FORM 8-K

Exhibit 99.1

Item 6. Selected Financial Data.

The following table presents selected financial and other data about us for the most recent five fiscal years. The following table and the discussion of our results of operations in 2008 and 2007 in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations includes references to, and analysis of, our Adjusted EBITDA results. Adjusted EBITDA is used by management to measure 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.

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

In October 2006, we acquired Excel and our results of operations for the year ended December 31, 2006 included the results of operations of the three operating mines and three development-stage mines (all of which are operating as of December 31, 2008) in New South Wales and Queensland, Australia from the date of acquisition.

On April 15, 2004, we acquired three coal operations from RAG Coal International AG. Our results of operations for the year ended December 31, 2004 include the results of operations of the two mines in Queensland, Australia and the results of operations of the Twentymile Mine in Colorado from the April 15, 2004 purchase date.

We have derived the selected historical financial data as of and for the years ended December 31, 2008, 2007, 2006, 2005 and 2004 from our audited financial statements. You should read the following table in conjunction with the financial statements, the related notes to those financial statements and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

As required, we adopted the following authoritative guidance effective January 1, 2009: Statement of Financial Accounting Standards (SFAS) No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment to ARB 51” (SFAS No. 160); Financial Accounting Standards Board (FASB) Staff Position (FSP) APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement)” (FSP APB 14-1); and FSP Emerging Issues Task Force (EITF) 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (FSP EITF 03-6-1). The consolidated financial statements reflect the retrospective application of these accounting standards. See Notes to Consolidated Financial Statements included herein for further description of these changes and their related impact on the financial statements.

The results of operations for the historical periods included in the following table are not necessarily indicative of the results to be expected for future periods. In addition, the Risk Factors section of Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2008 includes a discussion of risk factors that could impact our future results of operations.


	Year Ended December 31,
	2008			2007			2006			2005			2004
	(Dollars in millions, except share and per share data and tons sold)
Results of Operations Data
Revenues
Sales	$	6,036.3		$	4,335.1		$	3,944.9		$	3,516.1		$	2,680.8
Other revenues		557.1			210.0			106.0			81.8			82.2

Total revenues		6,593.4			4,545.1			4,050.9			3,597.9			2,763.0
Costs and Expenses
Operating costs and expenses		4,617.2			3,532.5			3,088.2			2,828.5			2,206.5
Depreciation, depletion and amortization		406.2			352.2			284.2			244.9			205.3
Asset retirement obligation expense		48.2			23.7			14.2			19.9			14.8
Selling and administrative expenses		201.8			147.1			128.0			132.6			84.5
Other operating income:
Net gain on disposal or exchange of assets		(72.9	)		(88.6	)		(53.5	)		(44.4	)		(18.1	)
Income from equity affiliates		—			(14.5	)		(22.8	)		(15.2	)		0.1

Operating Profit		1,392.9			592.7			612.6			431.6			269.9
Interest expense		227.2			235.8			139.1			98.0			90.9
Interest income		(10.1	)		(7.1	)		(11.3	)		(9.1	)		(4.0	)

Income From Continuing Operations Before Income Taxes		1,175.8			364.0			484.8			342.7			183.0
Income tax provision (benefit)		185.4			(73.2	)		(85.7	)		62.3			0.6

Income From Continuing Operations, Net of Income Taxes		990.4			437.2			570.5			280.4			182.4
Income (loss) from discontinued operations, net of income taxes		(31.3	)		(175.7	)		30.8			144.8			(6.1	)

Net income		959.1			261.5			601.3			425.2			176.3
Less: Net income (loss) attributable to noncontrolling interests		6.2			(2.3	)		0.6			2.5			1.0

Net income attributable to common stockholders	$	952.9		$	263.8		$	600.7		$	422.7		$	175.3

Basic Earnings Per Share From Continuing Operations	$	3.64		$	1.66		$	2.15		$	1.06		$	0.73
Diluted Earnings Per Share From Continuing Operations	$	3.61		$	1.63		$	2.11		$	1.04		$	0.71
Weighted average shares used in calculating basic earnings per share		268,860,528			264,068,180			263,419,344			261,519,424			248,732,744
Weighted average shares used in calculating diluted earnings per share		270,715,348			268,589,201			268,787,260			267,283,419			254,812,632
Dividends Declared Per Share	$	0.24		$	0.24		$	0.24		$	0.17		$	0.13
Other Data
Tons sold (in millions)		255.5			236.1			221.4			213.7			200.3
Net cash provided by (used in) continuing operations:
Operating activities	$	1,413.9		$	457.8		$	606.6		$	669.9		$	449.2
Investing activities		(531.5	)		(538.9	)		(2,055.6	)		(506.3	)		(742.8	)
Financing activities		(375.8	)		44.7			1,407.5			(38.9	)		577.4
Adjusted EBITDA ⁽¹⁾		1,847.3			968.6			911.0			696.4			490.0
Additions to property, plant, equipment and mine development		266.2			438.8			391.9			440.1			96.9
Federal coal lease expenditures		178.5			178.2			178.2			118.4			114.7
Acquisitions, net		110.1			—			1,507.8			—			426.6
Balance Sheet Data (at period end)
Total assets ⁽²⁾	$	9,695.6		$	9,082.3		$	9,504.7		$	6,852.0		$	6,178.6
Total long-term debt		2,793.6			2,909.0			2,911.6			1,332.0			1,362.7
Total equity		3,119.5			2,735.3			2,587.0			2,178.5			1,724.6


⁽¹⁾		Adjusted EBITDA is defined as income from continuing operations before deducting net interest expense, income taxes, asset retirement obligation expense and depreciation, depletion and amortization.

⁽²⁾		Our asset and liability coal trading derivative positions and other corporate hedging activities are offset on a counterparty-by-counterparty basis if the contractual agreement provides for the net settlement of contracts with the counterparty in the event of default or termination of any one contract in accordance with FASB Staff Position FIN 39-1, which was implemented January 1, 2008. The impact of netting resulted in a decrease in our total asset figure for 2007. The impact on total assets for 2006, 2005 and 2004 was immaterial.

Adjusted EBITDA is calculated as follows (unaudited):


	Year Ended December 31,
	2008			2007			2006			2005			2004
	(Dollars in millions)
Income from continuing operations, net of income taxes	$	990.4		$	437.2		$	570.5		$	280.4		$	182.4
Income tax provision (benefit)		185.4			(73.2	)		(85.7	)		62.3			0.6
Depreciation, depletion and amortization		406.2			352.2			284.2			244.9			205.3
Asset retirement obligation expense		48.2			23.7			14.2			19.9			14.8
Interest expense		227.2			235.8			139.1			98.0			90.9
Interest income		(10.1	)		(7.1	)		(11.3	)		(9.1	)		(4.0	)

Adjusted EBITDA	$	1,847.3		$	968.6		$	911.0		$	696.4		$	490.0

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

Overview

We are the largest private sector coal company in the world, with majority interests in 30 coal operations located throughout all major U.S. coal producing regions, except Appalachia, and international interests in Australia and Venezuela. In 2008, we produced 223.7 million tons of coal and sold 255.5 million tons of coal. Our U.S. sales represented 18% of U.S. coal consumption and were approximately 30% greater than the sales of our closest U.S. competitor.

U.S. coal consumption was approximately 1.1 billion tons in 2008, based on Energy Information Administration (EIA) estimates. Coal is primarily used for baseload electricity requirements. In 2008, coal’s share of electricity generation was approximately 50%. Between 2007 and 2030, the EIA projects coal-based electricity generation to grow 19%, outpacing all other primary fuel sources, representing 164 million tons of additional coal demand. During that same time frame, new coal-to-liquids facilities for both heat and power and liquids production is projected by the EIA to add another 70 million tons of coal demand. Coal production is expected to shift to western and interior U.S. locations to offset Appalachian declines. Specifically, production from facilities located west of the Mississippi River is projected to provide most of the incremental growth, comprising a 61% share of total production in 2030 versus 58% in 2007.

Global coal consumption has grown faster than any other fuel, averaging nearly 5% per year between 2000 and 2007. The International Energy Agency (IEA) projects demand for coal will rise more than any other fuel in absolute terms, accounting for over a third of the increase in energy use between 2006 and 2030. China and India combined represent 85% of the projected increase in world coal demand. Most of the increase in demand for coal comes from the power generation sector. Global electricity generation is projected by the IEA to rise 76% from 18,921 terawatt hours in 2006 to 33,265 terawatt hours in 2030. The IEA estimates 613 gigawatts of new power generating capacity is under construction around the world, approximately one-third of which is coal-based. The IEA expects coal to remain the main fuel for power generation worldwide, comprising 44% of the generation mix in 2030 versus 41% in 2006. In total, the IEA projects global primary coal demand will increase 61%, or approximately 2.6 billion tonnes by 2030.

For the year ended December 31, 2008, 82% of our total sales (by volume) were to U.S. electricity generators, 16% were to customers outside the U.S. and 2% were to the U.S. industrial sector. We typically sell coal to utility customers under long-term contracts (those with terms longer than one year). During 2008, approximately 90% of our worldwide sales (by volume) were under long-term contracts. As discussed more fully in Item 1A. Risk Factors of our Annual Report on Form 10-K for the year ended December 31, 2008, our results of operations in the near-term could be negatively impacted by the recent economic downturn, poor weather conditions, unforeseen geologic conditions or equipment problems at mining locations and by the availability of transportation for coal shipments. On a long-term basis, our results of operations could be impacted by our ability to secure or acquire high-quality coal reserves, find replacement buyers for coal under contracts with comparable terms to existing contracts, or the passage of new or expanded regulations that could limit our ability to mine, increase our mining costs, or limit our customers’ ability to utilize coal as fuel for electricity generation. In the past, we have achieved production levels that are relatively consistent with our projections. We may adjust our production levels further in response to changes in market demand.

We conduct business through four principal operating segments: Western U.S. Mining, Midwestern U.S. Mining, Australian Mining and Trading and Brokerage.

The principal business of the Western and Midwestern U.S. Mining segments is the mining, preparation and sale of steam coal, sold primarily to electric utilities. Our Western U.S. Mining operations consist of our Powder River Basin, Southwest and Colorado operations and are characterized by predominantly surface extraction processes, lower sulfur content and Btu of coal, and higher customer transportation costs (due to longer shipping distances). Geologically, the Western U.S. Mining operations mine bituminous and subbituminous coal deposits.

Our Midwestern U.S. Mining operations consist of our Illinois and Indiana operations and are characterized by a mix of surface and underground extraction processes, higher sulfur content and Btu of coal and lower customer transportation costs (due to shorter shipping distances). Geologically, the Midwestern U.S. Mining operations mine bituminous coal deposits.

Australian Mining operations are characterized by both surface and underground extraction processes, mining various qualities of low-sulfur, high Btu coal (metallurgical coal) as well as steam coal primarily sold to an international customer base with a small portion sold to Australian steel producers and power generators.

We own a 25.5% interest in Carbones del Guasare, which owns and operates the Paso Diablo Mine in Venezuela. The Paso Diablo Mine produced approximately 4.8 million tons of steam coal in 2008 for export to the U.S. and Europe. During 2008, the Paso Diablo Mine contributed $5.7 million to segment Adjusted EBITDA in “Corporate and Other Adjusted EBITDA” and paid a dividend of $19.9 million. At December 31, 2008, our investment in Paso Diablo was $54.2 million.

Metallurgical coal is produced primarily from five of our Australian mines. Metallurgical coal is approximately 3% of our total sales volume, but represents a larger share of our revenue, approximately 23% in 2008.

In addition to our mining operations, which comprised 90% of revenues in 2008, we generate revenues and additional cash flows from our Trading and Brokerage segment (9% of revenues) and other activities, including transactions utilizing our vast natural resource position (selling non-core land holdings and mineral interests).

We also continue to pursue development of coal-fueled generating and Btu Conversion projects in areas of the U.S. where electricity demand is strong and where there is access to land, water, transmission lines and low-cost coal.

Coal-fueled generating projects may involve mine-mouth generating plants using our surface lands and coal reserves. Our ultimate role in these projects could take numerous forms, including, but not limited to, equity partner, contract miner or coal sales. Currently, we own 5.06% of the 1,600-megawatt Prairie State Energy Campus that is under construction in Washington County, Illinois.

The long-term demand for oil and natural gas around the world is expected to lead to an increase in demand for unconventional sources of transportation fuel. We are exploring Btu Conversion projects designed to expand the uses of coal through coal-to-liquids and coal gasification technologies. Currently, we are pursuing development of a coal-to-gas facility in Muhlenberg County, Kentucky. The facility, known as Kentucky NewGas, is a planned “mine-mouth” gasification project using ConocoPhillips proprietary E-Gas^(™) technology to produce clean synthesis gas with carbon storage potential. The plant, assuming all necessary permits and financing are obtained and following selection of partners and sale of a majority of the output of each plant, could be operational following a four-year construction phase. We also own a noncontrolling interest in GreatPoint Energy, Inc., which is commercializing its coal-to-pipeline quality natural gas technology.

We are participating in the advancement of clean coal technologies, including carbon capture and storage, in the U.S., China and Australia. We are a founding member of the FutureGen Industrial Alliance, a non-profit company working in partnership with the U.S. DOE, which under its new configuration, would develop multiple carbon capture and storage sites. We are the only non-Chinese equity partner in GreenGen, a near-zero emissions coal-fueled power plant with carbon capture and storage. And in Australia, we made a 10-year commitment to fund the Australian COAL21 Fund designed to support clean coal technology demonstration projects and research in Australia.

Results of Operations

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

Adjusted EBITDA

The discussion of our results of operations below includes references to and analysis of our segments’ Adjusted EBITDA results. Adjusted EBITDA is defined as income from continuing operations before deducting 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 generally accepted accounting principles, in Note 22 to our consolidated financial statements.

Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

Summary

Higher average sales prices and volumes across all operating regions, particularly in Australia, contributed to a 45.1% increase in revenues to $6.59 billion. Segment Adjusted EBITDA rose 94.3% to $2.09 billion primarily on the higher pricing mentioned above and favorable results from Trading and Brokerage operations. Increases in sales prices and volumes were partially offset by higher commodity, material, supply, sales-related and labor costs in all operating regions. Income from continuing operations, net of income taxes was $990.4 million in 2008, or $3.61 per diluted share, 126.5% above 2007 income from continuing operations, net of income taxes of $437.2 million, or $1.63 per diluted share.

Tons Sold

The following table presents tons sold by operating segment for the years ended December 31, 2008 and 2007:


	Year Ended December 31,				Increase
	2008		2007		Tons		%
	(Tons in millions)
Western U.S. Mining		169.7		161.4		8.3		5.1	%
Midwestern U.S. Mining		30.7		29.6		1.1		3.7	%
Australian Mining		23.9		21.0		2.9		13.8	%
Trading and Brokerage		31.2		24.1		7.1		29.5	%

Total tons sold		255.5		236.1		19.4		8.2	%

Revenues

The following table presents revenues for the years ended December 31, 2008 and 2007:


					Increase (Decrease)
	Year Ended December 31,				to Revenues
	2008		2007		$			%
	(Dollars in millions)
Western U.S. Mining	$	2,533.1	$	2,063.2	$	469.9			22.8	%
Midwestern U.S. Mining		1,154.6		987.1		167.5			17.0	%
Australian Mining		2,275.2		1,138.9		1,136.3			99.8	%
Trading and Brokerage		601.8		320.7		281.1			87.7	%
Other		28.7		35.2		(6.5	)		(18.5	%)

Total revenues	$	6,593.4	$	4,545.1	$	2,048.3			45.1	%

Total revenues increased in 2008 compared to the prior year across all operating segments. The primary drivers of the increases included the following:

	•		An increase in average sales price at our Australian Mining operations (75.6%), primarily driven by the strength of metallurgical coal prices on our Australia contracts that reprice annually in the second quarter of each year.

	•		U.S. Mining operations’ average sales price increased over the prior year (15.2%) driven by the benefit of higher priced coal supply agreements signed in recent years.

	•		Australia’s volumes increased over the prior year (13.8%) from strong demand during the first three quarters of 2008 and additional production from recently completed mines. Year-over-year increases were partially offset by heavy rainfall and flooding in Queensland during the first quarter of 2008 and customer shipment deferrals in the fourth quarter of 2008 due to the global economic slowdown.

	•		Increased demand also led to higher volumes across our U.S. operating segments, which overcame slightly lower volumes at some of our Midwestern U.S. Mining surface operations due to poor weather in that operating region that impacted production during the first and second quarters. The volume increase of 5.1% at our Western U.S. Mining operations resulted from greater throughput from capital improvements and contributions from our new El Segundo Mine, partially offset by the flooding in the midwestern U.S. that impacted railroad shipping performance related to western U.S. production during the second quarter of 2008.

	•		Trading and Brokerage operations’ revenues increased over the prior year due to increased trading positions allowing us to capture market movements derived from the volatility of both domestic and international coal markets.

	•		Also impacting year-over-year revenues in our Western U.S. Mining operations was an agreement to recover previously recognized postretirement healthcare and reclamation costs of $56.9 million in the second quarter of 2008. The agreement is discussed in Note 20 to the consolidated financial statements.

Segment Adjusted EBITDA

The following table presents segment Adjusted EBITDA for the years ended December 31, 2008 and 2007:


					Increase (Decrease) to
	Year Ended December 31,				Segment Adjusted EBITDA
	2008		2007		$			%
			(Dollars in millions)
Western U.S. Mining	$	681.3	$	595.4	$	85.9			14.4	%
Midwestern U.S. Mining		177.3		200.0		(22.7	)		(11.4	%)
Australian Mining		1,017.0		166.1		850.9			512.3	%
Trading and Brokerage		218.9		116.6		102.3			87.7	%

Total Segment Adjusted EBITDA	$	2,094.5	$	1,078.1	$	1,016.4			94.3	%

Adjusted EBITDA from our Western U.S. Mining operations increased in 2008 over the prior year primarily driven by an overall increase in average sales prices per ton across the region ($2.10) and higher volumes in the region due to increased demand and greater throughput as a result of capital improvements. Also contributing to the increase was the recovery of postretirement healthcare and reclamation costs discussed above. Partially offsetting the pricing and volume contributions were higher per ton costs ($1.78). The cost increases were primarily due to higher sales related costs, higher material, supply and labor costs, higher repair and maintenance costs in the Powder River Basin and increased commodity costs, net of hedging activities, driven by higher average fuel and explosives pricing.

Midwestern U.S. Mining operations’ Adjusted EBITDA decreased in 2008 as increases in average sales price per ton ($4.22) were offset by cost increases resulting from higher costs for commodities, net of hedging activities, driven by higher average fuel and explosives prices, as well as higher material, supply and labor costs. Heavy rains and flooding in the midwestern U.S. affected sales volume at some of our mines, particularly in the first half of the year. Also affecting the Midwestern U.S. Mining segment was the decrease in revenues from coal sold to synthetic fuel plants in the prior year ($28.9 million) due to the producers exiting the synthetic fuel market after expiration of federal tax credits at the end of 2007.

Our Australian Mining operations’ Adjusted EBITDA increased in 2008 primarily due to higher pricing negotiated in the second quarter of 2008 ($40.86 per ton), higher overall volumes as a result of strong export demand and contributions from our recently completed mines, and lower demurrage costs. These favorable impacts were partially offset by higher fuel costs, an increase in labor and overburden removal expenses and higher contractor costs (five of ten Australian mines are managed utilizing contract miners).

Trading and Brokerage operations’ Adjusted EBITDA increased in 2008 over the prior year due to increased trading volumes and higher coal price volatility.

Income From Continuing Operations Before Income Taxes

The following table presents income from continuing operations before income taxes for the years ended December 31, 2008 and 2007:


							Increase (Decrease)
	Year Ended December 31,						to Income
	2008			2007			$			%
				(Dollars in millions)
Total Segment Adjusted EBITDA	$	2,094.5		$	1,078.1		$	1,016.4			94.3	%
Corporate and Other Adjusted EBITDA		(247.2	)		(109.5	)		(137.7	)		(125.8	%)
Depreciation, depletion and amortization		(406.2	)		(352.2	)		(54.0	)		(15.3	%)
Asset retirement obligation expense		(48.2	)		(23.7	)		(24.5	)		(103.4	%)
Interest expense		(227.2	)		(235.8	)		8.6			3.6	%
Interest income		10.1			7.1			3.0			42.3	%

Income from continuing operations before income taxes	$	1,175.8		$	364.0		$	811.8			223.0	%

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

Corporate and Other Adjusted EBITDA results include selling and administrative expenses, equity income from our joint ventures, net gains on asset disposals, 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. The decrease in Corporate and Other Adjusted EBITDA during 2008 compared to 2007 was due to the following:

	•		Higher selling and administrative expenses ($54.7 million) primarily driven by an increase in performance-based incentive costs and legal expenses;

	•		Cost reimbursement and partner fees received in the prior year for the Prairie State project, primarily related to the entrance of new project partners ($29.5 million);

	•		Lower net gains on disposals or exchanges of assets ($15.7 million). 2008 activity included a gain of $54.0 million on the sale of approximately 58 million tons of non-strategic coal reserves and surface lands located in Kentucky. 2007 activity included a gain of $50.5 million on the exchange of oil and gas rights and assets in more than 860,000 acres in the Illinois Basin, West Virginia, New Mexico and the Powder River Basin for coal reserves in West Virginia and Kentucky and cash proceeds. The prior year also included a gain of $26.4 million on the sale of approximately 172 million tons of coal reserves and surface lands to the Prairie State equity partners; and

•

Lower equity income ($15.5 million) from our 25.5% interest in Carbones del Guasare (owner and operator of the Paso Diablo Mine in Venezuela) and higher costs associated with Btu Conversion activities of $14.3 million in 2008.

Depreciation, depletion and amortization was higher in 2008 compared to the prior year because of increased depletion across our operating platform resulting from the volume increases and the impact of mining higher value coal reserves. In addition, depreciation and depletion increases resulted from our recently completed Australian mines and depletion at our El Segundo Mine.

Asset retirement obligation expense increased in 2008 as compared to the prior year due to an increase in the ongoing and closed mine reclamation rates that reflect higher fuel, labor and re-vegetation costs, as well as an overall increase in the number of acres disturbed. The addition of the El Segundo Mine, which was completed in June 2008, also contributed to higher asset retirement obligation expense.

Net Income Attributable to Common Stockholders

The following table presents net income attributable to common stockholders for the years ended December 31, 2008 and 2007:


							Increase (Decrease)
	Year Ended December 31,						to Income
	2008			2007			$			%
				(Dollars in millions)
Income from continuing operations before income taxes	$	1,175.8		$	364.0		$	811.8			223.0	%
Income tax (provision) benefit		(185.4	)		73.2			(258.6	)		(353.3	%)

Income from continuing operations, net of income taxes		990.4			437.2			553.2			126.5	%
Loss from discontinued operations, net of income taxes		(31.3	)		(175.7	)		144.4			82.2	%

Net income		959.1			261.5			697.6			266.8	%
Net (income) loss attributable to noncontrolling interests		(6.2	)		2.3			(8.5	)		(369.6	%)

Net income attributable to common stockholders	$	952.9		$	263.8		$	689.1			261.2	%

Net income attributable to common stockholders increased in 2008 compared to the prior year due to the increase in income from continuing operations before incomes taxes discussed above. The tax provision increase over the prior year is the result of the current year increased pre-tax earnings ($292.4 million) combined with the valuation allowance release against federal net operating loss credits recognized into income in the prior year ($197.8 million). These increases were partially offset by the non-cash tax benefit from the remeasurement of non-U.S. dollar denominated income tax accounts as a result of the strengthening of the Australian dollar in 2007 as compared to weakening of the Australian dollar in 2008 ($121.3 million), the favorable rate difference resulting from higher foreign generated income ($110.8 million) and the release of a valuation allowance against a portion of our Australia net operating loss carryforwards in the current year ($45.3 million) as a result of significantly higher earnings resulting from the higher contract pricing that was secured during 2008. Net income for 2008 was also impacted by a lower loss from discontinued operations as compared to the prior year due primarily to losses incurred for Patriot operations in 2007. The loss from discontinued operations for 2008 related to operating losses, net of a gain on sale of assets previously held for sale ($19.6 million) and an $11.7 million write-off of an excise tax refund receivable (net of tax) as a result of an April 2008 U.S. Supreme Court ruling (see Note 2 to the consolidated financial statements).

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

Summary

Higher average sales prices across all U.S. regions and increased volumes, primarily from Australian Mining operations, contributed to a 12.2% increase in revenues to $4.55 billion compared to 2006. Segment Adjusted EBITDA increased 3.8% to $1.08 billion primarily on higher prices in the Western U.S. Mining operations and increased results from Trading and Brokerage operations. Increases in sales volumes and prices in our U.S. mining operations were partially offset by challenges experienced during the period such as ongoing shipping constraints from port congestion in Australia; geologic and equipment issues, higher commodity costs, as well as a weaker U.S. dollar against the Australian Dollar. Also, negatively impacting Australian Mining results was lower metallurgical coal prices associated with annual contracts that began in April 2007. Income from continuing operations, net of income taxes was $437.2 million in 2007, or $1.63 per diluted share, a decrease of 23.4% from 2006 income from continuing operations, net of income taxes of $570.5 million, or $2.11 per diluted share.

Tons Sold

The following table presents tons sold by operating segment for the years ended December 31, 2007 and 2006:


	Year Ended December 31,				Increase
	2007		2006		Tons		%
			(Tons in millions)
Western U.S. Mining		161.4		160.5		0.9		0.6	%
Midwestern U.S. Mining		29.6		28.7		0.9		3.1	%
Australian Mining		21.0		10.8		10.2		94.4	%
Trading and Brokerage		24.1		21.4		2.7		12.6	%

Total tons sold		236.1		221.4		14.7		6.6	%

Revenues

The table below presents revenues for the years ended December 31, 2007 and 2006:


					Increase (Decrease)
	Year Ended December 31,				to Revenues
	2007		2006		$			%
			(Dollars in millions)
Western U.S. Mining	$	2,063.2	$	1,703.4	$	359.8			21.1	%
Midwestern U.S. Mining		987.1		858.5		128.6			15.0	%
Australian Mining		1,138.9		833.0		305.9			36.7	%
Trading and Brokerage		320.7		652.0		(331.3	)		(50.8	%)
Other		35.2		4.0		31.2			780.0	%

Total revenues	$	4,545.1	$	4,050.9	$	494.2			12.2	%

Total revenues increased in 2007 compared to 2006 across all mining operations. The primary drivers of the increases included the following:

	•		Prices in our Western U.S. Mining operations increased due to a sales realization increase of approximately 29% for our premium Powder River Basin product and an average increase across all U.S. regions of 16%.

	•		Midwestern U.S. Mining revenues increased due to higher revenues from coal sold to synthetic fuel plants as those plants were idled for part of 2006.

	•		Increased volumes from our Australian Mining operations. Volumes related to operations acquired in the October 2006 Excel acquisition accounted for 10.9 million tons of the increase to tons sold. Offsetting this increase was lower average sales prices in our Australian Mining operations related to lower metallurgical contract pricing and a significant change in sales mix resulting in higher thermal export and domestic product sales. Volumes were unfavorably impacted at some of our Australian Mining operations as a result of damaged rails and further amplified port and rail congestion throughout the year, in addition to adverse weather events that affected production.

	•		Partially offsetting sales price and volume increases was the continued shift towards trading contracts versus brokerage contracts in our Trading and Brokerage operations. Trading and Brokerage operations’ sales decreased during 2007 as the amount of brokerage business was reduced and replacement business was in the form of traded contracts. Contracts for trading activity are recorded at net margin in other revenues, whereas contracts for brokerage activity are recorded at gross sales price to revenues and operating costs.

Segment Adjusted EBITDA

The following table presents segment Adjusted EBITDA for the years ended December 31, 2007 and 2006:


					Increase (Decrease) to
	Year Ended December 31,				Segment Adjusted EBITDA
	2007		2006		$			%
			(Dollars in millions)
Western U.S. Mining	$	595.4	$	473.1	$	122.3			25.9	%
Midwestern U.S. Mining		200.0		186.2		13.8			7.4	%
Australian Mining		166.1		286.8		(120.7	)		(42.1	%)
Trading and Brokerage		116.6		92.6		24.0			25.9	%

Total Segment Adjusted EBITDA	$	1,078.1	$	1,038.7	$	39.4			3.8	%

Adjusted EBITDA from our Western U.S. Mining operations increased in 2007 over 2006 primarily related to the overall increase in average sales prices from our Powder River Basin operations. Partially offsetting higher average sales prices were higher costs associated with equipment repairs and maintenance and higher add-on taxes and royalties driven by higher sales prices compared to the prior year, mine shutdown for maintenance in our Colorado mine, higher fuel costs and adverse weather conditions in the Powder River Basin and capital project delays.

Midwestern U.S. Mining operations’ Adjusted EBITDA increased in 2007 over 2006 as both volumes and prices per ton saw moderate increases. Results improved compared to 2006 as benefits of higher volumes and sales prices were offset by higher costs for commodities, including fuel. The 2007 results were also positively impacted by higher revenues from coal sold to synthetic fuel facilities of $12.5 million as customers idled their synthetic fuel plants for a portion of 2006.

Our Australian Mining operations’ Adjusted EBITDA decreased in 2007 from 2006 primarily due to approximately $31 million of higher costs resulting from the weakening U.S. dollar (higher costs of approximately $112 million were offset by hedging gains of $81 million); higher congestion-related demurrage costs (approximately $50 million); lower pricing on annually repriced metallurgical coal contracts; and, rail and port congestion at Dalrymple Bay Coal Terminal and the Port of Newcastle. Dalrymple Bay Coal Terminal had been experiencing queues of over 41 vessels (approximately a 24-day load time) down from 50 vessels in the second quarter (approximately a 34-day delay). Partially offsetting these decreases were the full year contributions from our mines acquired in the Excel acquisition and a $6.3 million insurance recovery on a business interruption claim in the first half of 2007. Our Australian mines acquired in 2006 experienced shipping difficulties and damaged rail lines resulting from a storm late in 2007. The Port of Newcastle was closed for several days in 2007 due to a storm, with up to 79 vessels in the queue (a 35 — 40 day wait).

Trading and Brokerage operations’ Adjusted EBITDA increased in 2007 over 2006 as the results reflected higher international trading gains, resulting from higher volumes and pricing due to expanded global trading activities, strong supply/demand fundamentals and tightened seaborne market conditions.

Income From Continuing Operations Before Income Taxes

The following table presents income from continuing operations before income taxes for the years ended December 31, 2007 and 2006:


							Increase (Decrease)
	Year Ended December 31,						to Income
	2007			2006			$			%
				(Dollars in millions)
Total Segment Adjusted EBITDA	$	1,078.1		$	1,038.7		$	39.4			3.8	%
Corporate and Other Adjusted EBITDA		(109.5	)		(127.7	)		18.2			14.3	%
Depreciation, depletion and amortization		(352.2	)		(284.2	)		(68.0	)		(23.9	%)
Asset retirement obligation expense		(23.7	)		(14.2	)		(9.5	)		(66.9	%)
Interest expense		(235.8	)		(139.1	)		(96.7	)		(69.5	%)
Interest income		7.1			11.3			(4.2	)		(37.2	%)

Income from continuing operations before income taxes	$	364.0		$	484.8		$	(120.8	)		(24.9	%)

Income from continuing operations before income taxes in 2007 was lower than 2006 primarily due to higher interest expense and higher depreciation, depletion and amortization related to the acquisition of Excel in late 2006.

Corporate and Other Adjusted EBITDA results include selling and administrative expenses, equity income from our joint ventures, net gains on asset disposals or exchanges, costs associated with past mining obligations and revenues and expenses related to our other commercial activities such as generation development, Btu Conversion development and resource management. The improvement in Corporate and Other Adjusted EBITDA in 2007 compared to 2006 includes the following:

	•		Higher gains on asset disposals and exchanges of $35.1 million. The 2007 activity included a gain of $26.4 million on the sale of approximately 172 million tons of coal reserves to the Prairie State equity partners. Our 2007 activity also included a gain of $50.5 million on the exchange of our coalbed methane and oil and gas rights in the Illinois Basin, West Virginia, New Mexico and the Powder River Basin for high-Btu coal reserves located in West Virginia and Kentucky and cash proceeds. In comparison, the 2006 activity included a $39.2 million gain on an exchange with the Bureau of Land Management of approximately 63 million tons of leased coal reserves at our Caballo mining operation for approximately 46 million tons of coal reserves contiguous with our North Antelope Rochelle mining operation and other gains on asset disposals totaling $14.3 million;

	•		Higher past mining obligation expenses of $15.5 million resulting from increased retiree healthcare costs due to higher than anticipated healthcare utilization by retirees, particularly related to prescription drugs;

	•		Higher selling and administrative expenses of $19.1 million primarily resulting from the implementation of a new enterprise resource planning system and other corporate development initiatives; and

	•		Lower equity income of $6.8 million from our 25.5% interest in Carbones del Guasare (owner and operator of the Paso Diablo Mine in Venezuela), which primarily resulted from trucking issues experienced earlier in the year, a temporary shortage of explosives and delays in receiving equipment, which impacted operations.

Depreciation, depletion and amortization increased $68.0 million primarily related to the addition of the Australian operations acquired in late 2006.

Interest expense increased $96.7 million primarily due to approximately $1.8 billion in new debt issued or assumed as part of the Excel acquisition in the second half of 2006.

Net Income Attributable to Common Stockholders

The following table presents net income attributable to common stockholders for the years ended December 31, 2007 and 2006:


							Increase (Decrease)
	Year Ended December 31,						to Income
	2007			2006			$			%
				(Dollars in millions)
Income from continuing operations before income taxes	$	364.0		$	484.8		$	(120.8	)		(24.9	%)
Income tax benefit		73.2			85.7			(12.5	)		(14.6	%)

Income from continuing operations, net of income taxes		437.2			570.5			(133.3	)		(23.4	%)
Income (loss) from discontinued operations, net of income taxes		(175.7	)		30.8			(206.5	)		(670.5	%)

Net income		261.5			601.3			(339.8	)		(56.5	%)
Net (income) loss attributable to noncontrolling interests		2.3			(0.6	)		2.9			(483.3	%)

Net income attributable to common stockholders	$	263.8		$	600.7		$	(336.9	)		(56.1	%)

Net income attributable to common stockholders decreased in 2007 compared to prior year due to the decrease in income from continuing operations before income taxes discussed above and a lower income tax benefit compared to 2006. The decrease in the income tax benefit for the year ended 2007 related primarily to a $56.0 million foreign currency impact on deferred taxes as a result of increases in Australian dollar/U.S. dollar exchange rates and $33.2 million lower tax reserves than in 2006. This decrease was partially offset by lower pre-tax income, a $10.3 million increase in released valuation allowances and $24.3 million of additional tax credits. Noncontrolling interests increased primarily from the absorption of losses in excess of the noncontrolling interest capital contribution at one of our mines, partially offset by lower earnings allocable to partners.

Outlook

Near-Term Outlook

The current global financial slowdown has reduced gross domestic product expectations for U.S., China and other major world economies, which is expected to temper the growth of coal demand in the near term. As a result, we expect our 2009 prices to be lower than 2008 levels for our unpriced 2009 Australian-based metallurgical and thermal coal (see further discussion of unpriced coal below).

Fourth quarter 2008 global steel production declined 19% compared to fourth quarter 2007 due to the softening worldwide economies. Steel production in 2009 is anticipated to be as much as 20% lower than 2008. We estimate lower steel production will reduce 2009 seaborne metallurgical coal demand up to 40 million metric tonnes. In response to expected declines in demand, met coal producers have been reducing planned production levels. As of January 2009, approximately 30 million metric tonnes of seaborne met coal production cuts have been announced.

In January 2009, we announced planned production cuts of up to 2 million tons of Australian-based metallurgical coal to match expected changes in demand due to the global recession. As of January 2009, we have 4 to 5 million tons of expected Australian-based metallurgical coal production available to be priced for the last three quarters of 2009.

By the end of 2008, published thermal coal prices in most major markets declined from their mid-2008 highs, largely reversing gains from the first half of 2008. The decline was initiated by the accelerated liquidation of positions by financial counterparties that was followed by mild weather across the northern hemisphere during the third quarter of 2008 and the onset of the global economic downturn over the second half of the year.

As of January 2009, we have 5 to 6 million tons of Australian-based thermal coal available to be priced for the last three quarters of 2009.

In the U.S., declining gross domestic product is expected to lead to reduced electricity demand for 2009. In addition, higher-than-normal stockpiles, low natural gas prices and lower U.S. exports could dampen 2009 U.S. coal demand by up to 60 to 70 million tons. U.S. coal production is adjusting to anticipated changes in demand, with approximately 40 million tons of announced production cuts from 50% of the U.S. production base as of January 2009.

In January 2009, we announced planned reductions in 2009 Powder River Basin production of 10 million tons to better match production with expected demand. Our U.S. production is laregely sold out for 2009.

We are targeting full-year 2009 production of 190 to 195 million tons in the U.S. and 22 to 24 million tons in Australia with total sales in the range of 230 to 250 million tons.

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

We continue to manage costs and operating performance to mitigate external cost pressures, geologic conditions and potentially adverse port and rail performance. We have experienced increases in operating costs related to fuel, explosives, steel, tires, contract mining and healthcare, and have taken measures to mitigate the increases in these costs, including a company-wide initiative to instill best practices at all operations. We may also encounter poor geologic conditions, lower third-party contract miner or brokerage performance or unforeseen equipment problems that limit our ability to produce at forecasted levels. To the extent upward pressure on costs exceeds our ability to realize sales increases, or if we experience unanticipated operating or transportation difficulties, our operating margins would be negatively impacted. See Cautionary Notice Regarding Forward-Looking Statements and Item 1A. of our Annual Report on Form 10-K for the year ended December 31, 2008 for additional considerations regarding our outlook.

Long-term Outlook

Given the current global economic conditions, the near-term is less certain. However, our long-term outlook remains positive. Coal has been the fastest-growing fuel for each of the past five years, with consumption growing nearly twice as fast as total energy use.

The IEA’s World Energy Outlook estimates world primary energy demand will grow 45% between 2006 and 2030, with demand for coal rising more than any other fuel and comprising more than a third of the expected increase in energy use. China and India alone account for more than half of the expected incremental energy demand. Currently, 200 gigawatts of coal-fired electricity generating plants are under construction around the world, representing nearly 700 million tons of annual coal demand expected to come online in the next several years. In the U.S., 30 units are currently under construction in 19 states, representing more than 16 gigawatts of capacity and approximately 70 million tons of annual coal demand.

We believe that Btu Conversion applications such as coal-to-gas (CTG) and coal-to-liquids (CTL) plants represent a significant avenue for potential long-term industry growth. The EIA continues to project an increase in demand for unconventional sources of transportation fuel, including CTL, which is estimated to add 70 million tons of annual U.S. coal demand by 2030. In addition, China and India are developing CTG and CTL facilities.

Enactment of laws and passage of regulations regarding greenhouse gas emissions by the U.S. or some of its states or by other countries, or other actions to limit carbon dioxide emissions, could result in electricity generators switching from coal to other fuel sources. We continue to support clean coal technology development and voluntary initiatives addressing global climate change through our participation as a founding member of the FutureGen Alliance and the Australian COAL21 Fund, and through our participation in the Power Systems Development Facility, the PowerTree Carbon Company LLC, the Midwest Geopolitical Sequestration Consortium and the Asia-Pacific Partnership for Clean Development and Climate. In addition, we are the only non-Chinese equity partner in GreenGen, a planned near-zero emissions coal-fueled power plant with carbon capture and storage which is under development in China.

Critical Accounting Policies and Estimates

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

Employee-Related Liabilities

We have long-term liabilities for our employees’ postretirement benefit costs and defined benefit pension plans. Detailed information related to these liabilities is included in Notes 14 and 15 to our consolidated financial statements. Liabilities for postretirement benefit costs and workers’ compensation obligations are not funded. Our pension obligations are funded in accordance with the provisions of federal law. Expense for the year ended December 31, 2008 for the pension and postretirement liabilities totaled $74.4 million, while funding payments were $89.5 million.

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

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

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

Health care cost trend rate:


	One-Percentage-		One-Percentage-
	Point Increase		Point Decrease
	(Dollars in millions)
Effect on total service and interest cost components⁽¹⁾	$	6.6	$	(5.7	)
Effect on total postretirement benefit obligation ⁽¹⁾	$	79.7	$	(68.5	)

Discount rate:


	One-Half			One-Half
	Percentage-			Percentage-
	Point Increase			Point Decrease
	(Dollars in millions)
Effect on total service and interest cost components⁽¹⁾	$	0.8		$	(0.8	)
Effect on total postretirement benefit obligation ⁽¹⁾	$	(39.1	)	$	41.1


⁽¹⁾		In addition to the effect on total service and interest cost components of expense, changes in trend and discount rates would also increase or decrease the actuarial gain or loss amortization expense component. The gain or loss amortization would approximate the increase or decrease in the obligation divided by 10.68 years at December 31, 2008.

Asset Retirement Obligations

Our asset retirement obligations primarily consist of spending estimates for surface land reclamation and support facilities at both surface and underground mines in accordance with federal and state reclamation laws in the U.S. and Australia as defined by each mining permit. Asset retirement obligations are determined for each mine using various estimates and assumptions including, among other items, estimates of disturbed acreage as determined from engineering data, estimates of future costs to reclaim the disturbed acreage and the timing of these cash flows, discounted using a credit-adjusted, risk-free rate. As changes in estimates occur (such as mine plan revisions, changes in estimated costs, or changes in timing of the reclamation activities), the obligation and asset are revised to reflect the new estimate after applying the appropriate credit-adjusted, risk-free rate. If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could be materially different than currently estimated. Moreover, regulatory changes could increase our obligation to perform reclamation and mine closing activities. Asset retirement obligation expense for the year ended December 31, 2008 was $48.2 million, and payments totaled $11.4 million. See Note 13 to our consolidated financial statements for additional details regarding our asset retirement obligations.

Income Taxes

We account for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes” (SFAS No. 109), which requires that deferred tax assets and liabilities be recognized using enacted tax rates for the effect of temporary differences between the book and tax bases of recorded assets and liabilities. SFAS No. 109 also requires that deferred tax assets be reduced by a valuation allowance if it is “more likely than not” that some portion or all of the deferred tax asset will not be realized. In our annual evaluation of the need for a valuation allowance, we take into account various factors, including the expected level of future taxable income and available tax planning strategies. If actual results differ from the assumptions made in our annual evaluation of our valuation allowance, we may record a change in valuation allowance through income tax expense in the period such determination is made.

Interpretation No. 48 (FIN No. 48) “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109”) prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN No. 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. We adopted this interpretation effective January 1, 2007. See Note 11 to our consolidated financial statements for additional details regarding the effect of income taxes.

Revenue Recognition

In general, we recognize revenues when they are realizable and earned. We generated 92% of our revenue in 2008 from the sale of coal to our customers. Revenue from coal sales is realized and earned when risk of loss passes to the customer. Under the typical terms of our coal supply agreements, title and risk of loss transfer to the customer at the mine or port, where coal is loaded to the rail, barge, ocean-going vessel, truck or other transportation source(s) that delivers coal to its destination.

With respect to other revenues, other operating income, or gains on asset sales recognized in situations unrelated to the shipment of coal, we carefully review the facts and circumstances of each transaction and apply the relevant accounting literature as appropriate, and do not recognize revenue until the following criteria are met: persuasive evidence of an arrangement exists; delivery has occurred or services have been rendered; the seller’s price to the buyer is fixed or determinable; and collectibility is reasonably assured.

Trading Activities

We engage in the buying and selling of coal, freight and emissions allowances, both in over-the-counter markets and on exchanges. Under the provision of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” all derivative coal trading contracts are accounted for on a fair value (as defined by SFAS No. 157) basis, except those that qualify for and the Company has elected to apply a normal purchases and normal sales exception. For certain of our derivative coal trading contracts, we establish fair values using bid/ask price quotations obtained from multiple, independent third-party brokers to value coal, freight and emission allowance positions from the over-the-counter market. Prices from these sources are then averaged to obtain trading position values. We could experience difficulty in valuing our market positions if the number of third-party brokers should decrease or market liquidity is reduced. For our exchange-based positions, we utilize published settlement prices. Non-derivative coal contracts, including those that qualify for and the Company has elected to apply a normal purchases and normal sales exception, are accounted for on an accrual basis.

As of December 31, 2008, 94% of the contracts in our trading portfolio were valued utilizing prices from over-the-counter market sources, adjusted for coal quality and traded transportation differentials. As of December 31, 2008, 75% of the estimated future value of our trading portfolio was scheduled to be realized by the end of 2009 and 88% within 24 months. See Note 3 and Note 5 to our consolidated financial statements for additional details regarding assets and liabilities from our coal trading activities.

Fair Value Measurements

We use various methods to determine the fair value of financial assets and liabilities using market-quoted inputs for valuation or corroboration as available. We utilize market data or assumptions that market participants would use in pricing the particular asset or liability, including assumptions about inherent risk. We primarily apply the market approach for recurring fair value measurements utilizing the best available information.

We 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 evaluate the quality and reliability of the assumptions and data used to measure fair value in the three hierarchy levels, Level 1, 2 and 3, as prescribed by SFAS No. 157 (see Note 3 and Note 5 to our consolidated financial statements for additional information). Commodity swaps and options and physical commodity purchase/sale contracts transacted in less liquid markets or contracts, such as long-term arrangements, with limited price availability were classified in Level 3. Indicators of less liquid markets are those which our positions extend out to periods where there is low trade activity or where broker quotes reflect wide pricing spreads. Generally, these instruments or contracts are valued using internally generated models that include quotes from one to three reputable brokers where forward pricing curves are projected. 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 have consistently applied these valuation techniques in all periods presented, and believe we have obtained the most accurate information 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, which are categorized by level in the table below. 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.

Net assets (liabilities) related to coal trading activities at December 31, 2008 and 2007 are as follows:


	December 31,						Increase
	2008			2007			(Decrease)
	(Dollars in millions)
Level 1	$	(17.0	)	$	5.9		$	(22.9	)
Level 2		337.8			(86.6	)		424.4
Level 3		37.8			128.7			(90.9	)

Total	$	358.6		$	48.0		$	310.6

Our coal-trading platform includes positions designed to secure forward pricing for some of our production (i.e. cash flow hedges wherein the effective portion of the change in the fair value is recorded as a separate component of stockholders’ equity until the hedged transaction occurs) as well as positions designed to generate current period trading results. Overall pricing increases since December 31, 2007 and higher trading volumes, particularly from our international trading activities, have increased the value of our coal-trading portfolio during 2008. As a result, segment Adjusted EBITDA from our Trading and Brokerage segment totaled $218.9 million compared to $116.6 million in 2007. The fair value of coal trading positions designated as cash flow hedges of anticipated future sales was an asset of $220.4 million as of December 31, 2008 and a liability of $44.1 million as of December 31, 2007 (primarily classified as Level 2). The estimated realization of our aggregate coal trading portfolio of $358.6 million is 75% in 2009 and 88% within two years.

Level 3 Net Financial Asset (Liability) Detail

The Level 3 net financial assets (liabilities) as of December 31, 2008 are as follows:


	Net financial
	assets (liabilities)
	(Dollars in millions)
Physical commodity purchase/sale contracts — coal trading activities	$	38.9
Commodity swaps and options — coal trading activities		(1.1	)

Total net Level 3 financial assets	$	37.8


Total net financial assets (liabilities) measured at fair value	$	(129.2	)


Percent of Level 3 net financial assets to total net financial assets (liabilities) measured at fair value	Not meaningful ⁽¹⁾


(1)		Percentage of Level 3 net financial assets compared to total net financial assets (liabilities) is not meaningful due to overall liability position as of December 31, 2008.

The following table summarizes the changes in our recurring Level 3 net financial assets:


	Year ended December
	31, 2008
	(Dollars in millions)
Beginning of period	$	128.7
Total gains or losses (realized/unrealized):
Included in earnings		(9.8	)
Included in other comprehensive income		3.4
Purchases, issuances and settlements		(58.8	)
Net transfers out		(25.7	)

December 31, 2008	$	37.8

The following table summarizes the changes in unrealized gains (losses) relating to Level 3 net financial assets still held as January 1 and December 31, 2008:


	Year ended December
	31, 2008
	(Dollars in millions)
Changes in unrealized losses ⁽¹⁾	$	(34.8	)


⁽¹⁾		For the periods presented, unrealized gains and losses from Level 3 items are offset by 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.

Exploration and Drilling Costs

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

Advance Stripping Costs

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

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

Share-Based Compensation

We account for share-based compensation in accordance with the fair value recognition provisions of SFAS No. 123 (Revised 2004), “Share-Based Payment” (SFAS 123(R)), which we adopted using the modified prospective option on January 1, 2006. Under SFAS No. 123(R), share-based compensation expense is generally measured at the grant date and recognized as expense over the vesting period of the award. We utilize restricted stock, nonqualified stock options, performance units, deferred stock units and an employee stock purchase plan as part of our share-based compensation program. Determining fair value requires us to make a number of assumptions, including items such as expected term, risk-free rate, forfeiture rate and expected volatility. The assumptions used in calculating the fair value of share-based awards represent our best estimates, but these estimates involve inherent uncertainties and the application of management judgment. Although we believe the assumptions and estimates we have made are reasonable and appropriate, changes in assumptions could materially impact our reported financial results.

Liquidity and Capital Resources

Our primary sources of cash include sales of our coal production to customers, cash generated from our trading and brokerage activities, sales of non-core assets and financing transactions, including the sale of our accounts receivable (through our securitization program). Our primary uses of cash include our cash costs of coal production, capital expenditures, federal coal lease payments, interest costs and costs related to past mining obligations as well as acquisitions. Our ability to pay dividends, service our debt (interest and principal) and acquire new productive assets or businesses is dependent upon our ability to continue to generate cash from the primary sources noted above in excess of the primary uses. Future dividends and share repurchases, among other restricted items, are subject to limitations imposed in the covenants of our 5.875% and 6.875% Senior Notes and Convertible Junior Subordinated Debentures (the Debentures). We generally fund all of our capital expenditure requirements with cash generated from operations.

We believe our available borrowing capacity and operating cash flows will be sufficient in the near term. As of December 31, 2008, we had $1.5 billion of available borrowing capacity under our Senior Unsecured Credit Facility, net of outstanding letters of credit. The Senior Unsecured Credit Facility matures on September 15, 2011.

Our two defined benefit pension plans, which have approximately 45% of their assets invested in equity securities, experienced negative returns in 2008 due to recent equity market performance. The Pension Protection Act of 2006 (the Pension Protection Act), which was effective January 1, 2008, increased the long-term funding targets for single employer pension plans from 90% to 100%. In addition, the Pension Protection Act restricts “at risk” (generally defined as under 80% funded) plans from making lump sum payments and increasing benefits unless they are funded immediately, and also requires that the plan give participants notice regarding the at-risk status of the plan. If a plan falls below 60%, lump sum payments are prohibited and participant benefit accruals cease.

As of December 31, 2008, our pension plans were approximately 68% funded, before considering planned 2009 contributions. Our minimum funding requirement for 2009 is approximately $25 million, and would result in a funded status above 70%.

Net cash provided by operating activities from continuing operations for 2008 increased $956.1 million compared to the prior year. The increase was primarily related to a current year increase in operating cash flows generated from our Australian mining operations and the timing of cash flows for working capital driven by an increase in income tax amounts that will be payable in future periods.

Net cash used in investing activities from continuing operations decreased $7.4 million in 2008 compared to the prior year. The decrease primarily reflects lower capital spending of $160.5 million in 2008, mostly offset by the acquisition of noncontrolling interests of $110.1 million relating to our Millennium Mine, and a decrease in cash proceeds of $46.8 million, net of notes receivable, related to asset disposals.

Net cash used in financing activities reflects a use of $375.8 million in 2008 compared to $44.7 million of cash provided by financing activities in 2007. The increase in the use of cash in 2008 is primarily due to the repurchase of $199.8 million of our outstanding common stock, $97.7 million to repay the borrowings on our Revolving Credit Facility, and debt repayments of $32.7 million, including payments of $18.8 million on our Term Loan under the Senior Unsecured Credit Facility. During 2007, we repaid $37.9 million of our Term Loan and purchased in the open market $13.8 million face value of our 5.875% Senior Notes due 2016. We also made the final principal payment of $59.5 million on our 5% Subordinated Note. Our Revolving Credit Facility balance increased $97.7 million in 2007 as it was utilized to fund cash contributions to Patriot at the spin-off date.

Our total indebtedness as of December 31, 2008 and 2007 consisted of the following:


	December 31,
	2008		2007
	(Dollars in millions)
Term Loan under Senior Unsecured Credit Facility	$	490.3	$	509.1
Revolving Credit Facility		—		97.7
Convertible Junior Subordinated Debentures due 2066		369.9		368.4
7.375% Senior Notes due 2016		650.0		650.0
6.875% Senior Notes due 2013		650.0		650.0
7.875% Senior Notes due 2026		247.0		247.0
5.875% Senior Notes due 2016		218.1		218.1
6.84% Series C Bonds due 2016		43.0		43.0
6.34% Series B Bonds due 2014		18.0		21.0
6.84% Series A Bonds due 2014		10.0		10.0
Capital lease obligations		81.2		92.2
Fair value hedge adjustment		15.1		1.6
Other		1.0		0.9


Total	$	2,793.6	$	2,909.0

We were in compliance with all of the covenants of the Senior Unsecured Credit Facility, the 6.875% Senior Notes, the 5.875% Senior Notes, the 7.375% Senior Notes, the 7.875% Senior Notes and the Debentures as of December 31, 2008.

Senior Unsecured Credit Facility

In September 2006, we entered into a Third Amended and Restated Credit Agreement, which established a $2.75 billion Senior Unsecured Credit Facility and which amended and restated in full our then existing $1.35 billion Senior Secured Credit Facility. The Senior Unsecured Credit Facility provides a $1.8 billion Revolving Credit Facility and a $950.0 million Term Loan Facility. The Revolving Credit Facility is intended to accommodate working capital needs, letters of credit, the funding of capital expenditures and other general corporate purposes. The Revolving Credit Facility also includes a $50.0 million sub-facility available for same-day swingline loan borrowings.

Loans under the facility are available in U.S. dollars, with a sub-facility under the Revolving Credit Facility available in Australian dollars, pounds sterling and euros. Letters of credit under the Revolving Credit Facility are available to us in U.S. dollars with a sub-facility available in Australian dollars, pounds sterling and euros. The interest rate payable on the Revolving Credit Facility and the Term Loan Facility under the Senior Unsecured Credit Facility is based on a pricing grid tied to our leverage ratio, as defined in the Third Amended and Restated Credit Agreement. Currently, the interest rate payable on the Revolving Credit Facility and the Term Loan Facility is LIBOR plus 0.75%, which at December 31, 2008 was 2.2%.

Under the Senior Unsecured Credit Facility, we must comply with certain financial covenants on a quarterly basis including a minimum interest coverage ratio and a maximum leverage ratio, as defined in the Third Amended and Restated Credit Agreement. The financial covenants also place limitations on our investments in joint ventures, unrestricted subsidiaries, indebtedness of non-loan parties, and the imposition of liens on our assets. The new facility is less restrictive with respect to limitations on our dividend payments, capital expenditures, asset sales or stock repurchases. The Senior Unsecured Credit Facility matures on September 15, 2011.

As of December 31, 2008, we had no borrowings and $245.1 million letters of credit outstanding under our Revolving Credit Facility. Our Revolving Credit Facility is primarily used for standby letters of credit and short-term working capital needs. The remaining available borrowing capacity ($1.5 billion as of December 31, 2008) can be used to fund strategic acquisitions or meet other financing needs, including additional standby letters of credit.

Other Long-Term Debt

A description of our other debt instruments is described in Note 12 to the consolidated financial statements in Item 15 of this report.

Third-party Security Ratings

The ratings for our Senior Unsecured Credit Facility and our Senior Unsecured Notes are as follows: Moody’s has issued a Ba1 rating, Standard & Poor’s a BB+ rating, and Fitch has issued a BB+ rating. The ratings on the Debentures are as follows: Moody’s has issued a Ba3 rating, Standard & Poor’s a B+ rating, and Fitch has issued a BB- rating. These security ratings reflected the views of the rating agency only. An explanation of the significance of these ratings may be obtained from the rating agency. Such ratings are not a recommendation to buy, sell or hold securities, but rather an indication of creditworthiness. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant the change. Each rating should be evaluated independently of any other rating.

Shelf Registration Statement

On July 28, 2006, we filed an automatic shelf registration statement on Form S-3 as a well-known seasoned issuer with the SEC. The registration was for an indeterminate number of securities and is effective for three years, at which time we expect to be able to file an automatic shelf registration statement that would become immediately effective for another three-year term. Under this universal shelf registration statement, we have the capacity to offer and sell from time to time securities, including common stock, preferred stock, debt securities, warrants and units. The Debentures, 7.375% Senior Notes due 2016 and 7.875% Senior Notes due 2026 were issued pursuant to the shelf registration statement.

Share Repurchase Program

In July 2005, our Board of Directors authorized a share repurchase program of up to 5% of the then outstanding shares of our common stock, approximately 13 million shares. The repurchases may be made from time to time based on an evaluation of our outlook and general business conditions, as well as alternative investment and debt repayment options. In addition, our Board of Directors had previously authorized our Chairman and Chief Executive Officer to repurchase up to $100 million of our common stock outside the repurchase program. In October 2008, our Board of Directors amended the share repurchase program to increase the total authorized amount to $1 billion. The amended repurchase program does not have an expiration date and may be discontinued at any time. In 2008, we repurchased 5.5 million of our common shares for $199.8 million under this repurchase program and in 2006, we repurchased 2.2 million of our common shares for $99.8 million under this repurchase program.

Contractual Obligations

The following is a summary of our contractual obligations as of December 31, 2008:


	Payments Due By Year
			Less than		2 - 3		4 - 5		More than
	Total		1 Year		Years		Years		5 Years
					(Dollars in millions)
Long-term debt obligations (principal and interest)	$	5,356.1	$	198.5	$	861.8	$	1,004.1	$	3,291.8
Capital lease obligations (principal and interest)		99.4		19.1		30.2		38.1		12.0
Operating lease obligations		409.2		76.3		132.5		73.6		126.8
Unconditional purchase obligations⁽¹⁾		38.5		38.5		—		—		—
Coal reserve lease and royalty obligations		193.9		134.1		15.1		11.5		33.2
Other long-term liabilities ⁽²⁾		1,513.1		192.7		216.5		178.2		925.7

Total contractual cash obligations	$	7,610.2	$	659.2	$	1,256.1	$	1,305.5	$	4,389.5


⁽¹⁾		We have purchase agreements with approved vendors for most types of operating expenses. However, our specific open purchase orders (which have not been recognized as a liability) under these purchase agreements, combined with any other open purchase orders, are not material. The commitments in the table above relate to significant capital purchases.

⁽²⁾		Represents long-term liabilities relating to our postretirement benefit plans, work-related injuries and illnesses, defined benefit pension plans and mine reclamation and end of mine closure costs.

As of December 31, 2008, we had $38.5 million of purchase obligations for capital expenditures and $124.6 million of obligations related to federal coal reserve lease payments due over the next five years. The purchase obligations for capital expenditures primarily relate to the replacement and improvement of equipment and facilities at existing mines. We expect to fund capital expenditures primarily through operating cash flow.

We do not expect any of the $186.3 million of gross unrecognized tax benefits reported in our consolidated financial statements to require cash settlement within the next year. Beyond that, we are unable to make reasonably reliable estimates of periodic cash settlements with respect to such unrecognized tax benefits.

Off-Balance Sheet Arrangements

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

We use a combination of surety bonds, corporate guarantees (such as self bonds) and letters of credit to secure our financial obligations for reclamation, workers’ compensation, and coal lease obligations as follows as of December 31, 2008:


					Workers’
	Reclamation		Lease		Compensation
	Obligations		Obligations		Obligations		Other ⁽¹⁾		Total
					(Dollars in millions)
Self Bonding	$	773.4	$	—	$	—	$	—	$	773.4
Surety Bonds		740.6		99.2		19.3		15.2		874.3
Letters of Credit		0.1		—		54.9		199.3		254.3


	$	1,514.1	$	99.2	$	74.2	$	214.5	$	1,902.0


(1)		Other includes the four letter of credit obligations described below and an additional $24.3 million in self-bonding, letters of credit and surety bonds related to collateral for surety companies, road maintenance, performance guarantees and other operations.

We own a 37.5% interest in a partnership that leases a coal export terminal from the Peninsula Ports Authority of Virginia under a 30-year lease that permits the partnership to purchase the terminal at the end of the lease term for a nominal amount. The partners have severally (but not jointly) agreed to make payments under various agreements which in the aggregate provide the partnership with sufficient funds to pay rents and to cover the principal and interest payments on the floating-rate industrial revenue bonds issued by the Peninsula Ports Authority, and which are supported by letters of credit from a commercial bank. As of December 31, 2008, our maximum reimbursement obligation to the commercial bank was in turn supported by two letters of credit totaling $42.8 million.

We are party to an agreement with the PBGC and TXU Europe Limited, an affiliate of our former parent corporation, under which we are required to make special contributions to two of our defined benefit pension plans and to maintain a $37.0 million letter of credit in favor of the PBGC. If we or the PBGC give notice of an intent to terminate one or more of the covered pension plans in which liabilities are not fully funded, or if we fail to maintain the letter of credit, the PBGC may draw down on the letter of credit and use the proceeds to satisfy liabilities under the Employee Retirement Income Security Act of 1974, as amended. The PBGC, however, is required to first apply amounts received from a $110.0 million guarantee in place from TXU Europe Limited in favor of the PBGC before it draws on our letter of credit. On November 19, 2002 TXU Europe Limited was placed under the administration process in the United Kingdom (a process similar to bankruptcy proceedings in the U.S.) and continues under this process as of December 31, 2008. As a result of these proceedings, TXU Europe Limited may be liquidated or otherwise reorganized in such a way as to relieve it of its obligations under its guarantee.

At December 31, 2008, we have a $110.4 million letter of credit for collateral for bank guarantees issued with respect to certain reclamation and performance obligations related to the mines acquired in the Excel acquisition.

Other Guarantees

As part of arrangements through which we obtain exclusive sales representation agreements with small coal mining companies (the Counterparties), we issued financial guarantees on behalf of the Counterparties. These guarantees facilitate the Counterparties’ efforts to obtain bonding or financing. In the event of default, we have multiple recourse options, including the ability to assume the loans and procure title and use of the equipment purchased through the loans. If default occurs, we have the ability and intent to exercise our recourse options, so the liability associated with the guarantee has been valued at zero. The aggregate amount guaranteed by us for all such Counterparties was $10.0 million at December 31, 2008. Our obligations under the guarantees extend to September 2013.

As part of the Patriot spin-off, we agreed to maintain several letters of credit that secured Patriot obligations for certain employee benefits and workers’ compensation obligations. These letters of credit are to be released upon Patriot satisfying the beneficiaries with alternate letters of credit or insurance. If Patriot is unable to satisfy the primary beneficiaries by June 30, 2011, they are then required to provide directly to us a letter of credit in the amount of the remaining obligation. The amount of letters of credit maintained by us securing Patriot obligations was $7.0 million at December 31, 2008 and $136.8 million at December 31, 2007.

Under our accounts receivable securitization program, undivided interests in a pool of eligible trade receivables contributed to our wholly-owned, bankruptcy-remote subsidiary are sold, without recourse, to a multi-seller, asset-backed commercial paper conduit (Conduit). Purchases by the Conduit are financed with the sale of highly rated commercial paper. We utilize proceeds from the sale of our accounts receivable as an alternative to other forms of debt, effectively reducing our overall borrowing costs. The funding cost of the securitization program was $10.8 million for the year ended December 31, 2008 and $11.2 million for the year ended December 31, 2007. The securitization program and the underlying facilities will effectively expire in May 2009. The securitization transactions have been recorded as sales, with those accounts receivable sold to the Conduit removed from the consolidated balance sheets. The amount of undivided interests in accounts receivable sold to the Conduit was $275.0 million as of December 31, 2008 and December 31, 2007 (see Note 6 to our consolidated financial statements for additional information on accounts receivable securitization).

Newly Adopted Accounting Pronouncements and Accounting Pronouncements Not Yet Implemented

See Note 1 to the consolidated financial statements in Item 15 of this report for a discussion of newly adopted accounting pronouncements and accounting pronouncements not yet implemented.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

The potential for changes in the market value of our coal and freight trading, emission allowances, crude oil, diesel fuel, natural gas, explosives, interest rate and currency portfolios is referred to as “market risk.” Market risk related to our coal trading and freight portfolio is evaluated using a value at risk analysis (described below). Value at risk analysis is not used to evaluate our non-trading interest rate, diesel fuel, explosives or currency hedging portfolios. A description of each market risk category is set forth below. We attempt to manage market risks through diversification, controlling position sizes and executing hedging strategies. Due to lack of quoted market prices and the long-term, illiquid nature of the positions, we have not quantified market risk related to our non-trading, long-term coal supply agreement portfolio.

Coal Trading Activities and Related Commodity Price Risk

We engage in over-the-counter and direct trading of coal and ocean freight. These activities give rise to commodity price risk, which represents the potential loss that can be caused by an adverse change in the market value of a particular commitment. We actively measure, monitor and adjust traded position levels to remain within risk limits prescribed by management. For example, we have policies in place that limit the amount of total exposure, in value at risk terms, that we may assume at any point in time.

We account for coal trading using the fair value method, which requires us to reflect financial instruments with third parties, such as forwards, options and swaps, at market value in our consolidated financial statements. Our trading portfolio included forwards and swaps as of December 31, 2008 and December 31, 2007.

We perform a value at risk analysis on our coal trading portfolio, which includes over-the-counter and brokerage trading of coal. The use of value at risk allows us to quantify in dollars, on a daily basis, the price risk inherent in our trading portfolio. Value at risk represents the potential loss in value of our mark-to-market portfolio due to adverse market movements over a defined time horizon (liquidation period) within a specified confidence level. Our value at risk model is based on the industry standard variance/co-variance approach. This captures our exposure related to option, swap and forward positions. Our value at risk model assumes a 5 to 15-day holding period and a 95% one-tailed confidence interval. This means that there is a one in 20 statistical chance that the portfolio would lose more than the value at risk estimates during the liquidation period. During 2008, we implemented a change to our volatility calculation by incorporating an exponentially weighted moving average algorithm based on the previous 60 market days. This algorithm makes our volatility more representative of recent market conditions, while still reflecting an awareness of historical price movements.

The use of value at risk allows management to aggregate pricing risks across products in the portfolio, compare risk on a consistent basis and identify the drivers of risk. 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 value at risk methodology, we perform regular stress and scenario analysis 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 value at risk measure. The results of these analyses are used to supplement the value at risk methodology and identify additional market-related risks.

We use historical data to estimate price volatility as an input to value at risk and to better reflect current asset and liability volatilities. Given our reliance on historical data, we believe value at risk is effective in estimating risk exposures in markets in which there are not sudden fundamental changes or shifts in market conditions. An inherent limitation of value at risk is that past changes in market risk factors may not produce accurate predictions of future market risk. Value at risk should be evaluated in light of this limitation.

During the year ended December 31, 2008, the combined actual low, high, and average values at risk for our coal trading portfolio were $8.5 million, $27.2 million, and $19.1 million, respectively. Our value at risk increased over the prior year due to greater price volatility in the eastern U.S. and international coal markets.

As of December 31, 2008, the timing of the estimated future realization of the value of our trading portfolio was as follows:


Year of	Percentage
Expiration	of Portfolio
2009		75	%
2010		13	%
2011		11	%
2012		1	%

		100	%

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

Performance and Credit Risk

Our concentration of performance and credit risk is substantially with electric utilities, energy producers and energy marketers. Our policy is to independently evaluate each customer’s creditworthiness prior to entering into transactions and to regularly monitor the credit extended. If we engage in a transaction with a counterparty that does not meet our credit standards, we seek to protect our position by requiring the counterparty to provide an appropriate credit enhancement. These steps include obtaining letters of credit or cash collateral, requiring prepayments for shipments or the creation of customer trust accounts held for our benefit to serve as collateral in the event of a failure to pay. In general, increases in coal price volatility and our own trading activity resulted in greater exposure to our coal-trading counterparties during 2008.

In addition to credit risk, performance risk includes the possibility that a counterparty fails to deliver agreed production or trading volumes. When appropriate (as determined by our credit management function), we have taken steps to reduce our exposure to customers or counterparties whose credit has deteriorated and who may pose a higher risk of failure to perform under their contractual obligations. These steps include obtaining letters of credit or cash collateral, requiring prepayments for shipments or the creation of customer trust accounts held for our benefit to serve as collateral in the event of failure to pay. To reduce our credit exposure related to trading and brokerage activities, we seek to enter into agreements that include netting language with counterparties that permit us to offset trading positions, receivables, and payables with such counterparties.

We conduct our various hedging activities related to foreign currency, interest rate management, and fuel and explosives exposures with a variety of highly-rated commercial banks. In light of the recent turmoil in the financial markets we continue to closely monitor counterparty creditworthiness.

Foreign Currency Risk

We utilize currency forwards and options to hedge currency risk associated with anticipated Australian dollar expenditures. Our currency hedging program for 2009 targets hedging approximately 70% of our anticipated Australian dollar-denominated operating expenditures. The accounting for these derivatives is discussed in Note 3 to our consolidated financial statements. Assuming we had no hedges in place, our exposure in operating costs and expenses due to a five-cent change in the Australian dollar/U.S. dollar exchange rate is approximately $84.0 million for 2009. However, taking into consideration hedges currently in place, our net exposure to the same rate change is approximately $25.9 million for 2009. The chart at the end of Item 7A. shows the notional amount of our forward contracts as of December 31, 2008.

Interest Rate Risk

Our objectives in managing exposure to interest rate changes are to limit the impact of interest rate changes on earnings and cash flows and to lower overall borrowing costs. To achieve these objectives, we manage fixed-rate debt as a percent of net debt through the use of various hedging instruments, which are discussed in detail in Note 12 to our consolidated financial statements. As of December 31, 2008, after taking into consideration the effects of interest rate swaps, we had $2.1 billion of fixed-rate borrowings and $691.2 million of variable-rate borrowings outstanding. A one percentage point increase in interest rates would result in an annualized increase to interest expense of $6.9 million on our variable-rate borrowings. With respect to our fixed-rate borrowings, a one percentage point increase in interest rates would result in a $100.7 million decrease in the estimated fair value of these borrowings.

Other Non-trading Activities — Commodity Price Risk

Long-term Coal Contracts

We manage our commodity price risk for our non-trading, long-term coal contract portfolio through the use of long-term coal supply agreements, rather than through the use of derivative instruments. We sold 90% and 87% of our worldwide sales volume under long-term coal supply agreements during 2008 and 2007, respectively. As of January 27, 2009, we have largely sold out expected 2009 U.S. production. We had 9 to 11 million tons remaining to be priced for 2009 in Australia at January 27, 2009.

Diesel Fuel and Explosives Hedges

Some of the products used in our mining activities, such as diesel fuel and explosives, are subject to commodity price risk. To manage this risk, we use a combination of forward contracts with our suppliers and financial derivative contracts, which are primarily swap contracts with financial institutions. As of December 31, 2008, we had derivative contracts outstanding that are designated as cash flow hedges of anticipated purchases of fuel and explosives.

Notional amounts outstanding under fuel-related, derivative swap contracts are noted in the chart at the end of Item 7A. We expect to consume 125 to 130 million gallons of fuel next year. A $10 dollar per barrel change in the price of crude oil (the primary component of a refined diesel fuel product) would increase or decrease our annual fuel costs (ignoring the effects of hedging) by approximately $31 million.

Notional amounts outstanding under explosives-related swap contracts are noted in the chart below. We expect to consume 335,000 to 345,000 tons of explosives per year in the U.S. Explosives costs in Australia are generally included with the fees paid to our contract miners. Based on our expected usage, a price change in natural gas (often a key component in the production of explosives) of one dollar per million MMBtu (ignoring the effects of hedging) would result in an increase or decrease in our annual explosives costs of approximately $7 million.


															Account
	Notional Amount by term to Maturity														Classification by
															Cash		Fair
													2014 and		flow		value		Fair Value -
	Total		2009		2010		2011		2012		2013		thereafter		hedge		hedge		asset (liability)
Interest Rate Swaps
Fixed-to-floating (dollars in millions)	$	320.0	$	—	$	—	$	—	$	—	$	220.0	$	100.0	$	—	$	320.0	$	12.5
Floating-to-fixed (dollars in millions)	$	186.0	$	—	$	—	$	120.0	$	—	$	—	$	66.0	$	186.0	$	—	$	(21.8	)

Foreign Currency
A$:US$ forwards and options (A$ millions)		2,408.0		1,161.7		826.3		420.0		—		—		—		2,408.0		—		(283.8	)

Commodity Contracts
Diesel fuel hedge contracts (million gallons)		189.4		98.4		64.4		26.6		—		—		—		189.4		—		(176.5	)
U.S. explosives hedge contracts (million MMBtu)		6.5		3.6		2.9		—		—		—		—		6.5		—		(18.2	)

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders
Peabody Energy Corporation

We have audited the accompanying consolidated balance sheets of Peabody Energy Corporation (the Company) as of December 31, 2008 and 2007, and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Peabody Energy Corporation at December 31, 2008 and 2007, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.

As discussed in Notes 1, 3, 7, 11, 12, and 23 to the consolidated financial statements, the Company has retrospectively applied certain adjustments upon adoption of Statement of Financial Accounting Standards No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment to ARB 51, Financial Accounting Standards Board Staff Position Accounting Principles Board 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement) and Financial Accounting Standards Board Staff Position Emerging Issues Task Force 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities. As discussed in Note 1 to the consolidated financial statements, on January 1, 2008, the Company changed its method of accounting for the recognition of derivative positions with the same counterparty, on January 1, 2007, the Company changed its method of accounting for uncertain tax positions, on December 31, 2006, the Company changed its method for accounting for defined pension benefit and other postretirement plans, and on January 1, 2006, the Company change its method of accounting for stripping costs.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Peabody Energy Corporation’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 26, 2009, expressed an unqualified opinion thereon.



	/s/ Ernst & Young LLP

St. Louis, Missouri
February 26, 2009, except for the retrospective
adjustments described in Notes 1, 3, 7, 11, 12, and 23, as
to which the date is August 6, 2009

F-1

PEABODY ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS


	Year Ended December 31,
	2008			2007			2006
	(Dollars in millions, except share and per share data)
Revenues
Sales	$	6,036.3		$	4,335.1		$	3,944.9
Other revenues		557.1			210.0			106.0


Total revenues		6,593.4			4,545.1			4,050.9

Costs and Expenses
Operating costs and expenses		4,617.2			3,532.5			3,088.2
Depreciation, depletion and amortization		406.2			352.2			284.2
Asset retirement obligation expense		48.2			23.7			14.2
Selling and administrative expenses		201.8			147.1			128.0
Other operating income:
Net gain on disposal or exchange of assets		(72.9	)		(88.6	)		(53.5	)
Income from equity affiliates		—			(14.5	)		(22.8	)


Operating Profit		1,392.9			592.7			612.6
Interest expense		227.2			235.8			139.1
Interest income		(10.1	)		(7.1	)		(11.3	)

Income From Continuing Operations Before Income Taxes		1,175.8			364.0			484.8
Income tax provision (benefit)		185.4			(73.2	)		(85.7	)


Income From Continuing Operations, Net of Income Taxes		990.4			437.2			570.5
Income (loss) from discontinued operations, net of income taxes		(31.3	)		(175.7	)		30.8


Net Income		959.1			261.5			601.3
Less: Net income (loss) attributable to noncontrolling interests		6.2			(2.3	)		0.6

Net Income Attributable to Common Stockholders	$	952.9		$	263.8		$	600.7


Income From Continuing Operations
Basic earnings per share	$	3.64		$	1.66		$	2.15

Diluted earnings per share	$	3.61		$	1.63		$	2.11


Net Income Attributable to Common Stockholders
Basic earnings per share	$	3.52		$	0.99		$	2.27

Diluted earnings per share	$	3.50		$	0.98		$	2.22


Dividends declared per share	$	0.24		$	0.24		$	0.24

See accompanying notes to consolidated financial statements

F-2

PEABODY ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS


	December 31,
	2008			2007
	(Dollars in millions, except
	share and per share data)
ASSETS
Current assets
Cash and cash equivalents	$	449.7		$	45.3
Accounts receivable, net of allowance for doubtful accounts of $24.8 and $11.9 at December 31, 2008 and 2007, respectively		383.6			256.9
Inventories		277.7			264.7
Assets from coal trading activities, net		662.8			349.8
Deferred income taxes		1.7			58.8
Other current assets		195.8			335.0

Total current assets		1,971.3			1,310.5
Property, plant, equipment and mine development
Land and coal interests		7,354.7			7,175.4
Buildings and improvements		861.3			658.1
Machinery and equipment		1,265.8			1,256.2
Less accumulated depreciation, depletion and amortization		(2,166.6	)		(1,791.8	)

Property, plant, equipment and mine development, net		7,315.2			7,297.9
Investments and other assets		409.1			473.9

Total assets	$	9,695.6		$	9,082.3

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	17.0		$	134.4
Liabilities from coal trading activities, net		304.2			301.8
Accounts payable and accrued expenses		1,535.0			1,134.0


Total current liabilities		1,856.2			1,570.2

Long-term debt, less current maturities		2,776.6			2,774.6
Deferred income taxes		21.5			495.1
Asset retirement obligations		422.6			362.8
Accrued postretirement benefit costs		766.1			785.7
Other noncurrent liabilities		733.1			358.6

Total liabilities		6,576.1			6,347.0

Stockholders’ equity
Preferred Stock – $0.01 per share par value; 10,000,000 shares authorized, no shares issued or outstanding as of December 31, 2008 or 2007		—			—
Series A Junior Participating Preferred Stock – 1,500,000 shares authorized, no shares issued or outstanding as of December 31, 2008 or 2007		—			—
Perpetual Preferred Stock – 750,000 shares authorized, no shares issued or outstanding as of December 31, 2008 or 2007		—			—
Series Common Stock – $0.01 per share par value; 40,000,000 shares authorized, no shares issued or outstanding as of December 31, 2008 or 2007		—			—
Common Stock – $0.01 per share par value; 800,000,000 shares authorized, 275,211,240 shares issued and 266,644,979 shares outstanding as of December 31, 2008 and 800,000,000 shares authorized, 272,911,564 shares issued and 270,066,621 shares outstanding as of December 31, 2007		2.8			2.7
Additional paid-in capital		2,020.2			1,966.1
Retained earnings		1,802.4			940.9
Accumulated other comprehensive loss		(388.5	)		(67.1	)
Treasury shares, at cost: 8,566,261 shares as of December 31, 2008 and 2,844,943 shares as of December 31, 2007		(318.8	)		(108.0	)

Peabody Energy Corporation stockholders’ equity		3,118.1			2,734.6
Noncontrolling interests		1.4			0.7

Total equity		3,119.5			2,735.3

Total liabilities and stockholders’ equity	$	9,695.6		$	9,082.3

See accompanying notes to consolidated financial statements

F-3

PEABODY ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Year Ended December 31,
	2008			2007			2006
	(Dollars in millions)
Cash Flows From Operating Activities
Net income	$	959.1		$	261.5		$	601.3
(Income) loss from discontinued operations, net of income taxes		31.3			175.7			(30.8	)

Income from continuing operations, net of income taxes		990.4			437.2			570.5
Adjustments to reconcile income from continuing operations, net of income taxes to net cash provided by operating activities:
Depreciation, depletion and amortization		406.2			352.2			284.2
Deferred income taxes		(33.3	)		(196.5	)		(191.2	)
Amortization of debt discount and debt issuance costs		7.7			8.0			7.4
Net gain on disposal or exchange of assets		(72.9	)		(88.6	)		(53.5	)
Income from equity affiliates		—			(14.5	)		(22.8	)
Revenue recovery on coal supply agreements		(56.9	)		—			—
Stock compensation expense		34.9			20.1			17.1
Dividends received from equity affiliates		19.9			12.9			18.1
Changes in current assets and liabilities, net of acquisitions:
Accounts receivable, including securitization		(113.5	)		65.2			(110.5	)
Inventories		(13.0	)		(62.2	)		(27.3	)
Net assets from coal trading activities		(43.0	)		(77.6	)		(9.0	)
Other current assets		1.7			(57.1	)		(20.3	)
Accounts payable and accrued expenses		225.5			53.6			103.8
Asset retirement obligations		32.9			13.6			(3.1	)
Workers’ compensation obligations		10.3			2.7			(0.1	)
Accrued postretirement benefit costs		13.6			13.1			59.1
Contributions to pension plans		(21.3	)		(5.4	)		(6.1	)
Other, net		24.7			(18.9	)		(9.7	)

Net cash provided by continuing operations		1,413.9			457.8			606.6
Net cash used in discontinued operations		(128.2	)		(141.4	)		(23.3	)

Net cash provided by operating activities		1,285.7			316.4			583.3

Cash Flows From Investing Activities
Acquisition of Excel Coal Limited, net of cash acquired		—			—			(1,507.8	)
Acquisitions of noncontrolling interests		(110.1	)		—			—
Additions to property, plant, equipment and mine development		(266.2	)		(438.8	)		(391.9	)
Federal coal lease expenditures		(178.5	)		(178.2	)		(178.2	)
Investment in Prairie State		(40.9	)		(28.8	)		—
Proceeds from disposal of assets, net of notes receivable		72.8			119.6			29.4
Additions to advance mining royalties		(6.0	)		(8.1	)		(5.0	)
Investments in equity affiliates and joint ventures		(2.6	)		(4.6	)		(2.1	)

Net cash used in continuing operations		(531.5	)		(538.9	)		(2,055.6	)
Net cash provided by (used in) discontinued operations		26.0			(36.4	)		(88.2	)

Net cash used in investing activities		(505.5	)		(575.3	)		(2,143.8	)

Cash Flows From Financing Activities
Change in revolving line of credit		(97.7	)		97.7			—
Proceeds from long-term debt		—			—			2,604.1
Payments of long-term debt		(32.7	)		(117.8	)		(1,046.0	)
Common stock repurchase		(199.8	)		—			(99.8	)
Dividends paid		(64.9	)		(63.7	)		(63.5	)
Payment of debt issuance costs		—			(0.8	)		(40.6	)
Excess tax benefit related to stock options exercised		—			96.7			33.2
Proceeds from stock options exercised		14.1			26.2			15.6
Proceeds from employee stock purchases		5.2			6.4			4.5

Net cash provided by (used in) continuing operations		(375.8	)		44.7			1,407.5
Net cash used in discontinued operations		—			(67.0	)		(23.8	)

Net cash provided by (used in) financing activities		(375.8	)		(22.3	)		1,383.7

Net increase (decrease) in cash and cash equivalents		404.4			(281.2	)		(176.8	)
Cash and cash equivalents at beginning of year		45.3			326.5			503.3

Cash and cash equivalents at end of year	$	449.7		$	45.3		$	326.5

See accompanying notes to consolidated financial statements

F-4

PEABODY ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY


	Peabody Energy’s Stockholders’ Equity
					Accumulated
			Additional		Other												Total
	Common Stock		Paid-in Capital		Comprehensive Loss			Retained Earnings			Treasury Stock			Noncontrolling Interests			Stockholders’ Equity
								(Dollars in millions)
December 31, 2005	$	2.6	$	1,497.5	$	(47.0	)	$	729.1		$	(3.9	)	$	2.6		$	2,180.9
Comprehensive income:
Net income		—		—		—			600.7			—			0.6			601.3
Increase in fair value of cash flow hedges (net of $16.2 tax provision)		—		—		24.3			—			—			—			24.3
Minimum pension liability adjustment (net of $16.8 tax provision)		—		—		22.5			—			—			—			22.5

Comprehensive income						46.8			600.7			—			0.6			648.1

Postretirement plans and workers’ compensation obligations (net of $149.5 tax benefit):
Accumulated actuarial loss, net of tax		—		—		(242.0	)		—			—			—
Prior service cost, net of tax		—		—		(7.0	)		—			—			—

						(249.0	)											(249.0	)

Dividends paid		—		—		—			(63.5	)		—			—			(63.5	)
Noncontrolling interests activity related to discontinued operations		—		—		—			—			—			16.3			16.3
Distributions to noncontrolling interests		—		—		—			—			—			(4.5	)		(4.5	)
Acquisition of noncontrolling interests associated with Excel Coal Limited		—		—		—			—			—			18.3			18.3
Issuance of Convertible Junior Subordinated Debentures		—		215.4		—			—			—			—			215.4
Stock options exercised		0.1		15.5		—			—			—			—			15.6
Share-based compensation		—		21.9		—			—			—			—			21.9
Income tax benefits from stock options exercised		—		33.2		—			—			—			—			33.2
Employee stock purchases		—		4.5		—			—			—			—			4.5
Change in accounting for advanced stripping (net of $95.2 tax benefit)		—		—		—			(150.4	)		—			—			(150.4	)
Common stock repurchased		—		—		—			—			(99.8	)		—			(99.8	)

December 31, 2006	$	2.7	$	1,788.0	$	(249.2	)	$	1,115.9		$	(103.7	)	$	33.3		$	2,587.0
Comprehensive income:
Net income		—		—		—			263.8			—			(2.3	)		261.5
Increase in fair value of cash flow hedges (net of $14.5 tax provision)		—		—		21.9			—			—			—			21.9
Postretirement plans and workers’ compensation obligations (net of $50.2 tax provision)		—		—		87.2			—			—			—			87.2

Comprehensive income						109.1			263.8			—			(2.3	)		370.6

Dividends paid		—		—		—			(63.7	)		—			—			(63.7	)
Noncontrolling interests activity related to discontinued operations												—			(6.2	)		(6.2	)
Distributions to noncontrolling interests		—		—		—			—			—			(3.0	)		(3.0	)
Acquisition of noncontrolling interests associated with Excel Coal Limited — purchase accounting adjustment		—		—		—			—			—			(7.0	)		(7.0	)
Patriot Coal Corporation spin-off		—		—		73.0			(375.1	)		—			(14.1	)		(316.2	)
Stock options exercised		—		26.2		—			—			—			—			26.2
Income tax benefits from stock options exercised		—		96.7		—			—			—			—			96.7
Employee stock purchases		—		6.4		—			—			—			—			6.4
Employee stock grants		—		—		—			—			—			—			—
Share-based compensation		—		48.8		—			—			—			—			48.8
Shares relinquished		—		—		—			—			(4.3	)		—			(4.3	)

December 31, 2007	$	2.7	$	1,966.1	$	(67.1	)	$	940.9		$	(108.0	)	$	0.7		$	2,735.3
Comprehensive income:
Net income		—		—		—			952.9			—			6.2			959.1
Decrease in fair value of cash flow hedges (net of $178.2 tax benefit)		—		—		(217.9	)		—			—			—			(217.9	)
Postretirement plans and workers’ compensation obligations (net of $59.3 tax benefit)		—		—		(103.5	)		—			—			—			(103.5	)

Comprehensive income						(321.4	)		952.9			—			6.2			637.7

Dividends paid		—		—		—			(64.9	)		—			—			(64.9	)
Elimination of noncontrolling interests due to acquisitions		—		—		—			—			—			(4.4	)		(4.4	)
Distributions to noncontrolling interests		—		—		—			—			—			(1.1	)		(1.1	)
Patriot Coal Corporation spin-off adjustment		—		—		—			(26.5	)		—			—			(26.5	)
Stock options exercised		0.1		14.0		—			—			—			—			14.1
Employee stock purchases		—		5.2		—			—			—			—			5.2
Share-based compensation		—		34.9		—			—			—			—			34.9
Common stock repurchased		—		—		—			—			(199.8	)		—			(199.8	)
Shares relinquished		—		—		—			—			(11.0	)		—			(11.0	)

December 31, 2008	$	2.8	$	2,020.2	$	(388.5	)	$	1,802.4		$	(318.8	)	$	1.4		$	3,119.5

See accompanying notes to consolidated financial statements

F-5

PEABODY ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Summary of Significant Accounting Policies

Basis of Presentation

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

Description of Business

The Company is engaged in the mining of steam coal for sale primarily to electric utilities and metallurgical coal for sale to industrial customers. The Company’s mining operations are located in the United States (U.S.) and Australia, and include an equity interest in a mining operation in Venezuela. In addition to the Company’s mining operations, the Company markets, brokers and trades coal. The Company’s other energy related commercial activities include the development of mine-mouth coal-fueled generating plants, the management of its vast coal reserve and real estate holdings, and the evaluation of Btu Conversion technologies. The Company’s Btu Conversion projects are designed to expand the uses of coal through various technologies such as coal-to-liquids and coal gasification.

Newly Adopted Accounting Pronouncements

In June 2008, the Financial Accounting Standards Board (FASB) issued FASB Staff Position (FSP) No. Emerging Issues Task Force (EITF) 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (FSP EITF 03-6-1). FSP EITF 03-6-1, which became effective for the Company on January 1, 2009, addresses whether instruments granted in share-based payment awards that entitle their holders to receive nonforfeitable dividends or dividend equivalents before vesting should be considered participating securities and need to be included in the earnings allocation in computing earnings per share (EPS) under the “two-class method.” The two-class method is an earnings allocation formula that determines EPS for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. In accordance with FSP EITF 03-6-1, the Company’s unvested restricted stock awards are considered participating securities because they entitle holders to receive nonforfeitable dividends during the vesting term. In applying the two-class method, undistributed earnings are allocated between common shares and unvested restricted stock awards. The Company retrospectively applied the two-class method of computing basic and diluted EPS for all periods presented. See Note 7 for further information.

In May 2008, the FASB issued FSP No. Accounting Principles Board (APB) 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement)” (FSP APB 14-1). FSP APB 14-1 clarifies that convertible debt instruments that may be settled in cash upon conversion, including partial cash settlement, are not considered debt instruments within the scope of APB Opinion No. 14, “Accounting for Convertible Debt and Debt Issued with Stock Purchase Warrants.” FSP APB 14-1 also specifies that issuers of such instruments should separately account for the liability and equity components in a manner that will reflect the issuer’s nonconvertible debt borrowing rate when recognizing interest cost in subsequent periods. FSP APB 14-1 was effective for the Company for the fiscal year beginning January 1, 2009. Prior period balances have been adjusted to conform with the provisions of FSP APB 14-1 on a retrospective basis as though the provisions of FSP APB 14-1 had been in effect since the issuance of the Convertible Junior Subordinated Debentures (the Debentures) in late 2006, as set forth below.

F-6

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

The following table illustrates the effect of FSP APB 14-1 on the Company’s balance sheet as of December 31, 2008:


			Increase (decrease)
			due to application of
	As previously stated		FSP APB 14-1			As adjusted
	(Dollars in millions)
Investments and other assets	$	417.5	$	(8.4	)	$	409.1
Deferred income taxes (long-term asset)		118.4		(118.4	)		—
Long-term debt, less current maturities		3,139.2		(362.6	)		2,776.6
Deferred income taxes (long-term liability)		—		21.5			21.5
Additional paid-in capital		1,804.8		215.4			2,020.2
Retained earnings		1,803.5		(1.1	)		1,802.4

The following table illustrates the effect on the Company’s statement of operations for the year ended December 31, 2008:


			Increase (decrease)
			due to application of
	As previously stated		FSP APB 14-1			As adjusted
	(Dollars in millions)
Interest expense	$	226.2	$	1.0		$	227.2
Income tax provision (benefit)		185.8		(0.4	)		185.4

The following table illustrates the effect of FSP APB 14-1 on the Company’s balance sheet as of December 31, 2007:


			Increase (decrease)
			due to application of
	As previously stated		FSP APB 14-1			As adjusted
	(Dollars in millions)
Investments and other assets	$	482.8	$	(8.9	)	$	473.9
Long-term debt, less current maturities		3,138.7		(364.1	)		2,774.6
Deferred income taxes (long-term liability)		354.8		140.3			495.1
Additional paid-in capital		1,750.7		215.4			1,966.1
Retained earnings		941.4		(0.5	)		940.9

The following table illustrates the effect on the Company’s statement of operations for the year ended December 31, 2007:


				Increase (decrease)
				due to application of
	As previously stated			FSP APB 14-1			As adjusted
	(Dollars in millions)
Interest expense	$	235.0		$	0.8		$	235.8
Income tax benefit		(72.9	)		(0.3	)		(73.2	)

For the periods presented, there was no change to the Company’s EPS figures related to the retrospective application of FSP APB 14-1. There was no effect on the Company’s statement of operations for the year ended December 31, 2006 due to the adoption of FSP APB 14-1.

F-7

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

The following table illustrates the carrying amount of the equity and debt components of the Debentures as of December 31, 2008 and 2007:


	December 31, 2008			December 31, 2007
	(Dollars in millions)
Carrying amount of the equity component	$	215.4		$	215.4

Principal amount of the liability component		732.5			732.5
Unamortized discount		(362.6	)		(364.1	)

Net carrying amount	$	369.9		$	368.4

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


	Year Ended December 31,
	2008			2007			2006
	(Dollars in millions)
Effective interest rate		4.9	%		4.9	%		4.9	%

Interest expense — contractual interest coupon	$	34.5		$	34.9		$	1.1
Interest expense — amortization of debt discount		1.5			1.3			—

The remaining period over which the discount will be amortized is 33 years as of December 31, 2008.

In December 2007, the FASB issued Statement of Financial Accounting Standard (SFAS) No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51” (SFAS No. 160). SFAS No. 160 establishes accounting and reporting standards for noncontrolling interests in partially-owned consolidated subsidiaries and the loss of control of subsidiaries. SFAS No. 160 requires noncontrolling interests (minority interests) to be reported, retrospectively, as a separate component of equity. In addition, this statement requires that a parent recognize a gain or loss in net income when a subsidiary is deconsolidated on a prospective basis. SFAS No. 160 was effective for the Company for the fiscal year beginning January 1, 2009. The presentation and disclosure provisions have been applied on a retrospective basis for all periods presented whereby stockholders’ equity increased $1.4 million as of December 31, 2008 and $0.7 million as of December 31, 2007 for the inclusion of noncontrolling interests.

In April 2007, the FASB issued FSP FASB Interpretation Number (FIN) 39-1, “Amendment of FASB Interpretation No. 39” (FSP FIN 39-1). FSP FIN 39-1 amends certain provisions of FIN 39, “Offsetting of Amounts Related to Certain Contracts,” and permits companies to offset fair value amounts recognized for cash collateral receivables or payables against fair value amounts recognized for net derivative positions executed with the same counterparty under the same master netting arrangement. Prior to the implementation of FSP FIN 39-1, all positions executed with common counterparties were presented on a gross basis in the appropriate balance sheet line items. Effective January 1, 2008, in accordance with the provisions of FSP FIN 39-1, the Company offset its asset and liability coal trading derivative positions and other corporate hedging activities on a counterparty-by-counterparty basis if the contractual agreement provides for the net settlement of contracts with the counterparty in the event of default or termination of any one contract. The December 31, 2007 balances were reclassified to conform with the provisions of FSP FIN 39-1. See Note 5 for a presentation of the assets and liabilities from coal trading activities on a gross and net basis.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115” (SFAS No. 159). SFAS No. 159 provides all entities with an option to report selected financial assets and liabilities at fair value. SFAS No. 159 was effective for the Company for the fiscal year beginning January 1, 2008. SFAS No. 159 did not have an impact on the accompanying consolidated financial statements.

F-8

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

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS No. 157). SFAS No. 157 defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles (GAAP), and expands disclosures about fair value measurements. SFAS No. 157 applies under accounting pronouncements that require or permit fair value measurements, but the standard does not require any new fair value measurements. In February 2008, the FASB amended SFAS No. 157 to exclude leasing transactions and to delay the effective date by one year for nonfinancial assets and liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis. The Company adopted SFAS No. 157 on January 1, 2008. In October 2008, the FASB FSP No. 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active” (FSP 157-3), which clarified the application of SFAS No. 157 in an inactive market and demonstrated how the fair value of a financial asset is determined when the market for that financial asset is inactive. FSP 157-3 was effective upon issuance, including prior periods for which financial statements had not been issued. The adoption of FSP 157-3 did not have an impact on the Company’s determination of fair value for financial assets. See Note 3 for additional details on fair value.

In June 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109” (FIN No. 48). This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN No. 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company adopted the provisions of FIN No. 48 on January 1, 2007, and as a result, reported $135.0 million of net unrecognized tax benefits ($144.0 million gross) in its consolidated financial statements. Due to the valuation allowance recorded against the Company’s deferred tax asset for net operating loss (NOL) carryforwards as of January 1, 2007, none of the $135.0 million required an adjustment to retained earnings upon adoption.

In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (SFAS No. 158). For fiscal years ending after December 15, 2006, SFAS No. 158 requires recognition of the funded status of pension and other postretirement benefit plans (an asset for overfunded status or a liability for underfunded status) in a company’s balance sheet. In addition, the standard requires recognition of actuarial gains and losses, prior service cost, and any remaining transition amounts from the initial application of SFAS No. 87, “Employers’ Accounting for Pensions” (SFAS No. 87) and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” (SFAS No. 106) when determining a plan’s funded status, with a corresponding charge to accumulated other comprehensive income (loss). The Company adopted SFAS No. 158 on December 31, 2006, and as a result, recorded a noncurrent liability of $376.1 million, which reflected the net underfunded status of the pension, retiree healthcare and workers’ compensation plans. The funded status of each plan was measured as the difference between the fair value of the assets and the projected benefit obligation (the funded status). SFAS No. 158 did not impact net income.

In March 2005, the EITF issued EITF Issue No. 04-6, “Accounting for Stripping Costs in the Mining Industry” (EITF Issue No. 04-6). EITF Issue No. 04-6 and its interpretations require stripping costs incurred during a period to be attributed only to the inventory costs of the coal that is extracted during that same period. The Company adopted EITF Issue No. 04-6 on January 1, 2006 and utilized the cumulative effect adjustment approach whereby the cumulative effect adjustment reduced retained earnings by $150.4 million, net of tax. This non-cash item is excluded from the consolidated statements of cash flows. Advance stripping costs are primarily expensed as incurred.

Accounting Pronouncements not Yet Implemented

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133” (SFAS No. 161). SFAS No. 161 expands the disclosure requirements for derivative instruments and hedging activities. This statement specifically requires entities to provide enhanced disclosures addressing the following: (1) how and why an entity uses derivative instruments, (2) how derivative instruments and related hedged items are accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133) and its related interpretations, and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS No. 161 is effective for fiscal years and interim periods beginning after November 15, 2008 (January 1, 2009 for the Company). While SFAS No. 161 will have an impact on the Company’s disclosures, it will not affect the Company’s results of operations or financial condition.

F-9

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

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (SFAS No. 141(R)), which replaces SFAS No. 141. SFAS No. 141(R) changes the principles and requirements for the recognition and measurement of identifiable assets acquired, liabilities assumed, and any noncontrolling interest of an acquiree in the financial statements of an acquirer. This statement also provides guidance for the recognition and measurement of goodwill acquired in a business combination and related disclosure. This statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 (January 1, 2009 for the Company).

Sales

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

Other Revenues

Other revenues include royalties related to coal lease agreements, sales agency commissions, farm income, property and facility rentals, generation development activities, net revenues from coal trading activities accounted for under SFAS No. 133, as amended, and contract termination or restructuring payments. Royalty income generally results from the lease or sublease of mineral rights to third parties, with payments based upon a percentage of the selling price or an amount per ton of coal produced.

Discontinued Operations and Assets Held for Sale

The Company classifies items within discontinued operations in the consolidated statements of operations when the operations and cash flows of a particular component (defined as operations and cash flows that can be clearly distinguished, operationally and for financial reporting purposes, from the rest of the entity) of the Company have been (or will be) eliminated from the ongoing operations of the Company as a result of a disposal transaction, and the Company will no longer have any significant continuing involvement in the operations of that component. See Note 2 for additional details related to discontinued operations and assets held for sale.

Cash and Cash Equivalents

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

Inventories

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

Assets and Liabilities from Coal Trading Activities

The Company’s coal trading activities are evaluated under SFAS No. 133, as amended. Trading contracts that meet the SFAS No. 133 definition of a derivative are accounted for at fair value, while contracts that do not qualify as derivatives are accounted for under the accrual method.

The Company’s asset and liability coal trading derivative positions and other corporate hedging activities are offset on a counterparty-by-counterparty basis if the contractual agreement provides for the net settlement of contracts with the counterparty in the event of default or termination of any one contract in accordance with FSP FIN 39-1.

F-10

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

The Company’s trading contracts are reflected at fair value and are included in “Assets and liabilities from coal trading activities” in the consolidated balance sheets as of December 31, 2008 and 2007. Under EITF Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” all mark-to-market gains and losses on energy trading contracts (including derivatives and hedged contracts) are presented on a net basis in the consolidated statement of operations in “Other revenues,” even if settled physically.

Property, Plant, Equipment and Mine Development

Property, plant, equipment and mine development are recorded at cost. Interest costs applicable to major asset additions are capitalized during the construction period, including $1.5 million for the year ended December 31, 2007, and $3.0 million for the year ended December 31, 2006. There was no capitalized interest for the year ended December 31, 2008.

Expenditures which extend the useful lives of existing plant and equipment assets are capitalized. Maintenance and repairs are charged to operating costs as incurred. Costs incurred to develop coal mines or to expand the capacity of operating mines are capitalized. Costs incurred to maintain current production capacity at a mine and exploration expenditures are charged to operating costs as incurred, including costs related to drilling and study costs incurred to convert or upgrade mineral resources to reserves. Costs to acquire computer hardware and the development and/or purchase of software for internal use are capitalized and depreciated over the estimated useful lives.

Coal reserves are recorded at cost, or at fair value in the case of acquired businesses. The net book value of coal reserves totaled $5.4 billion as of December 31, 2008 and $5.6 billion as of December 31, 2007. These coal reserves include mineral rights for leased coal interests and advance royalties that had a net book value of $4.1 billion as of December 31, 2008 and $3.9 billion as of December 31, 2007. The remaining net book value of coal reserves of $1.3 billion at December 31, 2008 and $1.7 billion at December 31, 2007 relates to coal reserves held by fee ownership. Amounts attributable to properties where the Company was not currently engaged in mining operations or leasing to third parties and, therefore, the coal reserves were not currently being depleted was $1.9 billion as of December 31, 2008 and $2.1 billion as of December 31, 2007.

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


		Years
Building and improvements		10 to 20
Machinery and equipment		3 to 39
Leasehold improvements		Life of Lease

In addition, certain plant and equipment assets associated with mining are depreciated using the straight-line method over the estimated life of the mine, which varies from one to 39 years.

F-11

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

Investments in Joint Ventures

The Company accounts for its investments in less than majority owned corporate joint ventures under either the equity or cost method. The Company applies the equity method to investments in joint ventures when it has the ability to exercise significant influence over the operating and financial policies of the joint venture. Investments accounted for under the equity method are initially recorded at cost, and any difference between the cost of the Company’s investment and the underlying equity in the net assets of the joint venture at the investment date is amortized over the lives of the related assets that gave rise to the difference. The Company’s pro rata share of earnings from joint ventures and basis difference amortization is reported in the consolidated statements of operations in “Income from equity affiliates.” Included in the Company’s equity method investments is its 25.5% interest in Carbones del Guasare, which owns and operates the Paso Diablo Mine in Venezuela. The table below summarizes the book value of the Company’s equity method investments, which is reported in “Investments and other assets” in the consolidated balance sheets, the income from its equity affiliates and dividends received from its equity:


														Dividends received from equity
	Book value at				Income from equity affiliates for									affiliates for the year ended
	December 31,				the year ended December 31,									December 31,
	2008		2007		2008			2007			2006			2008		2007		2006
	(Dollars in millions)
Interest in Carbones del Guasare	$	54.2	$	68.4	$	5.7		$	21.2		$	28.0		$	19.9	$	12.9	$	18.1
Other equity method investments		7.0		8.3		(5.7	)		(6.7	)		(5.2	)		—		—		—

Total equity method investments	$	61.2	$	76.7	$	—		$	14.5		$	22.8		$	19.9	$	12.9	$	18.1

Generation Development Costs

The Company owns a 5.06% interest in the Prairie State Energy Campus (Prairie State), which is currently under construction. The Company has capitalized development costs of $69.7 million and $28.8 million that were recorded as part of “Investments and other assets” in the consolidated balance sheets as of December 31, 2008 and 2007, respectively.

Asset Retirement Obligations

SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143) addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The Company’s asset retirement obligation (ARO) liabilities primarily consist of spending estimates related to reclaiming surface land and support facilities at both surface and underground mines in accordance with applicable reclamation laws as defined by each mining permit.

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

Environmental Liabilities

Included in “Other noncurrent liabilities” are accruals for other environmental matters that are recorded in operating expenses when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Accrued liabilities are exclusive of claims against third parties and are not discounted. In general, costs related to environmental remediation are charged to expense.

F-12

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

Income Taxes

Income taxes are accounted for using a balance sheet approach in accordance with SFAS No. 109, “Accounting for Income Taxes.” The Company accounts for deferred income taxes by applying statutory tax rates in effect at the date of the balance sheet to differences between the book and tax basis of assets and liabilities. A valuation allowance is established if it is “more likely than not” that the related tax benefits will not be realized. In determining the appropriate valuation allowance, the Company considers projected realization of tax benefits based on expected levels of future taxable income, available tax planning strategies, and the overall deferred tax position.

FIN No. 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN No. 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company adopted this interpretation effective January 1, 2007.

Postretirement Health Care and Life Insurance Benefits

The Company accounts for postretirement benefits other than pensions in accordance with SFAS No. 106, which requires the costs of benefits to be provided to be accrued over the employees’ period of active service. These costs are determined on an actuarial basis. As a result of the adoption of SFAS No. 158 on December 31, 2006, the Company’s consolidated balance sheet reflects the funded status of postretirement benefits.

Pension Plans

The Company sponsors non-contributory defined benefit pension plans accounted for in accordance with SFAS No. 87, which requires that the cost to provide the benefits be accrued over the employees’ period of active service. These costs are determined on an actuarial basis. SFAS No. 158 amended SFAS No. 87 and as a result of the adoption of SFAS No. 158 on December 31, 2006, the Company’s consolidated balance sheet reflects the funded status of the defined benefit pension plans.

Postemployment Benefits

The Company provides postemployment benefits to qualifying employees, former employees and dependents and accounts for these benefits on the accrual basis in accordance with SFAS No. 112 “Employers’ Accounting for Postemployment Benefits.” Postemployment benefits include workers’ compensation occupational disease, which is accounted for on the actuarial basis over the employees’ period of active service; workers’ compensation traumatic injury claims, which are accounted for based on estimated loss rates applied to payroll and claim reserves determined by independent actuaries and claims administrators; disability income benefits, which are accrued when a claim occurs; and continuation of medical benefits, which are recognized when the obligation occurs. As a result of the adoption of SFAS No. 158 on December 31, 2006, the Company’s consolidated balance sheet reflects the funded status of postemployment benefits.

Derivatives

SFAS No. 133, as amended, requires the recognition at fair value of all derivatives as assets or liabilities on the consolidated balance sheets. Gains or losses from derivative financial instruments designated as fair value hedges are recognized immediately in the consolidated statements of operations, along with the offsetting gain or loss related to the underlying hedged item.

Gains or losses on derivative financial instruments designated as cash flow hedges are recorded as a separate component of stockholders’ equity until settlement (or until hedge ineffectiveness is determined), whereby gains or losses are reclassified to the consolidated statements of operations in conjunction with the recognition of the underlying hedged item. To the extent that the periodic changes in the fair value of the derivatives are not effective, or if the hedge ceases to qualify for hedge accounting, the ineffective portion of the periodic non-cash changes are recorded in the consolidated statement of operations in the period of the change. The potential for hedge ineffectiveness is present in the design of the Company’s cash flow hedge relationships (see Note 3 for additional details).

F-13

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

Use of Estimates in the Preparation of the Consolidated Financial Statements

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

Impairment of Long-Lived Assets

The Company records impairment losses on long-lived assets used in operations when events and circumstances indicate that assets might be impaired and the undiscounted cash flows estimated to be generated by those assets under various assumptions are less than the carrying amounts of the assets. Impairment losses are measured by comparing the estimated fair value of the impaired asset to its carrying amount. There were no impairment losses recorded during the years ended December 31, 2008, 2007 and 2006.

Fair Value

SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The Company adopted SFAS No. 157 effective January 1, 2008. Although the adoption of SFAS No. 157 did not materially impact the Company’s financial condition, results of operations or cash flows, additional disclosures related to fair value measurements are now required. See Note 3 for additional information.

Foreign Currency

The Company’s foreign subsidiaries utilize the U.S. dollar as their functional currency. As such, monetary assets and liabilities are remeasured at year-end exchange rates while non-monetary items are remeasured at historical rates. Income and expense accounts are remeasured at the average rates in effect during the year, except for those expenses related to balance sheet amounts that are remeasured at historical exchange rates. Gains and losses from foreign currency remeasurement related to tax balances are included as a component of income tax expense while all other remeasurement gains and losses are included in operating costs and expenses. The foreign currency remeasurement gain for the year ended December 31, 2008, was $69.9 million. The foreign currency remeasurement loss for the year end December 31, 2007 was $60.4 million and for December 31, 2006 was $12.8 million.

Share-Based Compensation

The Company accounts for share-based compensation in accordance with the fair value recognition provisions of SFAS No. 123 (Revised 2004), “Share-Based Payment” (SFAS 123(R)), which the Company adopted using the modified prospective option on January 1, 2006. Under SFAS No. 123(R), share-based compensation expense is generally measured at the grant date and recognized as expense over the vesting period of the award.

Exploration and Drilling Costs

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

Advance Stripping Costs

F-14

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

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

Reclassifications

Certain amounts in prior periods have been reclassified to conform with the presentation of 2008, with no effect on previously reported net income or stockholders’ equity.

(2) Discontinued Operations

Patriot Coal Corporation

On October 31, 2007, the Company spun off portions of its formerly Eastern U.S. Mining segment through a dividend of all outstanding shares of Patriot Coal Corporation (Patriot), which is now an independent public company traded on the New York Stock Exchange (symbol PCX). The spin-off included eight company-operated mines, two joint venture mines and numerous contractor operated mines serviced by eight coal preparation facilities along with 1.2 billion tons of proven and probable coal reserves. Revenues, pretax income (loss) and the income tax provision (benefit) related to the spun off operations were as follows:


	Year ended December 31,
	2008			2007			2006
	(Dollars in millions)
Revenues	$	431.2		$	1,024.5		$	1,147.9
Income (loss) before income taxes		(23.0	)		(235.2	)		67.9
Income tax provision (benefit)		(8.9	)		(81.5	)		8.6

Revenues from the spun-off operations are the result of supply agreements the Company entered into with Patriot to meet commitments under non-assignable, pre-existing customer agreements sourced from Patriot mining operations. The Company makes no profit as part of these arrangements and only sources coal from Patriot to meet customer obligations. Included in the loss from discontinued operations for the year ended December 31, 2008 was the first quarter write-off of a $19.4 million receivable related to coal excise taxes previously paid on export shipments produced from discontinued operations. As part of the Patriot spin-off, the Company retained a receivable for coal excise tax refunds on export shipments that had previously been ruled unconstitutional by the appellate court. The U.S. Supreme Court reversed the appellate court’s ruling on April 15, 2008, and the Company recorded a charge to discontinued operations.

In October 2008, the Energy Improvement and Extension Act of 2008 was enacted, which contained provisions that allow for the refund of coal excise tax collected on coal exported from the U.S. between January 1, 1990 and the date of the legislation. The Company has resubmitted a claim for refund, and that claim is subject to approval of the Internal Revenue Service (IRS). By statute, the IRS has 180 days to approve the refund claims and another 180 days to pay the refund with interest. Once the Company is notified of an approved amount, the final refund will be recorded to discontinued operations.

The Company had also entered into a transition services agreement, which expired in 2008, to provide certain administrative and other services to Patriot. Under this agreement, the Company billed $1.4 million for services during 2008 and $0.9 million for services during 2007.

F-15

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

The assets and liabilities of the Patriot related discontinued operations as of December 31, 2008 and 2007 are shown below.


	December 31, 2008		December 31, 2007
	(Dollars in millions)
Assets
Current assets
Other current assets	$	51.0	$	113.9

Total current assets		51.0		113.9

Noncurrent assets
Investments and other assets		4.9		39.6

Total assets	$	55.9	$	153.5


Liabilities
Current liabilities
Accounts payable and accrued expenses	$	69.1	$	180.4

Total current liabilities		69.1		180.4
Noncurrent liabilities
Other noncurrent liabilities		12.8		33.2

Total liabilities	$	81.9	$	213.6

Other current assets included receivables from customers in relation to the supply agreements with Patriot, and accounts payable and accrued expenses included the amounts due to Patriot on these pass-through transactions. Also included in other current assets is the current portion of deferred taxes related to these operations. Accounts payable and accrued expenses include an accrual for charges related to losses on firm purchase commitments that extend through 2010.

During 2008, the Company recognized an additional dividend to Patriot of $26.5 million related to the true-up of deferred tax assets associated with Patriot.

Other

In December 2008, the Company sold its Baralaba Mine, a non-strategic Australian mine, for $25.8 million of cash proceeds and an Australian dollar note receivable valued at approximately $8.7 million on December 31, 2008, resulting in a gain of $26.2 million. The non-cash portion of this transaction was excluded from the investing section of the consolidated statement of cash flows. Revenues related to these operations for the years ended December 31, 2008, 2007 and 2006 were $18.8 million, $22.1 million and $10.2 million, respectively. Loss before income taxes related to these operations was $15.7 million, $10.6 million and $10.6 million for the years ended December 31, 2008, 2007 and 2006, respectively. Income tax benefits for all periods presented were completely offset by valuation allowances recorded against the deferred tax assets created by the operating losses.

In December 2008, the Company committed to the divestiture of certain non-strategic Midwestern U.S. mining assets. At December 31, 2008, the carrying amount of assets held for sale totaled $12.6 million, which was included in “Investments and other assets.” The carrying amount of liabilities associated with assets held for sale totaled $9.4 million, which was included in “Other noncurrent liabilities.” Revenues related to these operations for the years ended December 31, 2008, 2007 and 2006 were $30.6 million, $39.5 million and $47.3 million, respectively. Loss, net of tax, related to these operations was $27.7 million, $8.2 million and $6.5 million for the years ended December 31, 2008, 2007 and 2006, respectively.

F-16

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

(3) Risk Management and Fair Value Measurements

Employees

As of December 31, 2008, the Company had approximately 7,200 employees. As of December 31, 2008, approximately 28% of the Company’s hourly employees were represented by organized labor unions and generated 10% of the 2008 coal production. Relations with its employees and, where applicable, organized labor are important to the Company’s success.

United States Labor Relations

Hourly workers at the Company’s Kayenta Mine in Arizona are represented by the United Mine Workers of America (UMWA) under the Western Surface Agreement, which is effective through September 2, 2013. This agreement covers approximately 7% of the Company’s U.S. subsidiaries’ hourly employees, who generated 4% of the Company’s U.S. production during the year ended December 31, 2008.

Hourly workers at the Company’s Willow Lake Mine in Illinois are represented by the International Brotherhood of Boilermakers under a labor agreement that expires April 15, 2011. This agreement covers approximately 8% of the Company’s U.S. subsidiaries’ hourly employees, who generated approximately 2% of the Company’s U.S. production during the year ended December 31, 2008.

Australia Labor Relations

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

Risk Management

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, while commodity price risk related to materials used in production is managed through the use of fixed price and cost plus contracts and derivatives. Interest rate and foreign currency exchange risk are managed through the use of forward contracts, swaps and options.

F-17

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

The following summarizes the Company’s interest rate, currency and commodity positions at December 31, 2008:


															Account
	Notional Amount by term to Maturity														Classification by
															Cash		Fair
													2014 and		flow		value		Fair Value -
	Total		2009		2010		2011		2012		2013		thereafter		hedge		hedge		asset (liability)
Interest Rate Swaps
Fixed-to-floating (dollars in millions)	$	320.0	$	—	$	—	$	—	$	—	$	220.0	$	100.0	$	—	$	320.0	$	12.5
Floating-to-fixed (dollars in millions)	$	186.0	$	—	$	—	$	120.0	$	—	$	—	$	66.0	$	186.0	$	—	$	(21.8	)

Foreign Currency
A$:US$ forwards and options (A $ millions)		2,408.0		1,161.7		826.3		420.0		—		—		—		2,408.0		—		(283.8	)

Commodity Contracts
Diesel fuel hedge contracts (million gallons)		189.4		98.4		64.4		26.6		—		—		—		189.4		—		(176.5	)
U.S. explosives hedge contracts (million MMBtu)		6.5		3.6		2.9		—		—		—		—		6.5		—		(18.2	)

Interest Rate Swaps

The Company’s usage of interest rate swaps is discussed in Note 12.

Foreign Currency Risk

The Company utilizes currency forwards and options to hedge currency risk associated with anticipated Australian dollar expenditures.

Diesel Fuel and Explosives Hedges

The Company uses a combination of forward contracts with its suppliers and financial derivative contracts, which are primarily swap contracts with financial institutions, to manage commodity risk associated with diesel fuel in the U.S. and Australia (non-contractor mines) and explosives in the U.S. Explosives costs in Australia are generally included in the fees paid to the Company’s contract miners.

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 as a separate component of stockholders’ equity until the hedged transaction occurs, whereby gains and losses are reclassified to the consolidated statement of operations in conjunction with the recognition of the underlying hedged item. The ineffective portion of the derivative’s change in fair value is recorded in the consolidated statement of operations. In addition, if the hedging relationship ceases to be highly effective, or it becomes probable that a forecasted transaction is no longer expected to occur, gains and losses on the derivative are recorded to the consolidated statements of operations.

A measure of ineffectiveness is inherent in hedging future diesel fuel purchases with derivative positions based on crude oil or other mid-distillate commodities, especially given the recent volatility in the prices of refined products.

The Company’s hedging of future explosives purchases is primarily through the use of derivative positions based on natural gas, which closely matches the contractual purchase price of explosives since price changes occur in a constant ratio of MMBtu per ton in the manufacture of explosives and generally carry a fixed surcharge.

F-18

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

In some instances, the Company has designated an existing 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 derivative that settles at a time later than the occurrence of the cash flow being hedged. The hedge yields ineffectiveness to the extent the fair value of the hedged item and the derivative hedge contract do not move by identical amounts.

For the year ended December 31, 2008, the Company recognized $5.0 million of higher operating costs related to hedge ineffectiveness. During 2007 and 2006, the Company did not recognize any hedge ineffectiveness.

Performance and Credit Risk

The Company’s concentration of performance and credit risk is substantially with electric utilities, energy producers and energy marketers. 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. These steps include obtaining letters of credit or cash collateral, 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. In general, increases in coal price volatility and the Company’s trading activity resulted in greater exposure to its coal-trading counterparties during 2008.

In addition to credit risk, performance risk includes the possibility that a counterparty fails to deliver agreed production or trading volumes. 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, 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. 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 receivables and payables with such counterparties.

The Company conducts its various hedging activities related to foreign currency, interest rate management, and fuel and explosives exposures with a variety of highly-rated commercial banks. In light of the recent turmoil in the financial markets the Company continues to closely monitor counterparty creditworthiness.

Fair Value Measurements – Risk Management and Coal Trading

The following table summarizes the income statement classification for the Company’s financial instruments for which fair value is measured on a recurring basis:


	Income Statement Classification
Financial Instrument	Gains/Losses - Realized	Gains/Losses - Unrealized⁽¹⁾
Commodity swaps and options — coal trading activities	Other revenues	Other revenues
Commodity swaps and options — other than coal	Operating costs and expenses	—
Physical commodity purchase/sale contracts — coal trading activities	Other revenues	Other revenues
Interest rate swaps	Interest expense	—
Foreign currency forwards and options	Operating costs and expenses	—


⁽¹⁾		Gains and losses on derivative financial instruments designated as cash flow hedges are recorded as a separate component of stockholders’ equity until settlement of underlying transaction (or until the hedge ineffectiveness is determined).

As discussed in Note 1, the Company adopted SFAS No. 157 effective January 1, 2008. Although the adoption of SFAS No. 157 did not materially impact the Company’s financial condition, results of operations or cash flows, additional disclosures related to fair value measurements are now required. SFAS No. 157 establishes 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.

F-19

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

The following table sets forth as of December 31, 2008 the hierarchy of the Company’s net financial asset (liability) positions for which fair value is measured on a recurring basis:


	Level 1			Level 2			Level 3			Total
	(Dollars in millions)
Commodity swaps and options — coal trading activities	$	(17.0	)	$	233.7		$	(1.1	)	$	215.6
Commodity swaps and options — other than coal		—			(194.7	)		—			(194.7	)
Physical commodity purchase/sale contracts — coal trading activities		—			104.1			38.9			143.0
Interest rate swaps		—			(9.3	)		—			(9.3	)
Foreign currency forwards and options		—			(283.8	)		—			(283.8	)

Total net financial assets (liabilities)	$	(17.0	)	$	(150.0	)	$	37.8		$	(129.2	)

For Level 1 and 2 financial assets and liabilities, the Company utilizes both direct and indirect observable price quotes, including LIBOR yield curves, New York Mercantile Exchange 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 – coal trading activities: 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).

	•		Commodity swaps and options – other than coal: generally valued based on a valuation that is corroborated by the use of market-based pricing (Level 2).

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

	•		Interest rate swaps: valued based on quoted inputs from counterparties corroborated with observable market data (Level 2).

	•		Foreign currency forwards and options: valued utilizing inputs obtained in quoted public markets (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. These instruments or contracts are valued based on quoted inputs from brokers or counterparties, or reflect methodologies that consider historical relationships among similar commodities to derive the Company’s best estimate of fair value. The Company has consistently applied these valuation techniques in all periods presented, and believes it has obtained the most accurate information available for the types of derivative contracts held.

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


	Year ended December
	31, 2008
	(Dollars in millions)
Beginning of period	$	128.7
Total gains or losses (realized/unrealized):
Included in earnings		(9.8	)
Included in other comprehensive income		3.4
Purchases, issuances and settlements		(58.8	)
Transfers in and/or out		(25.7	)

December 31, 2008	$	37.8

F-20

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

The following table summarizes the changes in unrealized losses relating to Level 3 net financial assets held both as of January 1 and December 31, 2008:


	Year ended December
	31, 2008
	(Dollars in millions)
Changes in unrealized losses (1)	$	(34.8	)


⁽¹⁾		For the periods presented, unrealized gains and losses from Level 3 items are offset by 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.

Fair Value – Other Financial Instruments

The following methods and assumptions were used by the Company in estimating its fair value disclosures for other financial instruments as of December 31, 2008 and 2007:

	•		Cash and cash equivalents, accounts receivable 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.

	•		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 7.875% Senior Notes due 2026 and the Debentures due 2066 are net of their unamortized note discount.

	•		Interest rate swaps are valued based on quoted inputs from counterparties corroborated with observable market data (Level 2).

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


	December 31, 2008				December 31, 2007
	Carrying		Estimated		Carrying		Estimated
	Amount		Fair Value		Amount		Fair Value
	(Dollars in millions)
Long-term debt	$	2,793.6	$	2,472.1	$	2,909.0	$	2,882.7

(4) Resource Management and Other Commercial Events

In 2008, the Company sold approximately 58 million tons of non-strategic coal reserves and surface lands located in Kentucky for $21.5 million cash proceeds and a note receivable of $54.9 million and recognized a gain of $54.0 million. The note receivable is being paid in two installments, $30.0 million of which was received in December 2008. The balance is to be paid in June 2009. The non-cash portion of this transaction was excluded from the investing section of the consolidated statement of cash flows.

In 2007, the Company sold approximately 172 million tons of coal reserves and surface lands to the Prairie State equity partners. The Company recognized a gain totaling $26.4 million and received $114.3 million in cash proceeds associated with this transaction. See Note 19 for additional information regarding Prairie State.

F-21

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

In 2007, the Company exchanged oil and gas rights and assets in more than 860,000 acres in the Illinois Basin, West Virginia, New Mexico and the Powder River Basin for coal reserves in West Virginia and Kentucky and $15.0 million in cash proceeds. The Company’s subsidiaries, including one subsidiary now owned by Patriot, received approximately 40 million tons of coal reserves. Based on the fair value of the coal reserves received, the Company recognized a $50.5 million gain on the exchange. The non-cash portion of this transaction was excluded from the investing section of the consolidated statement of cash flows.

In 2006, the Company exchanged approximately 63 million tons of coal reserves at its Caballo mining operation for approximately 46 million tons of coal reserves contiguous with the Company’s North Antelope Rochelle mining operation. Based on the fair value of the coal reserves exchanged, the Company recognized a gain totaling $39.2 million. This non-cash transaction was excluded from the investing section of the consolidated statement of cash flows.

In 2006, the Company recognized $35.8 million in gains related to the settlement of commitments by a third-party coal producer following a brokerage contract restructuring. The gains are included in “Other revenues” in the consolidated statements of operations.

(5) Assets and Liabilities from Coal Trading Activities

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


	December 31,
	2008						2007
	(Dollars in millions)
	Gross Basis			Net Basis			Gross Basis			Net Basis
Assets from coal trading activities	$	1,969.7		$	662.8		$	967.1		$	349.8
Liabilities from coal trading activities		(1,548.5	)		(304.2	)		(918.6	)		(301.8	)

Subtotal		421.2			358.6			48.5			48.0
Margin held ⁽¹⁾		(62.6	)		—			(0.5	)		—

Net assets from coal trading activities	$	358.6		$	358.6		$	48.0		$	48.0


⁽¹⁾		Represents margin held from counterparties that was netted in accordance with FSP FIN 39-1 and does not represent the Company’s total margin held or posted.

The increase in pricing since December 31, 2007 and higher trading volumes have significantly increased the value of the Company’s trading portfolio in 2008. As of December 31, 2008, forward contracts made up 50% and 77% of the Company’s trading assets and liabilities, respectively; financial swaps represent most of the remaining balances. The fair value of coal trading positions designated as cash flow hedges of anticipated future sales was an asset of $220.4 million as of December 31, 2008 and a liability of $44.1 million as of December 31, 2007. The net value of trading positions, including those designated as hedges of future cash flows, represents the fair value of the trading portfolio.

Of the coal trading derivatives and related hedge contracts in the Company’s trading portfolio as of December 31, 2008, 94% were valued utilizing prices from over-the-counter market sources, adjusted for coal quality and traded transportation differentials and 6% of the Company’s contracts were valued based on similar market transactions.

F-22

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

As of December 31, 2008, the estimated future realization of the value of the Company’s trading portfolio was as follows:


Year of	Percentage
Expiration	of Portfolio
2009		75	%
2010		13	%
2011		11	%
2012		1	%

		100	%

At December 31, 2008, 66% of the Company’s credit exposure related to coal trading activities with investment grade counterparties and 34% with non-investment grade counterparties. The Company’s coal trading operations traded 192.9 million tons, 166.5 million tons and 79.1 million tons for the years ended December 31, 2008, 2007 and 2006, respectively.

(6) Accounts Receivable Securitization

The Company has an accounts receivable securitization program through its wholly-owned, bankruptcy-remote subsidiary (Seller). Under the program, the Company contributes undivided interests in a pool of eligible trade receivables to the Seller, which then sells, without recourse, to a multi-seller, asset-backed commercial paper conduit (Conduit). Purchases by the Conduit are financed with the sale of highly rated commercial paper. The Company utilizes proceeds from the sale of its accounts receivable as an alternative to other forms of debt, effectively reducing its overall borrowing costs. The funding cost of the securitization program was $10.8 million, $11.2 million and $1.9 million for the years ended December 31, 2008, 2007 and 2006, respectively. The securitization program and the underlying facilities will effectively expire in May 2009.

The securitization transactions have been recorded as sales, with those accounts receivable sold to the Conduit removed from the consolidated balance sheets. The amount of undivided interests in accounts receivable sold to the Conduit was $275.0 million as of December 31, 2008 and 2007 and $219.2 million as of December 31, 2006.

The Seller is a separate legal entity whose assets are available first and foremost to satisfy the claims of its creditors. Eligible receivables, as defined in the securitization agreement, consist of trade receivables from most of the Company’s U.S. subsidiaries, and are reduced for certain items such as past due balances and concentration limits. Of the eligible pool of receivables contributed to the Seller, undivided interests in only a portion of the pool are sold to the Conduit. The Company (the Seller) continues to own $75.6 million of receivables as of December 31, 2008, which represents collateral supporting the securitization program. The Seller’s interest in these receivables is subordinate to the Conduit’s interest in the event of default under the securitization agreement. If the Company defaulted under the securitization agreement or if its pool of eligible trade receivables decreased significantly, the Company could be prohibited from selling any additional receivables in the future under the agreement.

F-23

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

(7) Earnings per Share

As discussed in Note 1, the Company adopted FSP EITF 03-6-1 effective January 1, 2009 and began using the two-class method to compute basic and diluted EPS for all periods presented. The following illustrates the earnings allocation method utilized in the calculation of basic and diluted EPS.


	Year Ended December 31,
	2008			2007			2006
	(Dollars in millions, except per share amounts)
Basic earnings per share using two-class method:
Income from continuing operations, net of income taxes	$	990.4		$	437.2		$	570.5
Less: Net (income) loss attributable to noncontrolling interests		(6.2	)		2.3			(0.6	)

Income from continuing operations attributable to common stockholders before allocation of earnings to participating securities		984.2			439.5			569.9
Less: Earnings allocated to participating securities		(5.5	)		(1.2	)		(1.9	)

Income from continuing operations attributable to common stockholders		978.7			438.3			568.0
Income (loss) from discontinued operations, net of income taxes		(31.3	)		(175.7	)		30.8

Net income attributable to common stockholders (numerator)	$	947.4		$	262.6		$	598.8


Weighted average shares outstanding — basic (denominator)		268,860,528			264,068,180			263,419,344


Basic earnings per share attributable to common stockholders:
Income from continuing operations	$	3.64		$	1.66		$	2.15
Income (loss) from discontinued operations		(0.12	)		(0.67	)		0.12

Net income	$	3.52		$	0.99		$	2.27


Diluted earnings per share using two-class method:
Income from continuing operations attributable to common stockholders before allocation of earnings to participating securities	$	984.2		$	439.5		$	569.9
Less: Earnings allocated to participating securities		(5.5	)		(1.2	)		(1.9	)

Income from continuing operations attributable to common stockholders before the reallocation of the earnings of participating securities		978.7			438.3			568.0
Reallocation of the earnings of participating securities		0.1			—			—

Income from continuing operations attributable to common stockholders		978.8			438.3			568.0
Income (loss) from discontinued operations, net of income taxes		(31.3	)		(175.7	)		30.8

Net income attributable to common stockholders (numerator)	$	947.5		$	262.6		$	598.8


Weighted average shares outstanding — basic		268,860,528			264,068,180			263,419,344
Dilutive impact of share-based compensation ⁽¹⁾		1,854,820			4,521,021			5,367,916

Weighted average shares outstanding — diluted (denominator)		270,715,348			268,589,201			268,787,260


Diluted earnings per share attributable to common stockholders:
Income from continuing operations	$	3.61		$	1.63		$	2.11
Income (loss) from discontinued operations		(0.11	)		(0.65	)		0.11

Net income	$	3.50		$	0.98		$	2.22


⁽¹⁾		Includes the dilutive impact of stock options, restricted stock awards, deferred stock units, employee stock purchase plan and performance units.

F-24

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

(8) Inventories

Inventories consisted of the following:


	December 31,
	2008		2007
	(Dollars in millions)
Materials and supplies	$	110.2	$	90.2
Raw coal		24.0		45.5
Saleable coal		143.5		129.0

Total	$	277.7	$	264.7

(9) Leases

The Company leases equipment and facilities under various noncancelable lease agreements. Certain lease agreements require the maintenance of specified ratios and contain restrictive covenants which limit indebtedness, subsidiary dividends, investments, asset sales and other Company actions. Rental expense under operating leases was $108.7 million, $104.7 million and $78.5 million for the years ended December 31, 2008, 2007 and 2006, respectively. The gross value of property, plant, equipment and mine development assets under capital leases was $99.4 million and $116.9 million as of December 31, 2008 and 2007, respectively, related primarily to the leasing of mining equipment. The accumulated amortization for these items was $18.2 million and $24.7 million at December 31, 2008 and 2007, respectively.

The Company also leases coal reserves under agreements that require royalties to be paid as the coal is mined. Certain agreements also require minimum annual royalties to be paid regardless of the amount of coal mined during the year. Total royalty expense was $508.2 million, $343.1 million and $285.7 million for the years ended December 31, 2008, 2007 and 2006, respectively.

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

F-25

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

Future minimum lease and royalty payments as of December 31, 2008, are as follows:


					Coal Lease
					and
	Capital		Operating		Royalty
Year Ended December 31,	Leases		Leases		Obligations
	(Dollars in millions)
2009	$	19.1	$	76.3	$	134.1
2010		15.1		73.3		8.0
2011		15.1		59.2		7.1
2012		15.1		41.2		6.2
2013		23.0		32.4		5.3
2014 and thereafter		12.0		126.8		33.2

Total minimum lease payments	$	99.4	$	409.2	$	193.9

Less interest		18.2

Present value of minimum capital lease payments	$	81.2

As of December 31, 2008, certain of the Company’s lease obligations were secured by outstanding surety bonds totaling $99.2 million.

(10) Accounts Payable and Accrued Expenses

Accounts payable and accrued expenses consisted of the following:


	December 31,
	2008		2007
	(Dollars in millions)
Trade accounts payable	$	427.9	$	393.5
Accrued taxes other than income		170.7		152.2
Accrued payroll and related benefits		120.1		76.1
Accrued health care		82.5		83.5
Workers’ compensation obligations		8.7		6.2
Other accrued benefits		4.1		3.1
Accrued royalties		77.7		35.4
Accrued environmental		7.6		7.1
Income taxes payable — Australia		142.7		27.6
Accrued interest		31.1		30.9
Other accrued expenses		131.7		131.8
Commodity and foreign currency hedge contracts		261.1		1.5
Liabilities associated with discontinued operations		69.1		180.4
Current liabilities associated with assets held for sale		—		4.7

Total accounts payable and accrued expenses	$	1,535.0	$	1,134.0

F-26

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

(11) Income Taxes

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


	Year Ended December 31,
	2008		2007		2006
	(Dollars in millions)
U.S.	$	185.1	$	296.2	$	235.3
Non U.S.		990.7		67.8		249.5

Total	$	1,175.8	$	364.0	$	484.8

Total income tax provision (benefit) consisted of the following:


	Year Ended December 31,
	2008			2007			2006
	(Dollars in millions)
Current:
U.S. federal	$	—		$	—		$	4.3
Non U.S.		218.7			26.4			67.6
State		—			0.2			0.4

Total current		218.7			26.6			72.3


Deferred:
U.S. federal		47.1			(136.8	)		(161.0	)
Non U.S.		(81.7	)		44.2			4.1
State		1.3			(7.2	)		(1.1	)

Total deferred		(33.3	)		(99.8	)		(158.0	)

Total provision (benefit)	$	185.4		$	(73.2	)	$	(85.7	)

The income tax rate differed from the U.S. federal statutory rate as follows:


	Year Ended December 31,
	2008			2007			2006
	(Dollars in millions)
Federal statutory rate	$	411.5		$	127.4		$	169.7
Excess depletion		(40.1	)		(55.3	)		(52.3	)
Foreign earnings rate differential		(124.4	)		(17.3	)		(20.4	)
Remeasurement of foreign deferred taxes		(65.2	)		56.0			—
State income taxes, net of U.S. federal tax benefit		(1.6	)		0.8			5.6
Tax credits		(12.6	)		(24.3	)		—
Changes in valuation allowance		(44.2	)		(175.7	)		(165.5	)
Changes in tax reserves		34.4			3.3			(28.7	)
Other, net		27.6			11.9			5.9

Total provision (benefit)	$	185.4		$	(73.2	)	$	(85.7	)

F-27

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

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


	December 31,
	2008			2007
	(Dollars in millions)
Deferred tax assets:
Tax credits and loss carryforwards	$	785.9		$	680.9
Postretirement benefit obligations		403.9			350.1
Intangible tax asset and purchased contract rights		58.1			83.6
Accrued reclamation and mine closing liabilities		46.2			32.4
Accrued long-term workers’ compensation liabilities		12.6			15.6
Employee benefits		56.2			35.9
Financial guarantee		23.8			24.4
Others		56.5			39.5

Total gross deferred tax assets		1,443.2			1,262.4


Deferred tax liabilities:
Property, plant, equipment and mine development, leased coal interests and advance royalties, principally due to differences in depreciation, depletion and asset writedowns		1,154.2			1,357.8
Unamortized discount on Convertible Junior Subordinated Debentures		139.9			140.3
Hedge activities		35.3			43.1
Investments and other assets		76.6			64.9

Total gross deferred tax liabilities		1,406.0			1,606.1

Valuation allowance		(57.0	)		(92.6	)

Net deferred tax liability	$	(19.8	)	$	(436.3	)


Deferred taxes are classified as follows:
Current deferred income taxes	$	1.7		$	58.8
Noncurrent deferred income taxes		(21.5	)		(495.1	)

Net deferred tax liability	$	(19.8	)	$	(436.3	)

The Company’s tax credits and loss carryforwards included alternative minimum tax (AMT) and general business credits of $62.4 million and $49.8 million, U.S. NOL carryforwards of $653.5 million and $574.3 million and foreign loss carryforwards of $70.0 million and $56.8 million as of December 31, 2008 and 2007, respectively. The AMT credits and foreign NOL and capital loss carryforwards have no expiration date and the U.S. NOL carryforwards begin to expire in the year 2020. The Company evaluated and assessed the expected near-term utilization of NOLs, future book and taxable income, available tax strategies and the overall deferred tax position to determine the appropriate amount and timing of valuation allowance adjustments. The largest component of the 2008 assessment was a $45.3 million reduction of a valuation allowance on foreign NOL’s. Significant reductions of valuation allowance on U.S. NOL carryforwards arose during the 2007 and 2006 assessments. The remaining valuation allowance at December 31, 2008 of $57.0 million represents a reserve for AMT credits, certain foreign deferred tax assets and state loss carryforwards due to uncertainty of their ultimate realization.

F-28

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

The total amount of the net unrecognized tax benefits was $176.9 million ($186.3 million gross) at December 31, 2008 and was $143.2 million ($152.6 million gross) at December 31, 2007. The amount of the Company’s gross unrecognized tax benefits has increased by $33.7 million since January 1, 2008. A reconciliation of the beginning and ending amount of gross unrecognized tax benefits is as follows (dollars in millions):


Balance at January 1, 2008	$	152.6
Additions based on tax positions related to current year		30.3
Addidtions to tax positions of prior years		3.4

Balance at December 31, 2008	$	186.3

The amount of the net unrecognized tax benefits that, if recognized, would directly affect the effective tax rate is $176.9 million. However, $27.0 million would generate a deferred tax asset for state NOL carryforwards that would more likely than not be offset by a valuation allowance. The Company does not expect any significant changes to its net unrecognized tax benefits within 12 months of this reporting date.

The Company recognizes interest and penalties accrued related to unrecognized tax benefits in its income tax provision. The Company has recognized $1.3 million of interest for the year ended December 31, 2008. The Company had $3.6 million and $2.3 million of accrued interest related to uncertain tax positions at December 31, 2008 and 2007, respectively. The Company has considered the application of penalties on its unrecognized tax benefits and determined, based upon several factors, including the existence of NOL carryforwards, that no accrual of penalties is required.

The Company’s federal income tax returns for the tax years 2005 and 2006 are currently under examination by the IRS while the Company’s federal income tax returns for 1999 through 2001, 2003 through 2004 and 2007 through 2008 remain subject to examination by the IRS. The Company’s state income tax returns for the tax years 1991 and beyond remain subject to examination by various state taxing authorities. The Company’s foreign income tax returns for the tax years 2003 and beyond remain subject to examination by various foreign taxing authorities.

The total amount of undistributed earnings of foreign subsidiaries for income tax purposes was approximately $1.2 billion at December 31, 2008 and $303.6 million at December 31, 2007. The Company has not provided deferred taxes on foreign earnings of $1.1 billion for 2008 and of $264.5 million for 2007 because such earnings were intended to be indefinitely reinvested outside the U.S. Should the Company repatriate all of these earnings, a one-time income tax charge to the Company’s consolidated results of operations of up to $387.0 million could occur.

The following table summarizes the Company’s tax payments:


	Year Ended December 31,
	2008		2007		2006
	(Dollars in millions)
U.S. — federal	$	—	$	3.0	$	3.9
U.S. — state and local		—		1.2		0.5
Non U.S.		65.8		80.0		23.1

Total tax payments	$	65.8	$	84.2	$	27.5

F-29

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

(12) Long-Term Debt

The Company’s total indebtedness as of December 31, 2008 and 2007, consisted of the following:


	December 31,
	2008		2007
	(Dollars in millions)
Term Loan under Senior Unsecured Credit Facility	$	490.3	$	509.1
Revolving Credit Facility		—		97.7
Convertible Junior Subordinated Debentures due 2066		369.9		368.4
7.375% Senior Notes due 2016		650.0		650.0
6.875% Senior Notes due 2013		650.0		650.0
7.875% Senior Notes due 2026		247.0		247.0
5.875% Senior Notes due 2016		218.1		218.1
6.84% Series C Bonds due 2016		43.0		43.0
6.34% Series B Bonds due 2014		18.0		21.0
6.84% Series A Bonds due 2014		10.0		10.0
Capital lease obligations		81.2		92.2
Fair value hedge adjustment		15.1		1.6
Other		1.0		0.9

Total	$	2,793.6	$	2,909.0

Senior Unsecured Credit Facility

On September 15, 2006, the Company entered into a Third Amended and Restated Credit Agreement (the Agreement), which established a $2.75 billion Senior Unsecured Credit Facility (the Senior Unsecured Credit Facility) and which amended and restated in full the Company’s then existing $1.35 billion Senior Secured Credit Facility (the Senior Secured Credit Facility). The Senior Unsecured Credit Facility provides a $1.8 billion Revolving Credit Facility (the Revolver) and a $950.0 million Term Loan Facility (the Term Loan Facility).

The Revolver is intended to accommodate working capital needs, letters of credit, and other general corporate purposes. The Revolver also includes a $50.0 million sub-facility available for same-day swingline loan borrowings. As of December 31, 2008, the Company had no borrowings and $245.1 million letters of credit outstanding under the Revolver, with a remaining available borrowing capacity of $1.5 billion.

The Term Loan Facility, which was fully drawn in October 2006 in connection with the Excel Coal Limited (Excel) acquisition was paid down ($403.0 million) from a portion of the net proceeds from the Debentures. In conjunction with the establishment of the Senior Unsecured Credit Facility, the Company incurred $8.6 million in financing costs, of which $5.6 million related to the Revolver and $3.0 million related to the Term Loan. These debt issuance costs are being amortized to interest expense over five years, the term of the Senior Unsecured Credit Facility.

Loans under the facility are available to the Company in U.S. dollars, with a sub-facility under the Revolver available in Australian dollars, pounds sterling and euros. Letters of credit under the Revolver are available to the Company in U.S. dollars with a sub-facility available in Australian dollars, pounds sterling and euros. The interest rate payable on the Revolver and the Term Loan is based on a pricing grid tied to the Company’s leverage ratio, as defined in the Agreement. The interest rate payable on the Revolver and the Term Loan is currently LIBOR plus 0.75%, which was 2.2% at December 31, 2008.

F-30

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

Under the Senior Unsecured Credit Facility, the Company must comply with certain financial covenants on a quarterly basis including a minimum interest coverage ratio and a maximum leverage ratio, as defined in the Agreement. The financial covenants also place limitations on the Company’s investments in joint ventures, unrestricted subsidiaries, indebtedness of non-loan parties and the imposition of liens on Company assets. The new facility is less restrictive with respect to limitations on the Company’s dividend payments, capital expenditures, asset sales and stock repurchases. The Senior Unsecured Credit Facility matures on September 15, 2011.

The Debentures

As of December 31, 2008, the Company had $732.5 million aggregate principal of 4.75% Debentures outstanding, which are due 2066, including $57.5 million issued pursuant to the underwriters’ exercise of their over-allotment option. The Debentures generally require interest to be paid semiannually at a rate of 4.75% per year. The Company may elect to, and to the extent that a mandatory trigger event (as defined in the indenture governing the Debentures) has occurred and is continuing will be required to, defer interest payments on the Debentures. After five years of deferral at the Company’s option, or upon the occurrence of a mandatory trigger event, the Company generally must sell warrants or preferred stock with specified characteristics and use the funds from that sale to pay deferred interest, subject to certain limitations. In no event may the Company defer payments of interest on the Debentures for more than 10 years.

The Debentures are convertible at any time on or prior to December 15, 2036 if any of the following conditions occur: (i) the Company’s closing common stock price exceeds 140% of the then applicable conversion price for the Debentures (currently $81.81 per share) for at least 20 of the final 30 trading days in any quarter; (ii) a notice of redemption is issued with respect to the Debentures; (iii) a change of control, as defined in the indenture governing the Debentures; (iv) satisfaction of certain trading price conditions; and (v) other specified corporate transactions described in the indenture governing the Debentures. In addition, the Debentures are convertible at any time after December 15, 2036 to December 15, 2041, the scheduled maturity date. In the case of conversion following a notice of redemption or upon a non-stock change of control, as defined in the indenture governing the Debentures, holders may convert their Debentures into cash in the amount of the principal amount of their Debentures and shares of the Company’s common stock for any conversion value in excess of the principal amount. In all other conversion circumstances, holders will receive perpetual preferred stock (see Note 16) with a liquidation preference equal to the principal amount of their Debentures, and any conversion value in excess of the principal amount will be settled with the Company’s common stock. As a result of the Patriot spin-off, the conversion rate was adjusted. The current conversion rate is 17.1125 shares of common stock per $1,000 principal amount of Debentures effective November 23, 2007. This adjusted conversion rate represents a conversion price of approximately $58.44.

The Debentures are not subject to redemption prior to December 20, 2011. Between December 20, 2011 and December 19, 2036 the Company may redeem the Debentures, in whole or in part, if for at least 20 out of the 30 consecutive trading days immediately prior to the date on which notice of redemption is given, the Company’s closing common stock price has exceeded 130% of the then applicable conversion price for the Debentures. On or after December 20, 2036, whether or not the redemption condition is satisfied, the Company may redeem the Debentures, in whole or in part. The Company may not redeem any Debentures unless (i) all accrued and unpaid interest on the Debentures has been paid in full on or prior to the redemption date and (ii) if any perpetual preferred stock is outstanding, the Company has first given notice to redeem the perpetual preferred stock in the same proportion as the redemption of the Debentures. Any redemption of the Debentures will be at a cash redemption price of 100% of the principal amount of the Debentures to be redeemed, plus accrued and unpaid interest to the date of redemption. As of December 31, 2008, the if-converted value did not exceed its principal amount.

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

F-31

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

In connection with the issuance of the Debentures, the Company entered into a Capital Replacement Covenant (the CRC). Pursuant to the CRC, the Company covenanted for the benefit of holders of covered debt, as defined in the CRC (currently the Company’s 7.875% Senior Notes due 2026, issued in the aggregate principal amount of $250.0 million), that neither the Company nor any of its subsidiaries shall repay, redeem or repurchase all or any part of the Debentures on or after December 15, 2041 and prior to December 15, 2046, except to the extent that the total repayment, redemption or repurchase price does not exceed the sum of: (i) 400% of the Company’s net cash proceeds from the sale of its common stock and rights to acquire its common stock (including common stock issued pursuant to the Company’s dividend reinvestment plan or employee benefit plans); (ii) the Company’s net cash proceeds from the sale of its mandatorily convertible preferred stock, as defined in the CRC, or debt exchangeable for equity, as defined in the CRC; and (iii) the Company’s net cash proceeds from the sale of other replacement capital securities, as defined in the CRC, in each case, during the six months prior to the notice date for the relevant payment, redemption or repurchase.

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

The application of FSP APB 14-1 on a retrospective basis is discussed in Note 1.

7.375% Senior Notes Due November 2016 and 7.875% Senior Notes Due November 2026

As of December 31, 2008, the Company had $650.0 million of 7.375% 10-year Senior Notes outstanding, which are due 2016 and $250.0 million of 7.875% 20-year Senior Notes outstanding, which are due 2026. The notes are general unsecured obligations of the Company and rank senior in right of payment to any subordinated indebtedness of the Company; equally in right of payment with any senior indebtedness of the Company; effectively junior in right of payment to the Company’s existing and future secured indebtedness, to the extent of the value of the collateral securing that indebtedness; and effectively junior to all the indebtedness and other liabilities of the Company’s subsidiaries that do not guarantee the notes. Interest payments are scheduled to occur on May 1 and November 1 of each year. The first interest payment occurred on May 1, 2007.

The notes are guaranteed by the Company’s Subsidiary Guarantors, as defined in the note indenture. The note indenture contains covenants that, among other things, limit the Company’s ability to create liens and enter into sale and lease-back transactions. The notes are redeemable at a redemption price equal to 100% of the principal amount of the notes being redeemed plus a make-whole premium, if applicable, and any accrued unpaid interest to the redemption date. Net proceeds from the offering, after deducting underwriting discounts and expenses, were $886.1 million.

6.875% Senior Notes Due March 2013

At December 31, 2008, the Company had $650.0 million of 6.875% Senior Notes outstanding, which are due March 2013. The notes are senior unsecured obligations of the Company and rank equally with all of the Company’s other senior unsecured indebtedness. Interest payments are scheduled to occur on March 15 and September 15 of each year. The notes are guaranteed by the Company’s Subsidiary Guarantors as defined in the note indenture. The note indenture contains covenants which, among other things, limit the Company’s ability to incur additional indebtedness and issue preferred stock, pay dividends or make other distributions, make other restricted payments and investments, create liens, sell assets and merge or consolidate with other entities. The notes are redeemable at fixed redemption prices as set forth in the indenture.

F-32

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

5.875% Senior Notes Due March 2016

As of December 31, 2008, the Company had $218.1 million of 5.875% Senior Notes outstanding, which are due March 2016. The notes are senior unsecured obligations of the Company and rank equally with all of the Company’s other senior unsecured indebtedness. Interest payments are scheduled to occur on April 15 and October 15 of each year, and commenced on April 15, 2004. The notes are guaranteed by the Company’s Subsidiary Guarantors as defined in the note indenture. The note indenture contains covenants which, among other things, limit the Company’s ability to incur additional indebtedness and issue preferred stock, pay dividends or make other distributions, make other restricted payments and investments, create liens, sell assets and merge or consolidate with other entities. The notes are redeemable prior to April 15, 2009, at a redemption price equal to 100% of the principal amount plus a make-whole premium (as defined in the indenture) and on or after April 15, 2009, at fixed redemption prices as set forth in the indenture. Net proceeds from the offering, after deducting underwriting discounts and expenses, were $244.7 million.

Series Bonds

As of December 31, 2008, the Company had $71.0 million in Series Bonds outstanding, which were assumed as part of the Excel acquisition. The 6.84% Series A Bonds have a balloon maturity in December 2014. The 6.34% Series B Bonds mature in December 2014 and are payable in installments with the first scheduled payment made in December 2008. The 6.84% Series C Bonds mature in December 2016 and are payable in installments beginning December 2012. Interest payments are scheduled to occur in June and December of each year.

Interest Rate Swaps

As of December 31, 2008, the Company had a series of fixed-to-floating and floating-to-fixed interest rate swaps. The following table details the swaps:


	Notional				Termination		Fair
	Amount		Benefit Received	Amount Paid	Date		Value
	(Dollars in millions)
Fixed to Floating
6 7/8 $650M Senior Notes	$	120.0	6.875% semi-annually	3M LIBOR + 196.9 bps quarterly		3/15/2013	$	6.0
6 7/8 $650M Senior Notes	$	25.0	6.875% semi-annually	6M LIBOR + 299.75 bps semi-annually		3/15/2013	$	0.8
6 7/8 $650M Senior Notes	$	25.0	6.875% semi-annually	6M LIBOR + 307 bps semi-annually		3/15/2013	$	0.8
6 7/8 $650M Senior Notes	$	25.0	6.875% semi-annually	6M LIBOR + 316 bps semi-annually		3/15/2013	$	(0.5	)
6 7/8 $650M Senior Notes	$	25.0	6.875% semi-annually	6M LIBOR + 307.5 bps semi-annually		3/15/2013	$	0.8
5 7/8 $250M Senior Note	$	100.0	5.875% semi-annually	6M LIBOR + 25.3 bps semi-annually		4/15/2016	$	4.6
Floating to Fixed
Senior Unsecured Term Loan A	$	120.0	3M LIBOR + 100 bps quarterly	6.25% semi-annually		9/15/2011	$	(12.8	)
Shovel Construction Financing	$	22.0	3M LIBOR quarterly	4.812% semi-annually		7/1/2014	$	(4.0	)
Shovel Construction Financing	$	22.0	3M LIBOR quarterly	4.6525% semi-annually		8/26/2014	$	(2.5	)
Shovel Construction Financing	$	22.0	3M LIBOR quarterly	4.758% semi-annually		12/29/2014	$	(2.5	)


Legend: M = millions; bps = basis points

In addition, the Company had three additional swaps, with a combined notional amount of $200.0 million that were terminated during the first half of 2008. The combined settlement amount of $6.9 million was recorded as an adjustment to the fair value hedge adjustment and will be amortized to interest expense over the remaining maturity period of the 6.875% Senior Notes.

Because the critical terms of the swaps and the respective debt instruments they hedge coincide, there was no hedge ineffectiveness recognized in the consolidated statements of operations during the years ended December 31, 2008 and 2007. At December 31, 2007 there was a net unrealized gain on the fair value hedges of $1.6 million. The fair value hedge is reflected as an adjustment to the carrying value of the Senior Notes.

F-33

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

Capital Lease Obligations and Other

Capital lease obligations include obligations assumed from the Excel acquisition, primarily for mining equipment (see Note 9 for additional information on the Company’s capital lease obligations).

Other long-term debt, which consists principally of notes payable, is due in installments through 2016. The weighted-average effective interest rate of this debt was 5.59% as of December 31, 2008.

The aggregate amounts of long-term debt maturities subsequent to December 31, 2008, including capital lease obligations, were as follows (Dollars in millions):


Year of Maturity
2009	$	17.0
2010		14.2
2011		505.0
2012		23.9
2013		706.6
2014 and thereafter		1,526.9

Total	$	2,793.6

Interest paid on long-term debt was $226.0 million, $191.9 million and $114.6 million for the years ended December 31, 2008, 2007 and 2006, respectively. The Company paid interest expense of $5.8 million, $1.5 million and $3.3 million on the Revolver in 2008, 2007 and 2006.

Shelf Registration Statement

On July 28, 2006, the Company filed an automatic shelf registration statement on Form S-3 as a well-known seasoned issuer with the Securities and Exchange Commission. The registration was for an indeterminate number of securities and is effective for three years, at which time the Company expects to be able to file an automatic shelf registration statement that would become immediately effective for another three-year term. Under this universal shelf registration statement, the Company has the capacity to offer and sell from time to time securities, including common stock, preferred stock, debt securities, warrants and units. The Debentures, 7.375% Senior Notes due 2016 and 7.875% Senior Notes due 2026 were issued pursuant to the shelf registration statement.

F-34

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

(13) Asset Retirement Obligations

Reconciliations of the Company’s asset retirement obligation liability are as follows:


	December 31,
	2008			2007
	(Dollars in millions)
Balance at beginning of year, including discontinued operations	$	362.8		$	418.8
Liabilities incurred or acquired		—			27.0
Liabilities settled or disposed		(6.4	)		(16.2	)
Accretion expense		20.5			27.5
Revisions to estimates		45.7			29.6

Consolidated asset retirement obligations		422.6			486.7
Liabilities related to the Patriot spin-off		—			(123.9	)

Balance at end of year	$	422.6		$	362.8


Balance at end of year — active locations	$	387.2		$	331.9

Balance at end of year — closed or inactive locations	$	35.4		$	30.9

The credit-adjusted, risk-free interest rates were 7.91% at December 31, 2008 and 7.85% and 6.60% at January 1, 2008 and 2007, respectively.

As of December 31, 2008 and 2007, the Company had $740.6 million and $418.3 million, respectively, in surety bonds outstanding to secure reclamation obligations or activities. The amount of reclamation self-bonding in certain states in which the Company qualifies was $773.4 million and $640.6 million as of December 31, 2008 and 2007, respectively. Additionally, the Company had $0.1 million and $1.6 million of letters of credit in support of reclamation obligations or activities as of December 31, 2008 and 2007, respectively.

(14) Pension and Savings Plans

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

During the period ended March 31, 1999, the Company made an amendment to phase out the Peabody Plan. Effective January 1, 2001, certain employees no longer accrue future service under the plan while other employees accrue reduced service under the plan based on their age and years of service as of December 31, 2000. For plan benefit calculation purposes, employee earnings are also frozen as of December 31, 2000. The Company has adopted an enhanced savings plan contribution structure in lieu of benefits formerly accrued under the defined benefit pension plan.

Annual contributions to the plans are made as determined by consulting actuaries based upon the Employee Retirement Income Security Act of 1974 minimum funding standard. In May 1998, the Company entered into an agreement with the Pension Benefit Guaranty Corporation (PBGC) which requires the Company to maintain certain minimum funding requirements. Beginning on January 1, 2008, new minimum funding standards were required by the Pension Protection Act of 2006. Assets of the plans are primarily invested in various marketable securities, including U.S. government bonds, corporate obligations and listed stocks.

F-35

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

Net periodic pension costs included the following components:


	Year Ended December 31,
	2008			2007			2006
	(Dollars in millions)
Service cost for benefits earned	$	2.0		$	12.7		$	12.2
Interest cost on projected benefit obligation		51.0			49.0			46.0
Expected return on plan assets		(60.6	)		(57.4	)		(54.6	)
Amortization of prior service cost		1.3			0.4			—
Amortization of actuarial (gains) losses		(0.5	)		15.3			22.7

Net periodic pension costs		(6.8	)		20.0			26.3
Curtailment gain		(0.6	)		(0.4	)		—

Total net periodic pension (benefit) cost	$	(7.4	)	$	19.6		$	26.3

In 2007, benefits were frozen for certain participants of the Company’s Western U.S. Mining operations and those participants impacted by the Patriot spin-off under the Peabody Plan resulting in actuarially determined curtailment gains of $0.6 million and $0.4 million for the years ended December 31, 2008 and 2007, respectively.

The following includes amounts recognized in accumulated other comprehensive income:


	Year Ended
	December 31, 2008
	(Dollars in millions)
Net actuarial loss arising during year	$	199.2
Amortizations:
Actuarial gain		0.5
Prior service cost/curtailment		(0.7	)

Total recognized in other comprehensive income		199.0
Net periodic pension costs		(6.8	)

Total recognized in net periodic pension costs and other comprehensive income	$	192.2

The Company amortizes actuarial gains and losses using a 5% corridor with a five-year amortization period. The estimated net actuarial gain and prior service cost that will be amortized from accumulated other comprehensive income (loss) into net periodic pension costs during the year ended December 31, 2009 are $1.7 million and $1.4 million, respectively.

F-36

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

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


	December 31,
	2008			2007
	(Dollars in millions)
Change in benefit obligation:
Projected benefit obligation at beginning of period	$	778.2		$	832.8
Service cost		2.0			12.7
Interest cost		51.0			49.0
Plan amendments		—			7.9
Curtailments		—			(20.5	)
Benefits paid		(46.7	)		(42.6	)
Actuarial gain		(15.9	)		(61.1	)

Projected benefit obligation at end of period		768.6			778.2


Change in plan assets:
Fair value of plan assets at beginning of period		732.4			704.2
Actual return on plan assets		(154.4	)		65.4
Employer contributions		21.3			5.4
Benefits paid		(46.7	)		(42.6	)

Fair value of plan assets at end of period		552.6			732.4

Funded status at end of year	$	(216.0	)	$	(45.8	)

Amounts recognized in the consolidated balance sheets:
Intangible asset (included in Investments and other assets)	$	—		$	0.2
Current obligation (included in Accounts payable and accrued expenses)		(1.6	)		(1.3	)
Noncurrent obligation (included in Other noncurrent liabilities)		(214.4	)		(44.7	)

Net amount recognized	$	(216.0	)	$	(45.8	)

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


	Year Ended December 31,
	2008			2007
Discount rate		6.90	%		6.75	%
Rate of compensation increase		N/A			N/A
Measurement date	December 31, 2008			December 31, 2007

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


	Year Ended December 31,
	2008			2007			2006
Discount rate		6.75	%		6.00	%		5.90	%
Expected long-term return on plan assets		8.75	%		8.75	%		8.75	%
Rate of compensation increase		N/A			3.50	%		3.50	%
Measurement date	December 31, 2007			December 31, 2006			December 31, 2005

F-37

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

The expected rate of return on plan assets is determined by taking into consideration expected long-term returns associated with each major asset class (net of inflation) based on long-term historical ranges, inflation assumptions and the expected net value from active management of the assets based on actual results.

The projected benefit obligation and the accumulated benefit obligation exceeded plan assets for all plans as of December 31, 2008 and 2007. The accumulated benefit obligation for all pension plans was $768.6 million and $681.1 million as of December 31, 2008, and 2007, respectively.

Plan Assets

Assets of the Peabody Plan and the Western Plan are commingled in the Peabody Investment Corporation Master Trust (the Master Trust) and are invested in accordance with investment guidelines that have been established by the Company’s Retirement Committee (the Retirement Committee) after consultation with outside investment advisors and actuaries.

Master Trust assets totaled $552.6 million at December 31, 2008 and $732.4 million at December 31, 2007 and were invested in the following major asset categories:


	December 31, 2008						December 31, 2007
	Percentage						Percentage
	Allocation of			Target			Allocation of Total			Target
	Total Assets			Allocation			Assets			Allocation
Equity securities		32.6	%		40.0	%		38.5	%		40.0	%
Fixed income		43.2	%		35.0	%		36.6	%		35.0	%
International equity		12.8	%		15.0	%		15.5	%		15.0	%
Real estate		11.4	%		10.0	%		9.4	%		10.0	%

Total		100.0	%		100.0	%		100.0	%		100.0	%

The asset allocation targets have been set with the expectation that the plan’s assets will fund the plan’s expected liabilities with an appropriate level of risk. To determine the appropriate target asset allocations, the Retirement Committee considers the demographics of the plan participants, the funding status of the plan, the business and financial profile of the Company and other associated risk preferences. These allocation targets are reviewed by the Retirement Committee on a regular basis and revised as necessary. Periodically, assets are rebalanced among major asset categories. During 2008, management allocated a substantial amount of Master Trust assets to fixed income securities to reduce exposure to variability in light of current economic conditions. However, management and the Retirement Committee believes this to be a temporary measure and the Company is currently reevaluating its target allocations.

Plan assets are either under active management by third-party investment advisors or in index funds, all selected and monitored by the Retirement Committee. The Retirement Committee has established specific investment guidelines for each major asset class including performance benchmarks, allowable and prohibited investment types and concentration limits. In general, the plan investment guidelines do not permit leveraging the Master Trust’s assets. Equity investment guidelines do not permit entering into put or call options (except as deemed appropriate to manage currency risk), and futures contracts are permitted only to the extent necessary to equitize cash holdings.

Contributions

The Pension Protection Act of 2006 (the Pension Protection Act), which was effective January 1, 2008, increased the long-term funding targets for single employer pension plans from 90% to 100%. In addition, the Pension Protection Act restricts “at risk” (generally defined as under 80% funded) plans from making lump sum payments and increasing benefits unless they are funded immediately, and also requires that the plan give participants notice regarding the at-risk status of the plan. If a plan falls below 60%, lump sum payments are prohibited and benefit accruals cease.

F-38

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

As of December 31, 2008, the Company’s pension plans were approximately 68% funded, before considering planned 2009 contributions. The Company’s minimum funding requirement for 2009 is approximately $25 million, and would result in a funded status above 70%.

Estimated Future Benefit Payments

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


	Pension Benefits
	(Dollars in millions)
2009	$	48.0
2010		49.6
2011		51.6
2012		53.5
2013		55.6
Years 2014-2018		314.0

Defined Contribution Plans

The Company sponsors employee retirement accounts under three 401(k) plans for eligible salaried U.S. employees. The Company matches voluntary contributions to each plan up to specified levels. The expense for these plans was $50.5 million, $21.7 million and $12.7 million for the years ended December 31, 2008, 2007 and 2006, respectively. A performance contribution feature allows for additional contributions from the Company based upon meeting specified Company performance targets. Performance contributions related to the years ended December 31, 2008, 2007, and 2006 were $18.7 million, $4.9 million and $7.3 million, respectively.

Multi-Employer Pension Plan — Discontinued Operations

Certain subsidiaries that were part of the Patriot spin-off participate in multi-employer pension plans (the 1950 Plan and the 1974 Plan), which provide defined benefits to substantially all hourly coal production workers represented by the UMWA under the 2007 NBCWA. During 2007, contributions of $5.9 million made to the 1974 Plan were expensed as paid, and are reflected in “Discontinued operations.” There were no contributions to the multi-employer pension plans during the years ended December 31, 2008 or 2006.

(15) Postretirement Health Care and Life Insurance Benefits

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

Net periodic postretirement benefit costs included the following components:


	Year Ended December 31,
	2008		2007			2006
	(Dollars in millions)
Service cost for benefits earned	$	10.1	$	9.4		$	7.6
Interest cost on accumulated postretirement benefit obligation		54.0		50.6			43.5
Amortization of prior service cost		0.4		(0.2	)		(2.2	)
Amortization of actuarial losses		17.3		22.8			18.1

Net periodic postretirement benefit costs	$	81.8	$	82.6		$	67.0

F-39

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

Net periodic postretirement benefit costs related to the spin-off of Patriot for the years ended December 31, 2007 and 2006, were $46.6 million and $41.4 million, respectively, and were included in “Discontinued operations.” The Company amortizes actuarial gains and losses using a 0% corridor with an amortization period that covers the average remaining service period of active employees (10.68 years and 8.92 years at January 1, 2008 and 2007, respectively).

The following includes amounts recognized in accumulated other comprehensive income:


	Year Ended
	December 31, 2008
	(Dollars in millions)
Net actuarial gain arising during year	$	(18.3	)
Amortizations:
Actuarial loss		(17.3	)
Prior service cost		(0.4	)

Total recognized in other comprehensive income		(36.0	)
Net periodic postretirement benefit costs		81.8

Total recognized in net periodic postretirement benefit costs and other comprehensive income	$	45.8

The estimated net actuarial loss and prior service cost that will be amortized from accumulated other comprehensive income (loss) into net periodic postretirement benefit costs during the year ended December 31, 2009 are $14.0 million and $1.5 million, respectively.

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


	December 31,
	2008			2007
	(Dollars in millions)
Change in benefit obligation:
Accumulated postretirement benefit obligation at beginning of period	$	855.8		$	872.7
Service cost		10.1			9.4
Interest cost		54.0			50.6
Participant contributions		1.5			0.9
Plan amendments		—			13.9
Benefits paid		(69.7	)		(67.2	)
Actuarial gain		(18.3	)		(24.5	)


Accumulated postretirement benefit obligation at end of period		833.4			855.8

Change in plan assets:
Fair value of plan assets at beginning of period		—			—
Employer contributions		68.2			66.3
Participant contributions		1.5			0.9
Benefits paid and administrative fees (net of Medicare Part D reimbursements)		(69.7	)		(67.2	)

Fair value of plan assets at end of period		—			—

Funded status at end of year		(833.4	)		(855.8	)
Less current portion (included in Accounts payable and accrued expenses)		67.3			70.1

Noncurrent obligation (included in Accrued postretirement benefit costs)	$	(766.1	)	$	(785.7	)

F-40

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

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


	Year Ended December 31,
	2008			2007
Discount rate		6.85	%		6.60	%
Rate of compensation increase		3.50	%		3.50	%
Measurement date	December 31, 2008			December 31, 2007

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


	Year Ended December 31,
	2008			2007			2006
Discount rate		6.60	%		6.00	%		5.90	%
Rate of compensation increase		3.50	%		3.50	%		3.50	%
Measurement date	December 31, 2007			December 31, 2006			December 31, 2005

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


	Year Ended December 31,
	2008			2007
Health care cost trend rate assumed for next year		7.50	%		7.50	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)		4.75	%		4.75	%
Year that the rate reaches the ultimate trend rate		2014			2013

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


	One Percentage-		One Percentage-
	Point Increase		Point Decrease
	(Dollars in millions)
Effect on total service and interest cost components	$	6.6	$	(5.7	)
Effect on total postretirement benefit obligation	$	79.7	$	(68.5	)

Plan Assets

The Company’s postretirement benefit plans are unfunded.

F-41

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

Estimated Future Benefit Payments

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


	Postretirement
	Benefits
	(Dollars in millions)
2009	$	67.3
2010		68.9
2011		71.3
2012		74.1
2013		74.8
Years 2014-2018		373.9

Medicare

On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) was signed into law. The Company elected not to defer the effects of the Act as discussed in FSP 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” which was superseded by FSP 106-2. Additionally, the Company did not elect the federal subsidy provisions of the Act; rather the Company coordinated benefits with available Medicare coverage considered the primary payer, whether or not the beneficiary enrolled and paid the required premiums.

The Company recognized a reduction in the benefit obligation on two distinct components. For plans that required amendment to incorporate the Act, the Company recognized a liability reduction of $19.1 million. This reduction was treated as a negative plan amendment and is being amortized to income over six years beginning December 15, 2003. For plans that did not require amendment, the Company recognized a liability reduction of $162.4 million. The reduction was treated as a change in the estimated cost to provide benefits to Medicare eligible beneficiaries constituting a component of the cumulative actuarial gain or loss subject to amortization in accordance with the Company’s amortization method.

Multi-Employer Benefit Plans — Discontinued Operations

Multi-employer benefit obligations related to the Combined Fund, the 1992 Benefit Plan and 1993 Benefit Plan became the responsibility of Patriot in conjunction with the spin-off. The Surface Mining Control and Reclamation Act Amendments of 2006 amended the federal laws establishing the Combined Fund and the 1992 Benefit Plan and include the 1993 Benefit Plan. To the extent that (i) the annual federal funding exceeds a specified amount, (ii) Congress does not allocate additional funds to cover the shortfall and (iii) Patriot’s subsidiaries do not pay for their share of the shortfall, some of the Company’s subsidiaries would be responsible for the additional costs.

The total expense for the Combined Fund, the 1992 Benefit Plan and 1993 Benefit Plan was $14.5 million and $8.2 million for the years ended December 31, 2007 and 2006, respectively, and was included in “Discontinued operations.”

Pursuant to the provisions of the Coal Act and the 1992 Benefit Plan, the Company was required to provide a specified amount of security. In accordance with the 1992 Benefit Plan, the Company had outstanding letters of credit of $41.4 million as of October 31, 2007 and $119.4 million as of December 31, 2006, to secure the Company’s obligation.

F-42

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

(16) Stockholders’ Equity

Common Stock

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

Effective February 22, 2006, the Company implemented a two-for-one stock split on all shares of its common stock. The Company had a similar two-for-one stock split on March 30, 2005. All share and per share amounts in these consolidated financial statements and related notes reflect the stock splits.

The following table summarizes common stock activity from December 31, 2005 to December 31, 2008:


	Shares
	Outstanding
December 31, 2005		263,357,402
Stock options exercised		1,940,539
Stock grants to employees		566,631
Employee stock purchases		156,785
Stock grants to non-employee directors		10,440
Shares repurchased		(2,184,958	)

December 31, 2006		263,846,839
Stock options exercised		5,222,074
Stock grants to employees		937,795
Employee stock purchases		185,646
Stock grants to non-employee directors		11,892
Shares relinquished		(137,625	)

December 31, 2007		270,066,621
Stock options exercised		1,388,174
Stock grants to employees		788,895
Employee stock purchases		119,737
Stock grants to non-employee directors		2,870
Shares repurchased		(5,524,574	)
Shares relinquished		(196,744	)

December 31, 2008		266,644,979

F-43

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

Preferred Stock and Series Common Stock

In addition to the common stock, the Board of Directors is authorized to issue up to 10.0 million shares of preferred stock and up to 40.0 million shares of series common stock. The Board of Directors is authorized to determine the terms and rights of each series, including the number of authorized shares, whether dividends (if any) will be cumulative or non-cumulative and the dividend rate of the series, redemption or sinking fund provisions, conversion terms, prices and rates, and amounts payable on shares of the series in the event of any voluntary or involuntary liquidation, dissolution or winding up of the affairs of the Company. The Board of Directors may also determine restrictions on the issuance of shares of the same series or of any other class or series, and the voting rights (if any) of the holders of the series. There were no outstanding shares of preferred stock or series common stock as of December 31, 2008.

Perpetual Preferred Stock

As discussed in Note 12, the Company had $732.5 million aggregate principal amount of Debentures outstanding as of December 31, 2008. Perpetual preferred stock issued upon a conversion of the Debentures will be fully paid and non-assessable, and holders will have no preemptive or preferential right to purchase any of the Company’s other securities. The perpetual preferred stock has a liquidation preference of $1,000 per share, is not convertible and is redeemable at the Company’s option at any time at a cash redemption price per share equal to the liquidation preference plus any accumulated dividends. Holders are entitled to receive cumulative dividends at an annual rate of 3.0875% if and when declared by the Company’s Board of Directors. If the Company fails to pay dividends on the perpetual preferred stock for five years, or upon the occurrence of a mandatory trigger event, as defined in the certificate of designations governing the perpetual preferred stock, the Company generally must sell warrants or preferred stock with specified characteristics and use the funds from that sale to pay accumulated dividends after the payment in full of any deferred interest on the Debentures, subject to certain limitations. In the event of a mandatory trigger event, the Company may not declare dividends on the perpetual preferred stock other than those funded through the sale of warrants or preferred stock as described above. Any deferred interest on the Debentures at the time of notice of conversion will be reflected as accumulated dividends on the perpetual preferred stock at issuance. Additionally, holders of the perpetual preferred stock are entitled to elect two additional members to serve on the Company’s Board of Directors if (i) prior to any remarketing of the perpetual preferred stock, the Company fails to declare and pay dividends with respect to the perpetual stock for 10 consecutive years or (ii) after any successful remarketing or any final failed remarketing of the perpetual preferred stock, the Company fails to declare and pay six dividends thereon, whether or not consecutive. The perpetual preferred stock may be remarketed at the holder’s election after December 15, 2046 or earlier, upon the first occurrence of a change of control if the Company does not redeem the perpetual preferred stock. There were no outstanding shares of perpetual preferred stock as of December 31, 2008.

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

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

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

Each Right entitles the holder to purchase one quarter of one-hundredth of a share of series A junior participating preferred stock from the Company at an exercise price of $27.50, which in turn provides rights to receive the number of common stock shares having a market value of two times the exercise price of the Right. The Right is exercisable only if a person or group acquires 15% or more of the Company’s common stock. The Board of Directors is authorized to issue up to 1.5 million shares of series A junior participating preferred stock. There were no outstanding shares of series A junior participating preferred stock as of December 31, 2008.

F-44

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

Treasury Stock

In July 2005, the Company’s Board of Directors authorized a share repurchase program of up to 5% of the then outstanding shares of its common stock, or approximately 13 million shares. The repurchases may be made from time to time based on an evaluation of the Company’s outlook and general business conditions, as well as alternative investment and debt repayment options. In addition, the Company’s Board of Directors had previously authorized the Company’s Chairman and Chief Executive Officer to repurchase up to $100 million of the Company’s common stock outside the share repurchase program. In October 2008, the Company’s Board of Directors amended the share repurchase program to increase the total authorized amount to $1 billion. The amended repurchase program does not have an expiration date and may be discontinued at any time. During the year ended December 31, 2008, the Company repurchased 5.5 million of its common shares at a cost of $199.8 million. During the year ended December 31, 2006, the Company repurchased 2.2 million of its common shares at a cost of $99.8 million. There were no share repurchases under this program for the year ended December 31, 2007.

During the year ended December 31, 2008, the Company received 196,744 shares of common stock as consideration for employees’ exercise of stock options and to pay estimated taxes at the vesting date of restricted stock. The value of the common stock tendered by employees to exercise stock options and to settle taxes on restricted stock was based upon the closing price on the dates of the respective transactions. The common stock tenders were in accordance with the provisions of the 1998 Stock Purchase and Option Plan, which was previously approved by the Company’s Board of Directors.

(17) Share-Based Compensation

The Company recognizes share-based compensation expense in accordance with SFAS No. 123(R), which it adopted on January 1, 2006, and utilizes restricted stock, nonqualified stock options, performance units, and an employee stock purchase plan as part of its share-based compensation program. The Company has four equity incentive plans for employees and non-employee directors that in the aggregate allow for the issuance of share-based compensation in the form of stock appreciation rights, restricted stock, performance awards, incentive stock options, nonqualified stock options and stock units. Members of the Company’s Board of Directors are eligible for stock option and restricted stock grants at the date of their election and annually in January. These plans made 47.4 million shares of the Company’s common stock available for grant, with 16.2 million shares available for grant as of December 31, 2008. Additionally, in 2001, the Company established an employee stock purchase plan that provided for the purchase of up to 6.0 million shares of the Company’s common stock. In 2008, the Company amended the employee stock purchase plan and reduced the number of shares authorized for purchase under the plan to 5.0 million shares. The 1.0 million shares were allocated from this plan to create a new employee stock purchase plan for the Company’s Australian employees.

For share-based payment instruments excluding restricted stock, the Company recognized $11.1 million (or $0.04 per diluted share), $6.6 million (or $0.02 per diluted share) and $17.7 million (or $0.07 per diluted share) of expense, net of taxes, for the years ended December 31, 2008, 2007 and 2006, respectively. Share-based compensation expense is recorded in “Selling and administrative expenses” in the consolidated statements of operations. As of December 31, 2008, the total unrecognized compensation cost related to nonvested awards was $27.8 million, net of taxes, which is expected to be recognized over 4.2 years with a weighted-average period of 0.9 years.

The Company used the Black-Scholes option pricing model to determine the fair value of stock options and employee stock purchase plan share-based payments made before and after the adoption of SFAS No. 123(R). The Company utilized U.S. Treasury yields as of the grant date for its risk-free interest rate assumption, matching the treasury yield terms to the expected life of the option or vesting period of the performance unit awards. The Company utilized historical company data to develop its dividend yield, expected volatility and expected option life assumptions.

Restricted Stock Awards

The Company began utilizing restricted stock as part of its equity-based compensation strategy in January 2005. Accounting for restricted stock awards was not changed by the adoption of SFAS No. 123(R). The Company recognized $10.3 million, $10.6 million and $4.2 million of expense, net of taxes, for the years ended December 31, 2008, 2007 and 2006, respectively, related to restricted stock.

F-45

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

A summary of restricted stock award activity is as follows:


				Weighted
	Year Ended			Average
	December 31,			Grant-Date
	2008			Fair Value
Nonvested at January 1, 2008		1,532,859		$	36.01
Granted		434,137			46.94
Vested		(68,184	)		41.79
Forfeited		(110,479	)		41.05

Nonvested at December 31, 2008		1,788,333		$	38.13

Stock Options

Employee and director stock options granted since the Company’s initial public offering (IPO) of common stock in May 2001 generally vest ratably over three years and expire after 10 years from the date of the grant, subject to earlier termination upon discontinuation of an employee’s service. Options granted prior to the IPO generally cliff vest in 2010 and represented 0.9 million options of the 3.3 million options outstanding at December 31, 2008. Option grants are typically made in January of each year or following the inception of employment for employees hired during the year who are eligible to participate in the plan. The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model. The Company recognized expense, net of taxes, of $4.0 million, $3.7 million and $4.7 million for the years ended December 31, 2008, 2007 and 2006, respectively, related to stock option grants to employees and non-employee directors.

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


						Weighted
				Weighted		Average		Aggregate
	Year Ended			Average		Remaining		Intrinsic
	December 31,			Exercise		Contractual		Value (in
	2008			Price		Life		millions)

Beginning balance		4,804,934		$	12.46
Granted		289,300			64.31
Exercised		(1,388,174	)		10.16
Forfeited		(455,203	)		13.95

Outstanding		3,250,857		$	17.84		4.7	$	36.4

Vested and Exercisable		1,636,390		$	13.09		4.9	$	19.0

During the years ended December 31, 2008, 2007 and 2006, the total intrinsic value of options exercised, defined as the excess fair value of the underlying stock over the exercise price of the options, was $72.8 million, $248.7 million and $84.2 million, respectively. The weighted-average fair values of the Company’s stock options and the assumptions used in applying the Black-Scholes option pricing model (for grants during the years ended December 31, 2008, 2007 and 2006) were as follows:


	December 31,
	2008			2007			2006
Weighted-average fair value	$	64.31		$	37.93		$	16.52
Risk-free interest rate		3.3	%		4.6	%		4.3	%
Expected option life	5.0 years			5.0 years			6.0 years
Expected volatility		40	%		43	%		36	%
Dividend yield		0.5	%		0.6	%		0.8	%

F-46

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

Performance Units

Performance units, which are typically granted annually in January, vest over a three-year measurement period subject to the achievement of performance goals and relative stock price performance at the conclusion of the vesting term. Three performance unit grants were outstanding during 2008 (the 2006, 2007 and 2008 grants), 2007 (the 2005, 2006 and 2007 grants) and 2006 (the 2004, 2005 and 2006 grants). The payouts related to all active grants will be settled in the Company’s common stock. Payouts for the 2004 through 2007 grants are based 50% on stock price performance compared to both an industry peer group and a S&P index (a “market condition” under SFAS No. 123(R)) and 50% on a return on capital target (a “performance condition” under SFAS No. 123(R)). The Company granted 0.1 million performance units during the year ended December 31, 2008 and 0.2 million performance units in each of the years ended December 31, 2007 and 2006.

A summary of performance unit activity is as follows:


				Weighted
				Average
	Year Ended			Remaining
	December 31,			Contractual
	2008			Life

Nonvested at January 1, 2008		345,708			1.5
Granted		129,191
Forfeited		(68,806	)
Vested		(155,402	)

Nonvested at December 31, 2008		250,691			1.5

As of December 31, 2008, there were 155,402 performance units vested that had an aggregate intrinsic value of $3.2 million and a conversion price per share of $22.51.

Under SFAS No. 123(R), the awards settled are accounted for based on their grant date fair value. The performance condition awards were valued utilizing the grant date fair values of the Company’s stock adjusted for dividends foregone during the vesting period. The market condition awards were valued utilizing a Monte Carlo simulation which incorporates the total shareholder return hurdles set for each grant. The Company recognized expense, net of taxes, of $5.7 million, $1.6 million and $11.7 million for the years ended December 31, 2008, 2007 and 2006, respectively, related to performance units. The assumptions used in the valuations for grants during the years ended December 31, 2008 and 2007 were as follows:


	December 31,
	2008			2007

Risk-free interest rate		2.9	%		4.7	%
Expected volatility		40	%		43	%
Dividend yield		0.5	%		0.6	%

Employee Stock Purchase Plan

Based on the Company’s employee stock purchase plans, eligible full-time and part-time employees are able to contribute up to 15% of their base compensation into this plan, subject to a limit of $25,000 per person per year. Employees are able to purchase Company common stock at a 15% discount to the lower of the fair market value of the Company’s common stock on the initial or final trading dates of each six-month offering period. Offering periods begin on January 1 and July 1 of each year. The fair value of the six-month “look-back” option in the Company’s employee stock purchase plan is estimated by adding the fair value of 0.15 of one share of stock to the fair value of 0.85 of an option on one share of stock. The Company recognized expense, net of taxes, of $0.9 million for the year ended December 31, 2008 related to its employee stock purchase plan. Shares purchased under the plan were 0.1 million for the year ended December 31, 2008 and 0.2 million for each of the years ended December 31, 2007 and 2006.

F-47

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

(18) Accumulated Other Comprehensive Income (Loss)

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


						Net Actuarial
						Loss
						Associated with
						Postretirement			Prior Service						Total
	Foreign		Minimum			Plans and			Cost Associated						Accumulated
	Currency		Pension			Workers’			with						Other
	Translation		Liability			Compensation			Postretirement			Cash Flow			Comprehensive
	Adjustment		Adjustment			Obligations			Plans			Hedges			Loss
	(Dollars in millions)
December 31, 2005	$	3.1	$	(69.3	)	$	—		$	—		$	19.2		$	(47.0	)
Net increase in value of cash flow hedges		—		—			—			—			45.8			45.8
Reclassification from other comprehensive income to earnings:		—		—			—			—			(21.5	)		(21.5	)
Current period change		—		22.5			—			—			—			22.5
Adjustment to initially apply SFAS No. 158		—		46.8			(288.8	)		(7.0	)		—			(249.0	)

December 31, 2006		3.1		—			(288.8	)		(7.0	)		43.5			(249.2	)
Net increase in value of cash flow hedges		—		—			—			—			83.7			83.7
Reclassification from other comprehensive income to earnings:
Continuing operations		—		—			24.3			(0.1	)		(61.8	)		(37.6	)
Discontinued operations		—		—			17.9			(6.1	)		—			11.8
Current period change		—		—			64.2			(13.0	)		—			51.2
Patriot spin-off		—		—			65.7			7.3			—			73.0

December 31, 2007		3.1		—			(116.7	)		(18.9	)		65.4			(67.1	)
Net decrease in value of cash flow hedges		—		—			—			—			(194.5	)		(194.5	)
Reclassification from other comprehensive income to earnings:		—		—			14.1			0.2			(23.4	)		(9.1	)
Current period change		—		—			(117.8	)		—			—			(117.8	)

December 31, 2008	$	3.1	$	—		$	(220.4	)	$	(18.7	)	$	(152.5	)	$	(388.5	)

Comprehensive income differs from net income by the amount of unrealized gain or loss resulting from valuation changes of the Company’s cash flow hedges (which include fuel and explosives hedges, currency forwards, traded coal index contracts and interest rate swaps) during the periods and the amortization of actuarial loss and prior service cost for the years ended December 31, 2008 and 2007. The values of the Company’s cash flow hedging instruments are affected by changes in interest rates, crude oil, diesel fuel, natural gas and coal prices and the U.S. dollar/Australian dollar exchange rate. The decline in value of these instruments during 2008 was due to significant price decline in crude oil, diesel fuel, natural gas and coal, and the weakening of the Australian dollar against the U.S. dollar.

(19) Guarantees and Financial Instruments 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, such as bank letters of credit, performance or surety bonds and other guarantees and indemnities, which are not reflected in the accompanying consolidated balance sheets. Such financial instruments are valued based on the amount of exposure under the instrument and the likelihood of required performance. In the Company’s past experience, virtually no claims have been made against these financial instruments. Management does not expect any material losses to result from these guarantees or off-balance-sheet instruments.

F-48

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

Letters of Credit and Bonding

The Company has letters of credit, surety bonds and corporate guarantees (such as self bonds) in support of the Company’s reclamation, coal lease obligations, and workers’ compensation as follows as of December 31, 2008:


					Workers’
	Reclamation		Lease		Compensation
	Obligations		Obligations		Obligations		Other ⁽¹⁾		Total
					(Dollars in millions)
Self Bonding	$	773.4	$	—	$	—	$	—	$	773.4
Surety Bonds		740.6		99.2		19.3		15.2		874.3
Letters of Credit		0.1		—		54.9		199.3		254.3


	$	1,514.1	$	99.2	$	74.2	$	214.5	$	1,902.0


(1)		Other includes the four letter of credit obligations described below and an additional $24.3 million in self-bonding, letters of credit and surety bonds related to collateral for surety companies, road maintenance, performance guarantees and other operations.

The Company owns a 37.5% interest in a partnership that leases a coal export terminal from the Peninsula Ports Authority of Virginia under a 30-year lease that permits the partnership to purchase the terminal at the end of the lease term for a nominal amount. The partners have severally (but not jointly) agreed to make payments under various agreements which in the aggregate provide the partnership with sufficient funds to pay rents and to cover the principal and interest payments on the floating-rate industrial revenue bonds issued by the Peninsula Ports Authority, and which are supported by letters of credit from a commercial bank. As of December 31, 2008, the Company’s maximum reimbursement obligation to the commercial bank was in turn supported by two letters of credit totaling $42.8 million.

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. On November 19, 2002 TXU Europe Limited was placed under the administration process in the United Kingdom (a process similar to bankruptcy proceedings in the U.S.) and continues under this process as of December 31, 2008. As a result of these proceedings, TXU Europe Limited may be liquidated or otherwise reorganized in such a way as to relieve it of its obligations under its guarantee.

At December 31, 2008, the Company has a $110.4 million letter of credit for collateral for bank guarantees issued with respect to certain reclamation and performance obligations related to the mines acquired in the Excel acquisition.

Other Guarantees

As part of arrangements through which the Company obtains exclusive sales representation agreements with small coal mining companies (the Counterparties), the Company issued financial guarantees on behalf of the Counterparties. These guarantees facilitate the Counterparties’ efforts to obtain bonding or financing. In the event of default, the Company has multiple recourse options, including the ability to assume the loans and procure title and use of the equipment purchased through the loans. If default occurs, the Company has the ability and intent to exercise its recourse options, so the liability associated with the guarantee has been valued at zero. The aggregate amount guaranteed by the Company for all such Counterparties was $10.0 million at December 31, 2008. The Company’s obligations under the guarantees extend to September 2013.

F-49

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

In 2007, the Company purchased approximately 427 million tons of coal reserves and surface lands in the Illinois Basin. In conjunction with this purchase, the Company agreed to provide up to $64.8 million of reclamation and bonding commitments to a third-party coal company. The Company recognized $61.8 million of these commitments as a liability as of December 31, 2008 and $64.8 million as of December 31, 2007.

The Company is the lessee under numerous equipment and property leases. It is common in such commercial lease transactions for the Company, as the lessee, to agree to indemnify the lessor for the value of the property or equipment leased, should the property be damaged or lost during the course of the Company’s operations. The Company expects that losses with respect to leased property would be covered by insurance (subject to deductibles). The Company and certain of its subsidiaries have guaranteed other subsidiaries’ performance under their various lease obligations. Aside from indemnification of the lessor for the value of the property leased, the Company’s maximum potential obligations under its leases are equal to the respective future minimum lease payments as presented in Note 9, and the Company assumes that no amounts could be recovered from third parties.

The Company’s former wholly-owned subsidiary, Prairie State Generating Company, LLC (PSGC), had previously entered into a cost reimbursable Target Price Engineering, Procurement and Construction Agreement (the EPC Agreement) with Bechtel Power Corporation (Bechtel) related to the Prairie State mine mouth pulverized coal-fired generating facility. The Company provided an absolute and unconditional payment guarantee of all amounts due until financial closing by PSGC to Bechtel under the EPC Agreement (Initial Owner Guarantee). In September 2007, PSGC gave Bechtel notice to proceed to full scale construction of the facility. On that date, the Company’s ownership interest in PSGC was transferred to an Indiana non-profit corporation that is owned and controlled by a group of owners (Owners), including two of the Company’s affiliates. Contemporaneously with the transfer of PSGC’s membership interests, each Owner (including the Company’s affiliates) issued a guarantee to Bechtel for its proportionate share of PSGC’s obligations under the EPC Agreement and the Company issued a guarantee to Bechtel for the Company’s two affiliates. The Initial Owner Guarantee was returned to the Company following the issuance of new guarantees by each Owner. After the sale of one of the Company’s owner affiliates in December 2007, the Company’s remaining affiliate owns 5.06% of PSGC.

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. See Note 12 for the descriptions of the Company’s (and its subsidiaries’) debt. Supplemental guarantor/non-guarantor financial information is provided in Note 23.

As part of the Patriot spin-off, the Company agreed to maintain in force several letters of credit that secured Patriot obligations for certain employee benefits and workers’ compensation obligations. These letters of credit are to be released upon Patriot satisfying the beneficiaries with alternate letters of credit or insurance. If Patriot is unable to satisfy the primary beneficiaries by June 30, 2011, they are then required to provide directly to the Company a letter of credit in the amount of the remaining obligation. The amount of letters of credit maintained by the Company securing Patriot obligations was $7.0 million at December 31, 2008 and $136.8 million at December 31, 2007.

A discussion of the Company’s accounts receivable securitization is included in Note 6 to the consolidated financial statements.

(20) Commitments and Contingencies

Commitments

As of December 31, 2008, purchase commitments for capital expenditures were $38.5 million. Commitments for expenditures to be made under coal leases are reflected in Note 9.

F-50

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

From time to time, the Company or its subsidiaries are involved in legal proceedings arising in the ordinary course of business or related to indemnities or historical operations. The Company believes it has recorded adequate reserves for these liabilities and that there is no individual case pending that is likely to have a material adverse effect on the Company’s financial condition, results of operations or cash flows. The Company discusses its significant legal proceedings below.

Litigation Relating to Continuing Operations

Navajo Nation Litigation

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

The outcome of this litigation is subject to numerous uncertainties. Based on 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 this matter is likely to be resolved without a material adverse effect on the Company’s financial condition, results of operations or cash flows.

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

Salt River Project and the other owners of the Navajo Generating Station filed a lawsuit on September 27, 1996, in the Superior Court of Maricopa County in Arizona seeking a declaratory judgment that certain costs relating to final reclamation, environmental monitoring work and mine decommissioning and costs primarily relating to retiree health care benefits are not recoverable by the Company’s subsidiary, Peabody Western, under the terms of a coal supply agreement dated February 18, 1977. The contract expires in 2011. The trial court subsequently ruled that the mine decommissioning costs were subject to arbitration but that the retiree health care costs were not subject to arbitration. All of the parties have negotiated and signed a comprehensive settlement to fully resolve all of the underlying claims and demands and to dismiss the associated litigation with prejudice, which became final and binding upon all of the parties on June 30, 2008. As a result of the retiree heath care cost settlement, the Company recorded pre-tax earnings of $56.9 million in 2008. The Company has a receivable for mine decommissioning costs of $90.4 million as of December 31, 2008 and $87.7 million as of December 31, 2007, and a receivable for retiree health care costs of $67.6 million as of December 31, 2008 included in “Investments and other assets” in the consolidated balance sheets.

Gulf Power Company Litigation

On June 22, 2006, Gulf Power Company filed a breach of contract lawsuit against 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 Company and seeking damages for alleged past and future tonnage shortfalls of nearly five million tons under the agreement, which expired on December 31, 2007. In February 2008, the court denied the Company’s motion to dismiss the Florida lawsuit or to transfer it to Illinois and retained jurisdiction over the case.

F-51

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

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

The outcome of litigation and these claims are subject to numerous uncertainties. Based 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 this matter is likely to be resolved without a material adverse effect on its financial condition, results of operations or cash flows.

F-52

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

Environmental Claims and Litigation

Environmental claims have been asserted against Gold Fields related to activities of Gold Fields or a former affiliate. Gold Fields or the former affiliate has been named a potentially responsible party (PRP) at five national priority list sites based on the Superfund Amendments and Reauthorization Act of 1986. Claims were asserted at 11 additional sites, bringing the total to 16, which have since been reduced to 12 by completion of work, transfer or regulatory inactivity. The number of PRP sites in and of itself is not a relevant measure of liability, because the nature and extent of environmental concerns varies by site, as does the estimated share of responsibility for Gold Fields or the former affiliate. Undiscounted liabilities for environmental cleanup-related costs for all of the sites noted above were $45.3 million as of December 31, 2008 and $43.5 million as of December 31, 2007, $7.6 million and $7.1 million of which was reflected as a current liability, respectively. These amounts represent those costs that the Company believes are probable and reasonably estimable. In September 2005, Gold Fields and other PRPs received a letter from the U.S. Department of Justice alleging that the PRP’s mining operations caused the EPA to incur approximately $125 million in residential yard remediation costs at Picher, Oklahoma and will cause the EPA to incur additional remediation costs relating to historical mining sites. In September 2008, Gold Fields and other PRPs received letters from the U.S. Department of Justice and the EPA re-initiating settlement negotiations. Gold Fields is participating in the settlement discussions. Gold Fields believes it has meritorious defenses to these claims. Gold Fields is involved in other litigation in the Picher area, and 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 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.

Other

In addition, at times the Company become a party to other claims, lawsuits, arbitration proceedings and administrative procedures in the ordinary course of business in the U.S., Australia and other countries where the Company does business. 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.

New York Office of the Attorney General Subpoena

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

F-53

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

Alaskan Villages’ Claims

In February 2008, the Native Village of Kivalina and the City of Kivalina filed a lawsuit in the U.S. District Court for the Northern District of California against 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, which cost is alleged to be $95 million to $400 million. The Company believes that this lawsuit is without merit and intends to defend against and oppose it vigorously, but cannot predict its outcome. 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 this matter is likely to be resolved without a materially adverse effect on its financial condition, results of operations or cash flows.

(21) Summary Quarterly Financial Information (Unaudited)

A summary of the unaudited quarterly results of operations for the years ended December 31, 2008 and 2007 is presented below. Peabody Energy common stock is listed on the New York Stock Exchange under the symbol “BTU.”


	Year Ended December 31, 2008
	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter
	(Dollars in millions except per share and stock price data)
Revenues	$	1,276.0	$	1,530.9	$	1,905.7	$	1,880.8
Operating profit		172.7		343.8		490.2		386.2
Income from continuing operations, net of income taxes		70.2		245.0		379.2		296.0
Net income attributable to common stockholders		57.0		233.3		369.4		293.2
Basic earnings per share — continuing operations⁽¹⁾		0.26		0.89		1.39		1.10
Diluted earnings per share — continuing operations ⁽¹⁾	$	0.25	$	0.89	$	1.38	$	1.10
Weighted average shares used in calculating basic earnings per share (in millions)		269.2		270.0		270.2		266.1
Weighted average shares used in calculating diluted earnings per share (in millions)		271.5		271.9		271.8		267.2
Stock price — high and low prices	$	63.97-$42.05	$	88.69-$49.38	$	88.39-$39.06	$	43.99-$16.00
Dividends per share	$	0.06	$	0.06	$	0.06	$	0.06


⁽¹⁾		Earnings per share for the quarters may not add to the amounts for the year, as each period is computed on a discrete basis.

Operating profit in the first quarter included a $54.0 million gain on the sale of coal reserves and surface lands (see Note 4 for information). Second, third and fourth quarter operating profits reflect higher contract pricing in Australia that began in the second quarter. The second quarter operating profit also included revenue recovery of $56.9 million on coal supply agreements (see Note 20 for information), as well as tax benefit of $45.3 million due to the reduction in net operating loss valuation allowances (see Note 11 for information). Net income for the third and fourth quarters of 2008 included a non-cash tax benefit from the remeasurement of non-U.S. income tax accounts. The benefit was $62.7 million in the third quarter and $35.9 million in the fourth quarter.

F-54

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


	Year Ended December 31, 2007
	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter
	(Dollars in millions except per share and stock price data)
Revenues	$	1,109.8	$	1,068.8	$	1,198.5	$	1,168.0
Operating profit		147.4		178.6		115.6		151.1
Income from continuing operations, net of income taxes		81.5		104.4		51.7		199.6
Net income attributable to common stockholders		88.4		107.6		32.2		35.6
Basic earnings per share — continuing operations ⁽¹⁾		0.31		0.38		0.21		0.76
Diluted earnings per share — continuing operations ⁽¹⁾	$	0.30	$	0.37	$	0.20	$	0.75
Weighted average shares used in calculating basic earnings per share (in millions)		263.0		263.5		263.9		265.9
Weighted average shares used in calculating diluted earnings per share (in millions)		267.8		268.4		268.6		270.0
Stock price — high and low prices	$	44.60-$36.20	$	55.76-$39.96	$	50.99-$38.42	$	62.55-$47.52
Dividends per share	$	0.06	$	0.06	$	0.06	$	0.06


⁽¹⁾		Earnings per share for the quarters may not add to the amounts for the year, as each period is computed on a discrete basis.

Second quarter operating profit included a $50.5 million gain resulting from an exchange of oil and gas rights for coal reserves (see Note 4 for information). Operating profit in the third and fourth quarters of 2007 included $17.8 million and $8.6 million, respectively, of gains from the sale of coal reserves and surface lands (see Note 4 for information). Operating profit for the third quarter of 2007 was negatively impacted by disruption in the coal-chain in Australia. Net income for the fourth quarter of 2007 included a tax benefit related to a reduction of $205.0 million in net operating loss valuation allowances, partially offset by ongoing tax expense and a $56.0 million non-cash tax impact from the remeasurement of non U.S. income tax accounts (see Note 11 for information).

(22) Segment Information

The Company reports its operations primarily through the following reportable operating segments: “Western U.S. Mining,” “Midwestern U.S. Mining,” “Australian Mining” and “Trading and Brokerage.” Western U.S. Mining operations reflect the aggregation of the Powder River Basin, Southwest and Colorado operating segments, and Midwestern U.S. Mining operations reflects the Company’s Midwestern operating segments in Illinois and Indiana. In 2008, the Company renamed its Eastern U.S. Mining segment to Midwestern U.S. Mining segment to better reflect the geography of the continuing operations of that region. The principal business of the Western U.S. Mining, Midwestern U.S. Mining and Australian Mining segments is the mining, preparation and sale of steam coal, sold primarily to electric utilities, and metallurgical coal, sold to steel and coke producers. For the year ended December 31, 2008, 82% of the Company’s total sales (by volume) were to U.S. electricity generators, 16% were to customers outside the U.S. and 2% were to the U.S. industrial sector. Western U.S. Mining operations are characterized by predominantly surface mining extraction processes, lower sulfur content and Btu of coal and higher customer transportation costs (due to longer shipping distances). Conversely, Midwestern U.S. Mining operations are characterized by a mix of surface and underground mining extraction processes, higher sulfur content and Btu of coal and lower customer transportation costs (due to shorter shipping distances). Geologically, Western operations mine bituminous and subbituminous coal deposits, and Midwestern operations mine bituminous coal deposits. Australian Mining operations are characterized by both surface and underground extraction processes, mining various qualities of low-sulfur, high Btu coal (metallurgical coal) as well as steam coal primarily sold to an international customer base with a small portion sold to Australian steel producers and power generators. The Trading and Brokerage segment’s principal business is primarily the brokering of coal sales of other coal producers both as principal and agent, and the trading of coal, freight and freight-related contracts. “Corporate and Other” includes selling and administrative expenses, net gains on property disposals, costs associated with past mining obligations, joint venture earnings related to the Company’s 25.5% investment in a Venezuelan mine and revenues and expenses related to the Company’s other commercial activities such as generation development and resource management.

The Company’s chief operating decision maker uses Adjusted EBITDA as the primary measure of segment profit and loss. Adjusted EBITDA is defined as income from continuing operations before deducting net interest expense, income taxes, asset retirement obligation expense and depreciation, depletion and amortization.

F-55

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

Operating segment results for the year ended December 31, 2008 were as follows:


	Western		Midwestern		Australian		Trading and		Corporate
	U.S. Mining		U.S. Mining		Mining		Brokerage		and Other			Consolidated
	(Dollars in millions)
Revenues	$	2,533.1	$	1,154.6	$	2,275.2	$	601.8	$	28.7		$	6,593.4
Adjusted EBITDA		681.3		177.3		1,017.0		218.9		(247.2	)		1,847.3
Total assets		3,140.4		552.0		2,985.9		920.3		2,097.0			9,695.6
Additions to property, plant, equipment and mine development		140.4		30.3		64.9		—		30.6			266.2
Federal coal lease expenditures		178.5		—		—		—		—			178.5
Income (loss) from equity affiliates		—		—		—		—		—			—

Operating segment results for the year ended December 31, 2007 were as follows:


	Western		Midwestern		Australian		Trading and		Corporate
	U.S. Mining		U.S. Mining		Mining		Brokerage		and Other			Consolidated
	(Dollars in millions)
Revenues	$	2,063.2	$	987.1	$	1,138.9	$	320.7	$	35.2		$	4,545.1
Adjusted EBITDA		595.4		200.0		166.1		116.6		(109.5	)		968.6
Total assets		2,893.8		529.6		3,033.3		346.8		2,278.8			9,082.3
Additions to property, plant, equipment and mine development		175.4		34.0		167.2		—		62.2			438.8
Federal coal lease expenditures		178.2		—		—		—		—			178.2
Income (loss) from equity affiliates		—		—		—		—		14.5			14.5

Operating segment results for the year ended December 31, 2006 were as follows:


	Western		Midwestern		Australian		Trading and		Corporate
	U.S. Mining		U.S. Mining		Mining		Brokerage		and Other			Consolidated
	(Dollars in millions)
Revenues	$	1,703.4	$	858.5	$	833.0	$	652.0	$	4.0		$	4,050.9
Adjusted EBITDA		473.1		186.2		286.8		92.6		(127.7	)		911.0
Total assets		2,628.1		348.8		2,784.9		240.3		3,502.6			9,504.7
Additions to property, plant, equipment and mine development		151.6		61.7		118.5		1.0		59.1			391.9
Federal coal lease expenditures		178.2		—		—		—		—			178.2
Income (loss) from equity affiliates		—		—		—		—		22.8			22.8

F-56

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

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


	Year Ended December 31,
	2008			2007			2006
	(Dollars in millions)
Total adjusted EBITDA	$	1,847.3		$	968.6		$	911.0
Depreciation, depletion and amortization		(406.2	)		(352.2	)		(284.2	)
Asset retirement obligation expense		(48.2	)		(23.7	)		(14.2	)
Interest expense		(227.2	)		(235.8	)		(139.1	)
Interest income		10.1			7.1			11.3
Income tax (provision) benefit		(185.4	)		73.2			85.7


Income from continuing operations, net of income taxes	$	990.4		$	437.2		$	570.5

(23) Supplemental Guarantor/Non-Guarantor Financial Information

In accordance with the indentures governing the 6.875% Senior Notes due March 2013, the 5.875% Senior Notes due March 2016, the 7.375% Senior Notes due November 2016 and the 7.875% Senior Notes due November 2026, certain wholly-owned U.S. subsidiaries of the Company have fully and unconditionally guaranteed these Senior Notes, on a joint and several basis. Separate financial statements and other disclosures concerning the Guarantor Subsidiaries are not presented because management believes that such information is not material to the Senior Note holders. The following historical financial statement information is provided for the Guarantor/Non-Guarantor Subsidiaries.

F-57

PEABODY ENERGY CORPORATION
SUPPLEMENTAL CONSOLIDATED STATEMENTS OF OPERATIONS


	Year Ended December 31, 2008
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(Dollars in millions)
Total revenues	$	—		$	3,788.4		$	3,013.8		$	(208.8	)	$	6,593.4
Costs and expenses:
Operating costs and expenses		(51.5	)		3,034.7			1,842.8			(208.8	)		4,617.2
Depreciation, depletion and amortization		—			265.9			140.3			—			406.2
Asset retirement obligation expense		—			42.8			5.4			—			48.2
Selling and administrative expenses		22.0			171.6			8.2			—			201.8
Other operating income:
Net gain on disposal or exchange of assets		—			(72.7	)		(0.2	)		—			(72.9	)
(Income) loss from equity affiliates		(1,075.0	)		5.7			(5.7	)		1,075.0			—
Interest expense		220.5			22.4			42.2			(57.9	)		227.2
Interest income		(15.1	)		(24.2	)		(28.7	)		57.9			(10.1	)

Income from continuing operations before income taxes		899.1			342.2			1,009.5			(1,075.0	)		1,175.8
Income tax provision (benefit)		(67.7	)		101.3			151.8			—			185.4

Income from continuing operations, net of income taxes		966.8			240.9			857.7			(1,075.0	)		990.4
Income (loss) from discontinued operations, net of income taxes		(13.9	)		(27.9	)		10.5			—			(31.3	)

Net income		952.9			213.0			868.2			(1,075.0	)		959.1
Less: Net income (loss) attributable to noncontrolling interests		—			(0.1	)		6.3			—			6.2

Net income attributable to common stockholders	$	952.9		$	213.1		$	861.9		$	(1,075.0	)	$	952.9

F-58

PEABODY ENERGY CORPORATION
SUPPLEMENTAL CONSOLIDATED STATEMENTS OF OPERATIONS


	Year Ended December 31, 2007
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(Dollars in millions)
Total revenues	$	—		$	3,271.7		$	1,435.3		$	(161.9	)	$	4,545.1
Costs and expenses:
Operating costs and expenses		(72.2	)		2,533.6			1,233.0			(161.9	)		3,532.5
Depreciation, depletion and amortization		—			236.0			116.2			—			352.2
Asset retirement obligation expense		—			17.8			5.9			—			23.7
Selling and administrative expenses		21.5			121.4			4.2			—			147.1
Other operating income:
Net (gain) loss on disposal or exchange of assets		—			(88.8	)		0.2			—			(88.6	)
(Income) loss from equity affiliates		(536.6	)		6.7			(21.2	)		536.6			(14.5	)
Interest expense		279.5			32.1			26.6			(102.4	)		235.8
Interest income		(17.5	)		(68.0	)		(24.0	)		102.4			(7.1	)

Income from continuing operations before income taxes		325.3			480.9			94.4			(536.6	)		364.0
Income tax provision (benefit)		(83.8	)		(94.4	)		105.0			—			(73.2	)

Income (loss) from continuing operations, net of income taxes		409.1			575.3			(10.6	)		(536.6	)		437.2
Loss from discontinued operations, net of income taxes		(145.3	)		(8.2	)		(22.2	)		—			(175.7	)

Net income		263.8			567.1			(32.8	)		(536.6	)		261.5
Less: Net income (loss) attributable to noncontrolling interests		—			0.9			(3.2	)		—			(2.3	)

Net income (loss) attributable to common stockholders	$	263.8		$	566.2		$	(29.6	)	$	(536.6	)	$	263.8

F-59

PEABODY ENERGY CORPORATION
SUPPLEMENTAL CONSOLIDATED STATEMENTS OF OPERATIONS


	Year Ended December 31, 2006
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(Dollars in millions)
Total revenues	$	—		$	2,921.3		$	1,235.7		$	(106.1	)	$	4,050.9
Costs and expenses:
Operating costs and expenses		(15.3	)		2,285.6			924.0			(106.1	)		3,088.2
Depreciation, depletion and amortization		—			221.4			62.8			—			284.2
Asset retirement obligation expense		—			13.7			0.5			—			14.2
Selling and administrative expenses		17.2			107.3			3.5			—			128.0
Other operating income:
Net gain on disposal or exchange of assets		—			(53.4	)		(0.1	)		—			(53.5	)
(Income) loss from equity affiliates		(708.8	)		5.2			(28.0	)		708.8			(22.8	)
Interest expense		198.5			51.7			14.9			(126.0	)		139.1
Interest income		(21.4	)		(85.2	)		(30.7	)		126.0			(11.3	)


Income from continuing operations before income taxes		529.8			375.0			288.8			(708.8	)		484.8
Income tax provision (benefit)		(70.9	)		(104.9	)		90.1			—			(85.7	)

Income from continuing operations, net of income taxes		600.7			479.9			198.7			(708.8	)		570.5
Income (loss) from discontinued operations, net of income taxes		—			(6.8	)		37.6			—			30.8

Net income		600.7			473.1			236.3			(708.8	)		601.3
Less: Net income (loss) attributable to noncontrolling interets		—			(0.2	)		0.8			—			0.6

Net income attributable to common stockholders	$	600.7		$	473.3		$	235.5		$	(708.8	)	$	600.7

F-60

PEABODY ENERGY CORPORATION
SUPPLEMENTAL CONSOLIDATED BALANCE SHEETS


	December 31, 2008
	Parent		Guarantor			Non-Guarantor			Reclassifications
	Company		Subsidiaries			Subsidiaries			& Eliminations			Consolidated
						(Dollars in millions)
Assets
Current assets
Cash and cash equivalents	$	161.2	$	4.5		$	284.0		$	—		$	449.7
Accounts receivable, net		0.6		4.8			378.2			—			383.6
Receivables from affiliates		935.6		1,632.7			933.0			(3,501.3	)		—
Inventories		—		173.7			104.0			—			277.7
Assets from coal trading activities, net		—		226.2			436.6			—			662.8
Deferred income taxes		43.7		21.7			—			(63.7	)		1.7
Other current assets		51.0		77.8			67.0			—			195.8

Total current assets		1,192.1		2,141.4			2,202.8			(3,565.0	)		1,971.3
Property, plant, equipment and mine development
Land and coal interests		—		4,655.5			2,699.2			—			7,354.7
Buildings and improvements		—		748.6			112.7			—			861.3
Machinery and equipment		—		1,016.1			249.7			—			1,265.8
Less accumulated depreciation, depletion and amortization		—		(1,806.7	)		(359.9	)		—			(2,166.6	)

Property, plant, equipment and mine development, net		—		4,613.5			2,701.7			—			7,315.2
Notes receivable from affiliates		213.4		819.2			—			(1,032.6	)		—
Deferred income taxes		212.8		99.1			—			(311.9	)		—
Investments and other assets		8,439.1		375.2			8.0			(8,413.2	)		409.1

Total assets	$	10,057.4	$	8,048.4		$	4,912.5		$	(13,322.7	)	$	9,695.6


Liabilities and Stockholders’ Equity
Current liabilities
Current maturities of long-term debt	$	—	$	—		$	17.0		$	—		$	17.0
Payables to affiliates		2,546.1		—			955.2			(3,501.3	)		—
Liabilities from coal trading activities, net		—		109.3			194.9			—			304.2
Deferred income taxes		—		—			63.7			(63.7	)		—
Accounts payable and accrued expenses		376.7		725.9			432.4			—			1,535.0

Total current liabilities		2,922.8		835.2			1,663.2			(3,565.0	)		1,856.2
Long-term debt, less current maturities		2,640.4		0.2			136.0			—			2,776.6
Deferred income taxes		21.5		119.2			192.7			(311.9	)		21.5
Notes payable to affiliates		1,032.6		—			—			(1,032.6	)		—
Other noncurrent liabilities		322.0		1,517.2			82.6			—			1,921.8

Total liabilities		6,939.3		2,471.8			2,074.5			(4,909.5	)		6,576.1
Peabody Energy Corporation’s stockholders’ equity		3,118.1		5,576.6			2,836.6			(8,413.2	)		3,118.1
Noncontrolling interests		—		—			1.4			—			1.4

Total equity		3,118.1		5,576.6			2,838.0			(8,413.2	)		3,119.5

Total liabilities and stockholders’ equity	$	10,057.4	$	8,048.4		$	4,912.5		$	(13,322.7	)	$	9,695.6

F-61

PEABODY ENERGY CORPORATION
SUPPLEMENTAL CONSOLIDATED BALANCE SHEETS


							December 31, 2007
	Parent			Guarantor			Non-Guarantor			Reclassifications
	Company			Subsidiaries			Subsidiaries			& Eliminations			Consolidated
			(Dollars in millions)
Assets
Current assets
Cash and cash equivalents	$	7.0		$	3.9		$	34.4		$	—		$	45.3
Accounts receivable, net		9.2			7.2			240.5			—			256.9
Receivables from affiliates		—			1,540.8			701.7			(2,242.5	)		—
Inventories		—			138.3			126.4			—			264.7
Assets from coal trading activities, net		—			222.1			127.7			—			349.8
Deferred income taxes		—			98.6			—			(39.8	)		58.8
Other current assets		221.8			64.8			48.4			—			335.0

Total current assets		238.0			2,075.7			1,279.1			(2,282.3	)		1,310.5
Property, plant, equipment and mine development
Land and coal interests		—			4,541.3			2,634.1			—			7,175.4
Buildings and improvements		—			549.3			108.8			—			658.1
Machinery and equipment		—			1,062.3			193.9			—			1,256.2
Less accumulated depreciation, depletion and amortization		—			(1,556.8	)		(235.0	)		—			(1,791.8	)

Property, plant, equipment and mine development, net		—			4,596.1			2,701.8			—			7,297.9
Notes receivable from affiliates		213.4			1,112.7			—			(1,326.1	)		—
Deferred income taxes		—			95.6			—			(95.6	)		—
Investments and other assets		7,759.5			(294.5	)		12.6			(7,003.7	)		473.9

Total assets	$	8,210.9		$	7,585.6		$	3,993.5		$	(10,707.7	)	$	9,082.3


Liabilities and Stockholders’ Equity
Current liabilities
Current maturities of long-term debt	$	122.7		$	—		$	11.7		$	—		$	134.4
Payables to affiliates		1,062.4			578.8			601.3			(2,242.5	)		—
Liabilities from coal trading activities, net		—			165.9			135.9			—			301.8
Deferred income taxes		39.8			—			—			(39.8	)		—
Accounts payable and accrued expenses		204.4			655.7			273.9			—			1,134.0

Total current liabilities		1,429.3			1,400.4			1,022.8			(2,282.3	)		1,570.2
Long-term debt, less current maturities		2,619.1			0.2			155.3			—			2,774.6
Deferred income taxes		245.6			—			345.1			(95.6	)		495.1
Notes payable to affiliates		1,054.1			—			272.0			(1,326.1	)		—
Other noncurrent liabilities		128.2			1,278.7			100.2			—			1,507.1

Total liabilities		5,476.3			2,679.3			1,895.4			(3,704.0	)		6,347.0
Peabody Energy Corporation’s stockholders’ equity		2,734.6			4,910.4			2,093.3			(7,003.7	)		2,734.6
Noncontrolling interests		—			(4.1	)		4.8			—			0.7

Total equity		2,734.6			4,906.3			2,098.1			(7,003.7	)		2,735.3

Total liabilities and stockholders’ equity	$	8,210.9		$	7,585.6		$	3,993.5		$	(10,707.7	)	$	9,082.3

F-62

PEABODY ENERGY CORPORATION
SUPPLEMENTAL CONSOLIDATED STATEMENTS OF CASH FLOWS


	Year Ended December 31, 2008
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Consolidated
				(Dollars in millions)
Cash Flows From Operating Activities
Net cash provided by continuing operations	$	17.7		$	465.6		$	930.6		$	1,413.9
Net cash used in discontinued operations		(94.5	)		(17.3	)		(16.4	)		(128.2	)

Net cash provided by (used in) operating activities		(76.8	)		448.3			914.2			1,285.7
Cash Flows From Investing Activities
Acquistions of noncontrolling interests		—			—			(110.1	)		(110.1	)
Additions to property, plant, equipment and mine development		—			(198.0	)		(68.2	)		(266.2	)
Federal coal lease expenditures		—			(178.5	)		—			(178.5	)
Investment in Prairie State		—			(40.9	)		—			(40.9	)
Proceeds from disposal of assets, net of notes receivable		—			72.3			0.5			72.8
Additions to advance mining royalties		—			(5.7	)		(0.3	)		(6.0	)
Investments in equity affiliates and joint ventures		—			(2.6	)		—			(2.6	)

Net cash used in continuing operations		—			(353.4	)		(178.1	)		(531.5	)
Net cash provided by (used in) discontinued operations		—			(0.4	)		26.4			26.0

Net cash used in investing activities		—			(353.8	)		(151.7	)		(505.5	)

Cash Flows From Financing Activities
Change in revolving line of credit		(97.7	)		—			—			(97.7	)
Payments of long-term debt		(18.8	)		—			(13.9	)		(32.7	)
Common stock repurchase		(199.8	)		—			—			(199.8	)
Dividends paid		(64.9	)		—			—			(64.9	)
Proceeds from stock options exercised		14.1			—			—			14.1
Proceeds from employee stock purchases		5.2			—			—			5.2
Transactions with affiliates, net		592.9			(93.9	)		(499.0	)		—

Net cash provided by (used in) financing activities		231.0			(93.9	)		(512.9	)		(375.8	)

Net increase in cash and cash equivalents		154.2			0.6			249.6			404.4
Cash and cash equivalents at beginning of year		7.0			3.9			34.4			45.3

Cash and cash equivalents at end of year	$	161.2		$	4.5		$	284.0		$	449.7

F-63

PEABODY ENERGY CORPORATION
SUPPLEMENTAL CONSOLIDATED STATEMENTS OF CASH FLOWS


				Year Ended December 31, 2007
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Consolidated
				(Dollars in millions)
Cash Flows From Operating Activities
Net cash provided by (used in) continuing operations	$	1.6		$	686.9		$	(230.7	)	$	457.8
Net cash used in discontinued operations		(25.5	)		(7.1	)		(108.8	)		(141.4	)

Net cash provided by (used in) operating activities		(23.9	)		679.8			(339.5	)		316.4
Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development		(25.0	)		(244.3	)		(169.5	)		(438.8	)
Federal coal lease expenditures		—			(178.2	)		—			(178.2	)
Investment in Prairie State		—			(28.8	)		—			(28.8	)
Proceeds from disposal of assets, net of notes receivable		—			118.3			1.3			119.6
Additions to advance mining royalties		—			(8.1	)		—			(8.1	)
Investments in equity affiliates and joint ventures		—			(4.6	)		—			(4.6	)

Net cash used in continuing operations		(25.0	)		(345.7	)		(168.2	)		(538.9	)
Net cash used in discontinued operations		—			(1.8	)		(34.6	)		(36.4	)

Net cash used in investing activities		(25.0	)		(347.5	)		(202.8	)		(575.3	)

Cash Flows From Financing Activities
Change in revolving line of credit		97.7			—			—			97.7
Payments of long-term debt		(51.1	)		(60.9	)		(5.8	)		(117.8	)
Dividends paid		(63.7	)		—			—			(63.7	)
Payment of debt issuance costs		—			(0.8	)		—			(0.8	)
Excess tax benefit related to stock options exercised		96.7			—			—			96.7
Proceeds from stock options exercised		26.2			—			—			26.2
Proceeds from employee stock purchases		6.4			—			—			6.4
Transactions with affiliates, net		(261.5	)		(270.4	)		531.9			—

Net cash provided by (used in) continuing operations		(149.3	)		(332.1	)		526.1			44.7
Net cash used in discontinued operations		(67.0	)		—			—			(67.0	)

Net cash provided by (used in) financing activities		(216.3	)		(332.1	)		526.1			(22.3	)

Net increase (decrease) in cash and cash equivalents		(265.2	)		0.2			(16.2	)		(281.2	)
Cash and cash equivalents at beginning of year		272.2			3.7			50.6			326.5

Cash and cash equivalents at end of year	$	7.0		$	3.9		$	34.4		$	45.3

F-64

PEABODY ENERGY CORPORATION
SUPPLEMENTAL CONSOLIDATED STATEMENTS OF CASH FLOWS


				Year Ended December 31, 2006
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Consolidated
				(Dollars in millions)
Cash Flows From Operating Activities
Net cash provided by (used in) continuing operations	$	(166.8	)	$	504.8		$	268.6		$	606.6
Net cash used in discontinued operations		—			(2.9	)		(20.4	)		(23.3	)

Net cash provided by (used in) operating activities		(166.8	)		501.9			248.2			583.3
Cash Flows From Investing Activities
Acquisition of Excel Coal, net of cash acquired		—			—			(1,507.8	)		(1,507.8	)
Additions to property, plant, equipment and mine development		—			(270.6	)		(121.3	)		(391.9	)
Federal coal lease expenditures		—			(178.2	)		—			(178.2	)
Proceeds from disposal of assets, net of notes receivable		—			28.8			0.6			29.4
Additions to advance mining royalties		—			(5.0	)		—			(5.0	)
Investments in equity affiliates and joint ventures		—			(2.1	)		—			(2.1	)

Net cash used in continuing operations		—			(427.1	)		(1,628.5	)		(2,055.6	)
Net cash used in discontinued operations		—			(0.9	)		(87.3	)		(88.2	)

Net cash used in investing activities		—			(428.0	)		(1,715.8	)		(2,143.8	)

Cash Flows From Financing Activities
Proceeds from long-term debt		2,603.2			—			0.9			2,604.1
Payments of long-term debt		(877.0	)		(11.0	)		(158.0	)		(1,046.0	)
Common stock repurchase		(99.8	)		—			—			(99.8	)
Dividends paid		(63.5	)		—			—			(63.5	)
Payment of debt issuance costs		(40.6	)		—			—			(40.6	)
Excess tax benefit related to stock options exercised		33.2			—			—			33.2
Proceeds from stock options exercised		15.6			—			—			15.6
Proceeds from employee stock purchases		4.5			—			—			4.5
Transactions with affiliates, net		(1,630.9	)		(61.7	)		1,692.6			—

Net cash provided by (used in) continuing operations		(55.3	)		(72.7	)		1,535.5			1,407.5
Net cash used in discontinued operations		—			—			(23.8	)		(23.8	)

Net cash provided by (used in) financing activities		(55.3	)		(72.7	)		1,511.7			1,383.7

Net increase (decrease) in cash and cash equivalents		(222.1	)		1.2			44.1			(176.8	)
Cash and cash equivalents at beginning of year		494.3			2.5			6.5			503.3

Cash and cash equivalents at end of year	$	272.2		$	3.7		$	50.6		$	326.5

F-65


Delaware	1-16463	13-4004153
(State or other jurisdiction of	(Commission File Number)	(I.R.S. Employer Identification No.)
incorporation or organization)


701 Market Street, St. Louis, Missouri		63101-1826
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code (314) 342-3400


Exhibit No.		Description of Exhibit

23.1		Consent of Independent Registered Public Accounting Firm

99.1		Revised Items 6, 7, 7A and 15 of Peabody Energy Corporation’s December 31, 2008 Form 10-K, originally filed on February 27, 2009


	PEABODY ENERGY CORPORATION
Date: August 6, 2009	By:	/s/ MICHAEL C. CREWS
		Michael C. Crews
		Executive Vice President and Chief Financial Officer

1.		Registration Statement (Form S-8 No. 333-61406) pertaining to the Peabody Energy Corporation Employee Stock Purchase Plan (as amended), Long-Term Equity Incentive Plan, and Equity Incentive Plan for Nonemployee Directors,

2.		Registration Statement (Form S-8 No. 333-70910) pertaining to the Peabody Holding Company, Inc. Employee Retirement Account, Lee Ranch Coal Company Retirement and Savings Plan for Salaried Employees, Lee Ranch Coal Company Retirement and Savings Plan for Hourly Employees, and Western Surface Agreement-UMWA 401(k) Plan,

3.		Registration Statement (Form S-8 No. 333-75058) pertaining to the Peabody Energy Corporation Deferred Compensation Plan,

4.		Registration Statement (Form S-8 No. 333-109305) pertaining to the Black Beauty Coal Company 401(k) Plan,

5.		Registration Statement (Form S-8 No. 333-105455) pertaining to the 1998 Stock Purchase and Option Plan for Key Employees of Peabody Energy Corporation,

6.		Registration Statement (Form S-8 No. 333-105456) pertaining to the 1998 Stock Purchase and Option Plan for Key Employees of Peabody Energy Corporation,

7.		Registration Statement (Form S-8 No. 333-117767) pertaining to the Peabody Energy Corporation 2004 Long-Term Equity Incentive Plan,

8.		Registration Statement (Form S-8 No. 333-136443) pertaining to the Big Ridge, Inc. 401(k) Profit Sharing Plan and Trust,

9.		Registration Statement (Form S-8 No. 333-140218) pertaining to the Peabody Investment Corporation Employee Retirement Account and the Peabody Western-UMWA 401(k) Plan and

10.		Registration Statement (Form S-8 No. 333-147507) pertaining to the Peabody Energy Corporation Australian Employee Stock Purchase Plan;


	Page
Report of Independent Registered Public Accounting Firm		F-1

Consolidated Statements of Operations — Years Ended December 31, 2008, 2007 and 2006		F-2

Consolidated Balance Sheets — December 31, 2008 and December 31, 2007		F-3

Consolidated Statements of Cash Flows — Years Ended December 31, 2008, 2007 and 2006		F-4

Consolidated Statements of Changes in Stockholders’ Equity — Years Ended December 31, 2008, 2007 and 2006		F-5

Notes to Consolidated Financial Statements		F-6