e10vq
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
(Mark One)
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þ |
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Quarterly Period Ended September 30, 2005
OR
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o |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number 1-13105
ARCH COAL, INC.
(Exact name of registrant as specified in its charter)
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Delaware
(State or other jurisdiction of
incorporation or organization)
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43-0921172
(I.R.S. Employer Identification No.) |
One CityPlace Drive, Suite 300, St. Louis, Missouri 63141
(Address of principal executive offices)(Zip Code)
Registrants telephone number, including area code: (314) 994-2700
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of
the Exchange Act). Yes þ No o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). Yes o No þ
At November 8, 2005,
there were 64,688,882 shares of registrants common stock outstanding.
PART I FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ARCH COAL, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
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September 30, |
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December 31, |
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2005 |
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2004 |
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(Unaudited) |
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Assets |
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Current assets |
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Cash and cash equivalents |
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$ |
227,428 |
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$ |
323,167 |
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Trade receivables |
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252,031 |
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180,902 |
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Other receivables |
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30,377 |
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34,407 |
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Inventories |
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142,012 |
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119,893 |
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Prepaid royalties |
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8,341 |
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12,995 |
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Deferred income taxes |
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9,778 |
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33,933 |
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Other |
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24,512 |
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25,560 |
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Total current assets |
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694,479 |
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730,857 |
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Property, plant and equipment, net |
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2,117,463 |
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2,033,200 |
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Other assets |
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Prepaid royalties |
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103,741 |
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87,285 |
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Goodwill |
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40,032 |
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37,381 |
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Deferred income taxes |
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273,237 |
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241,226 |
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Other |
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116,950 |
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126,586 |
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Total other assets |
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533,960 |
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492,478 |
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Total assets |
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$ |
3,345,902 |
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$ |
3,256,535 |
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Liabilities and stockholders equity |
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Current liabilities |
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Accounts payable |
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$ |
183,526 |
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$ |
148,014 |
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Accrued expenses |
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213,009 |
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217,216 |
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Current portion of debt |
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3,124 |
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9,824 |
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Total current liabilities |
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399,659 |
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375,054 |
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Long-term debt |
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972,875 |
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1,001,323 |
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Accrued postretirement benefits other than pension |
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402,073 |
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380,424 |
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Asset retirement obligations |
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184,538 |
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179,965 |
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Accrued workers compensation |
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74,698 |
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82,446 |
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Other noncurrent liabilities |
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144,055 |
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157,497 |
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Total liabilities |
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2,177,898 |
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2,176,709 |
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Stockholders equity |
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Preferred stock |
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29 |
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29 |
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Common stock |
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647 |
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631 |
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Paid-in capital |
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1,343,082 |
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1,280,513 |
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Retained deficit |
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(157,979 |
) |
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(166,273 |
) |
Unearned compensation |
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(3,140 |
) |
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(1,830 |
) |
Treasury stock, at cost |
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(1,190 |
) |
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(5,047 |
) |
Accumulated other comprehensive loss |
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(13,445 |
) |
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(28,197 |
) |
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Total stockholders equity |
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1,168,004 |
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1,079,826 |
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Total liabilities and stockholders equity |
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$ |
3,345,902 |
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$ |
3,256,535 |
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See notes to condensed consolidated financial statements.
1
ARCH COAL, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE DATA)
(UNAUDITED)
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Three Months Ended |
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Nine Months Ended |
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September 30, |
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September 30, |
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2005 |
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2004 |
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2005 |
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2004 |
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Revenues |
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Coal sales |
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$ |
654,716 |
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$ |
527,776 |
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$ |
1,888,978 |
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$ |
1,354,043 |
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Costs and expenses |
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Cost of coal sales |
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546,725 |
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448,638 |
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1,608,439 |
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1,161,259 |
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Depreciation, depletion and amortization |
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57,842 |
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43,491 |
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160,887 |
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115,677 |
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Selling, general and administrative expenses |
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20,285 |
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12,729 |
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60,540 |
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39,358 |
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Other operating expenses |
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15,150 |
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13,746 |
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40,695 |
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26,243 |
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640,002 |
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518,604 |
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1,870,561 |
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1,342,537 |
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Other operating income |
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Income from equity investments |
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1,143 |
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10,828 |
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Gain on sale of units of Natural Resource Partners, LP |
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289 |
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90,244 |
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Other operating income |
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19,463 |
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15,731 |
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63,206 |
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45,535 |
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19,463 |
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17,163 |
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63,206 |
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146,607 |
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Income from operations |
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34,177 |
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26,335 |
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81,623 |
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158,113 |
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Interest expense, net: |
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Interest expense |
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(17,994 |
) |
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(16,220 |
) |
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(55,454 |
) |
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(45,062 |
) |
Interest income |
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2,109 |
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1,110 |
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5,635 |
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2,723 |
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(15,885 |
) |
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(15,110 |
) |
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(49,819 |
) |
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(42,339 |
) |
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Other non-operating income (expense): |
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Expenses resulting from early debt extinguishment
and termination of hedge accounting for interest
rate swaps |
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(1,949 |
) |
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(2,066 |
) |
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(6,082 |
) |
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(6,199 |
) |
Other |
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(1,567 |
) |
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461 |
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(1,497 |
) |
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835 |
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(3,516 |
) |
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(1,605 |
) |
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(7,579 |
) |
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(5,364 |
) |
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Income before income taxes |
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14,776 |
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9,620 |
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24,225 |
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110,410 |
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(Benefit from) provision for income taxes |
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(4,150 |
) |
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(1,155 |
) |
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(4,750 |
) |
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18,545 |
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Net income |
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18,926 |
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|
10,775 |
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28,975 |
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|
91,865 |
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Preferred stock dividends |
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(1,797 |
) |
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(1,797 |
) |
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(5,391 |
) |
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(5,391 |
) |
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Net income available to common shareholders |
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$ |
17,129 |
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$ |
8,978 |
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$ |
23,584 |
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$ |
86,474 |
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Earnings per common share |
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Basic earnings per common share |
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$ |
0.27 |
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$ |
0.16 |
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$ |
0.37 |
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$ |
1.59 |
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Diluted earnings per common share |
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$ |
0.26 |
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$ |
0.16 |
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$ |
0.37 |
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$ |
1.48 |
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Basic weighted average shares outstanding |
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63,858 |
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|
54,874 |
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|
63,382 |
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|
54,431 |
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Diluted weighted average shares outstanding |
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64,791 |
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|
55,838 |
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|
64,371 |
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|
62,262 |
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Dividends declared per share |
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$ |
0.0800 |
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$ |
0.0800 |
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$ |
0.2400 |
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$ |
0.2175 |
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See notes to condensed consolidated financial statements.
2
ARCH COAL, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)
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Nine months Ended |
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September 30, |
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2005 |
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|
2004 |
|
Operating activities |
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Net income |
|
$ |
28,975 |
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$ |
91,865 |
|
Adjustments to reconcile to cash provided by
operating activities: |
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Depreciation, depletion and amortization |
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|
160,887 |
|
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|
115,677 |
|
Prepaid royalties expensed |
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|
12,143 |
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|
10,923 |
|
Accretion on asset retirement obligations |
|
|
11,392 |
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|
9,198 |
|
Net gain on disposition of assets |
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(29,882 |
) |
|
|
(748 |
) |
Gain on sale of units of Natural Resource Partners, LP |
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(90,244 |
) |
Net distributions from equity investments |
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|
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|
(10,828 |
) |
Income from equity investments |
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|
17,678 |
|
Other nonoperating expense |
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|
7,579 |
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|
5,364 |
|
Changes in: |
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Receivables |
|
|
(66,799 |
) |
|
|
(73,997 |
) |
Inventories |
|
|
(22,119 |
) |
|
|
(5,324 |
) |
Accounts payable and accrued expenses |
|
|
30,965 |
|
|
|
(19,889 |
) |
Income taxes |
|
|
(1,511 |
) |
|
|
(860 |
) |
Accrued postretirement benefits other than pension |
|
|
21,649 |
|
|
|
13,950 |
|
Asset retirement obligations |
|
|
(6,819 |
) |
|
|
(7,525 |
) |
Accrued workers compensation benefits |
|
|
(7,748 |
) |
|
|
(1,030 |
) |
Federal income tax receipts |
|
|
14,701 |
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Other |
|
|
9,615 |
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(14,404 |
) |
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|
|
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|
Cash provided by operating activities |
|
|
163,028 |
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|
39,806 |
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Investing activities |
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Payments for acquisitions, net of cash acquired |
|
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|
|
|
|
(381,905 |
) |
Capital expenditures |
|
|
(248,906 |
) |
|
|
(243,566 |
) |
Proceeds from sale of units of Natural Resource Partners, LP |
|
|
|
|
|
|
105,365 |
|
Proceeds from dispositions of capital assets |
|
|
30,183 |
|
|
|
1,279 |
|
Additions to prepaid royalties |
|
|
(23,945 |
) |
|
|
(27,171 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash used in investing activities |
|
|
(242,668 |
) |
|
|
(545,998 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financing activities |
|
|
|
|
|
|
|
|
Net proceeds from (payments on) revolver and lines of credit |
|
|
(25,000 |
) |
|
|
250,426 |
|
Net payments on long-term debt |
|
|
(9,125 |
) |
|
|
(6,300 |
) |
Deferred financing costs |
|
|
(2,631 |
) |
|
|
(1,160 |
) |
Dividends paid |
|
|
(20,681 |
) |
|
|
(17,249 |
) |
Proceeds from issuance of common stock |
|
|
41,338 |
|
|
|
30,732 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash provided by (used in) financing activities |
|
|
(16,099 |
) |
|
|
256,449 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease in cash and cash equivalents |
|
|
(95,739 |
) |
|
|
(249,743 |
) |
Cash and cash equivalents, beginning of period |
|
|
323,167 |
|
|
|
254,541 |
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period |
|
$ |
227,428 |
|
|
$ |
4,798 |
|
|
|
|
|
|
|
|
See notes to condensed consolidated financial statements.
3
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2005
(UNAUDITED)
Note A General
The accompanying unaudited Condensed Consolidated Financial Statements have been prepared in
accordance with generally accepted accounting principles for interim financial reporting and
Securities and Exchange Commission regulations, but are subject to any year-end adjustments that
may be necessary. In the opinion of management, all adjustments (consisting of normal recurring
accruals) considered necessary for a fair presentation have been included. Results of operations
for the period ended September 30, 2005 are not necessarily indicative of results to be expected
for the year ending December 31, 2005. These financial statements should be read in conjunction
with the audited financial statements and related notes thereto as of and for the year ended
December 31, 2004 included in Arch Coal, Inc.s Annual Report on Form 10-K as filed with the
Securities and Exchange Commission.
Arch Coal, Inc. (the Company) is engaged in the production of steam and metallurgical coal from
surface and deep mines throughout the United States, for sale to utility, industrial and export
markets. The Companys mines are primarily located in the Powder River Basin, Central Appalachia
and Western Bituminous regions of the United States. All subsidiaries (except as noted below) are
wholly owned. Intercompany transactions and accounts have been eliminated in consolidation.
The Companys Wyoming, Colorado and Utah coal operations are included in a joint venture named Arch
Western Resources, LLC (Arch Western). Arch Western is 99% owned by the Company and 1% owned by
BP Amoco. The Company also acts as the managing member of Arch Western.
On July 31, 2004, the Company acquired the remaining 35% of Canyon Fuel Company, LLC (Canyon
Fuel) that it did not already own. See Note C Business Combinations for further discussion.
Income from Canyon Fuel through July 31, 2004 is reflected in the Condensed Consolidated Statements
of Operations as income from equity investments (see additional discussion in Note E Equity
Investments).
Note B Recent Accounting Pronouncements
On March 30, 2005, the Financial Accounting Standards Board (FASB) ratified the consensus reached
by the Emerging Issues Task Force (EITF) on issue No. 04-6, Accounting for Stripping Costs in the
Mining Industry. This issue applies to stripping costs incurred in the production phase of a mine
for the removal of overburden or waste materials for the purpose of obtaining access to coal that
will be extracted. Under the new rule, stripping costs incurred during the production phase of the
mine are variable production costs that are included in the cost of inventory produced and
extracted during the period the stripping costs are incurred. Historically, the Company has
associated stripping costs at its surface mining operations with the cost of tons of coal uncovered
and has classified tons uncovered but not yet extracted as coal inventory (pit inventory). Pit
inventory, reported as coal inventory in Note H, was $38.3 million at September 30, 2005. The
guidance in this EITF consensus is effective for fiscal years beginning after December 15, 2005 for
which the cumulative effect of adoption should be recognized as an adjustment to the beginning
balance of retained earnings during the period. The Company expects to adopt the change as of
January 1, 2006.
Note C Business Combinations
Canyon Fuel 35% Acquisition
On July 31, 2004, the Company purchased the 35% interest in Canyon Fuel that it did not own from
ITOCHU Corporation. The purchase price, including related costs and fees, of $112.2 million was
funded with cash of $90.2 million and a five-year, $22.0 million non-interest bearing note. Net of
cash acquired, the fair value of the transaction totaled $97.4 million. The Company owns
substantially all of the ownership interests of Canyon Fuel and consolidates Canyon Fuel in its
financial statements. Prior to July 31, 2004, the investment in Canyon Fuel was accounted for on
the equity method. The results of operations of the Canyon Fuel mines are included in the Companys
Western Bituminous segment.
4
The purchase accounting allocation related to the acquisition has been recorded in the accompanying
consolidated financial statements as of, and for the period subsequent to, July 31, 2004. 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 |
|
$ |
7,432 |
|
Materials and supplies |
|
|
3,751 |
|
Coal inventory |
|
|
7,434 |
|
Other current assets |
|
|
6,466 |
|
Property, plant, equipment and mine development |
|
|
125,881 |
|
Accounts payable and accrued expenses |
|
|
(10,379 |
) |
Coal supply agreements |
|
|
(33,378 |
) |
Other noncurrent assets and liabilities, net |
|
|
(9,823 |
) |
|
|
|
|
Total purchase price, net of cash received of $11.0 million |
|
$ |
97,384 |
|
|
|
|
|
Amounts allocated to coal supply agreements noted in the table above represent the liability
established for the net below-market coal supply agreements to be amortized over the remaining
terms of the contracts. The liability is classified as an other noncurrent liability on the
accompanying Condensed Consolidated Balance Sheet. The remaining amortization period on these
acquired coal supply agreements ranges from three to 39 months.
Triton Acquisition
On August 20, 2004, the Company acquired (1) Vulcan Coal Holdings, L.L.C., which owns all of the
common equity of Triton Coal Company, LLC (Triton), and (2) all of the preferred units of Triton,
for a purchase price of $382.1 million, including transaction costs and working capital
adjustments. In 2003, Triton was the nations sixth largest coal producer and operated two mines in
the Powder River Basin: North Rochelle and Buckskin. Following the consummation of the transaction,
the Company completed an agreement to sell Buckskin to Kiewit Mining Acquisition Company. The net
sales price for this second transaction was $73.1 million. The total purchase price, including
related costs and fees, was funded with cash on hand, including the proceeds from the Buckskin
sale, $22.0 million in borrowings under the Companys existing revolving credit facility and a
$100.0 million term loan at its Arch Western Resources subsidiary. Upon acquisition, the Company
integrated the North Rochelle mine with its existing Black Thunder mine in the Powder River Basin.
The purchase accounting allocations related to the acquisition have been recorded in the
accompanying consolidated financial statements as of, and for the periods subsequent to August 20,
2004. 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 |
|
$ |
14,233 |
|
Materials and supplies |
|
|
4,161 |
|
Coal inventory |
|
|
4,875 |
|
Other current assets |
|
|
2,200 |
|
Property, plant, equipment and mine development |
|
|
325,194 |
|
Coal supply agreements |
|
|
8,486 |
|
Goodwill |
|
|
40,032 |
|
Accounts payable and accrued expenses |
|
|
(72,326 |
) |
Other noncurrent assets and liabilities, net |
|
|
(22,135 |
) |
|
|
|
|
Total purchase price, net of cash received of $0.4 million |
|
$ |
304,720 |
|
|
|
|
|
Amounts allocated to coal supply agreements noted in the table above represent the value attributed
to the net above-market coal supply agreements to be amortized over the remaining terms of the
contracts. The remaining amortization period on these acquired coal supply agreements ranges from
three to 15 months.
Pro Forma Financial Information
If Triton and Canyon Fuel had been included in the Companys results of operations during the three
months ended September 30, 2004, its unaudited pro forma revenues would have been $570.9 million,
unaudited pro forma net income available to common shareholders would have been $2.4 million and
unaudited pro forma basic and diluted earnings per share would both have been $0.04. If Triton and Canyon Fuel had been included
in the Companys results of operations during the nine months ended September 30, 2004, its
unaudited pro forma revenues would have been $1,605.8 million, unaudited pro forma net income
available to common shareholders would have been
5
$73.6 million and unaudited pro forma basic and
diluted earnings per share would have been $1.35 and $1.18, respectively.
Note D Stock-Based Compensation
These interim financial statements include the disclosure requirements of Statement of Financial
Accounting Standards No. 123, Accounting for Stock-Based Compensation (FAS 123), as amended by
Statement of Financial Accounting Standards No. 148,
Accounting for Stock-Based Compensation
Transition and Disclosure (FAS 148). With respect to accounting for its stock options, as
permitted under FAS 123, the Company has retained the intrinsic value method prescribed by
Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees (APB 25),
and related Interpretations. Had compensation expense for stock option grants been determined based
on the fair value at the grant dates consistent with the method required by FAS 123, the Companys
net income available to common shareholders and earnings per common share would have been changed
to the pro forma amounts as indicated in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2005 |
|
|
2004 |
|
|
2005 |
|
|
2004 |
|
|
|
(in thousands, except per share data) |
|
Net income available to common
shareholders, as reported |
|
$ |
17,129 |
|
|
$ |
8,978 |
|
|
$ |
23,584 |
|
|
$ |
86,474 |
|
Add: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based employee compensation
included in reported net income,
net of related tax effects |
|
|
101 |
|
|
|
495 |
|
|
|
8,718 |
|
|
|
1,342 |
|
Deduct: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stock-based employee
compensation expense determined
under fair value based method for
all awards, net of related tax
effects |
|
|
(1,122 |
) |
|
|
(1,829 |
) |
|
|
(11,767 |
) |
|
|
(5,474 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma net income available to
common shareholders |
|
$ |
16,108 |
|
|
$ |
7,644 |
|
|
$ |
20,535 |
|
|
$ |
82,342 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
earnings per share as reported |
|
|
0.27 |
|
|
|
0.16 |
|
|
|
0.37 |
|
|
|
1.59 |
|
Basic
earnings per share pro forma |
|
|
0.25 |
|
|
|
0.14 |
|
|
|
0.32 |
|
|
|
1.51 |
|
Diluted
earnings per share as reported |
|
|
0.26 |
|
|
|
0.16 |
|
|
|
0.37 |
|
|
|
1.48 |
|
Diluted
earnings per share pro forma |
|
|
0.25 |
|
|
|
0.14 |
|
|
|
0.32 |
|
|
|
1.41 |
|
In December 2004, the FASB issued Statement of Financial Accounting Standards No. 123 (revised
2004), Share-Based Payment (FAS 123R), which requires all public companies to measure
compensation cost in the income statement for all share-based payments (including employee stock
options) at fair value for interim and annual periods. On April 14, 2005, the Securities and
Exchange Commission (SEC) delayed the implementation of FAS 123R from its original implementation
date by six months for most registrants, requiring all public companies to adopt FAS 123R no later
than the beginning of the first fiscal year beginning after June 15, 2005. As such, the Company
intends to adopt FAS 123R on January 1, 2006 using the modified-prospective method. FAS 123R also
requires the benefits of tax deductions in excess of recognized compensation cost to be reported as
a financing cash flow, rather than as an operating cash flow as required under current literature.
This requirement will reduce net operating cash flows and increase net financing cash flows in
periods after adoption. The Company does not expect a material impact on its results of operations
after the date of adoption.
On January 14, 2004, the Company granted an award of 220,766 shares of performance-contingent
phantom stock that vested in the event the Companys stock price reached an average pre-established
price over a period of 20 consecutive trading days within five years following the date of grant.
On March 3, 2005, the price contingency discussed above was met, and the award was paid in a
combination of Company stock ($7.3 million) and cash ($2.6 million). As such, the Company
recognized a $9.9 million charge as a component of selling, general and administrative expense
($9.1 million) and cost of coal sales ($0.8 million) in the accompanying Condensed Consolidated
Statements of Operations in the first quarter of 2005.
In the third quarter 2005, the Companys Board of Directors approved a performance-contingent
phantom stock plan for 11 of its executives. The plan allows for participants to earn up to
252,600 units to be paid out in both cash and stock upon simultaneous attainment of certain levels
of stock price and EBITDA, as defined by the company. No expense related to this grant has been
recognized as the Company is unable to assess the probability of achieving the
6
performance and
market targets under APB25. The Company is continuing to determine the pro forma impact under FAS
123R, however, does not believe such impact will be material.
Note E Equity Investments
At September 30, 2005, the Company no longer held equity investments. The Company purchased the
remaining 35% interest in Canyon Fuel on July 31, 2004. Prior to July 31, 2004, the Company
accounted for its investment in Canyon Fuel on the equity method. In addition, on March 10, 2004,
the Company sold the majority of its interest in Natural Resource Partners, LP (NRP). Prior to
March 10, 2004, the Company accounted for its investment in NRP on the equity method. Amounts
recorded in the Condensed Consolidated Statements of Operations are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2005 |
|
|
2004 |
|
|
2005 |
|
|
2004 |
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Income from equity investments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from investment in Canyon Fuel |
|
$ |
|
|
|
$ |
1,143 |
|
|
$ |
|
|
|
$ |
8,410 |
|
Income from NRP |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,418 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from equity investments as reported
in the Condensed Consolidated Statements of
Operations |
|
$ |
|
|
|
$ |
1,143 |
|
|
$ |
|
|
|
$ |
10,828 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in Canyon Fuel
The following table presents unaudited summarized financial information for Canyon Fuel:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
Condensed Income Statement Information |
|
2005 |
|
|
2004 |
|
|
2005 |
|
|
2004 |
|
|
|
(in thousands) |
|
Revenues |
|
$ |
|
|
|
$ |
20,186 |
|
|
$ |
|
|
|
$ |
142,893 |
|
Total costs and expenses |
|
|
|
|
|
|
18,791 |
|
|
|
|
|
|
|
133,546 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income before cumulative effect
of accounting change |
|
$ |
|
|
|
$ |
1,395 |
|
|
$ |
|
|
|
$ |
9,347 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
65% of Canyon Fuel net income before
cumulative effect of accounting
change |
|
$ |
|
|
|
$ |
906 |
|
|
$ |
|
|
|
$ |
6,075 |
|
Effect of purchase adjustments |
|
|
|
|
|
|
237 |
|
|
|
|
|
|
|
2,335 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Arch Coals income from its equity
investment in Canyon Fuel |
|
$ |
|
|
|
$ |
1,143 |
|
|
$ |
|
|
|
$ |
8,410 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Through July 31, 2004, the Companys income from its equity investment in Canyon Fuel represented
65% of Canyon Fuels net income after adjusting for the effect of purchase adjustments related to
its investment in Canyon Fuel. The Companys investment in Canyon Fuel reflected purchase
adjustments primarily related to the reduction in amounts assigned to sales contracts, mineral
reserves and other property, plant and equipment. The purchase adjustments were amortized
consistent with the underlying assets of the joint venture.
Investment in NRP
During 2004, the Company sold its remaining limited partnership units of NRP in three separate
transactions occurring in March, June and October. Specifically during the nine months ended
September 30, 2004, the Company sold the majority of its remaining limited partnership units of NRP
for proceeds of approximately $105.4 million. The sale resulted in a gain of $90.2 million.
Note F Employee Benefit Plans
Defined Benefit Pension and Other Postretirement Benefit Plans
7
The Company has non-contributory defined benefit pension plans covering certain of its salaried and
non-union hourly employees. Benefits are generally based on the employees years of service and
compensation. The Company funds the plans in an amount not less than the minimum statutory funding
requirements nor more than the maximum amount that can be deducted for federal income tax purposes.
The Company also currently provides certain postretirement medical/life insurance coverage for
eligible employees. Generally, covered employees who terminate employment after meeting eligibility
requirements are eligible for postretirement coverage for themselves and their dependents. The
salaried employee postretirement medical/life plans are contributory, with retiree contributions
adjusted periodically, and contain other cost-sharing features such as deductibles and coinsurance.
The postretirement medical plan for retirees who were members of the United Mine Workers of America
(UMWA) is not contributory. The Companys current funding policy is to fund the cost of all
postretirement medical/life insurance benefits as they are paid.
Components of Net Periodic Benefit Cost
The following table details the components of pension and other postretirement benefit costs.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other postretirement |
|
|
Pension benefits |
|
benefits |
Three Months Ended September 30, |
|
2005 |
|
2004 |
|
2005 |
|
2004 |
|
|
(in thousands) |
Service cost |
|
$ |
2,304 |
|
|
$ |
2,396 |
|
|
$ |
1,364 |
|
|
$ |
1,089 |
|
Interest cost |
|
|
2,416 |
|
|
|
3,009 |
|
|
|
7,967 |
|
|
|
7,461 |
|
Expected return on plan assets* |
|
|
(3,334 |
) |
|
|
(3,698 |
) |
|
|
|
|
|
|
|
|
Other amortization and deferral |
|
|
2,195 |
|
|
|
1,227 |
|
|
|
6,470 |
|
|
|
4,159 |
|
|
|
|
|
|
$ |
3,581 |
|
|
$ |
2,934 |
|
|
$ |
15,801 |
|
|
$ |
12,709 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other postretirement |
|
|
|
Pension benefits |
|
|
benefits |
|
Nine Months Ended September 30, |
|
2005 |
|
|
2004 |
|
|
2005 |
|
|
2004 |
|
|
|
(in thousands) |
|
Service cost |
|
$ |
8,303 |
|
|
$ |
6,311 |
|
|
$ |
3,906 |
|
|
$ |
2,989 |
|
Interest cost |
|
|
9,112 |
|
|
|
8,616 |
|
|
|
23,663 |
|
|
|
22,185 |
|
Expected return on plan assets* |
|
|
(11,579 |
) |
|
|
(10,672 |
) |
|
|
|
|
|
|
|
|
Other amortization and deferral |
|
|
5,545 |
|
|
|
3,541 |
|
|
|
19,003 |
|
|
|
12,539 |
|
|
|
|
|
|
$ |
11,381 |
|
|
$ |
7,796 |
|
|
$ |
46,572 |
|
|
$ |
37,713 |
|
|
|
|
|
|
|
* |
|
The Company does not fund its other postretirement liabilities. |
Employer Contributions
The Company contributed 273,000 shares of treasury stock in August 2005. The Company has no
minimum contribution required.
Note G Other Comprehensive Income
Other comprehensive income items under FAS 130, Reporting Comprehensive Income, are transactions
recorded in stockholders equity during the year, excluding net income and transactions with
stockholders. The following table presents comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2005 |
|
|
2004 |
|
|
2005 |
|
|
2004 |
|
|
|
|
|
|
|
(in thousands) |
|
|
|
|
|
Net income |
|
$ |
18,926 |
|
|
$ |
10,775 |
|
|
$ |
28,975 |
|
|
$ |
91,865 |
|
Other comprehensive
income, net of income
taxes |
|
|
6,211 |
|
|
|
1,904 |
|
|
|
14,752 |
|
|
|
7,594 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income |
|
$ |
25,137 |
|
|
$ |
12,679 |
|
|
$ |
43,727 |
|
|
$ |
99,459 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8
Other comprehensive income for the three and nine months ended September 30, 2005 and 2004 consists
primarily of the reclassification of previously deferred mark-to-market adjustments from other
comprehensive income to net income and mark-to-market adjustments related to the Companys
financial derivatives which still qualify as effective hedges.
Note H Inventories
Inventories consist of the following:
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
|
(in thousands) |
|
Coal |
|
$ |
80,308 |
|
|
$ |
76,009 |
|
Repair parts and supplies |
|
|
61,704 |
|
|
|
43,884 |
|
|
|
|
|
|
|
|
|
|
$ |
142,012 |
|
|
$ |
119,893 |
|
|
|
|
|
|
|
|
Note I Debt
Debt consists of the following:
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
|
(in thousands) |
|
Indebtedness to banks under revolving credit agreement,
expiring December 22, 2009 |
|
$ |
|
|
|
$ |
25,000 |
|
6.75% senior notes ($950.0 million face value) due July 1, 2013 |
|
|
960,589 |
|
|
|
961,613 |
|
Promissory note |
|
|
15,405 |
|
|
|
17,523 |
|
Other |
|
|
5 |
|
|
|
7,011 |
|
|
|
|
|
|
|
|
|
|
|
975,999 |
|
|
|
1,011,147 |
|
Less current portion |
|
|
3,124 |
|
|
|
9,824 |
|
|
|
|
|
|
|
|
Long-term debt |
|
$ |
972,875 |
|
|
$ |
1,001,323 |
|
|
|
|
|
|
|
|
On December 22, 2004, the Company entered into a $700.0 million revolving credit facility that
matures on December 22, 2009. The rate of interest on borrowings under the credit facility is a
floating rate based on LIBOR. The Companys credit facility is secured by substantially all of its
assets as well as its ownership interests in substantially all of its subsidiaries, except its
ownership interests in Arch Western and its subsidiaries. The credit facility replaced the
Companys existing $350.0 million revolving credit facility. At September 30, 2005, the Company had
$106.2 million in letters of credit outstanding, resulting in $593.8 million of unused borrowings
under the revolver. Financial covenant requirements may restrict the amount of unused capacity
available to the Company for borrowings and letters of credit. As of September 30, 2005, the
Company was not restricted by financial covenants.
On October 22, 2004, the Company issued $250.0 million of 6.75% Senior Notes due 2013 at a price of
104.75% of par. Interest on the notes is payable on January 1 and July 1 of each year, beginning on
January 1, 2005. The senior notes were issued under an indenture dated June 25, 2003, under which the Company previously
issued $700.0 million of 6.75% Senior Notes due 2013. The senior notes are guaranteed by Arch
Western and certain of Arch Westerns subsidiaries and are secured by a security interest in loans
made to Arch Coal by Arch Western. The terms of the senior notes contain restrictive covenants that
limit Arch Westerns ability to, among other things, incur additional debt, sell or transfer
assets, and make certain investments.
On July 31, 2004, the Company issued a five-year, $22.0 million non-interest bearing note to help
fund the Canyon Fuel acquisition. At its issuance, the note was discounted to its present value
using a rate of 7.0%. The promissory note is payable in quarterly installments of $1.0 million
through July 2008 and $1.5 million from October 2008 through July 2009.
Note J Contingencies
The Company is a party to numerous claims and lawsuits with respect to various matters. The
Company provides for costs related to contingencies when a loss is probable and the amount is
reasonably determinable. After conferring with counsel, it is the opinion of management that the
ultimate resolution of these claims, to the extent not provided
9
for, will not have a material
adverse effect on the consolidated financial position, results of operations or liquidity of the
Company.
Note K Transactions or Events Affecting Comparability of Reported Results
During the third quarter of 2005, the Company recognized a gain of $9.0 million on the sale of
surface land rights at its Central Appalachian operations in West Virginia. The gain is reported as
other operating income in the accompanying Condensed Consolidated Statements of Operations.
During the third quarter, contingencies relating to the outcome of certain lawsuits were resolved.
The Company recorded a charge of $2.6 million during the third quarter to reflect its best estimate
of the cost of the resolution of these lawsuits in cost of coal sales in the accompanying Condensed
Consolidated Statements of Operations.
The change in market value of SO2 and coal derivatives was expense of $5.5 million and $7.5 million
for the three months and nine months ended September 30, 2005, respectively, recorded in other
operating income in the accompanying Condensed Consolidated Statements of Operations.
During the second quarter of 2005, the Company participated in a settlement from its insurance
broker related to certain types of commissions previously paid and recognized a gain of $1.0
million. The gain is reflected in other operating income in the Condensed Consolidated Statements
of Operations.
During the second quarter of 2005, the Company assigned its rights and obligations to an unused
loadout facility to a third party resulting in a gain of $1.7 million. Of the $1.7 million gain
recognized, $1.2 million was recorded as an increase to other operating income in the Condensed
Consolidated Statements of Operations while $0.5 million was reflected as a reduction in cost of
coal sales in the Condensed Consolidated Statements of Operations representing the elimination of
the reclamation obligation associated with this facility.
During the second quarter of 2005, the State of Wyoming completed an audit related to severance
taxes for the period of 1999 through 2001. The audit resulted in the Company being assessed
additional taxes. The Company has recorded a liability of $4.5 million on its books related to the
audit of which $2.6 million was recorded in cost of coal sales and interest associated with the
assessment of $1.4 million was recorded as interest expense in the second quarter in the Condensed
Consolidated Statements of Operations.
During the first quarter of 2005, the Company assigned its rights and obligations on several
parcels of land to a third party resulting in a gain of $9.3 million. The gain is reflected in
other operating income in the accompanying Condensed Consolidated Statements of Operations.
During the first quarter of 2005, the Company recognized a gain of $9.5 million resulting from
various equipment sales. The gain is reported as other operating income in the accompanying
Condensed Consolidated Statements of Operations.
During the third quarter of 2004, the Company was notified by the IRS that it would receive
additional black lung excise tax refunds and related interest from black lung claims that were
originally denied by the IRS in 2002. The Company recognized a gain of $2.8 million ($2.1 million
of principal and $0.7 million of interest) related to the claims. The $2.1 million principal amount
was recorded as a reduction of cost of coal sales, while the $0.7 million interest amount was
recorded as interest income.
During the second quarter of 2004, the Office of Surface Mining completed an audit of certain of
the Companys federal reclamation fee filings for the period from 1998 through 2003. The audit
resulted in the Company being assessed additional fees of $1.3 million and interest of $0.2
million. The additional fees were recorded as a component of cost of coal sales in the accompanying
Condensed Consolidated Statements of Operations, while the interest portion has been reflected as
interest expense.
During the first quarter of 2004,
Canyon Fuel, while accounted for under the equity method, began
the process of temporarily idling its Skyline Mine, and incurred severance costs of
$3.2 million for the nine months ended September 30, 2004. The
Companys share of these costs totals $2.1 million, and is reflected
in income from equity investments in the Condensed Consolidated Statements of Operations.
10
On June 25, 2003, the Company repaid the $675 million term loan of its Arch Western subsidiary with
the proceeds from the offering of $700.0 million in senior notes. The Company had designated
certain interest rate swaps as hedges of the variable rate interest payments due under the Arch
Western term loans. Pursuant to the requirements of Statement of Financial Accounting Standards No.
133, Accounting for Derivative Instruments and Hedging Activities (FAS 133), historical
mark-to-market adjustments related to these swaps through June 25, 2003 were deferred as a
component of Accumulated Other Comprehensive Loss. Subsequent to the repayment of the term loans,
these deferred amounts will be amortized as additional expense over the contractual terms of the
swap agreements. For the three months ending September 30, 2005 and 2004, the Company recognized
$1.9 million and $2.1 million of expense for the three months ended September 30, 2005 and 2004,
respectively, related to the amortization of previously deferred mark-to-market adjustments. For
the nine months ending September 30, 2005 and 2004, the Company recognized $6.1 million and $6.2
million of expense, respectively, related to the amortization of previously deferred mark-to-market
adjustments.
Note L Earnings Per Share
The following tables set forth the computation of basic and diluted earnings per common share from
continuing operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2005 |
|
|
|
Numerator |
|
|
Denominator |
|
|
Per Share |
|
|
|
(Income) |
|
|
(Shares) |
|
|
Amount |
|
Basic EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
18,926 |
|
|
|
63,858 |
|
|
$ |
0.30 |
|
Preferred stock dividends |
|
|
(1,797 |
) |
|
|
|
|
|
|
(0.03 |
) |
|
|
|
|
|
|
|
|
|
|
|
Basic income available to common shareholders |
|
$ |
17,129 |
|
|
|
|
|
|
$ |
0.27 |
|
|
|
|
|
|
|
|
|
|
|
|
Effect of dilutive securities: |
|
|
|
|
|
|
|
|
|
|
|
|
Effect of common stock equivalents arising from
stock options and restricted stock grants |
|
|
|
|
|
|
933 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
Diluted income available to common shareholders |
|
$ |
17,129 |
|
|
|
64,791 |
|
|
$ |
0.26 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2004 |
|
|
|
Numerator |
|
|
Denominator |
|
|
Per Share |
|
|
|
(Income) |
|
|
(Shares) |
|
|
Amount |
|
Basic EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
10,775 |
|
|
|
54,874 |
|
|
$ |
0.19 |
|
Preferred stock dividends |
|
|
(1,797 |
) |
|
|
|
|
|
|
(0.03 |
) |
|
|
|
|
|
|
|
|
|
|
|
Basic income available to common shareholders |
|
$ |
8,978 |
|
|
|
|
|
|
$ |
0.16 |
|
|
|
|
|
|
|
|
|
|
|
|
Effect of dilutive securities: |
|
|
|
|
|
|
|
|
|
|
|
|
Effect of common stock equivalents arising from
stock options and restricted stock grants |
|
|
|
|
|
|
964 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
Diluted income available to common shareholders |
|
$ |
8,978 |
|
|
|
55,838 |
|
|
$ |
0.16 |
|
|
|
|
|
|
|
|
|
|
|
11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2005 |
|
|
|
Numerator |
|
|
Denominator |
|
|
Per Share |
|
|
|
(Income) |
|
|
(Shares) |
|
|
Amount |
|
Basic EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
28,975 |
|
|
|
63,382 |
|
|
$ |
0.46 |
|
Preferred stock dividends |
|
|
(5,391 |
) |
|
|
|
|
|
|
(0.09 |
) |
|
|
|
|
|
|
|
|
|
|
|
Basic income available to common shareholders |
|
$ |
23,584 |
|
|
|
|
|
|
$ |
0.37 |
|
|
|
|
|
|
|
|
|
|
|
|
Effect of dilutive securities: |
|
|
|
|
|
|
|
|
|
|
|
|
Effect of common stock equivalents arising from
stock options and restricted stock grants |
|
|
|
|
|
|
989 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
Diluted income available to common shareholders |
|
$ |
23,584 |
|
|
|
64,371 |
|
|
$ |
0.37 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2004 |
|
|
|
Numerator |
|
|
Denominator |
|
|
Per Share |
|
|
|
(Income) |
|
|
(Shares) |
|
|
Amount |
|
Basic EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
91,865 |
|
|
|
54,431 |
|
|
$ |
1.69 |
|
Preferred stock dividends |
|
|
(5,391 |
) |
|
|
|
|
|
|
(0.10 |
) |
|
|
|
|
|
|
|
|
|
|
|
Basic income available to common shareholders |
|
$ |
86,474 |
|
|
|
|
|
|
$ |
1.59 |
|
|
|
|
|
|
|
|
|
|
|
|
Effect of dilutive securities: |
|
|
|
|
|
|
|
|
|
|
|
|
Effect of common stock equivalents arising from
stock options and restricted stock grants |
|
|
|
|
|
|
935 |
|
|
|
|
|
Effect of common stock equivalents arising from
convertible preferred stock |
|
|
5,391 |
|
|
|
6,896 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
Diluted income available to common shareholders |
|
$ |
91,865 |
|
|
|
62,262 |
|
|
$ |
1.48 |
|
|
|
|
|
|
|
|
|
|
|
Note M Guarantees
The Company holds a 17.5% general partnership interest in Dominion Terminal Associates (DTA),
which operates a ground storage-to-vessel coal transloading facility in Newport News, Virginia. DTA
leases the facility from Peninsula Ports Authority of Virginia (PPAV) for amounts sufficient to
meet debt-service requirements. Financing is provided through $132.8 million of tax-exempt bonds
issued by PPAV (of which the Company is responsible for 17.5%, or $23.2 million) that mature July
1, 2016. Under the terms of a throughput and handling agreement with DTA, each partner is charged
its share of cash operating and debt-service costs in exchange for the right to use its share of
the facilitys loading capacity and is required to make periodic cash advances to DTA to fund such
costs. On a cumulative basis, costs exceeded cash advances by $14.8 million at September 30, 2005,
which is included in other noncurrent liabilities. Future payments for fixed operating costs and
debt service are estimated to approximate $2.7 million annually through 2015 and $26.0 million in
2016.
In connection with the Companys acquisition of the coal operations of Atlantic Richfield Company
(ARCO) and the simultaneous combination of the acquired ARCO operations and the Companys Wyoming
operations into the Arch Western joint venture, the Company agreed to indemnify another member of
Arch Western against certain tax liabilities in the event that such liabilities arise as a result
of certain actions taken prior to June 1, 2013, including the sale or other disposition of certain
properties of Arch Western, the repurchase of certain equity interests in Arch Western by Arch
Western or the reduction under certain circumstances of indebtedness incurred by Arch Western in
connection with the acquisition. Depending on the time at which any such indemnification obligation
were to arise, it could have a material adverse effect on the business, results of operations and
financial condition of the Company.
Note N Segment Information
The Company produces steam and metallurgical coal from surface and deep mines for sale to utility,
industrial and export markets. The Company operates only in the United States, with mines in the
major low-sulfur coal basins. The Company has three reportable business segments, which are based on the coal basins in which the
Company operates. Coal quality, coal seam height, transportation methods and regulatory issues are
generally consistent within
12
a basin. Accordingly, market and contract pricing have developed by
coal basin. The Company manages its coal sales by coal basin, not by individual mine complex. Mine
operations are evaluated based on their per-ton operating costs (defined as including all mining
costs but excluding pass-through transportation expenses). The Companys reportable segments are
Powder River Basin (PRB), Central Appalachia (CAPP) and Western Bituminous (WBIT). The Companys
operations in the Powder River Basin are located in Wyoming and include one operating surface mine
and one idle surface mine. The Companys operations in Central Appalachia are located in southern
West Virginia, eastern Kentucky, and Virginia and include 18 underground mines and nine surface
mines. The Companys Western Bituminous operations are located in southern Wyoming, Colorado and
Utah and include four underground mines.
Operating segment results for the three and nine months ending September 30, 2005 and 2004 are
presented below. Results for the operating segments include all direct costs of mining. Corporate,
Other and Eliminations includes corporate overhead, land management, other support functions, and
the elimination of intercompany transactions.
Three months ending September 30, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other and |
|
|
|
|
(Amounts in thousands, except per ton amounts) |
|
|
PRB |
|
|
CAPP |
|
|
WBIT |
|
|
Eliminations |
|
|
Consolidated |
|
Coal sales |
|
|
|
|
|
$ |
189,112 |
|
|
$ |
358,610 |
|
|
$ |
106,994 |
|
|
$ |
|
|
|
$ |
654,716 |
|
Income from operations |
|
|
|
|
|
|
18,996 |
|
|
|
829 |
|
|
|
28,882 |
|
|
|
(14,530 |
) |
|
|
34,177 |
|
Total assets |
|
|
|
|
|
|
1,213,821 |
|
|
|
2,202,946 |
|
|
|
1,716,482 |
|
|
|
(1,787,347 |
) |
|
|
3,345,902 |
|
Depreciation, depletion and amortization |
|
|
|
|
|
|
27,230 |
|
|
|
18,383 |
|
|
|
11,855 |
|
|
|
374 |
|
|
|
57,842 |
|
Capital expenditures |
|
|
|
|
|
|
13,330 |
|
|
|
68,793 |
|
|
|
23,295 |
|
|
|
4,130 |
|
|
|
109,548 |
|
Operating cost per ton |
|
|
|
|
|
|
7.43 |
|
|
|
43.23 |
|
|
|
14.62 |
|
|
|
|
|
|
|
|
|
Three months ending September 30, 2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other and |
|
|
|
|
(Amounts in thousands, except per ton amounts) |
|
|
|
|
|
PRB |
|
|
CAPP |
|
|
WBIT |
|
|
Eliminations |
|
|
Consolidated |
|
Coal sales |
|
|
|
|
|
$ |
160,495 |
|
|
$ |
303,133 |
|
|
$ |
64,148 |
|
|
$ |
|
|
|
$ |
527,776 |
|
Income from equity investments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,143 |
|
|
|
|
|
|
|
1,143 |
|
Income from operations |
|
|
|
|
|
|
12,149 |
|
|
|
20,038 |
|
|
|
5,889 |
|
|
|
(11,741 |
) |
|
|
26,335 |
|
Total assets |
|
|
|
|
|
|
1,129,833 |
|
|
|
2,066,842 |
|
|
|
1,373,331 |
|
|
|
(1,631,879 |
) |
|
|
2,938,127 |
|
Depreciation, depletion and amortization |
|
|
|
|
|
|
21,145 |
|
|
|
15,224 |
|
|
|
6,850 |
|
|
|
273 |
|
|
|
43,492 |
|
Capital expenditures |
|
|
|
|
|
|
13,692 |
|
|
|
28,375 |
|
|
|
8,326 |
|
|
|
124,041 |
|
|
|
174,434 |
|
Operating cost per ton |
|
|
|
|
|
|
6.46 |
|
|
|
35.45 |
|
|
|
15.30 |
|
|
|
|
|
|
|
|
|
13
Nine months ending September 30, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other and |
|
|
|
|
(Amounts in thousands, except per ton amounts) |
|
PRB |
|
|
CAPP |
|
|
WBIT |
|
|
Eliminations |
|
|
Consolidated |
|
Coal sales |
|
$ |
559,901 |
|
|
$ |
1,019,340 |
|
|
$ |
309,737 |
|
|
$ |
|
|
|
$ |
1,888,978 |
|
Income (loss) from operations |
|
|
62,574 |
|
|
|
(1,611 |
) |
|
|
67,988 |
|
|
|
(47,328 |
) |
|
|
81,623 |
|
Depreciation, depletion and amortization |
|
|
79,666 |
|
|
|
51,387 |
|
|
|
28,875 |
|
|
|
959 |
|
|
|
160,887 |
|
Capital expenditures |
|
|
30,331 |
|
|
|
162,614 |
|
|
|
48,258 |
|
|
|
7,703 |
|
|
|
248,906 |
|
Operating cost per ton |
|
|
7.09 |
|
|
|
42.74 |
|
|
|
14.68 |
|
|
|
|
|
|
|
|
|
Nine months ending September 30, 2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other and |
|
|
|
|
(Amounts in thousands, except per ton amounts) |
|
PRB |
|
|
CAPP |
|
|
WBIT |
|
|
Eliminations |
|
|
Consolidated |
|
Coal sales |
|
$ |
397,951 |
|
|
$ |
837,901 |
|
|
$ |
118,191 |
|
|
$ |
|
|
|
$ |
1,354,043 |
|
Income from equity investments |
|
|
|
|
|
|
|
|
|
|
8,410 |
|
|
|
2,418 |
|
|
|
10,828 |
|
Income from operations |
|
|
42,910 |
|
|
|
39,818 |
|
|
|
17,346 |
|
|
|
58,039 |
|
|
|
158,113 |
|
Depreciation, depletion and amortization |
|
|
52,651 |
|
|
|
47,090 |
|
|
|
14,783 |
|
|
|
1,153 |
|
|
|
115,677 |
|
Capital expenditures |
|
|
41,275 |
|
|
|
62,541 |
|
|
|
11,356 |
|
|
|
128,394 |
|
|
|
243,566 |
|
Operating cost per ton |
|
|
6.19 |
|
|
|
34.20 |
|
|
|
15.82 |
|
|
|
|
|
|
|
|
|
Reconciliation of segment income from operations to consolidated income before income taxes and
cumulative effect of accounting change:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2005 |
|
|
2004 |
|
|
2005 |
|
|
2004 |
|
|
|
(in thousands) |
|
Income from operations |
|
$ |
34,177 |
|
|
$ |
26,335 |
|
|
$ |
81,623 |
|
|
$ |
158,113 |
|
Interest expense |
|
|
(17,994 |
) |
|
|
(16,220 |
) |
|
|
(55,454 |
) |
|
|
(45,062 |
) |
Interest income |
|
|
2,109 |
|
|
|
1,110 |
|
|
|
5,635 |
|
|
|
2,723 |
|
Other non-operating expense |
|
|
(3,516 |
) |
|
|
(1,605 |
) |
|
|
(7,579 |
) |
|
|
(5,364 |
) |
|
|
|
|
Income before income taxes |
|
$ |
14,776 |
|
|
$ |
9,620 |
|
|
$ |
24,225 |
|
|
$ |
110,410 |
|
|
|
|
Note O Subsequent Events
Asset dispositions Magnum Coal Company
On October 11, 2005, the Company and affiliates of ArcLight Capital Partners, LLC signed a
definitive agreement to contribute certain mining operations and properties to a new company
to be called Magnum Coal Company (Magnum) that would mine and market low-sulfur coal in the
Central Appalachian region. Arch will contribute four of its active Central Appalacian mining
operations and a total of 455 million tons of reserves to Magnum. These mining properties together
had sales of 9.7 million tons through September 30, 2005.
The Company and the affiliates of ArcLight Capital will receive approximately 37.5% and 62.5%,
respectively, of the ownership interest in Magnum. The transaction is contingent upon conclusion of
a number of agreements, and there is no assurance that the transaction will be completed.
West Elk mine evacuation
On October 27, 2005, the Company conducted a precautionary evacuation of its West Elk mine after
elevated readings of combustion-related gases were detected in an area of the mine where mining
activities were completed, but final longwall equipment removal had not yet occurred. A portion of
the equipment had already been moved to
14
another area of the mine where the Company intends to begin mining and the remainder is currently
isolated from the affected area by permanent and temporary seals.
Once the mine is determined to be safe for re-entry, the longwall equipment can be moved and
production can resume in the new area. While management does not anticipate an extended evacuation
or significant impact on production or results of operations, we cannot currently estimate when
production will resume.
Note P Reclassifications
Certain amounts in the 2004 financial statements have been reclassified to conform to the
classifications in the 2005 financial statements with no effect on previously reported net income
or members equity.
15
ITEM 2. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FORWARD-LOOKING STATEMENTS
In this quarterly report, statements that are not reported financial results or other
historical information are forward-looking statements. Forward-looking statements give current
expectations or forecasts of future events and are not guarantees of future performance. They are
based on our managements expectations that involve a number of business risks and uncertainties,
any of which could cause actual results to differ materially from those expressed in or implied by
the forward-looking statements.
Forward-looking statements can be identified by the fact that they do not relate strictly to
historic or current facts. They use words such as anticipate, estimate, project, intend,
plan, believe and other words and terms of similar meaning in connection with any discussion of
future operating or financial performance. In particular, these include statements relating to:
|
|
our expectation of continued growth in the demand for our coal by the domestic electric
generation industry; |
|
|
|
our belief that legislation and regulations relating to the Clean Air Act and other
proposed environmental initiatives and the relatively higher costs of competing fuels will
increase demand for our compliance and low sulfur coal; |
|
|
|
our expectations regarding incentives to generators of electricity to minimize their
fuel costs as a result of electric utility deregulation; |
|
|
|
our expectation that we will continue to have adequate liquidity from cash flow from operations; |
|
|
|
a variety of market, operational, geologic, permitting, labor, transportation and weather related factors; |
|
|
|
our expectations regarding any synergies to be derived from the Triton acquisition; and |
|
|
|
the other risks and uncertainties which are described below under Contingencies and
Certain Trends and Uncertainties, including, but not limited to, the following: |
|
o |
|
Due to the significant amount of our debt, a downturn in economic or industry
conditions could materially affect our ability to meet our future financial and
liquidity obligations. |
|
|
o |
|
A reduction in consumption by the domestic electric generation industry may cause
our profitability to decline. |
|
|
o |
|
Extensive environmental laws and regulations could cause the volume of our sales
to decline. |
|
|
o |
|
The coal industry is highly regulated, which restricts our ability to conduct
mining operations and may cause our profitability to decline. |
|
|
o |
|
We may not be able to obtain or renew our surety bonds on acceptable terms. |
|
|
o |
|
Unanticipated mining conditions may cause profitability to fluctuate. |
|
|
o |
|
Deregulation of the electric utility industry may cause customers to be more
price-sensitive, resulting in a potential decline in our profitability. |
|
|
o |
|
Our profitability may be adversely affected by the status of our long-term coal supply contracts. |
|
|
o |
|
Decreases in purchases of coal by our largest customers could adversely affect our revenues. |
|
|
o |
|
An unavailability of coal reserves would cause our profitability to decline. |
16
|
o |
|
Disruption in, or increased costs of, transportation services could adversely affect our profitability. |
|
|
o |
|
Numerous uncertainties exist in estimating our economically recoverable coal
reserves, and inaccuracies in our estimates could result in lower revenues, higher costs
or decreased profitability. |
|
|
o |
|
Title defects or loss of leasehold interests in our properties could result in
unanticipated costs or an inability to mine these properties. |
|
|
o |
|
All acquisitions involve a number of inherent risks, any of which could cause us
not to realize the benefits anticipated to result. |
|
|
o |
|
Changes in our credit ratings could adversely affect our costs and expenses. |
|
|
o |
|
Some of our agreements impose significant potential indemnification obligations on us. |
|
|
o |
|
Our expenditures for postretirement medical and pension benefits have increased
in recent periods and could further increase in the future. |
|
|
o |
|
Pending litigation involving third parties may impact our cash balance pension
plan and the retirement account formula used in its administration. |
|
|
o |
|
Any inability to comply with restrictions imposed by our credit facilities and
other debt arrangements could result in a default under these agreements. |
|
|
o |
|
Our estimated financial results may prove to be inaccurate. |
We cannot guarantee that any forward-looking statements will be realized, although we believe that
we have been prudent in our plans and assumptions. Achievement of future results is subject to
risks, uncertainties and assumptions that may prove to be inaccurate. Should known or unknown risks
or uncertainties materialize, or should underlying assumptions prove to be inaccurate, actual
results could vary materially from those anticipated, estimated or projected.
We undertake no obligation to publicly update forward-looking statements, whether as a result of
new information, future events or otherwise, except as may be required by law. You are advised,
however, to consider any additional disclosures that we may make on related subjects in future
filings with the SEC. You should understand that it is not possible to predict or identify all
factors that could cause our actual results to differ. Consequently, you should not consider any
such list to be a complete set of all potential risks or uncertainties.
RESULTS OF OPERATIONS
Items Affecting Comparability of Reported Results
The comparison of our operating results for the quarter-to-date and year-to-date periods ending
September 30, 2005 and 2004 are affected by the following items:
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
(Dollar amounts in millions) |
|
2005 |
|
|
2004 |
|
|
2005 |
|
|
2004 |
|
Income from operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on land, equipment and facility sales |
|
$ |
9.8 |
|
|
$ |
|
|
|
$ |
31.6 |
|
|
$ |
|
|
Mark to market adjustments on SO2 and coal
derivatives |
|
|
(5.5 |
) |
|
|
|
|
|
|
(7.5 |
) |
|
|
|
|
Resolution of lawsuits |
|
|
(2.6 |
) |
|
|
|
|
|
|
(2.6 |
) |
|
|
|
|
Insurance broker settlement |
|
|
|
|
|
|
|
|
|
|
1.0 |
|
|
|
|
|
Wyoming severance tax assessment |
|
|
|
|
|
|
|
|
|
|
(2.6 |
) |
|
|
|
|
Long-term incentive compensation expense |
|
|
|
|
|
|
|
|
|
|
(9.9 |
) |
|
|
|
|
Gain on sale of NRP units |
|
|
|
|
|
|
.3 |
|
|
|
|
|
|
|
90.2 |
|
Black lung excise tax refund |
|
|
|
|
|
|
2.1 |
|
|
|
|
|
|
|
2.1 |
|
Severance costs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2.1 |
) |
Reclamation fee assessment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1.3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net impact on operating income |
|
|
1.7 |
|
|
|
2.4 |
|
|
|
10.0 |
|
|
|
88.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net interest on tax assessments/refunds |
|
|
|
|
|
|
0.7 |
|
|
|
(1.4 |
) |
|
|
0.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net impact on pre-tax income |
|
$ |
1.7 |
|
|
$ |
3.1 |
|
|
$ |
8.6 |
|
|
$ |
89.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain from land, equipment and facility sales
During the quarter and nine months ended September 30, 2005, we recognized gains of $9.8 million
and $31.6 million, respectively, related to gains for land, equipment and facility sales. During
the first quarter of 2005, we assigned our rights and obligations on several parcels of land to a
third party resulting in a gain of $9.3 million. During the first quarter of 2005, we recognized a
gain of $9.5 million resulting from various equipment sales. In the third quarter of 2005, we sold
surface land resulting in a gain of $9.0 million and gains on miscellaneous property of $0.8
million. The gains are reflected in other operating income in the accompanying Condensed
Consolidated Statements of Operations. During the second quarter of 2005, we assigned our rights
and obligations to an unused loadout facility to a third party resulting in a gain of $1.7 million.
Of the $1.7 million gain recognized, $1.2 million was recorded as an increase to other revenues in
the Condensed Consolidated Statements of Operations while $0.5 million was reflected as a reduction
in cost of coal sales in the Condensed Consolidated Statements of Operations representing the
elimination of the reclamation obligation associated with this facility.
Mark to market adjustments on SO2 and coal derivatives
Amounts represent the amount recorded to reflect the change in fair market value during the period
and are reflected in other operating income in the Condensed Consolidated Statements of Operations.
These are discussed in more depth in the market risk disclosures included in Liquidity and Capital
Resources.
Insurance broker settlement
During the second quarter of 2005, we participated in a settlement from our insurance broker
related to certain types of commissions previously paid and recognized a gain of $1.0 million. The
gain is reflected in other operating income in the Condensed Consolidated Statements of Operations.
Wyoming severance tax assessment
During the second quarter of 2005, the State of Wyoming completed an audit related to severance
taxes for the period of 1999 through 2001. The audit resulted in additional taxes being assessed
against us. We are reviewing the assessment and as of September 30, 2005, we have recorded a
liability of $4.5 million on our books related to the audit. Of the $4.5 million recognized, $2.6
million was recorded during the second quarter of 2005 in cost of coal sales in the accompanying
Condensed Consolidated Statements of Operations, while $1.4 million, representing
18
interest associated with the assessment, was recorded as interest expense in the
second quarter of 2005 in the Condensed Consolidated Statements of Operations.
Long-term incentive compensation expense
During 2004, we granted an award of 220,766 shares of performance-contingent phantom stock that
vested in the event the Companys stock price reached an average pre-established price over a
period of 20 consecutive trading days within five years following the date of grant. During the
first quarter of 2005, the price contingency discussed above was met, and the award was paid in a
combination of Company stock and cash. As such, we recognized a $9.9 million charge as a component
of selling, general and administrative expense ($9.1 million) and cost of coal sales ($0.8 million)
in the accompanying Condensed Consolidated Statements of Operations.
Gain on sale of NRP units
During the nine months ended September 30, 2004, we sold the majority of our remaining limited
partnership units of Natural Resource Partners, LP (NRP) for proceeds of approximately $105.4
million. The sales resulted in a gain of $90.2 million.
Black lung excise tax refund
During the third quarter of 2004, the Company was notified by the IRS that it would receive
additional black lung excise tax refunds and related interest from black lung claims that were
originally denied by the IRS in 2002. The Company recognized a gain of $2.8 million ($2.1 million
of principal and $0.7 million of interest) related to the claims. The $2.1 million principal amount
was recorded as a reduction of cost of coal sales, while the $0.7 million interest amount was
recorded as interest income.
Severance costs Skyline Mine
During the first quarter of 2004, Canyon Fuel, our equity method investment, began the process of
idling its Skyline Mine (the idling process was completed in May 2004), and incurred severance
costs of $3.2 million for the nine months ended September 30, 2004. Our 65% share of
these costs totals $2.1 million (which was prior to our purchase of the remaining 35% interest) for
the nine months ended September 30, 2004, and is reflected in income from equity investments in the
accompanying Condensed Consolidated Statements of Operations.
Reclamation fee assessment
During the nine months ended September 30, 2004, the Office of Surface Mining completed an audit of
certain of our federal reclamation fee filings for the period from 1998 through 2003. The audit
resulted in an assessment of additional fees of $1.3 million and interest of $0.2 million. The
additional fees have been recorded as a component of cost of coal sales in the accompanying
Condensed Consolidated Statements of Operations, while the interest portion has been reflected as
interest expense.
Quarter Ended September 30, 2005 Compared to Quarter Ended September 30, 2004
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
|
|
|
September 30, |
|
|
Increase (Decrease) |
|
|
|
2005 |
|
|
2004 |
|
|
$ |
|
|
% |
|
|
|
(Amounts in thousands, except per ton data) |
|
Coal sales |
|
$ |
654,716 |
|
|
$ |
527,776 |
|
|
$ |
126,940 |
|
|
|
24.1 |
% |
Tons sold |
|
|
35,211 |
|
|
|
33,807 |
|
|
|
1,404 |
|
|
|
4.2 |
% |
Coal sales realization per ton sold |
|
$ |
18.59 |
|
|
$ |
15.61 |
|
|
$ |
2.98 |
|
|
|
19.1 |
% |
19
Tons sold by operating segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Three Months Ended |
|
|
|
September 30, 2005 |
|
|
September 30, 2004 |
|
|
|
tons |
|
|
% of total |
|
|
tons |
|
|
% of total |
|
|
|
|
|
|
(Amounts in thousands) |
|
|
|
|
|
Powder River Basin |
|
|
22,536 |
|
|
|
64.0 |
% |
|
|
22,646 |
|
|
|
67.0 |
% |
Central Appalachia |
|
|
7,976 |
|
|
|
22.7 |
% |
|
|
7,616 |
|
|
|
22.5 |
% |
Western Bituminous Region |
|
|
4,699 |
|
|
|
13.3 |
% |
|
|
3,545 |
|
|
|
10.5 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating regions |
|
|
35,211 |
|
|
|
100.0 |
% |
|
|
33,807 |
|
|
|
100.0 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal sales. The increase in coal sales resulted from the combination of higher pricing, increased
volumes and the acquisitions of Triton in the Powder River Basin on August 20, 2004 and the
remaining 35% interest in Canyon Fuel in the Western Bituminous region on July 31, 2004.
Volumes increased
32.6% at our Western Bituminous region in addition to a 4.7% increase in volumes
in Central Appalachia. Despite the acquisition of Triton in the Powder River Basin on August 20,
2004, volumes at our Powder River Basin operations declined 0.5% primarily due to lower purchased
coal volumes during the third quarter of 2005. The Western Bituminous region benefited from the
Canyon Fuel acquisition that was completed in the third quarter of 2004. Volumes in Central
Appalachia were higher during the current quarter primarily from increased brokered activity.
Transportation issues also affected sales volume in third quarter of 2004.
Per ton realizations
increased due primarily to higher contract prices in all three regions. In the
Powder River Basin, per ton realization increased 18.4%, as a result of increased base pricing and
higher SO2 quality premiums resulting from higher SO2 emission allowance prices. The Central
Appalachia region experienced an increase of 13.0%, as both contract and spot market prices were
higher than in the third quarter of 2004. Additionally, we received higher sales prices on our
metallurgical coal sales in the third quarter of 2005 as compared to the third quarter of 2004.
The Western Bituminous regions per ton realization increased 25.8%. In addition to higher contract
pricing, per ton realizations in the Western Bituminous region were also affected by the
acquisition of the remaining 35% interest in Canyon Fuel during the third quarter of 2004.
On a consolidated basis, the increase in per ton realizations was partially offset by the change in
mix of sales volumes among our operating regions as noted in the table above. Central Appalachia
has the highest average realization and Powder River Basin has the lowest average realization.
Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
|
|
|
September 30, |
|
|
Increase (Decrease) |
|
|
|
2005 |
|
|
2004 |
|
|
$ |
|
|
% |
|
|
|
(Amounts in thousands) |
|
Cost of coal sales |
|
$ |
546,725 |
|
|
$ |
448,638 |
|
|
$ |
98,087 |
|
|
|
21.9 |
% |
Depreciation, depletion and amortization |
|
|
57,842 |
|
|
|
43,491 |
|
|
|
14,351 |
|
|
|
33.0 |
% |
Selling, general and administrative expenses |
|
|
20,285 |
|
|
|
12,729 |
|
|
|
7,556 |
|
|
|
59.4 |
% |
Other operating expenses |
|
|
15,150 |
|
|
|
13,746 |
|
|
|
1,404 |
|
|
|
10.2 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
640,002 |
|
|
$ |
518,604 |
|
|
$ |
121,398 |
|
|
|
23.4 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of coal sales. The increase in the cost of coal sales resulted from the combination of higher
costs, increased volumes and the acquisitions of Triton in the Powder River Basin on August 20,
2004 and the remaining 35% interest in Canyon Fuel in the Western Bituminous region on July 31,
2004. Specific factors contributing to the increase are as follows (note that specifically the
increases discussed below for diesel fuel, explosives, utilities, operating supplies and repairs
and maintenance costs are partially due to the acquisitions of Triton and Canyon Fuel during the
third quarter of 2004):
|
|
|
Production taxes and coal royalties (which are incurred as a percentage of coal sales
realization) increased $25.2 million during the third quarter of 2005 compared to the same
period in the prior year. |
|
|
|
|
Our Central Appalachia operations incurred higher costs related to additional
processing necessary for coal sold in metallurgical markets as well as the move into less
favorable geologic conditions at our Mingo Logan mine during the third quarter of 2005. |
|
|
|
|
The cost of purchased coal increased $17.2 million, reflecting a combination of
increased purchase volumes and higher spot market prices that were prevalent during the
third quarter of 2005 compared to the same period in 2004. During the third quarter of
2005, we utilized purchased coal to fulfill steam coal sales commitments in order to direct
more of our produced coal into the metallurgical markets. |
20
|
|
|
Repairs and maintenance costs increased $5.2 million compared to the same period in the
prior year. |
|
|
|
|
Costs for diesel fuel, explosives and utilities increased $6.5 million, $2.9 million
and $1.7 million, respectively, compared to the same period in the prior year, resulting
from increased volumes and cost. |
|
|
|
|
Costs for operating supplies increased $8.2 million due partially to increased steel
prices during the current quarter compared to the prior years comparable quarter. |
Depreciation, depletion and amortization. The increase in depreciation, depletion and amortization
is due primarily to the property additions resulting from the acquisitions made during the third
quarter of 2004.
Regional Analysis:
Our operating costs (reflected below on a per-ton basis) are defined as including all mining costs,
which consist of all amounts classified as cost of coal sales (except pass-through transportation
costs and sales contract amortization) and all depreciation, depletion and amortization
attributable to mining operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
|
|
|
September 30, |
|
|
Increase (Decrease) |
|
|
|
2005 |
|
|
2004 |
|
|
$ |
|
|
% |
|
Powder River Basin |
|
$ |
7.43 |
|
|
$ |
6.46 |
|
|
$ |
0.97 |
|
|
|
15.0 |
% |
Central Appalachia |
|
$ |
43.23 |
|
|
$ |
35.45 |
|
|
$ |
7.78 |
|
|
|
21.9 |
% |
Western Bituminous Region |
|
$ |
14.62 |
|
|
$ |
15.30 |
|
|
$ |
(0.68 |
) |
|
|
(4.4 |
)% |
Powder River Basin On a per-ton basis, operating costs increased in the Powder River Basin
primarily due to higher diesel fuel costs ($0.19 per ton), higher parts and supplies costs ($0.11
per ton), higher depreciation, depletion and amortization costs ($0.27 per ton) and increased
production taxes and coal royalties ($0.54 per ton). Additionally, average costs were higher due to
the integration of the acquired North Rochelle mine into our Black Thunder mine in the third
quarter of 2004. These costs would have been largely offset by increased productivity, had rail
service not adversely impacted volumes during the quarter.
Central Appalachia Operating cost per ton increased due to increased costs for coal purchases
($3.22 per ton), increased labor costs ($0.98 per ton), increased costs for operating supplies
($0.10 per ton), increased diesel fuel ($0.20 per ton) and production taxes and coal royalties
($0.80 per ton) as well as the increased preparation costs for metallurgical coal discussed above.
Additionally, our Mingo Logan mine has moved into less favorable geological conditions, compared to
the comparable prior year quarter, resulting in higher costs.
Western Bituminous Region Operating cost per ton decreased primarily as a result of the
acquisition of the remaining 35% of Canyon Fuel during the third quarter of 2004. Canyon Fuels
mines in the aggregate have a lower operating cost per ton than the West Elk Mine, due to better
geologic conditions.
Selling, general and administrative expenses. Selling, general and administrative expenses
increased during the current quarter due primarily to increased contract services including legal
and professional fees ($1.6 million), employee severance expense associated with employees
terminated during the quarter ($1.3 million), executive deferred compensation expense ($2.0
million) and higher expenses resulting from amounts expected to be earned under our annual
incentive plans ($0.6 million).
Other Operating Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
|
|
|
September 30, |
|
|
Increase (Decrease) |
|
|
|
2005 |
|
|
2004 |
|
|
$ |
|
|
% |
|
|
|
(Amounts in thousands) |
|
Income from equity investments |
|
$ |
|
|
|
$ |
1,143 |
|
|
$ |
(1,143 |
) |
|
|
(100.0 |
)% |
Gain on sale of Natural Resource Partners, LP |
|
|
|
|
|
|
289 |
|
|
|
(289 |
) |
|
|
(100.0 |
)% |
Other operating income |
|
|
19,463 |
|
|
|
15,731 |
|
|
|
3,732 |
|
|
|
23.7 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
19,463 |
|
|
$ |
17,163 |
|
|
$ |
2,300 |
|
|
|
13.4 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
21
Other operating income. The increase in other operating income is primarily the result of the gain
on surface land of $9.0 million discussed above. This is partially offset by reduced bookout
income, related to the netting of coal sales and purchase contracts with the same counterparty, and
due to the elimination of administrative fees from Canyon Fuel subsequent to our acquisition of the
remaining 35% interest of this entity during the third quarter of 2004.
Interest Expense, Net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Increase (Decrease) |
|
|
|
September 30, |
|
|
To Net Income |
|
|
|
2005 |
|
|
2004 |
|
|
$ |
|
|
% |
|
|
|
(Amounts in thousands) |
|
Interest expense |
|
$ |
(17,994 |
) |
|
$ |
(16,220 |
) |
|
$ |
(1,774 |
) |
|
|
(10.9 |
%) |
Interest income |
|
|
2,109 |
|
|
|
1,110 |
|
|
|
999 |
|
|
|
90.0 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(15,885 |
) |
|
$ |
(15,110 |
) |
|
$ |
(775 |
) |
|
|
5.1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense. The increase in interest expense results from a higher amount of average
borrowings during the third quarter of 2005 as compared to the same period in 2004.
Interest Income. The increase in interest income results primarily from interest on short-term
investments.
22
Other Non-operating Income and Expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Increase (Decrease) |
|
|
|
September 30, |
|
|
To Net Income |
|
|
|
2005 |
|
|
2004 |
|
|
$ |
|
|
% |
|
|
|
(Amounts in thousands) |
|
Expenses resulting from early
debt extinguishment and termination
of hedge accounting for interest
rate swaps |
|
$ |
(1,949 |
) |
|
$ |
(2,066 |
) |
|
$ |
117 |
|
|
|
5.7 |
% |
Other non-operating income (expense) |
|
|
(1,567 |
) |
|
|
461 |
|
|
|
(2,028 |
) |
|
|
(439.9 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(3,516 |
) |
|
$ |
(1,605 |
) |
|
$ |
(1,911 |
) |
|
|
(119.1 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts reported as non-operating consist of income or expense resulting from the Companys
financing activities other than interest. As described above, the Companys results of operations
for the quarters ended September 30, 2005 and 2004 include expenses of $1.9 million and $2.1
million, respectively, related to the termination of hedge accounting and resulting amortization of
amounts that had previously been deferred. Other non-operating includes mark-to-market adjustments
related to certain swap activity that does not qualify for hedge accounting under FAS 133.
Income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Increase (Decrease) |
|
|
|
September 30, |
|
|
To Net Income |
|
|
|
2005 |
|
|
2004 |
|
|
$ |
|
|
% |
|
|
|
(Amounts in thousands) |
|
Benefit from income taxes |
|
$ |
(4,150 |
) |
|
$ |
(1,155 |
) |
|
$ |
2,995 |
|
|
|
259.3 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Companys effective tax rate is sensitive to changes in estimates of annual profitability and
excess depletion.
Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
|
|
|
|
September 30, |
|
|
Increase (Decrease) |
|
|
|
2005 |
|
|
2004 |
|
|
$ |
|
|
% |
|
|
|
(Amounts in thousands, except per ton data) |
|
Coal sales |
|
$ |
1,888,978 |
|
|
$ |
1,354,043 |
|
|
$ |
534,935 |
|
|
|
39.5 |
% |
Tons sold |
|
|
106,868 |
|
|
|
86,077 |
|
|
|
20,791 |
|
|
|
24.2 |
% |
Coal sales realization per ton sold |
|
$ |
17.68 |
|
|
$ |
15.73 |
|
|
$ |
1.95 |
|
|
|
12.4 |
% |
Tons sold by operating segment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30,2005 |
|
|
September 30,2004 |
|
|
|
tons |
|
|
% of total |
|
|
Tons |
|
|
% of total |
|
|
|
(Amounts in thousands) |
|
Powder River Basin |
|
|
69,582 |
|
|
|
65.1 |
% |
|
|
56,870 |
|
|
|
66.1 |
% |
Central Appalachia |
|
|
23,110 |
|
|
|
21.6 |
% |
|
|
22,471 |
|
|
|
26.1 |
% |
Western Bituminous Region |
|
|
14,176 |
|
|
|
13.3 |
% |
|
|
6,736 |
|
|
|
7.8 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating regions |
|
|
106,868 |
|
|
|
100.0 |
% |
|
|
86,077 |
|
|
|
100.0 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal sales. The increase in coal sales resulted from the combination of higher pricing, increased
volumes and the acquisitions of Triton in the Powder River Basin on August 20, 2004 and the
remaining 35% interest in Canyon Fuel in the Western Bituminous region on July 31, 2004.
Volumes increased dramatically during the first nine months of the year in 2005 compared to the
same period in 2004 in the Powder River Basin (an increase of 22.4%) and at our Western Bituminous
operations (an increase of 110.5%). Volumes in Central Appalachia increased by 2.8% compared to the
same period in the prior year. Volumes in both the Powder River Basin and the Western Bituminous
region benefited from the acquisitions that were completed in the third quarter of 2004.
23
Per ton realizations increased due primarily to higher contract prices in all three regions. In the
Powder River Basin, per ton realization increased 15.0%, as a result of increased base pricing and
above-market pricing on certain contracts acquired in the Triton acquisition as well as higher SO2
quality premiums resulting from higher SO2 emission allowance prices. The Central Appalachia Basin
experienced an increase of 18.3%, as both contract and spot market prices were higher than in the
first nine months of 2004. Additionally, we received higher sales prices on our metallurgical coal
sales in the first nine months of 2005 as compared to the first nine months of 2004. The Western
Bituminous regions per ton realization increased 24.5%. In addition to higher contract pricing,
per ton realizations in the Western Bituminous Basin were also affected by the acquisition of the
remaining 35% interest in Canyon Fuel during the third quarter of 2004.
On a consolidated basis, the increase in per ton realizations was partially offset by the change in
mix of sales volumes among our operating regions. As reflected in the table above, Central
Appalachia volumes (which have the highest average realization) increased slightly in the first
nine months of 2005 while volumes from lower realization regions (the Powder River Basin and
Western Bituminous Region) increased substantially from the prior years comparable period.
Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
|
|
|
|
September 30, |
|
|
Increase (Decrease) |
|
|
|
2005 |
|
|
2004 |
|
|
$ |
|
|
% |
|
|
|
(Amounts in thousands) |
|
Cost of coal sales |
|
$ |
1,608,439 |
|
|
$ |
1,161,259 |
|
|
$ |
447,180 |
|
|
|
38.5 |
% |
Depreciation, depletion and amortization |
|
|
160,887 |
|
|
|
115,677 |
|
|
|
45,210 |
|
|
|
39.1 |
% |
Selling, general and administrative expenses |
|
|
60,540 |
|
|
|
39,358 |
|
|
|
21,182 |
|
|
|
53.8 |
% |
Other operating expenses |
|
|
40,695 |
|
|
|
26,243 |
|
|
|
14,452 |
|
|
|
55.1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,870,561 |
|
|
$ |
1,342,537 |
|
|
$ |
528,024 |
|
|
|
39.3 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of coal sales. The increase in cost of coal sales is primarily due to the acquisitions of
Triton in the Powder River Basin on August 20, 2004 and the remaining 35% interest in Canyon Fuel
in the Western Bituminous region on July 31, 2004, along with the increase in sales sensitive costs
resulting from the previously discussed increase in revenues. Specific factors contributing to the
increase are as follows (note that specifically the increases discussed below for diesel fuel,
explosives, utilities, operating supplies and repairs and maintenance costs are partially due to
the acquisitions of Triton and Canyon Fuel during the third quarter of 2004):
|
|
|
Production taxes and coal royalties (which are incurred as a percentage of coal sales
realization) increased $86.9 million during the first nine months of 2005 compared to the
first nine months of 2004. |
|
|
|
|
Our Central Appalachia operations incurred higher costs related to additional
processing necessary for coal sold in metallurgical markets as well as the move into less
favorable geological conditions at our Mingo Logan mine during the first nine months of
2005. |
|
|
|
|
The cost of purchased coal increased $105.4 million, reflecting a combination of
increased purchase volumes and higher spot market prices that were prevalent during the
first nine months of 2005 compared to the same period in 2004. During the first nine months
of 2005, we utilized purchased coal to fulfill steam coal sales commitments in order to
direct more of our produced coal into the metallurgical markets. |
|
|
|
|
Repairs and maintenance costs increased $37.3 million compared to the same period in
the prior year. |
|
|
|
|
Costs for diesel fuel, explosives and utilities increased $24.3 million, $9.1 million
and $6.8 million, respectively, compared to the same period in the prior year. |
|
|
|
|
Costs for operating supplies increased $32.4 million due partially to increased steel
prices during the first nine months of 2005 compared to the same period in the prior year. |
Depreciation, depletion and amortization. The increase in depreciation, depletion and amortization
is due primarily to the property additions resulting from the acquisitions made during the third
quarter of 2004.
24
Regional Analysis:
Our operating costs (reflected below on a per-ton basis) are defined as including all mining costs,
which consist of all amounts classified as cost of coal sales (except pass-through transportation
costs and sales contract amortization) and all depreciation, depletion and amortization
attributable to mining operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months Ended |
|
|
|
|
|
|
September 30, |
|
|
Increase (Decrease) |
|
|
|
2005 |
|
|
2004 |
|
|
$ |
|
|
% |
|
Powder River Basin |
|
$ |
7.09 |
|
|
$ |
6.19 |
|
|
$ |
0.90 |
|
|
|
14.5 |
% |
Central Appalachia |
|
$ |
42.74 |
|
|
$ |
34.20 |
|
|
$ |
8.54 |
|
|
|
25.0 |
% |
Western Bituminous Region |
|
$ |
14.68 |
|
|
$ |
15.82 |
|
|
$ |
(1.14 |
) |
|
|
(7.2 |
)% |
Powder
River Basin On a per ton basis, operating costs increased in the Powder River Basin
primarily due to higher diesel fuel costs ($0.14 per ton), higher repairs and maintenance costs
($0.08 per ton), higher depreciation, depletion and amortization costs ($0.21 per ton), and
increased production taxes (including the $2.6 million severance tax accrual discussed above) and
coal royalties ($0.35 per ton). Additionally, average costs were higher due to the integration of
the acquired North Rochelle mine into our Black Thunder mine in the third quarter of 2004. These
costs would have been largely offset by increased productivity, had rail service not adversely
impacted volumes during the quarter.
Central Appalachia Operating cost per ton increased due to increased costs for coal purchases
($4.40 per ton), increased labor costs ($0.99 per ton), increased costs for operating supplies
($0.33 per ton), increased diesel fuel ($0.41 per ton) and production taxes and coal royalties
($0.63 per ton) as well as the increased preparation costs for metallurgical coal discussed above.
Additionally, the performance of our Mingo Logan mine has moved into less favorable geological
conditions, compared to the comparable prior year period, resulting in higher costs.
Western Bituminous Region Operating cost per ton decreased primarily due to increased production
activity as a result of the acquisition of the remaining 35% of Canyon Fuel during the third
quarter of 2004. Canyon Fuels mines in the aggregate have a lower operating cost per ton than the
West Elk Mine.
Selling, general and administrative expenses. Selling, general and administrative expenses
increased during the period due primarily to $9.5 million of expense that was recognized in the
first quarter of 2005 for the performance-contingent phantom stock award that was paid to certain
employees in March 2005. In addition, costs increased due to higher contract services including
legal and professional fees ($4.1 million), employee severance expense associated with several
employees terminated during the third quarter of 2005 ($1.3 million), and executive deferred
compensation expense ($3.5 million).
Other Operating Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months Ended |
|
|
|
|
|
|
September 30, |
|
|
Increase (Decrease) |
|
|
|
2005 |
|
|
2004 |
|
|
$ |
|
|
% |
|
|
|
(Amounts in thousands) |
|
Income from equity investments |
|
$ |
|
|
|
$ |
10,828 |
|
|
$ |
(10,828 |
) |
|
|
(100.0 |
)% |
Gain on sale of units of NRP |
|
|
|
|
|
|
90,244 |
|
|
|
(90,244 |
) |
|
|
(100.0 |
)% |
Other operating income |
|
|
63,206 |
|
|
|
45,535 |
|
|
|
17,671 |
|
|
|
38.8 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
63,206 |
|
|
$ |
146,607 |
|
|
$ |
(83,401 |
) |
|
|
(56.9 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other operating income. The increase in other operating income is primarily due to a $18.3 million
gain resulting from land sales, a gain on the sale of a facility of which $1.2 million was recorded
in other operating income, a $9.5 million gain resulting from various equipment sales and the
settlement from an insurance broker resulting in a gain of $1.0 million during the first nine
months of 2005 and are described previously. This was partially offset by the elimination of
administrative fees from Canyon Fuel subsequent to our acquisition of the remaining 35% interest
during the third quarter of 2004 and reduced bookout income of $6.8 million compared to the
comparable period in the prior year.
25
Interest Expense, Net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months Ended |
|
|
Increase (Decrease) |
|
|
|
September 30, |
|
|
To Net Income |
|
|
|
2005 |
|
|
2004 |
|
|
$ |
|
|
% |
|
|
|
(Amounts in thousands) |
|
Interest expense |
|
$ |
(55,454 |
) |
|
$ |
(45,062 |
) |
|
$ |
(10,392 |
) |
|
|
(23.1 |
)% |
Interest income |
|
|
5,635 |
|
|
|
2,723 |
|
|
|
2,912 |
|
|
|
106.9 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(49,819 |
) |
|
$ |
(42,339 |
) |
|
$ |
(7,480 |
) |
|
|
(17.7 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense. The increase in interest expense results from a higher amount of average
borrowings in the first nine months of 2005 as compared to the same period in 2004. In addition, we
recognized $1.4 million of interest expense associated with the severance tax assessed by the State
of Wyoming described above during the nine months of 2005.
Interest Income. The increase in interest income results primarily from interest on short-term
investments.
Other Non-operating Income and Expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
Increase (Decrease) |
|
|
|
September 30, |
|
|
To Net Income |
|
|
|
2005 |
|
|
2004 |
|
|
$ |
|
|
% |
|
|
|
(Amounts in thousands) |
|
Expenses resulting from early
debt extinguishment and termination
of hedge accounting for interest
rate swaps |
|
$ |
(6,082 |
) |
|
$ |
(6,199 |
) |
|
$ |
117 |
|
|
|
1.9 |
% |
Other non-operating income (expense) |
|
|
(1,497 |
) |
|
|
835 |
|
|
|
(2,332 |
) |
|
|
(279.3 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(7,579 |
) |
|
$ |
(5,364 |
) |
|
$ |
(2,215 |
) |
|
|
(41.3 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts reported as non-operating consist of income or expense resulting from the Companys
financing activities other than interest. As described above, the Companys results of operations
for the nine months ended September 30, 2005 and 2004 include expenses of $6.1 million and $6.2
million, respectively, related to the termination of hedge accounting and resulting amortization of
amounts that had previously been deferred. Other non-operating includes mark-to-market adjustments
related to certain swap activity that does not qualify for hedge accounting under FAS 133.
Income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended |
|
|
Increase (Decrease) |
|
|
|
September 30, |
|
|
To Net Income |
|
|
|
2005 |
|
|
2004 |
|
|
$ |
|
|
% |
|
|
|
(Amounts in thousands) |
|
(Benefit from) provision for income taxes |
|
$ |
(4,750 |
) |
|
$ |
18,545 |
|
|
$ |
23,295 |
|
|
|
125.6 |
% |
The Companys effective tax rate is sensitive to changes in estimates of annual profitability and
excess depletion. The decrease in the income tax provision in the nine months ended September 30,
2005 as compared to that recorded in the nine months ended September 30, 2004 is primarily the
result of the taxable income from non-mining sources from the sale of the NRP units in the first
quarter of 2004. The benefit for the nine months ended September 30, 2005 is the result of a
revision to taxable income and effective rate estimates for the fiscal year ending December 31,
2005.
DISCLOSURE CONTROLS AND CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
An evaluation was performed under the supervision and with the participation of our management,
including the CEO and CFO, of the effectiveness of the design and operation of our disclosure
controls and procedures as of September 30, 2005. Based on that evaluation, our management,
including the CEO and CFO, concluded that the disclosure controls and procedures were effective as
of such date. There have not been any changes in our internal control over financial reporting that
occurred during the quarter ended September 30, 2005 that have materially affected, or are
reasonably likely to materially affect, our internal control over financial reporting.
26
RECENT DEVELOPMENTS
OUTLOOK
Railroad Transportation Disruptions. During 2004 and again in the first nine months of 2005, rail
service disruptions resulted in missed shipments in all of our operating regions. In the second
and third quarters of 2005, the rail disruptions were most pronounced in the Powder River Basin of
Wyoming, where shipments from our Black Thunder mine were reduced by a total of six to seven
million tons and production was curtailed by approximately four to five million tons as a result.
The major maintenance repair work currently underway on the joint line rail system in the Powder
River Basin is expected to negatively impact shipments from the region through the end of 2005,
after which time we expect a gradual improvement.
Mingo Logan Operations. During the latter part of 2004 and the first nine months of 2005, our Mingo
Logan mine in West Virginia was adversely affected by a combination of difficult geologic
conditions in its previous longwall panel, a major longwall move and a slow startup of the new
longwall panel after the move. The start-up process was impaired principally by a
greater-than-expected influx of water, which in turn resulted in a series of equipment-related
difficulties at the mine. These issues, along with less favorable geologic conditions than
anticipated, reduced operating income at the Mingo Logan mine by $30.0 million during the first
nine months of 2005 compared to anticipated results. These operational challenges have been
addressed and we expect the mines recent improved performance to continue over the remainder of
2005.
West Elk mine evacuation. On October 27, 2005, the Company conducted a precautionary evacuation of
its West Elk mine after elevated readings of combustion-related gases were detected in an area of
the mine where mining activities were completed, but final longwall equipment removal had not yet
occurred. A portion of the equipment had already been moved to another area of the mine where the
Company intends to begin mining and the remainder is currently isolated from the affected area by
permanent and temporary seals.
Once the mine is determined to be safe for re-entry, the longwall equipment can be moved and
production can resume in the new area. While management does not anticipate an extended evacuation
or significant impact on production or results of operations, we cannot currently estimate when
production will resume.
Expenses Related to Interest Rate Swaps. We had designated certain interest rate swaps as hedges of
the variable rate interest payments due under Arch Westerns term loans. Pursuant to the
requirements of FAS 133, historical mark-to-market adjustments related to these swaps through June
25, 2003 of $27.0 million were deferred as a component of Accumulated Other Comprehensive Loss.
Subsequent to the repayment of the term loans, these deferred amounts will be amortized as
additional expense over the original contractual terms of the swap agreements. As of December 31,
2004, the remaining deferred amounts will be recognized as expense in the following periods: $7.7
million in 2005 ($6.1 million was recognized in the first nine months of 2005); $4.8 million in
2006; and $1.9 million in 2007.
Chief Objectives. We are focused on taking steps to increase shareholder returns by improving
earnings, reducing costs, strengthening cash generation, and improving productivity at our
large-scale mines, while building on our strategic position in each of the nations three principal
low-sulfur coal basins. We believe that success in the coal industry is largely dependent on
leadership in three crucial areas of performance safety, environmental stewardship and return on
investment and we are pursuing such leadership aggressively. We are also seeking to enhance our
position as a preferred supplier to U.S. power producers by acting as a reliable and highly ethical
partner. We plan to focus on organic growth by continuing to develop our existing reserve base,
which is large and highly strategic. We also plan to evaluate acquisitions that represent a good
fit with our existing operations.
LIQUIDITY AND CAPITAL RESOURCES
The following is a summary of cash provided by or used in each of the indicated types of activities
during the nine months ended September 30, 2005 and 2004:
27
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
|
2004 |
|
|
|
(in thousands) |
|
Cash provided by (used in): |
|
|
|
|
|
|
|
|
Operating activities |
|
$ |
163,028 |
|
|
$ |
39,806 |
|
Investing activities |
|
|
(242,668 |
) |
|
|
(545,998 |
) |
Financing activities |
|
|
(16,099 |
) |
|
|
256,449 |
|
Cash provided by operating activities increased in the nine months ended September 30, 2005 as
compared to the same period in 2004 primarily as a result of improved performance at our operations
in addition to a decreased investment in working capital. While trade accounts receivable and
inventory represented the largest use of funds, increasing by more than $88.9 million in the first
nine months of 2005 compared to an increase of $79.3 million in the first nine months of 2004, it
was offset by an increase in accounts payable and accrued expenses of more than $31.0 million in
the first nine months of 2005 compared to a decrease of $19.9 million in the prior years
comparable period. In addition, we received $14.7 million during the second quarter of 2005 related
to payment of receivables for settled audit years from the Internal Revenue Service.
Cash used in investing activities in the first nine months of 2005 reflects capital expenditures
and advance royalty payments of $248.9 million and $23.9 million, respectively, offset partially by
proceeds from the sales of land and equipment of $30.2 million. Cash used in investing activities
in the first nine months of 2004 is represented largely by payments for acquisitions, net of cash
acquired, during the third quarter of 2004. We acquired the remaining 35% of our Canyon Fuel
investment and the North Rochelle operations from Triton in July and August 2004, respectively.
Capital expenditures and advance royalty payments during the third quarter of 2004 were $243.6
million and $27.2 million, respectively.
Capital expenditures are made to improve and replace existing mining equipment, expand existing
mines, develop new mines and improve the overall efficiency of mining operations. We estimate that
our capital expenditures will range from $390 million to $410 million in total for 2005. This
estimate includes capital expenditures related to development work at certain of our mining
operations, including the Mountain Laurel complex in West Virginia and the North Lease mine at the
Skyline complex in Utah. Also, this estimate assumes no other acquisitions, significant expansions
of our existing mining operations or additions to our reserve base. We anticipate that we will fund
these capital expenditures with available cash, existing credit facilities and cash generated from
operations.
Cash used in financing activities during the nine months ended September 30, 2005 consists
primarily of net payments on our revolving credit facility of $25.0 million, net payments on our
long-term debt of $9.1 million and dividend payments of $20.7 million, offset partially by $41.3
million in proceeds from the issuance of common stock under our employee stock incentive plan. Cash
provided by financing activities during the nine months ended September 30, 2004 consists of
borrowings under our revolving credit facility and term loan facility of $250.4 million and
proceeds from the issuance of common stock under our employee stock incentive plan of $30.7
million, offset by payments on long-term debt of $6.3 million and dividend payments of $17.2
million.
Excluding any significant mineral reserve acquisitions, we generally satisfy our working capital
requirements and fund capital expenditures and debt-service obligations with cash generated from
operations. We believe that cash generated from operations and our borrowing capacity will be
sufficient to meet working capital requirements, anticipated capital expenditures and scheduled
debt payments for at least the next several years. Our ability to satisfy debt service obligations,
to fund planned capital expenditures, to make acquisitions and to pay dividends will depend upon
our future operating performance, which will be affected by prevailing economic conditions in the
coal industry and financial, business and other factors, some of which are beyond our control.
At September 30, 2005, we had $106.2 million in letters of credit outstanding, resulting in $593.8
million of unused borrowings under the revolver. At September 30, 2005, financial covenant
requirements do not restrict the amount of unused capacity available to us for borrowing and
letters of credit.
Financial covenants contained in our revolving credit facility consist of a maximum leverage ratio,
a maximum senior secured leverage ratio and a minimum interest coverage ratio. The leverage ratio
requires that we not permit the ratio of total net debt (as defined in the facility) at the end of
any calendar quarter to EBITDA (as defined in the facility) for the four quarters then ended to
exceed a specified amount. The interest coverage ratio requires that we not permit the ratio of EBITDA (as defined) at the end of any calendar quarter to interest
expense for the four quarters then ended to be less than a specified amount. The senior secured
leverage ratio requires that we not permit the ratio of total net senior secured debt (as defined)
at the end of any calendar quarter to EBITDA (as defined) for the four quarters then ended to
exceed a specified amount. We were in compliance with all financial covenants at September 30,
2005.
28
We periodically establish uncommitted lines of credit with banks. These agreements generally
provide for short-term borrowings at market rates. At September 30, 2005, there were $20.0 million
of such agreements in effect, of which none were outstanding.
We are exposed to market risk associated with interest rates due to our existing level of
indebtedness. At September 30, 2005, substantially all of our outstanding debt bore interest at
fixed rates.
Additionally, we are exposed to market risk associated with interest rates resulting from our
interest rate swap positions. Prior to the June 25, 2003 Arch Western Finance senior notes offering
and subsequent repayment of Arch Westerns term loans, we utilized interest rate swap agreements to
convert the variable-rate interest payments due under the term loans and our revolving credit
facility to fixed-rate payments.
At September 30, 2005, we had outstanding interest rate swaps with a total notional value of
$400.0 million consisting of offsetting positions of $200.0 million each. Because of the
offsetting nature of these positions, we are not exposed to significant market interest rate
risk related to these swaps. Under these swaps, we pay a weighted average fixed rate 5.72% on
$200.0 million of notional value and receive a weighted average fixed rate of 2.71% on $200.0
million of notional value. The remaining terms of these swap agreements at September 30, 2005
ranged from 2 to 22 months.
As of September 30, 2005, the fair value of our net interest rate swap position was a liability of
$5.7 million. This liability is included in other noncurrent liabilities in the accompanying
Consolidated Balance Sheets.
We are exposed to price risk related to the value of SO2 emission allowances that are a component
of the quality adjustment provisions in many of our coal supply contracts. We recently entered into
several put option and swap contracts to reduce volatility in the price of SO2 emission allowances.
These contracts serve to protect us from any possible downturn in the price of SO2 emission
allowances. The put option agreements grant us the right to sell a certain quantity of SO2 emission
allowances at a specified price on a specified date. The swap agreements essentially fix the price
we receive for SO2 emission allowances by allowing us to receive a fixed SO2 allowance price and
pay a floating SO2 allowance price.
We are also exposed to commodity price risk related to our purchase of diesel fuel. We enter into
forward purchase contracts and heating oil swaps to reduce volatility in the price of diesel fuel
for our operations. The swap agreements essentially fix the price paid for diesel fuel by requiring
us to pay a fixed heating oil price and receive a floating heating oil price. The changes in the
floating heating oil price highly correlate to changes in diesel fuel prices, accordingly the
derivatives qualify for hedge accounting and the asset of $12.2 million representing the fair value
of the derivatives is recorded through other comprehensive income.
The discussion below presents the sensitivity of the market value of our financial instruments to
selected changes in market rates and prices. The range of changes reflects our view of changes that
are reasonably possible over a one-year period. Market values are the present value of projected
future cash flows based on the market rates and prices chosen. The major accounting policies for
these instruments are described in Note 1 to our consolidated financial statements as of and for
the year ended December 31, 2004 as filed on our Annual Report on Form 10-K with the Securities and
Exchange Commission.
With respect to our SO2 emission allowance put option and swap positions, as well as our heating
oil swap positions, a change in price of the underlying products impacts our net financial
instrument position. At September 30, 2005, a $100 decrease in the price of SO2 emission allowances
would result in a $2.6 million increase in the fair value of the financial position of our SO2
emission allowance put option and swap agreements. At September 30, 2005, a $.05 per gallon
increase in the price of heating oil would result in a $1.0 million increase in the fair value of
the financial position of our heating oil swap agreements.
With respect to our interest rate swap positions noted above, due to the offsetting nature of these
positions, a 100-basis point increase in market interest rates does not have a material impact on
the fair value of our liability under our interest rate swap positions at September 30, 2005.
CONTINGENCIES
29
Reclamation
The federal Surface Mining Control and Reclamation Act of 1977 (SMCRA) and similar state statutes
require that mine property be restored in accordance with specified standards and an approved
reclamation plan. We accrue for the costs of reclamation in accordance with the provisions of FAS
143, which was adopted as of January 1, 2003. These costs relate to reclaiming the pit and support
acreage at surface mines and sealing portals at deep mines. Other costs of reclamation common to
surface and underground mining are related to reclaiming refuse and slurry ponds, eliminating
sedimentation and drainage control structures, and dismantling or demolishing equipment or
buildings used in mining operations. The establishment of the asset retirement obligation liability
is based upon permit requirements and requires various estimates and assumptions, principally
associated with costs and productivities.
We review our entire environmental liability periodically and make necessary adjustments, including
permit changes and revisions to costs and productivities to reflect current experience. Our
management believes it is making adequate provisions for all expected reclamation and other
associated costs.
Legal Contingencies
Permit Litigation Matters. A group of local and national environmental organizations filed suit
against the U.S. Army Corps of Engineers in the U.S. District Court in Huntington, West Virginia on
October 23, 2003. In its complaint, Ohio River Valley Environmental Coalition, et al v. Bulen, et
al, the plaintiffs allege that the Corps has violated its statutory duties arising under the Clean
Water Act, the Administrative Procedure Act and the National Environmental Policy Act in issuing
the Nationwide 21 (NWP 21) general permit. The plaintiffs allege that the procedural requirements
of the three federal statutes identified in their complaint have been violated, and that the Corps
may not utilize the mechanism of a nationwide permit to authorize valley fills. If the plaintiffs
prevail in this litigation, it may delay our receipt of these permits.
On July 8, 2004, the District court entered a final order enjoining the Corps from authorizing new
valley fills using the mechanism of its nationwide permit. The Court also ordered the Corps to
suspend current authorizations issued for fills that had not yet commenced construction on the date
of the order. The district court modified its earlier decision on August 13 when it directed the
Corps to suspend all permits for fills that had not commenced construction as of July 8, 2004.
Three permits issued at two of the Companys operating subsidiaries were affected by the Courts
July 8 order. Although the two operating subsidiaries were prohibited from constructing the fills
previously authorized, the Courts order does allow them to permit the fill construction using the
mechanism of an individual section 404 Clean Water Act permit. We do not believe that obtaining an
individual permit will adversely impact either of the operating subsidiaries.
The Corps and five intervening trade associations, three of which Arch is a member, filed an appeal
with the U.S. Court of Appeals for the Fourth Circuit in this matter on September 16, 2004. The
matter has been briefed and was argued before the Fourth Circuit on Sept 19, 2005. No decision is
expected until early 2006.
West Virginia Flooding Litigation. We and three of our subsidiaries have been served, among others,
in seventeen separate complaints filed and served in Wyoming, McDowell, Fayette, Kanawha, Raleigh,
Boone and Mercer Counties, West Virginia. These cases collectively include approximately 3,100
plaintiffs who are seeking to recover from more than 180 defendants for property damage and
personal injuries arising out of flooding that occurred in southern West Virginia on or about July
8, 2001. The plaintiffs have sued coal, timber, oil and gas, and land companies under the theory
that mining, construction of haul roads and removal of timber caused natural surface waters to be
diverted in an unnatural way, thereby causing damage to the plaintiffs. The West Virginia
Supreme Court has ruled that these cases, along with thirty-seven other flood damages cases not
involving our subsidiaries, be handled pursuant to the Courts Mass Litigation rules. As a result
of this ruling, the cases have been transferred to the Circuit Court of Raleigh County in West
Virginia to be handled by a panel consisting of three circuit court judges, which certified certain
legal issues back to the West Virginia Supreme Court. The West Virginia Supreme Court responded to
the questions certified, and discovery is underway.
30
While the outcome of this litigation is subject to uncertainties, based on our preliminary
evaluation of the issues and the potential impact on us, we believe this matter will be resolved
without a material adverse effect on our financial condition or results of operations or liquidity.
Ark Land Company v. Crown Industries. In response to a declaratory judgment action filed by Ark
Land Company, a subsidiary of ours, in Mingo County, West Virginia, against Crown Industries
involving the interpretation of a severance deed under which Ark Land controls the coal and mining
rights on property in Mingo County, West Virginia, Crown Industries filed a counterclaim against
Ark Land and a third party complaint against us and two of our other subsidiaries seeking damages
for trespass, nuisance and property damage arising out of the exercise of rights under the
severance deed on the property by our subsidiaries. The defendant alleged that our subsidiaries had
insufficient rights to haul certain foreign coals across the property without payment of certain
wheelage or other fees to the defendant. In addition, the defendant alleged that we and our
subsidiaries violated West Virginias Standards for Management of Waste Oil and the West Virginia
Surface Coal Mining and Reclamation Act. This case went to trial on October 4, 2005. Crown
Industries counterclaim against Ark Land was dismissed along with its cross claim against one of
the Companys subsidiaries and its claims for trespass, nuisance and wheelage. On October 12,
2005, the jury entered a verdict in favor of Crown Industries on its remaining claims, assessing
damages against the Company and its subsidiary in the amount of $2.5 million. The jury found in
favor of the Company and its subsidiary on their indemnity claim against the subsidiarys
contractor, and awarded the Company and its subsidiary $1.3 million on that claim. Crown Industries
also was awarded its reasonable attorneys fees, which remain to be determined. The Company is
evaluating appealing the judgment to the West Virginia Supreme Court.
Shonk Land Company v. Ark Land Company. Shonk Land Company leases certain West Virginia real
estate to our subsidiary Ark Land Company in exchange for royalties on coal mined from it. Shonk
Land Company filed a lawsuit in the Circuit Court for Kanawha County, WV, claiming, among other
things, that Ark Land Company misrepresented certain facts involving a lease amendment and that it
miscalculated and underpaid royalties under the lease. Shonk Land Company seeks damages of
approximately $14.5 million. Ark Land disputes its claims and filed a counterclaim for overpayment
of royalties in the approximate amount of $260,000. The court directed the parties to arbitrate
their dispute in accordance with the terms of their lease. The arbitration began on October 31,
2005, and we are awaiting the outcome.
While the outcome of this litigation is subject to uncertainties, based on our evaluation of the
issues and the potential impact on it, we believe this matter will be resolved without a material
adverse effect on our financial condition or results of operations.
We are a party to numerous other claims and lawsuits with respect to various matters. We provide
for costs related to contingencies, including environmental matters, when a loss is probable and
the amount is reasonably determinable. After conferring with counsel, it is the opinion of
management that the ultimate resolution of these claims, to the extent not previously provided for,
will not have a material adverse effect on our consolidated financial condition, results of
operations or liquidity.
Certain Trends and Uncertainties
Substantial Leverage Covenants
As of September 30, 2005, we had outstanding consolidated indebtedness of $976.0 million,
representing approximately 46% of our capital employed. Despite making substantial progress in
reducing debt, we continue to have significant debt service obligations, and the terms of our
credit agreements limit our flexibility and result in a number of limitations on us. We also have
significant lease and royalty obligations. Our ability to satisfy debt service, lease and royalty
obligations and to effect any refinancing of our indebtedness will depend upon future operating
performance, which will be affected by prevailing economic conditions in the markets that we serve
as well as financial, business and other factors, many of which are beyond our control. We may be
unable to generate sufficient cash flow from operations and future borrowings, or other financings
may be unavailable in an amount sufficient to enable us to fund our debt service, lease and royalty
payment obligations or our other liquidity needs.
Our relative amount of debt and the terms of our credit agreements could have material consequences
to our business, including, but not limited to: (i) making it more difficult to satisfy debt
covenants and debt service, lease payment and other obligations; (ii) making it more difficult to
pay quarterly dividends as we have in the past; (iii) increasing our vulnerability to general
adverse economic and industry conditions; (iv) limiting our ability to obtain
31
additional financing
to fund future acquisitions, working capital, capital expenditures or other general corporate
requirements; (v) reducing the availability of cash flows from operations to fund acquisitions,
working capital, capital expenditures or other general corporate purposes; (vi) limiting our
flexibility in planning for, or reacting to, changes in our business and the industry in which we
compete; or (vii) placing us at a competitive disadvantage when compared to competitors with less
relative amounts of debt.
The agreements governing our outstanding debt impose a number of restrictions on us. For example,
the terms of our credit facilities and leases contain financial and other covenants that create
limitations on our ability to, among other things, borrow the full amount under our credit
facilities, effect acquisitions or dispositions and incur additional debt, and require us to, among
other things, maintain various financial ratios and comply with various other financial covenants.
Our ability to comply with these restrictions may be affected by events beyond our control and, as
a result, we may be unable to comply with these restrictions. A failure to comply with these
restrictions could adversely affect our ability to borrow under our credit facilities or result in
an event of default under these agreements. In the event of a default, our lenders could terminate
their commitments to us and declare all amounts borrowed, together with accrued interest and fees,
immediately due and payable. If this were to occur, we might not be able to pay these amounts, or
we might be forced to seek an amendment to our debt agreements which could make the terms of these
agreements more onerous for us.
Any material downgrade in our credit ratings could adversely affect our ability to borrow and
result in more restrictive borrowing terms, including increased borrowing costs, more restrictive
covenants and the extension of less open credit. This in turn could affect our internal cost of
capital estimates and therefore operational decisions.
Profitability
Our mining operations are inherently subject to changing conditions that can affect levels of
production and production costs at particular mines for varying lengths of time and can result in
decreases in our profitability. We are exposed to commodity price risk related to our purchase of
diesel fuel, explosives and steel. In addition, weather conditions, equipment replacement or
repair, fires, variations in thickness of the layer, or seam, of coal, amounts of overburden, rock
and other natural materials and other geological conditions have had, and can be expected in the
future to have, a significant impact on our operating results. Prolonged disruption of production
at any of our principal mines, particularly our Black Thunder mine, would result in a decrease in
our revenues and profitability, which could be material. Other factors affecting the production and
sale of our coal that could result in decreases in our profitability include:
|
|
|
continued high pricing environment for our raw materials, including, among other
things, diesel fuel, explosives and steel; |
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|
|
disruption or increases in the cost of transportation services; |
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|
changes in laws or regulations, including permitting requirements; |
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|
|
litigation; |
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|
|
work stoppages or other labor difficulties; |
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|
|
labor shortages; |
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|
|
mine worker vacation schedules and related maintenance activities; and |
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|
|
|
changes in coal market and general economic conditions. |
Environmental and Regulatory Factors
The coal mining industry is subject to regulation by federal, state and local authorities on
matters such as:
|
|
|
the discharge of materials into the environment; |
|
|
|
|
employee health and safety; |
32
|
|
|
mine permits and other licensing requirements; |
|
|
|
|
reclamation and restoration of mining properties after mining is completed; |
|
|
|
|
management of materials generated by mining operations; |
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|
|
|
surface subsidence from underground mining; |
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|
water pollution; |
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|
legislatively mandated benefits for current and retired coal miners; |
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|
air quality standards; |
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|
protection of wetlands; |
|
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|
|
endangered plant and wildlife protection; |
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|
limitations on land use; |
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|
storage of petroleum products and substances that are regarded as hazardous under applicable laws; and |
|
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|
|
management of electrical equipment containing polychlorinated biphenyls, or PCBs. |
In addition, the electric generating industry, which is the most significant end-user of coal, is
subject to extensive regulation regarding the environmental impact of its power generation
activities, which could affect demand for our coal. The possibility exists that new legislation or
regulations may be adopted or that the enforcement of existing laws could become more stringent,
either of which may have a significant impact on our mining operations or our customers ability to
use coal and may require us or our customers to significantly change operations or to incur
substantial costs.
While it is not possible to quantify the expenditures we incur to maintain compliance with all
applicable federal and state laws, those costs have been and are expected to continue to be
significant. We post performance bonds pursuant to federal and state mining laws and regulations
for the estimated costs of reclamation and mine closing, including the cost of treating mine water
discharge when necessary. Compliance with these laws has substantially increased the cost of coal
mining for all domestic coal producers.
Clean Air Act. The federal Clean Air Act and similar state and local laws, which regulate emissions
into the air, affect coal mining and processing operations primarily through permitting and
emissions control requirements. The Clean Air Act also indirectly affects coal mining operations by
extensively regulating the emissions from coal-fired industrial boilers and power plants, which are
the largest end-users of our coal. These regulations can take a variety of forms, as explained
below.
The Clean Air Act imposes obligations on the Environmental Protection Agency, or EPA, and the
states to implement regulatory programs that will lead to the attainment and maintenance of
EPA-promulgated ambient air quality standards. EPA has promulgated ambient air quality standards
for a number of air pollutants, including standards for sulfur dioxide, particulate matter,
nitrogen oxides and ozone, which are associated with the combustion of coal. Owners of coal-fired power plants and industrial boilers have been required to
expend considerable resources in an effort to comply with these ambient air standards. In
particular, coal-fired power plants will be affected by state regulations designed to achieve
attainment of the ambient air quality standard for ozone, which may require significant
expenditures for additional emissions control equipment needed to meet the current national ambient
air standard for ozone. Ozone is produced by the combination of two precursor pollutants: volatile
organic compounds and nitrogen oxides. Nitrogen oxides are a by-product of coal combustion.
Accordingly, emissions control requirements for new and expanded coal-fired power plants and
industrial boilers will continue to become more demanding in the years ahead.
33
In July 1997, the EPA adopted more stringent ambient air quality standards for ozone and fine
particulate matter (PM2.5, which can be formed in the air from gaseous emissions of
sulfur dioxide and nitrogen oxides both of which are associated with coal combustion). In a
February 2001 decision, the U.S. Supreme Court largely upheld the EPAs position, although it
remanded the EPAs ozone implementation policy for further consideration. On remand, the Court of
Appeals for the D.C. Circuit affirmed the EPAs adoption of these more stringent ambient air
quality standards. As a result of the finalization of these standards, states that are not in
attainment for these standards will have to revise their State Implementation Plans to include
provisions for the control of ozone precursors and/or particulate matter. In April 2004, the EPA
issued final nonattainment designations for the eight-hour ozone standard, and, in December 2004,
issued the final nonattainment standard for PM2.5. States will have to revise their
State Implementation Plans to require electric power generators to further reduce nitrogen oxide
and particulate matter emissions, particularly in designated nonattainment areas. The potential
need to achieve such emissions reductions could result in reduced coal consumption by electric
power generators. Thus, future regulations regarding ozone, particulate matter and other pollutants
could restrict the market for coal and our development of new mines. This in turn may result in
decreased production and a corresponding decrease in our revenues. Although the future scope of
these ozone and particulate matter regulations cannot be predicted, future regulations regarding
these and other ambient air standards could restrict the market for coal and the development of new
mines.
The EPA has also initiated a regional haze program designed to protect and to improve visibility at
and around National Parks, National Wilderness Areas and International Parks, particularly those
located in the southwest and southeast United States. This program restricts the construction of
new coal-fired power plants whose operation may impair visibility at and around federally protected
areas. In June 2005, EPA finalized amendments to the regional haze rules which will require certain
existing coal-fired power plants to install Best Available Retrofit Technology (BART) limit
haze-causing emissions, such as sulfur dioxide, nitrogen oxides and particulate matter. By imposing
limitations upon the placement and construction of new coal-fired power plants and BART
requirements on existing coal-fired power plants, the EPAs regional haze program could affect the
future market for coal.
New regulations concerning the routine maintenance provisions of the New Source Review program were
published in October 2003. Fourteen states, the District of Columbia and a number of municipalities
filed lawsuits challenging these regulations, and in December 2003 the Court stayed the
effectiveness of these rules. In July 2004 EPA granted a petition to reconsider the legal basis for
the routine maintenance provisions and the litigation was suspended while the rule was being
reconsidered. In June 2005 EPA issued its final response, which does not change the rule. In
light of EPAs final action the litigation may proceed.
In January 2004, the EPA Administrator announced that EPA would be taking new enforcement actions
against utilities for violations of the existing New Source Review requirements, and shortly
thereafter, EPA issued enforcement notices to several electric utility companies. Additionally,
the U.S. Department of Justice, on behalf of the EPA, has filed lawsuits against several
investor-owned electric utilities for alleged violations of the Clean Air Act. The EPA claims that
these utilities have failed to obtain permits required under the Clean Air Act for alleged major
modifications to their power plants. We supply coal to some of the currently affected utilities,
and it is possible that other of our customers will be sued. These lawsuits could require the
utilities to pay penalties and install pollution control equipment or undertake other emission
reduction measures, which could adversely impact their demand for coal.
In March 2005, the EPA issued two new rules that will impact coal-fired power plants. These are
(i) the Clean Air Interstate Rule (CAIR), which permanently caps emissions of sulfur dioxide (SO2)
and nitrogen oxides (NOx) in the eastern United States; and (ii) the Clean Air Mercury Rule (CAMR)
to permanently cap and reduce mercury emissions from coal-fired power plants. Both rules provide power plant operators a market-based
system (cap and trade program) in which plants that exceed federal requirements can sell
pollution credits to plant operators who need more time to comply with the stricter rules. CAIR
requires reductions of SO2 and/or NOx emissions across 28 eastern states and the District of
Columbia and, when fully implemented in 2015, CAIR will reduce SO2 emissions in these states by
over 70 percent and NOx emissions by over 60 percent from 2003 levels. Under the new mercury
emissions rule, mercury emissions from coal-fired power plants will not be regulated as a Hazardous
Air Pollutant, which would require installation of Maximum Available Control Technology (MACT).
Instead, using the cap and trade system, these plants will have until 2010 to cut mercury emission
levels to 38 tons a year from 48 tons and until 2018 to bring that level down to 15 tons, a 69
percent reduction. Utility analysts have estimated meeting the goals for SO2 and NOx will cost
power generators approximately $50 billion to install the required filtration systems, or
scrubbers, on their smokestacks, but these controls are expected to also reduce the mercury
emissions to the targeted levels. Both the CAIR and the CAMR are the subject of ongoing litigation
challenging key provisions,
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and in the case of the CAMR, there is an effort in Congress to overturn
the rule in favor of the MACT approach. If CAIR and CAMR survive the legal challenges, or if a
MACT requirement is imposed for mercury emissions, the additional costs that may be associated with
operating coal-fired power generation facilities due to the implementation of these new rules may
render coal a less attractive fuel source.
Other Clean Air Act programs are also applicable to power plants that use our coal. For example,
the acid rain control provisions of Title IV of the Clean Air Act require a reduction of sulfur
dioxide emissions from power plants. Because sulfur is a natural component of coal, required sulfur
dioxide reductions can affect coal mining operations. Title IV imposes a two phase approach to the
implementation of required sulfur dioxide emissions reductions. Phase I, which became effective in
1995, regulated the sulfur dioxide emissions levels from 261 generating units at 110 power plants
and targeted the highest sulfur dioxide emitters. Phase II, implemented January 1, 2000, made the
regulations more stringent and extended them to additional power plants, including all power plants
of greater than 25 megawatt capacity. Affected electric utilities can comply with these
requirements by:
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burning lower sulfur coal, either exclusively or mixed with higher sulfur coal; |
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installing pollution control devices such as scrubbers, which reduce the emissions from high sulfur coal; |
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reducing electricity generating levels; or |
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purchasing or trading emissions credits. |
Specific emissions sources receive these credits, which electric utilities and industrial concerns
can trade or sell to allow other units to emit higher levels of sulfur dioxide. Each credit allows
its holder to emit one ton of sulfur dioxide.
Mine Health and Safety Laws. Stringent safety and health standards have been imposed by federal
legislation since the adoption of the Mine Safety and Health Act of 1969. The Mine Safety and
Health Act of 1977, which significantly expanded the enforcement of health and safety standards of
the Mine Safety and Health Act of 1969, imposes comprehensive safety and health standards on all
mining operations. In addition, as part of the Mine Safety and Health Acts of 1969 and 1977, the
Black Lung Act requires payments of benefits by all businesses conducting current mining operations
to coal miners with black lung and to some survivors of a miner who dies from this disease.
Surface Mining Control and Reclamation Act. SMCRA establishes operational, reclamation and closure
standards for all aspects of surface mining as well as many aspects of deep mining. SMCRA requires
that comprehensive environmental protection and reclamation standards be met during the course of
and upon completion of mining activities. In conjunction with mining the property, we are
contractually obligated under the terms of our leases to comply with all laws, including SMCRA and
equivalent state and local laws. These obligations include reclaiming and restoring the mined areas
by grading, shaping, preparing the soil for seeding and by seeding with grasses or planting trees
for use as pasture or timberland, as specified in the approved reclamation plan.
SMCRA also requires us to submit a bond or otherwise financially secure the performance of our
reclamation obligations. The earliest a reclamation bond can be completely released is five years
after reclamation has been achieved. Federal law and some states impose on mine operators the responsibility for repairing the
property or compensating the property owners for damage occurring on the surface of the property as
a result of mine subsidence, a consequence of longwall mining and possibly other mining operations.
In addition, the Abandoned Mine Lands Act, which is part of SMCRA, imposes a tax on all current
mining operations, the proceeds of which are used to restore mines closed before 1977. The maximum
tax is $0.35 per ton of coal produced from surface mines and $0.15 per ton of coal produced from
underground mines.
We also lease some of our coal reserves to third party operators. Under SMCRA, responsibility for
unabated violations, unpaid civil penalties and unpaid reclamation fees of independent mine lessees
and other third parties could potentially be imputed to other companies that are deemed, according
to the regulations, to have owned or controlled the mine operator. Sanctions against the
owner or controller are quite severe and can include civil penalties, reclamation fees and
reclamation costs. We are not aware of any currently pending or asserted claims against us
asserting that we own or control any of our lessees operations.
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Framework Convention on Global Climate Change. The United States and more than 160 other nations
are signatories to the 1992 Framework Convention on Global Climate Change, commonly known as the
Kyoto Protocol, that is intended to limit or capture emissions of greenhouse gases such as carbon
dioxide and methane. The U.S. Senate has neither ratified the treaty commitments, which would
mandate a reduction in U.S. greenhouse gas emissions, nor enacted any law specifically controlling
greenhouse gas emissions and the Bush Administration has withdrawn support for this treaty.
Nonetheless, future regulation of greenhouse gases could occur either pursuant to future U.S.
treaty obligations, statutory or regulatory changes under the Clean Air Act, or pursuant to laws
and regulations enacted by various states. Efforts to control greenhouse gas emissions could result
in reduced demand for coal if electric power generators switch to lower carbon sources of fuel.
West Virginia Antidegradation Policy. In January 2002, a number of environmental groups and
individuals filed suit in the U.S. District Court for the Southern District of West Virginia to
challenge the EPAs approval of West Virginias antidegradation implementation policy. Under the
federal Clean Water Act, state regulatory authorities must conduct an antidegradation review before
approving permits for the discharge of pollutants to waters that have been designated as high
quality by the state. Antidegradation review involves public and intergovernmental scrutiny of
permits and requires permittees to demonstrate that the proposed activities are justified in order
to accommodate significant economic or social development in the area where the waters are located.
In August 2003, the Southern District of West Virginia vacated the EPAs approval of West
Virginias anti-degradation procedures, and remanded the matter to the EPA. On March 29, 2004, EPA
Regions III sent a letter to the WVDEP that approved portions of the states anti-degradation
program, denied approval of portions pending further study, and recommended removal of certain
language on the states regulations. Depending upon the outcome of the DEP review, the issuance or
re-issuance of Clean Water Act permits to us may be delayed or denied, and may increase the costs,
time and difficulty associated with obtaining and complying with Clean Water Act permits for
surface mining operations.
Comprehensive Environmental Response, Compensation and Liability Act. CERCLA and similar state laws
affect coal mining operations by, among other things, imposing cleanup requirements for threatened
or actual releases of hazardous substances that may endanger public health or welfare or the
environment. Under CERCLA and similar state laws, joint and several liability may be imposed on
waste generators, site owners and lessees and others regardless of fault or the legality of the
original disposal activity. Although the EPA excludes most wastes generated by coal mining and
processing operations from the hazardous waste laws, such wastes can, in certain circumstances,
constitute hazardous substances for the purposes of CERCLA. In addition, the disposal, release or
spilling of some products used by coal companies in operations, such as chemicals, could implicate
the liability provisions of the statute. Thus, coal mines that we currently own or have previously
owned or operated, and sites to which we sent waste materials, may be subject to liability under
CERCLA and similar state laws. In particular, we may be liable under CERCLA or similar state laws
for the cleanup of hazardous substance contamination at sites where we own surface rights.
Mining Permits and Approvals. Mining companies must obtain numerous permits that strictly regulate
environmental and health and safety matters in connection with coal mining, some of which have
significant bonding requirements. In connection with obtaining these permits and approvals, we may
be required to prepare and present to federal, state or local authorities data pertaining to the
effect or impact that any proposed production of coal may have upon the environment. The
requirements imposed by any of these authorities may be costly and time consuming and may delay commencement or continuation of mining operations. Regulations also
provide that a mining permit can be refused or revoked if an officer, director or a shareholder
with a 10% or greater interest in the entity is affiliated with another entity that has outstanding
permit violations. Thus, past or ongoing violations of federal and state mining laws could provide
a basis to revoke existing permits and to deny the issuance of additional permits.
Regulatory authorities exercise considerable discretion in the timing of permit issuance. Also,
private individuals and the public at large possess rights to comment on and otherwise engage in
the permitting process, including through intervention in the courts. Accordingly, the permits we
need for our mining operations may not be issued, or, if issued, may not be issued in a timely
fashion, or may involve requirements that may be changed or interpreted in a manner that restricts
our ability to conduct our mining operations or to do so profitably.
In order to obtain mining permits and approvals from state regulatory authorities, mine operators,
including us, must submit a reclamation plan for restoring, upon the completion of mining
operations, the mined property to its prior condition, productive use or other permitted condition.
Typically we submit the necessary permit applications several months before we plan to begin mining
a new area. In our experience, permits generally are approved several months after a completed
application is submitted. In the past, we have generally obtained our mining permits without
36
significant delay. However, we cannot be sure that we will not experience difficulty in obtaining
mining permits in the future.
Future legislation and administrative regulations may emphasize the protection of the environment
and, as a consequence, the activities of mine operators, including us, may be more closely
regulated. Legislation and regulations, as well as future interpretations of existing laws, may
also require substantial increases in equipment expenditures and operating costs, as well as
delays, interruptions or the termination of operations. We cannot predict the possible effect of
such regulatory changes.
Under some circumstances, substantial fines and penalties, including revocation or suspension of
mining permits, may be imposed under the laws described above. Monetary sanctions and, under some
circumstances, criminal sanctions may be imposed for failure to comply with these laws.
Surety Bonds. Federal and state laws require us to obtain surety bonds to guarantee performance or
payment of certain long-term obligations including mine closure and reclamation costs, federal and
state workers compensation benefits, coal leases and other miscellaneous obligations. It has
become increasingly difficult for us to secure new surety bonds or retain existing bonds without
the posting of collateral. In addition, surety bond costs have increased and the market terms of
such bonds have generally become more unfavorable. We may be unable to maintain our surety bonds or
acquire new bonds in the future due to lack of availability, higher expense, unfavorable market
terms, or an inability to post sufficient collateral. Our failure to maintain, or inability to
acquire, surety bonds that are required by state and federal law would have a material adverse
impact on us.
Endangered Species. The federal Endangered Species Act and counterpart state legislation protects
species threatened with possible extinction. Protection of endangered species may have the effect
of prohibiting or delaying us from obtaining mining permits and may include restrictions on timber
harvesting, road building and other mining or agricultural activities in areas containing the
affected species. A number of species indigenous to our properties are protected under the
Endangered Species Act. Based on the species that have been identified to date and the current
application of applicable laws and regulations, however, we do not believe there are any species
protected under the Endangered Species Act that would materially and adversely affect our ability
to mine coal from our properties in accordance with current mining plans.
Other Environmental Laws Affecting Us. We are required to comply with numerous other federal, state
and local environmental laws in addition to those previously discussed. These additional laws
include, for example, the Resource Conservation and Recovery Act, the Safe Drinking Water Act, the
Toxic Substance Control Act and the Emergency Planning and Community Right-to-Know Act. We believe
that we are in substantial compliance with all applicable environmental laws.
Competition
The coal industry is intensely competitive, primarily as a result of the existence of numerous
producers in the coal-producing regions in which we operate, and some of our competitors may have
greater financial resources. We compete with several major coal producers in the Central
Appalachian and Powder River Basin areas. We also compete with a number of smaller producers in
those and other market regions.
Electric Industry Factors
Demand for coal and the prices that we will be able to obtain for our coal are closely linked to
coal consumption patterns of the domestic electric generation industry, which has accounted for
approximately 90% of domestic coal consumption in recent years. These coal consumption patterns are
influenced by factors beyond our control, including the demand for electricity (which is dependent
to a significant extent on summer and winter temperatures and the strength of the economy);
government regulation; technological developments and the location, availability, quality and price
of competing sources of coal; other fuels such as natural gas, oil and nuclear; and alternative
energy sources such as hydroelectric power. Demand for our low-sulfur coal and the prices that we
will be able to obtain for it will also be affected by the price and availability of high-sulfur
coal, which can be marketed in tandem with emissions allowances in order to meet federal Clean Air
Act requirements. Any reduction in the demand for our coal by the domestic electric generation
industry may cause a decline in profitability.
37
Electric utility deregulation is expected to provide incentives to generators of electricity to
minimize their fuel costs and is believed to have caused electric generators to be more aggressive
in negotiating prices with coal suppliers. Deregulation may have an adverse effect on our
profitability to the extent it causes our customers to be more cost-sensitive.
In addition, our ability to receive payment for coal sold and delivered depends on the
creditworthiness of our customers. In general, the creditworthiness of our customers has
deteriorated over the past several years. If such trends continue, our acceptable customer base may
be limited.
Terms of Long-Term Coal Supply Contracts
During 2004, sales of coal under long-term contracts, which are contracts with a term greater than
12 months, accounted for 70% of our total revenues. The prices for coal shipped under these
contracts may be below the current market price for similar type coal at any given time. For the
nine months ended September 30, 2005, the weighted average price of coal sold under our long-term
contracts was $17.85 per ton. As a consequence of the substantial volume of our sales which are
subject to these long-term agreements, we have less coal available with which to capitalize on
increases in coal prices. In addition, because long-term contracts may allow the customer to elect
volume flexibility, our ability to realize the higher prices that may be available on the spot
market may be restricted when customers elect to purchase higher volumes under such contracts. Our
exposure to market-based pricing may also be increased should customers elect to purchase fewer
tons. In addition, the increasingly short terms of sales contracts and the consequent absence of
price adjustment provisions in such contracts make it more likely that we will not be able to
recover inflation related increases in mining costs during the contract term.
Reserve Degradation and Depletion
Our profitability depends substantially on our ability to mine coal reserves that have the
geological characteristics that enable them to be mined at competitive costs. Replacement reserves
may not be available when required or, if available, may not be capable of being mined at costs
comparable to those characteristics of the depleting mines. We have in the past acquired and will
in the future acquire coal reserves for our mine portfolio from third parties. We may not be able
to accurately assess the geological characteristics of any reserves that we acquire, which may
adversely affect our profitability and financial condition. Exhaustion of reserves at particular
mines can also have an adverse effect on operating results that is disproportionate to the
percentage of overall production represented by such mines. Mingo Logans Mountaineer Mine is
estimated to exhaust its longwall mineable reserves in mid-2007, although we expect to make up the
lost production with our planned opening of our Mountain Laurel complex in Logan County, West
Virginia, which should ramp up to full production by the second half of 2007. The Mountaineer Mine
generated $30.5 million and $26.1 million of our total operating income in the years ended 2004 and
2003, respectively.
Potential Fluctuations in Operating Results Factors Routinely Affecting Results of Operations
Our mining operations are inherently subject to changing conditions that can affect levels of
production and production costs at particular mines for varying lengths of time and can result in
decreases in profitability. Weather conditions, equipment replacement or repair, fuel and supply
prices, insurance costs, fires, variations in coal seam thickness, amounts of overburden rock and
other natural materials, and other geological conditions have had, and can be expected in the
future to have, a significant impact on operating results. A prolonged disruption of production at
any of our principal mines, particularly the Mingo Logan operation in West Virginia or Black
Thunder mine in Wyoming, would result in a decrease, which could be material, in our revenues and
profitability.
The geological characteristics of Central Appalachia coal reserves, such as depth of overburden and
coal seam thickness, make them complex and costly to mine. As mines become depleted, replacement
reserves may not be available when required or, if available, may not be capable of being mined at
costs comparable to those characteristic of the depleting mines. In addition, as compared to mines
in the Powder River Basin, permitting and licensing and other environmental and regulatory
requirements are more costly and time-consuming to satisfy. These factors could materially
adversely affect the mining operations and cost structures of, and customers ability to use coal
produced by, operators in Central Appalachia, including us.
Other factors affecting the production and sale of our coal that could result in decreases in
profitability include: (i) expiration or termination of, or sales price redeterminations or
suspension of deliveries under, coal supply
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agreements; (ii) disruption or increases in the cost of
transportation services; (iii) changes in laws or regulations, including permitting requirements;
(iv) litigation; (v) work stoppages or other labor difficulties; (vi) mine worker vacation
schedules and related maintenance activities; and (vii) changes in coal market and general economic
conditions.
Transportation
The coal industry depends on rail, trucking and barge transportation to deliver shipments of coal
to customers, and transportation costs are a significant component of the total cost of supplying
coal. Disruption or insufficient availability of these transportation services could temporarily
impair our ability to supply coal to customers and thus adversely affect our business and the
results of our operations. As described in the Managements Discussion and Analysis of Financial
Condition-Outlook section of this Form 10-Q, we have experienced disruptions in rail service in
the past few months. In addition, increases in transportation costs associated with our coal, or
increases in our transportation costs relative to transportation costs for coal produced by our
competitors or of other fuels, could adversely affect our business and results of operations.
Reserves Title; Leasehold Interests
We base our reserve information on geological data assembled and analyzed by our staff, which
includes various engineers and geologists, and periodically reviewed by outside firms. The reserve
estimates are annually updated to reflect production of coal from the reserves and new drilling or
other data received. There are numerous uncertainties inherent in estimating quantities of
recoverable reserves, including many factors beyond our control. Estimates of economically
recoverable coal reserves and net cash flows necessarily depend upon a number of variable factors
and assumptions, such as geological and mining conditions which may not be fully identified by
available exploration data or may differ from experience in current operations, historical
production from the area compared with production from other producing areas, the assumed effects
of regulation by governmental agencies, and assumptions concerning coal prices, operating costs,
severance and excise taxes, development costs, and reclamation costs, all of which may cause
estimates to vary considerably from actual results.
For these reasons, estimates of the economically recoverable quantities attributable to any
particular group of properties, classifications of such reserves based on risk of recovery and
estimates of net cash flows expected therefrom, prepared by different engineers or by the same
engineers at different times, may vary substantially. Actual coal tonnage recovered from identified
reserve areas or properties, and revenues and expenditures with respect to our reserves, may vary
from estimates, and such variances may be material. These estimates thus may not accurately reflect
our actual reserves.
Most of our mining operations are conducted on properties we lease. The loss of any lease could
adversely affect our ability to develop the associated reserves. Because title to most of our
leased properties and mineral rights is not usually verified until we have made a commitment to
develop a property, which may not occur until after we have obtained necessary permits and
completed exploration of the property, our right to mine certain of our reserves may be adversely
affected if defects in title or boundaries exist. In order to obtain leases or mining contracts to
conduct mining operations on property where these defects exist, we have had to, and may in the
future have to, incur unanticipated costs. In addition, we may not be able to successfully
negotiate new leases or mining contracts for properties containing additional reserves or maintain
our leasehold interests in properties on which mining operations are not commenced during the term
of the lease.
Acquisitions
We continually seek to expand our operations and coal reserves in the regions in which we operate
through acquisitions of businesses and assets, including leases of coal reserves. Acquisition
transactions involve inherent risks, such as:
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uncertainties in assessing the value, strengths, weaknesses, contingent and other
liabilities and potential profitability of acquisition or other transaction candidates; |
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the potential loss of key personnel of an acquired business; |
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the ability to achieve identified operating and financial synergies anticipated to
result from an acquisition or other transaction; |
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problems that could arise from the integration of the acquired business; |
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unanticipated changes in business, industry or general economic conditions that affect
the assumptions underlying the acquisition or other transaction rationale; and |
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unexpected development costs, such as those related to the development of the Little
Thunder reserves, that adversely affect our profitability. |
Any one or more of these factors could cause us not to realize the benefits anticipated to result
from the acquisition of businesses or assets.
Post Retirement Benefits
We estimate our future postretirement medical and pension benefit obligations based on various
assumptions, including:
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actuarial estimates; |
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assumed discount rates; |
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estimates of mine lives; |
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expected returns on pension plan assets; and |
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changes in health care costs. |
Based on changes in our assumptions, our annual postretirement health and pension benefit costs
have increased. If our assumptions relating to these benefits change in the future, our costs could
further increase, which would reduce our profitability. In addition, future regulatory and
accounting changes relating to these benefits could result in increased obligations or additional
costs, which could also have a material adverse effect on our financial results.
On January 1, 1998, we replaced our existing pension plans with a new cash balance pension plan.
The accrued benefits of active participants under the former plans were vested as of that date and
the participants cash balance account was credited with the present value of the participants
earned pension benefit, payable at normal retirement age. On February 12, 2004, in an unrelated
case involving International Business Machines Corporation (IBM), the United States District
Court for the Southern District of Illinois affirmed its earlier ruling that the cash balance
formula used in IBMs conversion to a cash balance plan violated the age discrimination provisions
under ERISA. IBM has announced that it will appeal the decision to the Seventh Circuit Court of
Appeals. The Illinois District Courts decision conflicts with the decisions of two other district
courts and with proposed regulations for cash balance plans issued by Treasury and the IRS in
December 2002. In addition, on February 2, 2004, the Treasury Department proposed legislation that
would clarify that cash balance plans do not violate the age discrimination rules that apply to
pension plans as long as they treat older workers at least as well as younger workers. The
retirement account formula used for our pension plan may not meet the standard ultimately set forth
in the IBM Courts decision. Consequently, the IBM decision may have an impact on our and other
companies cash balance pension plans. The effect of the IBM decision on our cash balance plan or
our financial position has not been determined at this time.
Certain Contractual Arrangements
Our affiliate, Arch Western Resources, LLC, is the owner of our reserves and mining facilities in
the Powder River Basin and Western Bituminous regions of the United States. The agreement under
which Arch Western was formed provides that a subsidiary of ours, as the managing member of Arch
Western, generally has exclusive power and authority to conduct, manage and control the business of
Arch Western. However, consent of BP p.l.c., the other member of Arch Western, would generally be
required in the event that Arch Western proposes to make a distribution, incur indebtedness, sell
properties or merge or consolidate with any other entity if, at such time, Arch
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Western has a debt
rating less favorable than specified ratings with Moodys Investors Service or Standard & Poors or
fails to meet specified indebtedness and interest ratios.
In connection with our June 1, 1998 acquisition of Atlantic Richfield Companys (ARCO) coal
operations, we entered into an agreement under which we agreed to indemnify ARCO against specified
tax liabilities in the event that these liabilities arise as a result of certain actions taken
prior to June 1, 2013, including the sale or other disposition of certain properties of Arch
Western, the repurchase of certain equity interests in Arch Western by Arch Western, or the
reduction under certain circumstances of indebtedness incurred by Arch Western in connection with
the acquisition. ARCO was acquired by BP p.l.c. in 2000. Depending on the time at which any such
indemnification obligation was to arise, it could impact our profitability for the period in which
it arises.
Our Amended and Restated Certificate of Incorporation requires the affirmative vote of the holders
of at least two-thirds of outstanding common stock voting thereon to approve a merger or
consolidation and certain other fundamental actions involving or affecting control of us. Our
Bylaws require the affirmative vote of at least two-thirds of the members of our Board of Directors
in order to declare dividends and to authorize certain other actions.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by this Item is contained under the caption Managements Discussion and
Analysis of Financial Condition and Results of Operations in this report and is incorporated
herein by reference.
ITEM 4. CONTROLS AND PROCEDURES
The information required by this Item is contained under the caption Managements Discussion and
Analysis of Financial Condition and Results of Operations in this report and is incorporated
herein by reference.
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PART II OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
The information required by this Item is contained in the Contingencies Legal Contingencies
section of Managements Discussion and Analysis of Financial Condition and Results of Operations
in this report and is incorporated herein by reference.
ITEM 2. CHANGES IN SECURITIES, USE OF PROCEEDS AND ISSUER PURCHASES OF EQUITY SECURITIES
Nothing to report under this item.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
Nothing to report under this item.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Nothing to report under this item.
ITEM 5. OTHER INFORMATION
Nothing to report under this item.
ITEM 6. EXHIBITS
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2.1
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Master Contribution Agreement among Arch Coal, Inc., ArcLight Energy
Partners Fund I, L.P., Timothy Elliott and Magnum Coal Company, dated
October 7, 2005.*
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3.1
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Amended and Restated Certificate of Incorporation of Arch Coal, Inc. (incorporated herein by
reference to Exhibit 3.1 to the Companys Quarterly Report on Form 10-Q for the Quarter Ended
March 31, 2000) |
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3.2
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Amended and Restated Bylaws of Arch Coal, Inc. (incorporated herein by reference to Exhibit 3.2
to the Companys Annual Report on Form 10-K for the Year Ended December 31, 2000) |
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3.3
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Certificate of Designations Establishing the Designations, Powers, Preferences, Rights,
Qualifications, Limitations and Restrictions of the Companys 5% Perpetual Cumulative
Convertible Preferred Stock (incorporated herein by reference to Exhibit 3 to current report on
Form 8-A filed on March 5, 2003) |
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31.1
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Certification of Principal Executive Officer Pursuant to § 302 of the Sarbanes-Oxley Act of 2002. |
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31.2
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Certification of Principal Financial Officer Pursuant to § 302 of the Sarbanes-Oxley Act of 2002. |
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32.1
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Certification of Principal Executive Officer Pursuant to 18 U.S.C. § 1350, as adopted pursuant
to § 906 of the Sarbanes-Oxley Act of 2002. |
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32.2
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Certification of Principal Financial Officer Pursuant to 18 U.S.C. § 1350, as adopted pursuant
to § 906 of the Sarbanes-Oxley Act of 2002. |
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* |
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Arch Coal, Inc. agrees to furnish supplementally a copy of any
omitted exhibit or schedule to the Commission upon request.
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42
SIGNATURES
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.
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ARCH COAL, INC. |
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(Registrant) |
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Date: November 9, 2005
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/s/ John W. Lorson |
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John W. Lorson |
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Controller |
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(Chief Accounting Officer) |
43