0.1	)		—		(0.1	)
Foreign currency 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 the three or six months ended June 30, 2011 or 2010 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 June 30, 2011 and December 31, 2010:

•

Cash and cash equivalents, short-term investments, 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 financial nature of these instruments.

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	•		The Company’s 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 condensed consolidated balance sheets. The debt securities are recorded at cost, which approximates fair value, in Australian dollars adjusted for changes in the U.S. dollar to Australian dollar exchange rates. The equity 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:


	June 30, 2011				December 31, 2010
	Carrying		Estimated		Carrying		Estimated
	Amount		Fair Value		Amount		Fair Value
	(Dollars in millions)
Long-term debt	$	2,512.0	$	2,696.7	$	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 conducts its hedging activities related to foreign currency, interest rate, fuel and explosives exposures with a variety of investment grade commercial banks and closely monitors 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.

(6) 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-cleared. 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 unaudited condensed consolidated statements of operations and include realized and unrealized gains and losses on derivative instruments, including those 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.


	Three Months Ended June 30,					Six Months Ended June 30,
Trading Revenues by Type of Instrument	2011		2010			2011			2010
	(Dollars in millions)
Commodity swaps and options	$	5.8	$	(36.8	)	$	(26.0	)	$	(9.4	)

Physical commodity purchase/sale contracts		9.4		89.7			31.3			118.3


Total trading revenues	$	15.2	$	52.9		$	5.3		$	108.9

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 the six months ended June 30, 2011, the Company reclassified losses of $6.5 million out of “Accumulated other comprehensive income (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:


	June 30, 2011						December 31, 2010
	(Dollars in millions)
	Gross Basis			Net Basis			Gross Basis			Net Basis
Assets from coal trading activities	$	1,095.5		$	109.2		$	1,706.2		$	192.5
Liabilities from coal trading activities		(1,248.5	)		(106.1	)		(1,843.5	)		(181.7	)

Subtotal		(153.0	)		3.1			(137.3	)		10.8
Net margin posted ⁽¹⁾		156.1			—			148.1			—

Net value of coal trading positions	$	3.1		$	3.1		$	10.8		$	10.8


⁽¹⁾		Represents margin posted with counterparties and exchanges of $156.1 million at June 30, 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 posted at June 30, 2011, approximately 88% related to cash flow hedges.

The Company’s trading assets and liabilities are generally made up of forward contracts, financial swaps and margin. The net fair value of coal trading positions designated as cash flow hedges of anticipated future sales was a liability of $200.8 million and $174.2 million as of June 30, 2011 and December 31, 2010, respectively.

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


	June 30, 2011
	Level 1		Level 2			Level 3		Total
	(Dollars in millions)
Commodity swaps and options	$	7.3	$	(19.7	)	$	—	$	(12.4	)
Physical commodity purchase/sale contracts		—		5.5			10.0		15.5

Total net financial assets (liabilities)	$	7.3	$	(14.2	)	$	10.0	$	3.1


	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, New York Mercantile Exchange (NYMEX), Intercontinental Exchange indices (ICE), NOS Clearing ASA, LCH.Clearnet (formerly known as the London Clearing House), 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 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, 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.

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(Dollars in millions)
Beginning of period	$	12.5		$	12.5		$	18.6		$	17.0
Total gains or losses (realized/unrealized):
Included in earnings		(1.9	)		3.3			9.5			(0.4	)
Included in other comprehensive income		—			0.5			—			—
Settlements		(0.7	)		(2.5	)		1.0			(2.8	)
Transfers out		0.1			—			(19.1	)		—

End of period	$	10.0		$	13.8		$	10.0		$	13.8

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


	Three Months Ended June 30,					Six Months Ended June 30,
	2011			2010		2011		2010
	(Dollars in millions)
Changes in unrealized gains (losses) ⁽¹⁾	$	(0.6	)	$	2.2	$	9.9	$	1.3


(1)		Within the unaudited condensed consolidated statements of operations 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 the three or six months ended June 30, 2011 or 2010. During the six months ended June 30, 2011, 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. There were no significant transfers in or out of Level 3 during the three and six months ended June 30, 2010. 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 income (loss)” at June 30, 2011, unrealized losses to be reclassified from comprehensive income to earnings over the next 12 months are expected to be approximately $112 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 condensed consolidated statements of operations.

As of June 30, 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
	2011		54	%
	2012		32	%
	2013		4	%
	2014		7	%
	2015		3	%

			100	%

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 June 30, 2011, 43% of the Company’s credit exposure related to coal trading activities was with investment grade counterparties while 46% was with non-investment grade counterparties and 11% 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 was 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 June 30, 2011 and December 31, 2010, would have amounted to collateral postings of approximately $102 million and $160 million, respectively, to its counterparties. As of June 30, 2011, $5.9 million of 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 approximately $6 million at June 30, 2011 and zero at December 31, 2010 based on the aggregate fair value of all derivative trading instruments with such features that were in a net liability position. As of June 30, 2011, the Company had posted $1.0 million for such instruments in a net liability position. 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 by an exchange to post certain 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 June 30, 2011 and December 31, 2010, the Company had posted initial margin of $43.5 million and $39.5 million, respectively (reflected in “Other current assets”). In addition, the Company had posted $1.4 million and $4.4 million of margin in excess of the exchange-required variation (discussed below) and initial margin as of June 30, 2011 and December 31, 2010, respectively (also reflected in “Other current assets”).

The Company is required to post collateral on positions that are in a net liability position with an exchange, known as variation margin, which was $149.2 million as of June 30, 2011 and $137.4 million as of December 31, 2010 (reflected in “Liabilities from coal trading activities, net”).

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(7) Income Taxes

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(Dollars in millions)
Expected income tax provision at federal statutory rate	$	144.5		$	93.8		$	231.1		$	161.4
Excess depletion		(14.3	)		(12.9	)		(25.1	)		(22.6	)
Foreign earnings provision differential		(33.7	)		(13.1	)		(49.7	)		(27.9	)
Remeasurement of foreign income tax accounts		15.4			(19.3	)		21.8			(13.9	)
State income taxes, net of U.S. federal tax benefit		3.9			2.1			5.6			4.5
General business tax credits		(4.8	)		(3.9	)		(8.0	)		(7.5	)
Changes in valuation allowance		3.5			17.5			4.5			22.7
Changes in tax reserves		2.9			(8.9	)		4.9			(7.1	)
Other, net		2.4			(1.9	)		2.5			(0.1	)

Total provision	$	119.8		$	53.4		$	187.6		$	109.5

(8) Long-Term Debt

The Company’s total indebtedness consisted of the following at:


	June 30,		December 31,
	2011		2010
	(Dollars in millions)
Term Loan	$	481.3	$	493.8
5.875% Senior Notes due April 2016		—		218.1
7.375% Senior Notes due November 2016		650.0		650.0
6.5% Senior Notes due September 2020		650.0		650.0
7.875% Senior Notes due November 2026		247.2		247.2
Convertible Junior Subordinated Debentures due 2066		374.2		373.3
6.34% Series B Bonds due December 2014		12.0		12.0
6.84% Series C Bonds due December 2016		33.0		33.0
Capital lease obligations		62.3		69.6
Fair value hedge adjustment		—		2.2
Other		2.0		0.8

Total	$	2,512.0	$	2,750.0

5.875% Senior Notes Redemption

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.

Other Long-Term Debt

There were no other significant changes to the Company’s long-term debt since December 31, 2010.

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(9) Pension and Postretirement Benefit Costs

Net periodic pension costs included the following components:


	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
				(Dollars in millions)
Service cost for benefits earned	$	0.5		$	0.4		$	0.9		$	0.8
Interest cost on projected benefit obligation		12.5			12.6			24.9			25.2
Expected return on plan assets		(16.1	)		(15.0	)		(32.2	)		(29.2	)
Amortization of prior service cost		0.2			0.4			0.5			0.7
Amortization of actuarial loss		7.5			5.5			15.0			11.0

Net periodic pension costs	$	4.6		$	3.9		$	9.1		$	8.5

As of June 30, 2011, the Company’s qualified defined benefit pension plans were at or above the thresholds of the Pension Protection Act of 2006 to avoid benefit restrictions and at-risk penalties for 2011. No contributions to the qualified plans are expected during 2011. However, the Company does expect to make contributions to its non-qualified defined benefit pension plans during 2011 totaling less than $2 million.

Net periodic postretirement benefit costs included the following components:


	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
			(Dollars in millions)
Service cost for benefits earned	$	3.2	$	3.1	$	6.5	$	6.2
Interest cost on accumulated postretirement benefit obligation		14.5		14.6		28.9		29.1
Amortization of prior service cost		0.5		0.5		1.0		1.0
Amortization of actuarial loss		6.8		6.3		13.5		12.7

Net periodic postretirement benefit costs	$	25.0	$	24.5	$	49.9	$	49.0

(10) Comprehensive Income

The following table sets forth the after-tax components of comprehensive income:


	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011		2010
	(Dollars in millions)
Net income	$	292.2		$	214.2		$	470.9	$	350.9
Net increase (decrease) in fair value of cash flow hedges, net of income taxes		64.3			(187.2	)		96.8		(132.2	)
Net unrealized (losses) gains on available-for-sale securities, net of income taxes		(0.8	)		—			0.2		—
Amortization of actuarial loss and prior service cost associated with postretirement plans and workers’ compensation obligations, net of income taxes		10.0			8.5			23.5		16.0

Comprehensive income	$	365.7		$	35.5		$	591.4	$	234.7

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Comprehensive income differs from net income by the amount of unrealized gains or losses resulting from valuation changes of the Company’s cash flow hedges (see Note 5 and Note 6) or its available-for-sale securities (see Note 3) and the change in actuarial loss and prior service cost (see Note 9) during the periods presented. None of the reconciling items between net income and comprehensive income relates to the Company’s noncontrolling interest for the periods presented.

(11) Other Commercial Events

In June 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 $23.5 million gain on the exchange. Fair value was determined by using a discounted cash flows model that included assumptions for future coal sales prices, operating costs and discount rate. This non-cash transaction was excluded from the investing section of the unaudited condensed consolidated statement of cash flows.

In June 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 currently under construction.

(12) Earnings per Share (EPS)

The Company’s restricted stock awards are considered participating securities because holders are entitled to receive non-forfeitable dividends during the vesting term. As such, the Company uses the two-class method to compute basic and diluted EPS. Diluted EPS includes securities that could potentially dilute basic EPS during a reporting period, which for 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 8 to the Consolidated Financial Statements in the Company’s Annual Report on Form 10-K for the year ended December 31, 2010.

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 14 to the Consolidated Financial Statements in the Company’s Annual Report on Form 10-K for the year ended December 31, 2010.

For the three and six months ended June 30, 2011 and 2010, the computation of diluted EPS does not include anti-dilutive shares of approximately 0.1 million, which 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.

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following illustrates the earnings allocation method utilized in the calculation of basic and diluted EPS.


	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(In millions, except per share amounts)
EPS numerator:
Income from continuing operations, net of income taxes	$	293.0		$	214.7		$	472.6		$	351.8
Less: Net income attributable to noncontrolling interests		7.4			8.0			9.6			11.0

Income from continuing operations attributable to common stockholders, before allocation of earnings to participating securities		285.6			206.7			463.0			340.8
Less: Earnings allocated to participating securities		(1.7	)		(1.5	)		(2.6	)		(2.5	)

Income from continuing operations attributable to common stockholders, after earnings allocated to participating securities ⁽¹⁾		283.9			205.2			460.4			338.3
Loss from discontinued operations, net of income taxes		(0.8	)		(0.5	)		(1.7	)		(0.9	)

Net income attributable to common stockholders, after earnings allocated to participating securities ⁽¹⁾	$	283.1		$	204.7		$	458.7		$	337.4


EPS denominator:
Weighted average shares outstanding — basic		269.0			266.6			269.0			266.6
Impact of dilutive securities		1.5			1.7			1.6			1.7

Weighted average shares outstanding — diluted		270.5			268.3			270.6			268.3


Basic EPS attributable to common stockholders:
Income from continuing operations	$	1.05		$	0.77		$	1.71		$	1.27
Income (loss) from discontinued operations		—			—			(0.01	)		—

Net income	$	1.05		$	0.77		$	1.70		$	1.27


Diluted EPS attributable to common stockholders:
Income from continuing operations	$	1.05		$	0.76		$	1.70		$	1.26
Income (loss) from discontinued operations		—			—			(0.01	)		—

Net income	$	1.05		$	0.76		$	1.69		$	1.26


(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.

(13) 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 condensed 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.

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Financial Instruments with Off-Balance Sheet Risk

As of June 30, 2011, the Company had the following financial instruments with off-balance sheet risk:


					Workers’
	Reclamation		Lease		Compensation
	Obligations		Obligations		Obligations		Other ⁽¹⁾		Total
	(Dollars in millions)
Self bonding	$	936.6	$	—	$	—	$	—	$	936.6
Surety bonds		613.5		110.3		6.2		10.8		740.8
Bank guarantees		139.9		—		—		151.3		291.2
Letters of credit		—		—		62.7		2.8		65.5
Bilateral cash collateralization agreements		—		—		—		79.7		79.7

	$	1,690.0	$	110.3	$	68.9	$	244.6	$	2,113.8


⁽¹⁾		Other includes letter of credit and bilateral cash collateralization agreement obligations described below and an additional $162.1 million in bank guarantees 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 June 30, 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 the Company’s unsecured credit facility (Credit Facility). See Note 8 to the Consolidated Financial Statements in the Company’s Annual Report on Form 10-K for the year ended December 31, 2010 for more information on the Company’s 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 the Company’s Credit Facility. Such cash collateral is classified within cash and cash equivalents given the Company has the ability to substitute a letter 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 June 30, 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.

At June 30, 2011, the Company had a $2.8 million letter of credit outstanding for collateral for bank guarantees issued with respect to certain reclamation and performance obligations related to some of the Company’s Australian mines.

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 June 30, 2011, the Company had $4.5 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 the Company’s Credit Facility, effectively managing its overall borrowing costs and providing an additional source for working capital. The 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 six months ended June 30, 2011, the Company received total consideration of $2,376.8 million related to accounts receivable sold under the securitization program, including $1,805.9 million of cash up front from the sale of the receivables, an additional $344.8 million of cash upon the collection of the underlying receivables, and $226.1 million that had not been collected at June 30, 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 June 30, 2011 and December 31, 2010.

The securitization activity has been reflected in the unaudited condensed consolidated statements of cash flows as operating activity because both the cash received from the Conduits upon sale of the receivables as well as the cash received from the Conduits upon the ultimate collection of the 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 $0.5 million for each of the three months ended June 30, 2011 and 2010, and $1.1 million and $1.2 million for the six months ended June 30, 2011 and 2010, 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 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.

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(14) Commitments and Contingencies

Commitments

As of June 30, 2011, purchase commitments for capital expenditures were $307.4 million, all of which is obligated within the next two years with $245.7 million obligated in the next 12 months.

A subsidiary of the Company owns a 5.06% undivided interest in Prairie State. The Company invested $21.5 million during the six months ended June 30, 2011, representing its 5.06% share of the construction costs. Included in “Investments and other assets” in the condensed consolidated balance sheets as of June 30, 2011 and December 31, 2010 are costs of $224.0 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 most of the remaining funding expected in 2011.

There were no other material changes to the Company’s commitments from the information provided in Note 20 to the Consolidated Financial Statements in the Company’s Annual Report on Form 10-K for the year ended December 31, 2010.

Contingencies

From time to time, the Company and/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. The Navajo Nation alleged 16 claims, including Civil Racketeer Influenced and Corrupt Organizations Act (RICO) violations and fraud. On April 12, 2010, the Navajo Nation filed an amended complaint to substantially narrow the scope of its claims by removing the RICO allegations but leaving the other 12 common law tort and contractual claims. The complaint alleges that the defendants jointly participated in unlawful activity to obtain favorable coal lease amendments. The plaintiff is seeking various remedies including actual damages of at least $600 million, punitive damages of at least $1 billion, a determination that Peabody Western’s two coal leases terminated due to Peabody Western’s breach of these leases and a reformation of these leases to adjust the royalty rate to 20%. The court allowed the Hopi Tribe to intervene in this lawsuit, and the Hopi Tribe sought unspecified actual damages, punitive damages and reformation of its coal lease. One of the Company’s subsidiaries named as a defendant is now a subsidiary of Patriot Coal Corporation (Patriot). However, the Company is responsible for this litigation under the Separation Agreement entered into with Patriot in connection with the spin-off. The U.S. Supreme Court has ruled against the Navajo Nation in a related case against the U.S. government, and remanded that case to the lower court to dismiss the complaint. The U.S. Supreme Court said that none of the sources relied on by the Navajo Nation provided a basis for its breach-of-trust lawsuit against the U.S. government, which undermines some of the claims the Navajo Nation asserts in its litigation against the Company.

In October 2010, the Company and the other defendants settled the Hopi claims, and the court dismissed those claims. In August 2011, the Company 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 the three months ended June 30, 2011.

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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. Gulf Power filed a motion for partial summary judgment on liability, and the Company subsidiary filed a motion for summary judgment seeking complete dismissal. On June 30, 2009, the court granted Gulf Power’s motion for partial summary judgment and denied the Company subsidiary’s motion for summary judgment. The damages portion of the trial was held in February 2010. On September 30, 2010, the court entered its order on damages, awarding Gulf Power zero dollars in damages and the Company its costs to defend the lawsuit. The Company is also seeking its reasonable attorney’s fees incurred since October 15, 2008. 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 objected. The court entered an order on July 29, 2011, that (1) affirmed its September 30, 2010 decision in all respects except for 2007 cover coal purchases, (2) granted in part Gulf Power’s motion to alter judgment with respect to 2007 cover coal purchases, and (3) scheduled a hearing for August 25, 2011 to consider further evidence on expenses saved by Gulf Power in its 2007 cover coal purchases.

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

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 two property damage lawsuits 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. These cases were originally filed as putative class actions, but the court denied class certification and the cases were subsequently amended to include a number of individual plaintiffs.

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.

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 defenses 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.

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED 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 $51.6 million as of June 30, 2011 and $51.1 million as of December 31, 2010, $6.6 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.

Gold Fields is involved in other litigation and claims in the Picher area, and the Company indemnified TXU Group with respect to a defendant as is more fully discussed under the “Oklahoma Lead Litigation” caption above.

Significant uncertainty exists as to whether claims will be pursued against Gold Fields in all cases, and where they are pursued, the amount of the eventual costs and liabilities, which could be greater or less than the liabilities recorded in the consolidated balance sheets. Based on 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 are appealing the court’s dismissal to the U.S. Court of Appeals for the Ninth Circuit. The parties have filed their respective briefs with the court. The Ninth Circuit stayed the case until July 15, 2011, pending a decision by the U.S. Supreme Court in American Electric Power Co. (AEP) v. Connecticut . On June 20, 2011, the U.S. Supreme Court reversed and remanded the decision by the Second Circuit in AEP v. Connecticut , in which the Court unanimously held that plaintiffs’ federal common law public nuisance claim, which sought abatement of the utility company defendants’ carbon dioxide emissions from power plants, is displaced by the Clean Air Act, 42 U.S.C. § 7401, et. seq . The Kivalina parties have requested the Ninth Circuit to enter a briefing schedule to supplement the parties’ briefs based on the AEP decision.

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 that 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.

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(15) 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 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 were as follows:


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
	(Dollars in millions)
Revenues:
Western U.S. Mining	$	662.3		$	652.1		$	1,366.0		$	1,314.2
Midwestern U.S. Mining		327.9			323.3			694.9			632.7
Australian Mining		885.3			597.4			1,465.9			1,043.9
Trading and Brokerage		114.1			81.8			198.0			171.9
Corporate and Other		18.4			6.8			28.1			14.3

Total	$	2,008.0		$	1,661.4		$	3,752.9		$	3,177.0


Adjusted EBITDA:
Western U.S. Mining	$	134.1		$	207.3		$	313.5		$	415.2
Midwestern U.S. Mining		82.0			71.4			191.9			145.5
Australian Mining		376.9			223.6			567.4			346.9
Trading and Brokerage		50.4			14.3			77.2			46.7
Corporate and Other		(63.9	)		(76.2	)		(154.3	)		(156.7	)

Total	$	579.5		$	440.4		$	995.7		$	797.6

A reconciliation of Adjusted EBITDA to consolidated income from continuing operations follows:


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
	(Dollars in millions)
Total Adjusted EBITDA	$	579.5		$	440.4		$	995.7		$	797.6

Depreciation, depletion and amortization		105.3			105.1			214.1			210.6
Asset retirement obligation expense		15.8			10.9			28.9			20.4
Interest expense		49.1			57.9			100.1			107.9
Interest income		(3.5	)		(1.6	)		(7.6	)		(2.6	)
Income tax provision		119.8			53.4			187.6			109.5

Income from continuing operations, net of income taxes	$	293.0		$	214.7		$	472.6		$	351.8

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(16) Supplemental Guarantor/Non-Guarantor Financial Information

In accordance with the indentures governing the 6.875% Senior Notes due March 2013 (redeemed in the third quarter of 2010), the 5.875% Senior Notes due March 2016 (redeemed in the second quarter of 2011 as discussed in Note 8), the 7.375% Senior Notes due November 2016, the 6.5% Senior Notes due September 2020 and the 7.875% Senior Notes due November 2026 (collectively; the Senior Notes), certain wholly-owned U.S. subsidiaries of the Company have fully and unconditionally guaranteed the 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.

Unaudited Supplemental Condensed Consolidating Statements of Operations


	Three Months Ended June 30, 2011
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(Dollars in millions)
Total revenues	$	—		$	1,275.7		$	777.5		$	(45.2	)	$	2,008.0
Costs and expenses
Operating costs and expenses		(107.2	)		1,062.1			483.1			(45.2	)		1,392.8
Depreciation, depletion and amortization		—			69.3			36.0			—			105.3
Asset retirement obligation expense		—			10.2			5.6			—			15.8
Selling and administrative expenses		8.4			48.5			1.7			—			58.6
Other operating (income) loss:
Net gain on disposal or exchange of assets		—			(25.6	)		(0.1	)		—			(25.7	)
(Income) loss from equity affiliates		(251.9	)		1.8			1.0			251.9			2.8
Interest expense		50.2			13.7			2.4			(17.2	)		49.1
Interest income		(4.4	)		(5.3	)		(11.0	)		17.2			(3.5	)

Income from continuing operations before income taxes		304.9			101.0			258.8			(251.9	)		412.8
Income tax provision		19.9			20.4			79.5			—			119.8

Income from continuing operations, net of income taxes		285.0			80.6			179.3			(251.9	)		293.0
Loss from discontinued operations, net of income taxes		(0.2	)		(0.6	)		—			—			(0.8	)

Net income		284.8			80.0			179.3			(251.9	)		292.2
Less: Net income attributable to noncontrolling interests		—			—			7.4			—			7.4

Net income attributable to common stockholders	$	284.8		$	80.0		$	171.9		$	(251.9	)	$	284.8

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Unaudited Supplemental Condensed Consolidated Statements of Operations


	Three Months Ended June 30, 2010
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(Dollars in millions)
Total revenues	$	—		$	960.5		$	887.3		$	(186.4	)	$	1,661.4
Costs and expenses
Operating costs and expenses		(12.6	)		693.5			680.2			(186.4	)		1,174.7
Depreciation, depletion and amortization		—			72.7			32.4			—			105.1
Asset retirement obligation expense		—			8.0			2.9			—			10.9
Selling and administrative expenses		8.4			41.9			3.8			—			54.1
Other operating (income) loss:
Net gain on disposal or exchange of assets		—			(1.2	)		(0.2	)		—			(1.4	)
(Income) loss from equity affiliates		(240.5	)		1.9			1.8			230.4			(6.4	)
Interest expense		57.5			12.7			3.8			(16.1	)		57.9
Interest income		(3.8	)		(5.5	)		(8.4	)		16.1			(1.6	)

Income from continuing operations before income taxes		191.0			136.5			171.0			(230.4	)		268.1
Income tax provision (benefit)		(15.2	)		39.0			29.6			—			53.4

Income from continuing operations, net of income taxes		206.2			97.5			141.4			(230.4	)		214.7
Loss from discontinued operations, net of income taxes		—			(0.5	)		—			—			(0.5	)

Net income		206.2			97.0			141.4			(230.4	)		214.2
Less: Net income attributable to noncontrolling interests		—			—			8.0			—			8.0

Net income attributable to common stockholders	$	206.2		$	97.0		$	133.4		$	(230.4	)	$	206.2

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Unaudited Supplemental Condensed Consolidating Statements of Operations


	Six Months Ended June 30, 2011
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(Dollars in millions)
Total revenues	$	—		$	2,252.6		$	1,674.5		$	(174.2	)	$	3,752.9
Costs and expenses
Operating costs and expenses		(190.0	)		1,748.3			1,276.8			(174.2	)		2,660.9
Depreciation, depletion and amortization		—			143.5			70.6			—			214.1
Asset retirement obligation expense		—			20.0			8.9			—			28.9
Selling and administrative expenses		16.9			98.5			4.8			—			120.2
Other operating (income) loss:
Net (gain) loss on disposal or exchange of assets		—			(30.5	)		0.8			—			(29.7	)
(Income) loss from equity affiliates		(411.8	)		3.7			2.1			411.8			5.8
Interest expense		101.3			26.9			5.8			(33.9	)		100.1
Interest income		(8.7	)		(10.6	)		(22.2	)		33.9			(7.6	)

Income from continuing operations before income taxes		492.3			252.8			326.9			(411.8	)		660.2
Income tax provision		30.2			61.6			95.8			—			187.6

Income from continuing operations, net of income taxes		462.1			191.2			231.1			(411.8	)		472.6
Loss from discontinued operations, net of income taxes		(0.8	)		(0.9	)		—			—			(1.7	)

Net income		461.3			190.3			231.1			(411.8	)		470.9
Less: Net income attributable to noncontrolling interests		—			—			9.6			—			9.6

Net income attributable to common stockholders	$	461.3		$	190.3		$	221.5		$	(411.8	)	$	461.3


	Six Months Ended June 30, 2010
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(Dollars in millions)
Total revenues	$	—		$	2,064.0		$	1,485.2		$	(372.2	)	$	3,177.0
Costs and expenses
Operating costs and expenses		(40.9	)		1,522.3			1,174.2			(372.2	)		2,283.4
Depreciation, depletion and amortization		—			145.1			65.5			—			210.6
Asset retirement obligation expense		—			15.0			5.4			—			20.4
Selling and administrative expenses		17.5			86.5			5.5			—			109.5
Other operating (income) loss:
Net gain on disposal or exchange of assets		—			(8.5	)		(0.2	)		—			(8.7	)
(Income) loss from equity affiliates		(391.1	)		3.7			3.0			379.6			(4.8	)
Interest expense		107.0			25.5			7.5			(32.1	)		107.9
Interest income		(7.6	)		(10.9	)		(16.2	)		32.1			(2.6	)

Income from continuing operations before income taxes		315.1			285.3			240.5			(379.6	)		461.3
Income tax provision (benefit)		(24.8	)		87.9			46.4			—			109.5

Income from continuing operations, net of income taxes		339.9			197.4			194.1			(379.6	)		351.8
Loss from discontinued operations, net of income taxes		—			(0.9	)		—			—			(0.9	)

Net income		339.9			196.5			194.1			(379.6	)		350.9
Less: Net income attributable to noncontrolling interests		—			—			11.0			—			11.0

Net income attributable to common stockholders	$	339.9		$	196.5		$	183.1		$	(379.6	)	$	339.9

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Unaudited Supplemental Condensed Consolidating Balance Sheet


	June 30, 2011
	Parent		Guarantor			Non-Guarantor		Reclassifications/
	Company		Subsidiaries			Subsidiaries		Eliminations			Consolidated
	(Dollars in millions)
Assets
Current assets
Cash and cash equivalents	$	719.3	$	0.7		$	456.9	$	—		$	1,176.9
Short-term investments		50.0		—			25.0		—			75.0
Accounts receivable, net		5.4		19.3			620.1		—			644.8
Inventories		—		190.2			183.8		—			374.0
Assets from coal trading activities, net		—		21.4			87.8		—			109.2
Deferred income taxes		—		46.2			63.4		(6.1	)		103.5
Other current assets		444.9		30.3			151.8		—			627.0

Total current assets		1,219.6		308.1			1,588.8		(6.1	)		3,110.4
Property, plant, equipment and mine development, net		—		4,735.4			2,848.6		—			7,584.0
Investments and other assets		9,792.7		173.6			133.2		(9,048.3	)		1,051.2

Total assets	$	11,012.3	$	5,217.1		$	4,570.6	$	(9,054.4	)	$	11,745.6


Liabilities and Stockholders’ Equity
Current liabilities
Current maturities of long-term debt	$	25.0	$	—		$	18.8	$	—		$	43.8
Payables to (receivables from) affiliates, net		2,327.9		(2,576.4	)		248.5		—			—
Liabilities from coal trading activities, net		—		16.2			89.9		—			106.1
Deferred income taxes		6.1		—			—		(6.1	)		—
Accounts payable and accrued expenses		25.9		707.4			602.3		—			1,335.6

Total current liabilities		2,384.9		(1,852.8	)		959.5		(6.1	)		1,485.5
Long-term debt, less current maturities		2,377.7		0.1			90.4		—			2,468.2
Deferred income taxes		156.7		111.7			329.4		—			597.8
Notes payable to (receivables from) affiliates, net		819.1		(825.1	)		6.0		—			—
Other noncurrent liabilities		58.5		1,670.5			219.8		—			1,948.8

Total liabilities		5,796.9		(895.6	)		1,605.1		(6.1	)		6,500.3
Peabody Energy Corporation’s stockholders’ equity		5,215.4		6,112.7			2,935.6		(9,048.3	)		5,215.4
Noncontrolling interests		—		—			29.9		—			29.9

Total stockholders’ equity		5,215.4		6,112.7			2,965.5		(9,048.3	)		5,245.3

Total liabilities and stockholders’ equity	$	11,012.3	$	5,217.1		$	4,570.6	$	(9,054.4	)	$	11,745.6

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Supplemental Condensed Consolidating Balance Sheet


	December 31, 2010
	Parent		Guarantor			Non-Guarantor		Reclassifications/
	Company		Subsidiaries			Subsidiaries		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			550.6		—			558.2
Inventories		—		168.0			164.9		—			332.9
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			120.4		—			459.0

Total current assets		1,213.8		311.8			1,438.7		(6.1	)		2,958.2
Property, plant, equipment and mine development, net		—		4,732.7			2,693.4		—			7,426.1
Investments and other assets		9,331.0		179.8			99.1		(8,631.1	)		978.8

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			311.2		—			539.8
Notes payable to (receivables from) affiliates, net		818.9		(825.3	)		6.4		—			—
Other noncurrent liabilities		58.6		1,652.8			202.1		—			1,913.5

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
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Unaudited Supplemental Condensed Consolidating Statements of Cash Flows


	Six Months Ended June 30, 2011
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Consolidated
	(Dollars in millions)
Cash Flows From Operating Activities
Net cash provided by continuing operations	$	43.8		$	417.7		$	156.7		$	618.2
Net cash used in discontinued operations		(1.4	)		(1.2	)		—			(2.6	)

Net cash provided by operating activities		42.4			416.5			156.7			615.6


Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development		—			(123.6	)		(231.2	)		(354.8	)
Investment in Prairie State Energy Campus		—			(21.5	)		—			(21.5	)
Proceeds from disposal of assets		—			9.6			—			9.6
Investment in equity affiliates and joint ventures		—			(2.4	)		—			(2.4	)
Proceeds from sale of debt securities		—			—			21.0			21.0
Purchases of debt securities		—			—			(14.6	)		(14.6	)
Purchases of short-term investments		(75.0	)		—			(25.0	)		(100.0	)
Maturity of short-term investments		25.0			—			—			25.0
Other, net		—			(1.8	)		(0.3	)		(2.1	)

Net cash used in investing activities		(50.0	)		(139.7	)		(250.1	)		(439.8	)

Cash Flows From Financing Activities
Proceeds from long-term debt		—			—			1.4			1.4
Payments of long-term debt		(230.6	)		—			(7.6	)		(238.2	)
Dividends paid		(46.8	)		—			—			(46.8	)
Repurchase of employee common stock relinquished for tax withholding		(15.4	)		—			—			(15.4	)
Excess tax benefits related to share-based compensation		5.8			—			—			5.8
Proceeds from stock options exercised		4.4			—			—			4.4
Other, net		3.0			—			(8.3	)		(5.3	)
Transactions with affiliates, net		102.7			(281.3	)		178.6			—

Net cash provided by (used in) financing activities		(176.9	)		(281.3	)		164.1			(294.1	)

Net change in cash and cash equivalents		(184.5	)		(4.5	)		70.7			(118.3	)
Cash and cash equivalents at beginning of period		903.8			5.2			386.2			1,295.2

Cash and cash equivalents at end of period	$	719.3		$	0.7		$	456.9		$	1,176.9

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Unaudited Supplemental Condensed Consolidating Statements of Cash Flows


	Six Months Ended June 30, 2010
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Consolidated
	(Dollars in millions)
Cash Flows From Operating Activities
Net cash provided by (used in) continuing operations	$	(98.1	)	$	454.1		$	118.3		$	474.3
Net cash used in discontinued operations		(8.8	)		(1.1	)		—			(9.9	)

Net cash provided by (used in) operating activities		(106.9	)		453.0			118.3			464.4


Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development		—			(159.3	)		(28.2	)		(187.5	)
Investment in Prairie State Energy Campus		—			(30.5	)		—			(30.5	)
Proceeds from disposal of assets		—			4.9			1.2			6.1
Investment in equity affiliates and joint ventures		—			(15.0	)		(2.4	)		(17.4	)
Other, net		—			(4.3	)		(0.1	)		(4.4	)

Net cash used in investing activities		—			(204.2	)		(29.5	)		(233.7	)

Cash Flows From Financing Activities
Proceeds from long-term debt		500.0			—			—			500.0
Payments of long-term debt		(490.3	)		—			(5.4	)		(495.7	)
Dividends paid		(37.6	)		—			—			(37.6	)
Repurchase of employee common stock relinquished for tax withholding		(8.0	)		—			—			(8.0	)
Payment of debt issuance costs		(21.9	)		—			—			(21.9	)
Proceeds from stock options exercised		2.4			—			—			2.4
Other, net		2.8			(2.4	)		(2.1	)		(1.7	)
Transactions with affiliates, net		240.1			(246.4	)		6.3			—

Net cash provided by (used in) financing activities		187.5			(248.8	)		(1.2	)		(62.5	)

Net change in cash and cash equivalents		80.6			—			87.6			168.2
Cash and cash equivalents at beginning of period		368.4			0.2			620.2			988.8

Cash and cash equivalents at end of period	$	449.0		$	0.2		$	707.8		$	1,157.0

(17) Subsequent Events

Offer for Macarthur Coal Ltd

On August 1, 2011, the Company and ArcelorMittal SA (ArcelorMittal) launched an all-cash off-market takeover offer to acquire all the shares in Macarthur Coal Ltd (Macarthur). The offer is made by a newly formed company, PEAMCoal Pty Ltd (PEAMCoal), to be owned 60% by the Company and 40% by ArcelorMittal. PEAMCoal has a relevant interest of 16.1% in Macarthur’s shares.

Under the offer, Macarthur shareholders will have been offered a cash price of $15.50 Australian dollars per share. Macarthur shareholders will also be entitled to retain any final dividend declared by Macarthur in respect of the financial year ended June 30, 2011, up to an amount of 16 Australian cents per share, without there being any reduction in the offer price, implying a total value of up to a cash price of $15.66 Australian dollars per share. The proposal price values the equity in Macarthur at approximately $4.7 billion Australian dollars (or approximately $5.2 billion U.S. dollars). On August 4, 2011, the Company and ArcelorMittal lodged with the Australian Securities and Investments Commission the bidder’s statement associated with the offer.

The offer is subject to a number of conditions including minimum 50.01% acceptances, approval by Australia’s Foreign Investment Review Board, other regulatory approvals and other standard conditions.

Federal Coal Lease

In July 2011, the Company was named the winning bidder for control of approximately 220 million tons of low sulfur coal reserves in the Powder River Basin of Wyoming that will be assigned to the Company’s Caballo Mine. The Company made its first payment of $42.1 million in July 2011, with the remaining annual payments of $42.1 million to be made in July of each of the next four years.


Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Cautionary Notice Regarding Forward-Looking Statements

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

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

•

demand for coal in the United States (U.S.) and the seaborne thermal and metallurgical coal markets;

•

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

•

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, 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;

•

successful implementation of business strategies, including our Btu Conversion and generation development initiatives;

•

negotiation of labor contracts, employee relations and workforce availability;

•

changes in postretirement benefit and pension obligations and 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 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.

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, including the more detailed discussion of these factors, as well as other factors that could affect our results, contained in Item 1A. “Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2010. These forward-looking statements speak only as of the date on which such statements were made, and we undertake no obligation to update these statements except as required by federal securities laws.

Overview

We are the world’s largest private sector coal company, with majority interests in 28 coal mining operations in the U.S. and Australia. In 2010, we produced 218.4 million tons of coal and sold 245.9 million tons of coal.

We conduct business through four principal operating segments: Western U.S. Mining, Midwestern U.S. Mining, Australian Mining, and Trading and Brokerage. Our fifth segment, Corporate and Other, includes mining and export/transportation joint ventures, energy-related commercial activities, as well as the management of our vast coal reserve and real estate holdings. In the U.S., we typically sell coal to utility customers under long-term contracts (those with terms longer than one year). In Australia, our 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 contracts annually. During 2010, approximately 91% of our worldwide sales (by volume) were under long-term contracts. For the year ended December 31, 2010, 84% of our total sales (by volume) were to U.S. electricity generators, 14% were to customers outside the U.S. and 2% were to the U.S. industrial sector.

We continue to explore Btu Conversion projects that expand the uses of coal through coal-to-liquids (CTL) and coal-to-gas (CTG) technologies. Our participation in generation development projects involves using our surface lands and coal reserves as the basis for mine-mouth plants, such as with our involvement in the Prairie State Energy Campus (Prairie State). We are also advancing several initiatives associated with clean coal technologies, including carbon capture and storage (CCS).

Recent Events

On August 1, 2011, we announced, with ArcelorMittal SA (ArcelorMittal), that we jointly launched an all-cash off-market takeover offer to acquire all the shares in Macarthur Coal Ltd (Macarthur). The offer is made by a newly formed company, PEAMCoal Pty Ltd (PEAMCoal), to be owned 60% by us and 40% by ArcelorMittal. PEAMCoal has a relevant interest of 16.1% in Macarthur’s shares.

Under the offer, Macarthur shareholders will have been offered a cash price of $15.50 Australian dollars per share. Macarthur shareholders will also be entitled to retain any final dividend declared by Macarthur in respect of the financial year ended June 30, 2011, up to an amount of 16 Australian cents per share, without there being any reduction in the offer price, implying a total value of up to a cash price of $15.66 Australian dollars per share. The proposal price values the equity in Macarthur at approximately $4.7 billion Australian dollars (or approximately $5.2 billion U.S. dollars). On August 4, 2011, we and ArcelorMittal lodged with the Australian Securities and Investment Commission the bidder’s statement associated with the offer.

Results of Operations

Adjusted EBITDA

The discussion of our results of operations below includes references to and analysis of our segments’ 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), in Note 15 to our unaudited condensed consolidated financial statements.

Three and Six Months Ended June 30, 2011 Compared to Three and Six Months Ended June 30, 2010

Summary

Global demand for seaborne coal remained strong. During the first half of 2011, electricity generation has risen 13.5% and 8% in China and India, respectively, while world steel output has increased 8.2% year to date. Pacific Rim growth continued to drive demand and pricing for Australian seaborne metallurgical and thermal coal. The demand led to second quarter increases of 50% and 16% in realized prices for our seaborne metallurgical and thermal coal, respectively, from our Australian mines as compared to the same period in the prior year.

In the U.S., electricity generation through the first six months of 2011 was comparable to the prior year given weak economic growth and industrial production. Weather and flooding impacted our sales and production volumes in the Midwest and our shipped volumes in the Powder River Basin due to rail transportation constraints. However, U.S. export activity increased during the first quarter, the most recent publicly available data, with rising volumes at east, west and gulf coast ports.

Revenue increased for both periods compared to the prior year (three months, $346.6 million; six months, $575.9 million) and Segment Adjusted EBITDA increased for both periods over the prior year (three months, $126.8 million; six months, $195.7 million), led by higher Australian metallurgical and seaborne thermal coal pricing with increased Australian volumes impacting the three months ended June 30, 2011.

Income from continuing operations, net of income taxes, increased for both periods compared to the prior year (three months, $78.3 million; six months, $120.8 million) due to the increase in Segment Adjusted EBITDA discussed above and lower interest expense, partially offset by increased income taxes and decreased Corporate and Other Adjusted EBITDA.

At June 30, 2011, our available liquidity was $2.7 billion, as discussed further in “Liquidity and Capital Resources.”

Tons Sold

The following table presents tons sold by operating segment:


	Three Months Ended										Six Months Ended
	June 30,				Increase (Decrease)						June 30,				Increase (Decrease)
	2011		2010		Tons			%			2011		2010		Tons			%
	(Tons in millions)										(Tons in millions)
Western U.S. Mining		39.7		39.8		(0.1	)		(0.3	)%		83.5		79.8		3.7			4.6	%
Midwestern U.S. Mining		6.9		7.3		(0.4	)		(5.5	)%		14.5		14.4		0.1			0.7	%
Australian Mining		6.9		6.4		0.5			7.8	%		12.5		12.6		(0.1	)		(0.8	)%
Trading and Brokerage		4.7		6.2		(1.5	)		(24.2	)%		8.9		11.2		(2.3	)		(20.5	)%

Total tons sold		58.2		59.7		(1.5	)		(2.5	)%		119.4		118.0		1.4			1.2	%

Revenues

The following table presents revenues by operating segment:


	Three Months Ended									Six Months Ended
	June 30,				Increase to Revenues					June 30,				Increase to Revenues
	2011		2010		$		%			2011		2010		$		%
	(Dollars in millions)									(Dollars in millions)
Western U.S. Mining	$	662.3	$	652.1	$	10.2		1.6	%	$	1,366.0	$	1,314.2	$	51.8		3.9	%
Midwestern U.S. Mining		327.9		323.3		4.6		1.4	%		694.9		632.7		62.2		9.8	%
Australian Mining		885.3		597.4		287.9		48.2	%		1,465.9		1,043.9		422.0		40.4	%
Trading and Brokerage		114.1		81.8		32.3		39.5	%		198.0		171.9		26.1		15.2	%
Corporate and Other		18.4		6.8		11.6		170.6	%		28.1		14.3		13.8		96.5	%

Total revenues	$	2,008.0	$	1,661.4	$	346.6		20.9	%	$	3,752.9	$	3,177.0	$	575.9		18.1	%

The increase in Australian Mining operations’ revenues for both periods compared to the prior year was driven by a higher weighted average sales price (three months, 38.3%; six months, 41.6%) for seaborne metallurgical and thermal coal due to increased global coal demand. Volumes for the three months ended June 30, 2011 were also above the prior year (7.8%) due to the increased demand. Volumes for the six months ended June 30, 2011 were below the prior year (0.8%) as the first quarter was negatively impacted by flooding in Queensland that began in late 2010. Metallurgical coal sales totaled 2.3 million and 2.2 million tons for the three months ended June 30, 2011 and 2010, respectively, and 4.4 million and 4.5 million tons for the six months ended June 30, 2011 and 2010, respectively.

Western U.S. Mining operations’ revenues for the three months ended June 30, 2011 were slightly higher than the prior year as volumes and weighted average sale price were relatively flat compared to the prior year. The revenue increase for the six months ended June 30, 2011 compared to the prior year was due to increased sales volumes (4.6%) driven by our Powder River Basin and Southwest regions on strong first quarter demand due partly to customer inventory builds prior to the peak summer electricity generation period, partially offset by Midwest flooding that impacted rail performance during the three months ended June 30, 2011. Our weighted average sales price decreased by 0.7% for the six months ended June 30, 2011 due to a combination of sales mix and the expiration of some higher priced, long-term contracts signed before the economic recession in late 2008 and during 2009, resulting in a partial offset to the increased volumes.

In the Midwestern U.S. Mining segment, revenue improvements for both periods compared to the prior year were due to a higher weighted average sales price (three months, 8.4%; six months, 9.5%) driven by favorable contracts signed in recent years. Volumes were down (5.5%) for the three months ended June 30, 2011 due to coal chain disruptions and production issues caused by flooding in the Midwest, tempered by volume contributions from our new mines (Bear Run Mine commenced operations in May 2010; Wild Boar Mine commenced operations in December 2010).

Trading and Brokerage revenues were higher for both periods compared to the prior year due to a greater mix of export volumes and positive market movements on positions held in our trading book (three months). Revenues for the six months ended June 30, 2011 were negatively impacted by unfavorable market movements against positions held in our international trading book, due, in part, by pricing volatility resulting from the earthquake that occurred in Japan in March 2011.

Segment Adjusted EBITDA

The following table presents segment Adjusted EBITDA by operating segment:


					Increase (Decrease)										Increase (Decrease)
	Three Months Ended				to Segment Adjusted						Six Months Ended				to Segment Adjusted
	June 30,				EBITDA						June 30,				EBITDA
	2011		2010		$			%			2011		2010		$			%
	(Dollars in millions)										(Dollars in millions)
Western U.S. Mining	$	134.1	$	207.3	$	(73.2	)		(35.3	)%	$	313.5	$	415.2	$	(101.7	)		(24.5	)%
Midwestern U.S. Mining		82.0		71.4		10.6			14.8	%		191.9		145.5		46.4			31.9	%
Australian Mining		376.9		223.6		153.3			68.6	%		567.4		346.9		220.5			63.6	%
Trading and Brokerage		50.4		14.3		36.1			252.4	%		77.2		46.7		30.5			65.3	%

Total Segment Adjusted EBITDA	$	643.4	$	516.6	$	126.8			24.5	%	$	1,150.0	$	954.3	$	195.7			20.5	%

Australian Mining operations’ Adjusted EBITDA increased for both periods compared to the prior year due to a higher weighted average sales price (three months, $239.1 million; six months, $438.7 million). Volumes were also higher for the three months ended June 30, 2011 as discussed above. The above increases were partially offset by unfavorable foreign currency impact on operating costs, net of hedging (three months, $44.1 million; six months, $55.1 million), increased royalty expense associated with our higher-priced coal shipments (three months, $18.8 million; six months, $34.0 million), and cost escalations for labor, materials and services (three months, $15.1 million; six months, $28.7 million). The six months ended June 30, 2011 also included higher production costs related to the recovery from flooding issues in the first quarter, unfavorable geological conditions and longwall downtime associated with move days and the preparation of a new mining area ($100.8 million).

Midwestern U.S. Mining operations’ Adjusted EBITDA increased for both periods compared to the prior year due to a higher weighted average sales price (three months, $14.8 million; six months, $36.1 million) as discussed above as well as volume contributions from our new mines, partially offset by higher costs and lower production related to the flooding (three and six months, $17.3 million) as discussed above, and increased materials and services costs (three months, $6.6 million; six months, $13.2 million) related primarily to compliance measures at our underground mines. These higher costs were tempered by lower sales related costs (three months, $6.7 million; six months, $11.9 million), which were driven by higher realizations from customers for the recovery of compliance costs, and lower commodity pricing, net of hedging (three months, $4.4 million; six months, $10.3 million).

Western U.S. Mining operations’ Adjusted EBITDA decreased for both periods compared to the prior year as discussed below:

	•		Lower shipments and higher operating costs associated with geologic issues encountered at our Twentymile Mine (three months, approximately $34 million);

	•		Higher volume (excluding the impact of the reduced production at our Twentymile Mine discussed above) led to increased materials and services costs (three months, $13.3 million; six months, $23.8 million) primarily due to increased fuel and tire usage and higher outside service costs and increased labor costs (three months, $8.0 million; six months, $16.2 million);

	•		Higher equipment repairs and scheduled maintenance costs (three months, $10.3 million; six months, $27.7 million);

	•		Increased commodity pricing, net of hedging (three months, $8.8 million; six months, $16.2 million); and

	•		A provision of $24.5 million related to litigation recorded in the second quarter of the current year. See Note 14 to our unaudited condensed consolidated financial statements for additional information.

Trading and Brokerage Adjusted EBITDA increased primarily due to the higher trading revenues discussed above.

Income From Continuing Operations Before Income Taxes

The following table presents income from continuing operations before income taxes:


	Three Months Ended						Increase (Decrease)						Six Months Ended						Increase (Decrease)
	June 30,						to Income						June 30,						to Income
	2011			2010			$			%			2011			2010			$			%
	(Dollars in millions)												(Dollars in millions)
Total Segment Adjusted EBITDA	$	643.4		$	516.6		$	126.8			24.5	%	$	1,150.0		$	954.3		$	195.7			20.5	%
Corporate and Other Adjusted EBITDA ⁽¹⁾		(63.9	)		(76.2	)		12.3			16.1	%		(154.3	)		(156.7	)		2.4			1.5	%
Depreciation, depletion and amortization		(105.3	)		(105.1	)		(0.2	)		(0.2	)%		(214.1	)		(210.6	)		(3.5	)		(1.7	)%
Asset retirement obligation expense		(15.8	)		(10.9	)		(4.9	)		(45.0	)%		(28.9	)		(20.4	)		(8.5	)		(41.7	)%
Interest expense		(49.1	)		(57.9	)		8.8			15.2	%		(100.1	)		(107.9	)		7.8			7.2	%
Interest income		3.5			1.6			1.9			118.8	%		7.6			2.6			5.0			192.3	%

Income from continuing operations before income taxes	$	412.8		$	268.1		$	144.7			54.0	%	$	660.2		$	461.3		$	198.9			43.1	%


⁽¹⁾		Corporate and Other Adjusted EBITDA results include selling and administrative expenses, equity income (loss) from our joint ventures, net gains on asset disposals or exchanges, activity related to our captive insurance entity, costs associated with past mining obligations, and revenues and expenses related to our other commercial activities such as generation development and Btu Conversion development costs.

Income from continuing operations before income taxes was higher for both periods compared to the prior year primarily due to the higher Total Segment Adjusted EBITDA discussed above, lower interest expense and higher Corporate and Other Adjusted EBITDA, partially offset by increased asset retirement obligation expense.

Interest expense was lower for both periods compared to the prior year primarily due to charges of $9.3 million incurred in the prior year associated with the refinancing of our five-year Credit Facility, partially offset by current year debt extinguishment costs of $1.7 million associated with the redemption of our 5.875% Senior Notes due in April 2016 (the 5.875% Notes). See Note 8 to our unaudited condensed consolidated financial statements for additional information related to the 5.875% Notes redemption.

Corporate and Other Adjusted EBITDA reflects lower expenses for both periods compared to the prior year due primarily to the following:

	•		Increased gains on disposal or exchange of assets ($24.3 million) driven by a non-cash exchange of coal reserves in Kentucky and coal reserves and surface lands in Illinois for coal reserves in West Virginia, resulting in a $23.5 million gain in the second quarter of the current year; and

	•		A gain associated with the receipt of a $14.6 million project development fee related to our involvement in Prairie State; partially offset by

	•		Higher current year selling and administrative expenses primarily related to increased costs in support of our international expansion, acquisition activity and other growth initiatives (three months, $4.5 million; six months, $10.7 million); and

	•		Lower current year results from equity affiliates due primarily to earnings recognized in the second quarter of the prior year associated with transaction services related to our Mongolian joint venture ($10.0 million).

Asset retirement obligation expense increased for both periods compared to the prior year (three months, $4.9 million; six months, $8.5 million) due to an increase in fuel and revegetation costs across the mining platform, as well as an overall increase in the number of acres disturbed, led by our Bear Run and North Antelope Rochelle mines in the U.S. and our Wilpinjong Mine in Australia.

Net Income Attributable to Common Stockholders

The following table presents net income attributable to common stockholders:


	Three Months Ended						Increase (Decrease)						Six Months Ended						Increase (Decrease)
	June 30,						to Income						June 30,						to Income
	2011			2010			$			%			2011			2010			$			%
	(Dollars in millions)												(Dollars in millions)
Income from continuing operations before income taxes	$	412.8		$	268.1		$	144.7			54.0	%	$	660.2		$	461.3		$	198.9			43.1	%
Income tax provision		(119.8	)		(53.4	)		(66.4	)		(124.3	)%		(187.6	)		(109.5	)		(78.1	)		(71.3	)%

Income from continuing operations, net of income taxes		293.0			214.7			78.3			36.5	%		472.6			351.8			120.8			34.3	%
Loss from discontinued operations		(0.8	)		(0.5	)		(0.3	)		(60.0	)%		(1.7	)		(0.9	)		(0.8	)		(88.9	)%

Net income		292.2			214.2			78.0			36.4	%		470.9			350.9			120.0			34.2	%
Less: Net income attributable to noncontrolling interests		7.4			8.0			0.6			7.5	%		9.6			11.0			1.4			12.7	%

Net income attributable to common stockholders	$	284.8		$	206.2		$	78.6			38.1	%	$	461.3		$	339.9		$	121.4			35.7	%

Net income attributable to common stockholders increased for both periods compared to the prior year due to the increased income from continuing operations before income taxes as discussed above, partially offset by increased income tax provision. The income tax provision increased for both periods over the prior year due to the following:

	•		Increased expense associated with higher current year earnings (three months, $50.7 million; six months, $69.6 million), remeasurement of non-U.S. tax accounts as a result of the current year strengthening Australian dollar (three months, $34.7 million; six months, $35.7 million) and the prior year reduction of our gross unrecognized tax benefit ($15.2 million) resulting from the completion of the Internal Revenue Service examination of the 2005 federal income tax return in the second quarter of 2010; partially offset by

	•		Decreased expense associated with foreign rate differential due to increased current year foreign earnings (three months, $20.5 million; six months, $21.8 million) and removal of prior year valuation allowance against tax credits (three months, $16.5 million; six months, $20.8 million).

Other

The net fair value of our diesel fuel hedges increased from an asset of $40.3 million at December 31, 2010 to an asset of $95.3 million at June 30, 2011 due to the rising cost of diesel fuel in the current year. The net fair value of our foreign currency hedges increased from an asset of $640.1 million at December 31, 2010 to an asset of $773.6 million at June 30, 2011 due to the strengthening of the Australian dollar against the U.S. dollar in the current year. These increases are reflected in “Other current assets” and “Investments and other assets” in the condensed consolidated balance sheets.

The net fair value of our coal trading positions designated as cash flow hedges of future sales changed from a liability of $174.2 million at December 31, 2010 to a liability of $200.8 million at June 30, 2011 due to market price movements contrary to our positions held.

Outlook

Near-Term Outlook

Global coal supply-demand fundamentals are expected to remain solid in the near term. Pacific markets are driving global demand growth and Europe is increasing coal imports as some nuclear units are taken off line, while near-term U.S. market demand remains weak due to low economic growth. Supply constraints are evident due to weather related impacts, permitting delays and infrastructure challenges in a number of coal exporting nations.

The World Bank estimates global economic activity, as measured by gross domestic product (GDP), will grow 3.2% in 2011 and 3.6% in 2012, led by China and India. China’s GDP is projected by the World Bank to grow 9.3% in 2011. India, the world’s second fastest growing economy, is projected by the World Bank to grow 8.0% in 2011.

	•		According to the World Steel Association (WSA), global steel use is expected to increase 5.9% in 2011 and another 6.0% in 2012. The WSA forecasts India’s steel demand will rise 13.3% in 2011. Industry reports indicate China is expected to grow its steel use 5.0% in 2011 and 2012.

	•		Industry reports forecast that approximately 90 gigawatts of coal-fueled generation are expected to be under construction and/or come online in 2011, requiring more than 340 million tons of coal. China and India continue to make up the vast majority of this growth.

	•		Given coal supply constraints and continued growth in steel production and electricity generation from coal, prices for seaborne metallurgical and thermal coal have been high relative to prior years. High-quality hard coking coal has settled at $315 per tonne for quarterly contracts commencing July 2011, while thermal coal originating from Newcastle, Australia, has been selling in the $120 to $130 per tonne range.

According to the U.S. Energy Information Administration’s (EIA) Short-Term Energy Outlook, 2011 U.S. coal consumption is expected to fall by 2.5% in 2011, utility stockpiles are expected to decline in 2011, while production is expected to fall slightly. U.S. coal demand growth from the electric power sector is projected to resume in 2012.

U.S. natural gas consumption is projected to grow 2% and production expected to rise 5.8% in 2011, according to the EIA. The NYMEX — Henry Hub spot price averaged $4.54 per MMBtu in June, 23 cents higher than in May. The EIA projects natural gas consumption to decline slightly in 2012, while expecting natural gas production to rise slightly.

As of July 19, 2011, in Australia we had 2 to 3 million tons of our targeted 2011 metallurgical coal volumes and 1 to 2 million tons of our planned 2011 seaborne thermal coal volumes available for pricing. For 2012 in Australia, all of our expected metallurgical coal sales and 75% to 80% of our estimated seaborne thermal coal sales are available to price. In the U.S., we are essentially fully committed and priced for coal for 2011 delivery, 20% to 25% for 2012 and 60% to 70% for 2013. We may continue to adjust our production levels in response to changes in market demand.

We expect our third quarter to benefit from higher volumes and continued strength in pricing for Australian seaborne metallurgical and thermal coal, with volumes tempered to an extent by lingering weather impacts on U.S. shipments, co-shipper issues in Australia and longwall moves at two of our Australian metallurgical coal mines. In the fourth quarter, we are expecting U.S. volumes to increase from the third quarter as rail performance is anticipated to recover from the Midwest flooding and our Twentymile Mine returns to normal operating levels. In Australia, volumes are also expected to improve in the fourth quarter due to our Wilpinjong Mine expansion and fewer longwall move days.

We continue to manage costs and operating performance in an effort to mitigate external cost pressures, geologic conditions 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 our Annual Report on Form 10-K for the year ended December 31, 2010 for additional considerations regarding our outlook.

We rely on ongoing access to worldwide financial markets for capital, insurance, hedging and investments through a wide variety of financial instruments and contracts. To the extent these markets are not available or increase significantly in cost, this could have a negative impact on our ability to meet our business goals. Similarly, many of our customers and suppliers rely on the availability of the financial markets to secure the necessary financing and financial surety (letters of credit, bank guarantees, performance bonds, etc.) to complete transactions with us. To the extent customers and suppliers are not able to secure this financial support, it could have a negative impact on our results of operations and/or counterparty credit exposure.

Financial Regulation. On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd-Frank Act), 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 became generally 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, in many respects the ultimate impact of the Dodd-Frank Act on us may 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. Until the various provisions of the Dodd-Frank Act are finalized, along with any clarifying or implementation guidance, the extent of any impact cannot be determined at this time.

The potential for increased financial regulation is also evident in the European Union as the European Commission is considering a number of initiatives around financial derivatives transactions. These new regulations could also impact our hedging and 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. The Committee charged with consulting with industry and preparing recommendations as to the final form of the MRRT submitted its report in late December 2010. The Committee’s recommendations largely endorse the mining industry’s understanding as to what was agreed with the federal government prior to the federal election. In March 2011, the Committee’s 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 includes industry participants, to assist with drafting the legislation. Draft legislation and an accompanying explanatory memorandum was released for public consultation on June 7, 2011. A final exposure draft is expected to be issued in late 2011. 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. On July 10, 2011, the Australian government announced a carbon pricing framework that, as proposed, would commence on July 1, 2012. The carbon price would initially be $23 Australian dollars per tonne of carbon dioxide emissions, escalated by 2.5% per year for inflation over a three year period. After June 30, 2015, the proposed carbon price mechanism would transition to an emissions trading scheme. The Australian government has indicated that it expects to introduce the legislation into Parliament in the second half of 2011. It is not certain that this proposal will become law, in its current form or at all. We are still evaluating the proposal to determine the potential impact on the financial performance of our Australian operations, however it is expected that our underground operations at the North Goonyella, Wambo and Metropolitan mines will be impacted due to the inclusion of fugitive emissions (defined in the carbon pricing framework as the methane and carbon dioxide which escapes into the atmosphere when coal is mined and gas is produced). These three underground mines may be eligible to apply for a portion of the government’s $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.

Cross-State Air Pollution Rule. On July 7, 2011, the U.S. Environmental Protection Agency (EPA) finalized its Cross-State Air Pollution Rule (CSAPR), which requires 27 states in the eastern half of the U.S. 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. We are currently evaluating the CSAPR and have not yet determined what impact, if any, it may have on 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 2010, current policies scenario, that world primary energy demand will grow 47% between 2008 and 2035. Demand for coal is projected to rise 59%, 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 85% of the 2008 — 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 41% in 2008. By 2035, the IEA estimates coal’s fuel share to be 43% as it continues to have the largest share of worldwide electric power production. Currently, we estimate approximately 390 gigawatts of coal-fueled electricity generating plants are planned or under construction around the world, with expected online dates ranging between 2011 and 2015. When complete, those plants would require an estimated 1.4 billion tons of annual coal demand. While coal-based plant retirements are expected, the EIA is projecting U.S. coal demand to remain relatively constant through 2015.

The IEA projects global natural gas-fueled electricity generation will have a compound annual growth rate of 2.5%, from 4.3 trillion kilowatt hours in 2008 to 8.3 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 2008. Nuclear power is expected to grow 52%, however its share of total generation is expected to fall from 13.5% to 11% between 2008 and 2035. The recent events in Japan may impact these projections. Generation from liquid fuels is projected to decline an average of 2.2% annually to 1.5% of the 2035 generation mix.

We believe that Btu Conversion applications such as 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 CCS projects.

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, and we continue to work with the Government of Mongolia and other consortium parties to reach agreement on definitive terms and conditions related to project development. Agreements would then be submitted for consideration and approval by government agencies and the Parliament of Mongolia.

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 and the state of commercial development and deployment of CCS technologies. In view of the significant uncertainty surrounding each of these factors, it is not possible for us to reasonably predict the impact that any such laws or regulations may have on our results of operations, financial condition or cash flows.

Liquidity and Capital Resources

Capital Resources

Our primary sources of cash include sales of our coal production to customers, cash generated from our trading and brokerage activities, sales of non-core assets and financing transactions. Along with cash and cash equivalents and short-term investments, our liquidity includes the available balances from our revolving credit facility (the Revolver) under our unsecured credit facility (Credit Facility), accounts receivable securitization program and a bank overdraft facility in Australia. Our available liquidity includes $1.5 billion available for borrowing under the Revolver, net of outstanding letters of credit of $3.5 million, and available capacity under our accounts receivable securitization program of $4.5 million, net of outstanding letters of credit and amounts drawn. Our liquidity is also impacted by activity under certain bilateral cash collateralization arrangements. As of June 30, 2011, we had cash and cash equivalents of $1.2 billion and short-term investments of $75.0 million, and our total available liquidity was $2.7 billion.

We currently expect that our available liquidity and cash flow from operations will be sufficient to meet our anticipated capital requirements for our existing operations 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. As described in “Recent Events,” we announced, with ArcelorMittal, that we jointly launched an all-cash off-market takeover offer to acquire all the shares in Macarthur. The proposal price values the equity of Macarthur at approximately $4.7 billion Australian dollars (or approximately $5.2 billion U.S. dollars). We expect to finance the transaction with a combination of available cash, borrowings under our existing Revolver and proceeds from the issuance of debt and/or equity securities. We may also finance the transaction with borrowings under a $2 billion senior bridge credit facility.

Capital Requirements

Our primary uses of cash include our 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, we are not restricted in our ability to pay dividends or repurchase capital stock. We generally fund our capital expenditure requirements with cash generated from operations.

Capital Expenditures . Capital expenditures for 2011 are anticipated to be $900 million to $950 million, most of which is earmarked for new mines, expansion and extension projects. Approximately 70% of the growth and expansion capital is targeted for various Australian projects for metallurgical and thermal coal, with the remainder in the U.S. Estimated capital expenditures also include funding for our share of construction costs for Prairie State.

Federal Coal Lease Expenditures. In July 2011, we were named the winning bidder for control of approximately 220 million tons of low sulfur coal reserves in the Powder River Basin of Wyoming that will be assigned to our Caballo Mine. Based on our bid of $0.95 per mineable ton, we made our first payment of $42.1 million in July 2011, with the remaining annual payments of $42.1 million to be made in July of each of the next four years.

Prairie State . We spent $21.5 million during the six months ended June 30, 2011 representing our 5.06% share of the construction costs. Included in “Investments and other assets” in the condensed consolidated balance sheets as of June 30, 2011 and December 31, 2010 are costs of $224.0 million and $202.5 million, respectively. Our share of total construction costs for Prairie State is expected to be approximately $250 million, with most of the remaining funding expected in 2011.

Total Indebtedness. Our total indebtedness as of June 30, 2011 and December 31, 2010, consisted of the following:


	June 30,		December 31,
	2011		2010
	(Dollars in millions)
Term Loan	$	481.3	$	493.8
5.875% Senior Notes due April 2016		—		218.1
7.375% Senior Notes due November 2016		650.0		650.0
6.5% Senior Notes due September 2020		650.0		650.0
7.875% Senior Notes due November 2026		247.2		247.2
Convertible Junior Subordinated Debentures due 2066		374.2		373.3
6.34% Series B Bonds due December 2014		12.0		12.0
6.84% Series C Bonds due December 2016		33.0		33.0
Capital Lease Obligations		62.3		69.6
Fair value hedge adjustment		—		2.2
Other		2.0		0.8

Total Debt	$	2,512.0	$	2,750.0

Certain of our long-term debt arrangements contain various administrative, reporting, legal and financial covenants. As of June 30, 2011, we were in compliance with all such covenants.

On April 15, 2011, we used cash on hand to redeem our 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 notes, plus accrued and unpaid interest to April 15, 2011. We recognized costs of $1.7 million associated with the redemption.

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 posted at June 30, 2011 and December 31, 2010 was $201.0 million and $192.1 million, respectively. For the six months ended June 30, 2011 and 2010, cash outflows for margin were $9.0 million and $3.5 million, respectively.

There were no other material changes to our capital requirements from the information provided in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2010.

Historical Cash Flows


	Six Months Ended						Increase (Decrease)
	June 30,						To Cash Flow
	2011			2010			$			%
	(Dollars in millions)
Net cash provided by operating activities	$	615.6		$	464.4		$	151.2			32.6	%

Net cash used in investing activities		(439.8	)		(233.7	)		(206.1	)		(88.2	)%

Net cash used in financing activities		(294.1	)		(62.5	)		(231.6	)		(370.6	)%

Operating Activities. The changes from the prior year were driven by the following:

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

	•		Lower utilization of our accounts receivable securitization program in the current year.

Investing Activities. The changes from the prior year were driven by the following:

•

Higher current year capital spending of $167.3 million related primarily to our organic growth projects in the U.S and Australia; and

	•		Net current year purchases of $75.0 million of short-term investments; partially offset by

	•		A $15.0 million equity investment in the prior year.

Financing Activities. The increase in cash used compared to the prior year was due to the following:

	•		The redemption of our 5.875% Notes in the current year, which had an aggregate principal balance of $218.1 million at the time of redemption; and

	•		Increased dividends paid of $9.2 million due to a higher dividend rate in the current year; partially offset by

	•		Prior year debt issuance costs of $21.9 million related to the refinancing of our Credit Facility and issuance of our 6.5% Senior Notes due September 2020. The $500.0 million of proceeds from long-term debt represents our Term Loan, which was used to pay off the $490.3 million balance due on our previous term loan facility.

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 condensed 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.

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 June 30, 2011, we had $4.5 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 our Credit Facility, effectively managing our overall borrowing costs and providing an additional source for working capital. The 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 six months ended June 30, 2011, we received total consideration of $2,376.8 million related to accounts receivable sold under the securitization program, including $1,805.9 million of cash up front from the sale of the receivables, an additional $344.8 million of cash upon the collection of the underlying receivables, and $226.1 million that had not been collected at June 30, 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 June 30, 2011 and December 31, 2010.

The securitization activity has been reflected in the condensed 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 our trade receivables. We recorded expense associated with securitization transactions of $0.5 million for each of the three months ended June 30, 2011 and 2010, and $1.1 million and $1.2 million for the six months ended June 30, 2011 and 2010, respectively.

Other Off-Balance Sheet Arrangements. During 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 June 30, 2011. As of June 30, we had a total of $80.0 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.

See Note 13 to our unaudited condensed consolidated financial statements for a discussion of our guarantees.

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. We evaluate our estimates on an ongoing basis. 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.

Our critical accounting policies are discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2010. Our critical accounting policies remained unchanged at June 30, 2011. The following provides additional information about Level 3 fair value measurements.

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. 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, our 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 we do 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. 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.

Our Level 3 net financial assets represented approximately 1% ($10 million) and 3% ($19 million) of our total net financial assets as of June 30, 2011 and December 31, 2010, respectively. See Notes 5 and 6 to our unaudited condensed consolidated financial statements for additional information regarding fair value measurements.

Newly Adopted Accounting Standards and Accounting Standards Not Yet Implemented

See Note 2 to our unaudited condensed consolidated financial statements for a discussion of newly adopted accounting standards and accounting standards not yet implemented.

Item 3. 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 brokerage trading, 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

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 consolidated financial statements. Our trading portfolio included forwards, swaps and options as of June 30, 2011.

We perform a VaR analysis on our coal trading portfolio, which includes bilaterally-settled and exchange-settled over-the-counter and brokerage coal trading. The use of VaR allows us to quantify in dollars, on a daily basis, a measure of price risk inherent in our trading portfolio. VaR represents the 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 coal trading 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 six months ended June 30, 2011, the actual low, high, and average VaR for our coal trading portfolio was $7.8 million, $30.6 million and $18.7 million, respectively.

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, equity/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.

There have been no other material changes in market risk from the information provided in Item 7A. “Quantitative and Qualitative Disclosures About Market Risk” of our Annual Report on Form 10-K for the year ended December 31, 2010.

Item 4. 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. Our Chief Executive Officer and our 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 June 30, 2011, and have concluded that such controls and procedures are effective to provide reasonable assurance that the desired control objectives were achieved.

Additionally, during the most recent fiscal quarter, there have been no changes to our internal control over financial reporting that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

Item 1. Legal Proceedings.

See Note 14 to the unaudited condensed consolidated financial statements included in Part I, Item 1 of this report relating to certain legal proceedings, which information is incorporated by reference herein.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

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. The repurchases may be made from time to time based on an evaluation of our outlook and general business conditions, as well as alternative investment and debt repayment options. Our Chairman and Chief Executive Officer also has the authority to direct us to repurchase up to $100 million of our common stock outside the share repurchase program. The repurchase program does not have an expiration date and may be discontinued at any time. Through June 30, 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 program.


							Maximum Dollar
							Value that May
					Total Number of		Yet Be Used to
	Total				Shares Purchased		Repurchase Shares
	Number of		Average		as Part of Publicly		Under the Publicly
	Shares		Price per		Announced		Announced Program
Period	Purchased ⁽¹⁾		Share		Program		(In millions)
April 1 through April 30, 2011		394	$	68.11		—	$	700.4
May 1 through May 31, 2011		2,291		58.80		—		700.4
June 1 through June 30, 2011		1,182		59.05		—		700.4


Total		3,867	$	59.82		—


(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 5. Other Information.

(a) 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 our employees to provide a superior safety and health environment. We seek to implement this goal by: training employees in safe work practices; openly communicating with employees; establishing, following and improving safety standards; involving employees in safety processes; and recording, reporting and investigating accidents, incidents and losses to avoid reoccurrence. As part of our training, we collaborate with the Mine Safety and Health Administration (MSHA) and other government agencies to identify and test emerging safety technologies. We also believe that personal accountability is key. Every employee commits to our safety goals and governing principles. Managers, frontline supervisors and employees are held responsible for individual 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 our employees. We have signed letters of intent to field test a new mine emergency vehicle under development by outside companies. We are in the process of installing new communications and tracking systems at our U.S. underground mines, which will allow persons on the surface to determine the location of and communicate with all persons underground. In addition, we are exploring the use of proximity detection and collision avoidance systems to enhance the safety around our large equipment fleets.

As discussed above, our goal is to operate free of injuries, occupational illnesses, property damage and near misses. One of the ways we monitor safety performance is by incidence rate. We compute the incidence rate as the number of injuries (MSHA injury degree code 1 to 6) divided by employee hours worked, multiplied by 200,000 hours. Our incidence rate excludes the injuries and hours associated with office workers. The following table reflects our incidence rates:


	Six Months Ended June 30,
	2011		2010
U.S.		1.18		2.06


Australia		2.93		4.29


Total Peabody Energy Corporation		1.84		2.83

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 all U.S. coal mines, excluding the impact of office workers (“All Incidence Rate”). As of August 3, 2011, MSHA’s Mine Injury and Worktime Operators report for the six months ended June 30, 2011 had not yet been published. The MSHA All Incidence Rate for the three months ended March 31, 2011, was 3.58. The MSHA All Incidence Rate for the six months ended June 30, 2010, was 3.74.

We monitor MSHA compliance using violations per inspection day (in the U.S. only). We measure one inspection day for each visit to one of our mines by a MSHA inspector. For the six months ended June 30, 2011 and 2010, our violations per inspection day were 0.80 and 1.14, respectively.

The following disclosures are provided pursuant to the recently enacted Dodd-Frank Act, which requires 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 U.S. mining operations only as the requirements of the Dodd-Frank Act do not apply to our mines operated outside the U.S. Under the Dodd-Frank Act, the SEC is authorized to issue rules and regulations to carry out the purposes of these provisions. In December 2010, the SEC issued a proposed rule for the mine safety disclosures. With the comment period completed, a final rule is expected from the SEC in the second half of 2011.

Mine Safety Information. Whenever 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. While our Australian mines are not required to report safety information to MSHA, in 2008 we modified our injury reporting processes such that our Australian operations began capturing safety data using the same criteria as that of our U.S. operations. However, the safety data for our Australian mines does not include MSHA issued citations, orders and proposed assessments. As such, the mine safety disclosures below contain no information for our Australian mines.

The table that follows reflects citations and orders issued to us by MSHA during the three and six months ended June 30, 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 three and six months ended June 30, 2011 were taken from the MSHA system as of August 3, 2011.

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 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.

Three Months Ended June 30, 2011


					Section		Section						($)
	Section		Section		104(d)		104(e)		Section		Section		Proposed
	104		104(b)		Citations and		Potential Pattern		110(b)(2)		107(a)		MSHA
Mine ⁽¹⁾	Citations		Orders		Orders		of Violations		Violations		Orders		Assessments		Fatalities
													(in thousands)
Western U.S. Mining
Caballo		14		—		—		—		—		—		4.3		—
E1 Segundo		1		—		—		—		—		—		—		—
Kayenta		10		—		—		—		—		—		5.1		—
Lee Ranch		1		—		—		—		—		—		—		—
Rawhide		1		—		—		—		—		—		—		—
Twentymile (Foidel Creek)		28		—		1		—		—		—		26.6		—
Midwestern U.S. Mining
Air Quality (Air Quality Mine and South Wash Plant)		117		—		1		—		—		—		67.0		—
Bear Run		16		—		—		—		—		—		4.3		—
Cottage Grove (Wildcat Hills-Cottage Grove Pit)		12		—		—		—		—		—		7.9		—
Francisco Underground		123		—		3		—		—		—		55.2		—
Gateway		88		—		—		—		—		—		12.1		—
Somerville Central		11		—		—		—		—		—		10.3		—
Viking (Viking-Corning and Knox Pit)		5		—		—		—		—		—		—		—
Wild Boar		3		—		—		—		—		—		0.3		—
Wildcat Hills Underground		34		—		—		—		—		—		26.9		—
Willow Lake (Willow Lake Portal and Central Preparation Plant)		218		—		16		—		—		—		158.7		—


⁽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. Unless otherwise indicated, any of these other items associated with a single mine have been aggregated in the totals for that mine. 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(s) of the mine per the MSHA system.

Six Months Ended June 30, 2011


					Section		Section						($)
	Section		Section		104(d)		104(e)		Section		Section		Proposed
	104		104(b)		Citations and		Potential pattern		110(b)(2)		107(a)		MSHA
Mine ⁽¹⁾	Citations		Orders		Orders		of Violations		Violations		Orders		Assessments		Fatalities
													(in thousands)
Western U.S. Mining
Caballo		15		—		—		—		—		—		4.4		—
El Segundo		14		—		—		—		—		—		4.3		—
Kayenta		41		—		—		—		—		—		36.3		1
Lee Ranch		12		—		—		—		—		—		5.8		—
North Antelope Rochelle		3		—		—		—		—		—		—		—
Rawhide		1		—		—		—		—		—		—		—
Twentymile (Foidel Creek)		124		—		2		—		—		—		114.7		—
Midwestern U.S. Mining
Air Quality		254		1		2		—		—		1		234.6		—
Bear Run		16		—		—		—		—		—		4.3		—
Cottage Grove (Wildcat Hills-Cottage Grove Pit)		15		—		—		—		—		—		8.2		—
Farmersburg ⁽²⁾		1		—		—		—		—		—		0.2		—
Francisco Underground		238		—		4		—		—		—		158.9		—
Francisco Surface ⁽³⁾		6		—		—		—		—		—		6.8		—
Gateway		148		—		—		—		—		—		70.0		—
Somerville Central		11		—		—		—		—		—		10.3		—
Viking (Viking-Corning and Knot Pit)		17		—		—		—		—		—		11.7		—
Wild Boar		6		—		—		—		—		—		0.6		—
Wildcat Hills Underground		93		—		—		—		—		—		77.4		—
Willow Lake (Willow Lake Portal and Central Preparation Plant)		490		1		22		—		—		—		543.9		—


⁽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. Unless otherwise indicated, any of these other items associated with a single mine have been aggregated in the totals for that mine. 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(s) of the mine per the MSHA system.

⁽²⁾		The Farmersburg Mine was closed in the fourth quarter of 2010.

⁽³⁾		The Francisco Surface Mine was closed in the fourth quarter of 2009.

Pattern or Potential Pattern of Violations. During the three and six months ended June 30, 2011, none of the mines operated by us received written notice from MSHA of (a) a pattern of violations of mandatory health or safety standards that are of such nature as could have significantly and substantially contributed to the cause and effect of coal mine health or safety hazards under section 104(e) of the Mine Act or (b) the potential to have such a pattern.

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.

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 June 30, 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.


	Legal
Mine ⁽¹⁾	Actions
Western U.S. Mining
Kayenta		6
North Antelope Rochelle		9
Rawhide		4
Twentymile (Foidel Creek)		32
Midwestern U.S. Mining
Air Quality (Air Quality Mine and South Wash Plant)		34
Cottage Grove (Wildcat Hills-Cottage Grove Pit)		2
Francisco Underground		7
Gateway		12
Somerville Central		1
Viking (Viking-Corning and Knot Pit)		1
Wildcat Hills Underground		1
Willow Lake (Willow Lake Portal and Central Preparation Plant)		63


⁽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. Unless otherwise indicated, any of these other items associated with a single mine have been aggregated in the totals for that mine. 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(s) of the mine per the MSHA system.

(b) None

Item 6. Exhibits.

See Exhibit Index at page 57 of this report.

SIGNATURE

Pursuant to the requirements 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
Date: August 5, 2011	By:	/s/ MICHAEL C. CREWS
		Michael C. Crews
		Executive Vice President and Chief Financial Officer (On behalf of the registrant and as Principal Financial Officer)

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 (Incorporated by reference to Exhibit 3.1 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2008).

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 on September 16, 2008).

4.1*		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, relating to the 7 3/8% Senior Notes due 2016.

4.2*		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, relating to the 7 7/8% Senior Notes due 2026.

4.3*		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, relating to the 6.50% Senior Notes due 2020.

4.4*		Notice of Adjustment of Conversion Rate of 4.75% Convertible Junior Subordinated Debentures due 2066, dated February 7, 2011.

10.1		Peabody Energy Corporation 2011 Long-Term Equity Incentive Plan (incorporated by reference to Appendix A to Peabody Energy Corporation’s Proxy Statement filed on March 22, 2011).

10.2*		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.

31.1*		Certification of periodic financial report by Peabody Energy Corporation’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 Peabody Energy Corporation’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 Peabody Energy Corporation’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 Peabody Energy Corporation’s Chief Financial Officer.

101**		Interactive Data File (Form 10-Q for the quarterly period ended June 30, 2011 furnished in XBRL). Users of this data are advised in accordance with Rule 406T of Regulation S-T promulgated by the Securities and Exchange Commission that this Interactive Data File is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934 and otherwise is not subject to liability under these sections. The financial information contained in the XBRL-related documents is “unaudited” and “unreviewed.”


*		Filed herewith.

**		Submitted herewith.

TABLE OF CONTENTS

Item 2. Management S Discussion and Analysis Of Financial Condition and Results Of Operations Item 3. Quantitative and Qualitative Disclosures About Market Risk Item 4. Controls and Procedures Part II Other Information Item 1. Legal Proceedings Item 2. Unregistered Sales Of Equity Securities and Use Of Proceeds Item 5. Other Information Item 6. Exhibits

Exhibits

EX-4.1 EX-4.2 EX-4.3 EX-4.4 EX-10.2 EX-31.1 EX-31.2 EX-32.1 EX-32.2

BTU 10-Q Quarter ended June 30, 2011

Exhibits