Edgar Filing: ARCH COAL INC

Filed Pursuant to Rule 424(b)(1)
Registration No. 333-45198
PROSPECTUS
8,700,000 Shares

Arch Coal, Inc.

Common Stock
---------------

We are selling 3,943,032 shares and an Arch Coal, Inc. stockholder is
selling 4,756,968 shares. We are registering the selling stockholder's shares
on its behalf.

Our common stock trades on the New York Stock Exchange under the symbol
"ACI". On February 15, 2001, the last sale price of the shares as reported on
the New York Stock Exchange was $19.26 per share.

Investing in our common stock involves risks that are described in the
"Risk Factors" section beginning on page 6 of this prospectus.
---------------

Per Share Total
--------- -----

Public offering price............................. $19.00 $165,300,000
Underwriting discount............................. $.97 $8,439,000
Proceeds, before expenses, to Arch Coal........... $18.03 $71,092,867
Proceeds, before expenses, to the selling
stockholder...................................... $18.03 $85,768,133

The underwriter may also purchase up to an additional 1,227,765 shares
from us at the public offering price, less the underwriting discount, within 30
days from the date of this prospectus to cover over-allotments.

Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities or determined if
this prospectus is truthful or complete. Any representation to the contrary is
a criminal offense.

The shares will be ready for delivery on or about February 22, 2001.
---------------

Merrill Lynch & Co.
---------------

The date of this prospectus is February 15, 2001.

TABLE OF CONTENTS

Page
----

Prospectus Summary....................................................... 1
Risk Factors............................................................. 6
Forward-Looking Statements............................................... 13
Use of Proceeds.......................................................... 14
Price Range of Common Stock and Dividends................................ 14
Capitalization........................................................... 15
Selected Consolidated Financial and Operating Data....................... 16
Management's Discussion and Analysis of Financial Condition and Results
of Operations........................................................... 18
Business................................................................. 30
The Coal Industry........................................................ 39
Management............................................................... 46
Selling Stockholder...................................................... 49
Description of Capital Stock............................................. 50
United States Taxation of Non-U.S. Holders............................... 52
Underwriting............................................................. 56
Legal Matters............................................................ 59
Experts.................................................................. 59
Where You Can Find More Information...................................... 59
Glossary of Selected Mining Terms........................................ 61

---------------

You should rely only on the information contained or incorporated by
reference in this prospectus and in the registration statement filed in
connection with this offering and the exhibits to that registration statement.
We have not, and the selling stockholder and the underwriter have not,
authorized any other person to provide you with different information. We are
not, and the selling stockholder and the underwriter are not, making an offer
to sell these securities in any jurisdiction where the offer or sale is not
permitted.

PROSPECTUS SUMMARY

This summary may not contain all the information that may be important to
you. You should read the entire prospectus, including the information set forth
in "Risk Factors," and all the information incorporated by reference, before
making an investment decision. Some of the terms used in this prospectus
relating to the coal industry are defined in a glossary beginning on page 61 of
this prospectus.

Arch Coal

We are one of the largest coal producers in the United States. We mine,
process and market compliance and low-sulfur coal from mines located in both
the eastern and western United States, enabling us to ship coal cost-
effectively to most of the major domestic coal-fired electric generation
facilities. Compliance coal and low-sulfur coal are coals which, when burned,
emit 1.2 pounds or less and 1.6 pounds or less of sulfur dioxide per million
Btus, respectively. Compliance coal requires no mixing with other coals or use
of sulfur dioxide reduction technologies by generators of electricity to comply
with the requirements of the federal Clean Air Act. As of December 31, 1999, we
controlled approximately 3.5 billion tons of measured and indicated recoverable
coal reserves, approximately 2.0 billion tons of which were assigned reserves
and approximately 1.5 billion tons of which were unassigned reserves. Assigned
reserves are recoverable coal reserves that have been designated to be mined by
a specific operation. As of September 30, 2000, we had 28 operating mines. We
sold 111.2 million tons of coal in 1999 and 79.4 million tons of coal during
the nine months ended September 30, 2000. We sell substantially all of our coal
to producers of electric power.

We have a substantial amount of debt relative to our equity
capitalization. Our mining operations and coal reserves are inherently subject
to changing conditions that can result in fluctuations in our profitability. We
sell a significant amount of coal under long-term contracts, which are
contracts with a term of greater than 12 months, at above current market
prices, the expiration or renegotiation of which could adversely affect our
profitability. While coal prices have recently strengthened in all regions, our
recent results of operations reflected less favorable coal prices because
nearly all of our production was previously committed and priced under earlier
weak market conditions. Environmental and regulatory developments have forced
us to close a large surface mine in West Virginia. In 1999, we wrote down the
value of a portion of our assets in the eastern United States, restructured our
operations, and recorded several substantial charges. We believe, however, that
we are well-positioned to take advantage of several trends that are positively
affecting the coal industry:

. Demand for electricity continues to grow, and coal-fired electric
generation facilities currently provide more than 50% of the electric
power produced in the United States.

. Coal continues to be the least expensive fuel commonly used in the
generation of electricity. Utility deregulation trends are expected to
result in increased price competition among generators of electricity,
for which the importance of production costs should increase
correspondingly.

. Coal-fired electric generation plants operated at an average of 68% of
their capacity in 1999. These plants are capable of meeting the demand
for more electricity at a low incremental cost.

. The federal Clean Air Act, which provides for phased-in restrictions
on the amount of sulfur dioxide that electric generation and other
facilities can emit, has caused demand for low-sulfur coal to increase
in recent years. Approximately 90% of our reserve base consists of
low-sulfur coal, and two-thirds is compliance quality. We currently
produce only compliance and low-sulfur coals.

. Demand for coal from the Southern Powder River Basin in Wyoming, which
is low in sulfur content and relatively inexpensive to mine, has
approximately doubled over the last decade. We control approximately
1.4 billion tons of recoverable coal reserves in the Powder River
Basin. Our Black Thunder mine is one of the largest coal mines in the
nation, producing at a rate of approximately 60 million tons annually.

We continue to focus on realizing the potential of our assets and
maximizing stockholder value by making decisions based upon our five chief
financial objectives:

. aggressively paying down our debt,

. further strengthening our cash generation,

. improving our earnings,

. increasing our productivity, and

. reducing our costs.

Our principal executive office is located at CityPlace One, Suite 300,
St. Louis, Missouri 63141, and our telephone number is (314) 994-2700.

The Offering

Common stock offered:
By Arch Coal................................... 3,943,032
By Ashland Inc., the sole selling stockholder.. 4,756,968
----------
Total...................................... 8,700,000
Shares outstanding after the offering............. 42,116,219 shares
----------
Use of Proceeds................................... We estimate that our net proceeds from this
offering without exercise of the over-allotment
option will be approximately $70.7 million. We
intend to use the net proceeds of this offering
to reduce our indebtedness. We will not receive
any of the proceeds from the sale of shares by
the selling stockholder.
New York Stock Exchange Symbol.................... ACI

Unless otherwise indicated, the information in this prospectus assumes no
exercise by the underwriter of its over-allotment option.

The number of shares outstanding immediately after the offering is based
upon the number of shares outstanding as of December 31, 2000, and excludes
6,000,000 shares reserved for issuance under our existing stock incentive
plans, including 1,594,340 shares issuable upon exercise of options outstanding
as of that date at a weighted average exercise price of $19.11 per share.

See "Risk Factors" and the other information included or incorporated by
reference in this prospectus for a discussion of factors you should carefully
consider before deciding to invest in our common stock.

Summary Consolidated Financial and Operating Data

Nine Months Ended
Year Ended December 31, September 30,
-------------------------------- ---------------------
1997 1998 1999 1999 2000
---------- ---------- ---------- ---------- ----------
(in thousands, except per share data)
(unaudited)

Consolidated Statement of
Operations Data:
Total revenues........ $1,066,875 $1,505,635 $1,567,382 $1,194,654 $1,057,243
Income (loss) from
operations........... 41,882 87,847 (327,026) 47,325 38,715
Net income (loss)..... 30,281 30,013 (346,280) 2,072 (22,350)
Basic and diluted
earnings (loss) per
common share......... $ 1.00 $ 0.76 $ (9.02) $ 0.05 $ (0.59)
Consolidated Operating and Other
Data:
Tons sold............. 40,525 81,098 111,177 82,728 79,384
Tons produced......... 36,698 75,817 109,524 80,896 76,112
Adjusted EBITDA....... $ 224,646 $ 313,500 $ 325,949 $ 255,130 $ 220,480
Net cash provided from
operating
activities........... $ 190,263 $ 188,023 $ 279,963 $ 195,964 $ 127,257

As of September 30, 2000
------------------------
(in thousands)
(unaudited)

Consolidated Balance Sheet Data:
Total assets........................................... $2,260,480
Working capital........................................ (93,798)
Long-term debt......................................... 1,066,216
Other long-term obligations............................ 619,389
Accumulated deficit.................................... (242,400)
Stockholders' equity................................... 212,361

Adjusted EBITDA is income from operations before the effect of changes in
accounting principles and extraordinary items; merger-related costs, unusual
items, asset impairment and restructuring charges; net interest expense; income
taxes; and depreciation, depletion and amortization of Arch Coal and its
subsidiaries and its ownership percentage in its equity investments. Adjusted
EBITDA should not be considered in isolation nor as an alternative to net
income, operating income, cash flows from operations or as a measure of a
company's profitability, liquidity or performance under U.S. generally accepted
accounting principles.

Information for 1997 reflects our merger with Ashland Coal, Inc. on July
1, 1997 and also reflects a $39.1 million charge in connection with the Ashland
Coal merger comprised of termination benefits, relocation costs and costs
associated with duplicate facilities.

Information for 1998 reflects the acquisition of Atlantic Richfield
Company's domestic coal operations on June 1, 1998. We refinanced our debt in
connection with this acquisition, and incurred an extraordinary charge of $1.5
million, net of tax benefit, related to the early extinguishment of debt which
existed prior to the acquisition. Income from operations for 1998 reflects pre-
tax gains of $41.5 million from the disposition of assets, including $18.5
million on the sale of assets and idle properties in eastern Kentucky and $7.5
million on the sale of our idle Big Sandy Terminal.

The loss from operations for 1999 reflects one-time pre-tax charges of
$364.6 million related principally to the write-down of assets at our Dal-Tex,
Hobet 21 and Coal-Mac operations and the write-down of other coal reserves in
Central Appalachia, and a $23.1 million pre-tax charge related to the
restructuring of our administrative workforce and the closure of mines in
Illinois, Kentucky and West Virginia. We changed our depreciation method on
preparation plants and loadouts during the first quarter of 1999 and recorded a
cumulative effect of applying the new method for years prior to 1999, which
resulted in a decrease to net loss in 1999 of $3.8 million.

Recent Developments

On January 24, 2001, we reported our preliminary and unaudited financial
and operating results for the three months and year ended December 31, 2000, a
summary of which follows:

Three Months Ended Year Ended
December 31, 2000 December 31, 2000
------------------- -------------------
(in thousands, except per share data)
(unaudited)

Consolidated Statement of
Operations Data:
Total revenues................ $347,378 $ 1,404,621
Income from operations........ 35,269 73,984
Net income (loss)............. 9,614 (12,736)
Basic and diluted earnings
(loss) per common share...... 0.25 (0.33)
Consolidated Operating and Other
Data:
Tons sold..................... 26,135 105,519
Tons produced................. 23,947 100,060
Adjusted EBITDA............... $ 94,695 $ 315,175
Net cash provided from
operating activities......... $ 8,515 $ 135,772

As of
December 31, 2000
-----------------
(in thousands)
(unaudited)

Consolidated Balance Sheet Data:
Total assets................................................ $2,232,614
Working capital............................................. (37,556)
Long-term debt.............................................. 1,090,666
Other long-term obligations................................. 606,628
Accumulated deficit......................................... (234,980)
Stockholders' equity........................................ 219,874

RISK FACTORS

Investing in our common stock will provide you with an equity ownership
interest in Arch Coal. As one of our stockholders, your investment will be
subject to risks, including risks inherent in our business. The value of your
investment could decline and could result in a loss. You should carefully
consider the following factors as well as other information contained and
incorporated by reference in this prospectus before deciding to invest in our
common stock.

We have a substantial amount of debt relative to our equity capitalization,
which limits our flexibility and imposes restrictions on us, and a downturn in
economic or industry conditions may materially affect our ability to meet our
future debt service and liquidity needs.

As of September 30, 2000, we had outstanding consolidated indebtedness of
$1.152 billion, representing approximately 84% of our capital employed. As a
result, we will have significant debt service obligations, and the terms of our
credit agreements limit our flexibility and impose a number of restrictions
upon us. We also have significant lease and royalty obligations. Debt service
consists of payments of interest and principal. We are required to make
aggregate principal payments on our indebtedness of $33.6 million in 2001,
$60.5 million in 2002, $1.1 billion in 2003, $0.6 million in each of 2004 and
2005 and $2.9 million, in the aggregate, thereafter. Our ability to satisfy our
debt service and lease and royalty obligations, and our ability to effect any
refinancing of our indebtedness, will depend upon our future operating
performance, which will be affected by prevailing economic conditions in the
markets that we serve and financial, business and other factors, many of which
are beyond our control. We may be unable to generate sufficient cash flow from
operations and future borrowings or other financing may be unavailable in an
amount sufficient to enable us to fund our debt service, lease and royalty
payment obligations or our other liquidity needs.

Our relative amount of debt could have material consequences to our
business, including, but not limited to:

. making it more difficult for us to satisfy our debt covenants and
debt service, lease payment and other obligations;

. making it more difficult for us to pay quarterly dividends as we have
in the past;

. increasing our vulnerability to general adverse economic and industry
conditions;

. limiting our ability to obtain additional financing to fund future
acquisitions, working capital, capital expenditures or other general
corporate requirements;

. reducing the availability of cash flow from operations to fund
acquisitions, working capital, capital expenditures or other general
corporate purposes;

. limiting our flexibility in planning for, or reacting to, changes in
our business and the industry in which we compete; and

. placing us at a competitive disadvantage when compared to competitors
with less relative amounts of debt.

A significant portion of our debt bears interest at variable rates that
are linked to short-term interest rates. If interest rates rise, our costs
relative to those obligations would also rise.

We have recently experienced operating and net losses, which may continue or
reoccur in the future.

We incurred an operating loss of approximately $327.0 million and a net
loss of approximately $346.3 million for the year ended December 31, 1999, and
a preliminary and unaudited net loss of approximately $12.7 million for the
year ended December 31, 2000. The losses in 1999 were primarily attributable to
a write-down of the carrying value of some of our operating assets and coal
reserves. This adjustment was partially due

to adverse legal and regulatory rulings related to surface mining techniques,
as well as persistent negative pricing for Central Appalachian coal production.
The losses were also partially attributable to a restructuring of our workforce
and the closure of several mines. The loss in 2000 was primarily attributable
to the temporary idling of our West Elk mine in Colorado following the
detection of combustion gases in a portion of the mine. Because the coal mining
industry is subject to significant regulatory oversight, and due to the
continuing possibility of negative pricing or other industry trends beyond our
control, we may suffer losses in the future if legal and regulatory rulings,
mine idlings and closures, negative pricing trends or other factors continue to
affect our ability to mine and sell coal profitably.

We may be unable to comply with restrictions imposed by our credit facilities
and other debt agreements, which could result in a default under these
agreements, enabling lenders to declare amounts borrowed due and payable or
otherwise result in unanticipated costs.

The agreements governing our outstanding debt impose a number of
restrictions on us. For example, the terms of our credit facilities and leases
contain financial and other restrictive covenants that limit our ability to,
among other things, complete acquisitions or dispositions and borrow additional
funds, and require us to, among other things, maintain various financial ratios
and comply with various other financial covenants. Our ability to comply with
these restrictions may be affected by events beyond our control and, as a
result, we may be unable to comply with these restrictions. A failure to comply
with these restrictions could constitute a default under our debt agreements,
and any default could lead to defaults under our other debt agreements. In the
event of a default, the lenders could terminate their commitments to us and
declare all amounts borrowed, together with accrued interest and fees,
immediately due and payable. If this were to occur, we might not be able to pay
these amounts, or we might be forced to seek an amendment to our debt
agreements which could make the terms of these agreements more onerous for us.
For example, as of December 31, 1999, we were not in compliance with some
covenants contained in our bank credit facilities as a result of a write-down
of impaired assets and other restructuring costs. The credit facilities were
amended in January 2000, as a result of which we made a one-time payment of
$1.8 million, agreed to an interest rate increase of 0.375% on our term loan
and revolving credit facility and pledged assets to collateralize our term loan
and revolving credit facility, including the stock of some of our subsidiaries
and some real property holdings, accounts receivable and inventory. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations--Liquidity and Capital Resources--Credit Facilities" for a more
detailed discussion of this amendment to our credit facilities.

An adverse decision in pending litigation could result in the permanent closure
of all or a portion of our mining operations in West Virginia, which would
cause our profitability to materially decline and could cause our stock price
to decline.

A federal district court injunction that prohibits the West Virginia
Division of Environmental Protection from issuing permits for our Dal-Tex mine
to use valley fill mining techniques resulted in the shutdown of this mine in
July 1999. A subsequent order prohibits the construction or expansion of valley
fills in West Virginia. Valley fill, or mountaintop, mining techniques used in
Central Appalachia involve the creation of large, engineered works into which
excess earth and rock extracted during surface mining are placed. The
plaintiffs in the litigation alleged, among other things, that the issuance of
mining permits without the preparation of an environmental impact statement, or
EIS, that would evaluate the environmental effects of mountaintop mining and
the construction of valley fills violated environmental laws. We have appealed
the order specific to our Dal-Tex operations, and we, the West Virginia
Division of Environmental Protection and others have appealed the broader order
concerning valley fills. Because it is not financially viable for coal
producers to operate some mining properties without valley fills, if the
appeals court agrees with the district court, we and other coal producers in
West Virginia may be forced to close all or a portion of our mining operations
in West Virginia, to the extent those operations are dependent on the use of
valley fills. If we permanently close these operations in West Virginia, our
profitability will decline because we will record various charges in connection
with the closures. We will also experience a loss of revenues from these

operations. For the year ended December 31, 1998, we received approximately
$100.8 million in revenues from our Dal-Tex mining operations, which
constituted 6.7% of our total 1998 revenues. If the district court decision is
overturned, then a settlement agreement entered into between the parties will
require the preparation of an EIS prior to the issuance of permits for the
construction of valley fills. The preparation of these statements is time-
consuming and is sometimes the subject of litigation. As a result, even if the
district court decision is overturned, we do not expect to reopen our Dal-Tex
mining operation before mid-2001, at the earliest, subject to then-existing
market conditions. See "Business--Legal Proceedings--Dal-Tex Litigation" for a
more detailed description of the Dal-Tex litigation.

New environmental regulations governing coal-fired electric generating plants
could reduce the demand for coal as a fuel source and affect the volume of our
sales.

Several new environmental regulations require a reduction in nitrogen
oxide emissions generated by coal-fired electric generating plants.
Substantially all of our revenues from sales of coal in the year ended December
31, 1999 were from sales to generators operating these types of plants.
Enforcement actions against a number of these generators, which include some of
our customers, and proposed legislation ultimately may require additional
reductions in nitrogen oxide emissions. The Environmental Protection Agency is
also considering regulations that would require reductions in mercury emissions
from coal-fired electric generating plants. To comply with these regulations
and enforcement actions, these generators may choose to switch to other fuels
that generate less of these emissions, such as natural gas or oil. In addition,
coal has become less attractive as a fuel source to generators considering
constructing new electric generating facilities. These developments could cause
a material decrease in the volume of our sales. See "The Coal Industry--Clean
Air Act" for a more detailed discussion of these regulations.

Because our industry is highly regulated, our ability to conduct mining
operations is restricted and our profitability may decline.

Government authorities regulate the coal mining industry on matters as
diverse as employee health and safety, air quality standards, water pollution,
groundwater quality and availability, plant and wildlife protection, the
reclamation and restoration of mining properties, the discharge of materials
into the environment and surface subsidence from underground mining. In
addition, federal legislation mandates benefits for various retired coal miners
represented by the United Mine Workers of America. These regulations and
legislation have had, and will continue to have, a significant effect on our
costs of production and competitive position. Future regulations, legislation
or orders may also cause our sales or profitability to decline by hindering our
ability to continue our mining operations or by increasing our costs.

Mining companies must obtain numerous permits that strictly regulate
environmental and health and safety matters in connection with coal mining.
Regulatory authorities exercise considerable discretion in the timing of permit
issuance. Also, private individuals and the public at large possess rights to
comment on and otherwise engage in the permitting process, including through
intervention in the courts. As described above, we shut down our Dal-Tex mining
operation in West Virginia in July 1999 as a result of legal action preventing
the issuance of permits necessary for those operations. Accordingly, the
permits we need may not be issued, or if issued, may not be issued in a timely
fashion, or may involve requirements that may be changed or interpreted in a
manner which restricts our ability to conduct our mining operations or to do so
profitably.

Our profitability may be adversely impacted by unanticipated mine operating
conditions and other factors that are not within our control, which could cause
our quarterly or annual results to decrease and our stock price to decline.

or seam, of coal, amounts of rock and other natural materials and other
geological conditions, have had, and can be expected in the future to have, a
significant impact on our operating results. For example, we were forced to
temporarily idle our West Elk mine in Colorado for more than five months during
2000 following the detection of combustion gases in a portion of the mine. This
mine accounted for 7.0% of our total 1999 revenues. As a result of the
temporary closure of this mine, we incurred between $4 million and $6 million
per month in after-tax losses while the mine was idled. Additional fire-related
costs will be incurred in 2001. To date, we have received and recognized an
aggregate of $31 million of pre-tax partial insurance payments that cover a
portion of the losses incurred at West Elk during 2000. Any additional
insurance recovery will depend on resolution of our claim with the insurance
carrier, the timing of which is uncertain. In addition, a prolonged disruption
of production at any of our principal mines, particularly our Mingo Logan
operation in West Virginia, would result in a decrease, which could be
material, in our revenues and profitability. Other factors affecting the
production and sale of our coal that could result in decreases in our
profitability include:

. expiration or termination of, or sales price redeterminations or
suspension of deliveries under, coal supply agreements;

. disruption or increases in the cost of transportation services;

. changes in laws or regulations, including permitting requirements;

. litigation;

. the timing and amount of insurance recoveries;

. work stoppages or other labor difficulties;

. mine worker vacation schedules and related maintenance activities;
and

. changes in coal market and general economic conditions.

Any adverse impact on our operating results could cause our stock price
to decline substantially, particularly if the results are below research
analyst or investor expectations.

Intense competition and excess industry capacity in the coal producing regions
in which we operate has adversely affected our revenues and profitability and
may continue to do so in the future.

The coal industry is intensely competitive, primarily as a result of the
existence of numerous producers in the coal producing regions in which we
operate, and a number of our competitors have greater financial resources than
we do. We compete with approximately six major coal producers in each of the
Central Appalachian and Powder River Basin areas. We also compete with a number
of smaller producers in those and our other market regions. We are subject to
the risk of reduced profitability as a result of excess industry capacity,
which has occurred in the past, and which results in reduced prices for our
coal.

The demand for and pricing of our coal is greatly influenced by consumption
patterns of the domestic electric generation industry, and any reduction in the
demand for our coal by this industry may cause our profitability to decline.

Demand for coal and the prices that we will be able to obtain for our
coal are closely linked to coal consumption patterns of the domestic electric
generation industry, which has accounted for approximately 90% of domestic coal
consumption in recent years. These coal consumption patterns are influenced by
factors beyond our control, including the demand for electricity, which is
significantly dependent upon summer and winter temperatures in the United
States, 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 our low-sulfur coal and the prices that we will
be able to obtain for it will also be affected by the price and availability of
high-sulfur coal,
which can be marketed in tandem with emissions allowances in order to meet
federal Clean Air Act requirements. Any reduction in the demand for our coal by
the domestic electric generation industry may cause our profitability to
decline.

Deregulation of the electric utility industry may cause our customers to be
more price-sensitive in purchasing coal, which could cause our profitability to
decline.

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. To the extent utility deregulation causes our customers to be
more cost sensitive, deregulation may have a negative affect on our
profitability.

Our profitability may be adversely affected by the renegotiation, termination
or expiration of favorable long-term coal supply contracts.

We sell a substantial portion of our coal under long-term coal supply
agreements, which are contracts with a term greater than 12 months. As a
consequence, we may experience fluctuations in operating results due to the
expiration or termination of, or sales price redeterminations or suspensions of
deliveries under, these coal supply agreements. In 1999, sales of coal under
long-term contracts accounted for approximately 76% of our total revenues. Some
of these contracts include pricing which is above, and, in some cases,
materially above, current market prices. We currently supply coal under long-
term coal supply contracts with one customer which have price renegotiation or
modification provisions that take effect in mid-2001. The prices for coal
shipped under these contracts are materially above the current market price for
similar type coal. For the year ended December 31, 1999, and the nine months
ended September 30, 2000, approximately $16.8 million and $15.1 million,
respectively, of our operating income related to these contracts. We expect
income from operations to be reduced by approximately one-half of the operating
income attributable to these contracts in 2001, and by the full amount of this
operating income in 2002. These amounts are predicated on current market
pricing and will change with market conditions. Some price adjustment
provisions permit a periodic decrease in the contract price to reflect
decreases in production costs, including those related to technological
improvements, changes in specified price indices or items such as taxes or
royalties. Price renegotiation or modification provisions may provide for
downward adjustments in the contract price based on market factors. We have
also renegotiated some contracts to change the contract term or accommodate
adverse market conditions such as decreasing coal spot market prices. New
nitrous oxide emission limits could also result in price adjustments, or could
force electric generators to terminate or modify long-term contracts. Other
short- and long-term contracts define base or optional tonnage requirements by
reference to the customer's requirements, which may change as a result of
factors beyond our, and in some instances, the customer's control, including
utility deregulation. If the parties to any long-term contracts with us were to
modify, suspend or terminate those contracts, our profitability would decline
to the extent that we are unable to find alternative customers at a similar or
higher level of profitability.

Because our profitability is substantially dependent on the availability of an
adequate supply of coal reserves that can be mined at competitive costs, the
unavailability of these types of reserves would cause our profitability to
decline.

Our profitability depends substantially on our ability to mine coal
reserves that have the geological characteristics that enable them to be mined
at competitive costs. Replacement reserves may not be available when required
or, if available, may not be capable of being mined at costs comparable to
those characteristic of the depleting mines. We have in the past, and will in
the future, acquire coal reserves for our mine portfolio from third parties. We
may not be able to accurately assess the geological characteristics of any
reserves that we acquire, which may adversely affect our profitability and
financial condition.

Disruption in or increased costs of transportation services could adversely
affect our profitability.

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. Disruptions of these
transportation services could temporarily impair our ability to supply coal to
our customers. In

addition, increases in transportation costs, or changes in costs relative to
transportation costs for coal produced by our competitors, could adversely
affect our profitability.

We face numerous uncertainties in estimating our economically recoverable coal
reserves, and inaccuracies in our estimates could result in lower than expected
revenues, higher than expected costs and decreased profitability.

The coal reserve information included or incorporated in this prospectus
has not been audited by an independent expert. We base our reserve information
on geological data assembled and analyzed by our staff, which includes various
engineers and geologists. The reserve estimates are annually updated to reflect
production of coal from the reserves and new drilling or other data received.
There are numerous uncertainties inherent in estimating quantities of
recoverable reserves, including many factors beyond our control. Estimates of
economically recoverable coal reserves and net cash flows necessarily depend
upon a number of variable factors and assumptions, such as geological and
mining conditions, which may not be fully identified by available exploration
data or may differ from experience in current operations, historical production
from the area compared with production from other producing areas, the assumed
effects of regulation by governmental agencies and assumptions concerning coal
prices, operating costs, severance and excise taxes, development costs and
reclamation costs, all of which may vary considerably from actual results.

For these reasons, estimates of the economically recoverable quantities
attributable to any particular group of properties, classifications of reserves
based on risk of recovery and estimates of net cash flows expected therefrom
prepared by different engineers or by the same engineers at different times may
vary substantially. Actual coal tonnage recovered from identified reserve areas
or properties, and revenues and expenditures with respect to our reserves, may
vary from estimates, and these variances may be material. These estimates thus
may not accurately reflect our actual reserves.

Defects in title or the loss of any leasehold interests in our properties could
limit our ability to mine these properties or result in significant
unanticipated costs.

We conduct a significant part of our mining operations on properties that
we lease. The loss of any lease could adversely affect our ability to mine the
associated reserves. Because title to most of our leased properties and mineral
rights is not thoroughly verified until we make a commitment to develop a
property, which may not occur until after we have obtained necessary permits
and completed exploration of the property, our right to mine some of our
reserves has in the past, and may again in the future, be adversely affected if
defects in title or boundaries exist. In order to obtain leases or mining
contracts to conduct our mining operations on property where these defects
exist, we have had to, and may in the future have to, incur unanticipated
costs. In addition, we may not be able to successfully negotiate new leases or
mining contracts for properties containing additional reserves or maintain our
leasehold interests in properties where we have not commenced mining operations
during the term of the lease.

Agreements entered into in connection with the acquisition of our reserves and
mining facilities in the western United States contain limitations on our
ability to manage these operations exclusively and could subject us to
significant indemnification obligations.

Our affiliate, Arch Western Resources, LLC, is the owner of our reserves
and mining facilities in the western United States. The agreement under which
Arch Western was formed provides that one of our subsidiaries, 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 ARCO, 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 that time, Arch
Western has a debt rating less favorable than Ba3 from Moody's Investors
Service or BB- from Standard & Poor's or fails to meet specified indebtedness
and interest ratios.

In connection with the Arch Western acquisition, we entered into an
agreement under which we agreed to indemnify ARCO against specified tax
liabilities in the event that these liabilities arise as a result of actions
taken prior to June 1, 2013, including the sale or other disposition of
specified properties of Arch Western, the repurchase of some equity interests
in Arch Western by Arch Western or the reduction under some circumstances of
indebtedness incurred by Arch Western in connection with the Arch Western
acquisition. Depending on the time at which any indemnification obligation were
to arise, it could impact our profitability for the period in which it arises.

The membership interests in Canyon Fuel Company, LLC, 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 the
business and affairs of Canyon Fuel. Some major business decisions concerning
Canyon Fuel require the vote of 70% of the membership interests and therefore
limit our ability to make these decisions. These decisions include admission of
additional members, approval of annual business plans, the making of capital
expenditures, sales of coal below specified prices, agreements between Canyon
Fuel and any member, 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
restrictions on the transfer of our membership interest in Canyon Fuel.

Our stockholder rights plan and amended charter documents may make it harder
for others to obtain control of us even though some stockholders might consider
such a development favorable, which may adversely affect our stock price.

In March 2000, we adopted a stockholder rights plan which, together with
provisions of our amended and restated certificate of incorporation and our by-
laws, may delay, inhibit or prevent someone from gaining control of us through
a tender offer, business combination, proxy contest or some other method even
if some of our stockholders might believe a change in control is desirable. See
"Description of Capital Stock" for a description of our rights plan and these
charter and by-law provisions.

FORWARD-LOOKING STATEMENTS

This prospectus includes and incorporates by reference forward-looking
statements within the "safe harbor" provision of the Private Securities
Litigation Reform Act of 1995. These statements may generally be identified by
the use of words such as "estimate," "expect," "anticipate," "believe,"
"intend," "plan," "continue," "may," "will," "should," or "shall." We have
based these forward-looking statements on our current expectations and
projections about future events. These forward-looking statements are subject
to various risks and uncertainties that could cause actual results to differ
materially from those projected in these statements, some of which are
described under "Risk Factors" and "Management's Discussion and Analysis of
Financial Condition and Results of Operations." The forward-looking statements
contained and incorporated by reference in this prospectus are based on
expectations or assumptions, some or all of which may be incorrect. These
expectations and assumptions include the following:

. our expectation of continued growth in the demand for electricity;

. our belief that legislation and regulations relating to the Clean Air
Act will increase demand for our coal;

. our expectation of improving market conditions for the price of our
coal;

. our expectation that we will continue to have adequate liquidity from
our cash flow from operations, together with available borrowings under
our credit facilities, to finance our working capital needs and meet our
debt reduction goals; and

. our expections as to changes in mining rates and costs for a variety of
operational, geological, permitting, labor and weather-related reasons,
including equipment availability.

USE OF PROCEEDS

We estimate that the net proceeds to us from this offering will be
approximately $70.7 million, or approximately $92.9 million if the underwriter
exercises its over-allotment option in full to purchase 1,227,765 additional
shares, based on the public offering price of $19.00 per share, and after
deducting the underwriting discount and estimated offering expenses payable by
us.

We currently intend to use one-half of the net proceeds of this offering
to reduce indebtedness under our revolving credit facility and the remainder to
reduce indebtedness under our amortizing term loan. As of December 31, 2000,
outstanding indebtedness under our revolving credit facility and amortizing
term loan was $332.1 million and $135.0 million, respectively. The indebtedness
to be reduced bears interest at variable rates based on a PNC Bank base rate or
LIBOR. The interest rates in effect as of December 31, 2000 were 8.03% and
8.29% on outstanding indebtedness under the revolving credit facility and
amortizing term loan, respectively. The indebtedness under both the revolving
credit facility and amortizing term loan matures on May 31, 2003.

We will not receive any proceeds from the sale of shares offered by the
selling stockholder under this prospectus.

PRICE RANGE OF COMMON STOCK AND DIVIDENDS

Our common stock is listed on the New York Stock Exchange. The following
table sets forth for the periods indicated the range of high and low sales
prices per share of our common stock as reported on the New York Stock Exchange
and the cash dividends declared on the common stock for the periods indicated.

Common
Stock Price
-------------
High Low Dividends
------ ------ ---------

Year Ended December 31, 1999:
First Quarter......................................... $16.88 $ 9.75 $.1150
Second Quarter........................................ 14.81 10.94 .1150
Third Quarter......................................... 15.56 11.38 .1150
Fourth Quarter........................................ 13.00 8.56 .1150

Year Ended December 31, 2000:
First Quarter......................................... $11.38 $ 6.50 $.0575
Second Quarter........................................ 9.00 4.75 .0575
Third Quarter......................................... 11.25 6.94 .0575
Fourth Quarter........................................ 14.94 9.38 .0575

Year Ending December 31, 2001:
First Quarter (through February 15, 2001)............. $21.88 $12.88

On February 15, 2001, the last sale price of our common stock as reported
on the New York Stock Exchange was $19.26 per share. On December 31, 2000,
there were approximately 12,211 holders of record of our common stock.

The future declaration and payment of dividends and the amount of
dividends will depend upon our results of operations, financial condition, cash
requirements, future prospects, any limitations imposed by credit agreements or
senior securities and other factors deemed relevant by our board of directors.
In 2000, we reduced the amount of our dividend payments by 50%. Our board of
directors has considered and may again consider further reducing the amount of
dividends we pay.

CAPITALIZATION

The following table sets forth our capitalization as of September 30,
2000 and as adjusted to give effect to the sale of 3,943,032 shares of common
stock at the public offering price of $19.00 per share and the application of
the net proceeds as described in "Use of Proceeds."

As of September 30, 2000
----------------------------
(in thousands)
(unaudited)
Actual As Adjusted
------------ --------------

Total debt........................................ $1,152,216 $ 1,081,473
============ ============
Stockholders' equity:
Preferred stock, $.01 par value, 10,000,000
shares authorized, no shares issued and
outstanding, actual and as adjusted............. -- --
Common stock, $.01 par value, 100,000,000 shares
authorized, 38,164,482 issued and outstanding,
actual; 42,107,514 shares issued and
outstanding, as adjusted........................ 397 436
Paid-in capital.................................. 473,335 544,039
Accumulated deficit.............................. (242,400) (242,400)
Treasury stock, at cost.......................... (18,971) (18,971)
------------ ------------
Total stockholders' equity..................... $ 212,361 $ 283,104
============ ============
Total capitalization.............................. $1,364,577 $ 1,364,577
============ ============

SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA

The following table presents our selected consolidated financial and
operating data for, and as of the end of, each of the periods indicated. The
selected consolidated financial data for, and as of the end of, each of the
years ended December 31, 1997, 1998 and 1999 are derived from our audited
consolidated financial statements incorporated by reference in this prospectus.
The selected consolidated financial data for, and as of the end of, the nine
months ended September 30, 1999 and 2000 are derived from our unaudited
consolidated financial statements incorporated by reference in this prospectus,
and in the opinion of management, include all adjustments, consisting only of
normal recurring accruals, that are necessary for a fair presentation of our
financial position and operating results for these periods. The selected
consolidated financial and operating data are not necessarily indicative of the
results that may be expected for any future period. The selected consolidated
financial and operating data should be read in conjunction with "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
the financial statements and related notes incorporated by reference in this
prospectus.

Nine Months Ended
Year Ended December 31, September 30,
--------------------------------- ----------------------
1997 1998 1999 1999 2000
---------- ---------- ---------- ---------- ----------
(in thousands except per share data)

Statement of Operations
Data: (unaudited)
Coal sales, equity
income and other
revenues............... $1,066,875 $1,505,635 $1,567,382 $1,194,654 $1,057,243
Costs and expenses:
Cost of coal sales..... 916,802 1,313,400 1,426,105 1,071,187 946,617
Selling, general and
administrative
expenses.............. 28,885 44,767 46,357 33,188 29,611
Amortization of coal
supply agreements..... 18,063 34,551 36,532 28,894 30,790
Merger-related
expenses.............. 39,132 -- -- -- --
Write-down of impaired
assets................ -- -- 364,579 -- --
Other expenses......... 22,111 25,070 20,835 14,060 11,510
---------- ---------- ---------- ---------- ----------
Income (loss) from
operations............. 41,882 87,847 (327,026) 47,325 38,715
Interest expense, net... 17,101 61,446 88,767 67,466 68,165
Benefit from income
taxes.................. 5,500 5,100 65,700 18,400 7,100
---------- ---------- ---------- ---------- ----------
Income (loss) before
extraordinary loss and
cumulative effect of
accounting change...... 30,281 31,501 (350,093) (1,741) (22,350)
Extraordinary loss...... -- (1,488) -- -- --
Cumulative effect of
accounting change...... -- -- 3,813 3,813 --
---------- ---------- ---------- ---------- ----------
Net income (loss)....... $ 30,281 $ 30,013 $ (346,280) $ 2,072 $ (22,350)
========== ========== ========== ========== ==========
Balance Sheet Data (at
period end):
Total assets............ $1,656,324 $2,918,220 $2,332,374 $2,748,274 $2,260,480
Working capital......... 40,904 20,176 (54,968) 16,856 (93,798)
Long-term debt, less
current maturities..... 248,425 1,309,087 1,094,993 1,181,209 1,066,216
Other long-term
obligations............ 594,127 657,759 655,166 658,985 619,389
Retained earnings
(Accumulated deficit).. 138,676 150,423 (213,466) 139,277 (242,400)
Stockholders' equity.... 611,498 618,216 241,295 594,270 212,361

Common Stock Data:
Basic and diluted
earnings (loss) per
common share before
extraordinary loss and
cumulative effect of
accounting change...... 1.00 0.79 (9.12) (0.05) (0.59)
Basic and diluted
earnings (loss) per
common share........... 1.00 0.76 (9.02) 0.05 (0.59)
Dividends per share..... 0.445 0.46 0.46 0.3450 0.1725
Shares outstanding at
period end............. 39,658 39,372 38,164 38,463 38,164

Cash Flow Data:
Cash provided by
operating activities... $ 190,263 $ 188,023 $ 279,963 $ 195,964 $ 127,257
Depreciation, depletion
and amortization....... 143,632 204,307 235,658 179,942 153,286
Purchases of property,
plant and equipment.... 77,309 141,737 98,715 76,078 103,121
Dividend payments....... 13,630 18,266 17,609 13,218 6,584
Adjusted EBITDA......... 224,646 313,500 325,949 255,130 220,480

Operating Data:
Tons sold............... 40,525 81,098 111,177 82,728 79,384
Tons produced........... 36,698 75,817 109,524 80,896 76,112
Tons purchased from
third parties.......... 2,906 4,997 3,781 3,257 3,875

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS

Overview

We were originally organized as Arch Mineral Corporation in 1969. On July
1, 1997, Ashland Coal, Inc. then a majority-owned subsidiary of Ashland Inc.,
merged with a subsidiary of our company. A total of 18,660,054 shares of our
common stock were issued in the merger, resulting in a total purchase price,
including the fair value of stock options and transaction-related fees, of
approximately $464.8 million. In connection with the merger, we changed our
name to Arch Coal, Inc. Immediately prior to the merger, Ashland beneficially
owned common stock representing approximately 57% of the voting power of
Ashland Coal and approximately 51% of our voting stock. Immediately after the
merger, Ashland owned approximately 54% of our outstanding common stock, which
ownership increased to 58% as of June 1999, when Ashland announced an interest
in exploring strategic alternatives for its interest in our company. Ashland
retained its stake in our company until its March 2000 distribution of
approximately 17.4 million shares of our common stock to Ashland's stockholders
after which Ashland owned approximately 12.4% of our outstanding common stock.

On June 1, 1998, we acquired the United States coal operations of
Atlantic Richfield Company for an aggregate of approximately $1.14 billion in
cash and combined these operations with our western operations in a new joint
venture named Arch Western Resources, LLC. We own 99% of this joint venture and
ARCO owns the remaining 1% interest. The principal operating units of Arch
Western are Thunder Basin Coal Company, L.L.C., owned 100% by Arch Western,
which operates a coal mine in the Southern Powder River Basin in Wyoming;
Mountain Coal Company, L.L.C., owned 100% by Arch Western, which operates a
coal mine in Colorado; Canyon Fuel Company, LLC, 65% owned by Arch Western and
35% owned by ITOCHU Coal International Inc., a subsidiary of ITOCHU
Corporation, which operates three coal mines in Utah; and Arch of Wyoming, LLC,
owned 100% by Arch Western, which operates two coal mines in the Hanna Basin of
Wyoming.

Excluding our Canyon Fuel joint venture, the results of which we account
for under the equity method of accounting, we sold approximately 111.2 million
tons of coal in 1999, 107.1 million tons of which we produced and the balance
of which we purchased for resale through contractual arrangements. We sold
approximately 82% of this tonnage under long-term contracts, which are
contracts of greater than one year, and the balance on the spot market. We
derived approximately 76% of 1999 total revenues from sales of coal under long-
term contracts. Our sales of steam coal, which is coal used in steam boilers to
produce electricity, in 1999 totaled 108.7 million tons, or approximately 98%
of 1999 coal sales, while sales of metallurgical coal, which is coal suitable
for distillation into carbon in connection with the production of steel, in
1999 totaled 2.5 million tons, or approximately 2% of 1999 coal sales. In 1999,
sales of coal in the export market totaled approximately 3.5 million tons.
Sales of steam coal accounted for approximately 59% of these export sales,
while the balance of export sales consisted of sales of metallurgical coal.

Our mining operations are inherently subject to changing conditions that
can affect levels of production and production costs at particular mines for
varying lengths of time and result in fluctuations in our profitability.
Weather conditions, equipment replacement or repair, 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 our operating results. For example, we were
forced to temporarily idle our West Elk mine in Colorado for more than five
months during 2000 following the detection of combustion gases in a portion of
the mine. The temporary closure of this mine adversely affected our operating
results in 2000. A prolonged disruption of production at any of our principal
mines, particularly our Mingo Logan operation in West Virginia, would have a
material adverse effect on us. Other factors affecting the production and sale
of our coal that can result in fluctuations in our profitability include the
following:

. expiration or termination of, or sales price redeterminations or
suspension of deliveries under, coal supply agreements;

. disruption or increases in the cost of transportation services;

. changes in laws or regulations, including permitting requirements;

. litigation;

. work stoppages or other labor difficulties; and

. changes in coal market and general economic conditions.

Outlook

West Elk Mine.

On July 12, 2000, we resumed production at our West Elk underground mine
in Gunnison County, Colorado, and, after experiencing geological conditions
unrelated to the fire that have hindered production, the mine returned to
normal levels of production during the fourth quarter of 2000. West Elk had
been idle since January 28, 2000, following the detection of combustion-related
gases in a portion of the mine. We incurred between $4 million and $6 million
per month in after-tax losses while the mine was idled. Additional fire-related
costs were incurred at the West Elk mine following the resumption of mining
activities and will continue to be incurred in 2001 as we reclaim drilling
sites and roads and eventually dismantle pumping equipment. To date, we have
received and recognized aggregate pre-tax partial insurance payments of $31
million that cover a portion of the losses incurred at West Elk during 2000. We
expect to receive additional insurance payments under our property and business
interruption policy. Any additional recovery, however, will depend on
resolution of our claim with the insurance carrier, the timing of which is
uncertain.

West Virginia Operations.

On October 20, 1999, the U.S. District Court for the Southern District of
West Virginia permanently enjoined the West Virginia Division of Environmental
Protection (DEP) from issuing any permits that authorize the construction of
valley fills as part of coal mining operations. The West Virginia DEP complied
with the injunction by issuing an order banning the issuance of permits for the
construction of nearly all new valley fills and the expansion of nearly all
existing valley fills. On October 29, 1999, the district court granted a stay
of its injunction, pending the outcome of an appeal of the court's decision
filed by the West Virginia DEP with the U.S. Court of Appeals for the Fourth
Circuit. The West Virginia DEP rescinded its order in response to the stay
granted by the court. We cannot predict the outcome of the West Virginia DEP's
appeal to the Fourth Circuit. If, however, the district court's ruling is not
overturned or if a legislative or other solution is not achieved, we and other
coal producers in West Virginia may be forced to close all or a portion of our
mining operations in West Virginia, to the extent those operations are
dependent on the use of valley fills.

The injunction discussed above was entered as part of the litigation that
caused a delay in obtaining mining permits for our Dal-Tex operation described
under "Business--Legal Proceedings--Dal-Tex Litigation". In 1999, we recorded
charges for severance and closure costs aggregating $13.8 million with respect
to the idling of this operation. As a result of the delay, we idled our Dal-Tex
mining operation on July 23, 1999. If all necessary permits are obtained, which
is not expected to occur until mid-2001 at the earliest, and the permanent
injunction is withdrawn by the Fourth Circuit, then we may determine to reopen
the mine subject to then-existing market conditions.

Previously, we 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, we now believe that we can extend longwall mining at that
operation for an additional 12 months, which will be well into 2003. Longwall
mining is a mining technique in which a rotating drum is pulled mechanically
across the face of coal and a hydraulic system supports the roof of the mine
while it advances through the coal.

Coal Markets.

Recent developments, including rising natural gas prices, declining coal
inventory levels and the recent energy crisis in California, have translated
into improved market conditions for coal. As of January 2001, the

price of natural gas has more than doubled since December 1999. No domestic
nuclear plants are currently in the permitting stage while in September 2000,
Wisconsin Electric Power Company announced plans to construct two new coal-
fired units with a combined generating capacity of 1,200 megawatts, and in
January 2001, UniSource Energy Corp. and Bechtel Power Corp. each announced
plans to build 380 megawatt coal-fired units in northern Arizona, and LS Power
LLC, an independent power producer, announced plans to build a 1,000 to 1,600
megawatt coal-fired plant in Arkansas, which it anticipates will burn coal from
the Powder River Basin. Hydroelectric power conditions are weaker than normal
due to dry conditions. Also, since late July, quoted and spot prices for coal
produced in the regions in which we operate have risen. However, because most
of our production was already committed and priced for 2000, our results for
the year reflected the earlier market weakness.

We continue to take steps to match our production levels to market needs.
We have ceased production at our Coal Creek surface mine in Campbell County,
Wyoming. We also plan to maintain a production level of approximately 60
million tons from our Black Thunder mine near Gillette, Wyoming.

Low-Sulfur Coal Producer.

We continue to believe that we are well-positioned to capitalize on the
continuing growth in demand for low-sulfur coal to produce electricity. With
Phase II of the Clean Air Act in effect, compliance coal has captured a growing
share of United States coal demand and commands a higher price than high-sulfur
coals in the marketplace. Compliance coal is coal that meets the requirements
of Phase II of the Clean Air Act without the use of expensive scrubbing
technology. All of our western coal production and approximately half of our
eastern production is compliance quality.

Chief Financial Objectives.

We continue to focus on realizing the potential of our assets and
maximizing stockholder value by making decisions based upon our five chief
financial objectives: (1) further strengthening our cash generation, (2)
improving our earnings, (3) increasing our productivity, (4) aggressively
paying down our debt, and (5) reducing our costs. We are aggressively pursuing
cost savings which, together with improved productivity, are designed to enable
us to achieve our other financial objectives. In addition to the corporate-wide
restructuring in late 1999 that we believe will result in a substantial
reduction in operating costs for the current and future years, we recently
initiated a cost reduction effort targeting key cost drivers at each of our
captive mines. We may issue additional equity securities to further pursue our
objective of aggressively paying down our debt. We are also exploring Internet-
based solutions that could reduce costs, especially in the procurement area.

We repaid $28.8 million of debt during the first nine months of the year
and made the second of five annual payments of $31.6 million for the
Thundercloud federal reserve lease, despite lower cash generation and increased
expenditures related to the idling of the West Elk mine, and a net payment of
$31.6 million to purchase assets out of an operating lease. We anticipate
continuing to make substantial progress toward reducing debt in the future.

Recent Operating Results

We recently announced our preliminary and unaudited financial and
operating results for our fourth quarter and year ended December 31, 2000. Our
revenue for the quarter ended December 31, 2000 was $347.4 million, as compared
to revenue of $372.7 million in the same period of 1999. Net income for the
fourth quarter of 2000, was $9.6 million, as compared to a net loss of $348.4
million in the same quarter of 1999. Coal sales were 26.1 million tons in the
fourth quarter of 2000, as compared to 28.4 million tons in the same period of
1999. Fourth quarter 2000 results benefited from a third partial insurance
recovery of $7.0 million (pre-tax) related to the January 2000 fire at our West
Elk mine in Colorado, a $13.0 million pre-tax gain associated with the
settlement of certain workers' compensation liabilities, and a $9.8 million
pre-tax gain

resulting from previously unrecognized post-retirement benefit changes which
occurred in prior years. Partially offsetting that benefit were the adverse
roof conditions at West Elk and higher diesel fuel prices, which together had a
negative impact of $14.0 million for the quarter.

Results of Operations

Our results of operations for the years ended 1997, 1998 and 1999 and for
the first nine months of 1999 and 2000 are discussed below. Our results of
operations for 1997, 1998 and 1999 are not directly comparable because of our
July 1, 1997 merger with Ashland Coal and our June 1, 1998 acquisition of
ARCO's United States coal operations. Results of operations do not include the
activity of Ashland Coal or ARCO's United States coal operations prior to the
effective dates of those transactions.

Nine Months Ended September 30, 2000 Compared to Nine Months Ended September
30, 1999.

Net Income (Loss). We incurred a net loss of $22.4 million for the nine
months ended September 30, 2000 compared to net income of $2.1 million for the
nine months ended September 30, 1999. Results for the nine months ended
September 30, 2000 were adversely impacted by the temporary idling of our West
Elk mine in Gunnison County, Colorado. The mine was idled from January 28, 2000
to July 12, 2000, following the detection of combustion gases in a portion of
the mine. During the nine months ended September 30, 2000, the mine contributed
coal sales of $23.1 million and an operating loss of $38.6 million, excluding
insurance recoveries, compared to $80.1 million of coal sales and $7.6 million
of operating income during the nine months ended September 30, 1999. Offsetting
a portion of the loss at the West Elk mine were pre-tax partial insurance
payments aggregating $24.0 million received during the nine months ended
September 30, 2000 as part of our coverage under our property and business
interruption insurance policy. Also, as a result of recent permit revisions at
our idle mine properties in Illinois, we reviewed and reduced our reclamation
liability at those locations by $7.8 million during the current period. In
addition, the Internal Revenue Service issued a notice in 2000 outlining the
procedures for obtaining tax refunds on federal excise taxes paid by the
industry on export sales tonnage. The notice is a result of a 1998 federal
district court decision that found these taxes to be unconstitutional. We
recorded $12.7 million of pre-tax income related to these excise tax recoveries
during the nine months ended September 30, 2000.

Revenues. Total revenues for the nine months ended September 30, 2000
were $1.057 billion, a decrease of 11.5% from revenues of $1.195 billion for
the nine months ended September 30, 1999. Factors contributing to the decrease
included reduced sales at our West Elk mine as a result of the temporary idling
of that mine, as described above. Also, we closed our Dal-Tex, Wylo and Arch of
Illinois operations and two surface mines in Kentucky during the second half of
1999. In addition, production and sales at our Mingo Logan operation decreased
12% and 10%, respectively, in the current period compared to the same period in
the prior year. Partially offsetting sales at our closed eastern operations
were increased sales at other eastern operations.

We idled the Dal-Tex operation on July 23, 1999 due to a delay in
obtaining new mining permits which resulted from legal action in the U.S.
District Court for the Southern District of West Virginia, as described under
"Business--Legal Proceedings--Dal-Tex Litigation". The Wylo operation ceased
production in December 1999 due to the depletion of its recoverable reserves.
The Arch of Illinois underground operation, which had remained operative after
the closing of the Arch of Illinois surface operations in 1998, was closed in
December 1999 due to a lack of demand for the mine's high-sulfur coal. Demand
for high-sulfur coal has declined rapidly as a result of the stringent Clean
Air Act requirements that are driving a shift to low-sulfur coal. Two small
surface mines in Kentucky were closed because their cost structures were not
competitive in the then-existing market environment. The resulting decrease in
production and sales from our eastern operations was partially offset by
increased production and sales at our Black Thunder mine in Wyoming. As a
result, on a per-ton-sold basis, our average selling price of $12.72 during the
first nine months of 2000 reflected a decrease of $1.23 from the same period in
the prior year primarily as a result of the continuing increase in

coal sales from our western operations. Western coal, especially Powder River
Basin coal, has a significantly lower average sales price than that of eastern
coal, but is also significantly less costly to mine.

Income from Operations. Excluding the decrease in income from operations
resulting from the temporary idling of the West Elk mine, the partial insurance
payments, the reclamation liability adjustment at Arch of Illinois and the
excise tax recoveries, income from operations decreased $7.0 million for the
nine months ended September 30, 2000 when compared to the same period in the
prior year. The decrease was attributable to low sales relating to difficult
market conditions in United States coal markets during the period along with
increased fuel costs of over $1.0 million per month compared to the same period
in 1999, resulting from higher diesel fuel and oil prices. Income from
operations also declined at our Mingo Logan longwall operation where, despite
the contribution of $30.0 million to our income from operations, results were
below the $40.9 million of income from operations for the nine months ended
September 30, 1999. The decrease was primarily caused by depressed coal prices,
generally less favorable mining conditions and increased mine development
expenses associated with the start-up of operations in the Alma seam in
preparation for moving longwall equipment into the newly developed seam in
early 2001. Partially offsetting the decrease in income from operations was
improved performance at several of our other mines caused in part by our
continued focus on reducing costs and improving productivity and reduced costs
during the nine months ended September 30, 2000 resulting from the closure of
the Dal-Tex operation in July 1999. The Dal-Tex complex incurred production
shortfalls, deterioration of mining conditions and resulting lower operating
income prior to its closing on July 23, 1999. As a result of the closing, we
recorded a charge of $6.5 million through the third quarter of 1999, consisting
principally of severance costs, obligations for non-cancelable lease payments
and a change in the reclamation liability. Other factors that affected period
to period comparisons were several sales of surplus land which resulted in a
gain of $8.4 million during the current period. During the nine months ended
September 30, 1999, we sold a dragline at the Arch of Illinois operation,
resulting in a gain of $2.5 million, and also had settlements with two
suppliers that added $4.5 million to the prior period results.

Selling, General and Administrative Expenses. Selling, general and
administrative expenses decreased $3.6 million from the nine months ended
September 30, 1999. The decrease was attributable to cost savings resulting
from the restructuring of our administrative workforce that occurred during the
fourth quarter of 1999, partially offset by higher legal and consulting
expenses incurred during the second quarter of 2000.

Adjusted EBITDA. Adjusted EBITDA was $220.5 million for the nine months
ended September 30, 2000 compared to $255.1 million for the nine months ended
September 30, 1999. The decrease in adjusted EBITDA was primarily attributable
to the continued negative impact of the temporary idling of our West Elk mine,
excluding insurance recoveries, and lower operating profit at the Mingo Logan
operation. This was partially offset by improved performance at our Black
Thunder mine and the impact of the partial insurance payments due to the idling
of the West Elk mine.

Year Ended December 31, 1999 Compared to Year Ended December 31, 1998.

Net Income (Loss). We incurred a net loss in 1999 of $346.3 million
compared to net income of $30.0 million in 1998. Results for 1999 included
operating results of the Arch Western operations for the entire year, whereas
results for 1998 only included results of the Arch Western operations from June
1, 1998, including a 65% share of Canyon Fuel income, net of purchase
accounting adjustments.

The decrease in 1999 was primarily the result of several one-time
charges. During the fourth quarter of 1999, we determined that significant
changes were necessary in the manner and extent to which a portion of our
Central Appalachia coal assets would be deployed. The changes were necessitated
by the adverse legal and regulatory rulings related to surface mining
techniques as well as continued negative pricing trends related to Central
Appalachian coal production. In accordance with applicable accounting
pronouncements, we evaluated the recoverability of our active mining operations
and our coal reserves for which no future mining plans exist. This evaluation
indicated that the future undiscounted cash flows of three mining operations,
Dal-Tex, Hobet 21

and Coal-Mac, and coal reserves with no future mining plans were below their
carrying value. Accordingly, during the fourth quarter of 1999, we adjusted the
operating assets and coal reserves to their estimated fair value of
approximately $99.7 million, resulting in a non-cash impairment charge of
$364.6 million, including $50.6 million relating to operating assets and $314.0
million relating to coal reserves. The estimated fair value of the three mining
operations was based on anticipated future cash flows discounted at a rate
commensurate with the risk involved. The cash flow assumptions used in this
determination are consistent with our future plans for those operations and
consider the impact of inflation on coal prices and operating costs which are
expected to offset each other. The value of the coal reserves with no future
mining plans was based upon the fair value of these properties to be derived
from subleased operations. We do not expect the impairment charge to have a
material impact on our operating results subsequent to 1999.

During 1999, we also recorded pre-tax charges totaling $23.1 million
related to the restructuring of our administrative workforce, the closure of
our Dal-Tex mine in West Virginia, and the closure of several mines at our
Coal-Mac complex in Kentucky and the remaining underground mine at our Arch of
Illinois complex. Of the $23.1 million charge, $20.3 million was recorded in
cost of coal sales, $2.3 million was recorded in selling, general and
administrative expenses and $0.5 million was recorded in other expenses in our
consolidated statements of operations.

During 1999, we also recorded a $112.3 million valuation allowance for a
portion of our deferred tax assets that we believe, more likely than not, will
not be realized. Prior to the year ended December 31, 1999, our internal
forecast of book and taxable income provided sufficient anticipated future
taxable income to recognize deferred tax assets in full. However, a combination
of factors arising during 1999 resulted in a determination that, as of December
31, 1999, a valuation allowance of $112.3 million was appropriate, including:
(a) the significant increase in the amount of our gross tax assets attributable
to temporary differences arising from the 1999 impairment charge and (b)
unfavorable adjustments to forecasted future income attributable to (i) the
effect of the Dal-Tex litigation on future mountain top mining activities in
West Virginia and (ii) persistent negative trends in prices for our compliance
coal.

Effective January 1, 1999, we changed our method of depreciation on
preparation plants and loadouts from a straight-line basis to a units-of-
production basis, which is based upon units produced, subject to a minimum
level of depreciation. These assets are usage-based and their economic lives
are typically based and measured on coal processed by the assets. We believe
the units-of-production method is preferable to the method previously used
because the new method recognizes that depreciation of this equipment is
related substantially to physical wear due to usage as well as the passage of
time. This method recovers production costs over the lives of the preparation
plants and loadouts with coal sales revenue and results in a better matching of
the cost of the physical assets to the periods in which the assets are
consumed. The cumulative effect of applying the new depreciation method for
years prior to 1999 was an increase to income of $3.8 million.

Revenues. Total revenues of $1.567 billion for 1999 were 4.1% higher than
revenues for 1998, primarily as a result of including a full year of operating
results from the Arch Western operations in 1999, which accounted for
approximately $406.7 million of our revenues in 1999 compared to only seven
months of operating results from the Arch Western operations in 1998, which
accounted for approximately $228.5 million of our revenues in 1998. Revenues
were also favorably impacted by increased production and sales at our Samples
mine. The increase was partially offset by reduced production and sales at our
Dal-Tex and Wylo operations, both located in Central Appalachia, and our Arch
of Illinois surface mining operation. The Wylo operations and Arch of Illinois
surface operations ceased production in December 1999 and June 1998,
respectively, due to the depletion of their recoverable coal reserves. We idled
the Dal-Tex operation on July 23, 1999 due to a delay in obtaining new mining
permits which resulted from legal action in the U.S. District Court for the
Southern District of West Virginia. On a per-ton-sold basis, our average
selling price of $13.58 during 1999 reflected a decrease of $4.03 from 1998,
primarily because of the inclusion of the Arch Western

operations for all of 1999 compared to only seven months during 1998. Western
coal, especially Powder River Basin coal, has a significantly lower average
sales price than that of eastern coal, but is also significantly less costly to
mine.

Income from Operations. Excluding the one-time charges discussed above,
income from operations decreased $27.2 million despite the inclusion of the
Arch Western operations for the entire year compared to only seven months in
1998. Net gains on the disposition of assets were $7.5 million in 1999 compared
to $41.5 million in 1998. The gain in 1998 included a pre-tax gain of $18.5
million on the sale of assets and idle properties in eastern Kentucky and a
pre-tax gain of $7.5 million on the sale of our idle Big Sandy Terminal. The
operating results in 1999 also included pre-tax gains of $5.0 million related
to settlements with various suppliers. Operating results in 1999 were
negatively affected by production shortfalls, generally less favorable mining
conditions and lower operating income from our idled Dal-Tex mine complex.
Operating results were also negatively affected in 1999 at Mingo Logan, where,
despite a contribution of $46.6 million of operating income, results were
significantly below the $77.8 million contributed to income from operations in
1998. The decrease was primarily caused by depressed coal prices, generally
less favorable mining conditions and increased mine development expenses
associated with the start-up of mining in the Alma seam during 1999. The
Mountaineer Mine contributed 12% and 15% of our coal sales revenues in 1999 and
1998, respectively. During the first half of 1999, we continued to experience
production shortfalls and operating challenges at our Black Thunder mine in
Wyoming due to geological, water drainage and equipment sequencing problems.
The negative impacts discussed above were partially offset by lower operating
losses in 1999 at the Arch of Kentucky operation compared to 1998. The Arch of
Kentucky operation was shut down in January 1998. Results during 1998 were
impacted by the costs associated with the shut down of that operation.

Selling, General and Administrative Expenses. Selling, general and
administrative expenses increased $1.6 million primarily due to the inclusion
of the Arch Western operations for the entire year compared to only seven
months in 1998, the restructuring charge discussed above and additional legal
and other expenses related to surface-mining issues in West Virginia.

Amortization. Sales contract amortization increased $2.0 million
primarily from the inclusion of a full year of the Arch Western operations
compared to seven months in 1998.

Interest Expense. Interest expense increased $27.9 million due to the
increase in debt associated with the June 1998 Arch Western acquisition.

Income Taxes. The income tax benefit recorded in 1999 resulted from the
pre-tax loss, offset by the valuation allowance recorded against our deferred
tax assets. We believe that taxable income will be generated by us in future
periods that is consistent with historical income levels and will, more likely
than not, permit the realization of the net deferred tax assets remaining at
December 31, 1999. We expect to recognize part of the benefit of our deferred
tax asset at the alternative minimum tax rate of approximately 24%. Our
effective tax rate is sensitive to changes in annual profitability and
percentage depletion.

Adjusted EBITDA. Adjusted EBITDA was $325.9 million for 1999 compared to
$313.5 million for 1998. The increase in adjusted EBITDA is primarily
attributable to an inclusion of an entire year of Arch Western operations in
our financial results compared to only seven months in 1998.

Year Ended December 31, 1998 Compared to Year Ended December 31, 1997.

Net Income. Net income for 1998 was $30.0 million compared to $30.3
million for 1997. The 1998 results included a full year of operating results
from the former Ashland Coal operations, whereas 1997 included only six months
of results from those operations. In addition, 1998 included results of the
Arch Western operations from June 1, 1998, including a 65% share of Canyon Fuel
income, net of purchase accounting adjustments.

Revenues. Total revenues of $1.506 billion for 1998 increased 41% from
1997 as a result of the inclusion of a full year of results from the former
Ashland Coal operations in 1998 and seven months of operating results from the
Arch Western operations, including income from our equity investment in Canyon
Fuel. On a per-ton-sold basis, however, our average selling price decreased by
$7.93, primarily because of the inclusion of the Arch Western operations.
Western coal, especially Powder River Basin coal, has a significantly lower
average sales price than that of eastern coal, but is also significantly less
costly to mine. Selling prices in 1998 were also affected by adverse market
conditions in the western United States and export markets, as well as by
reduced seasonal demand caused by unusually warm winter weather.

Income from Operations. Net income for 1998 approximated that for 1997
despite the Arch Western acquisition and the inclusion of a full year of
results in 1998 from the former Ashland Coal operations. Operating results were
favorably impacted in 1998 by increased production from our Mingo Logan
longwall operation. This positive result was offset, in part, by production
shortfalls, deterioration of mining conditions and resulting lower net income
contributions from our Dal-Tex and Hobet mining complexes in Central Appalachia
and the June 1998 closure of our large surface operation in Illinois as a
result of reserve depletion. In particular, as a result of the continued delay
in receiving new mining permits because of the Dal-Tex litigation, the Dal-Tex
operation was forced to operate in less favorable mining areas with higher
overburden ratios and lower productivity, resulting in higher production costs.
Our 1998 results were also significantly impacted by operating difficulties at
the Arch Western operations. We experienced production shortfalls and operating
challenges at our Black Thunder mine in Wyoming due to geological, water
drainage and equipment sequencing problems and substantial transportation
delays at our West Elk mine in Colorado. In addition, Canyon Fuel experienced
difficult geological conditions at its Skyline Mine. Other items adversely
affecting 1998 results, as compared to 1997 results, included the expiration of
an above-market-price long-term coal supply contract with Georgia Power in
December 1997, reduced shipments under another above-market-price long-term
coal supply contract in 1998, the completion in 1997 of a $10.8 million annual
accretion of a 1993 unrecognized net gain related to pneumoconiosis, or black
lung, liabilities, and a net increase in reclamation costs of $4.9 million in
1998 compared to a benefit in 1997 of $4.4 million resulting from an adjustment
of our reclamation liability. Operating results in 1998 included gains from the
disposition of assets of $41.5 million compared to $4.8 million in 1997. The
gain in 1998 included pre-tax gains of $18.5 million on the sale of assets and
idle properties in eastern Kentucky and $7.5 million on the sale of our idle
Big Sandy Terminal. Results for 1997 were also affected by a one-time charge of
$23.8 million, net of a tax benefit of $15.3 million, related to the Ashland
Coal merger.

Selling, General and Administrative Expenses. Selling, general and
administrative expenses increased $15.9 million primarily due to the effects of
the Ashland Coal merger and the Arch Western acquisition.

Amortization. As a result of the amortization of the carrying value of
the sales contracts acquired in the Ashland Coal merger and the Arch Western
acquisition, amortization of coal supply agreements increased $16.5 million.

Interest Expense. Interest expense increased $44.4 million due to the
increase in debt as a result of the Arch Western acquisition.

Extraordinary Item. During 1998, we incurred an extraordinary charge of
$1.5 million, net of a tax benefit of $0.9 million, related to the early
extinguishment of debt in connection with the refinancing of our debt in
connection with the Arch Western acquisition.

Adjusted EBITDA. Adjusted EBITDA was $313.5 million for 1998 compared to
$224.6 million for 1997. The increase in adjusted EBITDA is primarily
attributable to the Ashland Coal merger and the Arch Western acquisition.

Liquidity And Capital Resources

We have generally satisfied our working capital requirements and funded
our capital expenditures and debt-service obligations with cash generated from
operations. We believe that cash generated from operations and our borrowing
capacity will be sufficient to meet our working capital requirements,
anticipated capital expenditures and scheduled debt payments for at least the
next several years. Our ability to satisfy our debt service obligations, to
fund planned capital expenditures, to make acquisitions and to pay dividends
will depend upon our future operating performance, which will be affected by
prevailing economic conditions in the coal industry and financial, business and
other factors, some of which are beyond our control.

Cash Flows.

The following is a summary of cash provided by or used in each of the
indicated types of activities for the periods presented.

Nine Months Ended
Year Ended December 31, September 30,
--------------------------------- --------------------
1997 1998 1999 1999 2000
--------- ----------- --------- --------- ---------
(dollars in thousands)

Cash provided by (used
in): (unaudited)
Operating activities... $ 190,263 $ 188,023 $ 279,963 $ 195,964 $ 127,257
Investing activities... (80,009) (1,271,371) (84,358) (65,342) (106,978)
Financing activities... (114,793) 1,101,585 (219,736) (153,896) (22,009)

Cash provided by operating activities decreased in the nine months ended
September 30, 2000 compared to the same period in 1999 due to a decrease in
cash provided from equity investments, and reduced cash from sales, increased
costs resulting from the temporary idling of the West Elk mine and increased
fuel costs. These were partially offset by increased receivable collections and
an increase in accounts payable and accrued expenses in the nine months ended
September 30, 2000 when compared to the prior year's period. The decrease in
cash provided from equity investments results primarily from the amendment in
the prior year of a coal supply agreement with the Intermountain Power Agency,
which was a significant portion of the $72.8 million cash distribution from
Canyon Fuel to us during the nine months ended September 30, 1999. Cash
provided by operating activities increased substantially during 1999 compared
to 1998 primarily as a result of a full year of operations from our Arch
Western mines in 1999 compared to only seven months of operations in 1998. The
slight decrease in cash provided by operating activities from 1997 to 1998 was
principally due to increased interest expense as a result of increased
borrowings associated with the Arch Western acquisition and tax payments
related to adjustments to income taxes payable in prior years. The decrease was
partially offset by increased operating activity resulting from the Arch
Western acquisition.

Cash used in investing activities increased in the nine months ended
September 30, 2000 compared to the same period in 1999 primarily as a result of
making the second of five annual $31.6 million payments under the Thundercloud
federal lease which is related to the Black Thunder mine in Wyoming. The first
payment was made at the time of the acquisition of the lease in 1998.
Subsequent annual payments were made in January 2000 and 2001. The remaining
payments are due in January 2002 and 2003. In addition, during the nine months
ended September 30, 2000, we purchased all remaining assets under a 1998 sale
and leaseback arrangement for $45.0 million. Comparisons between 2000 and 1999
are also affected by the amendment of a coal supply agreement during 1999. The
amendment changed the contract terms from above-market to market-based pricing.
As a result of the amendment, we received proceeds of $14.1 million from the
customer (net of royalty and tax obligations) during the first quarter of 1999.
The decrease in cash used in investing activities in 1999 compared to 1998
resulted primarily from the payment of $1.1 billion in cash in connection with
the Arch Western acquisition completed in 1998. The Arch Western acquisition
was also the reason for the significant increase in cash used for investing
activities in 1998 compared to 1997.

Our expenditures for property, plant and equipment were $103.1 million
for the nine months ended September 30, 2000, and $98.7 million, $141.7 million
and $77.3 million for 1999, 1998 and 1997, respectively. We make capital
expenditures to improve and replace existing mining equipment, expand existing
mines, develop new mines and improve the overall efficiency of mining
operations. We anticipate that these capital expenditures will be funded by
available cash and existing credit facilities.

Cash provided by financing activities for the nine months ended September
30, 2000 reflects reduced debt payments in the current period compared to the
same period in the prior year. In addition, during the second quarter of 2000,
we entered into a sale and leaseback arrangement with respect to certain
equipment which resulted in net proceeds of $13.4 million. Dividend payments
decreased $6.6 million in the nine months ended September 30, 2000 as compared
to the same period in the prior year, resulting from a decrease in shares
outstanding, and a reduction in the quarterly dividend from 11.5 cents per
share to 5.75 cents per share. The dividend reduction is attributable to our
goal to aggressively reduce debt. Cash used in financing activities during 1999
principally reflects debt reduction of $189.1 million. We were able to reduce
debt from greater cash flows generated from operations. Cash provided by
financing activities in 1998 reflects an increase in borrowings of $1.1 billion
associated with the Arch Western acquisition.

Credit Facilities.

In connection with the Arch Western acquisition, we entered into two new
five-year credit facilities: a $675 million non-amortizing term loan, or the
Arch Western credit facility, and a $900 million credit facility, or the Arch
Coal credit facility, including a $300 million fully amortizing term loan and a
$600 million revolving credit facility. Borrowings under the Arch Coal credit
facility were used to finance the acquisition of ARCO's Colorado and Utah coal
operations, to pay related fees and expenses, to refinance existing corporate
debt and for general corporate purposes. Borrowings under the Arch Western
credit facility were used to fund a portion of a $700 million cash distribution
by Arch Western to ARCO, which occurred simultaneously with ARCO's contribution
of its Wyoming coal operations and other assets to Arch Western. The $675
million term loan is secured by Arch Western's membership interests in its
subsidiaries. We have not guaranteed the Arch Western credit facility. At
September 30, 2000, there was $231.0 million available to borrow under our
revolving credit facility.

We are exposed to market risk associated with interest rates. At
September 30, 2000, our debt included $1.147 billion of floating-rate debt, for
which the rate of interest is, at our option, the PNC Bank base rate or a rate
based on LIBOR and current market rates for bank lines of credit. To manage
this exposure, we enter into interest-rate swap agreements to modify the
interest-rate characteristics of outstanding debt. At September 30, 2000, we
had interest-rate swap agreements having a total notional value of $755.0
million. These swap agreements are used to convert variable-rate debt to fixed-
rate debt. Under these swap agreements, we pay a weighted average fixed rate of
5.75% (before the credit spread over LIBOR) and receive a weighted average
variable rate based upon 30-day and 90-day LIBOR. At September 30, 2000, the
remaining term of the swap and collar agreements ranged from 23 to 57 months.
We accrue amounts to be paid or received under interest-rate swap agreements
over the lives of the agreements. These amounts are recognized as adjustments
to interest expense over the lives of agreements, thereby adjusting the
effective interest rate on our debt. The fair value of the swap agreements are
not recognized in the financial statements. Gains and losses on terminations of
interest-rate swap agreements are deferred on the balance sheet (in other long-
term liabilities) and amortized as an adjustment to interest expense over the
remaining term of the terminated swap agreement. All instruments are entered
into for other than trading purposes.

Financial covenants contained in our 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 we do not permit the ratio of our
total indebtedness at the end of any calendar quarter to adjusted EBITDA for
the 12 months then ended to exceed a specified amount. The fixed charge
coverage ratio requires us to maintain the ratio of our adjusted EBITDA plus
lease expense to our interest expense plus lease expense for the 12 months then
ended

above a specified amount. The net worth test requires that we do not permit our
net worth to be less than a specified amount plus 50% of cumulative net income.
At December 31, 1999, as a result of the effect of the write-down of impaired
assets and other restructuring costs, we did not comply with the net worth
test. At that date, we were required to have a net worth of at least $508.4
million. After giving effect to the write-down of impaired assets and other
restructuring costs, our net worth was $241.3 million at that date. We received
an amendment to the credit facilities on January 21, 2000 which reset the net
worth requirement to $163.0 million at December 31, 1999. These amendments
resulted in, among other things, a one-time payment of $1.8 million and an
increase in the interest rate of 0.375% associated with our term loan and the
revolving credit facility. In addition, the amendments required us to pledge
assets to collateralize the term loan and the revolving credit facility,
including the stock of some of our subsidiaries, some real property interests,
accounts receivable and inventory. We were in compliance with these financial
covenants at December 31, 2000.

At September 30, 2000, our debt amounted to $1.152 billion, or 84% of
capital employed, compared to $1.181 billion, or 83% of capital employed, at
December 31, 1999. Based on our current level of consolidated indebtedness and
prevailing interest rates, our debt service obligations, including optional
payments associated with the revolving credit facility, for the 12 months
ending September 30, 2001 will be approximately $180 million.

We periodically establish uncommitted lines of credit with banks. These
agreements generally provide for short-term borrowings at market rates. At
September 30, 2000, there were $20.0 million of these agreements in effect,
none of which were outstanding.

Lease and Royalty Obligations.

We lease equipment, land and various other properties under non-
cancelable long-term leases expiring at various dates. Minimum payments due
during the 12 months ending September 30, 2001, under agreements in effect at
September 30, 2000, will be approximately $84 million.

Contingencies

Reclamation.

The federal Surface Mining Control and Reclamation Act of 1977 and
similar state statutes require that mine property be restored in accordance
with specified standards and an approved reclamation plan. Reclamation is the
restoration of land and environmental conditions of a mining site after the
coal is removed. We accrue for the costs of final mine closure and 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 water and waste rock or coal
sediment mixtures, eliminating sedimentation and drainage control structures
and dismantling or demolishing equipment or buildings used in mining
operations. We also accrue 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 other ongoing reclamation liabilities
are based upon permit requirements and require various estimates and
assumptions, principally associated with costs and productivities.

We review our entire environmental liability periodically and make
necessary adjustments, including permit changes and revisions to costs and
productivities to reflect current experience. These adjustments are recorded to
cost of coal sales. Adjustments included a decrease in the liability of $9.2
million in the nine months ended September 30, 2000. The adjustments occurred
principally as a result of recent permit revisions at our idle mine properties
in Illinois. Adjustments recorded in the nine months ended September 30, 1999
resulted in a $0.7 million charge to expense. We believe that we are making
adequate provisions for all expected reclamation and other associated costs.

Legal Contingencies.

We are a party to numerous claims and lawsuits with respect to various
matters. We provide for costs related to contingencies, including environmental
matters, when a loss is probable and the amount is reasonably determinable. We
estimate that our probable aggregate loss as a result of claims as of September
30, 2000 is $4.0 million, which amount is included in other noncurrent
liabilities on our balance sheet. This amount does not include losses that may
be incurred as a result of the temporary or permanent shutdown of the Dal-Tex
operations. For a discussion of this litigation, see "Business--Legal
Proceedings--Dal-Tex Litigation". We estimate that our reasonably possible
aggregate losses from all material litigation that is currently pending could
be as much as $0.5 million on a pre-tax basis in excess of the probable loss
previously recognized. After conferring with counsel, we believe that the
ultimate resolution of these claims, to the extent not previously provided for,
will not have a material adverse effect on our consolidated financial
condition, results of operations or liquidity. For a more complete discussion
of litigation to which we are a party, see "Business--Legal Proceedings."

BUSINESS

Operations

As of September 30, 2000, we operated a total of 28 mines, all located in
the United States. Coal is transported from our mining complexes to customers
by railroad cars, river barges and trucks. As is customary in the industry,
virtually all of our coal sales are made F.O.B. mine or loadout, meaning that
customers are responsible for the cost of transporting purchased coal to their
facilities. The following tables set forth the location of and a summary of
information regarding our principal mining complexes and the recoverable coal
reserves associated with these operations.

Captive Contract Mining
Mining Complex (Location) Mines* Mines* Equipment(1) Transportation
-------------------------- ------- -------- ------------ --------------

Central Appalachia
Mingo Logan (WV)................... U U(4), S L, LW, C NS
Coal-Mac (KY)(5)................... S S L CSX
Dal-Tex (WV)(6).................... -- -- D, L, S CSX
Hobet 21 (WV)...................... S, U U D, L, S(7) CSX
Arch of West Virginia (WV)......... S, U -- D, L, S(8) CSX
Samples (WV)....................... S -- D, L, S(9) Barge, CSX
Campbells Creek (WV)............... -- U(2) -- Barge
Lone Mountain (KY)................. U(2) -- C NS
Pardee (VA)........................ S, U U L,C NS
Western United States
Black Thunder (WY)................. S -- D, S(10) UP, BN
Coal Creek (WY)(11)................ -- -- -- UP, BN
West Elk (CO)(12).................. U -- LW, C UP
Skyline (UT)(13)................... U -- LW, C UP
SUFCO (UT)(13)..................... U -- LW, C UP
Dugout Canyon (UT)(13)............. U -- C(14) UP
Arch of Wyoming (WY)............... S(2) -- D, S(15) UP
Midwestern United States
Arch of Illinois (IL)(16).......... -- -- C UP, IC

S = Surface Mine D = Dragline UP = Union Pacific Railroad
U = Underground Mine L = Loader/Truck IC = Illinois Central Railroad
S = Shovel/Truck BN = Burlington Northern Railroad
LW = Longwall NS = Norfolk Southern Railroad
C = Continuous Miner CSX = CSX Railroad

Tons Total
Tons Produced in Produced in Cost(4)/ Assigned
--------------------- the Nine Book Value Recoverable
1997(2) 1998(3) 1999 Months Ended As of Reserves Proven Probable
------- ------- ----- September 30, 2000 December 31, 1999 ----------- ------- --------
Mining Complex (Location) (in millions) (in millions) ($ in millions) (tonnage in millions)
-------------------------- --------------------- ------------------ ----------------- ----------------------------

Central Appalachia
Mingo Logan (WV)........ 4.7 11.0 12.2 8.1 $133/67 22.4 11.0 11.4
Coal-Mac (KY)(5)........ 0.8 1.5 1.0 -- 14/4 5.9 3.2 2.7
Dal-Tex (WV)(6)......... 2.5 4.6 2.3 -- 10/3 84.2 69.8 14.4
Hobet 21 (WV)........... 2.0 4.1 5.1 4.2 45/31 88.9 84.6 4.3
Arch of West Virginia
(WV)................... 4.9 5.5 4.7 2.7 120/25 19.6 19.6 --
Samples (WV)............ 4.4 4.9 5.9 4.8 115/48 27.5 27.5 --
Campbells Creek (WV).... 0.8 0.9 1.2 1.0 3/1 11.6 11.6 --
Lone Mountain (KY)...... 2.0 2.4 2.3 1.7 85/36 60.6 55.1 5.5
Pardee (VA)............. 2.5 1.4 1.7 1.3 34/11 9.3 5.6 3.7
Arch of Kentucky (KY)... 3.9 -- -- -- --
Western United States
Black Thunder (WY)...... -- 24.7 50.9 44.7 226/203 1,052.5 1,028.2 24.3
Coal Creek (WY)(11)..... -- 4.4 11.4 4.2 41/37 238.6 238.6 --
West Elk (CO)(12)....... -- 3.9 7.3 1.8 96/71 141.3 118.0 23.3
Skyline (UT)(13)........ -- 2.4 3.8 2.2 N/A 79.6 79.6 --
SUFCO (UT)(13).......... -- 3.7 5.8 4.3 N/A 117.9 50.5 67.4
Dugout Canyon (UT)(13).. -- 0.2 0.8 0.4 N/A 34.1 28.3 5.8
Arch of Wyoming (WY).... 2.2 1.3 1.0 0.6 58/4 0.4 0.4 --
Midwestern United States
Arch of Illinois
(IL)(16)............... 4.9 3.5 2.4 -- 107/3 20.0 20.0 --
---- ---- ----- ---- ------- ------- -----
Total................. 35.6 80.4 119.8 82.0 2,014.4 1,851.6 162.8

--------
* Amounts in parenthesis indicate the number of captive and contract mines at
the mining complex or location. Captive mines are mines which we own and
operate on land owned or leased by us. Contract mines are mines which other
operators mine for us under contracts on land owned or leased by us.

(1) Reported for captive operations only.

(2) Represents six months production for the mines acquired in the Ashland
Coal transaction, including Mingo Logan, Hobet 21, Dal-Tex and Coal-Mac.

(3) Represents seven months production for the mines acquired in the Arch
Western transaction, including Black Thunder, Coal Creek, West Elk,
Skyline, SUFCO and Dugout Canyon. Skyline, SUFCO and Dugout Canyon are
mines operated by Canyon Fuel; production represents 100% for these
facilities.

(4) Reflects the cost of plant and equipment, including purchase accounting
adjustments.

(5) We idled the two captive mining operations at our Coal-Mac (KY) complex on
January 3, 2000 because of the small surface mines' high cost structure
compared to our larger mines.

(6) We idled our mining operations at the Dal-Tex complex on July 23, 1999 due
to a delay in obtaining mining permits resulting from legal action in the
U.S. District Court for the Southern District of West Virginia. See "Legal
Proceedings--Dal-Tex Litigation" for further discussion regarding this
legal action.

(7) Utilizes an 83-cubic-yard dragline and a 51-cubic-yard shovel. A dragline
is a large machine used in the surface mining process to remove layers of
earth and rock covering coal.

(8) Utilizes a 49-cubic-yard dragline, a 43-cubic-yard shovel, a 22-cubic-yard
shovel and a 28-cubic-yard loader at the Ruffner Mine.

(9) Utilizes a 118-cubic-yard dragline, two 53-cubic-yard shovels, a 22-cubic-
yard hydraulic excavator, three 28-cubic-yard loaders, and one 23 cubic
yard loader.

(10) Utilizes 170-cubic-yard, 130-cubic-yard, 90-cubic-yard and 45-cubic-yard
draglines and 82-cubic-yard, 60-cubic-yard and 53-cubic-yard shovels.

(11) We idled our mining operations at Coal Creek during the third quarter of
2000 because its cost structure was not competitive in the current market
environment.

(12) We temporarily idled our mining operations at West Elk from January 28,
2000 to July 12, 2000 following the detection of higher than normal
levels of carbon monoxide in a portion of the mine.

(13) Mines are operated by Canyon Fuel. Canyon Fuel is an equity investment
and its financial statements are not consolidated into our financial
statements.

(14) Currently under development, full production projected to begin with the
addition of a longwall when market conditions warrant.

(15) Utilizes 76-cubic-yard and 64-cubic-yard draglines at Medicine Bow and a
32-cubic-yard dragline at Seminoe II.

(16) We idled our remaining operations at the Arch of Illinois mining complex
and sealed the underground mine in December 1999 due to a lack of demand
for the mine's high-sulfur coal. The mining complex was the last of our
mining operations in the Midwestern United States.

Coal Reserves

We estimate that we owned or controlled, as of December 31, 1999,
approximately 3.5 billion tons of measured and indicated recoverable reserves,
approximately 2.0 billion tons of which were assigned reserves and
approximately 1.5 billion tons of which were unassigned reserves. Assigned
reserves are recoverable coal reserves that have been designated to be mined by
a specific operation. Unassigned reserves are recoverable reserves that have
not yet been designated for mining by a specific operation. Recoverable
reserves include only saleable coal and do not include coal which would remain
unextracted, such as for support pillars, and processing losses, such as
washery losses. Reserve estimates are prepared by our engineers and geologists
and reviewed and updated periodically. Total recoverable reserve estimates and
reserves dedicated to mines and complexes change from time to time to reflect
mining activities, analysis of new engineering and geological data, changes in
reserve holdings and other factors. The following table presents our estimated
recoverable coal reserves at December 31, 1999:

Total Recoverable Reserves (tonnage in millions)

Sulfur Content
(lbs. per million Reserve
Total Btus) Control Mining Method
Recoverable ------------------ ------------ -------------------
Reserves Proven Probable -1.2 1.2-2.5 +2.5 Owned Leased Underground Surface
----------- ------ -------- ----- ------- ---- ----- ------ ----------- -------

Wyoming................. 1,455 1,431 24 1,455 -- -- 150 1,305 134 1,321
Central Appalachia...... 1,332 914 418 568 708 56 513 819 604 728
Illinois................ 299 218 81 -- 9 290 249 50 270 29
Utah*................... 233 159 74 233 -- -- 8 225 233 --
Colorado................ 141 118 23 141 -- -- 3 138 141 --
----- ----- --- ----- --- --- --- ----- ----- -----
Total................. 3,460 2,840 620 2,397 717 346 923 2,537 1,382 2,078
===== ===== === ===== === === === ===== ===== =====

Assigned Recoverable Reserves (tonnage in millions)

Sulfur Content
Total (lbs. per million Reserve
Assigned Btus) Control Mining Method
Recoverable ------------------ ------------ -------------------
Reserves Proven Probable -1.2 1.2-2.5 +2.5 Owned Leased Underground Surface
----------- ------ -------- ----- ------- ---- ----- ------ ----------- -------

Wyoming................. 1,291 1,267 24 1,291 -- -- -- 1,291 -- 1,291
Central Appalachia...... 330 288 42 177 148 5 103 227 146 184
Illinois................ 20 20 -- -- -- 20 20 -- 20 --
Utah*................... 232 159 73 232 -- -- 7 225 232 --
Colorado................ 141 118 23 141 -- -- 2 139 141 --
----- ----- --- ----- --- --- --- ----- --- -----
Total................. 2,014 1,852 162 1,841 148 25 132 1,882 539 1,475
===== ===== === ===== === === === ===== === =====

--------
* Represents 100% of the reserves held by Canyon Fuel, in which we have a 65%
interest.

Unassigned Recoverable Reserves (tonnage in millions)

Sulfur Content
Total (lbs. per million Reserve
Unassigned Btus) Control Mining Method
Recoverable ----------------- ------------ -------------------
Reserves Proven Probable -1.2 1.2-2.5 +2.5 Owned Leased Underground Surface
----------- ------ -------- ---- ------- ---- ----- ------ ----------- -------

Wyoming................. 163 163 -- 163 -- -- 150 13 134 29
Central Appalachia...... 1,002 626 376 392 560 50 410 592 458 544
Illinois................ 279 198 81 -- 9 270 229 50 250 29
Utah*................... 1 1 -- 1 -- -- 1 -- 1 --
Colorado................ -- -- -- -- -- -- -- -- -- --
----- --- --- --- --- --- --- --- --- ---
Total................. 1,445 988 457 556 569 320 790 655 843 602
===== === === === === === === === === ===

--------
* Represents 100% of the reserves held by Canyon Fuel, in which we have a 65%
interest.

Over 98% of our recoverable reserves consists of steam coal, which is
coal used in steam boilers to make electricity. Less than 2% of our recoverable
reserves consists of metallurgical coal, which is a grade of coal used in the
production of steel. Metallurgical coal represents an immaterial amount of our
operations.

Approximately 92,201 acres of our 664,000 acres of coal land as of
December 31, 1999, which includes 100% of the acreage held by Canyon Fuel, are
leased from the federal government under leases with terms expiring between
2001 and 2019, subject to readjustment or extension and to earlier termination
for failure to meet diligent development requirements. We have entered into
leases covering substantially all of our leased reserves which are not
scheduled to expire prior to expiration of projected mining activities. We also
control, through ownership or long-term leases, approximately 5,880 acres of
land which are used either for our coal processing facilities or are being held
for possible future development. Royalties are paid to lessors either as a
fixed price per ton or as a percentage of the gross sales price of the mined
coal. We pay percentage-based royalties under the majority of our significant
leases. The terms of most of these leases extend until the exhaustion of
mineable and merchantable coal. The remaining leases have initial terms ranging
from one to 40 years from the date of their execution, with most containing
options to renew. In some cases, a lease bonus, or prepaid royalty, is
required, payable either at the time of execution of the lease or in annual
installments. In most cases, the prepaid royalty amount is applied to reduce
future production royalties.

We must obtain permits from applicable state regulatory authorities
before we begin to mine reserves. Applications for permits require extensive
engineering and data analysis and presentation, and must address a variety of
environmental, health and safety matters associated with a proposed mining
operation. These matters include the manner and sequencing of coal extraction,
the storage, use and disposal of waste and other substances and other impacts
on the environment, the construction of overburden fills and water containment
areas, and reclamation of the area after coal extraction. We are required to
post bonds to secure our performance under our permits. We generally begin
preparing applications for permits for areas that we intend to mine up to three
years in advance of their expected issuance date.

Regulatory authorities have considerable discretion in the timing of
permit issuance and the public has rights to comment on and otherwise engage in
the permitting process, including through intervention in the courts. We idled
our Dal-Tex operation in West Virginia in June 1999 due to a delay in obtaining
mining permits for mines involving the use of valley fill mining techniques as
a result of litigation. See "Legal Proceedings--Dal-Tex Litigation."

Our reported coal reserves are those that could be economically and
legally extracted or produced at the time of their determination. In
determining whether our reserves meet this standard, we take into account,
among other things, our potential inability to obtain a mining permit, the
possible necessity of revising a mining plan, changes in estimated future
costs, changes in future cash flows caused by changes in costs required to be
incurred to meet regulatory requirements and obtaining mining permits,
variations in quantity and quality of coal, and varying levels of demand and
their effects on selling prices. Except for litigation described under "Legal
Proceedings" with respect to permits to conduct mining operations involving
valley fills (which remains unresolved but has been taken into account in
determining our reserves), we are not currently aware of matters which would
significantly hinder our ability to obtain future mining permits with respect
to our reserves.

Sales and Marketing

We sell coal both under long-term contracts, the terms of which are
greater than 12 months, and on a current market, or spot, basis. When our coal
sales contracts expire or are terminated, we are exposed to the risk of having
to sell coal into the spot market, where demand is variable and prices are
subject to greater volatility. Historically, the price of coal sold under long-
term contracts exceeded prevailing spot prices for coal. However, in the past
several years new contracts have been priced at or near existing spot rates.

The terms of our coal sales contracts result from bidding and extensive
negotiations with customers. Consequently, the terms of these contracts
typically vary significantly in many respects, including price adjustment
features, provisions permitting renegotiation or modification of coal sale
prices, coal quality requirements, quantity parameters, flexibility and
adjustment mechanisms, permitted sources of supply, treatment of environmental
constraints, options to extend and force majeure, suspension, termination and
assignment provisions.

Provisions permitting renegotiation or modification of coal sale prices
are present in many of our more recently negotiated long-term contracts and
usually occur midway through a contract or every two to three years, depending
upon the length of the contract. In some circumstances, customers have the
option to terminate the contract if prices have increased by a specified
percentage from the price at the commencement of the contract or if the parties
cannot agree on a new price. The term of sales contracts has decreased
significantly over the last two decades as competition in the coal industry has
increased and, more recently, as electricity generators have prepared
themselves for federal Clean Air Act requirements and the impending
deregulation of their industry.

There are some contract terms that differ between a standard "eastern
United States" contract and a standard "western United States" contract. In the
eastern United States, many customers require that the coal be sampled and
weighed at the destination. In the western United States, virtually all samples
are taken at the source. More eastern United States coal is purchased on the
spot market. The eastern United States market has more recently been a shorter-
term market because of the larger number of smaller mining operations in that
region. Western United States contracts sometimes stipulate that some
production taxes and coal royalties be reimbursed in full by the buyer rather
than as a pricing component within the contract. These items comprise a
significant portion of western United States coal pricing.

A factor that may impact our sale of coal in the future is the
development of coal commodity trading. The New York Mercantile Exchange
initiated electricity commodity trading a few years ago and has developed
standards for a coal contract. The Exchange has announced that it intends to
initiate coal contract trading based on a Huntington, West Virginia barge
loading hub. However, the Exchange has not yet initiated trading. The
development of standards to determine pricing has been difficult because of the
non-homogeneous character of coal and diversity in mining locations, conditions
and operations. Nonetheless, in anticipation of commodity trading, some
brokerage and marketing firms have entered the coal markets and devised
transactions that mimic commodity activity. Today, limited, but growing, over-
the-counter trading is being conducted on both firm-forward transactions as
well as put, call and other options. The trend to more commodity-type
transactions could mark a significant change in how coal is sold. We are unable
to predict whether this trend will have a material effect on us and whether any
such effect would be positive or negative on our operating results.

Competition

The coal industry is intensely competitive, primarily as a result of the
existence of numerous producers in the coal producing regions in which we
operate. We compete with approximately six major coal producers in each of the
Central Appalachian and Powder River Basin areas. We also compete with a number
of smaller producers in those and our other market regions. Excess industry
capacity, which has occurred in the past, tends to result in reduced prices for
our coal.

The most important factors on which we compete are coal price at the
mine, coal quality and characteristics, transportation costs from the mine to
the customer and the reliability of supply. Demand for coal and the prices that
we will be able to obtain for our coal are closely linked to coal consumption
patterns of the domestic electric generation industry, which has accounted for
approximately 90% of domestic coal consumption in recent years. These coal
consumption patterns are influenced by factors beyond our control, including
the demand for electricity, which is significantly dependent upon summer and
winter temperatures in the United States, 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 our low-
sulfur coal and the prices that we will be able to obtain for it will also be
affected by the price and availability of high-sulfur coal, which can be
marketed in tandem with emissions allowances in order to meet federal Clean Air
Act requirements.

Environmental Regulations

Federal, state and local governmental authorities regulate the coal
mining industry on matters as diverse as air quality standards, water
pollution, groundwater quality and availability, plant and wildlife protection,
the reclamation and restoration of mining properties, the discharge of
materials into the environment and surface subsidence from underground mining.
These regulations and legislation have had and will continue to have a
significant effect on our costs of production and competitive position. New
legislation, regulations or orders may be adopted or become effective which may
adversely affect our mining operations, our cost structure or the ability of
our customers to use coal. For example, new legislation, regulations or orders
may require us to incur increased costs or to significantly change our
operations. New legislation, regulations or orders may also cause coal to
become a less attractive fuel source, resulting in a reduction in coal's share
of the market for fuels used to generate electricity. Depending upon the nature
and scope of the legislation, regulations or orders, any legislation,
regulation or order could significantly increase our costs to mine coal. For
examples of environmental regulations which would affect our customers see "The
Coal Industry--Clean Air Act".

Permitting.

Mining companies must obtain numerous permits that impose strict
regulations on various environmental and health and safety matters in
connection with coal mining. For example, regulations are imposed on the
emission of air and water borne pollutants, the manner and sequencing of coal
extraction and reclamation, the storage, use and disposal of waste and other
substances, some of which may be hazardous, and the construction of fills and
impoundments, which are wastewater containment areas. Regulatory authorities
have considerable discretion in the timing of permit issuance and both private
individuals and the public at large possess rights to comment on and otherwise
engage in the permitting process, including through intervention in the courts.
For example, we idled our Dal-Tex operation in West Virginia on July 23, 1999
due to a delay in obtaining mining permits which resulted from legal action in
the U.S. District Court for the Southern District of West Virginia. See "Legal
Proceedings--Dal-Tex Litigation" for a discussion of this legal action.

Environmental Legislation.

The federal Surface Mining Control and Reclamation Act of 1977 was
enacted to regulate surface mining of coal and the surface effects of
underground mining. All states in which we operate have similar laws and
regulations enacted under SMCRA which regulate surface and deep mining that
impose, among other requirements, reclamation and environmental requirements
and standards.

The federal Clean Water Act affects coal mining operations in two
principal ways. First, the United States Army Corps of Engineers issues permits
under Section 404 of the Clean Water Act whenever a mine operator proposes to
build a fill or impoundment in waters of the United States. In addition, the
EPA must approve the issuance by a state agency of permits that allow the
discharge of pollutants into water bodies under

Section 402 of the Clean Water Act. These permits encompass storm water
discharges from a mine facility. Regular monitoring and compliance with
reporting requirements and performance standards are preconditions for the
issuance and renewal of these permits. All states in which we operate also have
laws restricting discharge of pollutants into the waters of those states.

The federal Resource Conservation and Recovery Act and implementing
federal regulations exclude from the definition of hazardous waste all coal
extraction, beneficiation and processing wastes. Additionally, other coal
mining wastes which are subject to a SMCRA permit are exempt from RCRA permits
and standards. Each of the states in which we are currently engaged in mining
similarly exempt coal mining waste from their respective state hazardous waste
laws and regulations. The federal Comprehensive Environmental Response,
Compensation and Liability Act of 1980, as amended by the Superfund Amendments
and Reauthorization Act, affects coal mining operations by subjecting them to
liability for the remediation of releases of hazardous substances, other than
waste excluded from federal and state regulation, as noted above, that may
endanger public health or welfare or the environment.

The federal Clean Air Act imposes numerous requirements on various
categories of emission sources, and West Virginia state air regulations impose
permitting obligations and performance standards on coal preparation plants and
coal handling facilities. The use of explosives in surface mining causes
nitrogen oxides, or "NOx", to be emitted into the air. The emissions of NOx
from the use of explosives at surface mines in the Powder River Basin is
gaining increased scrutiny from regulatory agencies and the public. We have
taken steps to monitor the level of NOx emitted during blasting activities at
our surface mines in the Powder River Basin and are continuing efforts to find
a method of reducing these NOx emissions. Any increase in the regulation of NOx
emissions from blasting activities could have an adverse effect on our Powder
River Basin surface mines. Depending upon the nature and scope of any such
regulations, the effect on the mines could be material.

On December 11, 1997, United States government representatives at the
climate change negotiations in Kyoto, Japan, agreed to reduce the emissions of
greenhouse gas in the United States, including carbon dioxide and other gas
emissions that are believed to be trapping heat in the atmosphere and warming
the earth's climate. The adoption of the requirements of the Kyoto protocol by
the United States is subject to conditions which may not occur, and are also
subject to the protocol's ratification by the United States Senate. The United
States Senate has indicated that it will not ratify an agreement unless
specified conditions, not currently provided for in the Kyoto protocol, are
met. At present, it is not possible to predict whether the Kyoto protocol will
attain the force of law in the United States or what its impact would be on us.
Further developments in connection with the Kyoto protocol could increase our
costs to mine coal.

Employees

As of September 30, 2000, we employed a total of 3,361 persons, 558 of
whom were represented by the UMWA under a collective bargaining agreement that
expires in 2002 and 143 of whom are represented by the Scotia Employees
Association under a collective bargaining agreement that expires in 2003.

Legal Proceedings

Dal-Tex Litigation.

On July 16, 1998, ten individuals and The West Virginia Highlands
Conservancy filed suit in the U.S. District Court for the Southern District of
West Virginia against the director of the West Virginia DEP and officials of
the U.S. Army Corps of Engineers alleging violations of SMCRA, the Clean Water
Act and the National Environmental Policy Act. Specifically, plaintiffs made
the following allegations in the suit:

. the Corps violated NEPA by approving mining permits without the
preparation of an EIS under NEPA that would evaluate the
environmental effects of mountaintop mining and the construction of
valley fills;

. the Corps violated the Clean Water Act by issuing generic Section 404
dredge and fill permits rather than site-specific individual permits;

. the West Virginia DEP has failed to require the restoration of mined
lands to approximate original contour and that it has not enforced
approved post-mining land uses following reclamation; and

. the West Virginia DEP lacked authority to issue permits for the
construction of valley fills.

Nine of our permits were identified in the complaint as violating the
legal standards that the plaintiffs requested the court to interpret. In
addition, pending permit applications for our Dal-Tex mining operations, which
are operated by our subsidiary, Hobet Mining, Inc., were specifically
identified as permits that should be enjoined from issuance. These permit
applications, known as the Spruce Fork permits, include a SMCRA mining permit
application requesting authorization from the West Virginia DEP to commence
surface mining operations and a Section 404 permit application requesting
authorization from the Corps to construct a valley fill. We intervened in the
lawsuit in support of the Corps and the West Virginia DEP on August 6, 1998.

Settlement Agreement. A settlement between the plaintiffs and the Corps,
which was reached on December 23, 1998, resolved the Clean Water Act and NEPA
claims against the Corps, except those relating to the Spruce Fork permits. The
settlement agreement requires the Corps, in cooperation with other agencies, to
prepare a programmatic EIS on the effects of valley fills on streams and the
environment. This EIS was scheduled to be completed by January 2001. This date,
however, was not met and there has been no indication from the Corps as to when
the EIS will be completed. Until it is completed, an individual Clean Water Act
Section 404 dredge and fill permit must be obtained prior to the construction
of any valley fill greater than 250 acres. Our Hobet Mining subsidiary later
agreed to apply for an individual Section 404 permit for the Dal-Tex valley
fill, which will require the preparation of an EIS to evaluate the effects of
the valley fill on the environment.

Preliminary Injunction. Subsequent to the settlement agreement, the West
Virginia DEP approved the Spruce Fork SMCRA permit. Plaintiffs sought a
preliminary injunction staying the Spruce Fork permit and enjoining us from
future operations on the permit until a full trial on the merits could be held.
The district court issued the preliminary injunction on March 3, 1999. As a
result, we idled the Dal-Tex mine on July 23, 1999.

Consent Decree. On July 26, 1999, the plaintiffs and the West Virginia
DEP submitted a proposed consent decree which would resolve the remaining
issues in the case, except those relating to the West Virginia DEP's authority
to issue permits for the construction of valley fills. Under the proposed
consent decree, the West Virginia DEP agreed in principle to amend its
regulations and procedures to correct alleged deficiencies. In addition, the
parties agreed in principle on a new definition of approximate original contour
as it applies to mountaintop mining, as well as to regulatory changes involving
post-mining land uses. Our Hobet Mining subsidiary agreed as part of the
consent decree to revise portions of its Spruce Fork permit applications to
conform to the new definition of approximate original contour to be adopted by
the West Virginia DEP. After inviting public comment on the proposed consent
decree, the court entered the consent decree in a final order on February 17,
2000, and the West Virginia legislature approved the West Virginia DEP's
proposed statutory and regulatory changes to implement the consent decree on
April 3, 2000.

Permanent Injunction. On October 20, 1999, the district court addressed
the remaining counts in the plaintiffs' complaint by issuing a permanent
injunction against the West Virginia DEP enjoining the issuance of any new
permits that authorize the construction of valley fills as part of mining
operations. The West Virginia DEP complied with the injunction by issuing an
order banning the issuance of permits for nearly all new valley fills and the
expansion of existing valley fills. The West Virginia DEP also filed an appeal
of the district court's decision with the U.S. Court of Appeals for the Fourth
Circuit. On October 29, 1999, the district court granted a stay of its
decision, pending the outcome of the appeal. The West Virginia DEP rescinded
its administrative order on November 1, 1999 in response to the district
court's action.

The U.S. Court of Appeals for the 4th Circuit heard oral arguments in
this case on December 7, 2000 and is expected to render an opinion in the first
half of 2001. We cannot predict the outcome of the West Virginia DEP's appeal.
If the district court's decision is upheld, we, and other coal producers, may
be forced to close all or a portion of our mining operations in West Virginia,
to the extent those operations are dependent on the use of valley fills. If we
are successful on appeal, then we could be required to complete the EIS for the
Section 404 dredge and fill permit and comply with the conditions imposed on
the Spruce Fork permit as a result of the consent decree, each of which could
delay the issuance of the Spruce Fork permit and, consequently, the reopening
of the mine until mid-2001 at the earliest. If all necessary permits are
issued, we may determine to reopen the mine subject to then-existing market
conditions.

Cumulative Hydrologic Impact Assessment Litigation.

On January 20, 2000, two environmental organizations, the Ohio Valley
Environmental Coalition and the Hominy Creek Watershed Association, filed suit
against the West Virginia DEP in the U.S. District Court in Huntington, West
Virginia. In addition to allegations that the West Virginia DEP violated state
law and provisions of the Clean Water Act, the plaintiffs allege that the West
Virginia DEP's issuance of permits for surface and underground coal mining has
violated non-discretionary duties mandated by SMCRA. Specifically, the
plaintiffs allege that the West Virginia DEP has failed to require coal
operators seeking permits to conduct water monitoring to verify stream flows
and ascertain water quality, to always include specified water quality
information in their permit applications and to analyze the probable hydrologic
consequences of their operations. The plaintiffs also allege that the West
Virginia DEP has failed to analyze the cumulative hydrologic impact of mining
operations on specific watersheds.

The plaintiffs seek an injunction to prohibit the West Virginia DEP from
issuing any new permits which fail to comply with all of the elements
identified in their complaint. The complaint identifies, and seeks to enjoin,
three pending permits that are sought by our Mingo Logan subsidiary to continue
existing surface mining operations at the Phoenix reserve. On January 15, 2001,
the West Virginia DEP notified the plaintiffs that we have completed all steps
necessary to obtain the permits. A hearing was held on February 14, 2001 on the
plaintiffs' motion for a preliminary injunction seeking to enjoin the DEP's
decision to issue the permits. If the permits are not issued, it is possible
that those operations will have to be suspended in early 2001. We cannot
predict whether this litigation will result in a suspension of the affected
surface mining operations. If, however, the operations are suspended, our
ability to mine surface coal at Mingo Logan could be adversely affected and,
depending upon the length of suspension, the effect could be material.

Lone Mountain Litigation.

On October 24, 1996, the rock strata overlaying an abandoned underground
mine adjacent to the coal-refuse impoundment used by the Lone Mountain
preparation plant failed, resulting in the discharge of approximately 6.3
million gallons of water mixed with fine coal refuse into a tributary of the
Powell River in Lee County, Virginia. The U.S. Department of the Interior has
notified us that it intends to file a civil action under the Clean Water Act
and the Comprehensive Environmental Response, Compensation and Liability Act to
recover the natural resource damages suffered as a result of the discharge. The
Interior Department alleges that fresh water mussels listed on the federal
endangered species list that reside in the Powell River were affected as a
consequence of the discharge. We and the Interior Department have reached an
agreement in principle to settle this matter, which would require us to make a
payment of $2.5 million. The settlement is subject to us and the Interior
Department entering into a definitive agreement. The Interior Department
initiated the final administrative steps to complete settlement of this claim,
and, following a period of public comment, we expect to make the settlement
payment in February 2001. Our consolidated balance sheet as of September 30,
2000 reflects a reserve for the full amount of this settlement.

THE COAL INDUSTRY

United States Coal Markets

Production of coal in the United States has increased from 434 million
tons in 1960 to over 1 billion tons in 1999. The following table sets forth
demand trends for United States coal by consuming sector through 2020 as
compiled, estimated(e) or forecasted(f) by the United States Department of
Energy/Energy Information Agency.

Annual
Growth
1998-
Consumption by Sector 1997 1998 1999e 2005f 2010f 2015f 2020f 2020f
--------------------- ----- ----- ----- ----- ----- ----- ----- ------
(tons in millions)

Electric Generation........... 922 939 940 1,070 1,092 1,129 1,177 1.0%
Industrial.................... 71 69 66 73 73 74 75 0.4%
Steel Production.............. 30 28 28 26 23 21 20 (1.6%)
Residential/Commercial........ 6 6 5 7 7 7 7 0.4%
Export........................ 84 78 58 62 64 57 58 (1.4%)
----- ----- ----- ----- ----- ----- -----
Total....................... 1,113 1,120 1,097 1,238 1,259 1,288 1,337 0.9%
===== ===== ===== ===== ===== ===== =====

Electricity Generation

Coal has consistently maintained a 50% to 53% market share over competing
energy sources to generate electricity during the past ten years because of its
relatively low cost and its availability throughout the United States. On an
average, all-in cost per megawatt-hour basis, coal-fired generation is
substantially less expensive than electricity generated utilizing natural gas,
oil or nuclear power. Hydroelectric power is inexpensive but is limited
geographically, and there are few suitable sites for new hydroelectric power
dams. Consequently, approximately 86% of the coal produced in the United States
in 1999 was sold in the domestic market as a fuel to the electric generation
segment. The remainder of the tons were sold in 1999 as steam coal for
industrial and residential purposes, into the export market, and as
metallurgical coal. In addition to the relative competitiveness of coal-fired
generation plants, coal consumption patterns are also influenced by the demand
for electricity, governmental regulation impacting coal production and power
generation, technological developments and the location, availability and
quality of competing sources of coal, as well as alternative fuels such as
natural gas, oil and nuclear and alternative energy sources such as
hydroelectric power.

Long-term demand for electric power will depend upon a variety of
economic, regulatory, technological and climatic factors beyond our control.
Historically, domestic demand for electric power has increased as the United
States economy has grown. Two important regulatory initiatives, one designed to
increase competition among utilities and lower the cost of electricity for
consumers, and another to improve air quality by reducing the level of sulfur
emitted from coal-burning power generation plants, have had and are expected to
continue to have significant effects on the electric utility industry and its
coal suppliers.

According to the Energy Information Agency, coal is expected to remain
the primary fuel for electricity generation through 2020. The following table
sets forth the source fuel for electricity generation from 1990 through 2020 as
compiled, estimated(e) or forecasted(f) by the Energy Information Agency.

1990 1995 1999e 2000f 2005f 2010f 2015f 2020f
----- ----- ----- ----- ----- ----- ----- -----
(billion kilowatt hours)

Coal............................ 1,590 1,710 1,882 1,931 2,127 2,172 2,251 2,347
Petroleum....................... 124 75 119 90 68 54 47 44
Natural Gas..................... 378 499 556 601 717 1,001 1,297 1,476
Nuclear......................... 577 673 728 688 674 627 511 427
Hydro/Renewable/other........... 356 401 407 402 425 443 451 462
----- ----- ----- ----- ----- ----- ----- -----
Total......................... 3,025 3,358 3,691 3,712 4,011 4,297 4,557 4,756

Coal's primary advantage is its relatively low cost compared to other
fuels used to generate electricity. The following table sets forth the Energy
Information Agency's forecast of delivered fuel prices to electric utilities
through 2020. The table contains two data-sets. The top data-set is derived
from the Energy Information Agency's Long-Term forecast published in December
1999 and is presented in 1998 dollars. The lower data-set is derived from the
Energy Information Agency's Short-Term outlook published in August 2000. The
expected prices for petroleum fuel-oil and natural gas for 2001 are
considerably above the forecasted prices published less than a year ago, which
highlights the pricing volatility of petroleum and natural gas compared to
coal.

1997 1998 1999e 2000f 2001f 2005f 2010f 2015f 2020f
------------------- ----- ----- ----- ----- ----- -----
(dollars per million Btus)

Annual Energy Outlook (December
1999)
Petrol (Residual).......... $ 2.92 $2.17 $2.55 $3.21 $3.04 $3.11 $3.13 $3.19 $3.30
Natural Gas................ 2.73 2.34 2.48 2.59 2.59 2.79 3.08 3.21 3.33
Coal....................... 1.28 1.25 1.26 1.24 1.19 1.11 1.07 1.03 0.98
Short-Term Energy Outlook (August
2000)
Petrol (Residual).......... $2.39 $4.09 $3.39
Natural Gas................ 2.57 3.70 3.66
Coal....................... 1.22 1.21 1.22

Coal Production

United States coal production was over one billion tons in 1999. The
following table, derived from data prepared by the Energy Information Agency,
sets forth principal United States production statistics for the periods
indicated.

1980 1985 1990 1995 1998 1999
------- ------- ------ ------ ------ ------

Total Tons (in millions).... 820 884 1,026 1,033 1,118 1,093
Percent of Total Tons
East...................... 69% 63% 61% 53% 51% 48%
West...................... 31 37 39 47 49 52
Underground............... 40 40 41 38 37 36
Surface................... 60 60 59 62 63 64
Number of Mines
Underground............... 1,875 1,695 1,422 977 827 753
Surface................... 1,997 1,660 1,285 1,127 899 870
------- ------- ------ ------ ------ ------
Total..................... 3,872 3,355 2,707 2,104 1,726 1,623
Average Number of Mine
Employees
Underground............... 150,328 107,357 84,154 57,879 49,391 43,325
Surface................... 74,610 61,924 47,152 32,373 37,866 34,352
Average Production per Mine
(tons in thousands)
Underground............... 175 207 298 406 505 516
Surface................... 246 321 469 565 779 810

Coal Producing Regions

Coal is mined from coalfields throughout the United States, with the
major production centers located in Central Appalachia, the Southern Powder
River Basin, western bituminous coalfields, Northern Appalachia and the
Illinois Basin.

[Map of major U.S. coal producing regions appears here]

Central Appalachia.

The Central Appalachia region includes coalfields in eastern Kentucky,
southwestern Virginia and central and southern West Virginia. Production in
Central Appalachia was 262 million tons in 1999 compared with 278 million tons
in 1998. A variety of mining techniques are used in this region as seams are
found on mountaintops and below valley floors. The coal from Central Appalachia
has an average heat content of 12,500 Btus per pound and generally has low
sulfur content.

Southern Powder River Basin.

The Southern Powder River Basin is located in northeastern Wyoming.
Production in the Southern Powder River Basin in 1999 was 317 million tons
compared with 297 million tons in 1998. Coal quality in this region averages
8,600 Btus per pound and 0.3% sulfur.

Western Bituminous Coal Regions.

The western bituminous coal regions include the Hanna and Carbon Basins
in Wyoming, the Uinta Basin in northwestern Colorado and Utah, the San Juan
Basin in New Mexico and Colorado and the Raton Basin in southern Colorado.
Production in the western bituminous coal region in 1999 was 114 million tons,
compared with 113 million tons in 1998. These regions produce high quality,
low-sulfur steam coal for selected markets in the region, for export through
West Coast ports and for shipments to some Midwestern power plants for which
the Powder River Basin's subbituminous coals are not suitable. Coal from the
western bituminous coal region has a heat content ranging from 9,000 to 11,500
Btus per pound and generally has low sulfur content.

Northern Appalachia.

Medium- and high-sulfur coal is found in the Northern Appalachia
coalfields of western Pennsylvania, southeastern Ohio and northern West
Virginia. Production in Northern Appalachia was approximately 141 million tons
in 1999 compared with 157 million tons in 1998. The coal from Northern
Appalachia has a heat content ranging from 12,500 to 13,000 Btus per pound.

Illinois Basin.

The Illinois Basin is located under most of Illinois, western Indiana and
western Kentucky. Production in the basin was 104 million tons in 1999 and 111
millions tons in 1998. The Illinois Basin is a declining production center due
to the region's relatively high-sulfur coal and competition from lower-sulfur
western coal. The coal from the Illinois Basin has a heat content ranging from
10,000 to 12,000 Btus per pound and generally has medium to high sulfur
content.

Coal Characteristics

In general, coal of all geological composition is characterized by end
use as either steam coal or metallurgical coal. Heat value and sulfur content,
the most important variables in the profitable marketing and transportation of
coal, determine the best end use of a particular type of coal. We mine,
process, market and transport bituminous and subbituminous coal,
characteristics of which are described below.

Heat Value.

The heat value of coal is commonly measured in British thermal units, or
"Btus". A Btu is the amount of heat needed to raise the temperature of one
pound of water by one degree Fahrenheit. Coal found in the Eastern and
Midwestern regions of the United States tends to have a heat content ranging
from 10,000

to 13,400 Btus per pound. Most coal found in the western United States ranges
from 8,000 to 10,000 Btus per pound.

Bituminous coal is a "soft" black coal with a heat content that ranges
from 10,500 to 14,000 Btus per pound. This coal is located primarily in
Appalachia, Arizona, the Midwest, Colorado and Utah, and is the type most
commonly used for electric power generation in the United States. Bituminous
coal is used for utility and industrial steam purposes, and includes
metallurgical coal, a feed stock for coke, which is used in steel production.
We produce an insignificant amount of metallurgical coal.

Subbituminous coal is a black coal with a heat content that ranges from
7,800 to 9,500 Btus per pound. Most subbituminous reserves are located in
Montana, Wyoming, New Mexico, Washington and Alaska. Subbituminous coal is used
almost exclusively by electric utilities and some industrial consumers.

Sulfur Content.

Sulfur content can vary from seam to seam and sometimes within each seam.
When coal is burned, it produces sulfur dioxide, the amount of which varies
depending on the chemical composition and the concentration of sulfur in the
coal. Demand for low-sulfur coal has increased, and is expected to continue to
increase, as generators of electricity strive to reduce sulfur dioxide
emissions to meet requirements of the Clean Air Act.

Subbituminous coal typically has a lower sulfur content than bituminous
coal, but some bituminous coal in southern West Virginia, eastern Kentucky,
Colorado and Utah also has low sulfur content.

Higher-sulfur coal can be burned in plants equipped with sulfur-reduction
technology, as a scrubbing process reduces sulfur dioxide emissions by 50% to
90%. Plants without scrubbers can burn high-sulfur coal by purchasing emission
allowances on the open market, which allow the user to emit a ton of sulfur
dioxide. Some older coal-fired plants have been retrofitted with scrubbers. Any
new coal-fired generation plant built in the United States will use clean coal-
burning technology.

Coal Mining Techniques

Coal mining operations commonly use four distinct techniques to extract
coal from the ground. The most appropriate technique is determined by coal seam
characteristics such as location, logistics and recoverable reserve base. Drill
hole data are used initially to define the size, depth and quality of the coal
reserve area before committing to a specific extraction technique. All coal
mining techniques rely heavily on technology; consequently, technological
improvements have resulted in increased productivity. A coal mine's yield is
defined as the ratio of clean output tonnage to raw material tonnage. The four
most common mining techniques are continuous mining, longwall mining, truck and
shovel mining and dragline mining. We utilize both continuous and longwall
mining techniques in our underground mining operations and either truck and
shovel or dragline techniques in our surface mining operations, depending on
the characteristics of the mine.

Continuous Mining.

Continuous mining is one of two underground mining methods used in the
United States. Main airways and transportation entries are evacuated and
remote-controlled continuous miners extract coal from so-called rooms, leaving
pillars to support the roof, by removing coal from the seam. Shuttle cars are
used to transport coal to the conveyor belt for transport to the surface. This
method is often used to mine smaller coal blocks or thin seams, and seam
recovery is typically approximately 50%. Productivity for continuous mining
averages 25 to 50 tons per manshift.

Longwall Mining.

Longwall mining is one of two underground mining methods used in the
United States. A rotating drum is pulled mechanically across the face of coal
and a hydraulic system supports the roof of the mine while

it advances through the coal. Chain belts then move the loosened coal to a
standard underground mine conveyor system for delivery to the surface.
Continuous mining is used to develop access to long rectangular panels of coal
which are then mined with longwall equipment, allowing controlled subsidence
behind the advancing machinery. Longwall mining is highly productive, but is
effective only for large blocks of medium to thick coal seams. High capital
costs associated with longwall mining demand a large, contiguous reserve base.
Seam recovery using longwall mining is typically 70% and productivity averages
48 to 80 tons per manshift.

Truck and Shovel Mining.

Truck and shovel mining is an open-cast method which uses large,
electric-powered shovels to remove earth and rock covering a coal seam, or
overburden, which is used to refill pits after the coal is removed. Shovels
load coal in haul trucks for transportation to the preparation plant or rail
loadout. Seam recovery using the truck and shovel method is typically 90%.
Productivity depends on equipment, geological composition and mining ratios and
varies between 250 to 400 tons per manshift in the Powder River Basin and 30 to
80 tons per manshift in Eastern regions of the United States.

Dragline Mining.

Dragline mining is an open-cast method which uses large capacity
electric-powered draglines, which are large buckets suspended from the end of a
long boom, to remove overburden to expose the coal seams. Shovels load coal in
haul trucks for transportation to the preparation plant and then to the rail
loadout. Truck capacity can range from 80 to 300 tons per load. Seam recovery
using the dragline method is typically 90% or more and productivity levels are
similar to those for truck and shovel mining.

Once the raw coal is mined, it is often crushed, sized and washed in
preparation plants where the product consistency and heat content are improved.
This process involves crushing the coal to the required size, removing
impurities and, where necessary, blending with other coal to match customer
specification.

Coal Costs

Coal costs vary dramatically and are affected by a number of factors. Two
general characteristics are particularly important. First, coal costs vary
widely depending upon the region in which the coal is produced. Second, utility
purchases of coal, in which both mine-mouth coal costs and transportation costs
are considered, strongly influence other coal costs. Other factors that
influence coal costs are geological characteristics such as seam thickness,
overburden ratios and depth of underground reserves, transportation costs,
regional coal production capacity relative to demand and coal quality
characteristics such as heat value, ash, moisture and sulfur content, royalty
payments and severance taxes. Powder River Basin coal is relatively inexpensive
to mine because the seams are thick and typically close to the surface. As a
result, open-cast mining methods are used. The large capital costs associated
with dragline mining and truck and shovel mining are amortized over millions of
tons of coal produced. Powder River Basin mines are highly productive and labor
is a much smaller component of the cost structure. Eastern coal is more
expensive to mine than western coal because it has a high percentage of
underground coal and its surface coal tends to have thinner coal seams.

Clean Air Act

A major regulatory development affecting the coal industry is Title IV of
the Clean Air Act Amendments, enacted in 1990. The amendments have had, and
will continue to have, a significant effect on the domestic coal industry. In
general, Phase I, which became effective in 1995, regulates the level of
emissions of sulfur dioxide from power plants and targets the highest sulfur
dioxide emitters. Phase II, implemented January 1, 2000, extended the
restrictions of the amendments to all power plants of greater than 75 megawatt
capacity. The amendments do not define allowable emission levels on a per plant
basis, but instead allocate emission allowances to the affected plants and
allow the emission allowances to be traded so that market participants can
fashion more efficient and flexible compliance strategies. The emission
allowance allocations for Phase I units

were based on 2.5 pounds of sulfur dioxide per million Btus and Phase II
allocations are based on 1.2 pounds of sulfur dioxide per million Btus. These
and other restrictions on sulfur dioxide emissions have increased the demand
for low-sulfur coal and decreased the demand for high-sulfur coal.

Several other developments under the Clean Air Act may affect our
customers' demand for coal as a fuel source. For example, in July 1997, the
Environmental Protection Agency proposed that 22 eastern states, including
states in which many of our customers are located, make substantial reductions
in NOx emissions. The EPA expects the states to achieve these reductions by
requiring power plants to reduce their nitrous oxide emissions to a level of
0.15 pounds of nitrous oxide per million Btus of energy consumed. Many of the
states sued the EPA in the U.S. Court of Appeals for the District of Columbia
Circuit to challenge the new standard. In June 2000, the court upheld the
standard, but did not determine the timeframe within which the standard must be
implemented. To achieve these reductions, power plants may be required to
install reasonably available control technology and additional control
measures. The installation of these measures would make it more costly to
operate coal-fired utility power plants and, depending on the requirements of
individual state implementation plans, could make coal a less attractive fuel
alternative in the planning and building of utility power plants in the future.

The EPA is also proposing to implement stricter ozone standards by 2003.
The U.S. Court of Appeals for the District of Columbia Circuit has, however,
enjoined the EPA from implementing the new ozone standards on constitutional
and other legal grounds. The U.S. Supreme Court has agreed to review the lower
court's decision. It is impossible to predict the outcome of this legal action.
If the EPA is successful on appeal, then the implementation of the standards
could require some of our customers to reduce NOx emissions, which is a
precursor to ozone formation, or even prevent the construction of new
facilities that contribute to the non-attainment of the new ozone standard.

The U.S. Department of Justice, on behalf of the EPA, has filed a lawsuit
against seven investor-owned utilities and brought an administrative action
against one government-owned utility for alleged violations of the Clean Air
Act. The EPA claims that over 30 of these utilities' power stations have failed
to obtain permits required under the Clean Air Act for major improvements which
have extended the useful service of the stations or increased their generating
capacity. We supply coal to seven of the eight utilities. It is impossible to
predict the outcome of this legal action. Any outcome that adversely affects
our customers or makes coal a less attractive fuel source could, however,
adversely affect our coal sales, revenues and profitability.

Health and Safety Matters

The Federal Mine Safety and Health Act of 1977 imposes health and safety
standards on all mining operations. Regulations are comprehensive and affect
numerous aspects of mining operations, including training of mine personnel,
mining procedures, blasting, and the equipment used in mining operations. The
Black Lung Benefits Reform Act of 1977 generally requires each coal mine
operator to secure payment of federal and state black lung benefits to its
employees through insurance, bonds, or contributions to a state-controlled
fund. This Act also provides for the payment from a trust fund of benefits and
medical expenses to employees for whom no benefits have been obtainable from
their employer. This trust is financed by a tax on coal sales.

The Coal Industry Retiree Health Benefit Act of 1992 addressed two under-
funded trust funds which were created to provide medical benefits for certain
UMWA retirees. The Benefit Act provides for the funding of medical and death
benefits for certain retired members of the UMWA through premiums to be paid by
assigned operators (former employers), transfers of monies in 1993 and 1994
from an overfunded pension trust established for the benefit of retired UMWA
members, and transfers from the Abandoned Mine Lands Fund, which is funded by a
federal tax on coal production, that commenced in 1995.

MANAGEMENT

Set forth below is information regarding each of our executive officers
and directors. All ages are presented as of January 1, 2001.

Name Age Position
---- --- --------

Steven F. Leer.......... 48 President and Chief Executive Officer and Director
Bradley M. Allbritten... 43 Vice President--Human Resources
C. Henry Besten, Jr..... 52 Vice President--Strategic Marketing
John W. Eaves........... 42 Senior Vice President--Marketing
Robert G. Jones......... 44 Vice President--Law & General Counsel
Robert J. Messey........ 54 Senior Vice President and Chief Financial Officer
Terry L. O'Connor....... 55 Vice President--External Affairs
David B. Peugh.......... 46 Vice President--Business Development
Robert W. Shanks........ 47 Vice President--Operations
Kenneth G. Woodring..... 50 Executive Vice President--Mining Operations
James R. Boyd........... 54 Chairman of the Board and Director
Philip W. Block......... 53 Director
Frank M. Burke, Jr...... 60 Director
Ignacio Dominguez
Urquijo................ 55 Director
Thomas L. Feazell....... 63 Director
Robert L. Hintz......... 70 Director
Douglas H. Hunt......... 47 Director
James L. Parker......... 63 Director
A. Michael Perry........ 64 Director
Theodore D. Sands....... 55 Director

Steven F. Leer has been our President and Chief Executive Officer and a
director of our company since 1992. He is also a Director of the Center for
Energy and Economic Development, Vice-Chairman of the National Coal Council,
and Chairman of the National Mining Association.

Bradley M. Allbritten has been our Vice President--Human Resources since
March 2000. Mr. Allbritten served as our Director of Human Resources from
February 1999 through February 2000. From January 1995 to February 1999, Mr.
Allbritten served as Human Resources Manager for Atlantic Richfield Company.

C. Henry Besten, Jr. has been our Vice President--Strategic Marketing and
President of our Arch Energy Resources, Inc. subsidiary since July 1997. Mr.
Besten also served as our acting Chief Financial Officer from December 1999
through November 2000. Mr. Besten served as Senior Vice President--Marketing
for Ashland Coal from 1990 until the Ashland Coal merger in July 1997.

John W. Eaves has been our Senior Vice President--Marketing since March
2000. He served as Vice President--Marketing from July 1997 through February
2000. Mr. Eaves has served as President of our Arch Coal Sales Company, Inc.
subsidiary since September 1995.

Robert G. Jones has been our Vice President--Law & General Counsel since
March 2000. Mr. Jones served as our Assistant General Counsel from July 1997
through February 2000 and as Senior Counsel from August 1993 to July 1997.

Robert J. Messey has been our Senior Vice President and Chief Financial
Officer since December 1, 2000. Prior to joining Arch Coal, Mr. Messey served
as vice president of financial services of Jacobs Engineering Group Inc., from
January 1999 and, prior to that, served as senior vice president and chief

financial officer of Sverdrup Corporation from 1992. Mr. Messey was employed
with Ernst & Young from June 1967 to December 31, 1992, most recently as an
audit partner. Mr. Messey serves on the board of directors of Baldor Electric
Company.

Terry L. O'Connor has been our Vice President--External Affairs since
June 1998. From 1989 to May 1998, he served as Vice President--External Affairs
of Atlantic Richfield Company.

David B. Peugh has been our Vice President--Business Development since
1993.

Robert W. Shanks has been our Vice President--Operations since July 1997.
Since April 1999 he has also served as President of Arch Western Resources,
LLC. Mr. Shanks was President of Apogee Coal Company, a subsidiary of our
company, from July 1995 to July 1997.

Kenneth G. Woodring has been our Executive Vice President--Mining
Operations since July 1997. Mr. Woodring served as Senior Vice President--
Operations of Ashland Coal from 1989 through July 1997.

James R. Boyd, our Chairman of the Board, has been a director of our
company since 1990. He has served as Senior Vice President and Group Operating
Officer of Ashland Inc., a multi-industry company with operations in chemicals,
motor oil and car care products and highway construction, since 1989.

Philip W. Block has been a director of our company since 1999 and, since
1992, has been Administrative Vice President of Human Resources of Ashland.

Frank M. Burke, Jr. has been a director of our company since September
2000. He has served as Chairman, Chief Executive Officer and Managing General
Partner of Burke, Mayborn Company, Ltd., a private investment and consulting
company, since 1984. Mr. Burke is also a director of Kaneb Services, Inc.,
Kaneb Pipe Line Partners, L.P., and Avidyn, Inc. (formerly Medical Control,
Inc.).

Ignacio Dominguez Urquijo has been a director of our company since 1998
and, since June 1998, has been Chief Executive Officer and Administrator of
Carboex, S.A., a fuel trading firm belonging to Endesa Group, the leading
Spanish utility company, and Senior Vice President of Endesa Group. Mr.
Dominguez was the General Manager of SE.PI, a Spanish government holding group,
from July 1996 to June 1998 and served as Director and General Manager for
Processing Industries of TENEO, a Spanish government holding group, and its
predecessor, I.N.I., from 1992 to July 1996.

Thomas L. Feazell has been a director of our company since 1997 and was a
director of Ashland Coal from 1981 to 1997. He served as Senior Vice President,
General Counsel and Secretary of Ashland from 1992 until his retirement in
March 1999. He is a director of National City Bank of Ashland, Kentucky.

Robert L. Hintz has been a director of our company since 1997 and, since
1989, has been Chairman of the Board of R. L. Hintz & Associates, a management
consulting firm. Mr. Hintz was a director of Ashland Coal from 1993 to 1997. He
is a director of Chesapeake Corporation.

Douglas H. Hunt has been a director of our company since 1995 and, since
May 1995, has served as Director of Acquisitions of Petro-Hunt, L.L.C., a
private oil and gas exploration and production company.

James L. Parker has been a director of our company since 1995. He served
as President of Hunt Petroleum Corporation, a private oil and gas exploration
and production company, from 1990 until his retirement in February 2001. Mr.
Parker has served as President and director of Hunt Coal Corporation, a
subsidiary of Hunt Petroleum Corporation since 1994.

A. Michael Perry has been a director of our company since 1998. He has
served as Chairman of Bank One, West Virginia, N.A. since 1993 and as its Chief
Executive Officer since 1983. Mr. Perry is also a director of Champion
Industries, Inc.

Theodore D. Sands has been a director of our company since 1999 and,
since February 1999, has served as President of HAAS Capital, LLC, a private
consulting and investment company. Mr. Sands is also a director of Mosiac Group
Inc., Protein Sciences Corporation and Terra Nitrogen Corporation. Mr. Sands
served as Managing Director, Investment Banking for the Global Metals/Mining
Group of Merrill Lynch & Co. from 1982 until February 1999.

SELLING STOCKHOLDER

The selling stockholder is Ashland Inc. Ashland is a multi-industry
company with operations in chemicals, motor oil and car care products and
highway construction. Ashland also owns 38% of Marathon Ashland Petroleum LLC,
a petroleum refiner and marketer. As of September 30, 2000, Ashland
beneficially owned 4,756,968 shares, or approximately 12.4%, of our outstanding
common stock and, after completion of the offering will own no shares of our
common stock. Messrs. Philip W. Block, James R. Boyd and Thomas L. Feazell,
directors of our company, are current or former executive officers of Ashland.
Messrs. Block and Boyd, as current officers of Ashland, may be deemed to be
beneficial owners of the shares of our common stock owned by Ashland, although
they disclaim any beneficial ownership.

Ashland acquired 50% of the shares of Arch Mineral Corporation, our
predecessor company, upon its formation in July 1969. In late 1969, in 1973 and
in 1977, Ashland acquired additional shares of Arch Mineral common stock,
during which time its ownership interest in Arch Mineral fluctuated between
approximately 45% and 50%. On July 1, 1997, one of our subsidiaries merged with
Ashland Coal. Immediately prior to the merger, Ashland acquired an additional
1% interest in Arch Mineral common stock, so that, immediately prior to the
merger, it beneficially owned common stock representing approximately 57% of
the voting power of Ashland Coal and approximately 51% of our voting stock.
Immediately after the merger, Ashland owned approximately 54% of our
outstanding common stock. On June 22, 1999, Ashland announced an interest in
exploring strategic alternatives for its then 58% interest in our company. On
March 16, 2000, Ashland's board of directors declared a taxable distribution to
its stockholders of approximately 17.4 million of its 22.1 million shares of
our common stock. On that date, Ashland also announced that it planned to
dispose of its remaining approximately 4.7 million shares of our common stock
within one year of the distribution, subject to market conditions. Ashland
distributed 17.4 million shares of our common stock to its stockholders of
record as of March 24, 2000. Ashland is party to a registration rights
agreement with us under which this offering is being registered under the
Securities Act of 1933. In addition, Ashland may, prior to the sale of shares
of our common stock contemplated by this prospectus, sell some of those shares
under Rule 144 under the Securities Act.

In the ordinary course of business, we receive services and purchase
fuel, oil and other products on a competitive basis from affiliates of Ashland,
which totaled $2.8 million for the nine months ended September 30, 2000, $4.8
million in 1999, $7.2 million in 1998, and $4.7 million in 1997. We believe
that charges between us and Ashland for services and purchases have been
transacted on terms equivalent to those prevailing among unaffiliated parties.

DESCRIPTION OF CAPITAL STOCK

Our certificate of incorporation provides for authorized capital
consisting of 100,000,000 shares of common stock, par value $.01 per share, and
10,000,000 shares of preferred stock, par value $.01 per share. Based on shares
of Arch common stock outstanding at December 31, 2000, upon completion of the
offering, there will be 42,116,219 shares of Arch common stock issued and
outstanding.

Common Stock

Each share of common stock entitles its holder of record to one vote on
all matters to be voted on by our stockholders. Subject to the rights of
holders of preferred stock, holders of common stock are entitled to share on a
pro rata basis in any distribution to stockholders in the event of our
liquidation, dissolution or winding up. No holder of common stock has any
preemptive right to subscribe for any stock or other security of ours.

Preferred Stock

Our board of directors, without further action by our stockholders, may
from time to time authorize the issuance of shares of preferred stock in one or
more series and, within some limitations, fix the powers, preferences and
rights and the qualifications, limitations or restrictions thereof and the
number of shares constituting any series or designations of such series. We
have established, but not issued, a series of junior participating preferred
stock in connection with our stockholder rights plan, which is discussed below.
Satisfaction of any dividend preferences of outstanding preferred stock would
reduce the amount of funds available for the payment of dividends on common
stock. Holders of preferred stock would normally be entitled to receive a
preference payment in the event of our liquidation, dissolution or winding up
before any payment is made to the holders of common stock. In addition, in
specified circumstances, the issuance of our preferred stock may render more
difficult or tend to discourage our change in control. Although we do not
currently have plans to issue shares of preferred stock, our board of
directors, without stockholder approval, may issue preferred stock with voting
and conversion rights which could adversely affect the rights of holders of
shares of common stock.

Rights Plan

In March 2000 we adopted a stockholder rights plan under which preferred
share purchase rights are held by holders of our common stock. The rights are
exercisable only if a person or group acquires 20% or more of our common stock
or announces a tender or exchange offer the consummation of which would result
in ownership by a person or group of 20% or more of our common stock. Each
right entitles the holder to buy one one-hundredth of a share of a series of
junior participating preferred stock at an exercise price of $42, or in certain
circumstances allows the holder (except for the acquiring person) to purchase
our common stock or voting stock of the acquiring person at a discount. At its
option, the board of directors may allow some or all holders (except for the
acquiring person) to exchange their rights for our common stock. The rights
will expire on March 20, 2010, subject to our earlier redemption or exchange as
described in the plan.

Certain Provisions of Our Governing Documents

Charter Provision Regarding Issuance of Preferred Stock.

Our certificate provides that preferred stock may be issued by the board
of directors, provided that the holders of preferred stock will not be entitled
to more than the lesser of one vote per $100 of liquidation value or one vote
per share, when voting as a class with the holders of shares of other capital
stock. Holders of preferred stock will not be entitled to vote on any matter
separately as a class, except to the extent required by

law or as specified with respect to (a) any amendment or alteration of our
charter that would adversely affect the powers, preferences or special rights
of the preferred stock or (b) our failure to pay dividends on any series of
preferred stock for any six quarterly dividend payment periods, whether or not
consecutive.

Charter Provisions Affecting Control and Other Transactions.

Our certificate requires the affirmative vote of not less than two-thirds
of the outstanding shares of common stock voting thereon before we may adopt an
agreement or plan of merger or consolidation, authorize the sale, lease or
exchange of all or substantially all of our property and assets, authorize our
dissolution or the distribution of all or substantially all of our assets to
our stockholders or amend certain provisions of our charter, including the
authorization of capital stock, the supermajority provisions and the election
not to be governed by Section 203 of the Delaware General Corporation Law. Our
bylaws permit the amendment or repeal of our bylaws upon the affirmative vote
of not less than two-thirds of our board of directors.

Charter Provisions Regarding the Number of Directors.

Our certificate provides that the number of directors may be established
or changed by the affirmative vote of not less than two-thirds of the members
of the board of directors but in no event shall the number be less than three.

Classification of Board of Directors.

Our certificate provides that our board of directors consists of three
classes of directors. At each annual meeting of our stockholders, only the
election of directors of the class whose term is expiring is voted upon, and
upon election each director serves a three-year term.

UNITED STATES TAXATION OF NON-U.S. HOLDERS

General

This section summarizes the material U.S. tax consequences to a holder of
common stock that is a "Non-U.S. Holder" (as defined below). However, the
discussion is limited in the following ways:

. The discussion only relates to you if you hold your common stock as a
capital asset (that is, for investment purposes), and if you do not
have a special tax status.

. The discussion does not relate to tax consequences that depend upon
your particular tax situation in addition to your ownership of common
stock. We suggest that you consult your tax advisor about the
consequences of holding common stock in your particular situation.

. The discussion is based on current law. Changes in the law may change
the tax treatment of common stock.

. The discussion does not relate to state, local or foreign law.

. We have not requested a ruling from the Internal Revenue Service on
the tax consequences of owning common stock. As a result, the IRS
could disagree with portions of this discussion.

If you are considering buying common stock, we suggest that you consult your
tax advisor about the tax consequences of holding common stock in your
particular situation.

For the purposes of this discussion, a "Non-U.S. Holder" is:

. an individual that is a nonresident alien;

. a corporation--or entity taxable as a corporation for U.S. federal
income tax purposes--created under non-U.S. law; or

. an estate or trust that is not taxable in the United States on its
worldwide income.

If a partnership holds common stock, the tax treatment of a partner will
generally depend upon the status of the partner and upon the activities of the
partnership. If you are a partner of a partnership holding common stock, we
suggest that you consult your tax advisor.

Withholding Taxes in General

Unless an exception applies, all dividends paid to a Non-U.S. Holder will
be subject to U.S. withholding tax at a rate of 30%. These taxes will be
withheld either by the paying agent or by the bank, broker, or other
intermediary through which you hold your common stock.

In general, the entire dividend we pay is subject to withholding tax.
However, special rules apply if we pay a dividend that is greater than our
current or accumulated "earnings and profits" as calculated for U.S. federal
income tax purposes. In that case, we (or the intermediary) either:

. may elect to withhold only on the portion of the dividend that is out
of our earnings and profits. In this case, the remainder of the
dividend would not be subject to withholding tax; or

. may withhold on the entire dividend. In that case, you would be
entitled to obtain a refund from the IRS for the withholding tax on
the portion of the dividend that exceeds our earnings and profits.

Exceptions to 30% Withholding Taxes

You may be entitled to a reduced rate of withholding taxes--or exemption
from withholding taxes--if you are eligible for a tax treaty between the United
States and your country of residence. The particular withholding tax rate that
would apply to you depends on your tax status and on the particular tax treaty.
However, the rate under most treaties is 15% for a typical portfolio investor.
To be eligible for preferential tax treatment under a tax treaty, you generally
must meet each of the following requirements:

. You must be the beneficial owner of our common stock. That is, you
are not holding our common stock on behalf of someone else;

. You must be a resident of the tax treaty jurisdiction and you satisfy
all the other requirements in the treaty;

. You must comply with the documentation requirements discussed below;
and

. If you are treated as a partnership or other pass-through entity
either for U.S. federal income tax purposes or under the tax laws of
the treaty jurisdiction, you must satisfy additional requirements.

In order to comply with the documentation requirements to claim tax
treaty benefits, you must satisfy one of the following conditions. These
conditions have been significantly changed for dividends paid on or after
January 1, 2001.

. You complete Form W-8BEN and provide it to the intermediary. The Form
W-8BEN must contain your name and address, and you must fill out Part
II of the form to state your claim for treaty benefits. As long as
our common stock remains actively traded, you are not required to
obtain a Taxpayer Identification Number to claim treaty benefits.

. You hold your common stock directly through a "qualified
intermediary." In this case, you need not file Form W-8BEN if the
qualified intermediary has in its files, or obtains from you, certain
information concerning your eligibility for treaty benefits. A
qualified intermediary is an intermediary that (1) is either a U.S.
or non-U.S. entity, (2) is acting out of a non-U.S. branch or office
and (3) has signed an agreement with the IRS providing that it will
administer all or part of the U.S. tax withholding rules under
specified procedures.

. In some limited circumstances, you may be permitted to provide
documentary evidence in lieu of Form W-8BEN even if you hold your
common stock through an intermediary that is not a qualified
intermediary.

Alternatively, even if the dividends paid to you are not exempt from U.S.
tax under a tax treaty, dividends paid to you will be exempt from U.S.
withholding tax if the dividend income is effectively connected with the
conduct of your trade or business in the United States. To claim this
exemption, you must generally complete Form W-8ECI.

Even if you meet one of the above requirements, you will not be entitled
to the reduction in--or exemption from--withholding tax on dividends paid to
you under any of the following circumstances:

. The withholding agent or an intermediary knows or has reason to know
that you are not entitled to the reduction in rate or the exemption
from withholding tax. Specific rules apply for this test.

. The IRS notifies the withholding agent that information that you or
an intermediary provided concerning your status is false.

. An intermediary through which you hold the common stock fails to
comply with the necessary procedures. In particular, an intermediary
is generally required to forward a copy of your Form W-8BEN (or other
documentary information concerning your status) to the withholding
agent for the common stock. However, if you hold your common stock
through a qualified intermediary--

or if there is a qualified intermediary in the chain of title between
yourself and the withholding agent for the common stock--the
qualified intermediary will not generally forward this information to
the withholding agent.

The amount of dividends paid to you, and the amount withheld from the
dividends, will generally be reported to the IRS and to you on Form 1042-S.
However, this reporting does not apply to you if you hold your common stock
directly through a qualified intermediary and the applicable procedures are
complied with.

The rules regarding withholding are complex and vary depending on your
individual situation. They are also subject to change, and certain transition
rules apply for calendar year 2001. In addition, special rules apply to
certain types of non-U.S. holders of common stock, including partnerships,
trusts, and other entities treated as pass-through entities for U.S. federal
income tax purposes. We suggest that you consult with your tax advisor
regarding the specific methods for satisfying these requirements.

Sale of Common Stock

If you sell all or any portion of your common stock, you will not be
subject to federal income tax on any gain unless one of the following applies:

. The gain is connected with a trade or business that you conduct in
the United States.

. You are an individual and are present in the United States for at
least 183 days during the year in which you dispose of the common
stock, and certain other conditions are satisfied.

. We are or have been a "United States real property holding
corporation" for U.S. federal income tax purposes at any time during
the shorter of the five-year period ending on the date of the
disposition or the period during which you hold your common stock. We
have not analyzed whether or not we are a real property holding
corporation for U.S. federal income tax purposes, but given the
nature of our industry, it is reasonably likely that we would qualify
as one. Even if we are a United States real property holding
corporation, a non-U.S. holder still will not be subject to U.S. tax
if our common stock were considered to be "regularly traded on an
established securities market" and you did not own, actually or
constructively, at any time during the shorter of the periods
described above, more than five percent of our common stock.

U.S. Trade or Business

If you hold your common stock in connection with a trade or business
that you are conducting in the United States.:

. Any dividends on the common stock, and any gain from disposing of the
common stock, generally will be subject to income tax at the usual
U.S. rates applicable to U.S. persons.

. If you are a corporation, you may be subject to the "branch profits
tax" on your earnings that are connected with your U.S. trade or
business, including earnings from the common stock. This tax is 30%,
but may be reduced or eliminated by an applicable income tax treaty.

Estate Taxes

If you are an individual, your common stock will be subject to U.S.
estate tax when you die unless you are entitled to the benefits of an estate
tax treaty.

Information Reporting and Backup Withholding

Under the U.S. information reporting rules, when a shareholder receives
dividends or proceeds of the sale of stock, the appropriate intermediary must
report to the IRS and to the shareholder the amount of the dividends or sale
proceeds. Some shareholders, including all corporations, are exempt from these
rules.

In addition, a nonexempt shareholder is required to provide the
intermediary with certain identifying information. If this information is not
supplied, or if the intermediary knows or has reason to know that it is not
true, dividends or sale proceeds are subject to "backup withholding" at a rate
of 31%. Backup withholding is not an additional tax, and the shareholder may
use the tax as a credit against the tax it otherwise owes.

These rules apply to Non-U.S. Holders of common stock as follows:

. Dividends paid to you will be exempt from the usual information
reporting rules if you are eligible for a reduced withholding rate
under a tax treaty as discussed above. However, as described above,
dividends paid to you may be reported to the IRS on Form 1042-S.

. If you are not eligible for a tax treaty and do not provide
information to the intermediary identifying yourself as a Non-U.S.
Holder, in some cases you may be subject to backup withholding at the
rate of 31% instead of regular dividend withholding at the rate of
30%. If necessary, you may provide the intermediary with Form W-8BEN,
without claiming treaty benefits, in order to claim the 30% rate.

Sale proceeds you receive on a sale of your common stock through a broker
may be subject to information reporting and/or backup withholding if you are
not eligible for an exemption. In particular, information reporting and backup
withholding may apply if you use the U.S. office of a broker, and information
reporting (but not backup withholding) may apply if you use the foreign office
of a broker that has certain connections to the U.S. In general, you may file
Form W-8BEN, without claiming treaty benefits, to claim an exemption from
information reporting and backup withholding. We suggest that you consult your
tax advisor concerning information reporting and backup withholding on a sale.

UNDERWRITING

We and the selling stockholder intend to offer the shares of our common
stock through the underwriter. Merrill Lynch, Pierce, Fenner & Smith
Incorporated is the sole underwriter. Subject to the terms and conditions in
the purchase agreement among us, the selling stockholder and the underwriter,
we and the selling stockholder have agreed to sell to the underwriter, and the
underwriter has agreed to purchase from us and the selling stockholder, a total
of 8,700,000 shares.

The underwriter has agreed to purchase all of the shares sold under the
purchase agreement if any of the shares are purchased.

We and the selling stockholder have agreed to indemnify the underwriter
against certain liabilities, including liabilities under the Securities Act, or
to contribute to payments the underwriter may be required to make in respect of
those liabilities.

The underwriter is offering the shares, subject to prior sale, when, as
and if issued to and accepted by it, subject to approval of legal matters by
its counsel, including the validity of the shares, and other conditions
contained in the purchase agreement, such as the receipt by the underwriter of
officer's certificates and legal opinions. The underwriter reserves the right
to withdraw, cancel or modify offers to the public and to reject orders in
whole or in part.

Commissions and Discounts

The underwriter has advised us and the selling stockholder that it
proposes initially to offer the shares to the public at the initial public
offering price on the cover page of this prospectus and to dealers at that
price less a concession not in excess of $.57 per share. The underwriter may
allow, and the dealers may reallow, a discount not in excess of $.10 per share
to other dealers. After the initial public offering, the public offering price,
concession and discount may be changed.

The following table shows the public offering price, underwriting
discount and proceeds before expenses to us and the selling stockholder. The
information assumes either no exercise or full exercise by the underwriter of
its over-allotment option.

Per Share Without Option With Option
--------- -------------- -----------

Public offering price.............. $19.00 $165,300,000 $188,627,535
Underwriting discount.............. $.97 $8,439,000 $9,629,932
Proceeds, before expenses, to Arch
Coal.............................. $18.03 $71,092,867 $93,229,470
Proceeds, before expenses, to
Ashland Inc., the sole selling
stockholder....................... $18.03 $85,768,133 $85,768,133

The expenses of the offering, not including the underwriting discount,
are estimated at $350,000, and will be paid by us.

Over-allotment Option

We have granted an option to the underwriter to purchase up to 1,227,765
additional shares at the public offering price less the underwriting discount.
The underwriter may exercise this option for 30 days from the date of this
prospectus solely to cover any over-allotments.

No Sales of Similar Securities

We, our directors, certain of our officers, the selling stockholder and
some other significant stockholders have agreed, with exceptions, not to sell
or transfer any common stock for 90 days after the date of this prospectus
without first obtaining the written consent of Merrill Lynch. Specifically, we
and these other parties have agreed not to directly or indirectly

. offer, pledge, sell or contract to sell any common stock,

. sell any option or contract to purchase any common stock,

. purchase any option or contract to sell any common stock,

. grant any option, right or warrant for the sale of any common stock,

. lend or otherwise dispose of or transfer any common stock,

. request or demand that we file a registration statement related to
the common stock, or

. enter into any swap or other agreement that transfers, in whole or in
part, the economic consequence of ownership of any common stock
whether any such swap or transaction is to be settled by delivery of
shares or other securities, in cash or otherwise.

This lockup provision applies to common stock and to securities
convertible into or exchangeable or exercisable for or repayable with common
stock. It also applies to common stock owned now or acquired later by the
person executing the agreement or for which the person executing the agreement
later acquires the power of disposition. Merrill Lynch, in its sole discretion,
may release any of the securities subject to lockup agreements at any time
prior to the expiration of the lockup period without notice. Merrill Lynch has
no present intent or arrangement to release any of the securities subject to
these lockup agreements.

We are not restricted by this lockup provision from the sale or
distribution of our common stock in connection with certain business
combination transactions, stock-based compensation plans and our dividend
reinvestment plan.

New York Stock Exchange Listing

The shares are listed on the New York Stock Exchange under the symbol
"ACI".

Price Stabilization, Short Positions

Until the distribution of the shares is completed, Securities and
Exchange Commission rules may limit the underwriter from bidding for and
purchasing our common stock. However, the underwriter may engage in
transactions that stabilize the price of the common stock, such as bids or
purchases to peg, fix or maintain that price.

In connection with the offering, the underwriter may make short sales of
the common stock. Short sales involve the sale by the underwriter at the time
of the offering of a greater number of shares than it is required to purchase
in the offering. Covered short sales are sales made in an amount not greater
than the over-allotment option. The underwriter may close out any covered short
position by either exercising its over-allotment option or purchasing shares in
the open market. In determining the source of shares to close out the covered
short position, the underwriter will consider, among other things, the price of
shares available for purchase in the open market as compared to the public
offering price at which it may purchase the shares through the over-allotment
option. Naked short sales are sales in excess of the over-allotment option. The
underwriter must close out any naked short position by purchasing shares in the
open market. A naked short position is more likely to be created if the
underwriter is concerned that there may be downward pressure on the price of
the shares in the open market after pricing that could adversely affect
investors who purchase in the offering. Purchases of the common stock to
stabilize its price or to reduce a short position may cause the price of the
common stock to be higher than it might be in the absence of such purchases.

Neither we nor the underwriter makes any representation or prediction as
to the direction or magnitude of any effect that the transactions described
above may have on the price of our common stock. In addition, neither we nor
the underwriter makes any representation that the underwriter will engage in
these transactions or that these transactions, once commenced, will not be
discontinued without notice.

The underwriter will be facilitating Internet distribution for this
offering to some of its Internet subscription customers. The underwriter
intends to allocate a limited number of shares for sale to its online brokerage
customers. An electronic prospectus is available on the Internet web site
maintained by Merrill Lynch. Other than the prospectus in electronic format,
the information on the Merrill Lynch web site is not part of this prospectus.

LEGAL MATTERS

The validity of the shares of common stock offered will be passed upon by
Robert G. Jones, our Vice President--Law and General Counsel. Certain legal
matters with respect to the offering will be passed upon for us by Kirkpatrick
& Lockhart LLP, Pittsburgh, Pennsylvania. The underwriter has been represented
by Cravath, Swaine & Moore, New York, New York. Cravath, Swaine & Moore
regularly provides legal services to Ashland.

EXPERTS

Ernst & Young LLP, independent auditors, have audited our financial
statements and schedule included or incorporated by reference in our Annual
Report on Form 10-K for the years ended December 31, 1997 and 1998 and Form 10-
K, as amended, for the year ended December 31, 1999, and the financial
statements of Canyon Fuel Company, LLC for the years ended December 31, 1998
and 1999 included in our Annual Report on Form 10-K, as amended, for the year
ended December 31, 1999, all as set forth in their reports, which are
incorporated by reference in this prospectus and elsewhere in the registration
statement. These financial statements and schedule are incorporated by
reference in reliance on the reports of Ernst & Young LLP given on their
authority as experts in accounting and auditing.

WHERE YOU CAN FIND MORE INFORMATION

We are subject to the reporting requirements of the Securities Exchange
Act of 1934 and, in accordance with that Act, file annual and quarterly
reports, proxy statements and other information with the Securities and
Exchange Commission. These reports, proxy statements and other information may
be inspected and copies of these materials may be obtained upon payment of fees
at the Public Reference Room maintained by the Securities and Exchange
Commission at 450 Fifth Street, N.W., Washington, D.C. 20549, as well as the
regional offices of the Securities and Exchange Commission located at 500 West
Madison Street, Chicago, Illinois, and Seven World Trade Center, New York, New
York. You may obtain information on the operation of the Public Reference Room
by calling the Commission at 1-800-SEC-0330. In addition, we are required to
file electronic versions of these materials with the Securities and Exchange
Commission through the Securities and Exchange Commission's Electronic and Data
Gathering, Analysis and Retrieval system. The Securities and Exchange
Commission maintains a World Wide Web site at http://www.sec.gov that contains
reports, proxy and information statements and other information regarding
registrants that file electronically with the Commission. Our common stock is
listed on the New York Stock Exchange, and reports and other information
concerning us may be inspected at the New York Stock Exchange, Inc. at 20 Broad
Street, New York, New York 10005.

We have filed with the Securities and Exchange Commission a registration
statement on Form S-3 under the Securities Act of 1933 with respect to the
common stock offered in this prospectus. This prospectus does not contain all
of the information set forth in the registration statement and the exhibits to
that registration statement. The Securities and Exchange Commission allows us
to "incorporate by reference" the information we file with them, which means
that we can disclose important information to you by referring to those
documents. All documents and reports subsequently filed by us under Sections
13(a), 13(c), 14 or 15(d) of the Exchange Act after the date of the
registration statement and prior to effectiveness of the registration statement
and after the date of this prospectus and prior to the termination of the
offering made by this prospectus are incorporated by reference. Any statement
contained in this prospectus or in a document incorporated or deemed to be
incorporated by reference in this prospectus shall be modified or superseded
for purposes of this prospectus to the extent that a statement contained in
this prospectus or in any subsequently filed document which is incorporated by
reference in this prospectus modifies or supersedes that statement. A statement
so modified or superseded will not be deemed, except as so modified or
superseded, to be a part of this prospectus.

Copies of the registration statement, including all exhibits to it, may
be obtained from the Securities and Exchange Commission's principal office in
Washington, D.C. upon the payment of the fees prescribed by the Securities and
Exchange Commission, or may be examined without charge at the offices of the
Securities and Exchange Commission described above. Copies of these materials
may also be obtained from the EDGAR database.

The following documents filed by us with the Securities and Exchange
Commission under the Exchange Act are incorporated by reference in this
prospectus:

1. Our Annual Report on Form 10-K for the fiscal year ended December
31, 1999, as amended;

2. Our Quarterly Reports on Form 10-Q for the quarters ended March 31,
2000, June 30, 2000 and September 30, 2000, each as amended;

3. Our Current Report on Form 8-K dated March 9, 2000;

4. The description of the common stock contained in our Registration
Statement on Form 8-B dated June 17, 1997, as the same may be
amended; and

5. The description of the preferred stock purchase rights contained in
our Registration Statement on Form 8-A dated March 9, 2000, as the
same may be amended.

We will provide to each person to whom a copy of this prospectus is
delivered, upon the written or oral request of such person, without charge, a
copy of any or all of the documents that are incorporated in this prospectus by
reference. Requests should be directed to External Affairs, Arch Coal, Inc.,
CityPlace One, Suite 300, St. Louis, Missouri 63141. Our telephone number is
(314) 994-2700.

GLOSSARY OF SELECTED MINING TERMS

Assigned Reserves. Recoverable coal reserves that have been designated
for mining by a specific operation.

Auger Mining. Auger mining employs a large auger, which functions much
like a carpenter's drill. The auger bores into a coal seam and discharges coal
out of the spiral onto waiting conveyor belts. After augering is completed, the
openings are reclaimed. This method of mining is usually employed to recover
any additional openings left in deep overburden areas that cannot be reached
economically by other types of surface mining.

Btu--British Thermal Unit. A measure of the energy required to raise the
temperature of one pound of water one degree Fahrenheit.

Coal Seam. A bed or stratum of coal.

Coal Washing. The process of removing impurities, such as ash and sulfur
based compounds, from coal.

Compliance Coal. Coal which, when burned, emits 1.2 pounds or less of
sulfur dioxide per million Btus.

Continuous Mining. One of two major underground mining methods now used
in the United States (also see "Longwall Mining"). This process utilizes a
machine--a "continuous miner"--that mechanizes the entire coal extraction
process. The continuous miner removes or "cuts" the coal from the seam. The
loosened coal then falls on a conveyor for removal to a shuttle car or larger
conveyor belt system.

Dragline. A large machine used in the surface mining process to remove
the overburden, or layers of earth and rock, covering a coal seam. The dragline
has a large bucket suspended from the end of a long boom. The bucket, which is
suspended by cables, is able to scoop up great amounts of overburden as it is
dragged across the excavation area.

Longwall Mining. One of two major underground coal mining methods
currently in use. This method employs a rotating drum, which is pulled
mechanically back and forth across a face of coal that is usually several
hundred feet long. The loosened coal falls onto a conveyor for removal from the
mine. Longwall operations include a hydraulic roof support system that advances
as mining proceeds, allowing the roof to fall in a controlled manner in areas
already mined.

Low-Sulfur Coal. Coal which, when burned, emits 1.6 pounds or less of
sulfur dioxide per million Btus.

Metallurgical Coal. The various grades of coal suitable for distillation
into carbon in connection with the manufacture of steel. Also known as "met"
coal.

Overburden. Layers of earth and rock covering a coal seam. In surface
mining operations, overburden is removed prior to coal extraction.

Overburden Ratio. A measurement indicating the volume of earth and rock,
in cubic yards, that must be removed to expose one ton of marketable coal.

Preparation Plant. A preparation plant is a facility for crushing, sizing
and washing coal to prepare it for use by a particular customer. The washing
process has the added benefit of removing some of the coal's sulfur content.

Probable (Indicated) Reserves. Reserves for which quantity and grade
and/or quality are computed from information similar to that used for proven
(measured) reserves, but the sites for inspection, sampling and measurement
are farther apart or are otherwise less adequately spaced. The degree of
assurance, although lower than that for proven (measured) reserves, is high
enough to assume continuity between points of observation.

Proven (Measured) Reserves. Reserves for which (a) quantity is computed
from dimensions revealed in outcrops, trenches, workings or drill holes; grade
and/or quality are computed from the results of detailed sampling and (b) the
sites for inspection, sampling and measurement are spaced so closely and the
geologic character is so well defined that size, shape, depth and mineral
content of reserves are well established.

Reclamation. The restoration of land and environmental values to a
mining site after the coal is extracted. Reclamation operations are usually
underway where the coal has already been taken from a mine, even as mining
operations are taking place elsewhere at the site. The process commonly
includes "recontouring" or reshaping the land to its approximate original
appearance, restoring topsoil and planting native grass and ground covers.

Recoverable Reserves. The amount of proven and probable reserves that
can actually be recovered from the reserve base taking into account all mining
and preparation losses involved in producing a saleable product using existing
methods and under current law.

Scrubber. Any of several forms of chemical/physical devices which
operate to neutralize sulfur compounds formed during coal combustion. These
devices combine the sulfur in gaseous emissions with other chemicals to form
inert compounds, such as gypsum, which must then be removed for disposal.

Spot Market. Sales of coal under an agreement for shipments over a
period of one year or less.

Steam Coal. Coal used in steam boilers to produce electricity.

Surface Mine. A mine in which the coal lies near the surface and can be
extracted by removing overburden.

Tons. References to a "ton" mean a "short" or net ton, which is equal to
2,000 pounds.

Unassigned Reserves. Recoverable coal reserves that have not yet been
designated for mining by a specific operation.

Underground Mine. Also known as a "deep" mine. Usually located several
hundred feet below the earth's surface, an underground mine's coal is removed
mechanically and transferred by shuttle car or conveyor to the surface.

Unit Train. A long train of between 90 and 150 hopper cars, carrying
coal between a single mine and a destination. A typical unit train can carry
at least 10,000 tons of coal in a single shipment.

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8,700,000 Shares
Arch Coal, Inc.
Common Stock

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PROSPECTUS
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Merrill Lynch & Co.

February 15, 2001

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