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
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period endedJuneSeptember 30, 2005
Commission File Number1-16463
PEABODY ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
   
Delaware 13-4004153
   
(State or other jurisdiction of(I.R.S. Employer

incorporation or organization)
 (I.R.S. Employer
Identification No.)
701 Market Street, St. Louis, Missouri63101-1826
(Address of principal executive offices)(Zip701 Market Street, St. Louis, Missouri63101-1826
(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).        
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 July 31,October 28, 2005: Common Stock, par value $0.01 per share, 131,159,264131,489,626 shares outstanding.
 
 

 


INDEX
     
  Page
    
     
    
     
  2 
     
  3 
     
  4 
     
  5 
     
  2528 
     
  3942 
     
  4144 
     
    
     
  41
4245 
     
  4245 
 Certificate of Amendment of 3rd Amended/Restated Certificate of IncorporationSeventh Supplemental Indenture
 Coal LeaseFifth Supplemental Indenture
Amended and Restated Receivables Purchase Agreement
 Certification of CEO Pursuant to Rule 13a-14(a)13A-14(A)
 Certification of EVP/CFO Pursuant to Rule 13a-14(a)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

 


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 Six Months Ended Quarter Ended Nine Months Ended 
 June 30, June 30, September 30, September 30, 
 2005 2004 2005 2004 2005 2004 2005 2004 
REVENUES
  
Sales $1,089,817 $898,582 $2,152,338 $1,643,033  $1,191,282 $895,156 $3,343,620 $2,538,189 
Other revenues 18,969 18,189 33,928 46,031  32,228 23,833 66,156 69,864 
                  
Total revenues 1,108,786 916,771 2,186,266 1,689,064  1,223,510 918,989 3,409,776 2,608,053 
  
COSTS AND EXPENSES
  
Operating costs and expenses 880,274 757,686 1,794,356 1,407,462  987,503 735,618 2,781,859 2,143,080 
Depreciation, depletion and amortization 79,309 73,020 155,262 132,860  77,159 70,132 232,421 202,992 
Asset retirement obligation expense 7,162 8,627 16,357 21,664  7,394 10,146 23,751 31,810 
Selling and administrative expenses 40,671 32,144 78,431 59,936  57,009 33,623 135,440 93,559 
Other operating income:  
Net gain on disposal of assets  (16,452)  (1,907)  (47,574)  (12,355)
Net gain on disposal or exchange of assets  (47,577)  (1,790)  (95,151)  (14,145)
Income from equity affiliates  (11,487)  (4,626)  (20,678)  (11,053)  (8,863)  (2,645)  (29,541)  (13,698)
                  
  
OPERATING PROFIT
 129,309 51,827 210,112 90,550  150,885 73,905 360,997 164,455 
Interest expense 25,205 24,595 50,761 45,923  25,327 24,926 76,088 70,849 
Early debt extinguishment gains   (556)   (556)
Interest income  (1,810)  (1,209)  (3,183)  (2,128)  (3,218)  (1,084)  (6,401)  (3,212)
                  
  
INCOME BEFORE INCOME TAXES AND MINORITY INTERESTS
 105,914 28,441 162,534 46,755  128,776 50,619 291,310 97,374 
Income tax provision (benefit) 10,162  (15,194) 14,586  (20,796) 14,714 6,933 29,300  (13,863)
Minority interests 498 390 804 653  722 247 1,526 900 
                  
  
INCOME FROM CONTINUING OPERATIONS
 95,254 43,245 147,144 66,898  113,340 43,439 260,484 110,337 
Loss from discontinued operations, net of income tax benefit of $1,177 and $1,892, respectively   (1,764)   (2,837)
Loss from discontinued operations, net of income tax benefit of $1 and $1,893, respectively   (2)   (2,839)
                  
 
NET INCOME
 $95,254 $41,481 $147,144 $64,061  $113,340 $43,437 $260,484 $107,498 
                  
  
BASIC EARNINGS PER SHARE
  
Income from continuing operations $0.73 $0.34 $1.13 $0.56  $0.86 $0.34 $1.99 $0.90 
Loss from discontinued operations   (0.02)   (0.03)     (0.02)
                  
Net income $0.73 $0.32 $1.13 $0.53  $0.86 $0.34 $1.99 $0.88 
                  
WEIGHTED AVERAGE SHARES OUTSTANDING — BASIC
 130,815,073 127,927,900 130,582,209 119,752,076  131,216,197 128,557,174 130,795,861 122,708,532 
                  
  
DILUTED EARNINGS PER SHARE
  
Income from continuing operations $0.71 $0.33 $1.10 $0.55  $0.84 $0.33 $1.95 $0.88 
Loss from discontinued operations   (0.01)   (0.03)     (0.02)
                  
Net income $0.71 $0.32 $1.10 $0.52  $0.84 $0.33 $1.95 $0.86 
                  
WEIGHTED AVERAGE SHARES OUTSTANDING — DILUTED
 133,810,208 130,876,522 133,683,624 122,622,612  134,260,988 131,558,064 133,855,704 125,641,992 
         
         
DIVIDENDS DECLARED PER SHARE
 $0.075 $0.0625 $0.15 $0.125  $0.095 $0.0625 $0.245 $0.1875 
                  
See accompanying notes to unaudited condensed consolidated financial statements.

2


PEABODY ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in thousands, except share and per share data)
                
 (Unaudited)   (Unaudited)   
 June 30, 2005 December 31, 2004 September 30, 2005 December 31, 2004 
ASSETS
  
Current assets  
Cash and cash equivalents $459,367 $389,636  $478,741 $389,636 
Accounts receivable, less allowance for doubtful accounts of $19,781 at June 30, 2005 and $1,361 at December 31, 2004 204,419 193,784 
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 363,561 323,609  368,850 323,609 
Assets from coal trading activities 52,834 89,165  85,554 89,165 
Deferred income taxes 15,050 15,461  15,050 15,461 
Other current assets 57,991 42,947  84,430 42,947 
          
Total current assets 1,153,222 1,054,602  1,269,163 1,054,602 
Property, plant, equipment and mine development, net of accumulated depreciation, depletion and amortization of $1,474,006 at June 30, 2005 and $1,333,645 at December 31, 2004 4,883,277 4,781,431 
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 368,162 342,559  371,603 342,559 
          
Total assets $6,404,661 $6,178,592  $6,654,795 $6,178,592 
          
 �� 
LIABILITIES AND STOCKHOLDERS’ EQUITY
  
Current liabilities  
Current maturities of long-term debt $21,861 $18,979  $23,031 $18,979 
Liabilities from coal trading activities 34,812 63,565  67,398 63,565 
Accounts payable and accrued expenses 748,514 691,600  809,956 691,600 
          
Total current liabilities 805,187 774,144  900,385 774,144 
 
Long-term debt, less current maturities 1,393,049 1,405,986  1,384,263 1,405,986 
Deferred income taxes 400,991 393,266  419,621 393,266 
Asset retirement obligations 402,071 396,022  398,979 396,022 
Workers’ compensation obligations 230,044 227,476  233,127 227,476 
Accrued postretirement benefit costs 942,201 939,503  945,670 939,503 
Other noncurrent liabilities 326,597 315,694  333,790 315,694 
          
Total liabilities 4,500,140 4,452,091  4,615,835 4,452,091 
Minority interests 1,713 1,909  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 June 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 June 30, 2005 or December 31, 2004   
Common Stock — $0.01 per share par value; 400,000,000 shares authorized, 131,201,979 shares issued and 130,940,799 shares outstanding as of June 30, 2005 and 150,000,000 shares authorized, 129,829,134 shares issued and 129,567,954 shares outstanding as of December 31, 2004 1,312 1,298 
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 1,474,590 1,437,319  1,491,038 1,437,319 
Retained earnings 478,533 350,968  579,411 350,968 
Unearned restricted stock awards  (6,703)  (459)  (6,323)  (459)
Accumulated other comprehensive loss  (41,008)  (60,618)  (24,251)  (60,618)
Treasury shares, at cost: 261,180 shares as of June 30, 2005 and December 31, 2004  (3,916)  (3,916)
Treasury shares, at cost: 261,180 shares as of September 30, 2005 and December 31, 2004  (3,916)  (3,916)
          
Total stockholders’ equity 1,902,808 1,724,592  2,037,275 1,724,592 
          
Total liabilities and stockholders’ equity $6,404,661 $6,178,592  $6,654,795 $6,178,592 
          
See accompanying notes to unaudited condensed consolidated financial statements.

3


PEABODY ENERGY CORPORATION
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in thousands)
                
 Six Months Ended Nine Months Ended 
 June 30, September 30, 
 2005 2004 2005 2004 
Cash Flows from Operating Activities
  
Net income $147,144 $64,061  $260,484 $107,498 
Loss from discontinued operations  2,837   2,839 
          
Income from continuing operations 147,144 66,898  260,484 110,337 
Adjustments to reconcile income from continuing operations to net cash provided by operating activities:  
Depreciation, depletion and amortization 155,262 132,860  232,421 202,992 
Deferred income taxes 11,699  (27,185) 28,406  (24,273)
Early debt extinguishment gains   (556)
Amortization of debt discount and debt issuance costs 3,465 3,970  5,177 6,097 
Net gain on disposal of assets  (47,574)  (12,355)
Net gain on disposal or exchange of assets  (95,151)  (14,145)
Income from equity affiliates  (20,678)  (11,053)  (29,541)  (13,698)
Dividends received from equity investments 5,095 1,860 
Dividends received from equity affiliates 6,082 5,164 
Changes in current assets and liabilities:  
Accounts receivable, net of sale  (35,635)  (45,760)  (67,754)  (5,476)
Inventories  (40,334)  (36,950)  (46,204)  (56,565)
Net assets from coal trading activities 7,578  (2,185) 7,444  (7,667)
Other current assets  (2,811) 2,634   (18,625)  (7,655)
Accounts payable and accrued expenses 57,787 67,708  119,229 46,076 
Asset retirement obligations  (719)  (2,423)  (4,082)  (5,238)
Workers’ compensation obligations 3,860 4,957  6,943 6,335 
Accrued postretirement benefit costs 2,698  (11,612) 6,167  (27,666)
Contributions to pension plans  (2,389)  (52,484)  (6,275)  (61,380)
Other, net 9,146 3,154  17,448  (177)
          
Net cash provided by operating activities 253,594 82,034  422,169 152,505 
          
Cash Flows from Investing Activities
  
Additions to property, plant, equipment and mine development  (187,650)  (115,858)  (346,703)  (148,345)
Purchase of mining assets  (56,500)    (56,500)  
Additions to advance mining royalties  (6,247)  (9,677)  (9,061)  (11,560)
Acquisitions, net   (422,164)   (426,265)
Investment in joint venture  (2,000)  
Proceeds from disposal of assets 60,231 22,803  71,185 24,623 
          
Net cash used in investing activities  (190,166)  (524,896)  (343,079)  (561,547)
          
Cash Flows from Financing Activities
  
Proceeds from long-term debt  250,000  11,459 250,000 
Payments of long-term debt  (14,085)  (16,697)  (15,621)  (28,749)
Net proceeds from equity offering  383,125   383,125 
Proceeds from stock options exercised 14,617 11,601  19,958 19,274 
Proceeds from employee stock purchases 1,350 1,139  3,010 2,343 
Increase of securitized interests in accounts receivable 25,000 50,000  25,000 100,000 
Payment of debt issuance costs   (8,910)   (8,922)
Distributions to minority interests  (1,000)  (694)  (1,750)  (818)
Dividends paid  (19,579)  (14,852)  (32,041)  (22,878)
          
Net cash provided by financing activities 6,303 654,712  10,015 693,375 
          
Net increase in cash and cash equivalents 69,731 211,850  89,105 284,333 
Cash and cash equivalents at beginning of period 389,636 117,502  389,636 117,502 
          
Cash and cash equivalents at end of period $459,367 $329,352  $478,741 $401,835 
          
See accompanying notes to unaudited condensed consolidated financial statements.

4


PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
JUNE
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 JuneSeptember 30, 2005 and for the quarters and sixnine months ended JuneSeptember 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 sixnine months ended JuneSeptember 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
     AtAfter the March 17, 2005 Emerging Issues Task Force (“EITF”) meeting, the Task Force reached a consensus inissued 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 ($224.1230.2 million and $197.2 million as of JuneSeptember 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 the consensus 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 of this consensus.application. The Company is currently evaluating which method of adoption it will use. The Company expects to adopt this consensusEITF 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

5


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 $3.9$4.5 million, net of taxes. The Company began utilizing restricted stock as part of its equity-based compensation

5


NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
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 $1.9$2.2 million, net of taxes, in 2006. The Company recognized expense for the sixnine months ended JuneSeptember 30, 2005 of $0.5$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 Junethe 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. Asproperties which included a resultreduction of the property transactions, asset retirement obligations were reduced byof $9.2 million.
     In Marchthe first quarter of 2005, the Company sold its remaining 0.838 million PVRPenn 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 Penn Virginia Resource Partners, L.P. (“PVR”)PVR whereby the Company sold 120 million tons of coal reserves in exchange for $72.5 million in cash and 2.76 million units or 15%, 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. As of March 2005 (theAt the time of the final sale of units),original transaction, a deferred gain from the sales of the reserves and units of $19.0 million remained and will beis 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
     TheDuring the first six months of 2005, the Company recorded net contract losses of approximately $34$10.7 million in the quarter ended March 31, 2005, primarily 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 and no offsetting receivable from the producer who breached the contract was assumed. The loss recorded is not equivalent to, nor indicative(in excess of the economic losses (i.e. legal damages) sought byestimated revenue expected to be earned on the Company as a result ofbrokerage sales).
     In the breach.
     During the secondthird quarter of 2005, the Company reduced its estimated losscompleted settlement of the dispute, and the related tolawsuit was dismissed (see further discussion in Note 12). Under the settlement, the Company received $10.0 million in cash, a new coal supply contract breach by approximately $12.5 million, primarily asagreement that partially replaced the disputed coal supply agreement, and exchanged certain coal

6


NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
properties. As a result of negotiating athe final settlement lateand based on the fair values of the items exchanged in the second quarter withoverall settlement transaction, the producer who breached the contract. The settlement mitigates the loss recognizedCompany further reduced its contract losses by $6.7 million and, as discussed above, recorded gains on assets exchanged of $37.4 million in the firstthird quarter and enables the Company to secure replacement coal at prices lower than originally anticipated. See Note 12 for more details on the breach of contract, subsequent lawsuit and the negotiated settlement.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 two2 to three3 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 Northern Indiana Public Service Company 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 preliminary estimates ofthe 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 78 to 89 million tons per year of steam coal with a planned production expansion up to 12 million tons per year by

6


NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
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 as of, and for periods subsequent to, April 15, 2004.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  $46,639 
Materials and supplies 5,669  5,669 
Coal inventory 11,543  11,543 
Other current assets 6,234  6,234 
Property, plant, equipment and mine development 463,567 
Property, plant, equipment and mine development, net 463,567 
Accounts payable and accrued expenses  (48,688)  (48,688)
Other noncurrent assets and liabilities, net  (63,699)  (63,699)
      
Total purchase price, net of cash received of $20,914 $421,265  $421,265 
      

7


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):
            
 Quarter Ended Six Months Ended Nine Months Ended 
 June 30, 2004 June 30, 2004 * September 30, 2004 * 
Revenues:  
As reported $916,771 $1,689,064  $2,608,053 
Pro forma 942,008 1,814,426  2,733,415 
 
Income from continuing operations 
Income from continuing operations: 
As reported $43,245 $66,898  $110,337 
Pro forma 44,757 64,257  107,696 
 
Net income 
Net income: 
As reported $41,481 $64,061  $107,498 
Pro forma 42,993 61,420  104,857 
 
Basic earnings per share — net income:  
As reported $0.32 $0.53  $0.88 
Pro forma 0.34 0.48  0.82 
 
Diluted earnings per share — net income:  
As reported $0.32 $0.52  $0.86 
Pro forma 0.33 0.47  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.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(6) Inventories
     Inventories consisted of the following (dollars in thousands):
                
 June 30, December 31, September 30, December 31, 
 2005 2004 2005 2004 
Materials and supplies $62,883 $57,467  $64,718 $57,467 
Raw coal 15,510 17,590  15,174 17,590 
Advance stripping 224,069 197,225  230,154 197,225 
Saleable coal 61,099 51,327  58,804 51,327 
          
Total $363,561 $323,609  $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 JuneSeptember 30, 2005 and December 31, 2004. The fair value of coal trading derivatives and related hedge contracts as of JuneSeptember 30, 2005 and December 31, 2004 is set forth below (dollars in thousands):
                                
 June 30, 2005 December 31, 2004 September 30, 2005 December 31, 2004 
 Assets Liabilities Assets Liabilities Assets Liabilities Assets Liabilities 
Forward contracts $52,834 $34,136 $89,042 $60,914  $85,554 $67,330 $89,042 $60,914 
Other  676 123 2,651   68 123 2,651 
                  
Total $52,834 $34,812 $89,165 $63,565  $85,554 $67,398 $89,165 $63,565 
                  
     Ninety-nine percent of the contracts in the Company’s trading portfolio as of JuneSeptember 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 JuneSeptember 30, 2005, the timing of the estimated future realization of the value of the Company’s trading portfolio was as follows:
        
Year of Percentage Percentage 
Expiration of Portfolio of Portfolio 
2005  91%  48%
2006  6%  42%
2007  1%  10%
2008  2%
      
  100%  100%
      
     At JuneSeptember 30, 2005, 70%47% of the Company’s credit exposure related to coal trading activities was with investment grade counterparties.counterparties and 48% was with other Powder River Basin coal producers. The Company’s coal trading operations traded 8.513.7 million tons and 8.37.6 million tons for the quarters ended JuneSeptember 30, 2005 and 2004, respectively, and 17.731.4 million tons and 18.325.9 million tons for the sixnine months ended JuneSeptember 30, 2005 and 2004, respectively.

8


NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(8) Earnings Per Share and Stockholders’ Equity
     Weighted Average Shares Outstanding
     A reconciliation of weighted average shares outstanding follows:
                               
 Quarter Ended June 30, Six Months Ended June 30, Quarter Ended September 30, Nine Months Ended September 30, 
 2005 2004 2005 2004 2005 2004 2005 2004 
Weighted average shares outstanding — basic 130,815,073 127,927,900 130,582,209 119,752,076  131,216,197 128,557,174 130,795,861 122,708,532 
Dilutive impact of stock options 2,995,135 2,948,622 3,101,415 2,870,536  3,044,791 3,000,890 3,059,843 2,933,460 
                  
Weighted average shares outstanding — diluted 133,810,208 130,876,522 133,683,624 122,622,612  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 Accounting Principles Board (“APB”)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 JuneSeptember 30, 2005 and 2004, respectively, and $0.8$1.2 million and $0.1

9


NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
$0.2 million in the sixnine months ended JuneSeptember 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 Six Months Ended Quarter Ended Nine Months Ended 
 June 30, June 30, September 30, September 30, 
 2005 2004 2005 2004 2005 2004 2005 2004 
Net income:  
As reported $95,254 $41,481 $147,144 $64,061  $113,340 $43,437 $260,484 $107,498 
Pro forma 93,962 39,786 144,534 60,617  112,041 42,131 256,500 103,971 
  
Basic earnings per share:  
As reported $0.73 $0.32 $1.13 $0.53  $0.86 $0.34 $1.99 $0.88 
Pro forma 0.72 0.31 1.11 0.51  0.85 0.33 1.96 0.85 
  
Diluted earnings per share:  
As reported $0.71 $0.32 $1.10 $0.52  $0.84 $0.33 $1.95 $0.86 
Pro forma 0.70 0.30 1.08 0.49  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 sixnine months ended JuneSeptember 30, 2005 and 2004 (dollars in thousands):
                 
  Quarter Ended Six Months Ended
  June 30, June 30,
  2005 2004 2005 2004
Net income $95,254  $41,481  $147,144  $64,061 
Increase (decrease) in fair value of cash flow hedges, net of tax of ($6,755) and $7,558 for the quarters ended June 30, 2005 and 2004, respectively, and $13,073 and $6,093 for the six months ended June 30, 2005 and 2004, respectively  (10,133)  11,338   19,610   9,139 
                 
Comprehensive income $85,121  $52,819  $166,754  $73,200 
                 

9


NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
                 
  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 exchangecurrency 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.

10


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 
 Quarter Ended Six Months Ended September 30, September 30, 
 June 30, June 30, 2005 2004 2005 2004 
 2005 2004 2005 2004
Service cost for benefits earned $2,963 $3,055 $5,926 $5,928  $2,964 $3,147 $8,890 $9,122 
Interest cost on projected benefit obligation 11,373 10,738 22,746 21,337  11,373 11,027 34,119 32,594 
Expected return on plan assets  (13,203)  (12,958)  (26,406)  (24,323)  (13,203)  (12,573)  (39,609)  (37,238)
Amortization of prior service cost  (4) 64  (8) 128   (4) 64  (12) 191 
Amortization of net loss 5,948 5,401 12,294 11,030  6,147 5,477 18,441 16,573 
                  
Net periodic pension costs 7,077 6,300 14,552 14,100  7,277 7,142 21,829 21,242 
Curtailment charges   9,527     9,527  
                  
Total pension costs $7,077 $6,300 $24,079 $14,100  $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 previously 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 JuneSeptember 30, 2005, $1.8$5.5 million of contributions have been made to the funded pension plans and $0.5$0.8 million of expected benefit payments attributable to the unfunded pension plans have been made. The Company presently anticipates it will contribute $5.1$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 
 Quarter Ended Six Months Ended September 30, September 30, 
 June 30, June 30, 2005 2004 2005 2004 
 2005 2004 2005 2004
Service cost for benefits earned $1,325 $1,180 $2,649 $2,400  $1,355 $908 $4,004 $3,308 
Interest cost on accumulated postretirement benefit obligation 18,175 15,797 36,351 31,591  18,154 16,089 54,505 47,680 
Amortization of prior service cost  (1,325)  (3,308)  (2,649)  (6,615)  (1,355)  (3,308)  (4,004)  (9,923)
Amortization of actuarial losses 6,575 1,063 13,150 1,837  6,579 918 19,729 2,755 
                  
Net periodic postretirement benefit costs $24,750 $14,732 $49,501 $29,213  $24,733 $14,607 $74,234 $43,820 
                  

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
     Cash Flows
     The Company previously 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. As of JuneFor the nine months ended September 30, 2005, payments of $42.4$63.6 million attributable to the Company’s postretirement benefit plans have been made.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, high Btumetallurgical 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.

12


NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
Operating segment results for the quarters and sixnine months ended JuneSeptember 30, 2005 and 2004 are as follows (dollars in thousands):
                                
 Quarter Ended Six Months Ended Quarter Ended Nine Months Ended 
 June 30, June 30, September 30, September 30, 
 2005 2004 2005 2004 2005 2004 2005 2004 
Revenues:  
Western U.S. Mining(1)
 $376,796 $344,003 $781,231 $648,031  $403,214 $373,629 $1,184,445 $1,021,660 
Eastern U.S. Mining 437,763 365,074 862,655 712,231  452,825 344,938 1,315,480 1,057,169 
Australian Mining 140,643 72,813 244,168 81,438  146,146 92,562 390,314 174,000 
Trading and Brokerage 149,293 132,255 290,862 241,384  216,098 105,205 506,960 346,589 
Corporate and Other 4,291 2,626 7,350 5,980  5,227 2,655 12,577 8,635 
                  
Total $1,108,786 $916,771 $2,186,266 $1,689,064  $1,223,510 $918,989 $3,409,776 $2,608,053 
                  
  
Adjusted EBITDA(2):
 
Adjusted EBITDA: 
Western U.S. Mining(1)
 $105,639 $100,389 $226,064 $183,757  $104,213 $113,874 $330,277 $297,631 
Eastern U.S. Mining 95,898 66,007 190,704 127,421  96,865 54,911 287,569 182,332 
Australian Mining 47,479 11,948 61,565 12,878  39,780 20,777 101,345 33,655 
Trading and Brokerage(3)(2)
 15,439 6,443  (6,429) 20,675  26,132 16,053 19,703 36,728 
Corporate and Other(4)(3)
  (48,675)  (51,313)  (90,173)  (99,657)  (31,552)  (51,432)  (121,725)  (151,089)
                  
Total $215,780 $133,474 $381,731 $245,074  $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) 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.
(3)Trading and Brokerage results include a benefit for the quarter and a charge for the sixnine months ended JuneSeptember 30, 2005 related to contract losses and a settlement agreement as discussed in Note 3.
 
(4)(3) Corporate and Other results include the gains on the salesdisposal or exchange of PVR unitsassets discussed in Note 3.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
     A reconciliation of adjusted EBITDA to consolidated income before income taxesfrom continuing operations follows (dollars in thousands):
                                
 Quarter Ended Six Months Ended Quarter Ended Nine Months Ended 
 June 30, June 30, September 30, September 30, 
 2005 2004 2005 2004 2005 2004 2005 2004 
Total adjusted EBITDA $215,780 $133,474 $381,731 $245,074  $235,438 $154,183 $617,169 $399,257 
 
Depreciation, depletion and amortization 79,309 73,020 155,262 132,860  77,159 70,132 232,421 202,992 
 
Asset retirement obligation expense 7,162 8,627 16,357 21,664  7,394 10,146 23,751 31,810 
 
Interest expense 25,205 24,595 50,761 45,923  25,327 24,926 76,088 70,849 
 
Early debt extinguishment gains   (556)   (556)
Interest income  (1,810)  (1,209)  (3,183)  (2,128)  (3,218)  (1,084)  (6,401)  (3,212)
 
Income tax provision (benefit) 14,714 6,933 29,300  (13,863)
Minority interests 498 390 804 653  722 247 1,526 900 
                  
Income from continuing operations $113,340 $43,439 $260,484 $110,337 
          
Income before income taxes $105,416 $28,051 $161,730 $46,102 
         
(12) Commitments and Contingencies
     Massey 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. The lawsuit soughtKentucky related to enforce COALTRADE’s contractual rights under a three-yeardisputed coal supply agreement, entered into by the parties effective January 1, 2003, and to recover damages caused by Massey’s repudiation and material breach of that agreement. On April 8, 2005, COALTRADE cancelled the coal supply agreement based upon Massey’s continuing refusal to deliver coal in accordance with its terms, and filed an amended complaint seeking recovery of damages for breach of contract and breach of duty of good faith and fair dealing. On April 18, 2005, Massey filed a counterclaim. The Company believes it has a significant contractual and factual basis for its claim.
During the quarter ended JuneSeptember 30, 2005, the Company worked to mitigate damages resulting from the breach, and negotiated a settlement with Massey. The Company and Massey signedcompleted a settlement agreement and mutual release, and the lawsuit has been stayed pending expected completion during the third quarter of 2005 of the transactions contemplated by the settlement.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”), at 22 sites in the United States and remediation has been completedrelated to activities of Gold Fields or substantially completed at four of those sites.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 its past operations. These sites are related to activities of Gold Fields or its former subsidiaries. Some of these claims are based on the Comprehensive Environmental Response Compensation and Liability Act of 1980 (“CERCLA”), as amended, and on similar state statutes.

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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. For certain sites, theThe 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 $40.0$39.5 million at JuneSeptember 30, 2005 and $40.5 million at December 31, 2004, $14.5$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 all significant remainingthe environmental remediation costs discussed aboveit has currently accrued will be paid by the end of 2009.2010.
     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

15


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.
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,

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
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 $70.8 million and $68.6 million included in “Investments and other assets” in the condensed consolidated balance sheets at June 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.
     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

16


NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
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 Company believes it is likely that the operation of the Mohave plant will cease or be suspendedsuspend operation on December 31, 2005. In the event the Mohave plant shuts down, the operations ofThe Company has issued Worker Adjustment and Retraining Notification (“WARN”) Act notices to its employees at the Black Mesa Mine could be adversely impacted starting in the third quarter of 2005, and the mine would be shut downregarding layoffs at the end of 2005. The Mohave plant is the sole customer of the Black Mesa Mine, which sold 2.43.5 million tons of coal in the first sixnine months of 2005 and 4.7 million tons during the year ended December 31, 2004. During the first sixnine months of 2005, the mine generated $11.9$20.3 million of Adjusted EBITDA (reconciled to its most comparable measure under generally accepted accounting principles in Note 11), which represented 3.1%3.3% of the Company’s total of $381.7$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.
     Oklahoma Lead LitigationSalt River Project Agricultural Improvement and Power District — Mine Closing and Retiree Health Care
     Gold Fields, which is a defendant in various litigation discussed below, is a dormant, non-coal producing entity that was previously managedSalt River Project and owned by Hanson PLC, a predecessor ownerthe other owners of the Company. InNavajo 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 1997 spin-off18, 1977. The contract expires in 2011.
     Peabody Western filed a motion to compel arbitration of its energy businesses, Hanson PLC transferred ownership of Gold Fieldsthese 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 Company, despite the fact that Gold Fields had no ongoing operationsretiree 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 had no prior involvementhas recorded a receivable for mine decommissioning costs of $72.3 million and $68.6 million included in its past operations.
     Gold Fields“Investments and three other companies are defendants in two class action lawsuits filedassets” in the U.S. District Court for the Northern District of Oklahoma (Betty Jean Cole, et al. v. Asarco Inc., et al.condensed consolidated balance sheets at September 30, 2005 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 has agreed to indemnify one of the other defendants, which is a former subsidiary of Gold Fields.
     Gold Fields is also a defendant, along with other companies, in five individual lawsuits arising out of the same lead mill operations. In JulyDecember 31, 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 alleged personal injuries from lead exposure. The trials for five of the individual plaintiffs have been set for November 2005. A second trial for seven individuals has been set for January 2006.

14


NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
     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 potentially responsible parties (“PRPs”) alleging that they had concluded that there is a reasonable probability of making a successful claim against the PRPs for damages to natural resources.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 the Company’sits 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 JuneSeptember 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 will appealhas 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

17


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 quarter and sixnine months ended JuneSeptember 30, 2005, respectively.2005. The receivable balance, net of the allowance, was zero and $18.1 million at JuneSeptember 30, 2005 and December 31, 2004, respectively.
     At JuneSeptember 30, 2005, purchase commitments for capital expenditures were approximately $204.8$332.0 million.

15


NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(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 June 30, 2005
  Parent Guarantor Non-Guarantor    
  Company Subsidiaries Subsidiaries Eliminations Consolidated
Total revenues $  $865,475  $264,750  $(21,439) $1,108,786 
Costs and expenses:                    
Operating costs and expenses  (4,508)  692,203   214,018   (21,439)  880,274 
Depreciation, depletion and amortization     70,429   8,880      79,309 
Asset retirement obligation expense     6,441   721      7,162 
Selling and administrative expenses  952   37,571   2,148      40,671 
Other operating income:                    
Net gain on disposal of assets     (16,347)  (105)     (16,452)
Income from equity affiliates     (11,487)        (11,487)
Interest expense  38,328   7,523   5,032   (25,678)  25,205 
Interest income  (5,172)  (16,030)  (6,286)  25,678   (1,810)
   
Income (loss) before income taxes and minority interests  (29,600)  95,172   40,342      105,914 
Income tax provision (benefit)  (18,106)  19,858   8,410      10,162 
Minority interests     498         498 
   
Net income (loss) $(11,494) $74,816  $31,932  $  $95,254 
   

16


NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Statements of Operations
(Dollars in thousands)
                     
  Quarter Ended June 30, 2004
  Parent Guarantor Non-Guarantor    
  Company Subsidiaries Subsidiaries Eliminations Consolidated
Total revenues $  $781,274  $153,204  $(17,707) $916,771 
Costs and expenses:                    
Operating costs and expenses  (161)  636,925   138,629   (17,707)  757,686 
Depreciation, depletion and amortization     67,780   5,240      73,020 
Asset retirement obligation expense     8,158   469      8,627 
Selling and administrative expenses  234   31,013   897      32,144 
Other operating income:                    
Net gain on disposal of assets     (1,877)  (30)     (1,907)
Income from equity affiliates     (4,626)        (4,626)
Interest expense  38,435   33,835   648   (48,323)  24,595 
Interest income  (21,691)  (23,441)  (4,400)  48,323   (1,209)
   
Income (loss) before income taxes and minority interests  (16,817)  33,507   11,751      28,441 
Income tax provision (benefit)  (16,359)  915   250      (15,194)
Minority interests     390         390 
   
Income (loss) from continuing operations  (458)  32,202   11,501      43,245 
Loss from discontinued operations, net of taxes     (1,764)        (1,764)
   
Net income (loss) $(458) $30,438  $11,501  $  $41,481 
   

17


NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Statements of Operations
(Dollars in thousands)
                                        
 Six Months Ended June 30, 2005 Quarter Ended September 30, 2005 
 Parent Guarantor Non-Guarantor     Parent Guarantor Non-Guarantor     
 Company Subsidiaries Subsidiaries Eliminations Consolidated Company Subsidiaries Subsidiaries Eliminations Consolidated 
Total revenues $ $1,764,323 $462,570 $(40,627) $2,186,266  $ $959,278 $287,688 $(23,456) $1,223,510 
Costs and expenses:  
Operating costs and expenses  (7,391) 1,448,708 393,666  (40,627) 1,794,356   (12,025) 779,477 243,507  (23,456) 987,503 
Depreciation, depletion and amortization  139,386 15,876  155,262   68,853 8,306  77,159 
Asset retirement obligation expense  15,202 1,155  16,357   8,049  (655)  7,394 
Selling and administrative expenses 1,548 74,424 2,459  78,431  1,288 53,753 1,968  57,009 
Other operating income:  
Net gain on disposal of assets   (47,478)  (96)   (47,574)
Net gain on disposal or exchange of assets   (47,516)  (61)   (47,577)
Income from equity affiliates   (20,678)    (20,678)   (3,803)  (5,060)   (8,863)
Interest expense 75,776 15,554 10,387  (50,956) 50,761  39,163 13,607 5,463  (32,906) 25,327 
Interest income  (10,094)  (31,565)  (12,480) 50,956  (3,183)  (6,255)  (22,942)  (6,927) 32,906  (3,218)
    
Income (loss) before income taxes and minority interests  (59,839) 170,770 51,603  162,534   (22,171) 109,800 41,147  128,776 
Income tax provision (benefit)  (29,219) 36,237 7,568  14,586   (18,545) 24,474 8,785  14,714 
Minority interests  804   804   722   722 
    
Net income (loss) $(30,620) $133,729 $44,035 $ $147,144  $(3,626) $84,604 $32,362 $ $113,340 
    

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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)
                                        
 Six Months Ended June 30, 2004 Quarter Ended September 30, 2004 
 Parent Guarantor Non-Guarantor     Parent Guarantor Non-Guarantor     
 Company Subsidiaries Subsidiaries Eliminations Consolidated Company Subsidiaries Subsidiaries Eliminations Consolidated 
Total revenues $ $1,506,031 $216,406 $(33,373) $1,689,064  $ $784,385 $150,642 $(16,038) $918,989 
Costs and expenses:  
Operating costs and expenses  (9) 1,242,423 198,421  (33,373) 1,407,462   (1,874) 633,143 120,387  (16,038) 735,618 
Depreciation, depletion and amortization  126,525 6,335  132,860   63,221 6,911  70,132 
Asset retirement obligation expense  21,153 511  21,664   9,615 531  10,146 
Selling and administrative expenses 556 57,931 1,449  59,936  354 32,279 990  33,623 
Other operating income:  
Net gain on disposal of assets   (11,996)  (359)   (12,355)
Net (gain) loss on disposal or exchange of assets   (1,795) 5   (1,790)
Income from equity affiliates   (11,053)    (11,053)   (2,645)    (2,645)
Interest expense 70,166 60,027 1,331  (85,601) 45,923  37,201 13,470 1,184  (26,929) 24,926 
Early debt extinguishment gains  (556)     (556)
Interest income  (42,990)  (35,781)  (8,958) 85,601  (2,128)  (4,594)  (17,965)  (5,454) 26,929  (1,084)
    
Income (loss) before income taxes and minority interests  (27,723) 56,802 17,676  46,755   (30,531) 55,062 26,088  50,619 
Income tax provision (benefit)  (22,181)  (276) 1,661   (20,796)  (11,875) 9,870 8,938  6,933 
Minority interests  653   653   247   247 
    
Income (loss) from continuing operations  (5,542) 56,425 16,015  66,898   (18,656) 44,945 17,150  43,439 
Loss from discontinued operations, net of taxes   (2,837)    (2,837)   (2)    (2)
    
Net income (loss) $(5,542) $53,588 $16,015 $ $64,061  $(18,656) $44,943 $17,150 $ $43,437 
    

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
Peabody Energy Corporation

Unaudited Supplemental Condensed Consolidated Balance SheetsStatements of Operations
(Dollars in thousands)
                     
  June 30, 2005
  Parent Guarantor Non-Guarantor    
  Company Subsidiaries Subsidiaries Eliminations Consolidated
ASSETS
                    
Current assets                    
Cash and cash equivalents $444,338  $1,774  $13,255  $  $459,367 
Accounts receivable  3,188   112,664   88,567      204,419 
Inventories     317,864   45,697      363,561 
Assets from coal trading activities     52,834         52,834 
Deferred income taxes     15,050         15,050 
Other current assets  31,672   21,030   5,289      57,991 
                     
Total current assets  479,198   521,216   152,808      1,153,222 
Property, plant, equipment and mine development     5,825,226   532,057      6,357,283 
Less accumulated depreciation, depletion and amortization     (1,408,480)  (65,526)     (1,474,006)
Investments and other assets  4,621,435   408,662   3,974   (4,665,909)  368,162 
                     
Total assets $5,100,633  $5,346,624  $623,313  $(4,665,909) $6,404,661 
                     
                     
LIABILITIES AND STOCKHOLDERS’ EQUITY
                    
Current liabilities                    
Current maturities of long-term debt $8,750  $12,229  $882  $  $21,861 
Payables and notes payable to affiliates, net  1,727,839   (2,097,461)  369,622       
Liabilities from coal trading activities     34,812         34,812 
Accounts payable and accrued expenses  22,575   633,261   92,678      748,514 
                     
Total current liabilities  1,759,164   (1,417,159)  463,182      805,187 
Long-term debt, less current maturities  1,334,654   56,547   1,848      1,393,049 
Deferred income taxes  18,323   370,264   12,404      400,991 
Other noncurrent liabilities  17,192   1,876,668   7,053      1,900,913 
                     
Total liabilities  3,129,333   886,320   484,487      4,500,140 
Minority interests     1,713         1,713 
Stockholders’ equity  1,971,300   4,458,591   138,826   (4,665,909)  1,902,808 
                     
Total liabilities and stockholders’ equity $5,100,633  $5,346,624  $623,313  $(4,665,909) $6,404,661 
                     
                     
  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 
   

20


NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
Peabody Energy Corporation

Unaudited Supplemental Condensed Consolidated Balance SheetsStatements of Operations
(Dollars in thousands)
                     
  December 31, 2004
  Parent Guarantor Non-Guarantor    
  Company Subsidiaries Subsidiaries Eliminations Consolidated
ASSETS
                    
Current assets                    
Cash and cash equivalents $373,066  $3,562  $13,008  $  $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   501,359   158,829      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   34,410   3,577   (4,503,630)  342,559 
                     
Total assets $5,202,616  $4,931,965  $547,641  $(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   (2,332,635)  310,598       
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   (1,656,846)  383,833      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   647,417   395,144      4,452,091 
Minority interests     1,909         1,909 
Stockholders’ equity  1,793,086   4,282,639   152,497   (4,503,630)  1,724,592 
                     
Total liabilities and stockholders’ equity $5,202,616  $4,931,965  $547,641  $(4,503,630) $6,178,592 
                     
                     
  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 
   

21


NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
Peabody Energy Corporation

Unaudited Supplemental Condensed Consolidated Statements of Cash FlowsBalance Sheets
(Dollars in thousands)
                 
  Six Months Ended June 30, 2005
  Parent Guarantor Non-Guarantor  
  Company Subsidiaries Subsidiaries Consolidated
Cash Flows from Operating Activities
                
Net cash provided by (used in) operating activities $(84,340) $279,925  $58,009  $253,594 
                 
                 
Cash Flows from Investing Activities
                
Additions to property, plant, equipment and mine development     (86,218)  (101,432)  (187,650)
Purchase of mining assets     (56,500)     (56,500)
Additions to advance mining royalties     (6,242)  (5)  (6,247)
Proceeds from disposal of assets     60,098   133   60,231 
                 
Net cash used in investing activities     (88,862)  (101,304)  (190,166)
                 
                 
Cash Flows from Financing Activities
                
Payments of long-term debt  (2,500)  (11,014)  (571)  (14,085)
Proceeds from stock options exercised  14,617         14,617 
Proceeds from employee stock purchases  1,350         1,350 
Increase of securitized interests in accounts receivable        25,000   25,000 
Distributions to minority interests     (1,000)     (1,000)
Dividends paid  (19,579)        (19,579)
Transactions with affiliates, net  161,724   (180,837)  19,113    
                 
Net cash provided by (used in) financing activities  155,612   (192,851)  43,542   6,303 
                 
                 
Net increase (decrease) in cash and cash equivalents  71,272   (1,788)  247   69,731 
Cash and cash equivalents at beginning of period  373,066   3,562   13,008   389,636 
                 
Cash and cash equivalents at end of period $444,338  $1,774  $13,255  $459,367 
                 
                     
  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 
                

22


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 
                

23


NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Statements of Cash Flows
(Dollars in thousands)
                                
 Six Months Ended June 30, 2004 Nine Months Ended September 30, 2005 
 Parent Guarantor Non-Guarantor   Parent Guarantor Non-Guarantor   
 Company Subsidiaries Subsidiaries Consolidated Company Subsidiaries Subsidiaries Consolidated 
Cash Flows from Operating Activities
  
Net cash provided by (used in) operating activities $(26,666) $103,344 $5,356 $82,034  $(114,649) $469,136 $67,682 $422,169 
                  
  
Cash Flows from Investing Activities
  
Additions to property, plant, equipment and mine development   (55,577)  (60,281)  (115,858)   (173,109)  (173,594)  (346,703)
Purchase of mining assets   (56,500)   (56,500)
Additions to advance mining royalties   (9,427)  (250)  (9,677)   (9,061)   (9,061)
Acquisitions, net   (189,656)  (232,508)  (422,164)
Investment in joint venture   (2,000)   (2,000)
Proceeds from disposal of assets  22,261 542 22,803   69,353 1,832 71,185 
                  
Net cash used in investing activities   (232,399)  (292,497)  (524,896)   (171,317)  (171,762)  (343,079)
                  
  
Cash Flows from Financing Activities
  
Proceeds from long-term debt 250,000   250,000   11,459  11,459 
Payments of long-term debt  (2,250)  (13,458)  (989)  (16,697)  (3,750)  (11,104)  (767)  (15,621)
Net proceeds from equity offering 383,125   383,125 
Proceeds from stock options exercised 11,601   11,601  19,958   19,958 
Proceeds from employee stock purchases 1,139   1,139  3,010   3,010 
Increase of securitized interests in accounts receivable   50,000 50,000    25,000 25,000 
Payment of debt issuance costs  (8,910)    (8,910)
Distributions to minority interests   (694)   (694)   (1,750)   (1,750)
Dividends paid  (14,852)    (14,852)  (32,041)    (32,041)
Transactions with affiliates, net  (388,084) 143,996 244,088   225,069  (297,738) 72,669  
                  
Net cash provided by financing activities 231,769 129,844 293,099 654,712 
Net cash provided by (used in) financing activities 212,246  (299,133) 96,902 10,015 
                  
 
Net increase in cash and cash equivalents 205,103 789 5,958 211,850 
Net increase (decrease) in cash and cash equivalents 97,597  (1,314)  (7,178) 89,105 
Cash and cash equivalents at beginning of period 114,575 1,392 1,535 117,502  373,066 3,496 13,074 389,636 
                  
Cash and cash equivalents at end of period $319,678 $2,181 $7,493 $329,352  $470,663 $2,182 $5,896 $478,741 
                  

24


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 $17.2$16.4 million loan facility as of JuneSeptember 30, 2005. The total amount of the joint venture’s debt guaranteed by the Company was $8.4$8.0 million as of JuneSeptember 30, 2005.

25


NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
     The Company has guaranteed the performance of Asset Management Group (“AMG”) under atheir coal purchase contract with a third party, which has terms extending through December 31, 2006. Default occurs upon AMG’s non-delivery ofif AMG does not deliver specified monthly tonnage.tonnage amounts to the third party. In the event of a default, the Company assumeswould assume AMG’s obligation to ship coal at agreed prices for the remaining term of the purchase contract. The guarantee arose from an agreement by which AMG mines under a royalty-based contract with the Company. As of JuneSeptember 30, 2005, the maximum potential future payments under this

23


NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
guarantee are approximately $10$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 the AMGAMG’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 totalCompany 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 $1.6$4.4 million, and the fair value of the guarantees recognized as a liability was less than $0.1$0.4 million as of JuneSeptember 30, 2005. The Company’s obligations under the guarantees extend to the end of 2007.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) Subsequent EventsRisk Management and Financial Instruments
     On July 21, 2005,The Company enters into both derivative and non-derivative contracts to manage its exposure to the Company announced that its Boardprice volatility of Directors increased the quarterly dividend by 27 percentdiesel fuel. Fuel costs make up between three and authorized a share repurchase program. The share repurchase program allows for the repurchase of up to 5four percent of the Company’s common shares; however, any repurchase undertotal operating costs and expenses. As of September 30, 2005, the program requires a separate approvalCompany 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 Company’s Boardfourth quarter of Directors2005 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

26


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 Executive Committee. The repurchases may be made from time to timehedges.
     Ineffectiveness is inherent in hedging diesel fuel with derivative positions based on an evaluationother 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 outlook and general business conditions, as well as alternative investment and debt repayment options. The increase in the regular quarterly dividend on common stock, to $0.095 per share, is payable on August 25, 2005 to shareholders of record on August 4, 2005.results.

2427


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 filed with the Securities and Exchange Commission and all related documents incorporated by reference.10-K. We do not undertake any obligation to update these statements.statements, except as required by federal securities laws.

2528


Overview
     We are the largest private sector coal company in the world, with majority interests in 3233 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.Venezuela, and a 49% interest in an Appalachia joint venture. In the secondthird quarter and first halfnine months of 2005, we sold 57.761.6 million and 116.9178.4 million tons of coal, respectively.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, and by the availability of transportation for coal shipments.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 sixnine months ended JuneSeptember 30, 2005. Each of ourOur mining operations isare 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 86%82% of revenues in the secondthird quarter of 2005, we also generated 13%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 are developing threecontinue 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. TheseThe 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, N.M.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, wouldcould be operational following a four-year construction phase. The first of these plants willwould not be operational earlier than mid-2010.
     The Prairie State Energy Campus project has continued to advance in 2005.     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. Other than as noted in Part II, Item 4, “Submission of Matters to a Vote of Security Holders,” allAll 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 percent5% of the outstanding shares of our common stock. However, any repurchase under the program requires a separate approval from the Company’s Board of Directors or its Executive Committee. The repurchases may be made from time to time based on an evaluation of the Company’sour 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

27


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 JuneSeptember 30, 2005 Compared to Quarter Ended JuneSeptember 30, 2004
Summary
     In the second quarter of 2005, ourOur revenues increased $192.0$304.5 million, or 33.1%, to $1,108.8 million, a 20.9% increase over the prior year, primarily driven by improved pricing in most regions. Our segment Adjusted EBITDA totaled $264.5$1,223.5 million in the secondthird quarter of 2005 compared to $184.8the 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 43.1%29.8% increase. NetThird quarter net income improved 129.6% to $95.3of $113.3 million, or $0.71$0.84 per share, in the second quarterwas 160.9% higher than prior year net income of 2005, compared to $41.5$43.4 million, or $0.32$0.33 per share, in the prior year.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 JuneSeptember 30, 2005 and 2004:
                                
 (Unaudited)   (Unaudited)   
 Quarter Ended June 30, Increase (Decrease) Quarter Ended September 30, Increase (Decrease) 
 2005 2004 Tons % 2005 2004 Tons % 
 (Tons in millions)  (Tons in millions) 
Western U.S. Mining Operations 36.7 35.0 1.7  4.9% 39.1 37.9 1.2  3.2%
Eastern U.S. Mining Operations 13.2 12.7 0.5  3.9% 13.4 12.3 1.1  8.9%
Australian Mining Operations 2.1 1.7 0.4  23.5% 1.9 2.0  (0.1)  (5.0)%
Trading and Brokerage Operations 5.7 7.6  (1.9)  (25.0)% 7.2 6.5 0.7  10.8%
              
Total 57.7 57.0 0.7  1.2% 61.6 58.7 2.9  4.9%
                

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Revenues
     The following table presents revenues for the quarters ended JuneSeptember 30, 2005 and 2004:
                                
 (Unaudited) Increase (Unaudited) Increase 
 Quarter Ended June 30, to Revenues Quarter Ended September 30, to Revenues 
 2005 2004 $ % 2005 2004 $ % 
 (Dollars in thousands)  (Dollars in thousands) 
Sales $1,089,817 $898,582 $191,235  21.3% $1,191,282 $895,156 $296,126  33.1%
Other revenues 18,969 18,189 780  4.3% 32,228 23,833 8,395  35.2%
              
Total revenues $1,108,786 $916,771 $192,015  20.9% $1,223,510 $918,989 $304,521  33.1%
              

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     Overall, ourOur revenues increased $192.0$304.5 million, or 20.9%33.1%, overoverall compared to the prior year second quarter.third quarter of 2004. Sales increased $191.2$296.1 million, in the second quarter of 2005, reflecting increases in every segment: Western U.S. Mining ($33.530.1 million), Eastern U.S. Mining ($68.0105.3 million), Australian Mining ($68.154.1 million), and Trading & Brokerage ($21.6106.6 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 Twentymile Mine due to improved productivity from its longwall and 15 additional days of operation in the current year and 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 4.2%4.6% higher despite a $13.4 million charge to provide an allowance for disputed receivables as discussed in Note 12 to our unaudited condensed consolidated financial statements.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 two train derailments and subsequenttransportation from on-going rail maintenance, which lowered shipments through much of the quarter.maintenance. The restricted transportation capacity impacted all coal producers in the area,Powder River Basin, and rail capacity is not expected to return to pre-derailmenthigher levels until late in 2005 as discussed in “Outlook” below. In our Eastern U.S. Mining operations, increases inthe recent trend of higher average selling prices continued, rising 15.6%20.4% in the secondthird quarter of 2005 compared to prior year and resulting in a $68.0 million increase in sales due primarily to strongyear. Strong demand for steam and metallurgical coal demand. In addition, volumefrom the region is driving the higher prices and supporting higher volumes in our Midwest operations improved overboth Appalachia and the prior year.Midwest. The increase in our Australian Mining operations’ sales increase primarily reflected higher sales prices for metallurgical coal and an increasecoal. Volumes for the quarter in volumesAustralia were comparable to prior year as production from a new mine offset lower production at the mines, primarilyone of our metallurgical operations due to an additional 15 days of ownership of the Burton and North Goonyella Minespoor roof conditions as further discussed in the second quarter of 2005.“Segment Adjusted EBITDA” below. Average sales prices in our Australian operations improved 62.5%.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 $264.5$267.0 million for the secondthird quarter of 2005, compared with $184.8$205.6 million in the prior year, detailed as follows:
                                
 Increase to Increase (Decrease) to 
 (Unaudited) Segmented Adjusted (Unaudited) Segmented Adjusted 
 Quarter Ended June 30, EBITDA Quarter Ended September 30, EBITDA 
 2005 2004 $ % 2005 2004 $ % 
 (Dollars in thousands)  (Dollars in thousands) 
Western U.S. Mining Operations $105,639 $100,389 $5,250  5.2% $104,213 $113,874 $(9,661)  (8.5)%
Eastern U.S. Mining Operations 95,898 66,007 29,891  45.3% 96,865 54,911 41,954  76.4%
Australian Mining Operations 47,479 11,948 35,531  297.4% 39,780 20,777 19,003  91.5%
Trading and Brokerage Operations 15,439 6,443 8,996  139.6% 26,132 16,053 10,079  62.8%
              
Total Segment Adjusted EBITDA $264,455 $184,787 $79,668  43.1% $266,990 $205,615 $61,375  29.8%
              
     Western U.S. Mining operations’ Adjusted EBITDA increased $5.3decreased $9.7 million, or 5.2%8.5%, in the secondthird quarter of 2005 compared to prior year. ExcludingThe decrease was primarily caused by an $8.9 million lower contribution from our Colorado operations due to a longwall move in the $13.4third quarter of 2005 (there was no longwall move in the third quarter of 2004) and an additional $3.5 million charge for disputed receivables discussed in Note 12 to our unaudited condensed consolidated financial statements,rebuilding of equipment while the longwall was idle. Adjusted EBITDA increased $18.7$3.7 million or 18.6%. The increase primarily reflected increased volumes and sales prices for the Powder River operations and increased volumes in our Colorado operations, partially offset by higher per unit operating costs from transportation delays in the Powder River Basin and rising fuel costs in all regions. Improvements at our Powder River operations were primarily due to demand-driven sales volume

32


increases and improved margin per ton, primarily due to higher sales prices. Although strong demand for Powder River Basin coal continued, sales volumes atThe increase in prices offset higher per ton costs resulting from higher materials costs (including fuel and tires) and the Powder River operations were impacted by two train derailments, which lowered shipments through muchimpact of the quarter and increased per unit costs. Increased volumes in our Colorado operations reflected strong productivity of the Twentymile Mine’s longwall operations and increased demand.fixed costs over lower than anticipated volume. Costs were also negatively impacted by an increase inhigher revenue-based production and sales taxes. Excluding the impactGains from our fuel hedging program offset most of the disputed receivables charge,increase in fuel prices during the quarter. The Southwest operations’ results were comparable with prior year.

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     Eastern U.S. Mining operations’ Adjusted EBITDA increased $29.9$42.0 million in the secondcompared to third quarter of 2005 compared to 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 25%36% (over 60%75% for metallurgical coal) in 2005, partially offset by. Overall, volumes were higher than prior year, although one metallurgical mine experienced lower production at twoduring the quarter that will extend into the first quarter of our mines, mainly related to problems from excessive water and geologic issues, and higher contract2006 as the operation engages in development of a new longwall mining costs. The resultsarea. Results in our Midwest operations were higher than prior year as the benefits ofbenefiting from higher volumes and prices were partiallywhich offset by 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 $35.5$19.0 million in the secondthird quarter of 2005 compared to the prior year. Improved results were mainly driven by sales price increases of over 60%68% quarter over quarter. Current year results benefited from the strong sales prices, but were negatively impacted by continued port congestion, relatedpoor 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 lower production due to geological problems at the longwall operation.timing of vessel loadings also negatively impacted results.
     Trading and Brokerage operations’ Adjusted EBITDA increased $9.0$10.1 million inversus the secondthird quarter of 2005 compared2004, due to improved brokerage margins, higher prices and trading volumes and the prior year, primarily related to a $12.5 million reductionpositive effect of the previously established reserve forsettlement 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 (Unaudited) Increase (Decrease) to 
 Quarter Ended June 30, Income Quarter Ended September 30, Income 
 2005 2004 $ % 2005 2004 $ % 
 (Dollars in thousands)  (Dollars in thousands) 
Total Segment Adjusted EBITDA $264,455 $184,787 $79,668  43.1% $266,990 $205,615 $61,375  29.8%
  
Corporate and Other Adjusted EBITDA  (48,675)  (51,313) 2,638  5.1%  (31,552)  (51,432) 19,880  38.7%
Depreciation, depletion and amortization  (79,309)  (73,020)  (6,289)  (8.6)%  (77,159)  (70,132)  (7,027)  (10.0)%
Asset retirement obligation expense  (7,162)  (8,627) 1,465  17.0%  (7,394)  (10,146) 2,752  27.1%
Interest expense  (25,205)  (24,595)  (610)  (2.5)%  (25,327)  (24,926)  (401)  (1.6)%
Early debt extinguishment gains  556  (556) n/a 
Interest income 1,810 1,209 601  49.7% 3,218 1,084 2,134  196.9%
              
Income before income taxes and minority interests $105,914 $28,441 $77,473  272.4% $128,776 $50,619 $78,157  154.4%
              
     Income before income taxes and minority interests increased $77.5$78.2 million compared withversus the secondthird quarter of 2004, primarily due to improved segment Adjusted EBITDA results. Corporate and Other Adjusted EBITDA also 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 by $2.6included:
higher gain on disposal or exchange of assets of $45.8 million, included:primarily related to:
  highera $37.4 million gain on disposalsettlement of assets of $14.5 million primarily related to aggregate gains of $12.5 million on three sales involving non-strategica contract dispute with a third-party coal assets and properties;supplier; and
 
  income in 2005 of $6.1a $6.2 million gain from the December 2004 acquisition of a 25.5%an asset exchange where we acquired strategic Illinois Basin coal reserves for non-strategic reserves, our interest in Carbones del Guasare, which ownsa joint venture and operates the Paso Diablo Mine in Venezuela.monetary consideration (see Note 3); and

30


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:
  ana $6.9 million increase in past mining obligations expense, of $10.2 million, 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 thehigher amortization of actuarial losses in 2005; and
 
  an $8.5a $23.4 million increase in selling and administrative expenses primarily related to higher annualan 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 long-term performance-based incentives,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 business development and support services, acquisitions and higher administrative costs in our Australian operations.regulatory compliance.
     Depreciation, depletion and amortization increased $6.3$7.0 million in 2005 primarily associated withdue to increased production volumes in 2005 for the mines acquired in April 2004 as well as volume improvements at existing mines.2005.
Net Income
                                
 (Unaudited) Increase (Decrease) to (Unaudited) Increase (Decrease) to 
 Quarter Ended June 30, Income Quarter Ended September 30, Income 
 2005 2004 $ % 2005 2004 $ % 
 (Dollars in thousands)  (Dollars in thousands) 
Income before income taxes and minority interests $105,914 $28,441 $77,473  272.4% $128,776 $50,619 $78,157  154.4%
  
Income tax (provision) benefit  (10,162) 15,194  (25,356) n/a 
Income tax provision  (14,714)  (6,933)  (7,781)  (112.2)%
Minority interests  (498)  (390)  (108)  (27.7)%  (722)  (247)  (475)  (192.3)%
              
Income from continuing operations 95,254 43,245 52,009  120.3% 113,340 43,439 69,901  160.9%
Loss from discontinued operations, net of taxes   (1,764) 1,764 n/a    (2) 2 n/a 
              
Net income $95,254 $41,481 $53,773  129.6% $113,340 $43,437 $69,903  160.9%
              
     NetOur net income increased $53.8$69.9 million, or 160.9%, in the third quarter of 2005 compared to the second quarter of 2004prior 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 recorded in 2005 differs from the benefit in 2004is higher than prior year primarily as a result of higher pre-tax income and a positive effective tax rate in 2005, which is driven by the magnitude of the percentage depletion deduction relative to pretax income.

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SixNine Months Ended JuneSeptember 30, 2005 Compared to SixNine Months Ended JuneSeptember 30, 2004
Summary
     InOur revenues increased $801.7 million to $3,409.8 million for the first sixnine months of 2005, our revenues increased $497.2 million to $2,186.3 million, a 29.4%30.7% increase over the prior year, with a 7.4%year. The increase in sales volume andrevenue was primarily due to improved pricing in all regions. Our segmentregions, increased sales volumes from strong demand at domestic and international mining operations and the benefit of mining operations acquired during 2004. Segment Adjusted EBITDA totaled $471.9was $738.9 million infor the first sixnine months of 2005 compared to $344.7$550.3 million in the prior year, a 36.9%34.3% increase. Net income improved 129.7% to $147.1of $260.5 million, or $1.10$1.95 per share, was 142.3% higher in the first sixnine months of 2005, compared to $64.1$107.5 million, or $0.52$0.86 per share, in the prior year. The improvements were primarily driven by improveddue to greater demand-driven volume, improved sales prices particularly for our metallurgical and Powder River Basin products, and the impact of mining operations acquired in 2004. In addition, higher gains on property transactions contributed to higher year over year results.

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Tons Sold
     The following table presents tons sold by operating segment for the sixnine months ended JuneSeptember 30, 2005 and 2004:
                                
 (Unaudited)   (Unaudited)   
 Six Months Ended June 30, Increase (Decrease) Nine Months Ended September 30, Increase (Decrease) 
 2005 2004 Tons % 2005 2004 Tons % 
 (Tons in millions)  (Tons in millions) 
Western U.S. Mining Operations 75.4 67.5 7.9  11.7% 114.5 105.4 9.1  8.6%
Eastern U.S. Mining Operations 26.2 25.2 1.0  4.0% 39.5 37.5 2.0  5.3%
Australian Mining Operations 4.1 2.0 2.1  105.0% 6.0 4.1 1.9  46.3%
Trading and Brokerage Operations 11.2 14.1  (2.9)  (20.6)% 18.4 20.5  (2.1)  (10.2)%
              
Total 116.9 108.8 8.1  7.4% 178.4 167.5 10.9  6.5%
              
Revenues
     The following table presents revenues for the sixnine months ended JuneSeptember 30, 2005 and 2004:
                                
 (Unaudited) Increase (Decrease) (Unaudited) Increase (Decrease) 
 Six Months Ended June 30, to Revenues Nine Months Ended September 30, to Revenues 
 2005 2004 $ % 2005 2004 $ % 
 (Dollars in thousands)  (Dollars in thousands) 
Sales $2,152,338 $1,643,033 $509,305  31.0% $3,343,620 $2,538,189 $805,431  31.7%
Other revenues 33,928 46,031  (12,103)  (26.3)% 66,156 69,864  (3,708)  (5.3)%
              
Total revenues $2,186,266 $1,689,064 $497,202  29.4% $3,409,776 $2,608,053 $801,723  30.7%
              
     Overall, ourOur total revenues increased $497.2$801.7 million, or 29.4%30.7%, overto $3,409.8 million compared to the first sixnine months of the prior year,2004, driven by both increased volumespricing in all regions and sales prices. We acquiredhigher overall volume. The three mines we acquired in the second quarter of 2004 that contributed approximately $156$259.0 million to the increase in revenue in the first six months of 2005.revenues. The remaining $542.7 million increase of $341 million is primarily attributable to increases in average sales prices and volumes across all mining segments, and increases in volume, 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 $509.3$805.4 million in the first sixnine months of 2005, reflecting increases in every segment: Western U.S. Mining ($137.1167.3 million), Eastern U.S. Mining ($143.8249.0 million), Australian Mining ($162.7216.8 million), and Trading and Brokerage ($65.7172.3 million). Increases in average per ton selling prices continued, rising 7.9%6.7% and 16.7%18.0% in our Western U.S. and Eastern U.S. miningMining operations, respectively, in the first sixnine months of 2005 compared to prior year. The 16.4% increase in sales for our Western U.S. Mining operations sales increased $137.1 million, or 21.3%, was primarily

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attributable to the 2004 acquisition of the Twentymile Mine and to increases in both sales price and sales volumesvolume in the Powder River Basin. Excluding the impact of a $16.2 million allowance that was established relative to disputed receivables (discussed in Note 12 to our unaudited condensed consolidated financial statements), Western US Mining sales increased $153.3 million, or 23.8%. Production in the Powder River Basin continuedincreased 6.7 million tons, or 7.8%, compared to increasethe prior year in response to overall higher demand, increasing 4.9 million tons compared to the prior year, overcoming two train derailments, weather and track maintenance disruptions on the main shipping line out of the basin, which reduced our shipments from the region by an estimated 3.5 million tons in the second quarter of 2005.basin. Eastern U.S. Mining operations’ sales increased $143.8 million, or 20.6%,24.0% compared with prior year primarily 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 were primarilywas 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 subsequent openingstartup of an adjoiningour Eaglefield surface mine in 2004 and increases in the selling price for metallurgical coal. Improved2004. Trading and Brokerage sales primarily reflected increases in coal prices for brokerage sales.

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were up $172.3 million on higher pricing. Other revenues decreased $12.1 million in the first six months of 2005 compared towere comparable with the prior year, primarily as the result of a $12.7 million decrease in coal trading revenues in 2005. In 2004, higher trading revenues were driven by significant pricing increases related to our Eastern trading portfolio. Appalachia steam coal prices remain strong in 2005, but are more stable and have not provided the same opportunities for trading revenues as in 2004.year.
Segment Adjusted EBITDA
     Our total segment Adjusted EBITDA was $471.9$738.9 million for the first sixnine months of 2005, compared with $344.7$550.3 million in the prior year, detailed as follows:
                                
 Increase (Decrease) to Increase (Decrease) to 
 (Unaudited) Segmented Adjusted (Unaudited) Segmented Adjusted 
 Six Months Ended June 30, EBITDA Nine Months Ended September 30, EBITDA 
 2005 2004 $ % 2005 2004 $ % 
 (Dollars in thousands)  (Dollars in thousands) 
Western U.S. Mining Operations $226,064 $183,757 $42,307  23.0% $330,277 $297,631 $32,646  11.0%
Eastern U.S. Mining Operations 190,704 127,421 63,283  49.7% 287,569 182,332 105,237  57.7%
Australian Mining Operations 61,565 12,878 48,687  378.1% 101,345 33,655 67,690  201.1%
Trading and Brokerage Operations  (6,429) 20,675  (27,104) n/a  19,703 36,728  (17,025)  (46.4)%
              
Total Segment Adjusted EBITDA $471,904 $344,731 $127,173  36.9% $738,894 $550,346 $188,548  34.3%
              
     Western U.S. Mining operations’ Adjusted EBITDA increased $42.3$32.6 million, or 23.0%11.0%, in the first sixnine 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 as well as improvements in the Powder River Basin.operations. The improvement at our Powder River operations was primarily due to an 8.7%higher prices, leading to a 21.1% increase in per ton margin, and a 7.8% volume increase in response to increased demand, and improved margin per ton, primarily due to higher sales prices.demand. In 2005, secondthird quarter volumes were reduced fromreached record volumelevels after sequentially decreasing in the firstsecond 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 sales taxes,production taxes. Improvements in the Powder River Basin and the impact of adding higher value Twentymile productionColorado overcame a decrease in Adjusted EBITDA for our cost mix.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 $63.3$105.2 million in the first sixnine 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 30%31.9% in 2005, partially offset by lower production at two of our mines mainly related to problems from excessive water at one mine 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 $48.7$67.7 million in the first sixnine 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 resultsmargins also benefited from strong sales prices, but were negatively impactedmargin growth was limited by the impact of port congestion, related demurrage costs and lower productionhigher costs due to geological problems at the longwall operations.underground mine.
     Trading and Brokerage operations’ Adjusted EBITDA decreased $27.1$17.0 million compared with the prior year, primarily related to a net $14.1 million charge associated with a contractual dispute (see Note 3

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to our unaudited condensed consolidated financial statements) with one of our coal suppliers and less favorable trading results in 2005 compared to 2004, discussed above.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 (Unaudited) Increase (Decrease) to 
 Six Months Ended June 30, Income Nine Months Ended September 30, Income 
 2005 2004 $ % 2005 2004 $ % 
 (Dollars in thousands)  (Dollars in thousands) 
Total Segment Adjusted EBITDA $471,904 $344,731 $127,173  36.9% $738,894 $550,346 $188,548  34.3%
  
Corporate and Other Adjusted EBITDA  (90,173)  (99,657) 9,484  9.5%  (121,725)  (151,089) 29,364  19.4%
Depreciation, depletion and amortization  (155,262)  (132,860)  (22,402)  (16.9)%  (232,421)  (202,992)  (29,429)  (14.5)%
Asset retirement obligation expense  (16,357)  (21,664) 5,307  24.5%  (23,751)  (31,810) 8,059  25.3%
Interest expense  (50,761)  (45,923)  (4,838)  (10.5)%  (76,088)  (70,849)  (5,239)  (7.4)%
Early debt extinguishment gains  556  (556) n/a 
Interest income 3,183 2,128 1,055  49.6% 6,401 3,212 3,189  99.3%
              
Income before income taxes and minority interests $162,534 $46,755 $115,779  247.6% $291,310 $97,374 $193,936  199.2%
              
     Income before income taxes and minority interests increased $115.8$193.9 million compared with the first sixnine 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 $9.5$29.4 million improvement in Corporate and Other results included:
  higher gains on disposal or exchange of assets of $35.2$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, ($21.2 million) and to three resource sales involving non-strategic coal assets and properties ($12.5 million), and an asset exchange in 2005.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 recognizedalso realized a $31.1 million gain (see Note 3 to our unaudited condensed consolidated financial statements) 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 $11.0$16.1 million from our recently acquired 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 $2.6$4.8 million, primarily due to reimbursements from the Prairie State Energy Campus partnership group. The reimbursements include $1.8 million for expenses previously incurred on behalf of the project and the amortization of a $4.9 million non-refundable payment over the project development service period (which ends in mid-2006).

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These improvements were offset by the following items:
  an increase in past mining obligations expense of $21.9$28.8 million, primarily related to higher retiree health care costs. The increase in retiree health care costs was due toactuarially driven by higher trend rates, lower interest discount assumptions and thehigher amortization of actuarial losses in 2005; and
 
  an $18.5a $41.9 million increase in selling and administrative expenses primarily related to higher annual and long-term 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 business development initiativessupport services, acquisitions and the support and management of the Twentymile Mine and Australia operations acquired during 2004.regulatory compliance.

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     Depreciation, depletion and amortization increased $22.4$29.4 million in 2005 with approximately 46%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 $5.3$8.1 million due to expenses in 2004 related to the acceleration of planned reclamation of certain closed mine sites. Interest expense increased $4.8$5.2 million primarily related to the issuance of $250 million of 5.875% Senior Notes due 2016 in late March of 2004.2004 and increases in the cost of floating rate debt due to higher interest rates.
Net Income
                                
 (Unaudited) Increase (Decrease) to (Unaudited) Increase (Decrease) to 
 Six Months Ended June 30, Income Nine Months Ended September 30, Income 
 2005 2004 $ % 2005 2004 $ % 
 (Dollars in thousands)  (Dollars in thousands) 
Income before income taxes and minority interests $162,534 $46,755 $115,779  247.6% $291,310 $97,374 $193,936  199.2%
  
Income tax (provision) benefit  (14,586) 20,796  (35,382) n/a   (29,300) 13,863  (43,163) n/a 
Minority interests  (804)  (653)  (151)  (23.1)%  (1,526)  (900)  (626)  (69.6)%
              
Income from continuing operations 147,144 66,898 80,246  120.0% 260,484 110,337 150,147  136.1%
Loss from discontinued operations, net of taxes   (2,837) 2,837 n/a    (2,839) 2,839 n/a 
              
Net income $147,144 $64,061 $83,083  129.7% $260,484 $107,498 $152,986  142.3%
              
     Net income increased $83.1$153.0 million, or 142.3%, compared to the first sixnine 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 pre-taxpretax 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 reducedlower than expected in the second quarter and to a lesser extent in the third quarter of 2005 due to two train derailments and the beginning of a six-month remedial maintenance program undertaken by the two railroad companies serving the Powder River Basin. The maintenance and repairs are expected to be completed bycontinue in late 2005 to earlyand 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.
     We are continuingMetallurgical coal production from our Appalachia operations is expected to experience transportation difficulties at our Australian operations due to port congestion at Dalrymple Bay Coal Terminalbe 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 Portexisting mine has depleted the final panel of Hay Pointavailable reserves in Queensland, Australia. The port congestion beganits current location and is relocating to a reserve extension in early 2004 as demand began exceeding port capacitythe 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 has not eased overcutting capabilities. In the last year. Discussions regarding capacity expansion are on-going.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.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 almost 4%at an annual rate of 3.3% in the firstsecond 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 strengtheninggrowing economy, low customer stockpiles, production difficulties for some producers, 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

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increasing 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 60.892.9 million tons through the first halfnine months of 2005. Metallurgical coal is selling at a significant premium to steam coal.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 JuneSeptember 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 sixnine 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 JuneSeptember 30, 2005, we had letters of credit outstanding under the facility of $412.8$409.9 million, leaving $487.2$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 JuneSeptember 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 $253.6$422.2 million in the first sixnine months of 2005, an increase of $171.6$269.7 million, or 176.8%, from the first sixnine months of 2004. The increase was primarily driven by stronger operational performance in 2005, and the funding of our pension plans for $52.5 million in 2004 compared to $2.4 million in 2005. Netas net income increased $83.1$153.0 million from the prior year, and in 2004, we electively funded oneyear. Also contributing to the increase was lower funding of our pension plans, as we voluntarily pre-funded $50.0 million.million in the prior year. The remainder of the increase iswas primarily due to higher working capital and other changes.cash flows of $25.4 million.
     Net cash used in investing activities was $190.2$343.1 million during the first sixnine months of 2005 compared to $524.9$561.5 million used in 2004. Capital expenditures were $187.7$346.7 million in the first sixnine months of 2005, an increase of $71.8$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. AlsoThe 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 wealso reflected $56.5 million in capital expenditures for mining assets acquired mining assets,from Lexington Coal Company, including 70 million tons of Illinois and Indiana coal reserves, surface properties and equipment, from Lexington Coal Company for $61.0 million. The purchase price was paid with $59.0 million on the closing date and an additional $2.0

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million to be paid within 12 months of the close pending no outstanding claims related to the acquired mining assets. Capital expenditures include $56.5 million paid for reserves and equipment, and inventories include $2.5 million paid for materials and supplies.equipment. Proceeds from the disposal of assets increased $37.4$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 $417.2$421.3 million and we made a $5.0 million acquisition 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 $6.3$10.0 million during the first sixnine months of 2005 compared to $654.7$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 sixnine months of 2005 and 2004, we made scheduled payments on our long-term debt of $14.1$15.6 and $16.7$28.7 million, respectively. We received cash of $14.6 and $11.6 million in the first six months of 2005 and 2004, respectively, from the exercise of stock options. Securitized interest in accounts receivable increased by $25.0 million in the first sixnine months of 2005 compared to an increase of $50.0$100.0 million in 2004. We paid dividends of $19.6$32.0 million and $14.9$22.9 million in the first sixnine 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 JuneSeptember 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 JuneSeptember 30, 2005, we had $204.8$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 anticipatehave 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

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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 JuneSeptember 30, 2005 and December 31, 2004, respectively.
     There were no other material changes to our off-balance sheet arrangements during the sixnine months ended JuneSeptember 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.
     During the first quarter of 2005, a producer ceased shipping to us on a coal supply agreement. We have filed a lawsuit for breach of contract to enforce our contractual rights and to recover damages caused by this material breach of the coal supply agreement. We have agreed to settlement terms with the producer, and the lawsuit has been stayed pending completion of the transactions in the agreed upon settlement. See Notes 3 and 12 to our unaudited condensed consolidated financial statements.
Mohave Generating Station
     See Note 12 to our unaudited condensed consolidated financial statements included in this report relating to the likely cessation or suspension of the operations of our Black Mesa Mine and the Mohave Generating Station on December 31, 2005.

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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 JuneSeptember 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.

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     During the sixnine months ended JuneSeptember 30, 2005, the actual low, high, and average values at risk for our coal trading portfolio were $1.3 million, $3.9 million, and $2.4$2.5 million, respectively. As of JuneSeptember 30, 2005, the timing of the estimated future realization of the value of the Company’s trading portfolio was as follows:
        
Year of Percentage Percentage 
Expiration of Portfolio of Portfolio 
2005  91%  48%
2006  6%  42%
2007  1%  10%
2008  2%
      
  100%  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 JuneSeptember 30, 2005, we had in place forward contracts designated as cash flows hedges with Australian dollar-denominated notional amounts outstanding totaling $610$735 million, of which $175$96 million, $280$371 million, $120$184 million, and $35$84 million will expire in 2005, 2006, 2007 and 2008, respectively. Our current expectation for the remaining fourth quarter

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2005 non-capital, Australian dollar-denominated cash expenditures is approximately $240$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 JuneSeptember 30, 2005, after taking into consideration the effects of interest rate swaps, we had $865.9$859.8 million of fixed-rate borrowings and $549.0$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 $56.6$53.8 million decrease in the estimated fair value of these borrowings.

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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 JuneSeptember 30, 2005, we are essentially sold out of our planned 2005 production. Also as of JuneSeptember 30, 2005, we had 3520 to 4530 million tons, 95 to 105 million tons and 110165 to 120175 million tons of expected production available for sale or repricing at market prices for 2006, 2007 and 2007,2008, 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 JuneSeptember 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 55.744.9 million gallons of heating oil and 27.324.1 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 approximately 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 JuneSeptember 30, 2005 and has concluded that the disclosure controls and procedures were effective.
     During the second quarter of 2005, we completed the integration of our Australian operations acquired in 2004 into our system of internal control over financial reporting. We implemented new general ledger and reporting systems in our Australian operations and will complete our assessment of the effectiveness of related controls over financial reporting by the end of 2005. Other than changes made in our Australian operations,Additionally, during the most recent fiscal quarter, there have been no other 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.

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Item 4. Submission of Matters to a Vote of Security Holders.
     Peabody Energy Corporation’s annual meeting of stockholders was held on May 6, 2005. The shares of common stock eligible to vote were based on a record date of March 15, 2005 and do not reflect the March 30, 2005 two-for-one stock split. Four Class I directors were elected to serve for three-year terms expiring in 2008. A tabulation of votes for each director is set forth below:
         
  For Withheld
B.R. Brown  59,711,173   1,986,575 
Henry Givens, Jr.  58,745,000   2,952,748 
James R. Schlesinger  45,976,481   15,721,267 
Sandra Van Trease  59,716,590   1,981,158 
     Stockholders also voted to ratify Ernst & Young LLP as our independent registered public accounting firm for 2005 and voted to approve an increase in the number of authorized common stock shares from 150,000,000 shares to 400,000,000 shares and number of total authorized capital stock shares from 200,000,000 shares to 450,000,000 shares. Three stockholder proposals were voted on at the annual meeting, including a proposal regarding director independence submitted by Amalgamated Bank LongView MidCap 400 Index Fund, a proposal to declassify the Board for the purpose of director elections submitted by the AFL-CIO Reserve Fund, and a proposal to require a majority of affirmative votes for the election of director nominees submitted by the Sheet Metal Workers’ National Pension Fund. The result of the vote on each of these matters is set forth below:
                 
              Broker
  For Against Abstentions Non-votes
Ratification of independent registered public accounting firm  61,153,591   383,733   160,424    
Approval of increase in number of authorized common stock shares  57,046,627   4,636,333   14,743    
Proposal regarding director independence  22,560,474   30,184,555   84,274   8,868,445 
Proposal regarding declassification of Board  37,246,968   15,482,029   100,305   8,868,445 
Proposal regarding majority vote for election of director nominees  19,465,711   33,061,714   301,877   8,868,445 
     Each of the shareholder proposals submitted at the annual meeting was advisory in nature. The Nominating & Corporate Governance Committee, which consists entirely of independent directors, is evaluating the impact of the vote on these proposals and will recommend a course of action for consideration by the full Board.
Item 6. Exhibits.
     See Exhibit Index at page 4447 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: AugustNovember 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*3.3 Certificate of Amendment of Third Amended and Restated Certificate of Incorporation of Peabody Energy Corporation.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).
   
10.1*4.1* Federal Coal Lease WYW151134 effective May 1, 2005: West Roundup.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.
   
10.24.2*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 April 8,July 21, 2005 by and between Peabody Energy Corporation and Gregory H. BoyceJohn F. Turner (incorporated by reference to Exhibit 10.1 toof the Company’s Current Report on Form 8-K filed on April 14,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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