SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q/A
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 For the Quarterly Period Ended September 30, 2002
OR
[ ]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)
Delaware 43-0921172
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
One CityPlace Drive, Suite 300, St. Louis, Missouri 63141
(Address of principal executive offices)(Zip Code)
Registrant's 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 X No ___
At November 1, 2002, there were 52,382,010 shares of registrant's common stock
outstanding.
EXPLANATORY NOTE TO FORM 10-Q/A
Arch Coal, Inc. is filing this Amendment to its Quarterly Report on Form 10-Q
for the Quarter ended September 30, 2002. It is amending Part I, Item 1
(Financial Statements) to correct an inadvertent clerical error. The line item
"Long-term debt" in the Company's Condensed Consolidated Balance Sheets was
dropped in its entirety during the process of converting the document to EDGAR.
This error did not affect the remainder of the Balance Sheets and there is no
change to the Company's Condensed Consolidated Statements of Operations or
Condensed Consolidated Statements of Cash Flows.
INDEX
PART I. FINANCIAL INFORMATION PAGE
Item 1. Financial Statements
Condensed Consolidated Balance Sheets as of September 30, 2002 and
December 31, 2001................................................1
Condensed Consolidated Statements of Operations for the Three
Months Ended September 30, 2002 and 2001 and the Nine Months
Ended September 30, 2002 and 2001................................2
Condensed Consolidated Statements of Cash Flows for the
Nine Months Ended September 30, 2002 and 2001....................3
Notes to Condensed Consolidated Financial Statements..................4
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations.................9
Item 3. Quantitative and Qualitative Disclosures About Market Risk...29
PART II. OTHER INFORMATION
Item 1. Legal Proceedings...........................................29
Item 6. Exhibits and Reports on Form 8-K............................29
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ARCH COAL, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
September 30, December 31,
2002 2001
-------------------- ----------------------
(Unaudited)
Assets
Current assets
Cash and cash equivalents $ 9,213 $ 6,890
Trade accounts receivable 141,887 149,956
Other receivables 33,253 32,303
Inventories 73,710 60,133
Prepaid royalties 1,994 1,997
Deferred income taxes 23,840 23,840
Other 12,948 14,337
-------------------- ----------------------
Total current assets 296,845 289,456
-------------------- ----------------------
Property, plant and equipment, net 1,388,412 1,396,786
-------------------- ----------------------
Other assets
Prepaid royalties 51,198 35,216
Coal supply agreements 65,551 81,424
Deferred income taxes 212,108 195,411
Investment in Canyon Fuel 157,800 170,686
Other 44,269 34,580
-------------------- ----------------------
Total other assets 530,926 517,317
-------------------- ----------------------
Total assets $ 2,216,183 $ 2,203,559
==================== ======================
Liabilities and stockholders' equity
Current liabilities
Accounts payable $ 109,757 $ 99,081
Accrued expenses 142,122 134,062
Current portion of debt 6,500 6,500
-------------------- ----------------------
Total current liabilities 258,379 239,643
Long-term debt 792,291 767,355
Accrued postretirement benefits other than pension 324,501 326,098
Accrued reclamation and mine closure 130,411 123,761
Accrued workers' compensation 82,715 78,768
Accrued pension cost - 22,539
Obligations under capital leases 432 8,210
Other noncurrent liabilities 72,650 66,443
-------------------- ----------------------
Total liabilities 1,661,379 1,632,817
-------------------- ----------------------
Stockholders' equity
Common stock 527 527
Paid-in-capital 835,740 835,427
Retained deficit (252,004) (239,336)
Treasury stock, at cost (5,047) (5,047)
Accumulated other comprehensive loss (24,412) (20,829)
-------------------- ----------------------
Total stockholders' equity 554,804 570,742
-------------------- ----------------------
Total liabilities and stockholders' equity $ 2,216,183 $ 2,203,559
==================== ======================
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)
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------------------ ---------------------------------
2002 2001 2002 2001
---------------- ---------------- ----------------- ----------------
Revenues
Coal sales $ 386,298 $ 337,246 $ 1,103,882 $ 1,047,502
Income from equity investment 1,222 4,066 2,291 14,372
Other revenues 13,235 11,993 37,523 41,437
---------------- -------------- ---------------- --------------
400,755 353,305 1,143,696 1,103,311
---------------- -------------- ---------------- --------------
Costs and expenses
Cost of coal sales 368,054 330,196 1,056,194 992,297
Selling, general and administrative expenses 9,734 8,751 29,675 34,589
Amortization of coal supply agreements 5,385 6,217 15,872 21,378
Other expenses 7,484 4,097 20,856 12,621
---------------- -------------- ---------------- --------------
390,657 349,261 1,122,597 1,060,885
---------------- -------------- ---------------- --------------
Income from operations 10,098 4,044 21,099 42,426
Interest expense, net:
Interest expense (13,425) (15,128) (39,783) (51,208)
Interest income 217 244 799 3,881
---------------- -------------- ---------------- --------------
(13,208) (14,884) (38,984) (47,327)
---------------- -------------- ---------------- --------------
Loss before income taxes (3,110) (10,840) (17,885) (4,901)
Benefit from income taxes (4,750) (2,700) (14,250) (3,700)
---------------- -------------- ---------------- --------------
Net income (loss) $ 1,640 $ (8,140) $ (3,635) $ (1,201)
================ ============== ================ ==============
Basic and diluted earnings (loss)
per common share $ 0.03 $ (0.15) $ (0.07) $ (0.03)
================ ============== ================ ==============
Dividends declared per share $ 0.0575 $ 0.0575 $ 0.1725 $ 0.1725
================ ============== ================ ==============
See notes to condensed consolidated financial statements
2
ARCH COAL, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)
Nine Months Ended
September 30,
--------------------------------------------
2002 2001
-------------------- --------------------
Operating activities
Net loss $ (3,635) $ (1,201)
Adjustments to reconcile to cash provided by operating activities:
Depreciation, depletion and amortization 130,835 132,298
Prepaid royalties expensed 5,738 5,406
Net gain on disposition of assets (501) (7,334)
Income from equity investment (2,291) (14,372)
Net distributions from equity investment 15,177 42,711
Changes in:
Receivables 7,119 1,771
Inventories (13,577) (8,639)
Accounts payable and accrued expenses 403 (3,787)
Income taxes (14,406) (10,339)
Accrued postretirement benefits other than pension (1,597) (10,137)
Accrued reclamation and mine closure 6,650 (328)
Accrued workers' compensation benefits 3,947 1,348
Other (4,113) (3,680)
-------------------- --------------------
Cash provided by operating activities 129,749 123,717
-------------------- --------------------
Investing activities
Additions to property, plant and equipment (117,363) (89,795)
Proceeds from dispositions of property, plant and equipment 2,231 8,122
Additions to prepaid royalties (21,717) (21,674)
-------------------- --------------------
Cash used in investing activities (136,849) (103,347)
-------------------- --------------------
Financing activities
Net borrowings (payments) on revolver and lines of credit 24,936 (250,423)
Payments on term loans - (135,000)
Debt financing costs (8,228) -
Proceeds from sale and leaseback of equipment 9,213 -
Reduction of obligations under capital leases (7,778) (2,351)
Dividends paid (9,033) (8,554)
Proceeds from sale of common stock 313 380,998
Purchase of treasury stock - (5,048)
-------------------- --------------------
Cash provided by (used in) financing activities 9,423 (20,378)
-------------------- --------------------
Increase (decrease) in cash and cash equivalents 2,323 (8)
Cash and cash equivalents, beginning of period 6,890 6,028
-------------------- --------------------
Cash and cash equivalents, end of period $ 9,213 $ 6,020
==================== ====================
See notes to condensed consolidated financial statements.
3
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2002
(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 nine month period ended September 30, 2002 are not necessarily indicative of
results to be expected for the year ending December 31, 2002. Arch Coal, Inc.
(the "Company") operates one reportable segment: 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 Company's mines are
primarily located in the central Appalachian and western regions of the United
States. All subsidiaries (except as noted below) are wholly owned. Significant
intercompany transactions and accounts have been eliminated in consolidation.
The Company's 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.
The membership interests in the Utah coal operations, Canyon Fuel Company, LLC
("Canyon Fuel"), are owned 65% by Arch Western and 35% by a subsidiary of ITOCHU
Corporation. The Company's 65% ownership of Canyon Fuel is accounted for on the
equity method in the Condensed Consolidated Financial Statements as a result of
certain super-majority voting rights in the joint venture agreement. Income from
Canyon Fuel is reflected in the Condensed Consolidated Statements of Operations
as income from equity investment (see additional discussion in "Investment in
Canyon Fuel" in Note C).
Note B - 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,
------------- -- ------------- ------------ -- ----------------
2002 2001 2002 2001
------------- ------------- ------------ ----------------
(in thousands)
Net income (loss) $ 1,640 $ (8,140) $ (3,635) $ (1,201)
Other comprehensive loss net of income tax
benefit (8,078) (5,904) (3,583) (13,806)
------------- ------------- ------------ ----------------
Total comprehensive loss $ (6,438) $(14,044) $ (7,218) $ (15,007)
============= ============= ============ ================
Note C - Investment in Canyon Fuel
The following table presents unaudited summarized financial information for
Canyon Fuel, which is accounted for on the equity method:
4
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------------- ---------------------------
Condensed Income Statement Information 2002 2001 2002 2001
------------- ------------ ----------- ------------
(in thousands)
Revenues $ 52,337 $ 77,060 $ 189,637 $ 218,581
Total costs and expenses 54,610 70,220 194,209 197,052
------------- ------------ ----------- ------------
Net income (loss) $ (2,273) $ 6,840 $ (4,572) $ 21,529
============= ============ =========== ============
65% of Canyon Fuel net income (loss) $ (1,477) $ 4,446 $ (2,972) $ 13,994
Effect of purchase adjustments 2,699 (380) 5,263 378
------------- ------------ ----------- ------------
Company's income from its equity
investment in Canyon Fuel $ 1,222 $ 4,066 $ 2,291 $ 14,372
============= ============ =========== ============
The Company's income from its equity investment in Canyon Fuel represents 65% of
Canyon Fuel's net income (loss) after adjusting for the effect of purchase
adjustments related to its investment in Canyon Fuel. The Company's investment
in Canyon Fuel reflects purchase adjustments primarily related to the reduction
in amounts assigned to sales contracts, mineral reserves and other property,
plant and equipment. The purchase adjustments are amortized consistent with the
underlying assets of the joint venture.
Note D - Inventories
Inventories consist of the following:
September 30, December 31,
2002 2001
----------------- ----------------
(in thousands)
Coal $ 41,910 $ 28,165
Repair parts and supplies 31,800 31,968
----------------- ----------------
$ 73,710 $ 60,133
================= ================
Note E - Debt
Debt consists of the following:
September 30, December 31,
2002 2001
---------------- ----------------
(in thousands)
Indebtedness to banks under lines of credit $ 20,000 $ 13,500
Indebtedness to banks under revolving credit
agreement, expiring April 18, 2007 102,400 80,000
Indebtedness to banks under variable rate,
non-amortizing term loan due April 18, 2007 150,000 -
Indebtedness to banks under variable rate,
non-amortizing term loan due April 18, 2008 525,000 -
Indebtedness to banks under variable rate,
non-amortizing term loan due May 31, 2003 - 675,000
Other 1,391 5,355
---------------- ----------------
798,791 773,855
Less current portion 6,500 6,500
---------------- ----------------
Long-term debt $ 792,291 $ 767,355
================ ================
5
On April 18, 2002, the Company and Arch Western completed a refinancing of their
existing credit facilities. The new credit facilities include five- and six-year
non-amortizing term loans totaling $675.0 million at Arch Western and a
five-year revolving credit facility totaling $350.0 million for the Company. The
five-year non-amortizing term loan at Arch Western is for $150.0 million and the
six-year non-amortizing term loan is for $525.0 million. The rate of interest on
borrowings under both of the credit facilities is a floating rate based on
LIBOR. The Company's credit facility is secured by ownership interests in
substantially all of its subsidiaries, except its ownership interests in Arch
Western and its subsidiaries. The Arch Western credit facility is secured by its
ownership interests in substantially all of its subsidiaries, but is not
guaranteed by the Company.
Note F - 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 previously provided for, will not have a material
adverse effect on the consolidated financial position, results of operations or
liquidity of the Company.
Note G - Changes in Estimates and Other Non-Recurring Revenues and Expenses
During the nine months ended September 30, 2002, the Company settled certain
coal contracts with a customer that was partially unwinding its coal supply
position and desired to buy out of the remaining terms of those contracts. The
settlements resulted in a pre-tax gain of $5.6 million which was recognized in
other revenues in the Condensed Consolidated Statements of Operations.
The Company recognized a pre-tax gain of $4.6 million during the nine months
ended September 30, 2002 as a result of a workers' compensation premium
adjustment refund from the State of West Virginia. During 1998, the Company
entered into the West Virginia workers' compensation plan at one of its
subsidiary operations. The subsidiary paid standard base rates until the West
Virginia Division of Workers' Compensation could determine the actual rates
based on claims experience. Upon review, the Division of Workers' Compensation
refunded $4.6 million in premiums which the Company received during the quarter
ended June 30, 2002. Partially offsetting this gain was an increase to the
workers' compensation accrual resulting in a pre-tax loss of $3.3 million caused
by adverse experience at several of the Company's self insured locations. These
workers' compensation items were recognized as adjustments to costs of coal
sales in the Condensed Consolidated Statements of Operations.
The Company's operating results for the nine months ended September 30, 2001
reflect a $9.4 million insurance settlement as part of the Company's coverage
under its property and business interruption policy. The insurance settlement
represents the final settlement for losses incurred at the West Elk Mine in
Gunnison County, Colorado, which was idled from January 28, 2000 to July 12,
2000 following the detection of combustion-related gasses. The final settlement
was recorded as a reduction in cost of coal sales in the Condensed Consolidated
Statements of Operations.
During the third quarter ended September 30, 2001, as a result of estimate
changes associated with reclamation, the Company reduced its reclamation
liability resulting in a pre-tax gain of $1.9 million. During the nine months
ended September 30, 2001, the Company reduced its reclamation liability
resulting in a pre-tax gain of $5.4 million, of which $3.5 million was a result
of permit revisions at its idle mine properties in Illinois recorded in the
first quarter of 2001. These adjustments were recognized as a reduction in cost
of coal sales.
During the nine months ended September 30, 2001, as a result of progress in
processing claims associated with the recovery of certain previously paid excise
taxes on export sales, the Company recognized a pre-tax gain of $4.6 million. Of
the $4.6 million recognized, $3.1 million represents the interest component of
the claim and was recorded as interest income. The gain stems from an IRS notice
during the second quarter of 2000 outlining the procedures for obtaining tax
refunds on black lung excise taxes paid by the industry on export sales. The
notice was the result of a 1998 federal district court decision that found such
taxes to be unconstitutional.
6
The Company reduced its stock based benefit program accruals for awards that did
not meet minimum performance levels to qualify for a payout which resulted in an
increase in pre-tax income of $4.3 million during the three months ended
September 30, 2001. For the nine months ended September 30, 2001, the Company
recognized pre-tax charges of $4.0 million (which is net of the $4.3 million
accrual reduction included in the third quarter of 2001) for stock-based
compensation benefit programs that may be realized in future periods as a result
of improved stock performance. During the nine months ended September 30, 2001,
the Company also recognized reduced interest expense of $1.7 million primarily
as a result of the termination of certain interest rate swaps, which did not
qualify as hedges under accounting prescribed by FAS 133, "Accounting for
Derivative Instruments and Hedging Activities." During the nine months ended
September 30, 2001, Canyon Fuel, the Company's equity method investment,
recovered previously paid property taxes. The Company's share of these
recoveries was $2.6 million and is reflected in income from equity investment on
the Condensed Consolidated Statements of Operations. During the three and nine
months ended September 30, 2001, the Company sold surplus land resulting in a
$2.9 million and $6.5 million pre-tax gain, respectively.
Note H - Earnings (Loss) per Share
The following table sets forth the computation of basic and diluted earnings
(loss) per common share from continuing operations.
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------------- -------------------------------
2002 2001 2002 2001
-------------- ------------ ------------ --------------
(in thousands, except per share data)
Numerator:
Net income (loss) $ 1,640 $ (8,140) $ (3,635) $ (1,201)
============== ============ ============ ==============
Denominator:
Weighted average shares - denominator for basic 52,380 52,681 52,371 47,404
Dilutive effect of employee stock options 121 - - -
-------------- ------------ ------------ --------------
Adjusted weighted average shares - denominator
for diluted 52,501 52,681 52,371 47,404
============== ============ ============ ==============
Earnings (loss) per common share
Basic $ .03 $ (.15) $ (.07) $ (.03)
Diluted $ .03 $ (.15) $ (.07) $ (.03)
============== ============ ============ ==============
For the three month period ended September 30, 2001 and the nine month periods
ended September 30, 2002 and 2001, employee stock options did not have a
dilutive impact because the Company incurred losses in those periods.
Note I - Other Items
On April 19, 2002, the Company created a limited partnership, Natural Resource
Partners L.P., with three private affiliated companies: Western Pocahontas
Properties Limited Partnership, Great Northern Properties Limited Partnership
and New Gauley Coal Corporation (collectively the "WPP Group"). Natural Resource
Partners was formed to engage principally in the business of owning and managing
coal royalty properties in the three major coal producing regions in the United
States: Appalachia, the Illinois Basin and the Western United States. A
registration statement on Form S-1 was filed with the Securities and Exchange
Commission relating to an initial public offering of common units representing
limited partner interests in Natural Resource Partners. The Company contributed
approximately 454 million tons of its 3.4 billion tons of total coal reserves to
Natural Resource Partners in exchange for its ownership interest in the
partnership.
In October 2002, the Company completed the sale of 1.9 million common units of
Natural Resource Partners resulting in net proceeds of $33.6 million after the
underwriting discount and expenses. The proceeds were immediately applied to
debt reduction. After the completion of the sale, the Company holds 34.1% of the
limited partner interests and 42.25% of the general partnership. The investment
will be accounted for using the equity method.
7
Note J - Accounting Development
In June 2001, the Financial Accounting Standards Board issued FAS 143,
"Accounting for Asset Retirement Obligations," which is effective for fiscal
years beginning after June 15, 2002. The statement requires legal obligations
associated with the retirement of long-lived assets to be recognized at their
fair value at the time that the obligations are incurred. Upon initial
recognition of a liability, that cost should be capitalized as part of the
related long-lived asset and allocated to expense over the useful life of the
asset. The Company will adopt FAS 143 on January 1, 2003. Due to the significant
number of mines that the Company operates throughout the United States and the
extensive amount of information that must be reviewed and estimates that must be
made to assess the effects of the statement, the expected impact of adoption of
FAS 143 on the Company's financial position or results of operations has not yet
been determined.
8
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
FORWARD-LOOKING STATEMENTS
Statements in this quarterly report which are not statements of historical fact
are forward-looking statements within the "safe harbor" provision of the Private
Securities Litigation Reform Act of 1995. These forward-looking statements are
based on the information available to, and the expectations and assumptions
deemed reasonable by, the Company at the time the statements were made. Because
these forward-looking statements are subject to various risks and uncertainties,
actual results may differ materially from those projected in the statements.
These expectations, assumptions and uncertainties include the Company's
expectation of growth in the demand for electricity; belief that legislation and
regulations relating to the Clean Air Act and the relatively higher costs of
competing fuels will increase demand for its compliance and low-sulfur coal;
expectation that the Company will continue to have adequate liquidity from its
cash flow from operations, together with available borrowings under its credit
facilities, to finance the Company's working capital needs and meet its debt
reduction goals; a variety of market, operational, geologic, permitting, labor
and weather related factors and the other risks and uncertainties which are
described below under "Contingencies" and "Certain Trends and Uncertainties."
RESULTS OF OPERATIONS
Quarter Ended September 30, 2002, Compared
to Quarter Ended September 30, 2001
Net Income. Net income for the quarter ended September 30, 2002 was $1.6 million
compared to a net loss of $8.1 million for the quarter ended September 30, 2001.
Results for the current quarter were negatively impacted by the state of
oversupply in the coal market that resulted from an extremely mild winter and a
period of industrial economic weakness that dampened electricity demand. As a
result, during the third quarter of 2002, the Company continued its reduced
rates of production from planned levels at its mining operations. Partially
offsetting these negative items in the current quarter were higher contract
prices for coal shipped during the quarter compared to the same period in the
prior year, an increased income tax benefit resulting from higher levels of
percentage depletion, and reduced interest expense associated with lower
interest rates.
Results for the third quarter of 2001 were negatively impacted by production
difficulties and increased costs at the Company's West Elk mine in Colorado
caused by high methane levels and by production difficulties at the Samples
surface operation in West Virginia caused by a sandstone intrusion into the coal
seam. Results for the third quarter of 2001 were also impacted by the following
other items: (1) A $2.9 million pre-tax gain primarily from the sale of surplus
land. (2) An increase of pre-tax income of $1.9 million caused by a reduction in
the Company's reclamation liability due to changes in estimates. (3) A pre-tax
$4.3 million gain from the partial reversal of previously recorded compensation
accruals resulting from certain stock-based compensation plans not achieving
minimum performance targets required for awards.
Revenues. Total revenues for the quarter ended September 30, 2002 were $400.8
million, an increase of $47.5 million from the quarter ended September 30, 2001.
The increase was primarily caused by increased pricing on coal shipped during
the quarter ended September 30, 2002 compared to the same period in the prior
year. Average coal sales realizations on a per ton basis were $13.45 per ton for
the quarter ended September 30, 2002 compared to $12.44 per ton for the quarter
ended September 30, 2001. In addition to the impact of favorably priced
contracts, the Company also benefited from increased shipments in the quarter
ended September 30, 2002 as compared to the same period in the prior year. The
Company shipped 28.7 million tons during the quarter ended September 30, 2002
compared to 27.1 million tons during the quarter ended September 30, 2001.
Income From Equity Investment. Income from the equity investment in Canyon Fuel
for the quarter ended September 30, 2002 was $1.2 million, a decrease of $2.9
million from the quarter ended September 30, 2001. The decrease was primarily
the result of lower realizations due to an above market price contract reopening
to market-based rates in accordance with contract terms on December 31, 2001.
9
Other Revenues. The increase in other revenues of $1.2 million in the third
quarter of 2002 compared to the third quarter of 2001 was primarily attributable
to increased royalties from third parties, increased transloading fees, and
premiums earned on purchase options granted to certain customers. These
increases were offset by a reduction of other revenues of $2.9 million as gains
from land sales decreased from $2.9 million in the quarter ended September 30,
2001 to zero in the quarter ended September 30, 2002.
Income From Operations. The following table presents income from operations
adjusting for the items discussed above.
Three Months Ended
September 30,
2002 2001
---------------- ---------------
(in millions)
Income from operations as reported $10.1 $4.0
Adjustments to (exclude)/add-back:
Losses at the West Elk mine - 2.3
Samples surface operation losses - 5.6
Land sales - (2.9)
Stock based compensation accrual adjustment - (4.3)
Reclamation adjustment - (1.9)
---------------- ---------------
Adjusted income from operations $10.1 $2.8
================ ===============
The increase in adjusted income from operations is primarily attributable to
improved performance at the Company's Black Thunder and Samples operations.
However, these improvements were offset by planned cut-backs of production in
response to the weak market environment described above. The decision to scale
back production during the year came after the Company prepared most of the
operations to maximize production in order to capitalize on the higher market
prices for coal the Company had previously projected for 2002. Therefore,
certain costs incurred to maximize production did not result in higher revenues
but did increase the cost of coal sales. Cost of coal sales on a per ton basis
was $12.82 per ton for the quarter ended September 30, 2002, compared to $12.18
per ton for the quarter ended September 30, 2001.
Interest Expense. Interest expense decreased by $1.7 million to $13.4 million
for the third quarter of 2002 primarily as a result of lower interest rates
during the third quarter of 2002 when compared to the third quarter of 2001.
Income Taxes. The Company's effective tax rate is sensitive to changes in
estimates of annual profitability and percentage depletion. The income tax
benefit recorded in the third quarter of 2002 is primarily the result of the
favorable impact of percentage depletion. The benefit resulting from percentage
depletion increased in the third quarter of 2002 as compared to the same period
in 2001 as a result of the impact of higher coal prices and increased
profitability at certain of the Company's mines.
Adjusted EBITDA. Adjusted EBITDA (income from operations before the effect of
net interest expense; income taxes; and depreciation, depletion and amortization
of the Company, its subsidiaries and its ownership percentage in its equity
investments) was $59.2 million for the current quarter compared to $58.6 million
for the third quarter of 2001. Adjusted EBITDA should not be considered in
isolation or as an alternative to net income, operating income or cash flows
from operations or as a measure of a company's profitability, liquidity or
performance under generally accepted accounting principles.
10
Nine Months Ended September 30, 2002, Compared
to Nine Months Ended September 30, 2001
Net Loss. The net loss for the nine months ended September 30, 2002 was $3.6
million compared to a net loss of $1.2 million for the nine months ended
September 30, 2001. Results for the nine months ended September 30, 2002 were
negatively impacted by the current state of oversupply in the coal market that
resulted from an extremely mild winter and a period of industrial economic
weakness that dampened electricity demand. As a result, during the nine months
ended September 30, 2002 the Company reduced the rate of production from planned
levels at its mining operations. In addition, as described below, the Company's
results for the nine months ended September 30, 2002 continued to be negatively
impacted by production difficulties at its Samples surface operation in West
Virginia. Partially offsetting these negative items in the nine months ended
September 30, 2002 were higher contract prices for coal shipped during the
period compared to the same period in the prior year, an increased income tax
benefit resulting from higher levels of percentage depletion and reduced
interest expense associated with lower debt levels and lower interest rates.
Results for the nine months ended September 30, 2002 were also impacted by the
settlement of certain coal contracts with a customer that was partially
unwinding its coal supply position and desired to buy-out of the remaining terms
of those contracts. The settlement resulted in a pre-tax gain of $5.6 million.
Results for the nine months ended September 30, 2001 were impacted by production
difficulties and increased costs at the Company's West Elk mine in Colorado
caused by high methane levels, and by production difficulties at the Samples
surface operation in West Virginia caused by a sandstone intrusion into the coal
seam. Results for the nine months ended September 30, 2001 were also impacted by
the following other items: (1) A $9.4 million pre-tax insurance settlement as
part of the Company's coverage under its property and business interruption
policy. The insurance settlement represents the final settlement for losses
incurred for the West Elk mine idling. (2) A $4.6 million pre-tax gain as a
result of progress in processing claims associated with the recovery of certain
previously paid excise taxes on export sales. The gain stems from an IRS notice
during the second quarter of 2000 outlining the procedures for obtaining tax
refunds on black lung excise taxes paid by the industry on export sales. The
notice was the result of a 1998 federal district court decision that found such
taxes to be unconstitutional. Of the $4.6 million recognized, $3.1 million
represented the interest component of the claim and was recorded as interest
income. (3) An increase of pre-tax income of $5.4 million primarily from a
reduction in the amount of expected reclamation work at the Company's idle mine
properties resulting from permit revisions. (4) A $1.7 million reduction in
interest expense primarily associated with the termination of certain interest
rate swaps that did not qualify as hedges under the accounting treatment
prescribed by FAS 133, "Accounting for Derivative Instruments and Hedging
Activities." (5) A pre-tax charge of $4.0 million for stock-based compensation
benefits that may be realized in future periods.
Despite improved operating performance in the third quarter of 2002, results at
the Samples surface operations for the nine months ended September 30, 2002 were
negatively impacted by the transition into a new permit area and away from the
sandstone intrusion first encountered during the second quarter of 2001. The
intrusion caused the principal coal seam to thin which resulted in lower
production and higher associated costs from the second quarter of 2001 through
the first quarter of 2002. Although the Samples surface operation worked out of
the influence of the sandstone channel early in the second quarter of 2002, it
was hindered during the second quarter by market conditions, mine sequencing
issues associated with the delayed issuance of permits, and isolated geologic
issues. During the nine months ended September 30, 2002 and 2001, the Samples
surface operation incurred pre-tax operating losses of $2.2 million and $9.2
million, respectively. In 2001, the West Elk mine encountered
higher-than-expected methane levels following the relocation of its longwall
mining system to the eastern section of the mine in late February 2001. The high
methane levels reduced production during the nine months ended September 30,
2001, which resulted in a pre-tax loss at the operation of $13.1 million,
exclusive of insurance recoveries.
Revenues. Total revenues for the nine months ended September 30, 2002 were
$1,143.7 million, an increase of $40.4 million from the nine months ended
September 30, 2001. The increase was caused primarily by the Company shipping
more favorably priced contracts during the first nine months of 2002 as compared
to the same period in 2001. Average coal sales realizations on a per ton basis
were $13.85 per ton for the nine months ended September 30, 2002 compared to
$12.40 per ton for the nine months ended September 30, 2001. The impact of the
pricing increases was partially offset by reduced coal shipments due to
oversupply conditions that existed in the market as described above. The Company
shipped 78.3 million tons during the nine months ended September 30, 2002
compared to 81.0 million tons during the nine months ended September 30, 2001.
11
Income From Equity Investment. Income from the Company's equity investment in
Canyon Fuel during the nine months ended September 30, 2002 was $2.3 million as
compared to $14.4 million during the nine months ended September 30, 2001. The
decrease was primarily the result of lower realizations due to an above market
price contract reopening to market-based rates in accordance with contract terms
on December 31, 2001 and recoveries of previously paid property taxes during the
nine months ended September 30, 2001. The Company's share of these recoveries
was $2.6 million.
Other Revenues. The decrease in other revenues of $3.9 million in the nine
months ended September 30, 2002 compared to the nine months ended September 30,
2001 was primarily attributable to additional sales of assets during the nine
months ended September 30, 2001. These asset sales resulted in a pre-tax gain of
$6.5 million in the nine months ended September 30, 2001 compared to $0.5
million during the nine months ended September 30, 2002. In addition, during the
nine months ended September 30, 2001, the Company amortized a gain on a coal
sales contract buy-down that resulted in $4.9 million of pre-tax income. The
gain was fully amortized prior to December 31, 2001. The results for the nine
months ended September 30, 2002 were also affected by the settlement of certain
coal contracts with a customer that was unwinding its coal supply position and
desired to buy-out of the remaining terms of those contracts, as described
above.
Income From Operations. The following table presents income from operations
adjusting for the items discussed above.
Nine Months Ended
September 30,
------------------------------------
---------------- ---------------
2002 2001
---------------- ---------------
(in millions)
Income from operations as reported $21.1 $42.4
Adjustments to (exclude)/add-back:
Gain on contract buy-out (5.6) -
Gain amortization on contract buydown - (4.9)
Losses at the West Elk mine - 13.1
West Elk mine insurance recoveries - (9.4)
Samples surface operation losses 2.2 9.2
Land sales (0.5) (6.5)
Reclamation adjustment - (5.4)
Stock based compensation accrual adjustment - 4.0
Canyon Fuel property tax recoveries - (2.6)
---------------- ---------------
Adjusted income from operations $17.2 $39.9
================ ===============
The decrease in adjusted income from operations is primarily attributable to the
Company's planned cut-back of production during the nine months ended September
30, 2002 in response to the weak market environment described above. The
decision to scale back production during the period came after the Company
prepared most of the operations to maximize production in order to capitalize on
the higher market prices for coal the Company had previously projected for 2002.
Therefore, certain costs incurred to maximize production did not result in
higher revenues but did increase the cost of coal sales. Cost of coal sales on a
per ton basis was $13.48 per ton for the nine months ended September 30, 2002,
compared to $12.26 per ton for the nine months ended September 30, 2001.
Selling, General and Administrative Expenses. Selling, general and
administrative expenses declined $4.9 million to $29.7 million during the nine
months ended September 30, 2002 when compared to expenses of $34.6 million
during the nine months ended September 30, 2001. The decrease is primarily
attributable to the stock-based compensation accruals recorded during the first
nine months of 2001 as discussed above. The Company did not record any stock
based compensation accruals during the nine months ended September 30, 2002.
12
Amortization of Coal Supply Agreements. Amortization of coal supply agreements
was reduced to $15.9 million for the nine months ended September 30, 2002,
compared to $21.4 million in the same period of 2001. The decrease is a result
of the expiration and buy-out of above-market contracts that were valued as
assets on the Company's balance sheet and amortized in 2001.
Other Expenses. Other expenses increased to $20.9 million during the nine months
ended September 30, 2002 from $12.6 million for the same period of 2001
primarily due to the cost of terminating certain contractual obligations for the
purchase or sale of coal.
Interest Expense. Interest expense decreased by $11.4 million to $39.8 million
during the nine months ended September 30, 2002 as a result of lower debt levels
and lower interest rates during the nine months ended September 30, 2002 when
compared to the same period in 2001. The net proceeds from two public stock
offerings in the first nine months of 2001 were used to significantly reduce
debt levels. Interest expense during the nine months ended September 30, 2001
was reduced by $1.7 million as a result of the termination of certain interest
rate swaps described previously.
Interest Income. The decrease in interest income of $3.1 million was the result
of the recognition of the interest component of the black lung excise tax
recovery during the nine months ended September 30, 2001 described previously.
Income Taxes. The Company's effective tax rate is sensitive to changes in
estimates of annual profitability and percentage depletion. The income tax
benefit recorded in the nine months ended September 30, 2002 is primarily the
result of the impact of percentage depletion. The benefit resulting from
percentage depletion increased in the nine months ended September 30, 2002 as
compared to the same period in 2001 as a result of the impact of higher coal
prices and increased profitability at certain of the Company's mines.
Adjusted EBITDA. Adjusted EBITDA (income from operations before the effect of
net interest expense; income taxes; and depreciation, depletion and amortization
of the Company, its subsidiaries and its ownership percentage in its equity
investments) was $171.1 million during the nine months ended September 30, 2002
compared to $207.2 million for the same period of 2001. The decrease in adjusted
EBITDA was primarily attributable to the $21.3 million decrease in income from
operations resulting from the reduction in production levels and the Samples
production issues, both of which are discussed above.
OUTLOOK
Production Levels. The Company reduced its rate of coal production at its
eastern and western operations by approximately 5% during the first nine months
of 2002. These actions were taken in response to unfavorable spot coal markets
following an extremely mild winter and a period of industrial economic weakness
that dampened electricity demand. Although the timing of any recovery in coal
markets remains uncertain, there have been indications that prices may return to
more favorable levels in the future. These indications include more normal
weather patterns, some indication of economic recovery and an overall decrease
in coal production and utility stockpiles.
Previously, the Company had disclosed that longwall mineable reserves at Mingo
Logan were likely to be exhausted during 2002. As a result of improvements to
the mine plan, the mine is not expected to exhaust its longwall mineable
reserves until 2006, subject to permit modifications. However, due to more
difficult mining conditions, production levels in the future are expected to be
lower than those experienced historically.
Permitting Issues. On May 8, 2002, in Kentuckians for the Commonwealth v.
Rivenburgh, the U.S. District Court for the Southern District of West Virginia
enjoined the Huntington, West Virginia office of the U.S. Army Corps of
Engineers from issuing any new Section 404 Clean Water Act permits that
authorize the placement of rock and soil into channels that comprise waters of
the United States. This process is used both in surface mining operations, where
layers of dirt and rock are removed to expose the underlying coal seam, as well
as underground mining operations. The excess material is then placed into
"valley fills". The court reached its conclusion on the basis that the material
constituted "waste" which may not be disposed of in valley fills under
Corps-issued permits.
13
Following the issuance of the court's May 8, 2002 order, the plaintiff in the
Kentuckians case filed a motion for further injunctive relief, requesting that
the court require the Huntington, West Virginia office of the U.S. Army Corps of
Engineers to revoke the Section 404 valley fill permit identified in the
plaintiff's complaint. In addition, various defendants and intervenors filed
motions seeking a clarification of the court's order, a stay pending appeal, and
a dismissal for failure to join a necessary party. In response to the
defendants' motion for clarification, the court decided that its injunction
applies to any fill activity that does not have a "constructive primary
purpose," citing as an example fills used solely for the disposal of waste. The
court noted that such fills could include not only valley fills, but also other
mining activities such as refuse impoundments, fills from standard contour or
surface mines, slurry impoundments and coal refuse disposal areas or fills
related to mine sites with "approximate original contour" waivers. The court
noted, however, that determining whether a particular fill has a "constructive
primary purpose" is up to the technical expertise of the U.S. Army Corps of
Engineers. The court denied both the defendants' motion for stay pending appeal
and their motion for dismissal. Unless reversed, the ruling may adversely impact
both the Company's ability to sustain its current mining operations and its
ability to open new mines. For further discussion of this case, see Certain
Trends and Uncertainties - Environmental and Regulatory Factors - The Clean
Water Act beginning on page 22.
The Company idled its Dal-Tex operation on July 23, 1999 as a result of an
adverse ruling in prior litigation on the issue of valley fills. This ruling was
later reversed on appeal; however, as of the date of the 2002 injunction
described above, the Company had not yet completed the process necessary to
obtain the Section 404 permits for the mine. Therefore, the Company may not be
able to reopen its Dal-Tex surface mining operation unless the current
injunction is reversed on appeal and it is able to obtain all necessary permits
or its permit application meets the "constructive primary purpose" test. If the
current litigation is favorably resolved and the Company is able to obtain the
necessary permits, it may determine to reopen the mine subject to then-existing
market conditions. In addition, on January 15, 2002, the Corps of Engineers
reissued the Section 404 nationwide permits, including the Nationwide 21 permit
used by coal companies to construct valley fills. In that notice of reissue, the
Corps stated that any activities commenced under the nationwide permit, "will
have until February 11, 2003 to complete the activity." The ruling in the
Kentuckians case may adversely impact the Corps' ability to issue or extend any
Section 404 permit beyond February 11, 2003 to complete the construction of a
valley fill.
Low-Sulfur Coal Producer. The Company continues to believe that it is well
positioned to capitalize on the continuing growth in demand for low-sulfur coal
to produce electricity. Approximately one hundred percent of the Company's
current coal production and approximately 90% of its reserves are low in sulfur.
Approximately 65% of the Company's coal reserves are compliance quality, which
means that they meet Phase II standards of the Clean Air Act without application
of expensive scrubbing technology. With Phase II now in effect, compliance coal
has captured a growing share of United States coal demand and commands a higher
price in the marketplace than high-sulfur coal.
Chief Objectives. The Company continues to focus on taking steps designed to
increase shareholder returns by improving earnings, strengthening cash
generation, improving productivity and reducing costs at its large-scale mines,
while building on its leading position in its target coal-producing basins, the
Powder River Basin and the Central Appalachian Basin.
Natural Resource Partners L.P. The Company announced on April 19, 2002 that it
had created a limited partnership, Natural Resource Partners L.P., with three
private affiliated companies: Western Pocahontas Properties Limited Partnership,
Great Northern Properties Limited Partnership and New Gauley Coal Corporation
(collectively, the "WPP Group"). Natural Resource Partners was formed to engage
principally in the business of owning and managing coal royalty properties in
the three major coal-producing regions of the United States: Appalachia, the
Illinois Basin and the Western United States. The Company completed the sale of
1.9 million common units representing limited partner interests in Natural
Resource Partners in October 2002, which resulted in net proceeds to the Company
of $33.6 million. The proceeds were immediately applied to debt reduction. After
the completion of the sale, the Company holds 34.1% of the limited partner
interests and 42.25% of the general partnership. The Company contributed
approximately 454 million tons of its 3.4 billion tons of total coal reserves to
Natural Resource Partners in exchange for its original ownership interest in the
partnership.
14
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, 2002 and 2001:
2002 2001
---------------- ----------------
(in millions)
Cash provided by (used in):
Operating activities $129.7 $123.7
Investing activities (136.8) (103.3)
Financing activities 9.4 (20.4)
Despite lower net income and an increase in inventories, cash provided by
operating activities increased during the nine months ended September 30, 2002
when compared to the same period in 2001. The increase was primarily
attributable to reduced requirements for working capital components other than
inventories. Cash used in investing activities during the nine months ended
September 30, 2002 increased over the same period in 2001 due to higher capital
expenditures during the first nine months of 2002 as the Company increased
capital expenditures to maintain existing infrastructure and prepared to
increase production for anticipated higher market prices. During January of 2001
and 2002, the Company made the third and fourth, respectively, of five annual
$31.6 million payments under the Thundercloud federal lease, which is part of
the Black Thunder mine in Wyoming. The remaining payment is due in January 2003.
Cash provided by financing activities was $9.4 million during the nine months
ended September 30, 2002 compared to cash used in financing activities of $20.4
million during the nine months ended September 30, 2001. The cash provided by
financing activities during the first nine months of 2002 reflects borrowings on
the Company's revolver and line of credit caused in part by higher capital
expenditures during the first nine months of 2002, while cash used in financing
activities during the first nine months of 2001 reflects the pay-down of $385.4
million of debt primarily from a February 2001 and April 2001 issuance of common
stock which resulted in proceeds of $372.2 million. In addition, during the nine
months ended September 30, 2002, the Company acquired certain assets that were
held under a capital lease arrangement for a payment of $6.5 million. Also
during the first nine months of 2002, the Company entered into a sale and
leaseback of equipment that resulted in proceeds of $9.2 million.
The Company generally satisfies its working capital requirements and funds its
capital expenditures and debt-service obligations with cash generated from
operations. The Company believes that cash generated from operations and its
borrowing capacity will be sufficient to meet its working capital requirements,
anticipated capital expenditures and scheduled debt payments for at least the
next several years. The Company's ability to satisfy debt service obligations,
to fund planned capital expenditures, to make acquisitions and to pay dividends
will depend upon its 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 the Company's control.
Expenditures for property, plant and equipment were $117.4 million for the nine
months ended September 30, 2002, compared to $89.8 million for the nine months
ended September 30, 2001. Capital expenditures are made to rebuild, improve and
replace existing mining equipment, expand and extend the infrastructure at
existing mines, develop new mines and improve the overall efficiency of mining
operations. It is anticipated that future capital expenditures will be funded by
available cash and existing credit facilities.
At September 30, 2002, the Company had $41.8 million in letters of credit
outstanding which, when combined with borrowings under the revolver, resulted in
$205.8 million of unused capacity under the Company's revolving credit facility.
Sufficient unused facility is currently available to fund all operating needs.
Financial covenant requirements may restrict the unused capacity available to
the Company for borrowing and letters of credit.
15
On April 18, 2002, the Company and Arch Western completed a refinancing of their
existing credit facilities. The new credit facilities include five- and six-year
non-amortizing term loans totaling $675.0 million at Arch Western and a
five-year revolving credit facility totaling $350.0 million for the Company. The
five-year non-amortizing term loan at Arch Western is for $150.0 million while
the six-year non-amortizing term loan is for $525.0 million. The rate of
interest on borrowings under both of the credit facilities is a floating rate
based on LIBOR. The Company's credit facility is secured by ownership interests
in substantially all of its subsidiaries, except its ownership interests in Arch
Western and its subsidiaries. The Arch Western credit facility is secured by
substantially all of its subsidiaries, but is not guaranteed by the Company.
Financial covenants contained in the Company's new credit facilities consist of
a maximum leverage ratio, a minimum fixed charge coverage ratio and a minimum
net worth test. The leverage ratio requires that the Company not permit the
ratio of total indebtedness at the end of any calendar quarter to adjusted
EBITDA for the four quarters then ended exceed a specified amount. The fixed
charge coverage ratio requires that the Company not permit the ratio of the
Company's adjusted EBITDA plus lease expense to interest expense plus lease
expense for the four quarters then ended to be less than a specified amount. The
net worth test requires that the Company not permit its net worth to be less
than a specified amount plus 50% of cumulative net income.
The Company periodically establishes uncommitted lines of credit with banks.
These agreements generally provide for short-term borrowings at market rates. At
September 30, 2002, there were $20.0 million of such agreements in effect, all
of which were outstanding. The Company can also issue an additional $455.5
million in public debt and equity securities under a shelf registration
statement.
The Company is exposed to market risk associated with interest rates. At
September 30, 2002, debt included $797.4 million of floating-rate debt, for
which the rate of interest is a rate based on LIBOR and current market rates for
bank lines of credit. To manage this exposure, the Company enters into
interest-rate swap agreements to modify the interest-rate characteristics of
outstanding Company debt. At September 30, 2002, the Company had interest-rate
swap agreements having a total notional value of $525 million, including $250
million for which the fixed rate becomes effective as of October 2003. These
swap agreements are used to convert variable-rate debt to fixed-rate debt. Under
these swap agreements, the Company pays a weighted average fixed rate of 5.74%
(before the credit spread over LIBOR) and receives a weighted average variable
rate based upon 30-day and 90-day LIBOR. The Company accrues amounts to be paid
or received under interest-rate swap agreements over the lives of the agreements
as adjustments to interest expense, thereby adjusting the effective interest
rate on the Company's debt. After taking into consideration interest-rate swap
agreements, debt exposed to variable rates was $522.4 million at September 30,
2002. Gains and losses on terminations of interest-rate swap agreements are
deferred on the Company's balance sheet (in other long-term liabilities) and
amortized as an adjustment to interest expense over the original term of the
terminated swap agreement as if it were still in place. The remaining terms of
the swap agreements at September 30, 2002 ranged from 35 to 60 months. All
instruments are entered into for other than trading purposes.
The Company is also exposed to commodity price risk related to its purchase of
diesel fuel. The Company enters into heating oil swaps to substantially
eliminate volatility in the price of diesel fuel purchased for its operations.
The swap agreements essentially fix the price paid for diesel fuel by requiring
the Company to pay a fixed heating oil price and receive a floating heating oil
price. Gains and losses on terminations of heating oil swap agreements are
deferred on the balance sheet (in other long-term liabilities) and amortized as
an adjustment to diesel fuel cost over the original term of the terminated
heating oil swap agreement as if it were still in place.
The discussion below presents the sensitivity of the market value of the
Company's financial instruments to selected changes in market rates and prices.
The range of changes reflects the Company's 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 the
consolidated financial statements of the Company as of and for the year ended
December 31, 2001 as filed on its Annual Report on Form 10-K with the Securities
and Exchange Commission.
16
Changes in interest rates have different impacts on the fixed-rate and
variable-rate portions of the Company's debt portfolio. A change in interest
rates on the fixed portion of the debt portfolio impacts the net financial
instrument position but has no impact on interest incurred or cash flows. A
change in interest rates on the variable portion of the debt portfolio impacts
the interest incurred and cash flows but does not impact the net financial
instrument position. The sensitivity analysis related to the fixed portion of
the Company's debt portfolio assumes an instantaneous 100-basis-point move in
interest rates from their levels at September 30, 2002, with all other variables
held constant. A 100-basis-point decrease in market interest rates would result
in a $17.6 million increase in the fair value of the fixed portion of the debt
at September 30, 2002. Based on the variable-rate debt included in the Company's
debt portfolio as of September 30, 2002, after considering the effect of the
swap agreements, a 100-basis-point increase in interest rates would result in an
annualized additional $5.2 million of interest expense incurred based on
September 30, 2002 debt levels. Similarly, relative to the Company's diesel
hedge position, at September 30, 2002, a $0.10 per gallon decrease in the price
of heating oil would result in a $0.98 million increase in the fair value of the
financial position of the heating oil swap.
DISCLOSURE CONTROLS AND PROCEDURES
An evaluation was performed under the supervision and with the participation of
the Company's management, including the CEO and CFO, of the effectiveness of the
design and operation of the Company's disclosure controls and procedures as of
September 30, 2002. Based on that evaluation, the Company's management,
including the CEO and CFO, concluded that the Company's disclosure controls and
procedures were effective as of such date. There have been no significant
changes in the Company's internal controls or in other factors that could
significantly affect internal controls subsequent to September 30, 2002.
CONTINGENCIES
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. The Company accrues for
the costs of final mine closure reclamation over the estimated useful mining
life of the property. These costs relate to reclaiming the pit and support
acreage at surface mines and sealing portals at deep mines. Other costs of final
mine closure 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 Company also accrues for significant reclamation that is
completed during the mining process prior to final mine closure. The
establishment of the final mine closure reclamation liability and the other
ongoing reclamation liabilities are based upon permit requirements and require
various estimates and assumptions, principally associated with costs and
productivities.
The Company reviews its entire environmental liability periodically and makes
necessary adjustments, including permit changes and revisions to costs and
productivities to reflect current experience. The Company's management believes
it is making adequate provisions for all expected reclamation and other
associated costs.
Legal Contingencies.
The Company is a party to numerous claims and lawsuits with respect to various
matters, including those discussed below. The Company provides 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
the consolidated financial condition, results of operations or liquidity of the
Company.
CERTAIN TRENDS AND UNCERTAINTIES
Substantial Leverage - Variable Interest Rate - Covenants.
As of September 30, 2002, the Company had outstanding consolidated indebtedness
of $798.8 million, representing approximately 59% of the Company's capital
employed. Despite making substantial progress in reducing debt, the Company
continues to have significant debt-service obligations, and the terms of its
17
credit agreements limit its flexibility and result in a number of limitations on
the Company. The Company also has significant lease and royalty obligations. The
Company's ability to satisfy debt service, lease and royalty obligations and to
effect any refinancing of its indebtedness will depend upon future operating
performance, which will be affected by prevailing economic conditions in the
markets that the Company serves as well as financial, business and other
factors, many of which are beyond the Company's control. The Company 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 it to
fund its debt service, lease and royalty payment obligations or its other
liquidity needs.
The Company's relative amount of debt and the terms of its credit agreements
could have material consequences to its 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 the Company has in the past; (iii) increasing the Company's
vulnerability to general adverse economic and industry conditions; (iv) limiting
the Company's ability to obtain 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 the Company's flexibility in planning for, or
reacting to, changes in the Company's business and the industry in which the
Company competes; or (vii) placing the Company at a competitive disadvantage
when compared to competitors with less relative amounts of debt.
After taking into consideration the Company's interest-rate swaps which convert
the Company's variable rate debt to fixed, approximately 65% of the Company's
indebtedness bears interest at variable rates that are linked to short-term
interest rates. If interest rates rise, the Company's costs relative to those
obligations would also rise.
Terms of the Company's credit facilities and leases contain financial and other
covenants that create limitations on the Company's ability to, among other
things, effect acquisitions or dispositions and borrow additional funds, and
require the Company to, among other things, maintain various financial ratios
and comply with various other financial covenants. Failure by the Company to
comply with such covenants could result in an event of default under these
agreements which, if not cured or waived, would enable the Company's lenders to
declare amounts borrowed due and payable, or otherwise result in unanticipated
costs.
Losses.
The Company reported a net loss of $3.6 million for the nine months ended
September 30, 2002. The losses in the first nine months of 2002 were primarily
due to the Company's decision to scale back production during the first nine
months of the year in response to a weak market environment and increased costs
at certain of the Company's operations. The decision to scale back production
came after the Company had prepared most of the operations to maximize
production in order to capitalize on higher market prices for coal the Company
had previously projected for 2002. Therefore, certain costs incurred to maximize
production did not result in higher revenues but did increase cost of coal
sales.
Because the coal mining industry is subject to significant regulatory oversight
and due to the possibility of continued adverse pricing trends or other industry
trends beyond the Company's control, the Company may suffer losses in the future
if legal and regulatory rulings, mine idlings and closures, adverse pricing
trends or other factors affect the Company's ability to mine and sell coal
profitably.
18
Environmental and Regulatory Factors.
The coal mining industry is subject to regulation by federal, state and local
authorities on matters such as:
o the discharge of materials into the environment;
o employee health and safety;
o mine permits and other licensing requirements;
o reclamation and restoration of mining properties after mining is
completed;
o management of materials generated by mining operations;
o surface subsidence from underground mining;
o water pollution;
o legislatively mandated benefits for current and retired coal miners;
o air quality standards;
o protection of wetlands;
o endangered plant and wildlife protection;
o limitations on land use;
o storage of petroleum products and substances that are regarded as hazardous
under applicable laws; and
o 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 the
Company's 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 the Company's mining operations
or its customers' ability to use coal and may require the Company or its
customers to change operations significantly or incur substantial costs.
While it is not possible to quantify the expenditures incurred by the Company to
maintain compliance with all applicable federal and state laws, those costs have
been and are expected to continue to be significant. The Company posts
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 the Company's 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,
including standards for sulfur dioxide, particulate matter, nitrogen oxides and
ozone. 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. Significant additional emissions control expenditures
will be needed in order to meet the current national ambient air standard for
ozone. In particular, coal-fired power plants will be affected by state
regulations designed to achieve attainment of the ambient air quality 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.
In July 1997, the EPA adopted more stringent ambient air quality standards for
particulate matter and ozone. In a February 2001 decision, the U.S. Supreme
Court largely upheld the EPA's position, although it remanded the EPA's ozone
implementation policy for further consideration. On remand, the Court of Appeals
for the D.C. Circuit affirmed the EPA's adoption of these more stringent ambient
19
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. Revised State Implementation Plans could
require electric power generators to further reduce nitrogen oxide and
particulate matter emissions. 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 the development of new
mines by the Company. This in turn may result in decreased production by the
Company and a corresponding decrease in the Company's 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.
Furthermore, in October 1998, the EPA finalized a rule that will require 19
states in the Eastern United States that have ambient air quality problems to
make substantial reductions in nitrogen oxide emissions by the year 2004. To
achieve these reductions, many power plants would be required to install
additional control measures. The installation of these measures would make it
more costly to operate coal-fired power plants and, depending on the
requirements of individual state implementation plans, could make coal a less
attractive fuel.
Along with these regulations addressing ambient air quality, the EPA has
initiated a regional haze program designed to protect and to improve visibility
at and around National Parks, National Wilderness Areas and International Parks.
This program restricts the construction of new coal-fired power plants whose
operation may impair visibility at and around federally protected areas.
Moreover, this program may require certain existing coal-fired power plants to
install additional control measures designed to 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,
the EPA's regional haze program could affect the future market for coal.
Additionally, the U.S. Department of Justice, on behalf of the EPA, has filed
lawsuits against several investor-owned electric utilities and brought an
administrative action against one government-owned electric utility 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. The Company supplies coal to some of the
currently affected utilities, and it is possible that other of the Company's
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.
Other Clean Air Act programs are also applicable to power plants that use the
Company's 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:
o burning lower sulfur coal, either exclusively or mixed with higher
sulfur coal;
o installing pollution control devices such as scrubbers, which reduce the
emissions from high sulfur coal;
o reducing electricity generating
levels; or
o purchasing or trading emission credits.
Specific emissions sources receive these credits that 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.
In addition to emissions control requirements designed to control acid rain and
to attain the national ambient air quality standards, the Clean Air Act also
imposes standards on sources of hazardous air pollutants. Although these
standards have not yet been extended to coal mining operations, the EPA recently
announced that it will regulate hazardous air pollutants from coal-fired power
plants. Under the Clean Air Act, coal-fired power plants will be required to
control hazardous air pollution emissions by no later than 2009. These controls
are likely to require significant new improvements in controls by power plant
owners. The most prominently targeted pollutant is mercury, although other
by-products of coal combustion may be covered by future hazardous air pollutant
standards for coal combustion sources.
20
Other proposed initiatives may have an effect upon coal operations. One such
proposal is the Bush Administration's recently announced Clear Skies Initiative.
As proposed, this initiative is designed to reduce emissions of sulfur dioxide,
nitrogen oxides, and mercury from power plants. Other so-called multi-pollutant
bills, which could regulate additional air pollutants, have been proposed by
various members of Congress. While the details of all of these proposed
initiatives vary, there appears to be a movement towards increased regulation of
a number of air pollutants. Were such initiatives enacted into law, power plants
could choose to shift away from coal as a fuel source to meet these
requirements.
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, the
Company is contractually obligated under the terms of its 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 the Company to submit a bond or otherwise financially secure
the performance of its 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.
The Company also leases some of its 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. The Company is not aware of
any currently pending or asserted claims against it asserting that it "owns" or
"controls" any of its lessees' operations.
On March 29, 2002, the U.S. District Court for the District of Columbia issued a
ruling that could restrict underground mining activities conducted in the
vicinity of public roads, within a variety of federally protected lands, within
national forests and within a certain proximity of occupied dwellings. The
lawsuit, Citizens Coal Council v. Norton, was filed in February 2000 to
challenge regulations issued by the Department of Interior providing, among
other things, that subsidence and underground activities that may lead to
subsidence are not surface mining activities within the meaning of SMCRA. SMCRA
generally contains restrictions and certain prohibitions on the locations where
surface mining activities can be conducted. The District Court entered summary
judgment upon the plaintiff's claims that the Secretary of the Interior's
determination violated SMCRA. By order dated April 9, 2002, the court remanded
the regulations to the Secretary of the Interior for reconsideration.
The significance of this decision for the coal mining industry remains unclear
because this ruling is subject to appellate review. The Department of Interior
and the National Mining Association, a trade group that intervened in this
action, sought a stay of the order pending appeal to the U.S. Court of Appeals
for the District of Columbia Circuit and the stay was granted. If the District
21
Court's decision is not overturned, or if some legislative solution is not
enacted, this ruling could have a material adverse effect on all coal mine
operations that utilize underground mining techniques, including those of the
Company. While it still may be possible to obtain permits for underground mining
operations in these areas, the time and expense of that permitting process are
likely to increase significantly.
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 or pursuant to
statutory or regulatory changes under the Clean Air Act. Efforts to control
greenhouse gas emissions could result in reduced demand for coal if electric
power generators switch to lower carbon sources of fuel.
Clean Water Act. Section 301 of the Clean Water Act prohibits the discharge of a
pollutant from a point source into navigable waters except in accordance with a
permit issued under either Section 402 or Section 404 of the Clean Water Act.
Navigable waters are broadly defined to include streams, even those that are not
navigable in fact, and may include wetlands.
All mining operations in Appalachia generate excess material, which must be
placed in fills in adjacent valleys and hollows. Likewise, coal refuse disposal
areas and coal processing slurry impoundments are located in valleys and
hollows. Almost all of these areas contain intermittent or perennial streams,
which are considered navigable waters. An operator must secure a Clean Water Act
permit before filling such streams. For approximately the past twenty-five
years, operators have secured Section 404 fill permits to authorize the filling
of navigable waters with material from various forms of coal mining. Operators
have also obtained permits under Section 404 for the construction of slurry
impoundments although the use of these impoundments, including discharges from
them requires permits under Section 402. Section 402 discharge permits are
generally not suitable for authorizing the construction of fills in navigable
waters.
On May 8, 2002, the United States District Court for the Southern District of
West Virginia issued an order in Kentuckians for the Commonwealth v. Rivenburgh
enjoining the Huntington, West Virginia office of the U.S. Army Corps of
Engineers from issuing permits under Section 404 of the Clean Water Act for the
construction of valley fills for the disposal of overburden from mountaintop
mining operations solely for the purpose of waste disposal. These valleys
typically contain streams that, under the Clean Water Act, are considered
navigable waters of the United States. The court held that the filling of these
waters solely for waste disposal is a violation of the Clean Water Act. The
effect of this injunction, if it is not overturned by an appellate court or
subsequent legislation, will be to make mountaintop mining uneconomical in those
areas subject to the injunction.
The court's injunction also prohibits the issuance of permits authorizing fill
activities associated with types of mining activities other than mountaintop
mining where the primary purpose or use of those fill activities is the disposal
of waste. Such activities might include those associated with slurry
impoundments and coal refuse disposal areas. If the injunction is not overturned
by an appellate court or subsequent legislation, the Company may not be able to
obtain permits in many cases to use these common fill activities, which could
render these operations uneconomical.
Following the issuance of the court's May 8, 2002 order, the plaintiff in the
Kentuckians case filed a motion for further injunctive relief requesting that
the court require the Huntington, West Virginia office of the U.S. Army Corps of
Engineers to revoke the Section 404 valley fill permit identified in the
plaintiff's complaint. In addition, various defendants and intervenors filed
motions seeking a clarification of the court's order, a stay pending appeal, and
a dismissal for failure to join a necessary party.
On June 17, 2002, the court ruled on all of the parties' motions. In response to
the defendants' motion for clarification, the court decided that its injunction
applies to any fill activity that does not have a "constructive primary
purpose", citing as an example fills used solely for the disposal of waste. The
court noted that such fills could include not only valley fills, but also other
mining activities such as refuse impoundments, fills from standard contour or
22
surface mines, or fills related to mine sites with "approximate original
contour" waivers. The court noted, however, that determining whether a
particular fill has a "constructive primary purpose" is up to the technical
expertise of the U.S. Army Corps of Engineers. It also appears that the court
would allow the U.S. Army Corps of Engineers to take into consideration
post-mining land uses when applying the "constructive primary purpose" test to a
particular fill activity. This ruling creates additional uncertainty about how
the U.S. Army Corps of Engineers is to apply the "constructive primary purpose"
test.
Following its discussion of the motion for clarification, the court addressed
and denied both the defendants' motion for stay pending appeal and their motion
for dismissal. Along with its denials of the defendants' various motions, the
court denied the plaintiff's motion for further injunctive relief. Accordingly,
the court did not require the U.S. Army Corps of Engineers to revoke the
challenged Section 404 permit. The court based its decision on the grounds that
it did not have sufficient factual information to determine whether the
particular fill at issue had a "constructive primary purpose".
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 EPA's approval of West Virginia's
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. The
plaintiffs in this lawsuit, Ohio Valley Environmental Coalition v. Whitman,
challenge provisions in West Virginia's antidegradation implementation policy
that exempt current holders of National Pollutant Discharge Elimination System
(NPDES) permits and Section 404 permits, among other parties, from the
antidegradation-review process. The Company is exempt from antidegradation
review under these provisions. Revoking this exemption and subjecting the
Company to the antidegradation review process could delay the issuance or
reissuance of Clean Water Act permits to the Company or cause these permits to
be denied. If the plaintiffs are successful and if the Company discharges into
waters that have been designated as high-quality by the state, the costs, time
and difficulty associated with obtaining and complying with Clean Water Act
permits for surface mining of its operations could increase.
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 the Company currently owns or has previously owned or operated, and
sites to which the Company sent waste materials, may be subject to liability
under CERCLA and similar state laws. In particular, the Company may be liable
under CERCLA or similar state laws for the cleanup of hazardous substance
contamination at sites where it owns surface rights.
Mining Permits and Approvals. Numerous governmental permits or approvals are
required for mining operations. In connection with obtaining these permits and
approvals, the Company 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.
In order to obtain mining permits and approvals from state regulatory
authorities, mine operators, including the Company, 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
the Company submits the necessary permit applications several months before it
23
plans to begin mining a new area. In the Company's experience, permits generally
are approved several months after a completed application is submitted. In the
past, the Company has generally obtained its mining permits without significant
delay. However, the Company cannot be sure that it 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 the Company, 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. The Company
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, in severe circumstances, criminal sanctions may be
imposed for failure to comply with these laws.
Surety Bonds. Federal and state laws require the Company to obtain surety bonds
to secure payment of certain long-term obligations including mine closure or
reclamation costs, federal and state workers' compensation costs, coal leases
and other miscellaneous obligations. Many of these bonds are renewable on a
yearly basis. It has become increasingly difficult for the Company to secure new
surety bonds or renew such bonds without the posting of collateral. In addition,
surety bond costs have increased while the market terms of such bonds have
generally become more unfavorable.
West Virginia Cumulative Hydrologic Impact Analysis Litigation. Two
environmental groups sued the West Virginia Department of Environmental
Protection in January 2000 in federal court, alleging various violations of the
Clean Water Act and SMCRA. The lawsuit was amended in September 2001 to name
Gale Norton, Secretary of the Interior, as a defendant. The U.S. Office of
Surface Mining is a division within the Department of Interior. The lawsuit,
Ohio River Valley Environmental Coalition, Inc. v. Castle, specifically alleges
that the West Virginia Department of Environmental Protection has violated its
non-discretionary duty to require all surface and underground mining permit
applications to include certain stream flow and water quality data and an
analysis of the probable hydrologic consequences of the proposed mine, and that
the West Virginia Department of Environmental Protection failed to conduct
SMCRA-required cumulative hydrologic impacts analysis prior to issuing mining
permits. The lawsuit also alleges that the Office of Surface Mining has a
non-discretionary duty to apply the federal SMCRA law in West Virginia due to
the deficiencies in the state program. In March 2001, the district court denied
the plaintiff's motion for a preliminary injunction on its claims against the
West Virginia Department of Environmental Protection. In September 2001, the
district court denied a motion to dismiss for lack of jurisdiction filed by
defendant Michael Callaghan, Secretary of the West Virginia Department of
Environmental Protection. Callaghan filed an interlocutory appeal of this
decision in October 2001. The Fourth Circuit Court of Appeals is awaiting
briefing under an extended schedule in this case. If the plaintiffs are
eventually successful in this lawsuit, the West Virginia Department of
Environmental Protection will have to modify its procedures and requirements for
the content and review of mining permit applications, or the federal government
will be ordered to assume control over mining permits in West Virginia. Any of
these changes are likely to increase the cost of preparing applications and the
time required for their review, and may entail additional operating expenditures
and, possibly, restrictions on operating.
West Virginia SMCRA Bond Lawsuit. In November 2000, the West Virginia Highlands
Conservancy filed a lawsuit in federal district court against the U.S.
Department of Interior, the U.S. Office of Surface Mining and the West Virginia
Department of Environmental Protection. The lawsuit, West Virginia Highlands
Conservancy v. Norton, which seeks declaratory and injunctive relief, generally
challenges the adequacy of the two-tier West Virginia alternative bond
reclamation program. The first tier requires mine operators to post a bond of up
to $5,000 per acre mined. The second tier creates a special reclamation fund
which is funded by an assessment on mine operators of three cents per ton of
coal mined. The West Virginia Highlands Conservancy claims that, individually
and collectively, the alternative bond reclamation program has inadequate funds
to cover the state's cost of conducting mining site reclamation for those sites
where the mine operator has defaulted, or might default, on its reclamation
obligations. Based upon the alleged inadequacy of the alternative bonding
program, the lawsuit claims that the Department of the Interior and the Office
of Surface Mining violated their obligations under SMCRA by either (1) not
24
asserting federal control over the West Virginia SMCRA bonding program or (2)
not revoking federal approval of the West Virginia SMCRA program and assuming
control under SMCRA. The lawsuit also alleges that the West Virginia Department
of Environmental Protection (1) failed to ensure that the state bonding program
met certain minimum requirements and (2) improperly issued SMCRA permits without
requiring mine operators to post sufficient reclamation bonds.
In May 2001, the district court dismissed all claims against the West Virginia
Department of Environmental Protection based upon the principle of sovereign
immunity. The Office of Surface Mining, in June 2001, initiated formal
administrative action against the West Virginia Department of Environmental
Protection regarding the alleged deficiencies in the state bonding program.
The remaining claims in this lawsuit against the federal defendants were the
subject of an August 2001 order by the district court. The court denied the
federal defendants' motion to dismiss the suit and granted partial summary
judgment for the plaintiffs. The court allowed the Office of Surface Mining to
continue its administrative action. That action required the West Virginia
Department of Environmental Protection to submit proposed new regulatory
initiatives to the state legislature's rulemaking committee and, within 45 days
of the close of the 2002 legislative session, the state was required to provide
final, enacted legislation, signed by the Governor of West Virginia, that
addressed all problems with the current state bonding system. The West Virginia
Legislature passed, and the Governor of West Virginia signed, an amended
alternative bond program, called the 7-Up Plan, and the U.S. Office of Surface
Mining approved those amendments.
The plaintiffs filed a motion in January 2002 asking the court to compel the
Office of Surface Mining to perform its non-discretionary duties and find that
the new alternative bonding program promulgated by West Virginia still fails to
meet the requirements of the federal SMCRA. In March 2002, the court denied the
plaintiffs' motion, based in part upon representations by the Office of Surface
Mining that it would make a final determination regarding the adequacy of the
7-Up Plan by no later than May 28, 2002.
On May 29, 2002, the Office of Surface Mining issued a final rule that approved
amendments to the West Virginia alternative bonding scheme adopted by the West
Virginia Department of Environmental Protection and enacted by the state
legislature. These amendments require, among other things, eliminating the
current deficit and restoring the Special Reclamation Fund to solvency, removing
spending limitations on the expenditure of funds for water treatment, creating a
special advisory council to advise on structural reforms to the bonding program
to avoid deficits in the future and annual reporting to the state legislature on
the adequacy of the funds in the alternative bonding scheme.
The current deficit will be eliminated through special reclamation taxes on
clean coal production totaling fourteen cents per ton, of which seven cents is
an additional temporary tax that will terminate in 39 months. The Office of
Surface Mining has projected that these taxes will eliminate the deficit. These
taxes and whatever other requirements may be adopted in the future by the
advisory council will likely result in increases in the funds that mine
operators are required to post in order to obtain permits and could result in
further additional costs or fees related to the operation of a coal mine or the
sale of coal. Any changes to the state reclamation bonding program could also
complicate and protract the process of applying for and obtaining necessary
permits.
On June 25, 2002, the West Virginia Highlands Conservancy filed an amended
complaint challenging the Office of Surface Mining's approval of the amendments
to the West Virginia alternative bonding program.
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 the Company
from obtaining mining permits and may include restrictions on timber harvesting,
road building and other mining or silvicultural activities in areas containing
the affected species. A number of species indigenous to the Company's 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, the Company does not believe there are any species
protected under the Endangered Species Act that would materially and adversely
affect its ability to mine coal from its properties in accordance with current
mining plans.
25
Other Environmental Laws Affecting the Company. The Company is 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. The Company believes that it is in substantial compliance
with all applicable environmental laws.
Competition-Excess Industry Capacity.
The coal industry is intensely competitive, primarily as a result of the
existence of numerous producers in the coal-producing regions in which the
Company operates, and a number of the Company's competitors have greater
financial resources. The Company competes with several major coal producers in
the central Appalachian and Powder River Basin areas. The Company also competes
with a number of smaller producers in those and other market regions. The
Company is also subject to the risk of reduced profitability as a result of
excess industry capacity, which results in reduced coal prices.
Electric Industry Factors;Customer Creditworthiness.
Demand for coal and the prices that the Company will be able to obtain for its
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 the Company's control, including the demand for electricity
(which is dependent to a significant extent on summer and winter temperatures);
government regulation; technological developments and the location,
availability, quality and price of competing sources of coal; alternative fuels
such as natural gas, oil and nuclear; and alternative energy sources such as
hydroelectric power. Demand for the Company's low-sulfur coal and the prices
that the Company 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 the Company's coal by the domestic electric
generation industry may cause a decline in profitability.
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 a negative effect on the Company's profitability to the
extent it causes the Company's customers to be more cost-sensitive.
In addition, the Company's ability to receive payment for coal sold and
delivered depends on the creditworthiness of its utility customers and trading
partners. In general, the creditworthiness of the Company's customers,
especially its coal trading counterparties, has deteriorated. If such trends
continue, the Company's acceptable customer base may be limited.
Reliance On And Terms Of Long-Term Coal Supply Contracts.
During 2001, sales of coal under long-term contracts, which are contracts with a
term greater than 12 months, accounted for 77% of the Company's 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. As a consequence of the
substantial volume of its sales which are subject to these long-term agreements,
the Company has less coal available with which to capitalize on stronger coal
prices if and when they arise. In addition, because long-term contracts
typically allow the customer to elect volume flexibility, the Company's ability
to realize the higher prices that may be available in the spot market may be
restricted when customers elect to purchase higher volumes under such contracts,
or the Company's exposure to market-based pricing may be increased should
customers elect to purchase fewer tons. The increasingly short terms of sales
contracts and the consequent absence of price adjustment provisions in such
contracts also make it more likely that inflation related increases in mining
costs during the contract term will not be recovered by the Company.
26
Reserve Degradation And Depletion.
The Company's profitability depends substantially on its 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
characteristic of the depleting mines. The Company has in the past acquired and
will in the future acquire, coal reserves for its mine portfolio from third
parties. The Company may not be able to accurately assess the geological
characteristics of any reserves that it acquires, which may adversely affect the
profitability and financial condition of the Company. 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 Logan's Mountaineer Mine is estimated to exhaust its longwall
mineable reserves in 2006. The Mountaineer Mine generated $29.9 million and
$28.8 million of the Company's total operating income in the first nine months
of 2002 and 2001, respectively.
Potential Fluctuations In Operating Results-Factors Routinely Affecting Results
Of Operations.
The Company's 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 prices, 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 the Company's principal mines, particularly
its Mingo Logan operation in West Virginia or Black Thunder mine in Wyoming,
would result in a decrease, which could be material, in the Company's revenues
and profitability. Other factors affecting the production and sale of the
Company's coal that could result in decreases in its profitability include: (i)
expiration or termination of, or sales price redeterminations or suspension of
deliveries under, coal supply agreements; (ii) disruption or increases in the
cost of transportation services; (iii) changes in laws or regulations, including
permitting requirements; (iv) litigation; (v) the timing and amount of insurance
recoveries; (vi) work stoppages or other labor difficulties; (vii) mine worker
vacation schedules and related maintenance activities; and (viii) 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 of these
transportation services could temporarily impair the Company's ability to supply
coal to its customers. Increases in transportation costs, or changes in such
costs relative to transportation costs for coal produced by its competitors or
of other fuels, could have an adverse effect on the Company's business and
results of operations.
Reserves - Title.
There are numerous uncertainties inherent in estimating quantities of
recoverable reserves, including many factors beyond the control of the Company.
Estimates of economically recoverable coal reserves and net cash flows
necessarily depend upon the 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 the
Company's reserves may vary from estimates, and such variances may be material.
These estimates thus may not accurately reflect the Company's actual reserves.
A significant part of the Company's mining operations are conducted on
properties leased by the Company. The loss of any lease could adversely affect
the Company's ability to develop the associated reserves. Because title to most
of the Company's leased properties and mineral rights is not usually verified
until a commitment is made by the Company to develop a property, which may not
27
occur until after the Company has obtained necessary permits and completed
exploration of the property, the Company's right to mine certain of its 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, the Company has had to, and may in the future have to,
incur unanticipated costs. In addition, the Company may not be able to
successfully negotiate new leases or mining contracts for properties containing
additional reserves or maintain its leasehold interests in properties on which
mining operations are not commenced during the term of the lease.
Certain Contractual Arrangements.
The Company's affiliate, Arch Western Resources, LLC, is the owner of Company
reserves and mining facilities in the western United States. The agreement under
which Arch Western was formed provides that a subsidiary of the Company, 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
Amoco, 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 Western has a debt rating less favorable than specified ratings with
Moody's Investors Service or Standard & Poor's or fails to meet specified
indebtedness and interest ratios.
In connection with the Company's June 1, 1998 acquisition of Atlantic Richfield
Company's ("ARCO") coal operations, the Company entered into an agreement under
which it 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. Depending on the time at which
any such indemnification obligation were to arise, it could impact the Company's
profitability for the period in which it arises.
The membership interests in Canyon Fuel, which operates three coal mines in
Utah, are owned 65% by Arch Western and 35% by a subsidiary of ITOCHU
Corporation of Japan. The agreement which governs the management and operations
of Canyon Fuel provides for a management board to manage its business and
affairs. Some major business decisions concerning Canyon Fuel require the vote
of 70% of the membership interests and therefore limit the Company's ability to
make these decisions. These decisions include admission of additional members;
approval of annual business plans; the making of significant capital
expenditures; sales of coal below specified prices; agreements between Canyon
Fuel and any member; the institution or settlement of litigation; a material
change in the nature of Canyon Fuel's business or a material acquisition; the
sale or other disposition, including by merger, of assets other than in the
ordinary course of business; incurrence of indebtedness; entering into leases;
and the selection and removal of officers. The Canyon Fuel agreement also
contains various restrictions on the transfer of membership interests in Canyon
Fuel.
The Company's 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 the Company. The Company's
Bylaws require the affirmative vote of at least two-thirds of the members of the
Board of Directors of the Company in order to declare dividends and to authorize
certain other actions.
28
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by this Item is contained under the caption
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" in this report and is incorporated herein by reference.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
The information required by this Item is contained in the "Contingencies - Legal
Contingencies" section of "Management's Discussion and Analysis of Financial
Condition and Results of Operations" in this report and is incorporated herein
by reference.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a)
3.1 Amended and Restated Certificate of Incorporation of Arch Coal, Inc.
(incorporated herein by reference to Exhibit 3.1 to the Company's Quarterly
Report on Form 10-Q for the Quarter Ended March 31, 2000)
3.2 Amended and Restated Bylaws of Arch Coal, Inc. (incorporated herein by
reference to Exhibit 3.2 to the Company's Annual Report on Form 10-K for
the Year Ended December 31, 2000)
4.1 Form of Rights Agreement, dated March 3, 2000 (incorporated herein by
reference to Exhibit 1 to a Current Report on Form 8-A filed on March 9,
2000)
99.1 Statement Under Oath of Principal Executive Officer Regarding Facts and
Circumstances Relating to Exchange Act Filings executed by Steven F. Leer
99.3 Statement Under Oath of Principal Financial Officer Regarding Facts and
Circumstances Relating to Exchange Act Filings executed by Robert J. Messey
(b) Reports on Form 8-K
Reports on Form 8-K: A report on Form 8-K dated July 18, 2002 announcing
the Company's second quarter earnings was filed by the Company in the
quarter ended September 30, 2002.
29
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.
ARCH COAL, INC.
---------------
(Registrant)
/s/ John W. Lorson
------------------
Date: November 12, 2002 John W. Lorson
Controller
(Chief Accounting Officer)
CERTIFICATIONS
I, Steven F. Leer, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Arch Coal, Inc;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors:
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
30
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
quarterly report whether there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: November 12, 2002
/s/ Steven F. Leer
---------------------------
Steven F. Leer
President and Chief Executive Officer
I, Robert J. Messey, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Arch Coal, Inc.;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a. designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
b. evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this quarterly report (the "Evaluation Date"); and
c. presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors:
a. all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
31
b. any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
quarterly report whether there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: November 12, 2002
/s/ Robert J. Messey
---------------------------
Robert J. Messey
Senior Vice President and
Chief Financial Officer
32