e10vq
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
     
    QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2005
Commission File Number 1-16463
PEABODY ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
     
Delaware   13-4004153
     
(State or other jurisdiction of
incorporation or organization)
  (I.R.S. Employer
Identification No.)
701 Market Street, St. Louis, Missouri                      63101-1826
 
(Address of principal executive offices)                      (Zip Code)
(314) 342-3400
 
(Registrant’s telephone number, including area code)
     
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.                     
þ  Yes          o  No
   
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
þ  Yes   o  No
     
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).                
o  Yes  þ  No
Number of shares outstanding of each of the Registrant’s classes of Common Stock, as of October 28, 2005: Common Stock, par value $0.01 per share, 131,489,626 shares outstanding.
 
 

 


INDEX
         
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    42  
 
       
    44  
 
       
       
 
       
    45  
 
       
    45  
 Seventh Supplemental Indenture
 Fifth Supplemental Indenture
 Amended and Restated Receivables Purchase Agreement
 Certification of CEO Pursuant to Rule 13A-14(A)
 Certification of EVP/CFO Pursuant to Rule 13A-14(A)
 Certification of CEO Pursuant to 18 U.S.C. Section 1350
 Certification of EVP/CFO Pursuant to 18 U.S.C. 18 Section 1350

 


Table of Contents

PART I — FINANCIAL INFORMATION
Item 1. Financial Statements.
PEABODY ENERGY CORPORATION
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in thousands, except share and per share data)
                                 
    Quarter Ended     Nine Months Ended  
    September 30,     September 30,  
    2005     2004     2005     2004  
REVENUES
                               
Sales
  $ 1,191,282     $ 895,156     $ 3,343,620     $ 2,538,189  
Other revenues
    32,228       23,833       66,156       69,864  
 
                       
Total revenues
    1,223,510       918,989       3,409,776       2,608,053  
 
                               
COSTS AND EXPENSES
                               
Operating costs and expenses
    987,503       735,618       2,781,859       2,143,080  
Depreciation, depletion and amortization
    77,159       70,132       232,421       202,992  
Asset retirement obligation expense
    7,394       10,146       23,751       31,810  
Selling and administrative expenses
    57,009       33,623       135,440       93,559  
Other operating income:
                               
Net gain on disposal or exchange of assets
    (47,577 )     (1,790 )     (95,151 )     (14,145 )
Income from equity affiliates
    (8,863 )     (2,645 )     (29,541 )     (13,698 )
 
                       
 
                               
OPERATING PROFIT
    150,885       73,905       360,997       164,455  
Interest expense
    25,327       24,926       76,088       70,849  
Early debt extinguishment gains
          (556 )           (556 )
Interest income
    (3,218 )     (1,084 )     (6,401 )     (3,212 )
 
                       
 
                               
INCOME BEFORE INCOME TAXES AND MINORITY INTERESTS
    128,776       50,619       291,310       97,374  
Income tax provision (benefit)
    14,714       6,933       29,300       (13,863 )
Minority interests
    722       247       1,526       900  
 
                       
 
                               
INCOME FROM CONTINUING OPERATIONS
    113,340       43,439       260,484       110,337  
Loss from discontinued operations, net of income tax benefit of $1 and $1,893, respectively
          (2 )           (2,839 )
 
                       
 
NET INCOME
  $ 113,340     $ 43,437     $ 260,484     $ 107,498  
 
                       
 
                               
BASIC EARNINGS PER SHARE
                               
Income from continuing operations
  $ 0.86     $ 0.34     $ 1.99     $ 0.90  
Loss from discontinued operations
                      (0.02 )
 
                       
Net income
  $ 0.86     $ 0.34     $ 1.99     $ 0.88  
 
                       
 
WEIGHTED AVERAGE SHARES OUTSTANDING — BASIC
    131,216,197       128,557,174       130,795,861       122,708,532  
 
                       
 
                               
DILUTED EARNINGS PER SHARE
                               
Income from continuing operations
  $ 0.84     $ 0.33     $ 1.95     $ 0.88  
Loss from discontinued operations
                      (0.02 )
 
                       
Net income
  $ 0.84     $ 0.33     $ 1.95     $ 0.86  
 
                       
 
WEIGHTED AVERAGE SHARES OUTSTANDING — DILUTED
    134,260,988       131,558,064       133,855,704       125,641,992  
 
                       
 
DIVIDENDS DECLARED PER SHARE
  $ 0.095     $ 0.0625     $ 0.245     $ 0.1875  
 
                       
See accompanying notes to unaudited condensed consolidated financial statements.

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PEABODY ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in thousands, except share and per share data)
                 
    (Unaudited)        
    September 30, 2005     December 31, 2004  
ASSETS
               
Current assets
               
Cash and cash equivalents
  $ 478,741     $ 389,636  
Accounts receivable, less allowance for doubtful accounts of $19,995 at September 30, 2005 and $1,361 at December 31, 2004
    236,538       193,784  
Inventories
    368,850       323,609  
Assets from coal trading activities
    85,554       89,165  
Deferred income taxes
    15,050       15,461  
Other current assets
    84,430       42,947  
 
           
Total current assets
    1,269,163       1,054,602  
Property, plant, equipment and mine development, net of accumulated depreciation, depletion and amortization of $1,543,759 at September 30, 2005 and $1,333,645 at December 31, 2004
    5,014,029       4,781,431  
Investments and other assets
    371,603       342,559  
 
           
Total assets
  $ 6,654,795     $ 6,178,592  
 
           
 
               
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
Current liabilities
               
Current maturities of long-term debt
  $ 23,031     $ 18,979  
Liabilities from coal trading activities
    67,398       63,565  
Accounts payable and accrued expenses
    809,956       691,600  
 
           
Total current liabilities
    900,385       774,144  
 
               
Long-term debt, less current maturities
    1,384,263       1,405,986  
Deferred income taxes
    419,621       393,266  
Asset retirement obligations
    398,979       396,022  
Workers’ compensation obligations
    233,127       227,476  
Accrued postretirement benefit costs
    945,670       939,503  
Other noncurrent liabilities
    333,790       315,694  
 
           
Total liabilities
    4,615,835       4,452,091  
Minority interests
    1,685       1,909  
Stockholders’ equity
               
Preferred Stock — $0.01 per share par value; 10,000,000 shares authorized, no shares issued or outstanding as of September 30, 2005 or December 31, 2004
           
Series Common Stock — $0.01 per share par value; 40,000,000 shares authorized, no shares issued or outstanding as of September 30, 2005 or December 31, 2004
           
Series A Junior Participating Preferred Stock — 1,500,000 shares authorized, no shares issued or outstanding as of September 30, 2005 or December 31, 2004
           
Common Stock — $0.01 per share par value; 400,000,000 shares authorized, 131,676,733 shares issued and 131,415,553 shares outstanding as of September 30, 2005 and 150,000,000 shares authorized, 129,829,134 shares issued and 129,567,954 shares outstanding as of December 31, 2004
    1,316       1,298  
Additional paid-in capital
    1,491,038       1,437,319  
Retained earnings
    579,411       350,968  
Unearned restricted stock awards
    (6,323 )     (459 )
Accumulated other comprehensive loss
    (24,251 )     (60,618 )
Treasury shares, at cost: 261,180 shares as of September 30, 2005 and December 31, 2004
    (3,916 )     (3,916 )
 
           
Total stockholders’ equity
    2,037,275       1,724,592  
 
           
Total liabilities and stockholders’ equity
  $ 6,654,795     $ 6,178,592  
 
           
See accompanying notes to unaudited condensed consolidated financial statements.

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PEABODY ENERGY CORPORATION
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in thousands)
                 
    Nine Months Ended  
    September 30,  
    2005     2004  
Cash Flows from Operating Activities
               
Net income
  $ 260,484     $ 107,498  
Loss from discontinued operations
          2,839  
 
           
Income from continuing operations
    260,484       110,337  
Adjustments to reconcile income from continuing operations to net cash provided by operating activities:
               
Depreciation, depletion and amortization
    232,421       202,992  
Deferred income taxes
    28,406       (24,273 )
Early debt extinguishment gains
          (556 )
Amortization of debt discount and debt issuance costs
    5,177       6,097  
Net gain on disposal or exchange of assets
    (95,151 )     (14,145 )
Income from equity affiliates
    (29,541 )     (13,698 )
Dividends received from equity affiliates
    6,082       5,164  
Changes in current assets and liabilities:
               
Accounts receivable, net of sale
    (67,754 )     (5,476 )
Inventories
    (46,204 )     (56,565 )
Net assets from coal trading activities
    7,444       (7,667 )
Other current assets
    (18,625 )     (7,655 )
Accounts payable and accrued expenses
    119,229       46,076  
Asset retirement obligations
    (4,082 )     (5,238 )
Workers’ compensation obligations
    6,943       6,335  
Accrued postretirement benefit costs
    6,167       (27,666 )
Contributions to pension plans
    (6,275 )     (61,380 )
Other, net
    17,448       (177 )
 
           
Net cash provided by operating activities
    422,169       152,505  
 
           
Cash Flows from Investing Activities
               
Additions to property, plant, equipment and mine development
    (346,703 )     (148,345 )
Purchase of mining assets
    (56,500 )      
Additions to advance mining royalties
    (9,061 )     (11,560 )
Acquisitions, net
          (426,265 )
Investment in joint venture
    (2,000 )      
Proceeds from disposal of assets
    71,185       24,623  
 
           
Net cash used in investing activities
    (343,079 )     (561,547 )
 
           
Cash Flows from Financing Activities
               
Proceeds from long-term debt
    11,459       250,000  
Payments of long-term debt
    (15,621 )     (28,749 )
Net proceeds from equity offering
          383,125  
Proceeds from stock options exercised
    19,958       19,274  
Proceeds from employee stock purchases
    3,010       2,343  
Increase of securitized interests in accounts receivable
    25,000       100,000  
Payment of debt issuance costs
          (8,922 )
Distributions to minority interests
    (1,750 )     (818 )
Dividends paid
    (32,041 )     (22,878 )
 
           
Net cash provided by financing activities
    10,015       693,375  
 
           
Net increase in cash and cash equivalents
    89,105       284,333  
Cash and cash equivalents at beginning of period
    389,636       117,502  
 
           
Cash and cash equivalents at end of period
  $ 478,741     $ 401,835  
 
           
See accompanying notes to unaudited condensed consolidated financial statements.

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PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2005
(1) Basis of Presentation
     The condensed consolidated financial statements include the accounts of the Company and its controlled affiliates. All intercompany transactions, profits and balances have been eliminated in consolidation.
     Effective March 30, 2005, the Company implemented a two-for-one stock split on all shares of its common stock. All share and per share amounts in these condensed consolidated financial statements and related notes reflect the stock split.
     The accompanying condensed consolidated financial statements as of September 30, 2005 and for the quarters and nine months ended September 30, 2005 and 2004, and the notes thereto, are unaudited. However, in the opinion of management, these financial statements reflect all normal, recurring adjustments necessary for a fair presentation of the results of the periods presented. The balance sheet information as of December 31, 2004 has been derived from the Company’s audited consolidated balance sheet. The results of operations for the quarter and nine months ended September 30, 2005 are not necessarily indicative of the results to be expected for future quarters or for the year ending December 31, 2005.
(2) New Pronouncements
     After the March 17, 2005 Emerging Issues Task Force (“EITF”) meeting, the Task Force issued EITF Issue 04-6, “Accounting for Stripping Costs in the Mining Industry,” stating “that stripping costs incurred during the production phase of a mine are variable production costs that should be included in the costs of the inventory produced during the period that the stripping costs are incurred.” Advance stripping costs include those costs necessary to remove overburden above an unmined coal seam as part of the surface mining process, and are included as the “work-in-process” component of “Inventories” in the condensed consolidated balance sheets ($230.2 million and $197.2 million as of September 30, 2005 and December 31, 2004, respectively — see Note 6). This is consistent with the concepts embodied in Accounting Research Bulletin No. 43, “Restatement and Revision of Accounting Research Bulletins,” which provides that “the term inventory embraces goods awaiting sale . . . , goods in the course of production (work in process), and goods to be consumed directly or indirectly in production . . . .” At the June 15-16, 2005 EITF meeting, the Task Force clarified that the intended meaning of “inventory produced” is “inventory extracted.” Based on this clarification, stripping costs incurred during a period will be attributed only to the inventory costs of the coal that is extracted during that same period.
     EITF Issue 04-6 is effective for the first reporting period in fiscal years beginning after December 15, 2005 (January 1, 2006 for the Company), with early adoption permitted. At the June EITF meeting, the Task Force modified the transition provisions of EITF Issue 04-6, indicating that companies that adopt in periods beginning after June 29, 2005 may utilize a cumulative effect adjustment approach where the cumulative effect adjustment is recorded directly to retained earnings in the year of adoption. If the Company had implemented the cumulative effect adjustment approach at September 30, 2005, the entry to reduce retained earnings, net of tax, would have been $141.9 million. Alternatively, a company may recognize this change in accounting by restatement of its prior-period financial statements through retrospective application. The Company is currently evaluating which method of adoption it will use. The Company expects to adopt EITF Issue 04-6 on January 1, 2006.
     The Financial Accounting Standards Board (“FASB”) issued FASB Interpretation (“FIN”) No. 47, “Accounting for Conditional Asset Retirement Obligations” in March of 2005. FIN 47 clarifies that an entity must record a liability for a conditional asset retirement obligation if the fair value of the obligation can be reasonably estimated. This interpretation also clarifies the circumstances under which an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective no later than the end of fiscal

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
years ending after December 15, 2005. The Company expects to adopt this interpretation on December 31, 2005. The adoption of this interpretation will not have a material impact on the Company’s financial condition, results of operations or cash flows.
     The Securities and Exchange Commission has deferred the adoption date of Statement of Financial Accounting Standard (“SFAS”) No. 123R, “Share-Based Payment,” to the beginning of fiscal years that begin after June 15, 2005 (January 1, 2006 for calendar year companies). SFAS No. 123R requires the recognition of share-based payments, including employee stock options, in the income statement based on their fair values. The Company expects to adopt this standard on January 1, 2006. Based on stock option grants made in 2005 and currently anticipated for 2006, the Company estimates it will (assuming the modified prospective method is used) recognize stock option expense for the year ending December 31, 2006 of $4.5 million, net of taxes. The Company began utilizing restricted stock as part of its equity-based compensation strategy in January 2005. Based on the restricted stock grants made in 2005 and years prior, and those currently anticipated for 2006, the Company estimates it will recognize expense related to restricted stock of $1.0 million, net of taxes, in 2005 and $2.2 million, net of taxes, in 2006. The Company recognized expense for the nine months ended September 30, 2005 of $0.7 million, net of taxes, for restricted stock grants made in 2005 and years prior.
(3) Significant Transactions and Events
     Gains on Disposal or Exchange of Assets
     In the third quarter of 2005, the Company exchanged certain idle steam coal reserves for steam and metallurgical coal reserves as part of a contractual dispute settlement. The exchange resulted in a $37.4 million gain as further discussed below and in Note 12. Also in the third quarter of 2005, the Company recognized a $6.2 million gain from an exchange transaction involving the acquisition of Illinois Basin coal reserves in exchange for coal reserves, cash, notes, and the Company’s 45% equity interest in a partnership. The exchanges were accounted for at fair value in accordance with the provisions of Accounting Principles Board (“APB”) Opinion No. 29, “Accounting for Nonmonetary Transactions,” as modified by SFAS No. 153, “Exchanges of Nonmonetary Assets — an amendment of APB Opinion No. 29” and EITF 01-2, “Interpretations of APB Opinion No. 29.”
     In the second quarter of 2005, the Company recognized an aggregate $12.5 million gain from three property sales involving non-strategic coal assets and properties which included a reduction of asset retirement obligations of $9.2 million.
     In the first quarter of 2005, the Company sold its remaining 0.838 million Penn Virginia Resource Partners, L.P. (“PVR”) units for net proceeds of $41.9 million and recognized a $31.1 million gain on the sale. In the first quarter of 2004, the Company sold 0.575 million PVR units for net proceeds of $18.5 million and recognized a $9.9 million gain on the sale. The sales of the PVR units were accounted for under SFAS No. 66, “Sales of Real Estate.” In December 2002, the Company entered into a transaction with PVR whereby the Company sold 120 million tons of coal reserves in exchange for $72.5 million in cash and 2.76 million units of the PVR master limited partnership. The Company’s subsidiaries leased back the coal and pay royalties as the coal is mined. No gain or loss was recorded at the inception of this transaction. At the time of the original transaction, a deferred gain from the sales of the reserves and units of $19.0 million remained and is being amortized over the minimum term of the leases. As of September 30, 2005, the deferred gain related to the PVR transactions was $17.4 million.
     Contract Losses
     During the first six months of 2005, the Company recorded net contract losses of $10.7 million related to the breach of a coal supply contract by a producer. The estimated loss related to the supply contract breach reflected amounts accrued for estimated costs to obtain replacement coal in the current market (in excess of the estimated revenue expected to be earned on the brokerage sales).
     In the third quarter of 2005, the Company completed settlement of the dispute, and the related lawsuit was dismissed (see further discussion in Note 12). Under the settlement, the Company received $10.0 million in cash, a new coal supply agreement that partially replaced the disputed coal supply agreement, and exchanged certain coal

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
properties. As a result of the final settlement and based on the fair values of the items exchanged in the overall settlement transaction, the Company further reduced its contract losses by $6.7 million and, as discussed above, recorded gains on assets exchanged of $37.4 million in the third quarter of 2005.
(4) Acquisition of Mining Assets
     In March 2005, the Company purchased mining assets from Lexington Coal Company for $61.0 million, $59.0 million of which was paid on the closing date and up to $2.0 million is to be paid within 12 months of the close pending no outstanding claims related to the acquired mining assets. The purchased assets included $2.5 million of materials and supplies that were recorded in “Inventories” in the condensed consolidated balance sheet. The remaining purchased assets consisted of approximately 70 million tons of reserves, preparation plants, facilities and mining equipment that were recorded in “Property, plant, equipment and mine development” in the condensed consolidated balance sheet. The Company is using the acquired assets to open a new mine that is expected to produce 2 to 3 million tons per year, after it reaches full capacity, and to provide other synergies to existing properties. The new mine, which began production early in the third quarter, will supply coal under a new agreement with terms that can be extended through 2015 (and a minimum term through the end of 2008). The Company also recorded $21.6 million for the estimated asset retirement obligations associated with the acquired assets.
(5) Business Combinations
     On April 15, 2004, the Company purchased, through two separate agreements, all of the equity interests in three coal operations from RAG Coal International AG. The combined purchase price, including related costs and fees, of $442.2 million was funded from the Company’s equity and debt offerings in March 2004. Net proceeds from the equity and debt offerings were $383.1 million and $244.7 million, respectively. The purchases included two mines in Queensland, Australia that collectively produce 7 to 8 million tons per year of metallurgical coal and the Twentymile Mine in Colorado, which produces 8 to 9 million tons per year of steam coal with a planned production expansion up to 12 million tons per year by 2008. The results of operations of the two mines in Queensland, Australia are included in the Company’s Australian Mining Operations segment and the results of operations of the Twentymile Mine are included in the Company’s Western U.S. Mining Operations segment. The acquisition was accounted for as a purchase.
     The purchase accounting allocations related to the acquisition have been finalized and recorded in the accompanying condensed consolidated financial statements. The following table summarizes the fair values of the assets acquired and the liabilities assumed at the date of acquisition (dollars in thousands):
         
Accounts receivable
  $ 46,639  
Materials and supplies
    5,669  
Coal inventory
    11,543  
Other current assets
    6,234  
Property, plant, equipment and mine development, net
    463,567  
Accounts payable and accrued expenses
    (48,688 )
Other noncurrent assets and liabilities, net
    (63,699 )
 
     
Total purchase price, net of cash received of $20,914
  $ 421,265  
 
     

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
     The following unaudited pro forma financial information presents the combined results of operations of the Company and the operations acquired from RAG Coal International AG, on a pro forma basis, as though the companies had been combined as of the beginning of the period presented. The pro forma financial information does not necessarily reflect the results of operations that would have occurred had the Company and the operations acquired from RAG Coal International AG constituted a single entity during this period (dollars in thousands, except per share data):
         
    Nine Months Ended  
    September 30, 2004 *  
Revenues:
       
As reported
  $ 2,608,053  
Pro forma
    2,733,415  
 
Income from continuing operations:
       
As reported
  $ 110,337  
Pro forma
    107,696  
 
Net income:
       
As reported
  $ 107,498  
Pro forma
    104,857  
 
Basic earnings per share — net income:
       
As reported
  $ 0.88  
Pro forma
    0.82  
 
Diluted earnings per share — net income:
       
As reported
  $ 0.86  
Pro forma
    0.80  
 
*   During the first quarter of 2004, prior to the Company’s acquisition, the Australian underground mine acquired by the Company in April 2004 experienced a roof collapse on a portion of the active mine face, resulting in the temporary suspension of mining activities. Due to the inability to ship during a portion of this downtime, costs to return the mine to operations and shipping limits imposed as the result of unrelated restrictions of capacity at a third party loading facility, the Australian operation experienced a pro forma net loss in the quarter immediately prior to acquisition.
(6) Inventories
     Inventories consisted of the following (dollars in thousands):
                 
    September 30,     December 31,  
    2005     2004  
Materials and supplies
  $ 64,718     $ 57,467  
Raw coal
    15,174       17,590  
Advance stripping
    230,154       197,225  
Saleable coal
    58,804       51,327  
 
           
Total
  $ 368,850     $ 323,609  
 
           

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(7) Assets and Liabilities from Coal Trading Activities
     The Company’s coal trading portfolio consisted of forward and swap contracts as of September 30, 2005 and December 31, 2004. The fair value of coal trading derivatives and related hedge contracts as of September 30, 2005 and December 31, 2004 is set forth below (dollars in thousands):
                                 
    September 30, 2005     December 31, 2004  
    Assets     Liabilities     Assets     Liabilities  
 
Forward contracts
  $ 85,554     $ 67,330     $ 89,042     $ 60,914  
Other
          68       123       2,651  
 
                       
Total
  $ 85,554     $ 67,398     $ 89,165     $ 63,565  
 
                       
     Ninety-nine percent of the contracts in the Company’s trading portfolio as of September 30, 2005 were valued utilizing prices from over-the-counter market sources, adjusted for coal quality and traded transportation differentials, and 1% of the Company’s contracts were valued based on similar market transactions.
     As of September 30, 2005, the timing of the estimated future realization of the value of the Company’s trading portfolio was as follows:
         
  Year of   Percentage  
Expiration   of Portfolio  
2005
    48 %
2006
    42 %
2007
    10 %
 
     
 
    100 %
 
     
     At September 30, 2005, 47% of the Company’s credit exposure related to coal trading activities was with investment grade counterparties and 48% was with other Powder River Basin coal producers. The Company’s coal trading operations traded 13.7 million tons and 7.6 million tons for the quarters ended September 30, 2005 and 2004, respectively, and 31.4 million tons and 25.9 million tons for the nine months ended September 30, 2005 and 2004, respectively.
(8) Earnings Per Share and Stockholders’ Equity
     Weighted Average Shares Outstanding
     A reconciliation of weighted average shares outstanding follows:
                                 
    Quarter Ended September 30,     Nine Months Ended September 30,  
    2005     2004     2005     2004  
Weighted average shares outstanding — basic
    131,216,197       128,557,174       130,795,861       122,708,532  
Dilutive impact of stock options
    3,044,791       3,000,890       3,059,843       2,933,460  
 
                       
Weighted average shares outstanding — diluted
    134,260,988       131,558,064       133,855,704       125,641,992  
 
                       
     Stock Compensation
     These interim financial statements include the disclosure requirements of SFAS No. 123, “Accounting for Stock-Based Compensation,” as amended by SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure.” The Company applies APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations in accounting for its equity incentive plans. The Company recorded in “Selling and administrative expenses” in the condensed consolidated statements of operations $0.4 million and $0.1 million of compensation expense for equity-based compensation during each of the quarters ended September 30, 2005 and 2004, respectively, and $1.2 million and

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
$0.2 million in the nine months ended September 30, 2005 and 2004, respectively. The following table reflects pro forma net income and basic and diluted earnings per share as if compensation cost had been determined for the Company’s non-qualified and incentive stock options based on the fair value at the grant dates consistent with the methodology set forth under SFAS No. 123 (dollars in thousands, except per share data):
                                 
    Quarter Ended     Nine Months Ended  
    September 30,     September 30,  
    2005     2004     2005     2004  
Net income:
                               
As reported
  $ 113,340     $ 43,437     $ 260,484     $ 107,498  
Pro forma
    112,041       42,131       256,500       103,971  
 
                               
Basic earnings per share:
                               
As reported
  $ 0.86     $ 0.34     $ 1.99     $ 0.88  
Pro forma
    0.85       0.33       1.96       0.85  
 
                               
Diluted earnings per share:
                               
As reported
  $ 0.84     $ 0.33     $ 1.95     $ 0.86  
Pro forma
    0.83       0.32       1.92       0.83  
(9) Comprehensive Income
     The following table sets forth the after-tax components of comprehensive income for the quarters and nine months ended September 30, 2005 and 2004 (dollars in thousands):
                                 
    Quarter Ended     Nine Months Ended  
    September 30,     September 30,  
    2005     2004     2005     2004  
Net income
  $ 113,340     $ 43,437     $ 260,484     $ 107,498  
Increase in fair value of cash flow hedges, net of tax of $11,230 and $3,091 for the quarters ended September 30, 2005 and 2004, respectively, and $24,303 and $9,184 for the nine months ended September 30, 2005 and 2004, respectively
    16,757       3,718       36,367       12,857  
 
                       
Comprehensive income
  $ 130,097     $ 47,155     $ 296,851     $ 120,355  
 
                       
     Other 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 hedges, foreign currency hedges and interest rate swaps) during the period. Changes in interest rates, crude and heating oil prices, and the U.S. dollar/Australian dollar exchange rate affect the valuation of these instruments.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(10) Pension and Postretirement Benefit Costs
     Components of Net Periodic Pension Costs
     Net periodic pension costs included the following components (dollars in thousands):
                                 
    Quarter Ended     Nine Months Ended  
    September 30,     September 30,  
    2005     2004     2005     2004  
 
Service cost for benefits earned
  $ 2,964     $ 3,147     $ 8,890     $ 9,122  
Interest cost on projected benefit obligation
    11,373       11,027       34,119       32,594  
Expected return on plan assets
    (13,203 )     (12,573 )     (39,609 )     (37,238 )
Amortization of prior service cost
    (4 )     64       (12 )     191  
Amortization of net loss
    6,147       5,477       18,441       16,573  
 
                       
Net periodic pension costs
    7,277       7,142       21,829       21,242  
Curtailment charges
                9,527        
 
                       
Total pension costs
  $ 7,277     $ 7,142     $ 31,356     $ 21,242  
 
                       
     Curtailment
     The curtailment loss resulted from the planned closure during 2005 of two of the Company’s three operating mines that participate in the Western Surface UMWA Pension Plan (the “Plan”). The loss is actuarially determined and consists of an increase in the actuarial liability, the accelerated recognition of previously unamortized prior service cost and contractual termination benefits under the Plan resulting from the closures.
     Contributions
     The Company disclosed in its consolidated financial statements for the year ended December 31, 2004 that it expected to contribute $4.6 million to its funded pension plans and make $1.2 million in expected benefit payments attributable to its unfunded pension plans during 2005. As of September 30, 2005, $5.5 million of contributions have been made to the funded pension plans and $0.8 million of expected benefit payments attributable to the unfunded pension plans have been made. The Company presently anticipates it will contribute $6.1 million in total to its funded pension plans and make total benefit payments of $1.2 million attributable to its unfunded pension plans during 2005.
     Components of Net Periodic Postretirement Benefits Costs
     Net periodic postretirement benefits costs included the following components (dollars in thousands):
                                 
    Quarter Ended     Nine Months Ended  
    September 30,     September 30,  
    2005     2004     2005     2004  
 
Service cost for benefits earned
  $ 1,355     $ 908     $ 4,004     $ 3,308  
Interest cost on accumulated postretirement benefit obligation
    18,154       16,089       54,505       47,680  
Amortization of prior service cost
    (1,355 )     (3,308 )     (4,004 )     (9,923 )
Amortization of actuarial losses
    6,579       918       19,729       2,755  
 
                       
Net periodic postretirement benefit costs
  $ 24,733     $ 14,607     $ 74,234     $ 43,820  
 
                       

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
     Cash Flows
     The Company disclosed in its financial statements for the year ended December 31, 2004 that it expected to pay $85.7 million attributable to its postretirement benefit plans during 2005. For the nine months ended September 30, 2005, payments of $63.6 million attributable to the Company’s postretirement benefit plans have been made, and the Company does not anticipate any significant changes to its original estimate for 2005.
(11) Segment Information
     The Company reports its operations primarily through the following reportable operating segments: “Western U.S. Mining,” “Eastern U.S. Mining,” “Australian Mining” and “Trading and Brokerage.” The principal business of the Western U.S. Mining, Eastern 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. Western U.S. Mining operations are characterized by predominantly surface mining extraction processes, lower sulfur content and Btu of coal, and longer shipping distances from the mine to the customer. Conversely, Eastern U.S. Mining operations are characterized by a majority of underground mining extraction processes, higher sulfur content and Btu of coal, and shorter shipping distances from the mine to the customer. Geologically, Western operations mine primarily subbituminous and Eastern operations mine bituminous coal deposits. Australian Mining operations are characterized by surface and underground extraction processes, mining primarily low sulfur, metallurgical coal sold to an international customer base. The Trading and Brokerage segment’s principal business is the marketing, brokerage and trading of coal. “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 coalbed methane, 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 early debt extinguishment costs, net interest expense, income taxes, minority interests, asset retirement obligation expense and depreciation, depletion and amortization.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
     Operating segment results for the quarters and nine months ended September 30, 2005 and 2004 are as follows (dollars in thousands):
                                 
    Quarter Ended     Nine Months Ended  
    September 30,     September 30,  
    2005     2004     2005     2004  
Revenues:
                               
Western U.S. Mining (1)
  $ 403,214     $ 373,629     $ 1,184,445     $ 1,021,660  
Eastern U.S. Mining
    452,825       344,938       1,315,480       1,057,169  
Australian Mining
    146,146       92,562       390,314       174,000  
Trading and Brokerage
    216,098       105,205       506,960       346,589  
Corporate and Other
    5,227       2,655       12,577       8,635  
 
                       
Total
  $ 1,223,510     $ 918,989     $ 3,409,776     $ 2,608,053  
 
                       
 
                               
Adjusted EBITDA:
                               
Western U.S. Mining (1)
  $ 104,213     $ 113,874     $ 330,277     $ 297,631  
Eastern U.S. Mining
    96,865       54,911       287,569       182,332  
Australian Mining
    39,780       20,777       101,345       33,655  
Trading and Brokerage (2)
    26,132       16,053       19,703       36,728  
Corporate and Other (3)
    (31,552 )     (51,432 )     (121,725 )     (151,089 )
 
                       
Total
  $ 235,438     $ 154,183     $ 617,169     $ 399,257  
 
                       
 
(1)   For the nine months ended September 30, 2005, Western U.S. Mining results include a charge related to the reserves established for disputed legal fees billed to customers as discussed in Note 12.
 
(2)   Trading and Brokerage results include a benefit for the quarter and a charge for the nine months ended September 30, 2005 related to contract losses and a settlement agreement as discussed in Note 3.
 
(3)   Corporate and Other results include the gains on the disposal or exchange of assets discussed in Note 3.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
     A reconciliation of adjusted EBITDA to consolidated income from continuing operations follows (dollars in thousands):
                                 
    Quarter Ended     Nine Months Ended  
    September 30,     September 30,  
    2005     2004     2005     2004  
 
Total adjusted EBITDA
  $ 235,438     $ 154,183     $ 617,169     $ 399,257  
Depreciation, depletion and amortization
    77,159       70,132       232,421       202,992  
Asset retirement obligation expense
    7,394       10,146       23,751       31,810  
Interest expense
    25,327       24,926       76,088       70,849  
Early debt extinguishment gains
          (556 )           (556 )
Interest income
    (3,218 )     (1,084 )     (6,401 )     (3,212 )
Income tax provision (benefit)
    14,714       6,933       29,300       (13,863 )
Minority interests
    722       247       1,526       900  
 
                       
Income from continuing operations
  $ 113,340     $ 43,439     $ 260,484     $ 110,337  
 
                       
(12) Commitments and Contingencies
     Coal Supply Agreement
     On March 9, 2005, the Company’s subsidiary, COALTRADE, LLC (“COALTRADE”), filed a lawsuit against Massey Coal Sales Company, Inc. (“Massey”) in the U.S. District Court for the Eastern District of Kentucky related to a disputed coal supply agreement, and Massey filed a counterclaim. During the quarter ended September 30, 2005, the Company and Massey completed a settlement agreement and mutual release, and the lawsuit was dismissed. See Note 3 for more details on the negotiated settlement.
     Environmental
     The Company is subject to federal, state and local environmental laws and regulations, including the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (“CERCLA” or “Superfund”), the Superfund Amendments and Reauthorization Act of 1986, the Clean Air Act, the Clean Water Act and the Conservation and Recovery Act. Superfund and similar state laws create liability for investigation and remediation in response to releases of hazardous substances in the environment and for damages to natural resources. Under that legislation and many state Superfund statutes, joint and several liability may be imposed on waste generators, site owners and operators and others regardless of fault. These regulations could require the Company to do some or all of the following:
    Remove or mitigate the effects on the environment at various sites from the disposal or release of certain substances;
 
    Perform remediation work at such sites; and
 
    Pay damages for loss of use and non-use values.
     Environmental claims have been asserted against a subsidiary of the Company, Gold Fields Mining, LLC (“Gold Fields”), related to activities of Gold Fields or its former subsidiaries. Gold Fields is a dormant, non-coal producing entity that was previously managed and owned by Hanson PLC, a predecessor owner of the Company. In the February 1997 spin-off of its energy businesses, 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

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
its past operations. The Company has been named a potentially responsible party (“PRP”) based on CERCLA at five sites, and other claims have been asserted at 17 sites. 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 Company’s estimated share of responsibility.
     The Company’s policy is to accrue environmental cleanup-related costs of a non-capital nature when those costs are believed to be probable and can be reasonably estimated. The quantification of environmental exposures requires an assessment of many factors, including the nature and extent of contamination, the timing, extent and method of the remedial action, changing laws and regulations, advancements in environmental technologies, the quality of information available related to specific sites, the assessment stage of each site investigation, preliminary findings and the length of time involved in remediation or settlement. The Company also assesses the financial capability and proportional share of costs of other potentially responsible parties and, where allegations are based on tentative findings, the reasonableness of the Company’s apportionment. The Company has not anticipated any recoveries from insurance carriers or other potentially responsible third parties in the estimation of liabilities recorded on its condensed consolidated balance sheets. Undiscounted liabilities for environmental cleanup-related costs for all of the sites noted above totaled $39.5 million at September 30, 2005 and $40.5 million at December 31, 2004, $14.1 million and $15.1 million of which was 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 PRP’s received a letter from the U.S. Department of Justice seeking to initiate settlement discussions relating to residential yard cleanup costs incurred by the Environmental Protection Agency (“EPA”) at Picher, Oklahoma. A predecessor of Gold Fields formerly operated two lead mills near Picher, Oklahoma prior to the 1950’s and mined, in accordance with lease agreements and permits, approximately 1.7% of the total amount of the ore mined in the county. The Department of Justice alleged that the PRPs’ mining operations caused the EPA to incur approximately $125 million in residential yard remediation costs and will cause the EPA to incur additional remediation costs relating to historic mining sites. Gold Fields believes it has meritorious defenses to these claims. Gold Fields is involved in other litigation in the Picher area as discussed under the “Oklahoma Lead Litigation” caption below.
     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 this provision. The Company anticipates that the environmental remediation costs it has currently accrued will be paid by the end of 2010.
     Although waste substances generated by coal mining and processing are generally not regarded as hazardous substances for the purposes of Superfund and similar legislation, some products used by coal companies in operations, such as chemicals, and the disposal of these products are governed by the statute. Thus, coal mines currently or previously owned or operated by the Company, and sites to which it has sent waste materials, may be subject to liability under Superfund and similar state laws.
Oklahoma Lead Litigation
     Gold Fields and three other companies are defendants in two class action lawsuits filed in the U.S. District Court for the Northern District of Oklahoma (Betty Jean Cole, et al. v. Asarco Inc., et al. and Darlene Evans, et al. v. Asarco Inc., et al.). The plaintiffs have asserted nuisance and trespass claims predicated on allegations of intentional lead exposure by the defendants and are seeking compensatory damages for diminution of property value, punitive damages and the implementation of medical monitoring and relocation programs for the affected individuals. A predecessor of Gold Fields formerly operated two lead mills near Picher, Oklahoma prior to the 1950’s and mined, in accordance with lease agreements and permits, approximately 1.7% of the total amount of the ore mined in the county.
     Gold Fields is also a defendant, along with other companies, in five individual lawsuits arising out of the same lead mill operations. In July 2004, two lawsuits were filed, one in the U.S. District Court for the Northern District of Oklahoma and one in Ottawa County, Oklahoma (subsequently removed to the U.S. District Court for the Northern District of Oklahoma), on behalf of 48 individuals against Gold Fields and three other companies (Billy Holder, et al. v. Asarco Inc., et al.). Plaintiffs in these actions are seeking compensatory and punitive damages for

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
alleged personal injuries from lead exposure. Previously scheduled trials for individual plaintiffs have been postponed.
     In December 2003, the Quapaw Indian tribe and certain Quapaw owners of interests in land filed a class action lawsuit against Gold Fields and five other companies in the U.S. District Court for the Northern District of Oklahoma. The plaintiffs are seeking compensatory and punitive damages based on public and private nuisance, trespass, strict liability, natural resource damage claims under CERCLA, and claims under the Resource Conservation and Recovery Act. Gold Fields has denied liability to the plaintiffs, has filed counterclaims against the plaintiffs seeking indemnification and contribution and has filed a third-party complaint against the United States, owners of interests in chat and real property in the Picher area. In February 2005, the state of Oklahoma on behalf of itself and several other parties sent a notice to Gold Fields and other PRP’s alleging that they had concluded that there is a reasonable probability of making a successful claim against the PRP’s for damages to natural resources. Gold Fields believes it has meritorious defenses to these claims.
     The outcome of litigation is subject to numerous uncertainties. Based on the Company’s evaluation of the issues and their potential impact, the amount of any potential loss cannot be estimated. However, 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.
     Navajo Nation
     On June 18, 1999, the Navajo Nation served the Company’s subsidiaries, Peabody Holding Company, Inc., Peabody Coal Company and 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 and tortious interference with contractual relationships. The complaint alleges that the defendants jointly participated in unlawful activity to obtain favorable coal lease amendments. Plaintiff also alleges that defendants interfered with the fiduciary relationship between the United States and the Navajo Nation. 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 for the Kayenta and Black Mesa mines have terminated due to Peabody Western’s breach of these leases and a reformation of the two coal leases to adjust the royalty rate to 20%. On March 15, 2001, the court allowed the Hopi Tribe to intervene in this lawsuit. The Hopi Tribe has asserted seven claims including fraud and is seeking various remedies including unspecified actual damages, punitive damages and reformation of its coal lease. On March 4, 2003, the U.S. Supreme Court issued a ruling in a companion lawsuit involving the Navajo Nation and the United States. The court rejected the Navajo Nation’s allegation that the United States breached its trust responsibilities to the Tribe in approving the coal lease amendments and was liable for money damages.
     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. Peabody Western, the Navajo Nation, the Hopi Tribe and the customers purchasing coal from the Black Mesa and Kayenta mines are in mediation with respect to this litigation and other business issues.
     The outcome of litigation, or the current mediation, is subject to numerous uncertainties. Based on the Company’s evaluation of the issues and their potential impact, the amount of any potential loss cannot be estimated. However, 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.
     California Public Utilities Commission Proceedings Regarding the Future of the Mohave Generating Station
     Peabody Western has a long-term coal supply agreement with the owners of the Mohave Generating Station that expires on December 31, 2005. Southern California Edison (the majority owner and operator of the plant) is involved in a California Public Utilities Commission proceeding related to the operation of the Mohave plant beyond 2005 or a temporary or permanent shutdown of the plant. Southern California Edison has stated to the Commission that the Mohave plant is not likely to return to service as a coal-fueled resource until 2010 at the earliest if the plant is shut down at December 31, 2005. There is a dispute with the Hopi Tribe regarding the use of groundwater in the transportation of the coal by pipeline from Peabody Western’s Black Mesa Mine to the Mohave

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plant. As a part of the alternate dispute resolution referenced in the Navajo Nation litigation, Peabody Western has been participating in mediation with the owners of the Mohave Generating Station and the Navajo Generating Station, and the two tribes to resolve the complex issues surrounding the groundwater dispute and other disputes involving the two generating stations. Resolution of these issues is critical to the continuation of the operation of the Mohave Generating Station and the renewal of the coal supply agreement after December 31, 2005. There is no assurance that the issues critical to the continued operation of the Mohave plant will be resolved. The owners of the Mohave Generating Station entered into a consent decree with the Grand Canyon Trust, the Sierra Club, and the National Parks and Conservation Association that required the owners to install scrubbers by December 31, 2005 if the Mohave plant was to operate beyond that date. In a letter dated May 25, 2005, the Grand Canyon Trust, the Sierra Club, and the National Parks and Conservation Association rejected a request by the Navajo Nation and the Hopi Tribe to extend the December 31, 2005 deadline and therefore, the Mohave plant will suspend operation on December 31, 2005. The Company has issued Worker Adjustment and Retraining Notification (“WARN”) Act notices to its employees at the Black Mesa Mine regarding layoffs at the end of 2005. The Mohave plant is the sole customer of the Black Mesa Mine, which sold 3.5 million tons of coal in the first nine months of 2005 and 4.7 million tons during the year ended December 31, 2004. During the first nine months of 2005, the mine generated $20.3 million of Adjusted EBITDA (reconciled to its most comparable measure under generally accepted accounting principles in Note 11), which represented 3.3% of the Company’s total of $617.2 million. In 2004, the mine contributed $25.2 million of Adjusted EBITDA, or 4.5% of the Company’s total Adjusted EBITDA of $559.2 million.
     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.
     Peabody Western filed a motion to compel arbitration of these claims, which was granted in part by the trial court. Specifically, the trial court ruled that the mine decommissioning costs were subject to arbitration but that the retiree health care costs were not subject to arbitration. This ruling was subsequently upheld on appeal. As a result, Peabody Western, Salt River Project and the other owners of the Navajo Generating Station will arbitrate the mine decommissioning costs issue and will litigate the retiree health care costs issue. The Company has recorded a receivable for mine decommissioning costs of $72.3 million and $68.6 million included in “Investments and other assets” in the condensed consolidated balance sheets at September 30, 2005 and December 31, 2004, respectively.
     The outcome of litigation is subject to numerous uncertainties. Based on the Company’s evaluation of the issues and their potential impact, the amount of any potential loss cannot be estimated. However, 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.
     Other
     In addition to the matters described above, the Company at times becomes a party to other claims, lawsuits, arbitration proceedings and administrative procedures in the ordinary course of business. Management believes that the ultimate resolution of pending or threatened proceedings is not likely to have a material adverse effect on the financial condition, results of operations or cash flows of the Company.
     Accounts receivable in the condensed consolidated balance sheets as of September 30, 2005 and December 31, 2004, includes $19.4 and $18.1 million, respectively, of receivables billed between 2001 and 2005 related to legal fees incurred in the Company’s defense of the Navajo lawsuit discussed above. The billings have been disputed by two customers, who have withheld payment. The Company believes these billings were made properly under the coal supply agreement with each customer. The billings were consistent with past practice, when litigation costs related to legal or regulatory issues were billed under the contracts and paid by the customers. The Company is in litigation with these customers to resolve this issue. In the second quarter of 2005, the trial court in one of the cases dismissed the Company’s claim, and the Company has appealed that decision. Although the Company believes it has meritorious grounds for appeal and has not yet litigated the other claim, the Company has recognized an

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
allowance against both disputed receivables, which resulted in a charge of $13.4 million in the second quarter of 2005 and $16.2 million in the nine months ended September 30, 2005. The receivable balance, net of the allowance, was zero and $18.1 million at September 30, 2005 and December 31, 2004, respectively.
     At September 30, 2005, purchase commitments for capital expenditures were approximately $332.0 million.
(13) Supplemental Guarantor/Non-Guarantor Financial Information
     In accordance with the indentures governing the 6.875% Senior Notes due 2013 and the 5.875% Senior Notes due 2016, certain wholly-owned U.S. subsidiaries of the Company have fully and unconditionally guaranteed the 6.875% Senior Notes and the 5.875% Senior Notes, on a joint and several basis. Separate financial statements and other disclosures concerning the Guarantor Subsidiaries are not presented because management believes that such information is not material to the holders of the 6.875% Senior Notes and the 5.875% Senior Notes. The following unaudited condensed historical financial statement information is provided for the Guarantor/Non-Guarantor Subsidiaries.
Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Statements of Operations
(Dollars in thousands)
                                         
    Quarter Ended September 30, 2005  
    Parent     Guarantor     Non-Guarantor              
    Company     Subsidiaries     Subsidiaries     Eliminations     Consolidated  
Total revenues
  $     $ 959,278     $ 287,688     $ (23,456 )   $ 1,223,510  
Costs and expenses:
                                       
Operating costs and expenses
    (12,025 )     779,477       243,507       (23,456 )     987,503  
Depreciation, depletion and amortization
          68,853       8,306             77,159  
Asset retirement obligation expense
          8,049       (655 )           7,394  
Selling and administrative expenses
    1,288       53,753       1,968             57,009  
Other operating income:
                                       
Net gain on disposal or exchange of assets
          (47,516 )     (61 )           (47,577 )
Income from equity affiliates
          (3,803 )     (5,060 )           (8,863 )
Interest expense
    39,163       13,607       5,463       (32,906 )     25,327  
Interest income
    (6,255 )     (22,942 )     (6,927 )     32,906       (3,218 )
     
Income (loss) before income taxes and minority interests
    (22,171 )     109,800       41,147             128,776  
Income tax provision (benefit)
    (18,545 )     24,474       8,785             14,714  
Minority interests
          722                   722  
     
Net income (loss)
  $ (3,626 )   $ 84,604     $ 32,362     $     $ 113,340  
     

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Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Statements of Operations
(Dollars in thousands)
                                         
    Quarter Ended September 30, 2004  
    Parent     Guarantor     Non-Guarantor              
    Company     Subsidiaries     Subsidiaries     Eliminations     Consolidated  
Total revenues
  $     $ 784,385     $ 150,642     $ (16,038 )   $ 918,989  
Costs and expenses:
                                       
Operating costs and expenses
    (1,874 )     633,143       120,387       (16,038 )     735,618  
Depreciation, depletion and amortization
          63,221       6,911             70,132  
Asset retirement obligation expense
          9,615       531             10,146  
Selling and administrative expenses
    354       32,279       990             33,623  
Other operating income:
                                       
Net (gain) loss on disposal or exchange of assets
          (1,795 )     5             (1,790 )
Income from equity affiliates
          (2,645 )                 (2,645 )
Interest expense
    37,201       13,470       1,184       (26,929 )     24,926  
Early debt extinguishment gains
    (556 )                       (556 )
Interest income
    (4,594 )     (17,965 )     (5,454 )     26,929       (1,084 )
     
Income (loss) before income taxes and minority interests
    (30,531 )     55,062       26,088             50,619  
Income tax provision (benefit)
    (11,875 )     9,870       8,938             6,933  
Minority interests
          247                   247  
     
Income (loss) from continuing operations
    (18,656 )     44,945       17,150             43,439  
Loss from discontinued operations, net of taxes
          (2 )                 (2 )
     
Net income (loss)
  $ (18,656 )   $ 44,943     $ 17,150     $     $ 43,437  
     

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Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Statements of Operations
(Dollars in thousands)
                                         
    Nine Months Ended September 30, 2005  
    Parent     Guarantor     Non-Guarantor              
    Company     Subsidiaries     Subsidiaries     Eliminations     Consolidated  
Total revenues
  $     $ 2,723,601     $ 750,258     $ (64,083 )   $ 3,409,776  
Costs and expenses:
                                       
Operating costs and expenses
    (19,416 )     2,228,185       637,173       (64,083 )     2,781,859  
Depreciation, depletion and amortization
          208,239       24,182             232,421  
Asset retirement obligation expense
          23,251       500             23,751  
Selling and administrative expenses
    2,836       128,109       4,495             135,440  
Other operating income:
                                       
Net gain on disposal or exchange of assets
          (94,994 )     (157 )           (95,151 )
Income from equity affiliates
          (13,445 )     (16,096 )           (29,541 )
Interest expense
    114,939       41,337       16,824       (97,012 )     76,088  
Interest income
    (16,349 )     (67,657 )     (19,407 )     97,012       (6,401 )
     
Income (loss) before income taxes and minority interests
    (82,010 )     270,576       102,744             291,310  
Income tax provision (benefit)
    (47,764 )     57,013       20,051             29,300  
Minority interests
          1,526                   1,526  
     
Net income (loss)
  $ (34,246 )   $ 212,037     $ 82,693     $     $ 260,484  
     

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Statements of Operations
(Dollars in thousands)
                                         
    Nine Months Ended September 30, 2004  
    Parent     Guarantor     Non-Guarantor              
    Company     Subsidiaries     Subsidiaries     Eliminations     Consolidated  
Total revenues
  $     $ 2,290,416     $ 367,048     $ (49,411 )   $ 2,608,053  
Costs and expenses:
                                       
Operating costs and expenses
    (1,883 )     1,875,566       318,808       (49,411 )     2,143,080  
Depreciation, depletion and amortization
          189,746       13,246             202,992  
Asset retirement obligation expense
          30,768       1,042             31,810  
Selling and administrative expenses
    910       90,210       2,439             93,559  
Other operating income:
                                       
Net gain on disposal or exchange of assets
          (13,791 )     (354 )           (14,145 )
Income from equity affiliates
          (13,698 )                 (13,698 )
Interest expense
    107,367       73,497       2,515       (112,530 )     70,849  
Early debt extinguishment gains
    (556 )                       (556 )
Interest income
    (47,584 )     (53,746 )     (14,412 )     112,530       (3,212 )
     
Income (loss) before income taxes and minority interests
    (58,254 )     111,864       43,764             97,374  
Income tax provision (benefit)
    (34,056 )     9,594       10,599             (13,863 )
Minority interests
          900                   900  
     
Income (loss) from continuing operations
    (24,198 )     101,370       33,165             110,337  
Loss from discontinued operations, net of taxes
          (2,839 )                 (2,839 )
     
Net income (loss)
  $ (24,198 )   $ 98,531     $ 33,165     $     $ 107,498  
     

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Balance Sheets
(Dollars in thousands)
                                         
    September 30, 2005  
    Parent     Guarantor     Non-Guarantor              
    Company     Subsidiaries     Subsidiaries     Eliminations     Consolidated  
ASSETS
                                       
Current assets
                                       
Cash and cash equivalents
  $ 470,663     $ 2,182     $ 5,896     $     $ 478,741  
Accounts receivable
    5,225       127,647       103,666             236,538  
Inventories
          312,492       56,358             368,850  
Assets from coal trading activities
          85,554                   85,554  
Deferred income taxes
          15,050                   15,050  
Other current assets
    42,446       29,476       12,508             84,430  
 
                             
Total current assets
    518,334       572,401       178,428             1,269,163  
Property, plant, equipment and mine development
          5,954,792       602,996             6,557,788  
Less accumulated depreciation, depletion and amortization
          (1,470,169 )     (73,590 )           (1,543,759 )
Investments and other assets
    4,752,269       366,773       50,155       (4,797,594 )     371,603  
 
                             
Total assets
  $ 5,270,603     $ 5,423,797     $ 757,989     $ (4,797,594 )   $ 6,654,795  
 
                             
 
                                       
LIABILITIES AND STOCKHOLDERS’ EQUITY
                                       
Current liabilities
                                       
Current maturities of long-term debt
  $ 10,000     $ 12,149     $ 882     $     $ 23,031  
Payables and notes payable to affiliates, net
    1,779,560       (2,236,025 )     456,465              
Liabilities from coal trading activities
          67,398                   67,398  
Accounts payable and accrued expenses
    15,362       700,786       93,808             809,956  
 
                             
Total current liabilities
    1,804,922       (1,455,692 )     551,155             900,385  
Long-term debt, less current maturities
    1,313,896       68,715       1,652             1,384,263  
Deferred income taxes
    29,494       366,033       24,094             419,621  
Other noncurrent liabilities
    16,524       1,887,877       7,165             1,911,566  
 
                             
Total liabilities
    3,164,836       866,933       584,066             4,615,835  
Minority interests
          1,685                   1,685  
Stockholders’ equity
    2,105,767       4,555,179       173,923       (4,797,594 )     2,037,275  
 
                             
Total liabilities and stockholders’ equity
  $ 5,270,603     $ 5,423,797     $ 757,989     $ (4,797,594 )   $ 6,654,795  
 
                             

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
Peabody Energy Corporation
Supplemental Condensed Consolidated Balance Sheets
(Dollars in thousands)
                                         
    December 31, 2004  
    Parent     Guarantor     Non-Guarantor              
    Company     Subsidiaries     Subsidiaries     Eliminations     Consolidated  
ASSETS
                                       
Current assets
                                       
Cash and cash equivalents
  $ 373,066     $ 3,496     $ 13,074     $     $ 389,636  
Accounts receivable
    1,611       86,748       105,425             193,784  
Inventories
          290,863       32,746             323,609  
Assets from coal trading activities
          89,165                   89,165  
Deferred income taxes
          15,050       411             15,461  
Other current assets
    19,737       15,971       7,239             42,947  
 
                             
Total current assets
    394,414       501,293       158,895             1,054,602  
Property, plant, equipment and mine development
          5,686,143       428,933             6,115,076  
Less accumulated depreciation, depletion and amortization
          (1,289,947 )     (43,698 )           (1,333,645 )
Investments and other assets
    4,808,202       4,151       33,836       (4,503,630 )     342,559  
 
                             
Total assets
  $ 5,202,616     $ 4,901,640     $ 577,966     $ (4,503,630 )   $ 6,178,592  
 
                             
 
                                       
LIABILITIES AND STOCKHOLDERS’ EQUITY
                                       
Current liabilities
                                       
Current maturities of long-term debt
  $ 5,000     $ 12,971     $ 1,008     $     $ 18,979  
Payables and notes payable to affiliates, net
    2,022,037       (2,357,000 )     334,963              
Liabilities from coal trading activities
          63,565                   63,565  
Accounts payable and accrued expenses
    20,120       599,253       72,227             691,600  
 
                             
Total current liabilities
    2,047,157       (1,681,211 )     408,198             774,144  
Long-term debt, less current maturities
    1,338,465       65,228       2,293             1,405,986  
Deferred income taxes
    5,250       386,351       1,665             393,266  
Other noncurrent liabilities
    18,658       1,852,684       7,353             1,878,695  
 
                             
Total liabilities
    3,409,530       623,052       419,509             4,452,091  
Minority interests
          1,909                   1,909  
Stockholders’ equity
    1,793,086       4,276,679       158,457       (4,503,630 )     1,724,592  
 
                             
Total liabilities and stockholders’ equity
  $ 5,202,616     $ 4,901,640     $ 577,966     $ (4,503,630 )   $ 6,178,592  
 
                             

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Statements of Cash Flows
(Dollars in thousands)
                                 
    Nine Months Ended September 30, 2005  
    Parent     Guarantor     Non-Guarantor        
    Company     Subsidiaries     Subsidiaries     Consolidated  
Cash Flows from Operating Activities
                               
Net cash provided by (used in) operating activities
  $ (114,649 )   $ 469,136     $ 67,682     $ 422,169  
 
                       
 
                               
Cash Flows from Investing Activities
                               
Additions to property, plant, equipment and mine development
          (173,109 )     (173,594 )     (346,703 )
Purchase of mining assets
          (56,500 )           (56,500 )
Additions to advance mining royalties
          (9,061 )           (9,061 )
Investment in joint venture
          (2,000 )           (2,000 )
Proceeds from disposal of assets
          69,353       1,832       71,185  
 
                       
Net cash used in investing activities
          (171,317 )     (171,762 )     (343,079 )
 
                       
 
                               
Cash Flows from Financing Activities
                               
Proceeds from long-term debt
          11,459             11,459  
Payments of long-term debt
    (3,750 )     (11,104 )     (767 )     (15,621 )
Proceeds from stock options exercised
    19,958                   19,958  
Proceeds from employee stock purchases
    3,010                   3,010  
Increase of securitized interests in accounts receivable
                25,000       25,000  
Distributions to minority interests
          (1,750 )           (1,750 )
Dividends paid
    (32,041 )                 (32,041 )
Transactions with affiliates, net
    225,069       (297,738 )     72,669        
 
                       
Net cash provided by (used in) financing activities
    212,246       (299,133 )     96,902       10,015  
 
                       
Net increase (decrease) in cash and cash equivalents
    97,597       (1,314 )     (7,178 )     89,105  
Cash and cash equivalents at beginning of period
    373,066       3,496       13,074       389,636  
 
                       
Cash and cash equivalents at end of period
  $ 470,663     $ 2,182     $ 5,896     $ 478,741  
 
                       

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Statements of Cash Flows
(Dollars in thousands)
                                 
    Nine Months Ended September 30, 2004  
    Parent     Guarantor     Non-Guarantor        
    Company     Subsidiaries     Subsidiaries     Consolidated  
Cash Flows from Operating Activities
                               
Net cash provided by (used in) operating activities
  $ (43,734 )   $ 134,977     $ 61,262     $ 152,505  
 
                       
 
                               
Cash Flows from Investing Activities
                               
Additions to property, plant, equipment and mine development
          (81,666 )     (66,679 )     (148,345 )
Additions to advance mining royalties
          (11,310 )     (250 )     (11,560 )
Acquisitions, net
          (190,940 )     (235,325 )     (426,265 )
Proceeds from disposal of assets
          24,069       554       24,623  
 
                       
Net cash used in investing activities
          (259,847 )     (301,700 )     (561,547 )
 
                       
 
                               
Cash Flows from Financing Activities
                               
Proceeds from long-term debt
    250,000                   250,000  
Payments of long-term debt
    (13,850 )     (13,236 )     (1,663 )     (28,749 )
Net proceeds from equity offering
    383,125                   383,125  
Proceeds from stock options exercised
    19,274                   19,274  
Proceeds from employee stock purchases
    2,343                   2,343  
Increase of securitized interests in accounts receivable
                100,000       100,000  
Payment of debt issuance costs
    (8,922 )                 (8,922 )
Distributions to minority interests
          (818 )           (818 )
Dividends paid
    (22,878 )                 (22,878 )
Transactions with affiliates, net
    (298,710 )     139,993       158,717        
 
                       
Net cash provided by financing activities
    310,382       125,939       257,054       693,375  
 
                       
 
Net increase in cash and cash equivalents
    266,648       1,069       16,616       284,333  
Cash and cash equivalents at beginning of period
    114,575       1,392       1,535       117,502  
 
                       
Cash and cash equivalents at end of period
  $ 381,223     $ 2,461     $ 18,151     $ 401,835  
 
                       
(14) Guarantees
     In the normal course of business, the Company is a party to the following guarantees:
     The Company owns a 30.0% 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. The Company’s maximum reimbursement obligation of $42.8 million is supported by a letter of credit.
     The Company owns a 49.0% interest in a joint venture that operates an underground mine and preparation plant facility in West Virginia. The partners have severally agreed to guarantee the debt of the joint venture, which consists of a $16.4 million loan facility as of September 30, 2005. The total amount of the joint venture’s debt guaranteed by the Company was $8.0 million as of September 30, 2005.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
     The Company has guaranteed the performance of Asset Management Group (“AMG”) under their coal purchase contract with a third party, which has terms extending through December 31, 2006. Default occurs if AMG does not deliver specified monthly tonnage amounts to the third party. In the event of a default, the Company would assume AMG’s obligation to ship coal at agreed prices for the remaining term of the contract. As of September 30, 2005, the maximum potential future payments under this guarantee are approximately $7 million, based on recent spot coal prices. As a matter of recourse in the event of a default, the Company has access to cash held in escrow and the ability to trigger an assignment of AMG’s assets to the Company. Based on these recourse options and the remote probability of non-performance by AMG due to their proven operating history, the Company has valued the liability associated with the guarantee at zero.
     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. The Company also guaranteed bonding for a partnership in which it formerly held an interest as part of an exchange in which the Company obtained strategic Illinois Basin coal reserves (see Note 3). The aggregate amount guaranteed by the Company was $4.4 million, and the fair value of the guarantees recognized as a liability was $0.4 million as of September 30, 2005. The Company’s obligations under the guarantees extend to September 2015.
     The Company is the lessee under numerous equipment and property leases. It is common in such commercial lease transactions for the Company, as the lessee, to agree to indemnify the lessor for the value of the property or equipment leased, should the property be damaged or lost during the course of the Company’s operations. The Company expects that losses with respect to leased property would be covered by insurance (subject to deductibles). The Company and certain of its subsidiaries have guaranteed other subsidiaries’ performance under their various lease obligations. Aside from indemnification of the lessor for the value of the property leased, the Company’s maximum potential obligations under its leases are equal to the respective future minimum lease payments and assume that no amounts could be recovered from third parties.
     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. Supplemental guarantor/non-guarantor financial information is provided in Note 13.
(15) Risk Management and Financial Instruments
     The Company enters into both derivative and non-derivative contracts to manage its exposure to the price volatility of diesel fuel. Fuel costs make up between three and four percent of the Company’s total operating costs and expenses. As of September 30, 2005, the Company had designated derivative contracts as cash flow hedges with notional amounts totaling 69.0 million gallons (44.9 million gallons of heating oil and 24.1 million gallons of crude oil), with maturities extending from the fourth quarter of 2005 through the end of 2007. The condensed consolidated balance sheets as of September 30, 2005 and December 31, 2004 reflect unrealized gains on the derivatives designated as cash flow hedges of $54.2 million and $5.8 million, respectively, which is recorded net of tax provisions of $21.7 million and $2.3 million, respectively, in “Accumulated other comprehensive loss.”
     The Company accounts for its fuel hedge derivative instruments as cash flow hedges, as defined in SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. Under SFAS No. 133, all derivatives designated as hedges that meet certain requirements are granted hedge accounting treatment. Generally, utilizing the hedge accounting, all periodic changes in fair value of the derivatives designated as hedges that are considered to be effective, as defined, are recorded in “Accumulated other comprehensive income (loss)” until the underlying diesel fuel is consumed. However, the Company is exposed to the risk that periodic changes will not be effective, as defined, or that the derivatives will no longer qualify for hedge accounting.
     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, those periodic non-cash changes are recorded as ineffectiveness to “Operating costs and expenses” in the income statement in the period of the change. During the quarter ended

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
September 30, 2005, the Company recognized approximately $0.1 million of lower operating costs and expenses related to the ineffectiveness of its hedges.
     Ineffectiveness is inherent in hedging diesel fuel with derivative positions based on other crude oil related commodities. Due to the volatility in markets for crude oil, and crude oil related products, and the current refining spreads that have widened the price spread between crude oil and other petroleum distillates (such as diesel fuel), the Company is unable to predict the amount of ineffectiveness each period, including the loss of hedge accounting (which could be determined on a derivative by derivative basis or in the aggregate), which may result in increased volatility in the Company’s results.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Cautionary Notice Regarding Forward-Looking Statements
     This report includes statements of our expectations, intentions, plans and beliefs that constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 and are intended to come within the safe harbor protection provided by those sections. These statements relate to future events or our future financial performance, including, without limitation, the section captioned “Outlook.” We use words such as “anticipate,” “believe,” “expect,” “may,” “project,” “will” or other similar words to identify forward-looking statements.
     Without limiting the foregoing, all statements relating to our future outlook, anticipated capital expenditures, future cash flows and borrowings, and sources of funding are forward-looking statements. These forward-looking statements are based on numerous assumptions that we believe are reasonable, but are open to a wide range of uncertainties and business risks and actual results may differ materially from those discussed in these statements. Among the factors that could cause actual results to differ materially are:
    growth of domestic and international coal and power markets;
 
    coal’s market share of electricity generation;
 
    prices of fuels which compete with or impact coal usage, such as oil or natural gas;
 
    future worldwide economic conditions;
 
    economic strength and political stability of countries in which we have operations or serve customers;
 
    weather;
 
    transportation performance and costs, including demurrage;
 
    ability to renew sales contracts;
 
    successful implementation of business strategies;
 
    regulatory and court decisions;
 
    future legislation;
 
    variation in revenues related to synthetic fuel production;
 
    changes in postretirement benefit and pension obligations;
 
    negotiation of labor contracts, employee relations and workforce availability;
 
    availability and costs of credit, surety bonds and letters of credit;
 
    the effects of changes in currency exchange rates;
 
    price volatility and demand, particularly in higher-margin products;
 
    risks associated with customers;
 
    availability and costs of key supplies and commodities such as diesel fuel, steel, explosives and tires;
 
    reductions of purchases by major customers;
 
    geology and equipment risks inherent to mining;
 
    terrorist attacks or threats;
 
    performance of contractors, third party coal suppliers or major suppliers of mining equipment or supplies;
 
    replacement of reserves;
 
    implementation of new accounting standards and Medicare regulations;
 
    inflationary trends, including those impacting materials used in our business;
 
    the effects of interest rate changes;
 
    the effects of acquisitions or divestitures;
 
    changes to contribution requirements to multi-employer benefit funds; and
 
    other factors, including those discussed in Part II, Item 1, “Legal Proceedings.”
     When considering these forward-looking statements, you should keep in mind the cautionary statements in this document and in our other Securities and Exchange Commission (“SEC”) filings, including the more detailed discussion of these factors, as well as other factors that could affect our results, contained in the “Risks Relating to Our Company” section of Item 7 of our 2004 Annual Report on Form 10-K. We do not undertake any obligation to update these statements, except as required by federal securities laws.

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Overview
     We are the largest private sector coal company in the world, with majority interests in 33 active coal operations located throughout all major U.S. coal producing regions and internationally in Australia. We also own a 25.5% interest in Carbones del Guasare, which owns and operates the Paso Diablo Mine in Venezuela, and a 49% interest in an Appalachia joint venture. In the third quarter and first nine months of 2005, we sold 61.6 million and 178.4 million tons of coal, respectively, which are records for the Company. In 2004, we sold 227.2 million tons of coal that accounted for 20% of all U.S. coal sales, and were more than 85% greater than the sales of our closest competitor. According to reports published by the Energy Information Administration, 1.1 billion tons of coal were consumed in the United States in 2004. The Energy Information Administration also published estimates indicating that domestic consumption of coal by electricity generators would grow at a rate of 1.6% per year through 2025. Coal-fueled generation is used in most cases to meet baseload electricity requirements, and coal use generally grows at the pace of electricity growth. In 2004, coal’s share of U.S. electricity generation was approximately 52%.
     Our primary customers are U.S. utilities, which accounted for 90% of our sales in 2004. We typically sell coal to utility customers under long-term contracts (those with terms longer than one year). During 2004, approximately 90% of our sales were under long-term contracts. Our results of operations in the near term can be negatively impacted by poor weather conditions, unforeseen geologic conditions or equipment problems at mining locations, the performance of contractors or third party coal suppliers, by the availability of transportation for coal shipments and the availability and costs of key supplies and commodities such as steel, tires, diesel fuel and explosives. On a long-term basis, our results of operations could be impacted by the availability and prices of competing electricity-generation fuels, our ability to secure or acquire high-quality coal reserves, our ability to 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 conduct business through four principal operating segments: Western U.S. Mining, Eastern U.S. Mining, Australian Mining, and Trading and Brokerage. Our Western U.S. Mining operations consist of our Powder River Basin, Southwest and Colorado operations, and its principal business is the mining, preparation and sale of steam coal, sold primarily to electric utilities. Our Eastern U.S. Mining operations consist of our Appalachia and Midwest operations, and its principal business is the mining, preparation and sale of steam coal, sold primarily to electric utilities, as well as the mining of metallurgical coal, sold to steel and coke producers.
     Geologically, our Western operations mine bituminous and subbituminous coal deposits, and our Eastern operations mine bituminous coal deposits. Our 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). Our Eastern U.S. Mining operations are characterized by a majority of underground mining extraction processes, higher sulfur content and Btu of coal, and lower customer transportation costs (due to shorter shipping distances).
     Our Australian Mining operations consist of four mines. The Burton and North Goonyella mines were acquired in April 2004. We opened the Eaglefield Mine in 2004, which is a surface operation adjacent to, and fulfilling contract tonnages in conjunction with, the North Goonyella underground mine. In addition, we have owned and operated our Wilkie Creek Mine since 2002, which is our only steam coal operation in Australia. We expect to begin production from our Baralaba mine during the fourth quarter of 2005. Baralaba will be a surface operation producing metallurgical coal. Our Australian Mining operations are characterized by surface and underground extraction processes, mining primarily low sulfur, metallurgical coal sold to an international customer base.
     Metallurgical coal represented approximately 5% of our total sales volume and approximately 3% of U.S. sales volume in the nine months ended September 30, 2005. Our mining operations are described in Item 1 of our 2004 Annual Report on Form 10-K.

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     In addition to our mining operations, which comprised 82% of revenues in the third quarter of 2005, we also generated 18% of our revenues from brokering and trading coal. We generate additional income and cash flows by extracting value from our vast natural resource position by selling non-core, idle or reclaimed land holdings and non-strategic mineral interests.
     We continue to pursue the development of coal-fueled generating 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. The projects 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 lessor. The projects we are currently pursuing are as follows: the 1,500 megawatt Prairie State Energy Campus in Washington County, Illinois; the 1,500 megawatt Thoroughbred Energy Campus in Muhlenberg County, Kentucky; and the 300 megawatt Mustang Energy Project near Grants, New Mexico. The plants, 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. The first of these plants would not be operational earlier than mid-2010.
     In February 2005, a group of Midwest rural electric cooperatives and municipal joint action agencies entered into definitive agreements to acquire 47% of the Prairie State Energy Campus project. After an initial appeal was successfully resolved related to the air permit that was issued in January 2005, the Illinois Environmental Protection Agency reissued the air permit on April 28, 2005. The same parties who filed the earlier permit challenge filed a new appeal on June 8, 2005. The Company believes the permit was appropriately issued and expects to prevail in the appeal process.
     In the first quarter of 2005, the Board of Directors, after completing an orderly succession planning process, elected Gregory H. Boyce, President and Chief Operating Officer, to the position of President and Chief Executive Officer, effective January 1, 2006. Chairman and Chief Executive Officer, Irl F. Engelhardt will continue his CEO duties through 2005, and will remain employed as Chairman of the Board on January 1, 2006. Effective March 1, 2005, Mr. Boyce was also elected to the Board of Directors and Chairman of the Executive Committee of the Board.
     Effective March 30, 2005, we implemented a two-for-one stock split on all shares of our common stock. All share and per share amounts in this Quarterly Report on Form 10-Q reflect the stock split. During July 2005, we increased our quarterly dividend 27% to $0.095 per share and our Board of Directors authorized a share repurchase program of up to 5% of the outstanding shares of our common stock. The repurchases may be made from time to time based on an evaluation of our outlook and general business conditions, as well as alternative investment and debt repayment options.
     In July 2005, the Board of Directors elected John F. Turner as an independent director who will serve on the Board’s Nominating and Corporate Governance Committee. Turner is former U.S. Assistant Secretary of State for Oceans and International Environmental and Scientific Affairs (OES) within the State Department and is the past President and Chief Executive Officer of the Conservation Fund, a national nonprofit organization dedicated to public-private partnerships to protect land and water resources. He has also served as the Director of the U.S. Fish and Wildlife Service, with responsibility for increasing wetland protection and establishing 55 National Wildlife Refuges, the most of any administration in the nation’s history.

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Results of Operations
Adjusted EBITDA
     The discussion of our results of operations in 2005 and 2004 below includes references to, and analysis of our segments’ Adjusted EBITDA results. Adjusted EBITDA is defined as income from continuing operations before deducting early debt extinguishment costs, net interest expense, income taxes, minority interests, asset retirement obligation expense and depreciation, depletion and amortization. Adjusted EBITDA is used by management primarily as a measure of our segments’ operating performance. 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 11 to our unaudited condensed consolidated financial statements included in this report.
Recent Acquisitions Impacting Comparability of Results of Operations
     Results in our Western U.S. Mining Operations segment include amounts for our April 15, 2004 acquisition of the Twentymile Mine in Colorado. Results in our Australian Mining Operations segment include amounts for our April 15, 2004 acquisition of the Burton and North Goonyella Mines as well as the opening of the Eaglefield Mine adjacent to the North Goonyella Mine in the fourth quarter of 2004. Our Corporate and Other segment includes results from our December 2004 acquisition of a 25.5% interest in Carbones del Guasare, which owns and operates the Paso Diablo Mine in Venezuela.
Quarter Ended September 30, 2005 Compared to Quarter Ended September 30, 2004
Summary
     Our revenues increased $304.5 million, or 33.1%, to $1,223.5 million in the third quarter of 2005 compared to the prior year. Segment Adjusted EBITDA was $267.0 million in the third quarter of 2005 compared to $205.6 million in the prior year, a 29.8% increase. Third quarter net income of $113.3 million, or $0.84 per share, was 160.9% higher than prior year net income of $43.4 million, or $0.33 per share. The improvements were primarily driven by higher sales prices in nearly every region and for all of our products, particularly metallurgical coal, and by demand-driven volume increases, particularly for our Midwest products and for our ultra-low sulfur Powder River Basin products. In addition, higher gains on property transactions contributed to higher year over year results.
Tons Sold
     The following table presents tons sold by operating segment for the quarters ended September 30, 2005 and 2004:
                                 
    (Unaudited)        
    Quarter Ended September 30,     Increase (Decrease)  
    2005     2004     Tons     %  
    (Tons in millions)                          
Western U.S. Mining Operations
    39.1       37.9       1.2       3.2 %
Eastern U.S. Mining Operations
    13.4       12.3       1.1       8.9 %
Australian Mining Operations
    1.9       2.0       (0.1 )     (5.0 )%
Trading and Brokerage Operations
    7.2       6.5       0.7       10.8 %
 
                         
Total
    61.6       58.7       2.9       4.9 %
 
                         

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Revenues
     The following table presents revenues for the quarters ended September 30, 2005 and 2004:
                                 
    (Unaudited)     Increase  
    Quarter Ended September 30,     to Revenues  
    2005     2004     $     %  
    (Dollars in thousands)                  
Sales
  $ 1,191,282     $ 895,156     $ 296,126       33.1 %
Other revenues
    32,228       23,833       8,395       35.2 %
 
                         
Total revenues
  $ 1,223,510     $ 918,989     $ 304,521       33.1 %
 
                         
     Our revenues increased $304.5 million, or 33.1%, overall compared to the third quarter of 2004. Sales increased $296.1 million, reflecting increases in every segment: Western U.S. Mining ($30.1 million), Eastern U.S. Mining ($105.3 million), Australian Mining ($54.1 million), and Trading & Brokerage ($106.6 million). Western U.S. Mining sales increased primarily due to higher sales prices in the Powder River and Colorado regions and higher volumes at our Powder River operations due to continued higher demand for Powder River Basin coal. Sales price increases overcame the short-term volume impact of a longwall move during the quarter at one of our Colorado operations. Average sales prices for the Western U.S. Mining operations were 4.6% higher during the quarter versus prior year. Sales volumes for the Powder River operations were higher in 2005 compared to the prior year despite the negative impact of transportation from on-going rail maintenance. The restricted transportation capacity impacted all coal producers in the Powder River Basin, and rail capacity is not expected to return to higher levels until late in 2005 as discussed in “Outlook” below. In our Eastern U.S. Mining operations, the recent trend of higher average selling prices continued, rising 20.4% in the third quarter of 2005 compared to prior year. Strong demand for steam and metallurgical coal from the region is driving the higher prices and supporting higher volumes in both Appalachia and the Midwest. The increase in our Australian Mining operations’ sales primarily reflected higher sales prices for metallurgical coal. Volumes for the quarter in Australia were comparable to prior year as production from a new mine offset lower production at one of our metallurgical operations due to poor roof conditions as further discussed in “Segment Adjusted EBITDA” below. Average sales prices in our Australian operations improved 68.2%, reflecting the strong demand for metallurgical coal. Improved Trading and Brokerage sales primarily reflected improved pricing for broker transactions. The $8.4 million increase in other revenues was driven primarily by improved trading revenues in our trading operations.
Segment Adjusted EBITDA
     Our total segment Adjusted EBITDA was $267.0 million for the third quarter of 2005, compared with $205.6 million in the prior year, detailed as follows:
                                 
                    Increase (Decrease) to  
    (Unaudited)     Segmented Adjusted  
    Quarter Ended September 30,     EBITDA  
    2005     2004     $     %  
    (Dollars in thousands)                  
Western U.S. Mining Operations
  $ 104,213     $ 113,874     $ (9,661 )     (8.5 )%
Eastern U.S. Mining Operations
    96,865       54,911       41,954       76.4 %
Australian Mining Operations
    39,780       20,777       19,003       91.5 %
Trading and Brokerage Operations
    26,132       16,053       10,079       62.8 %
 
                         
Total Segment Adjusted EBITDA
  $ 266,990     $ 205,615     $ 61,375       29.8 %
 
                         
     Western U.S. Mining operations’ Adjusted EBITDA decreased $9.7 million, or 8.5%, in the third quarter of 2005 compared to prior year. The decrease was primarily caused by an $8.9 million lower contribution from our Colorado operations due to a longwall move in the third quarter of 2005 (there was no longwall move in the third quarter of 2004) and an additional $3.5 million for rebuilding of equipment while the longwall was idle. Adjusted EBITDA increased $3.7 million in our Powder River operations primarily due to demand-driven sales volume

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increases and higher sales prices. The increase in prices offset higher per ton costs resulting from higher materials costs (including fuel and tires) and the impact of fixed costs over lower than anticipated volume. Costs were also negatively impacted by higher revenue-based production and sales taxes. Gains from our fuel hedging program offset most of the increase in fuel prices during the quarter. The Southwest operations’ results were comparable with prior year.
     Eastern U.S. Mining operations’ Adjusted EBITDA increased $42.0 million compared to third quarter of prior year, primarily driven by higher sales prices for metallurgical and steam coal in our Appalachia operations. Adjusted EBITDA in our Appalachia operations increased principally as a result of quarter over quarter sales price increases of 36% (over 75% for metallurgical coal). Overall, volumes were higher than prior year, although one metallurgical mine experienced lower production during the quarter that will extend into the first quarter of 2006 as the operation engages in development of a new longwall mining area. Results in our Midwest operations were higher than prior year benefiting from higher volumes and prices which offset higher fuel and dragline repair costs. Also, gains from our fuel hedging program offset a significant portion of the increase in fuel prices during the quarter.
     Australian Mining operations’ Adjusted EBITDA increased $19.0 million in the third quarter of 2005 compared to the prior year. Improved results were mainly driven by sales price increases of over 68% quarter over quarter. Current year results benefited from strong sales prices, but were negatively impacted by poor roof conditions that interrupted production on the longwall and a subsequent roof fall that curtailed operations during the month of September at our underground metallurgical coal operation. Continued high demurrage costs and timing of vessel loadings also negatively impacted results.
     Trading and Brokerage operations’ Adjusted EBITDA increased $10.1 million versus the third quarter of 2004, due to improved brokerage margins, higher prices and trading volumes and the positive effect of settlement of a contractual dispute with one of our coal suppliers, as discussed in Note 3 to our unaudited condensed consolidated financial statements.
Income Before Income Taxes And Minority Interests
                                 
    (Unaudited)     Increase (Decrease) to  
    Quarter Ended September 30,     Income  
    2005     2004     $     %  
    (Dollars in thousands)                  
Total Segment Adjusted EBITDA
  $ 266,990     $ 205,615     $ 61,375       29.8 %
 
                               
Corporate and Other Adjusted EBITDA
    (31,552 )     (51,432 )     19,880       38.7 %
Depreciation, depletion and amortization
    (77,159 )     (70,132 )     (7,027 )     (10.0 )%
Asset retirement obligation expense
    (7,394 )     (10,146 )     2,752       27.1 %
Interest expense
    (25,327 )     (24,926 )     (401 )     (1.6 )%
Early debt extinguishment gains
          556       (556 )     n/a  
Interest income
    3,218       1,084       2,134       196.9 %
 
                         
Income before income taxes and minority interests
  $ 128,776     $ 50,619     $ 78,157       154.4 %
 
                         
     Income before income taxes and minority interests increased $78.2 million versus the third quarter of 2004, primarily due to improved segment Adjusted EBITDA results. Corporate and Other Adjusted EBITDA improved by 38.7% and asset retirement obligation expense was lower, partially offset by an increase in depreciation, depletion and amortization.

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     Corporate and Other Adjusted EBITDA results include selling and administrative expenses, equity income from our Venezuelan joint venture, 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 coalbed methane, generation development and resource management. The $19.9 million improvement of Corporate and Other results included:
    higher gain on disposal or exchange of assets of $45.8 million, primarily related to:
    a $37.4 million gain on settlement of a contract dispute with a third-party coal supplier; and
 
    a $6.2 million gain from an asset exchange where we acquired strategic Illinois Basin coal reserves for non-strategic reserves, our interest in a joint venture and monetary consideration (see Note 3); and
    income in 2005 of $5.1 million from a 25.5% interest in Carbones del Guasare, acquired in December 2004, which owns and operates the Paso Diablo Mine in Venezuela.
These improvements were partially offset by the following items:
    a $6.9 million increase in past mining obligations expense, primarily related to higher retiree health care costs. The increase in retiree health care costs was primarily associated with actuarial assumptions such as higher trend rates, lower interest discount assumptions and higher amortization of actuarial losses in 2005; and
 
    a $23.4 million increase in selling and administrative expenses primarily related to an increase in performance-based incentives ($19.6 million), principally long-term plans that are driven by total shareholder returns. Our share price increased 62% during the quarter and 184% in the last twelve months, significantly outperforming market benchmarks and the peer group. The remaining increase is from higher outside services costs related to support services, acquisitions and regulatory compliance.
     Depreciation, depletion and amortization increased $7.0 million in 2005 primarily due to increased production volumes in 2005.
Net Income
                                 
    (Unaudited)     Increase (Decrease) to  
    Quarter Ended September 30,     Income  
    2005     2004     $     %  
    (Dollars in thousands)                  
Income before income taxes and minority interests
  $ 128,776     $ 50,619     $ 78,157       154.4 %
 
                               
Income tax provision
    (14,714 )     (6,933 )     (7,781 )     (112.2 )%
Minority interests
    (722 )     (247 )     (475 )     (192.3 )%
 
                         
Income from continuing operations
    113,340       43,439       69,901       160.9 %
Loss from discontinued operations, net of taxes
          (2 )     2       n/a  
 
                         
Net income
  $ 113,340     $ 43,437     $ 69,903       160.9 %
 
                         
     Our net income increased $69.9 million, or 160.9%, in the third quarter of 2005 compared to prior year due to the increase in income before income taxes and minority interests discussed above, partially offset by an increase in the income tax provision. The income tax provision in 2005 is higher than prior year primarily as a result of higher pretax income.

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Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004
Summary
     Our revenues increased $801.7 million to $3,409.8 million for the first nine months of 2005, a 30.7% increase over the prior year. The increase in revenue was primarily due to improved pricing in all regions, increased sales volumes from strong demand at domestic and international mining operations and the benefit of mining operations acquired during 2004. Segment Adjusted EBITDA was $738.9 million for the first nine months of 2005 compared to $550.3 million in the prior year, a 34.3% increase. Net income of $260.5 million, or $1.95 per share, was 142.3% higher in the first nine months of 2005, compared to $107.5 million, or $0.86 per share, in the prior year. The improvements were primarily due to greater demand-driven volume, improved sales prices and the impact of mining operations acquired in 2004. In addition, higher gains on property transactions contributed to higher year over year results.
Tons Sold
     The following table presents tons sold by operating segment for the nine months ended September 30, 2005 and 2004:
                                 
    (Unaudited)        
    Nine Months Ended September 30,     Increase (Decrease)  
    2005     2004     Tons     %  
    (Tons in millions)                  
Western U.S. Mining Operations
    114.5       105.4       9.1       8.6 %
Eastern U.S. Mining Operations
    39.5       37.5       2.0       5.3 %
Australian Mining Operations
    6.0       4.1       1.9       46.3 %
Trading and Brokerage Operations
    18.4       20.5       (2.1 )     (10.2 )%
 
                         
Total
    178.4       167.5       10.9       6.5 %
 
                         
Revenues
     The following table presents revenues for the nine months ended September 30, 2005 and 2004:
                                 
    (Unaudited)     Increase (Decrease)  
    Nine Months Ended September 30,     to Revenues  
    2005     2004     $     %  
    (Dollars in thousands)                  
Sales
  $ 3,343,620     $ 2,538,189     $ 805,431       31.7 %
Other revenues
    66,156       69,864       (3,708 )     (5.3 )%
 
                         
Total revenues
  $ 3,409,776     $ 2,608,053     $ 801,723       30.7 %
 
                         
     Our total revenues increased $801.7 million, or 30.7%, to $3,409.8 million compared to the first nine months of 2004, driven by increased pricing in all regions and higher overall volume. The three mines we acquired in the second quarter of 2004 contributed approximately $259.0 million to the increase in revenues. The remaining $542.7 million increase is primarily attributable to increases in average sales prices and volumes across all mining segments, particularly in the Powder River Basin, where strong demand continues to drive expansion of our operating capacity. Volume in our Trading and Brokerage segment was lower than prior year, but was more than offset by higher pricing in 2005.
     Sales increased $805.4 million in the first nine months of 2005, reflecting increases in every segment: Western U.S. Mining ($167.3 million), Eastern U.S. Mining ($249.0 million), Australian Mining ($216.8 million), and Trading and Brokerage ($172.3 million). Increases in average per ton selling prices continued, rising 6.7% and 18.0% in our Western U.S. and Eastern U.S. Mining operations, respectively, in the first nine months of 2005 compared to prior year. The 16.4% increase in sales for our Western U.S. Mining operations was primarily

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attributable to the 2004 acquisition of the Twentymile Mine and to increases in both sales price and volume in the Powder River Basin. Production in the Powder River Basin increased 6.7 million tons, or 7.8%, compared to the prior year in response to overall higher demand, overcoming train derailments, weather and track maintenance disruptions on the main shipping line out of the basin. Eastern U.S. Mining operations’ sales increased 24.0% compared with prior year due to improved pricing in Appalachia that resulted from strong steam and metallurgical coal demand, and higher volume and prices in the Midwest. The increase in Australian Mining operations’ sales was due to significantly higher prices for metallurgical coal in 2005 and the contribution from higher volumes due to the acquisition of two mines and the startup of our Eaglefield surface mine in 2004. Trading and Brokerage sales were up $172.3 million on higher pricing. Other revenues were comparable with the prior year.
Segment Adjusted EBITDA
     Our total segment Adjusted EBITDA was $738.9 million for the first nine months of 2005, compared with $550.3 million in the prior year, detailed as follows:
                                 
                    Increase (Decrease) to  
    (Unaudited)     Segmented Adjusted  
    Nine Months Ended September 30,     EBITDA  
    2005     2004     $     %  
    (Dollars in thousands)                  
Western U.S. Mining Operations
  $ 330,277     $ 297,631     $ 32,646       11.0 %
Eastern U.S. Mining Operations
    287,569       182,332       105,237       57.7 %
Australian Mining Operations
    101,345       33,655       67,690       201.1 %
Trading and Brokerage Operations
    19,703       36,728       (17,025 )     (46.4 )%
 
                         
Total Segment Adjusted EBITDA
  $ 738,894     $ 550,346     $ 188,548       34.3 %
 
                         
     Western U.S. Mining operations’ Adjusted EBITDA increased $32.6 million, or 11.0%, in the first nine months of 2005 compared to prior year. The increase reflected improvements in our Powder River Basin operations and the addition of the Twentymile Mine to our Colorado operations in April 2004 and increased productivity from its operations. The improvement at our Powder River operations was due to higher prices, leading to a 21.1% increase in per ton margin, and a 7.8% volume increase in response to increased demand. In 2005, third quarter volumes reached record levels after sequentially decreasing in the second quarter due to constraints on the region’s rail system. Improved revenues overcame increased unit costs that resulted from higher fuel costs, lower than anticipated volume due to rail difficulties and an increase in revenue-based royalties and production taxes. Improvements in the Powder River Basin and Colorado overcame a decrease in Adjusted EBITDA for our Southwest operations due to a $16.2 million allowance that was established relative to disputed receivables (discussed in Note 12 to our unaudited condensed consolidated financial statements).
     In the first quarter, we recorded approximately $9.5 million of operating expenses related to pension curtailment charges at our Black Mesa and Seneca mines, which are expected to close during 2005. The impact to Western U.S. Mining operations’ segment Adjusted EBITDA was not significant as the majority of these curtailment costs are billable under current supply agreements. Through the third quarter of 2005, $8.5 million had been billed to customers.
     Eastern U.S. Mining operations’ Adjusted EBITDA increased $105.2 million in the first nine months of 2005 compared to prior year, primarily driven by higher sales prices for metallurgical and steam coal. Adjusted EBITDA in our Appalachia operations increased principally as a result of sales price increases of 31.9% in 2005, partially offset by lower production at two of our mines and higher costs related to geologic issues, contract mining, and roof support. The results in our Midwest operations were improved compared to the prior year results, as the benefits of higher volumes and prices were partially offset by higher operating costs due to the impact of heavy rainfall on surface operations in the first quarter and higher fuel, repair and maintenance costs.

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     Australian Mining operations’ Adjusted EBITDA increased $67.7 million in the first nine months of 2005 compared to the prior year. Volumes in Australia increased 46.3% primarily due to the acquisition of two metallurgical coal mines and the opening of a new surface operation at the end of 2004. Current year margins also benefited from strong sales prices, but margin growth was limited by the impact of port congestion, related demurrage costs and higher costs due to geological problems at the underground mine.
     Trading and Brokerage operations’ Adjusted EBITDA decreased $17.0 million compared with the prior year, primarily related to less favorable trading results in 2005 compared to 2004. The first nine months of 2005 includes a net charge of $7.5 million, primarily related to the breach of a coal supply contract by a producer (see Note 3 to our unaudited condensed consolidated financial statements).
Income Before Income Taxes And Minority Interests
                                 
    (Unaudited)     Increase (Decrease) to  
    Nine Months Ended September 30,     Income  
    2005     2004     $     %  
    (Dollars in thousands)                  
Total Segment Adjusted EBITDA
  $ 738,894     $ 550,346     $ 188,548       34.3 %
 
                               
Corporate and Other Adjusted EBITDA
    (121,725 )     (151,089 )     29,364       19.4 %
Depreciation, depletion and amortization
    (232,421 )     (202,992 )     (29,429 )     (14.5 )%
Asset retirement obligation expense
    (23,751 )     (31,810 )     8,059       25.3 %
Interest expense
    (76,088 )     (70,849 )     (5,239 )     (7.4 )%
Early debt extinguishment gains
          556       (556 )     n/a  
Interest income
    6,401       3,212       3,189       99.3 %
 
                         
Income before income taxes and minority interests
  $ 291,310     $ 97,374     $ 193,936       199.2 %
 
                         
     Income before income taxes and minority interests increased $193.9 million compared with the first nine months of 2004, primarily due to improved segment Adjusted EBITDA results, improved Corporate and Other Adjusted EBITDA, and lower asset retirement obligation expense, partially offset by increases in depreciation, depletion and amortization and interest expense.
     Corporate and Other Adjusted EBITDA results include selling and administrative expenses, equity income from our Venezuelan joint venture, 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 coalbed methane, generation development and resource management. The $29.4 million improvement in Corporate and Other results included:
    higher gains on disposal or exchange of assets of $81.0 million primarily related to settlement of a contract dispute with a third-party coal supplier (see Note 3), Penn Virginia (“PVR”) unit sales, three resource sales involving non-strategic coal assets and properties ($12.5 million), and an asset exchange in which we acquired Illinois Basin coal reserves in exchange for a) coal reserves, b) our interest in a joint venture and c) monetary consideration. In 2005, we also realized a $31.1 million gain from the sale of all of our remaining 0.838 million PVR units compared to a gain of $9.9 million on the sale of 0.575 million PVR units in 2004;
 
    income in 2005 of $16.1 million from our 25.5% interest in Carbones del Guasare (acquired in December 2004), which owns and operates the Paso Diablo Mine in Venezuela; and
 
    lower net expenses related to generation development of $4.8 million, primarily due to reimbursements from the Prairie State Energy Campus partnership group.

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These improvements were offset by the following items:
    an increase in past mining obligations expense of $28.8 million, primarily related to higher retiree health care costs. The increase in retiree health care costs was actuarially driven by higher trend rates, lower interest discount assumptions and higher amortization of actuarial losses in 2005; and
 
    a $41.9 million increase in selling and administrative expenses primarily related to higher performance-based incentives ($30.0 million), principally long-term plans that are driven by total shareholder returns. Our share price increased 109% during the first nine months of 2005, significantly outperforming benchmarks and the peer group. The remaining increase is from higher personnel and outside services costs, which are being driven by support services, acquisitions and regulatory compliance.
     Depreciation, depletion and amortization increased $29.4 million in 2005 with approximately 54% of the increase due to acquisitions made in 2004 and the remainder of the increase due primarily to improved volume at existing mines in 2005. Asset retirement obligation expense decreased $8.1 million due to expenses in 2004 related to the acceleration of planned reclamation of certain closed mine sites. Interest expense increased $5.2 million primarily related to the issuance of $250 million of 5.875% Senior Notes in late March of 2004 and increases in the cost of floating rate debt due to higher interest rates.
Net Income
                                 
    (Unaudited)     Increase (Decrease) to  
    Nine Months Ended September 30,     Income  
    2005     2004     $     %  
    (Dollars in thousands)                  
Income before income taxes and minority interests
  $ 291,310     $ 97,374     $ 193,936       199.2 %
 
                               
Income tax (provision) benefit
    (29,300 )     13,863       (43,163 )     n/a  
Minority interests
    (1,526 )     (900 )     (626 )     (69.6 )%
 
                         
Income from continuing operations
    260,484       110,337       150,147       136.1 %
Loss from discontinued operations, net of taxes
          (2,839 )     2,839       n/a  
 
                         
Net income
  $ 260,484     $ 107,498     $ 152,986       142.3 %
 
                         
     Net income increased $153.0 million, or 142.3%, compared to the first nine months of 2004 due to the increase in income before income taxes and minority interests discussed above, partially offset by an increase in the income tax provision. The income tax provision recorded in 2005 differs from the benefit in 2004 primarily as a result of higher pretax income and a positive effective tax rate in 2005, which is driven by the magnitude of the percentage depletion deduction relative to pretax income.
Outlook
Events Impacting Near-Term Operations
     Shipments from our Powder River mines were lower than expected in the second quarter and to a lesser extent in the third quarter of 2005 due to a six-month remedial maintenance program undertaken by the two railroad companies serving the Powder River Basin. The maintenance and repairs are expected to continue in late 2005 and into 2006. We expect these repairs may restrict shipments from our Powder River operations for the remainder of the current year, but continue to anticipate record shipment levels in 2005 and even higher levels in 2006.
     Metallurgical coal production from our Appalachia operations is expected to be lower than prior year periods through the first quarter of 2006 as a metallurgical coal mine in the U.S. continues development work on a new section. The longwall at the existing mine has depleted the final panel of available reserves in its current location and is relocating to a reserve extension in the first half of 2006.

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     Our underground metallurgical coal mine in Australia is experiencing difficult geologic conditions that are expected to continue disrupting production in the near term. In the first quarter of 2006, we plan to install longwall replacement equipment with better roof control and cutting capabilities. In the interim, we plan to meet our shipping commitments from this mine by supplementing its output with production from our newly-opened, adjacent surface operation. In May 2005, we were notified of a reduced port allocation that is aimed at improving the loading of vessels and reducing demurrage at the main port for our Australian coal operations. Although port congestion has been reduced, high demurrage costs and unpredictable timing of vessel loading could continue to impact future results.
Outlook Overview
     Our outlook for the coal markets remains positive. We believe strong coal markets will continue worldwide, as long as growth continues in the U.S., Asia and other industrialized economies that are increasing coal demand for electricity generation and steelmaking. The U.S. economy grew at an annual rate of 3.3% in the second quarter of 2005 as reported by the U.S. Commerce Department, and China’s economy grew 9.5% as published by the National Bureau of Statistics of China. Strong demand for coal and coal-based electricity generation in the U.S. is being driven by the growing economy, low customer stockpiles, favorable weather, capacity constraints of nuclear generation and high prices of natural gas and oil. The high price of natural gas is leading some coal-fueled generating plants to operate at increased levels. U.S. coal inventories at quarter end remained at levels well below the five-year average. Primarily due to a 26% increase in cooling degree days, U.S. electricity generation increased by 8.2% in the third quarter of 2005 compared to the same period in the prior year and increased 3.4% for the first nine months year-over-year according to the Edison Electric Institute.
     Demand for Powder River Basin coal is increasing, particularly for our ultra-low sulfur products. The Powder River Basin represents more than half of our production, and the published reference price for high-Btu, ultra-low sulfur Powder River Basin coal has increased. We control approximately 3.4 billion tons of proven and probable reserves in the Southern Powder River Basin and sold 115.8 million tons of coal from this region during the year ended December 31, 2004, and 92.9 million tons through the first nine months of 2005. Metallurgical coal is selling at a significant premium to steam coal and metallurgical markets remain strong with global steel production growing 6% to 7% in 2005. We expect to capitalize on the strong global market for metallurgical coal primarily through a portion of our Appalachia operations and our Australian operations, which produce mainly metallurgical coal.
     We continue to target 2005 production of 210 million to 220 million tons and total sales volume of 240 million to 250 million tons, including 12 to 14 million tons of metallurgical coal. As of September 30, 2005, we are essentially sold out of our planned 2005 production.
     Management expects strong market conditions and operating performance to overcome external cost pressures, geologic conditions and adverse port and rail performance. We are experiencing increases in operating costs related to fuel, explosives, steel, tires and healthcare, and have taken measures to mitigate the increases in these costs. Portions of the recent increase in materials costs have been due to weather-related supply disruptions in the Gulf of Mexico. In addition, historically low long-term interest rates also have a negative impact on expenses related to our actuarially determined, employee-related liabilities. We may also encounter poor geologic conditions, lower third party contract miner or brokerage source 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” for additional considerations regarding our outlook.
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, interest costs and costs related to past mining obligations as well as planned 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, among other things, are subject to limitations imposed by our 6.875% Senior Notes, 5.875% Senior Notes and Senior Secured Credit Facility covenants. We typically fund all of our capital expenditure

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requirements with cash generated from operations, and during 2004 and the first nine months of 2005, have had no borrowings outstanding under our $900.0 million revolving line of credit, which we use primarily for standby letters of credit. As of September 30, 2005, we had letters of credit outstanding under the facility of $409.9 million, leaving $490.1 million available for borrowing. This provides us with available borrowing capacity under the line of credit to fund strategic acquisitions or meet other financing needs. We were in compliance with all of the covenants of the Senior Secured Credit Facility, the 6.875% Senior Notes and the 5.875% Senior Notes as of September 30, 2005. On May 9, 2005, we filed a shelf registration statement on Form S-3 with the SEC, which was declared effective in June 2005. The universal shelf registration statement permits us to offer and sell from time to time up to an aggregate maximum of $3 billion of securities, including common stock, preferred stock, debt securities, warrants and units. As of September 30, 2005, no securities have been issued under the universal shelf registration statement, which remains effective.
     Net cash provided by operating activities was $422.2 million in the first nine months of 2005, an increase of $269.7 million, or 176.8%, from the first nine months of 2004. The increase was primarily driven by stronger operational performance in 2005, as net income increased $153.0 million from the prior year. Also contributing to the increase was lower funding of pension plans, as we voluntarily pre-funded $50.0 million in the prior year. The remainder of the increase was primarily due to higher working capital cash flows of $25.4 million.
     Net cash used in investing activities was $343.1 million during the first nine months of 2005 compared to $561.5 million used in 2004. Capital expenditures were $346.7 million in the first nine months of 2005, an increase of $198.4 million over prior year. Included in the 2005 capital expenditures was a $63.5 million payment for the 327 million ton West Roundup federal coal reserve lease in the Powder River Basin, which was awarded to us in February 2005. The 2005 capital expenditures also included expenditures for Twentymile mine longwall equipment, expenditures for longwall components and other projects at our Australian mines, the acquisition of new coal reserves, and the opening of new mines and upgrading of existing mines in the Midwest. Investing activities in 2005 also reflected $56.5 million in capital expenditures for mining assets acquired from Lexington Coal Company, including 70 million tons of Illinois and Indiana coal reserves, surface properties and equipment. Proceeds from the disposal of assets increased $46.6 million primarily due to higher proceeds in 2005 from the sale of PVR units and non-strategic property, reserves and equipment. In 2004, we acquired the Twentymile mine in Colorado and two mines in Australia for $421.3 million and made a $5.0 million earn-out payment related to our April 2003 acquisition of the remaining minority interest in Black Beauty Coal Company.
     Net cash provided by financing activities was $10.0 million during the first nine months of 2005 compared to $693.4 million in the prior year, with the decrease primarily related to the 2004 issuance of 17.6 million shares of common stock at $22.50 per share, netting proceeds of $383.1 million; issuance of $250 million of 5.875% Senior Notes due in 2016; and the payment of debt issuance costs of $8.9 million in connection with the acquisition of the three mines discussed above. During the first nine months of 2005 and 2004, we made scheduled payments on our long-term debt of $15.6 and $28.7 million, respectively. Securitized interest in accounts receivable increased by $25.0 million in the first nine months of 2005 compared to an increase of $100.0 million in 2004. We paid dividends of $32.0 million and $22.9 million in the first nine months of 2005 and 2004, respectively. In September 2005, we issued $11.5 million in notes payable as part of an asset exchange in which we acquired additional Illinois Basin coal reserves.

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Contractual Obligations
     The following table updates, as of September 30, 2005, our contractual coal reserve lease and royalty obligations presented in our 2004 Annual Report on Form 10-K. These obligations have changed due to the Federal Coal Lease bid that we won in February 2005. The first payment of $63.5 million on this lease was made during the first quarter of 2005, and future payments of the same amount will be due annually through 2009.
                                 
    Payments Due by Year  
    Within     2-3     4-5     After  
(Dollars in thousands)   1 Year     Years     Years     5 Years  
                                 
Coal reserve lease and royalty obligations
  $ 142,575     $ 401,642     $ 334,736     $ 52,996  
     At September 30, 2005, we had $332.0 million of purchase obligations related to capital expenditures, of which $312.7 million is for 2005 and 2006. Commitments for coal reserve-related expenditures, including Federal Coal Leases, are included in the table above. Total projected capital expenditures for calendar year 2005 are approximately $450 million to $500 million. Approximately 50% of projected 2005 capital expenditures relate to the Federal Coal Leases and longwall equipment at the Twentymile Mine and longwall replacement components in Australia, and the remainder is expected to be used to purchase or develop reserves, replace or add equipment, fund cost reduction initiatives and upgrade equipment and facilities at recently acquired operations. We have and expect to continue funding these capital expenditures primarily through operating cash flow.
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.
     In March 2000, we established an accounts receivable securitization program. Under the program, undivided interests in a pool of eligible trade receivables that have been 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 used proceeds from the sale of the accounts receivable to repay long-term debt, effectively reducing our overall borrowing costs. The securitization program is scheduled to expire in September 2009, and the maximum amount of undivided interests in accounts receivable that may be sold to the Conduit is $225.0 million. The securitization transactions have been recorded as sales, with those accounts receivable sold to the Conduit removed from the consolidated balance sheet. In the third quarter of 2005, we renegotiated certain terms of the program, including lowering the program pricing, removing a minimum balance requirement and adding the ability to issue letters of credit under the program. We expect the new program terms to result in annual savings of approximately $2 million. The amount of undivided interests in accounts receivable sold to the Conduit was $225.0 million and $200.0 million as of September 30, 2005 and December 31, 2004, respectively.
     There were no other material changes to our off-balance sheet arrangements during the nine months ended September 30, 2005. Material off-balance sheet arrangements are discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2004. See Note 14 to our unaudited condensed consolidated financial statements included in this report for a discussion of our guarantees.

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Other
Labor Agreements
     The miners at our Burton mine in Australia have agreed to a new labor agreement that expires on June 9, 2008. The Western Surface Agreement of 2000, which applies to hourly workers at two mines in Arizona and one of our Colorado mines, was extended during the third quarter of 2005 for an additional two years and expires on September 1, 2007.
Risks Related to Contract Miners and Brokerage Sources
     In conducting our trading, brokerage and mining operations, we utilize third party sources of coal production, including contract miners and brokerage sources, to fulfill deliveries under our coal supply agreements. Recently, certain of our brokerage sources and contract miners have experienced adverse geologic mining and/or financial difficulties that have made their delivery of coal to us at the contractual price difficult or uncertain. Our profitability or exposure to loss on transactions or relationships such as these is dependent upon the reliability (including financial viability) and price of the third-party supply, our obligation to supply coal to customers in the event that adverse geologic mining conditions restrict deliveries from our suppliers, our willingness to participate in temporary cost increases experienced by our third-party coal suppliers, our ability to pass on temporary cost increases to our customers, the ability to substitute, when economical, third-party coal sources with internal production or coal purchased in the market, and other factors.
Mohave Generating Station
     See Note 12 to our unaudited condensed consolidated financial statements included in this report relating to the suspension of the operations of our Black Mesa Mine and the Mohave Generating Station on December 31, 2005.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
     The potential for changes in the market value of our coal trading, interest rate and currency portfolios is referred to as “market risk.” Market risk related to our coal trading 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 and currency 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. 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 at September 30, 2005 and December 31, 2004.
     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 both option and forward positions. Our value at risk model assumes a 15-day holding period and a 95% one-tailed

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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.
     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. 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 our value at risk and to better reflect current asset and liability volatilities. Given our reliance on historical data, 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 nine months ended September 30, 2005, the actual low, high, and average values at risk for our coal trading portfolio were $1.3 million, $3.9 million, and $2.5 million, respectively. As of September 30, 2005, the timing of the estimated future realization of the value of the Company’s trading portfolio was as follows:
         
Year of   Percentage  
Expiration   of Portfolio  
2005
    48 %
2006
    42 %
2007
    10 %
 
     
 
    100 %
 
     
     We also monitor other types of risk associated with our coal trading activities, including credit, market liquidity and counterparty nonperformance.
Credit Risk
     Our concentration of credit risk is substantially with energy producers and marketers, electric utilities, steel producers, and financial institutions. Our policy is to independently evaluate each customer’s creditworthiness prior to entering into transactions and to constantly monitor the credit extended. In the event that we engage in a transaction with a counterparty that does not meet our credit standards, we generally seek to protect our position by requiring the counterparty to provide appropriate credit enhancement. When appropriate (as determined by our credit management function), we have taken steps to reduce our credit exposure to customers or counterparties whose credit has deteriorated and who may pose a higher risk of failure to perform under their contractual obligations. These steps include obtaining letters of credit or cash collateral, requiring prepayments for shipments or the creation of customer trust accounts held for our benefit to serve as collateral in the event of a failure to pay. To reduce our credit exposure related to trading and brokerage activities, we seek to enter into netting agreements with counterparties that permit us to offset receivables and payables with such counterparties. Counterparty risk with respect to interest rate swap, foreign currency forwards and options transactions, and fuel hedging derivatives is not considered to be significant based upon the creditworthiness of the participating financial institutions.
Foreign Currency Risk
     We utilize currency forwards and options to hedge currency risk associated with anticipated Australian dollar expenditures. Our currency hedging program for the remainder of 2005 involves hedging approximately 75% of our anticipated, non-capital Australian dollar-denominated expenditures and portions of our near-term capital expenditures. As of September 30, 2005, we had in place forward contracts designated as cash flows hedges with Australian dollar-denominated notional amounts outstanding totaling $735 million, of which $96 million, $371 million, $184 million, and $84 million will expire in 2005, 2006, 2007 and 2008, respectively. Our current expectation for the fourth quarter

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2005 non-capital, Australian dollar-denominated cash expenditures is approximately $120 million. A change in the Australian dollar/U.S. dollar exchange rate of US$0.01 (ignoring the effects of hedging) would result in an increase or decrease in our operating costs of $4.8 million per year.
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. As of September 30, 2005, after taking into consideration the effects of interest rate swaps, we had $859.8 million of fixed-rate borrowings and $547.5 million of variable-rate borrowings outstanding. A one-percentage point increase in interest rates would result in an annualized increase to interest expense of $5.5 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 $53.8 million decrease in the estimated fair value of these borrowings.
Other Non-trading Activities
     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% of our sales volume under long-term coal supply agreements during 2004 and 2003. As of September 30, 2005, we are essentially sold out of our planned 2005 production. Also as of September 30, 2005, we had 20 to 30 million tons, 95 to 105 million tons and 165 to 175 million tons of expected production available for sale or repricing at market prices for 2006, 2007 and 2008, respectively. We have an annual metallurgical coal production capacity of 12 to 14 million tons, all of which is priced for 2005 and approximately 50% of which is priced for 2006.
     Some of the products used in our mining activities, such as diesel fuel and explosives, are subject to commodity price risk. To manage some of this risk, we use a combination of forward contracts with our suppliers and financial derivative contracts, primarily swap contracts with financial institutions. In addition, we utilize derivative contracts to hedge some of our commodity price exposure. As of September 30, 2005, we had derivative contracts outstanding that are designated as cash flow hedges of anticipated purchases of fuel. Notional amounts outstanding under these contracts, scheduled to expire through 2007, were 44.9 million gallons of heating oil and 24.1 million gallons of crude oil. Overall, we have fixed prices for approximately 90% of our anticipated diesel fuel requirements in 2005.
     We expect to consume 95 to 100 million gallons of fuel per year. On a per gallon basis, based on this usage, a change in fuel prices of one cent per gallon (ignoring the effects of hedging) would result in an increase or decrease in our operating costs of approximately $1 million per year. Alternatively, a one dollar per barrel change in the price of crude oil would increase or decrease our annual fuel costs (ignoring the effects of hedging) by approximately $2.3 million.
Item 4. Controls and Procedures.
     Our disclosure controls and procedures are designed to, among other things, provide reasonable assurance that material information, both financial and non-financial, and other information required under the securities laws to be disclosed is identified and communicated to senior management on a timely basis. Under the direction of the Chief Executive Officer and Executive Vice President and Chief Financial Officer, management has evaluated our disclosure controls and procedures as of September 30, 2005 and has concluded that the disclosure controls and procedures were effective.
     Additionally, during the most recent fiscal quarter, there have been no changes to our internal control over financial reporting that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II — OTHER INFORMATION
Item 1. Legal Proceedings.
     See Note 12 to the unaudited condensed consolidated financial statements included in Part I, Item 1 of this report relating to certain legal proceedings, including proceedings brought against us by the Navajo Nation, the Hopi and Quapaw Tribes, two class action lawsuits brought on behalf of the residents of the towns of Cardin, Quapaw and Picher, Oklahoma and natural resource damage claims asserted by Oklahoma and several other parties, which is incorporated by reference herein. See Part I, Item 3, “Legal Proceedings” in our 2004 Annual Report on Form 10-K for a discussion of our legal proceedings.
Item 6. Exhibits.
     See Exhibit Index at page 47 of this report.

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SIGNATURE
     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
         
  PEABODY ENERGY CORPORATION
 
 
Date: November 8, 2005  By:   /s/ RICHARD A. NAVARRE    
    Richard A. Navarre   
    Executive Vice President and Chief Financial Officer
(On behalf of the registrant and as Principal Financial Officer) 
 
 

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EXHIBIT INDEX
The exhibits below are numbered in accordance with the Exhibit Table of Item 601 of Regulation S-K.
     
Exhibit    
No.   Description of Exhibit
 
3.1
  Third Amended and Restated Certificate of Incorporation of the Registrant (incorporated by reference to Exhibit 3.1 of the Registrant’s Form S-1 Registration Statement No. 333-55412).
 
   
3.2
  Amended and Restated By-Laws of the Registrant (incorporated by reference to Exhibit 3.2 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004 filed on March 16, 2005).
 
   
3.3
  Certificate of Amendment of Third Amended and Restated Certificate of Incorporation of Peabody Energy Corporation (incorporated by reference to Exhibit 3.3 of the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 filed on August 8, 2005).
 
   
4.1*
  6 7/8% Senior Notes Indenture Due 2013 Seventh Supplemental Indenture, dated as of September 30, 2005, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee.
 
   
4.2*
  5 7/8% Senior Notes Due 2016 Fifth Supplemental Indenture, dated as of September 30, 2005, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee.
 
   
10.1
  Indemnification Agreement dated July 21, 2005 by and between Peabody Energy Corporation and John F. Turner (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on August 5, 2005).
 
   
10.2*
  Amended and Restated Receivables Purchase Agreement, dated as of September 30, 2005, by and among Seller, Registrant, the Sub-Servicers named therein, Market Street Funding Corporation, as Issuer, PNC Bank, National Association, as Administrator and as LC Bank, and financial institutions from time to time parties thereto, as LC Participants.
 
   
31.1*
  Certification of periodic financial report by Peabody Energy Corporation’s Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as amended pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
   
31.2*
  Certification of periodic financial report by Peabody Energy Corporation’s Executive Vice President and Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as amended pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
   
32.1*
  Certification of periodic financial report pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Peabody Energy Corporation’s Chief Executive Officer.
 
   
32.2*
  Certification of periodic financial report pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Peabody Energy Corporation’s Executive Vice President and Chief Financial Officer.
 
*   Filed herewith.

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