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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM _____________TO_____________
COMMISSION FILE NO.: 0-26823
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ALLIANCE RESOURCE PARTNERS, L.P.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 73-1564280
(STATE OR OTHER JURISDICTION OF (IRS EMPLOYER IDENTIFICATION NO.)
INCORPORATION OR ORGANIZATION)
1717 SOUTH BOULDER AVENUE, SUITE 600, TULSA, OKLAHOMA 74119
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES AND ZIP CODE)
(918) 295-7600
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
common units representing limited partner interests
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Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
The aggregate value of the common units held by non-affiliates of the
registrant (treating all executive officers and directors of the registrant, for
this purpose, as if they may be affiliates of the registrant) was approximately
$178,670,542 on March 28, 2002, based on $24.18 per unit, the closing price of
the common units as reported on the Nasdaq National Market on such date.
As of March 28, 2002, 8,982,780 common units and 6,422,531 subordinated
units are outstanding.
DOCUMENTS INCORPORATED BY REFERENCE: None
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TABLE OF CONTENTS
<Table>
<Caption>
PAGE
PART I
ITEM 1. BUSINESS ....................................................................................... 4
ITEM 2. PROPERTIES ..................................................................................... 17
ITEM 3. LEGAL PROCEEDINGS............................................................................... 22
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITIES HOLDERS .......................................... 22
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON UNITS AND RELATED UNITHOLDER MATTERS ............................ 23
ITEM 6. SELECTED FINANCIAL DATA ........................................................................ 24
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS .......... 25
ITEM 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK ..................................... 34
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA .................................................... 35
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE ........... 61
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE MANAGING GENERAL PARTNER ............................... 61
ITEM 11. EXECUTIVE COMPENSATION ......................................................................... 64
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANGEMENT .................................. 68
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS ................................................. 69
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K ............................... 73
</Table>
1
FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K contains "forward-looking statements"
within the meaning of Section 21E of the Securities Exchange Act of 1934 and the
Private Securities Litigation Reform Act of 1995. These statements are based on
our beliefs as well as assumptions made by, and information currently available
to, us. When used in this document, the words "anticipate," "believe,"
"continue," "estimate," "expect," "forecast", "may," "project", "will," and
similar expressions identify forward-looking statements. These statements
reflect our current views with respect to future events and are subject to
various risks, uncertainties and assumptions. Specific factors which could cause
actual results to differ from those in the forward-looking statements, include:
o competition in coal markets and our ability to respond to the
competition;
o fluctuation in coal price, which could adversely affect our
operating results and cash flows;
o deregulation of the electric utility industry and/or the
effects of any adverse change in the domestic coal industry,
electric utility industry, or general economic conditions;
o dependence on significant customer contracts, including
renewing customer contracts upon expiration;
o customer cancellations of, or breaches to, existing contracts;
o customer delays or defaults in making payments;
o fluctuations in coal demand, price and availability due to
labor and transportation costs and disruptions, equipment
availability, governmental regulations and other factors;
o our productivity levels and margins that we earn on our coal
sales;
o any unanticipated increases in labor costs, adverse changes in
work rules, or unexpected cash payments associated with
post-mine reclamation and workers' compensation claims;
o greater than expected environmental regulation, costs and
liabilities;
o a variety of operational, geologic, permitting, labor and
weather-related factors;
o risk of major mine-related accidents or interruptions; and
o results of litigation.
If one or more of these risks or uncertainties materialize, or should
underlying assumptions prove incorrect, our actual results may differ materially
from those described in any forward-looking statement. When considering
forward-looking statements, you should also keep in mind the risk factors
described in "Risk Factors" above. The risk factors could also cause our actual
results to differ materially from those contained in any forward-looking
statement. We disclaim any obligation to update the above list or to announce
publicly the result of any revisions to any of the forward-looking statements to
reflect future events or developments
You should consider the above information when reading any
forward-looking statements contained:
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o in this Annual Report on Form 10-K;
o other reports filed by us with the SEC;
o our press releases; and
o oral statements made by us or any of our officers or other
persons acting on our behalf.
3
PART I
ITEM 1. BUSINESS
GENERAL
We are a diversified producer and marketer of coal to major United States
utilities and industrial users. We began mining operations in 1971 and, since
then, have grown through acquisitions and internal development to become the
eighth largest coal producer in the eastern United States. At December 31, 2001,
we had approximately 400.7 million tons of reserves in Illinois, Indiana,
Kentucky, Maryland and West Virginia. In 2001, we produced 15.7 million tons of
coal and sold 17.0 million tons of coal. The coal we produced in 2001 was 28.7%
low-sulfur coal, 17.2% medium-sulfur coal and 54.1% high-sulfur coal. In 2001,
approximately 91% of our medium- and high-sulfur coal was sold to utility plants
with installed pollution control devices, also known as "scrubbers," to remove
sulfur dioxide. We classify low-sulfur coal as coal with a sulfur content of
less than 1%, medium-sulfur coal as coal with a sulfur content between 1% and 2%
and high-sulfur coal as coal with a sulfur content of greater than 2%.
We currently operate seven mining complexes in Illinois, Indiana, Kentucky
and Maryland. Six of our mining complexes are underground and one has multiple
surface operations and a single underground mine. Our mining activities are
organized into three operating regions: (a) the Illinois Basin operations, (b)
the East Kentucky operations, and (c) the Maryland operations.
We and our subsidiary, Alliance Resource Operating Partners, L.P. (referred
to as the intermediate partnership), were formed to acquire, own and operate
substantially all of the coal production and marketing assets of Alliance
Resource Holdings, Inc., a Delaware corporation formerly known as Alliance Coal
Corporation. We completed our initial public offering on August 20, 1999, at
which time Alliance Resource Holdings contributed substantially all of its
operating assets and liabilities to the intermediate partnership.
Our managing general partner, Alliance Resource Management GP, LLC, and our
special general partner, Alliance Resource GP, LLC (collectively referred to as
our general partners) own an aggregate 2% general partner interests in us. Our
limited partners, including the general partners as holders of common units and
subordinated units, own an aggregate 98% of the limited partner interests in us.
The coal production and marketing assets of Alliance Resource Holdings
acquired by us are referred to as our "predecessor." All 1999 operating data
contained herein includes our results and our predecessor's results.
MINING OPERATIONS
We produce a diverse range of steam coals with varying sulfur and heat
contents, which enables us to satisfy the broad range of specifications required
by our customers. The following chart summarizes our production by region for
the last five years.
<Table>
<Caption>
OPERATING REGION AND MINES 2001 2000 1999 1998 1997
- -------------------------- ---- ---- ---- ---- ----
(TONS IN MILLIONS)
Illinois Basin Operations:
Dotiki, Pattiki, Hopkins County, Gibson County 10.2 8.4 8.5 7.9 5.2
East Kentucky Operations:
Pontiki, MC Mining 2.8 2.7 2.8 2.5 2.8
Maryland Operations:
Mettiki 2.7 2.6 2.8 3.0 2.9
---- ---- ---- ---- ----
Total 15.7 13.7 14.1 13.4 10.9
==== ==== ==== ==== ====
</Table>
4
ILLINOIS BASIN OPERATIONS
Our Illinois Basin mining operations are located in western Kentucky,
southern Illinois and southern Indiana. We have approximately 975 employees in
the Illinois Basin and currently operate four mining complexes.
Webster County Coal, LLC. Webster County Coal operates the Dotiki mine,
which is an underground mining complex, located near Providence, Kentucky in
Webster and Hopkins Counties, Kentucky. The mine was opened in 1966, and we
purchased the mine in 1971. Our Dotiki operation utilizes continuous mining
units employing room-and-pillar mining techniques. The preparation plant has a
throughput capacity of 1,000 tons of raw coal an hour.
Production from the mine is shipped via the CSX railroad, the Paducah &
Louisville railroad and by truck on U.S. and state highways. Our primary
customers for coal produced at Dotiki are Seminole Electric Cooperative, Inc.
(Seminole), Tennessee Valley Authority (TVA) and Western Kentucky Energy Corp.
(WKE), which purchase our coal pursuant to long-term contracts for use in their
scrubbed generating units. During August 2001, Dotiki began construction of a
new mine shaft and ancillary facilities, which is expected to be operational in
late 2002 and will provide a new access for miners and supplies.
White County Coal, LLC. White County Coal operates the Pattiki mine, which
is an underground mining complex, located near New Harmony, Indiana in White
County, Illinois. We began construction of the mine in 1980 and have operated it
since its inception. Our Pattiki operation utilizes continuous mining units
employing room-and-pillar mining techniques. We are in the process of extending
our Pattiki mine into adjacent coal reserves, which will include two new shafts
and ancillary facilities. This extension involves capital expenditures of
approximately $30 million during the 2000-2003 period and allows the Pattiki
mining complex to continue and expand its existing productive capacity for the
next 15 years. The preparation plant has a throughput capacity of 1,000 tons of
raw coal an hour.
Production from the mine is shipped via the CSX railroad. Our primary
customers for coal produced at Pattiki are Seminole and Cincinnati Gas &
Electric Company, which purchase our coal pursuant to long-term contracts for
use in their scrubbed generating units.
Hopkins County Coal, LLC. Hopkins County Coal is a mining complex located
near Madisonville, Kentucky in Hopkins County, Kentucky. We acquired Hopkins
County Coal in January 1998, and consistent with our acquisition plans,
purchased new mining equipment and completed extensive equipment rebuilds during
1998. The operation has three surface mines, one of which is currently idle, and
one underground mine. The surface operations utilize dragline mining, and the
underground operation utilizes a continuous mining unit employing
room-and-pillar mining techniques. The preparation plant has a throughput
capacity of 1,000 tons of raw coal an hour.
Production from the complex is shipped via the CSX and the Paducah &
Louisville railroads and by truck on U.S. and state highways. Our primary
customers for coal produced at Hopkins County Coal have been Louisville Gas &
Electric Company (LG&E), TVA and WKE, which have purchased our coal pursuant to
long-term contracts for use in their scrubbed generating units. As discussed
under "Other Operations; Coal Synfuel" below, we now sell most of Hopkins County
Coal's production to the synfuel facility owner, which in turn sells coal
synfuel to LG&E, TVA and other potential customers. We have put in place
"back-up" coal supply agreements with these customers, which automatically
provide for sale of our coal to them in the event they do not receive coal
synfuel.
5
Gibson County Coal, LLC. Gibson County Coal is an underground mining
complex located near Princeton, Indiana in Gibson County, Indiana. In October
1999, we announced the award of engineering and construction contracts for the
development of dual mine slopes and a mine shaft to support mining operations.
Subsequent contracts were awarded by our special general partner for the
construction of a coal preparation plant and handling facilities, providing us
access to these facilities under a long-term operating lease agreement. The mine
began production with a single mining unit in November 2000. The Gibson County
mining complex utilizes multiple continuous mining units employing
room-and-pillar mining techniques. The preparation plant has a throughput
capacity of 700 tons of raw coal an hour.
Production from Gibson County Coal is a low-sulfur coal, shipped via truck
approximately 10 miles on U.S. and state highways to our primary customer, PSI
Energy Inc. (PSI), a subsidiary of Cinergy Corporation. In 1997, we acquired an
additional 99.9 million tons of undeveloped recoverable reserves in Gibson
County, which are not contiguous to the reserves currently being mined. We refer
to these reserves as the Gibson County "South" reserves.
EAST KENTUCKY OPERATIONS
Our East Kentucky mining operations are located in the Central Appalachia
coal fields. Our East Kentucky mines produce low-sulfur coal. We have
approximately 435 employees and operate two mining complexes in East Kentucky.
Pontiki Coal, LLC. Pontiki is an underground mining complex located near
Inez, Kentucky in Martin County, Kentucky. We constructed the mine in 1977.
Pontiki owns the mining complex and reserves and Excel Mining LLC, an affiliate
of Pontiki, is responsible for conducting all mining operations. Substantially
all of the coal produced at Pontiki meets or exceeds the compliance requirements
of Phase II of the Clean Air Act amendments. Our Pontiki operation utilizes
continuous mining units employing room-and-pillar mining techniques. The
preparation plant has a throughput capacity of 800 tons of raw coal an hour.
Production from the mine is shipped via the Norfolk Southern railroad or by
truck via U.S. and state highways to various docks on the Big Sandy River in
Kentucky. Our primary customers for coal produced at Pontiki are James River
Cogeneration Company, the successor to Cogentrix of Virginia, Inc., and AEI Coal
Sales Company, Inc.
MC Mining, LLC. MC Mining is an underground mining complex located near
Pikeville, Kentucky in Pike County, Kentucky. MC Mining was acquired in 1989.
When we began operations in late 1996, MC Mining was operated by an unaffiliated
contract mining company. During 2000, the contract mining agreement was
terminated and MC Mining entered into an intercompany support services agreement
with Excel Mining. Selected employees of the contractor and other qualified
individuals were hired by Excel Mining, which is responsible for conducting all
mining operations. The operation utilizes continuous mining units employing
room-and-pillar mining techniques. The preparation plant has a throughput
capacity of 800 tons of raw coal an hour.
Production from the mine is shipped via the CSX railroad or by truck via
U.S. and state highways to various docks on the Big Sandy River. MC Mining sells
its low-sulfur production primarily in the spot market.
MARYLAND OPERATIONS
Our Maryland mining operation is located in the Northern Appalachia coal
fields. We have approximately 235 employees and operate one mining complex in
Maryland.
6
Mettiki Coal, LLC. Mettiki is an underground longwall mining complex
located near Oakland, Maryland in Garrett County, Maryland. We constructed
Mettiki in 1977 and have operated it since its inception. The operation utilizes
a longwall miner for the majority of the coal extraction as well as continuous
mining units used to prepare the mine for future longwall mining. The
preparation plant has a throughput capacity of 1,350 tons of raw coal an hour.
Our primary customer for coal produced at Mettiki is Virginia Electric and
Power Company (VEPCO), which purchases the coal pursuant to a long-term contract
for use in the generating units at its Mt. Storm, West Virginia power plant,
located less than 20 miles away. Our coal is trucked to Mt. Storm over a private
haul road, which links to a state highway. Mettiki is also served by the CSX
railroad. We also process coal at Mettiki for Anker Energy Corporation and one
of its affiliates.
Mettiki Coal (WV), LLC. Mettiki (WV) has approximately 15.8 million tons of
undeveloped recoverable reserves in Grant and Tucker Counties, West Virginia
adjacent to Mettiki in Garrett County, Maryland. We currently conduct no mining
operations at Mettiki (WV).
OTHER OPERATIONS
MT. VERNON TRANSFER TERMINAL, LLC
The Mt. Vernon terminal is a rail-to-barge loading terminal on the Ohio
River in Mt. Vernon, Indiana. The terminal has a capacity of 5.5 million tons
per year with existing ground storage. The terminal was used from 1983 through
1998 for shipments from Pattiki and Dotiki under our coal supply agreement with
Seminole. Seminole now transports these shipments to its generating units
directly by CSX railroad. We recently entered into coal supply agreements that
are intended to ship approximately 1.4 million tons through the Mt. Vernon
terminal in 2002.
COAL SYNFUEL
We recently entered into long-term agreements with Synfuel Solutions
Operating LLC (SSO) to host and operate its coal synfuel facility at Hopkins
County Coal, supply coal feedstock, assist with the coal synfuel marketing and
provide other services through December 31, 2007. These agreements provide us
with coal sales and service fees from SSO based on the synfuel facility
throughput tonnage, which amounts are dependent on the ability of the facility's
owners to use certain qualifying tax credits applicable to the facility. A
portion of these services will be performed by a newly formed subsidiary,
Alliance Service, Inc., which is subject to federal and state income tax. As
discussed above in "Mining Operations; Illinois Basin; Hopkins County Coal", we
now sell most of the coal produced at our Hopkins County Coal mining complex to
SSO, while Alliance Coal Sales, an unincorporated sales business unit of
Alliance Coal, assists SSO with the sale of its coal synfuel to our customers
pursuant to a sales agency agreement. The term of each of these agreements is
subject to early cancellation provisions customary for transactions of these
types, including the unavailability of synfuel tax credits, the termination of
associated coal synfuel sales contracts, and the occurrence of certain force
majeure events. Therefore, the continuation of the operating revenues associated
with the coal synfuel production facility cannot be assured. However, we have
put in place "back up" coal supply agreements with each coal synfuel customer,
which automatically provide for sale of our coal to them in the event they do
not receive coal synfuel.
COAL BROKERAGE
We buy coal from outside producers throughout the eastern United States,
which we then resell, both directly and indirectly, to utility and industrial
customers. We purchased and sold approximately 535,000 tons
7
of outside coal in 2001. We have a policy of matching our outside coal purchases
and sales to minimize market risks associated with buying and reselling coal.
ADDITIONAL SERVICES
We develop and market additional services in order to establish ourselves
as the supplier of choice for our customers. Examples of the kind of services we
have offered to date include ash and scrubber sludge removal, coal yard
maintenance, and arranging alternate transportation services.
COAL MARKETING and SALES
As is customary in the coal industry, we have entered into long-term
contracts with many of our customers. These arrangements are mutually
beneficial. Our utility customers secure a fuel supply for their power plants
for years into the future. Our long-term contracts contribute to both our
customers' and our stability and profitability by providing greater
predictability of sales volumes and sales prices. In 2001, approximately 78% of
our sales tonnage, accounting for 75% of our total revenue, was sold under
long-term contracts (contracts having a term of greater than one year) with
maturities ranging from 2001 to 2012. Our total nominal commitment under
significant long-term contracts was approximately 84.6 million tons at December
31, 2001 and is expected to be delivered as follows: 15.4 million tons in 2002,
12.6 million tons in 2003, 11.9 million tons in 2004 and 11.6 million tons in
2005 and 2006, and 21.5 million tons thereafter during the remaining terms of
the relevant coal supply agreements. The total commitment of coal under contract
is an approximate number because, in some instances, our contracts contain
provisions that could cause the nominal total commitment to increase or decrease
by as much as 20%. The contractual time commitments for customers to nominate
future purchase volumes under these contracts are sufficient to allow us to
balance our sales commitments with production capacity. In addition, the nominal
total commitment can otherwise change because of price reopener provisions
contained in certain of these long-term contracts. We believe our long-term
contract position compares favorably to those of our competitors.
The terms of long-term contracts are the results of both bidding procedures
and extensive negotiations with the customer. As a result, the terms of these
contracts vary significantly in many respects, including, among others, price
adjustment features, price and contract reopener terms, permitted sources of
supply, force majeure provisions, coal qualities, and quantities. Virtually all
of our long-term contracts are subject to price adjustment provisions which
permit an increase or decrease periodically in the contract price to reflect
changes in specified price indices or items such as taxes, royalties or actual
production costs. These provisions, however, may not assure that the contract
price will reflect every change in production or other costs. Failure of the
parties to agree on a price pursuant to an adjustment or a reopener provision
can lead to early termination of a contract. Some of the long-term contracts
also permit the contract to be reopened to renegotiate terms and conditions
other than the pricing terms, and where a mutually acceptable agreement on terms
and conditions cannot be concluded, either party may have the option to
terminate the contract. The long-term contracts typically stipulate procedures
for quality control, sampling and weighing. Most contain provisions requiring us
to deliver coal within stated ranges for specific coal characteristics such as
heat, sulfur, ash, moisture, grindability, volatility and other qualities.
Failure to meet these specifications can result in economic penalties or
termination of the contracts. While most of the contracts specify the approved
seams and/or approved locations from which the coal is to be mined, some
contracts allow the coal to be sourced from more than one mine or location.
Although the volume to be delivered pursuant to a long-term contract is
stipulated, the buyers often have the option to vary the volume within specified
limits.
RELIANCE on MAJOR CUSTOMERS
Our three largest customers in 2001 were Seminole, TVA and VEPCO. Sales to
these customers in the aggregate accounted for approximately 41% of our 2001
total revenues, and sales to each of these customers
8
accounted for more than 10% of our 2001 total revenues. Each of these customers
has purchased coal regularly from us for more than 15 years. In addition, under
the agreements we have entered into with SSO to supply coal feedstock and other
services, we now sell most of the coal produced at our Hopkins County Coal
facility to SSO. SSO, through Alliance Coal Sales, acting as its agent, in turn
sells coal synfuel to our former customers at Hopkins County Coal, including
TVA. As a result, in 2002 it is likely that our coal sales to SSO will account
for more than 10% of our revenues, while our sales to TVA will no longer account
for more than 10% of our revenues.
On February 28, 2002, a major customer of our Pontiki mine (not one of the
three major customers discussed above) voluntarily filed for Chapter 11
bankruptcy protection. Accompanying the bankruptcy filing was a pre-packaged
plan of reorganization unanimously approved by certain creditor classes. The
customer has represented in its bankruptcy filing and public press releases that
all existing trade claims will be paid in full and a vast majority of its
contracts will be continued without any adverse impact. All of the accounts
receivable under the long-term contract with this customer are current.
Management does not anticipate that this event will have a material impact on
our financial condition or results of operations.
COMPETITION
The United States coal industry is highly competitive with numerous
producers in all coal producing regions. We compete with other large producers
and hundreds of small producers in the United States. The largest coal company
is estimated to have sold approximately 15% of the total 2001 tonnage sold in
the United States market. We compete with other coal producers primarily on the
basis of coal price at the mine, coal quality (including sulfur content),
transportation cost from the mine to the customer, and the reliability of
supply. Continued demand for our coal and the prices that we obtain are also
affected by demand for electricity, environmental and government regulations,
technological developments, and the availability and price of alternative fuel
supplies, including nuclear, natural gas, oil, and hydroelectric power.
TRANSPORTATION
Our coal is transported to our customers by rail, truck and barge.
Depending on the proximity of the customer to the mine and the transportation
available for delivering coal to that customer, transportation costs can range
from 10% to 80% of the delivered cost of a customer's coal. As a consequence,
the availability and cost of transportation constitute important factors in the
marketability of coal. We believe our mines are located in favorable geographic
locations that minimize transportation costs for our customers.
Customers pay the transportation costs from the contractual F.O.B. point
(free-on-board point), which is consistent with practice in the industry and is
generally from the mine to the customer's plant. In 2001, the largest volume
transporter of our coal production was the CSX railroad, which moved
approximately 50% of our tonnage over its rail system. The practices of, and
rates set by, the railroad serving a particular mine or customer might affect,
either adversely or favorably, our marketing efforts with respect to coal
produced from the relevant mine. At our Gibson and Mettiki mines, a contractor
operates a truck delivery system that transports the coal from the mine to the
primary customer's power plant.
REGULATION AND LAWS
The coal mining industry is subject to regulation by federal, state and
local authorities on matters such as:
- employee health and safety;
- mine permits and other licensing requirements;
- air quality standards;
- water pollution;
9
- storage of petroleum products and substances which are regarded as
hazardous under applicable laws or which, if spilled, could reach
waterways or wetlands;
- storage and handling of explosives;
- plant and wildlife protection;
- reclamation and restoration of mining properties after mining is
completed;
- the discharge of materials into the environment;
- management of solid wastes generated by mining operations;
- protection of wetlands;
- management of electrical equipment containing polychlorinated biphenyls
(PCBs);
- surface subsidence from underground mining;
- the effects (if any) that mining has on groundwater quality and
availability; and
- legislatively mandated benefits for current and retired coal miners.
In addition, the utility industry is subject to extensive regulation
regarding the environmental impact of its power generation activities, which
could affect demand for our coal. The possibility exists that new legislation or
regulations, or new interpretations of existing laws or regulations, may be
adopted that may have a significant impact on our mining operations or our
customers' ability to use coal, or may require us or our customers to change our
or their operations significantly or to incur substantial costs.
We are committed to conducting mining operations in compliance with all
applicable federal, state and local laws and regulations. However, because of
extensive and comprehensive regulatory requirements, violations during mining
operations are not unusual in the industry and, notwithstanding our compliance
efforts, we do not believe these violations can be eliminated completely. None
of the violations to date or the monetary penalties assessed at our operations
have been material.
While it is not possible to quantify the costs of compliance with all
applicable federal and state laws, those costs have been and are expected to
continue to be significant. Capital expenditures for environmental matters have
not been material in recent years. We have accrued for the present value
estimated cost of reclamation and mine closing, including the cost of treating
mine water discharge, when necessary. The accrual for reclamation and mine
closing costs is based upon permit requirements and the costs and timing of
reclamation and mine closing procedures. Although management believes it has
made adequate provisions for all expected reclamation and other costs associated
with mine closures, future operating results would be adversely affected if we
later determine these accruals to be insufficient. Compliance with these laws
has substantially increased the cost of coal mining for all domestic coal
producers.
MINING PERMITS AND APPROVALS
Numerous governmental permits or approvals are required for mining
operations. We may be required to prepare and present to federal, state or local
authorities data pertaining to the effect or impact that any proposed production
of coal may have upon the environment. All requirements imposed by any of these
authorities may be costly and time-consuming, and may delay commencement or
continuation of mining operations. Future legislation and administrative
regulations may emphasize more heavily the protection of the environment and, as
a consequence, our activities may be more closely regulated. Legislation and
regulations, as well as future interpretations of existing laws, may require
substantial increases in equipment and operating costs, or delays, interruptions
or termination of operations, the extent of any of which cannot be predicted.
Before commencing mining on a particular property, we must obtain mining
permits and approvals by state regulatory authorities of a reclamation plan for
restoring, upon the completion of mining, the mined property to its approximate
prior condition, productive use or other permitted condition. Typically, we
commence actions to obtain permits between 18 and 24 months before we plan to
mine a new area. In our experience, permits generally are approved within 12
months after a completed application is submitted. We
10
have not experienced material or significant difficulties in obtaining mining
permits in the areas where our reserves are currently located. However, we
cannot assure you that we will not experience difficulty in obtaining mining
permits in the future.
On January 29, 2002, the West Virginia Department of Environmental
Protection (West Virginia DEP) denied a permit application for the mining of
approximately 3.1 million tons of Mettiki (WV)'s non-reserve coal deposits.
Mettiki planned to mine the tons covered by the denied permit from its existing
underground infrastructure because this portion of Mettiki (WV)'s non-reserve
coal deposits are contiguous to Mettiki's reserves located in Maryland. We have
appealed the permit denial by the West Virginia DEP to the West Virginia Surface
Mining Board and hearings have been scheduled during May 2002.
Under some circumstances, substantial fines and penalties, including
revocation of mining permits, may be imposed under the laws described above.
Monetary sanctions and, in severe circumstances, criminal sanctions may be
imposed for failure to comply with these laws. Regulations also provide that a
mining permit can be refused or revoked if the permit applicant or permittee
owns or controls, directly or indirectly through other entities, mining
operations which have outstanding environmental violations. Although we have
been cited for violations in the ordinary course of our business, we have never
had a permit suspended or revoked because of any violation, and the penalties
assessed for these violations have not been material.
MINE HEALTH AND SAFETY LAWS
Stringent safety and health standards have been imposed by federal
legislation since 1969 when the Coal Mine Health and Safety Act of 1969 (CMHSA)
was adopted. CMHSA resulted in increased operating costs and reduced
productivity. The Federal Mine Safety and Health Act of 1977, which
significantly expanded the enforcement of health and safety standards of CMHSA,
imposes comprehensive safety and health standards on all mining operations.
Regulations are comprehensive and affect numerous aspects of mining operations,
including training of mine personnel, mining procedures, blasting, the equipment
used in mining operations and other matters. The Mine Safety and Health
Administration monitors compliance with these federal laws and regulations. In
addition, as part of CMHSA and the Mine Safety and Health Act of 1977, the Black
Lung Benefits Act requires payments of benefits by all businesses that conduct
current mining operations to a coal miner with black lung disease and to some
survivors of a miner who dies from this disease. Most of the states where we
operate also have state programs for mine safety and health regulation and
enforcement. In combination, federal and state safety and health regulation in
the coal mining industry is perhaps the most comprehensive and rigorous system
for protection of employee safety and health affecting any segment of any
industry. Even the most minute aspects of mine operations, particularly
underground mine operations, are subject to extensive regulation. This
regulation has a significant effect on our operating costs. For example, new
regulations governing exposures to diesel particulate matter in underground
mines will likely increase our compliance costs in 2002. However, our
competitors in all of the areas in which we operate are subject to the same laws
and regulations.
BLACK LUNG BENEFITS ACT (BLBA)
The Federal BLBA levies a tax on production of $1.10 per ton for
underground-mined coal and $0.55 per ton for surface-mined coal, but not to
exceed 4.4% of the applicable sales price, in order to compensate miners who are
totally disabled due to black lung disease and some survivors of miners who died
from this disease, and who were last employed as miners prior to 1970 or
subsequently where no responsible coal mine operator has been identified for
claims. In addition, BLBA provides that some claims for which coal operators had
previously been responsible will be obligations of the government trust funded
by the tax. The Revenue Act of 1987 extended the termination date of this tax
from January 1, 1996, to the earlier of January 1, 2014, or the date on which
the government trust becomes solvent. For miners last employed as miners after
1969 and who are determined to have contracted black lung, we self-insure
against potential cost using actuarially
11
determined estimates of the cost of present and future claims. We are also
liable under state statutes for black lung claims.
The U.S. Department of Labor published revised regulations in December
2000, that became effective in January 2001, that will alter the claims process
for federal black lung benefit recipients, which among other things:
- simplify administrative procedures for the adjudication of claims;
- propose preference for the miner's treating physician under certain
circumstances;
- allow previously denied claims to be refiled and litigated under a
different standard;
- limit the amount of evidence all parties may submit for consideration;
- create a rebuttable presumption that medical treatment for any
pulmonary condition is caused or aggravated by the miner's work; and
- expand the definition of pneumoconiosis and total disability.
Because the revised regulations are expected to result in an increase in
the incidence and recovery of black lung claims, both the coal and insurance
industries are currently challenging certain provisions of the revised
regulations through litigation. A federal judge upheld these regulations in
August 2001. An appeal was filed in August 2001. In addition, Congress and state
legislatures regularly consider various items of black lung legislation, which,
if enacted, could adversely affect our business financial condition and results
of operations.
WORKERS' COMPENSATION
We are required to compensate employees for work-related injuries. Several
states in which we operate consider changes in workers compensation laws from
time to time.
COAL INDUSTRY RETIREE HEALTH BENEFITS ACT (CIRHBA)
The Federal CIRHBA was enacted to provide for the funding of health
benefits for some United Mine Workers of America retirees. The act merged
previously established union benefit plans into a single fund into which
"signatory operators" and "related persons" are obligated to pay annual premiums
for beneficiaries. The act also created a second benefit fund for miners who
retired between July 21, 1992, and September 30, 1994, and whose former
employers are no longer in business. Because of our union-free status, we are
not required to make payments to retired miners under CIRHBA, with the exception
of limited payments made on behalf of predecessors of MC Mining, LLC. However,
in connection with the sale of the coal assets acquired by Alliance Resource
Holdings in 1996, MAPCO Inc. agreed to retain, and be responsible for, all
liabilities under CIRHBA.
SURFACE MINING CONTROL AND RECLAMATION ACT (SMCRA)
The Federal SMCRA establishes operational, reclamation and closure
standards for all aspects of surface mining as well as many aspects of deep
mining. The act requires that comprehensive environmental protection and
reclamation standards be met during the course of and upon completion of mining
activities. In conjunction with mining the property, we reclaim and restore the
mined areas by grading, shaping and preparing the soil for seeding. Upon
completion of the mining, reclamation generally is completed by seeding with
grasses or planting trees for a variety of uses, as specified in the approved
reclamation plan. We believe that we are in compliance in all material respects
with applicable regulations relating to reclamation.
SMCRA and similar state statutes, require, among other things, that mined
property be restored in accordance with specified standards and approved
reclamation plans. The act requires us to restore the surface to approximate the
original contours as contemporaneously as practicable with the completion of
surface
12
mining operations. The mine operator must submit a bond or otherwise secure the
performance of these reclamation obligations. The earliest a reclamation bond
can be released is five years after reclamation has been achieved. Federal law
and some states impose on mine operators the responsibility for replacing
certain water supplies damaged by mining operations and repairing or
compensating for damage occurring on the surface as a result of mine subsidence,
a consequence of longwall mining and possibly other mining operations. In
addition, the Abandoned Mine Lands Program, which is part of SMCRA, imposes a
tax on all current mining operations, the proceeds of which are used to restore
mines closed before 1977. The maximum tax is $0.35 per ton on surface-mined coal
and $0.15 per ton on underground-mined coal. We have accrued for the estimated
costs of reclamation and mine closing, including the cost of treating mine water
discharge when necessary. In addition, states from time to time have increased
and may continue to increase their fees and taxes to fund reclamation of
orphaned mine sites and acid mine drainage control on a statewide basis.
Under SMCRA, responsibility for unabated violations, unpaid civil penalties
and unpaid reclamation fees of independent contract mine operators and other
third parties can be imputed to other companies which are deemed, according to
the regulations, to have "owned" or "controlled" the third party violator.
Sanctions against the "owner" or "controller" are quite severe and can include
being blocked from receiving new permits and revocation of any permits that have
been issued since the time of the violations or, in the case of civil penalties
and reclamation fees, since the time their amounts became due. We are not aware
of any currently pending or asserted claims against us relating to the
"ownership" or "control" theories discussed above. However, we cannot assure you
that such claims will not develop in the future.
CLEAN AIR ACT (CAA)
The Federal CAA and similar state laws, which regulate emissions into the
air, affect coal mining and processing operations primarily through permitting
and emissions control requirements. The CAA also indirectly affects coal mining
operations by extensively regulating the air emissions of coal-fired electric
power generating plants. For example, the CAA requires reduction of sulfur
dioxide (SO2) emissions from electric power generation plants in two phases.
Only some facilities were subject to the Phase I requirements. Beginning in year
2000, Phase II requires nearly all facilities to reduce emissions. The effected
utilities are able to meet these requirements by:
- switching to lower sulfur fuels;
- installing pollution control devices such as scrubbers;
- reducing electricity generating levels; or
- purchasing or trading so-called pollution "credits."
Specific emissions sources receive these "credits" that utilities and
industrial concerns can trade or sell to allow other units to emit higher levels
of SO2. In addition, the CAA requires a study of utility power plant emissions
of some toxic substances and their eventual regulation, if warranted. The effect
of the CAA cannot be completely ascertained at this time, although the SO2
emissions reduction requirement is projected generally to increase the demand
for lower sulfur coal and potentially decrease demand for higher sulfur coal.
The CAA also indirectly affects coal mining operations by requiring
utilities that currently are major sources of nitrogen oxides (NOx) in moderate
or higher ozone nonattainment areas to install reasonably available control
technology for NOx, which are precursors of ozone. In October 1998, the U.S.
Environmental Protection Agency (EPA) issued a rule requiring 22 eastern states
and the District of Columbia to make substantial reductions in NOx emissions by
the year 2003, which was substantially upheld by the U.S. Court of Appeals for
the D.C. Circuit on March 3, 2000. On March 5, 2001, the U.S. Supreme Court
declined to review that decision, in response to a petition by seven states and
the power and coal industries. This deadline was recently extended by EPA to
2004. EPA expects that affected states will achieve reductions by requiring
power plants to make substantial reductions in their NOx emissions. This in turn
will
13
require power plants to install reasonably available control technology and
additional control measures. Installation of reasonably available control
technology and additional measures required under EPA regulations will make it
more costly to operate coal-fired plants and, depending on the requirements of
individual state implementation plans and the development of revised new source
performance standards, could make coal a less attractive fuel alternative in the
planning and building of utility power plants in the future. Any reduction in
coal's share of the capacity for power generation could have a material adverse
effect on our business, financial condition and results of operations. The
effect these regulations, or other requirements that may be imposed in the
future, could have on the coal industry in general and on our business in
particular cannot be predicted with certainty. We cannot assure you that the
implementation of the CAA, the new National Ambient Air Quality Standards
(NAAQS) discussed below, or any other current or future regulatory provision,
will not materially adversely affect us.
In addition, EPA has already issued and is considering further regulations
relating to fugitive dust and emissions of other coal-related pollutants such as
mercury, nickel, dioxin and fine particulates. For example, in July 1997 EPA
adopted new, more stringent NAAQS for particulate matter, which may require some
states to change existing implementation plans. These NAAQS are expected to be
implemented by 2003. These NAAQS were effectively affirmed by the U.S. Supreme
Court on February 27, 2001, subject to the resolution of certain issues pending
on remand. That decision upheld the constitutionality of EPA's NAAQS statutory
authority, finding that EPA acted properly in not considering costs in setting
the NAAQS, and remanded the case to the U.S. Court of Appeals for the D.C.
Circuit to dispose of any remaining challenges to the rules. On March 26, 2002,
the U.S. Court of Appeals for the D.C. Circuit upheld EPA's NAAQS. Because coal
mining operations and utilities emit particulate matter, our mining operations
and utility customers are likely to be directly affected when the revisions to
the NAAQS are implemented by the states. Both Congress and EPA are considering
additional controls on other air pollutants emitted by electric utilities. Any
such controls, if adopted, could adversely affect the market for coal.
EPA has filed suit against a number of our customers over implementation of
new source performance standards and preconstruction review requirements for new
sources and major modifications under the prevention of significant
deterioration and nonattainment regulations. This issue surrounds the issue of
what constitutes regular maintenance versus new construction. Some of our
customers have agreed to or proposed settlements with EPA while others are
preparing for litigation. These and other regulatory developments may restrict
the size of our market, and the type of coal in demand. This in turn could
adversely affect our ability to develop new mines, or could require us or our
customers to modify existing operations.
FRAMEWORK CONVENTION ON GLOBAL CLIMATE CHANGE (KYOTO PROTOCOL)
The United States and more than 160 other nations are signatories to the
Kyoto Protocol which is intended to limit or capture emissions of greenhouse
gases, such as carbon dioxide. The Kyoto Protocol established a binding set of
emissions targets for developed nations. The specific limits vary from country
to country. Under the terms of the Kyoto Protocol, the United States would be
required to reduce emissions to 93% of 1990 levels over a five-year budget
period from 2008 through 2012. The Clinton Administration signed the Kyoto
Protocol in November 1998. Although the U.S. Senate has not ratified the Kyoto
Protocol and no comprehensive regulations focusing on greenhouse gas emissions
have been enacted, efforts to control greenhouse gas emissions could result in
reduced use of coal if electric power generators switch to lower carbon sources
of fuel.
In March 2001, President Bush expressed his opposition to the Kyoto
Protocol and stated that he did not believe that the government should impose
mandatory carbon dioxide emission reductions on power plants. In February 2002,
President Bush proposed voluntary actions to reduce greenhouse gas intensity of
the United States. Greenhouse gas intensity measures the ratio of greenhouse gas
emissions, such as carbon dioxide, to economic output. The President's climate
change initiative calls for a reduction in greenhouse gas intensity
14
over the next ten years, which is approximately equivalent to the reduction that
has occurred over each of the past two decades. These restrictions, if
established through regulation or legislation, could have a material adverse
effect on our business, financial condition and results of operations.
CLEAN WATER ACT (CWA)
The Federal CWA affects coal mining operations by imposing restrictions on
effluent discharge into waters. Regular monitoring, as well as compliance with
reporting requirements and performance standards, are preconditions for the
issuance and renewal of permits governing the discharge of pollutants into
water. We are also subject to CWA Section 404, which imposes permitting and
mitigation requirements associated with the dredging and filling of wetlands.
The CWA and equivalent state legislation, where such equivalent state
legislation exists, affect coal mining operations that impact wetlands. We
believe we have obtained all necessary wetlands permits required under CWA
Section 404. However, mitigation requirements under those existing, and possible
future, wetlands permits may vary considerably. In January 2001, the U.S Supreme
Court issued a decision narrowing the CWA jurisdiction over isolated wetlands
not connected to navigable waters. It is not yet known how this will affect
wetland mitigation and protection programs under federal and state laws. At this
time we do not anticipate any increase in such requirements or in post-mining
reclamation accrual requirements. For that reason, the setting of post-mine
reclamation accruals for such mitigation projects is difficult to ascertain with
certainty. We believe that we have obtained all permits required under the CWA
as traditionally interpreted by the responsible agencies. Although more
stringent permitting requirements may be imposed in the future, we are not able
to accurately predict the impact, if any, of any such permitting requirements.
However, each individual state is required to submit to EPA their biennial
CWA Section 303(d) lists identifying all waterbodies not meeting state specified
water quality standards. For each listed waterbody, the state is required to
begin developing a Total Maximum Daily Load (TMDL) to:
- determine the maximum pollutant loading the waterbody can assimilate
without violating water quality standards,
- identify all current pollutant sources and loadings to that waterbody,
- calculate the pollutant loading reduction necessary to achieve water
quality standards, and
- establish a means of allocating that burden among and between the point
and non-point sources contributing pollutants to the waterbody.
We are currently participating in stakeholders meetings and in negotiations
with states and EPA to establish reasonable TMDLs that will accommodate
expansion. These and other regulatory developments may restrict our ability to
develop new mines, or could require us or our customers to modify existing
operations, the extent of which we cannot accurately or reasonably predict.
SAFE DRINKING WATER ACT (SDWA)
The Federal SDWA and its state equivalents affect coal mining operations by
imposing requirements on the underground injection of fine coal slurries, fly
ash, and flue gas scrubber sludge, and by requiring a permit to conduct such
underground injection activities. The inability to obtain these permits could
have a material impact on our ability to inject materials such as fine coal
refuse, fly ash, or flue gas scrubber sludge into the inactive areas of some of
our old underground mine workings.
In addition to establishing the underground injection control program, the
Federal SDWA also imposes regulatory requirements on owners and operators of
"public water systems." This regulatory program could impact our reclamation
operations where subsidence, or other mining-related problems, require the
provision of drinking water to affected adjacent homeowners. However, the
Federal SDWA defines a "public water system" for purposes of regulatory
jurisdiction as a system for the provision to the public of water for human
15
consumption through pipes or other constructed conveyances, if the system has at
least fifteen service connections or regularly serves at least twenty-five
individuals. It is unlikely that any of our reclamation activities would require
the provision of such a "public water system." While we have drinking water
supply sources for our employees and contractors that are subject to SDWA
regulation, the SDWA is unlikely to have a material impact on our operations.
COMPREHENSIVE ENVIRONMENTAL RESPONSE, COMPENSATION AND LIABILITY ACT
(CERCLA)
The Federal CERCLA and similar state laws affect coal mining operations by,
among other things, imposing cleanup requirements for threatened or actual
releases of hazardous substances that may endanger public health or welfare or
the environment. Under CERCLA, and similar state laws, joint and several
liability may be imposed on waste generators, site owners and operators and
others regardless of fault or the legality of the original disposal activity.
Some products used by coal companies in operations, such as chemicals, generate
waste containing hazardous substances, which are governed by the statute. Thus,
coal mines that we currently own or have previously owned or operated, and sites
to which we sent waste materials, may be subject to liability under CERCLA and
similar state laws. We have been, on rare occasions, the subject of
administrative proceedings, litigation and investigations relating to CERCLA
matters, none of which has had a material adverse effect on our financial
condition or results of operations. We cannot assure you that we will not become
involved in future proceedings, litigation or investigations, or that
liabilities arising out of any such proceedings will not be material.
TOXIC SUBSTANCES CONTROL ACT (TSCA)
The Federal TSCA regulates, among other things, electrical equipment
containing PCBs in excess of 50 parts-per-million. Specifically, TSCA's PCB
rules require that all PCB-containing equipment be properly labeled, stored, and
disposed of, and require the on-site maintenance of annual records regarding the
presence and use of equipment containing PCBs in excess of 50 parts-per-million.
Because the regulated PCB-containing electrical equipment in use in our
operations is owned by the utilities that serve the operations where they are
located, and because the use of PCB-containing fluids in such equipment is in
the process of being phased out, we do not believe TSCA will have a material
impact on our operations.
RESOURCE CONSERVATION AND RECOVERY ACT (RCRA)
The Federal RCRA affects coal mining operations by imposing requirements
for the generation, transportation, treatment, storage, disposal and cleanup of
hazardous wastes. Many mining wastes are excluded from the regulatory definition
of hazardous wastes, and coal mining operations covered by SMCRA permits are
exempted from regulation under RCRA by statute. RCRA also allows EPA to require
corrective action at sites where there is a release of hazardous substances. In
addition, each state has its own laws regarding the proper management and
disposal of waste material. While these laws impose ongoing compliance
obligations, we do not believe that these costs will have a material impact on
our operations.
COAL COMBUSTION BY-PRODUCTS
In 2000, EPA declined to impose hazardous wastes regulatory controls on the
disposal of some coal combustion by-products, including the practice of using
coal combustion by-products as minefill. However, EPA is currently evaluating
the possibility of placing additional solid waste burdens on the disposal of
these types of materials, but it may be several years before these standards
will be developed.
While we cannot predict the ultimate outcome of EPA's assessment, we
believe the beneficial uses of coal combustion by-products (like the practice of
placing this by-product in abandoned mine areas) that we employ do not
constitute poor environmental practices because among other things, our CWA
discharge permits for treated acid mine drainage contain parameters for
pollutants of concern,
16
such as metals, and those permits require monitoring and reporting of effluent
quality data. Small quantities of regulated hazardous wastes are generated at
some of our facilities. However, we do not believe that the cost of complying
with applicable regulations for those wastes will have a material impact on our
operations.
OTHER ENVIRONMENTAL, HEALTH AND SAFETY REGULATION
In addition to the laws and regulations described above, we are subject to
regulations regarding underground and above ground storage tanks where we may
store petroleum or other substances. Some monitoring equipment that we use is
subject to licensing under the Federal Atomic Energy Act. Water supply wells
located on our property are subject to federal, state and local regulation. The
costs of compliance with these requirements should not have a material adverse
effect on our business, financial condition or results of operations.
EMPLOYEES
We have approximately 1,745 employees, including approximately 100
corporate employees and approximately 1,645 employees involved in active mining
operations. Our work-force is entirely union-free. Relations with our employees
are generally good.
ITEM 2. PROPERTIES
COAL RESERVES
We must obtain permits from applicable state regulatory authorities before
beginning to mine particular 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 performance under our permits. As is typical in
the coal industry, we strive to obtain mining permits within a time frame that
allows us to mine reserves as planned on an uninterrupted basis. We begin
preparing applications for permits for areas that we intend to mine sufficiently
in advance of our planned mining activities to allow adequate time to complete
the permitting process. 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 intervention in the
courts. For the reserves set forth in the table below, we are not currently
aware of matters which would significantly hinder our ability to obtain future
mining permits on a timely basis.
Our reported coal reserves are those that we believe can be economically
and legally extracted or produced at the time of the filing of this Annual
Report on Form 10-K. In determining whether our reserves meet this economical
and legal standard, we take into account, among other things, our potential
ability or 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 mining permits, variations in quantity and
quality of coal, and varying levels of demand and their effects on selling
prices.
As of December 31, 2001, we had approximately 400.7 million tons of coal
reserves. All of the estimates of reserves which are presented in this Annual
Report on Form 10-K are of proven and probable reserves.
The following table sets forth reserve information, as of December 31,
2001, about each of our mining complexes.
17
<Table>
<Caption>
Heat Proven and Probable Reserves
Content ------------------------------- Reserve Assignment
Mine (Btus Pounds SO2 per MMbtu --------------------
Operations Type per pound) <1.2 1.2 - 2.5 >2.5 Total Assigned Unassigned
- ---------- ----------- ---------- ---- --------- ---- ----- -------- ----------
(tons in millions)
Illinois Basin Operations
Dotiki Underground 12,500 -- -- 88.9 88.9 88.9 --
Pattiki Underground 11,700 -- -- 53.9 53.9 53.9 --
Hopkins County Underground 11,300 -- -- 21.4 21.4 1.4 20.0
Coal / Surface -- -- 11.6 11.6 11.6 --
Gibson County Underground 11,600 -- 36.2 -- 36.2 36.2 --
Coal (North)
Gibson County Underground 11,600 -- 55.0 44.9 99.9 -- 99.9
Coal (South)
---- ----- ----- ----- ----- -----
Region Total -- 91.2 220.7 311.9 192.0 119.9
---- ----- ----- ----- ----- -----
East Kentucky Operations
Pontiki/Excel Underground 12,800 16.0 1.9 -- 17.9 17.9 --
MC Mining/Excel Underground 12,800 22.0 -- -- 22.0 22.0 --
---- ----- ----- ----- ----- -----
Region Total 38.0 1.9 -- 39.9 39.9 --
---- ----- ----- ----- ----- -----
Maryland Operations
Mettiki Underground 13,000 -- 15.0 18.1 33.1 18.1 15.0
Mettiki(WV) Underground 13,000 -- -- 15.8 15.8 10.2 5.6
---- ----- ----- ----- ----- -----
-- 15.0 33.9 48.9 28.3 20.6
---- ----- ----- ----- ----- -----
Total 38.0 108.1 254.6 400.7 260.2 140.5
==== ===== ===== ===== ===== =====
% of Total 9.5% 27.0% 63.5% 100.0% 64.9% 35.1%
==== ==== ==== ===== ==== ====
</Table>
Our reserve estimates are prepared from geological data assembled and
analyzed by our staff of geologists and engineers. This data is obtained through
our extensive, ongoing exploration drilling and in-mine channel sampling
programs. Our drill spacing criteria adhere to standards as defined by the U.S.
Geological Survey. The maximum acceptable distance from seam data points varies
with the geologic nature of the coal seam being studied, but generally the
standard for (a) proven reserves is that points of observation are no greater
than 1/2 mile apart, and are projected to extend as a 1/4 mile wide belt around
each point of measurement and (b) probable reserves is that the points of
observation are between 1/2 and 1 1/2 miles apart and are projected to extend as
a 1/2 mile wide belt that lies 1/4 mile from the points of measurement.
Reserve estimates will change from time to time in reflection of mining
activities, analysis and new engineering and geological data, acquisition or
divestment of reserve holdings, modification of mining plans or mining methods,
and other factors. Weir International Mining Consultants performed an overview
audit of all of our reserves as of March 31, 1999 in conjunction with our
initial public offering.
Reserves represent that part of a mineral deposit that can be economically
and legally extracted or produced, and reflects estimated losses involved in
producing a saleable product. All of our reserves are steam coal. The 38.0
million tons of reserves listed as <1.2 pounds of SO2 per MMbtu are compliance
coal.
Assigned reserves are those reserves that have been designated for mining
by a specific operation.
Unassigned reserves are those reserves that have not yet been designated
for mining by a specific operation.
BTU values are reported on an as shipped, fully washed, basis. Shipments
that are either fully or partially raw will have a lower BTU value.
18
A permit application related to the 15.8 million tons of reserves
controlled by Mettiki (WV) has been submitted to the West Virginia Department of
Environmental Protection ("West Virginia DEP"). The West Virginia DEP has not
advised us concerning the status of the permit application. In regard to a
different permit application concerning other coal reserves, on January 29,
2002, the West Virginia DEP denied such permit application related to 3.1
million tons of coal that are not contiguous to the 15.8 million tons of
reserves. Consequently, the 3.1 million tons is classified as a non-reserve coal
deposit and not included in our reported reserves. The permit denial has been
appealed to the West Virginia Surface Mining Board.
We control certain leases for coal deposits that are nearby, but not
contiguous to our primary reserve bases. The tons controlled by these leases are
classified as non-reserve coal deposits and are not included in our reported
reserves. These non-reserve coal deposits are as follows: Dotiki - 2.6 million
tons, Pattiki - 5.8 million tons, Gibson County North - 2.0 million tons, and
Gibson County South - 4.3 million tons.
We lease almost all of our reserves and generally have the right to
maintain the lease in force until the exhaustion of minable and merchantable
coal located within the leased premises or a larger coal reserve area. These
leases provide for royalties to be paid to the lessor at a fixed amount per ton
or as a percentage of the sales price. Many leases require payment of minimum
royalties, payable either at the time of the execution of the lease or in
periodic installments, even if no mining activities have begun. These minimum
royalties are normally credited against the production royalties owed to a
lessor once coal production has commenced.
The following table sets forth production data about each of our mining
complexes.
<Table>
<Caption>
Tons Produced
------------------
Operations 2001 2000 1999 Transportation Equipment
- ---------- ---- ---- ---- ----------------- ---------
(tons in millions)
Illinois Basin Operations
Dotiki 4.6 3.9 3.6 CSX; truck; barge CM
Pattiki 1.9 2.3 2.3 CSX; truck; barge CM
Hopkins County Coal 2.0 2.1 2.6 CSX, PAL; truck DL; CM
Gibson County Coal (North) 1.7 0.1 -- Truck CM
---- ---- ----
Region Total 10.2 8.4 8.5
---- ---- ----
East Kentucky Operations
Pontiki/Excel 1.7 1.9 1.8 NS; truck CM
MC Mining/Excel 1.1 0.8 1.0 NS; truck CM
---- ---- ----
Region Total 2.8 2.7 2.8
---- ---- ----
Maryland Operations
Mettiki 2.7 2.6 2.8 Truck; CSX LW; CM
---- ---- ----
Total 15.7 13.7 14.1
---- ---- ----
</Table>
CSX -- CSX Railroad
PAL -- Paducah and Louisville Railroad
NS -- Norfolk & Southern Railroad
CM -- Continuous Miner
DL -- Dragline with Stripping Shovel, Front End Loaders and Dozers
LW -- Longwall
RISK FACTORS
If any of the following risks were actually to occur, our business,
financial condition or results of operations could be materially adversely
affected and the trading price of our common units could decline.
19
RISKS INHERENT IN OUR BUSINESS
- Competition within the coal industry may adversely affect our ability
to sell coal, and excess production capacity in the industry could put
downward pressure on coal prices.
- We expect most newly constructed power plants to be fueled by natural
gas. Any change in consumption patterns by utilities away from the use
of coal could affect our ability to sell the coal we produce.
- From time to time conditions in the coal industry may make it more
difficult for us to extend existing or enter into new long-term
contracts. This could affect the stability and profitability of our
operations.
- Some of our long-term contracts contain provisions allowing for the
renegotiation of prices and, in some instances, the termination of the
contract or the suspension of purchases by customers.
- Some of our long-term contracts require us to supply all of our
customers coal needs. If these customers' coal requirements decline,
our revenues under these contracts will also drop.
- A substantial portion of our coal has a high-sulfur content. This coal
may become more difficult to sell because the Clean Air Act may impact
the ability of electric utilities to burn high-sulfur coal through the
regulation of emissions.
- We depend on a few customers for a significant portion of our revenues,
and the loss of one or more significant customers could impact our
ability to sell the coal we produce.
- Litigation relating to disputes with our customers may result in
substantial costs, liabilities and loss of revenues.
- The term of each of the agreements associated with the coal synfuel
facility at Hopkins County Coal is subject to early cancellation
provisions customary for transactions of these types, including the
unavailability of synfuel tax credits, the termination of associated
coal synfuel sales contracts, and the occurrence of certain force
majeure events. Therefore, the continuation of the operating revenues
associated with the coal synfuel production facility cannot be assured.
- Any loss of the benefit from state tax credits may affect adversely our
ability to pay distributions.
- Coal mining is subject to inherent risks that are beyond our control
and these risks may not be fully covered under our insurance policies.
- Any significant increase in transportation costs or disruption of the
transportation of our coal may impair our ability to sell coal.
- We may not be able to grow successfully through future acquisitions,
and we may not be able to effectively integrate the various businesses
or properties we do acquire.
- Our business may be adversely affected if we are unable to replace our
coal reserves.
- The estimates of our reserves may prove inaccurate, and unitholders
should not place undue reliance on these estimates.
20
- Cash distributions are not guaranteed and may fluctuate with our
performance. In addition, our managing general partner's discretion in
establishing reserves may negatively impact a unitholder's receipt of
cash distributions.
- Our indebtedness may limit our ability to borrow additional funds, make
distributions to unitholders or capitalize on business opportunities.
RISKS INHERENT IN AN INVESTMENT IN THE PARTNERSHIP
- Unitholders have limited voting rights and do not control our managing
general partner.
- We may issue additional common units without the approval of common
unitholders, which would dilute existing unitholders' interests.
- The issuance of additional common units, including upon conversion of
subordinated units, will increase the risk that we will be unable to
pay the full minimum quarterly distribution on all common units.
- Cost reimbursements to our general partners may be substantial and will
reduce our cash available for distribution.
- Our managing general partner has a limited call right that may require
unitholders to sell their common units at an undesirable time or price.
- Unitholders may not have limited liability under some circumstances.
REGULATORY RISKS
- Federal and state laws require bonds to secure our obligations related
to (a) the statutory requirement that we return mined property to its
approximate original condition and (b) workers compensation. We may
have difficulty maintaining our surety bonds for mine reclamation as
well as workers' compensation and black lung benefits. As of December
31, 2001, we had $64.1 million of surety bonds in place. Our failure to
maintain, or inability to acquire, surety bonds that are required by
state and federal law would have a material adverse effect on us.
- We are subject to federal, state and local regulations on health,
safety, environmental and numerous other matters. These regulations
increase our costs of doing business, or discourage customers from
buying our coal.
- We have black lung benefits and workers' compensation obligations that
could increase if new legislation is enacted.
- The Clean Air Act affects our customers and could significantly
influence their purchasing decisions. New regulations under the Clean
Air Act could also reduce demand for our coal.
- The passage of legislation responsive to the Kyoto Protocol could
result in a reduced use of coal by electric power generators. Any such
reduction in use could adversely affect our revenues and results of
operations.
21
- We are subject to the Clean Water Act which imposes limitations, and
monitoring and reporting obligations, on our discharge of pollutants
into water. Those limitations and obligations may become more stringent
and result in restricted operations and increased costs.
- We are subject to the Safe Drinking Water Act, which imposes various
requirements on us.
- We are subject to reclamation, mine closure and real property
restoration regulatory obligations and must accrue for the estimated
cost of complying with these regulations.
- We could incur significant costs under federal and state Superfund and
waste management statutes.
TAX RISKS TO COMMON UNITHOLDERS
- The IRS could choose to treat us as a corporation, which would
substantially reduce the cash available for distribution to
unitholders.
- We have not requested an IRS ruling with respect to our tax treatment.
- You may be required to pay taxes on income from us even if you receive
no cash distributions.
- Tax gain or loss on disposition of common units could be different than
expected.
- Common unitholders, other than individuals who are U.S. residents, may
experience adverse tax consequences from owning common units.
- We have registered with the IRS as a tax shelter. This may increase the
risk of an IRS audit of us or a common unitholder.
- We treat a purchaser of common units as having the same tax benefits as
the seller. The IRS may challenge this treatment, which could adversely
affect the value of common units.
- Common unitholders will likely be subject to state and local taxes as a
result of an investment in common units.
ITEM 3. LEGAL PROCEEDINGS
We are subject to various types of litigation in the ordinary course of our
business. Disputes with our customers over the provisions of long-term coal
supply contracts arise occasionally and generally relate to, among other things,
coal quality, quantity, pricing, and the existence of force majeure conditions.
Other than the contract dispute with PSI described under "Other" in Item 8.
Financial Statements and Supplementary Data. - Note 15. Commitments and
Contingencies, we are not involved in any litigation involving our long-term
coal supply contracts. However, we cannot assure you that disputes will not
occur or that we will be able to resolve those disputes in a satisfactory
manner. We are not engaged in any litigation which we believe is material to our
operations, including under the various environmental protection statutes to
which we are subject. The information under "General Litigation" under "Item 8.
Financial Statements and Supplementary Data. - Note 15. Commitments and
Contingencies" is incorporated herein by this reference.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITIES HOLDERS
None.
22
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON UNITS AND RELATED UNITHOLDER MATTERS
The common units representing limited partners' interest are listed on the
Nasdaq National Market under the symbol "ARLP." The common units began trading
on August 20, 1999, when the market price for the initial public offering of the
common units was $19.00 per unit. On March 28, 2002, the closing market price
for the common units was $24.18 per unit. There were approximately 9,200 record
holders and beneficial owners (held in street name) at December 31, 2001 of
common units.
The following table sets forth, the range of high and low sales price per
common unit and the amount of cash distribution declared and paid with respect
to the units, for the two most recent fiscal years.
<Table>
<Caption>
HIGH LOW DISTRIBUTIONS PER UNIT
---- --- ----------------------
1st Quarter 2000 $ 14.50 $ 12.13 $0.50 (paid May 15, 2000)
2nd Quarter 2000 $ 15.13 $ 12.63 $0.50 (paid August 14, 2000)
3rd Quarter 2000 $ 17.75 $ 14.25 $0.50 (paid November 14, 2000)
4th Quarter 2000 $ 18.25 $ 15.00 $0.50 (paid February 14, 2001)
1st Quarter 2001 $ 22.50 $ 16.63 $0.50 (paid May 15, 2001)
2nd Quarter 2001 $ 29.99 $ 20.63 $0.50 (paid August 14, 2001)
3rd Quarter 2001 $ 25.20 $ 21.73 $0.50 (paid November 14, 2001)
4th Quarter 2001 $ 27.45 $ 22.65 $0.50 (paid February 14, 2002)
</Table>
We have also issued 6,422,531 subordinated units, all of which are held by
the special general partner, for which there is no established public trading
market.
We will distribute to our partners (including holders of subordinated
units), on a quarterly basis, all of our available cash. "Available cash"
generally means, with respect to any quarter, all cash on hand at the end of
each quarter less cash reserves in the amount necessary or appropriate in the
reasonable discretion of the managing general partner to (a) provide for the
proper conduct of our business, (b) comply with applicable law of any debt
instrument or other agreement of ours or any of its affiliates, or (c) provide
funds for distributions to unitholders and the general partners for any one or
more of the next four quarters. Available cash is defined in our partnership
agreement listed as an exhibit of this Annual Report on Form 10-K. Our
partnership agreement defines minimum quarterly distributions (MQDs) as $0.50
for each full fiscal quarter. Distributions of available cash to the holder of
the subordinated units are subject to the prior rights of the holders of the
common units to receive MQDs for each quarter during the subordination period,
and to receive any arrearages in the distribution of the MQDs on the common
units for prior quarters during the subordination period. The subordination
period will generally not end before September 30, 2004. Under certain
circumstances, up to half of the subordinated units may convert into common
units before the end of the subordination period, which will generally not occur
before September 30, 2003.
23
ITEM 6. SELECTED FINANCIAL DATA
On August 20, 1999, we completed our initial public offering whereby we
became the successor to the business of our predecessor. Our selected pro forma
and historical financial data below was derived from our audited consolidated
financial statements as of December 31, 2001, 2000 and 1999, for the years ended
December 31, 2001 and 2000 and the period from our commencement of operations
(on August 20, 1999) to December 31, 1999, the audited combined financial
statements of our predecessor, as of August 19, 1999, and for the period from
January 1, 1999 to August 19, 1999, and as of and for the years ended December
31, 1998, and 1997.
<Table>
<Caption>
(in millions, except per unit and per ton data) Partnership
---------------------------------------------------------------------
From
Commencement
of Operations (on
Year Ended Pro Forma August 20, 1999)
December 31, Year Ended to
------------------------------ December 31, December 31,
2001 2000 1999(1) 1999
------------ ------------ ------------ -----------------
STATEMENTS OF INCOME:
Sales and operating revenues
Coal sales $ 422.0 $ 347.2 $ 345.9 $ 128.8
Transportation revenues(2) 18.1 13.5 19.1 4.9
Other sales and operating revenues 6.2 2.8 0.9 0.4
------------ ------------ ------------ ------------
Total revenues 446.3 363.5 365.9 134.1
------------ ------------ ------------ ------------
Expenses
Operating expenses 308.0 257.4 242.0 89.9
Transportation expenses(2) 18.1 13.5 19.1 4.9
Outside purchases 31.8 16.9 24.2 6.4
General and administrative 17.7 15.2 15.1 6.2
Depreciation, depletion and amortization 45.5 39.1 39.7 15.1
Interest expense 16.8 16.6 19.4 5.9
Unusual items(3) -- (9.5) -- --
------------ ------------ ------------ ------------
Total expenses 437.9 349.2 359.5 128.4
------------ ------------ ------------ ------------
Income from operations 8.4 14.3 6.4 5.7
Other income (expense) 0.8 1.3 1.2 0.6
------------ ------------ ------------ ------------
Income before income taxes and
cumulative effect of accounting change 9.2 15.6 7.6 6.3
Income tax expense -- -- -- --
------------ ------------ ------------ ------------
Income before cumulative effect of
accounting change 9.2 15.6 7.6 6.3
Cumulative effect of accounting change(4) 7.9 -- -- --
------------ ------------ ------------ ------------
Net income $ 17.1 $ 15.6 $ 7.6 $ 6.3
============ ============ ============ ============
Basic net income per limited partner unit $ 1.09 $ 0.99 $ 0.48 $ 0.40
============ ============ ============ ============
Basic net income per limited partner unit
before accounting change $ 0.58 $ 0.99 $ 0.48 $ 0.40
============ ============ ============ ============
Diluted net income per limited partner unit $ 1.07 $ 0.98 $ 0.48 $ 0.40
============ ============ ============ ============
Diluted net income per limited partner unit
before accounting change $ 0.57 $ 0.98 $ 0.48 $ 0.40
============ ============ ============ ============
Weighted average number of units
outstanding-basic 15,405,311 15,405,311 15,405,311 15,405,311
============ ============ ============ ============
Weighted average number of units
outstanding-diluted 15,684,550 15,551,062 15,405,311 15,405,311
============ ============ ============ ============
BALANCE SHEET DATA:
Working capital (deficit) $ (2.3) $ 38.6 $ -- $ 61.2
Total assets 290.9 309.2 -- 314.8
Long-term debt 211.3 226.3 -- 230.0
Total liabilities 337.8 341.0 -- 330.7
Net Parent investment -- -- -- --
Partners' capital (deficit) (46.9) (31.8) -- (15.9)
OTHER OPERATING DATA:
Tons sold 17.0 15.0 15.0 5.6
Tons produced 15.7 13.7 14.1 5.3
Revenues per ton sold(5) $ 25.19 $ 23.33 $ 23.12 $ 23.07
Cost per ton sold(6) $ 21.03 $ 19.30 $ 18.75 $ 18.30
OTHER FINANCIAL DATA:
EBITDA(7) $ 79.4 $ 71.3 $ 66.7 $ 27.3
Net cash provided by (used in)
operating activities 63.7 71.4 -- (13.9)
Net cash used in investing activities (26.2) (41.0) -- (43.9)
Net cash provided by (used in)
financing activities (35.2) (31.4) -- 65.8
Maintenance capital expenditures(8) 24.4 21.2 6.0 6.0
<Caption>
(in millions, except per unit and per ton data) Predecessor
------------------------------------------
For the
period from
January 1, 1999 Year Ended
to December 31,
August 19, ----------------------
1999 1998 1997
--------------- ------- -------
STATEMENTS OF INCOME:
Sales and operating revenues
Coal sales $ 217.0 $ 357.4 $ 305.3
Transportation revenues(2) 14.2 41.4 42.7
Other sales and operating revenues 0.6 4.5 8.5
------- ------- -------
Total revenues 231.8 403.3 356.5
------- ------- -------
Expenses
Operating expenses 152.1 237.6 197.4
Transportation expenses(2) 14.2 41.4 42.7
Outside purchases 17.7 51.2 49.8
General and administrative 8.9 15.3 15.4
Depreciation, depletion and amortization 24.6 39.8 33.7
Interest expense 0.1 0.2 --
Unusual items(3) -- 5.2 --
------- ------- -------
Total expenses 217.6 390.7 339.0
------- ------- -------
Income from operations 14.2 12.6 17.5
Other income (expense) 0.5 (0.1) 0.5
------- ------- -------
Income before income taxes and
cumulative effect of accounting change 14.7 12.5 18.0
Income tax expense 4.5 3.8 4.3
------- ------- -------
Income before cumulative effect of
accounting change 10.2 8.7 13.7
Cumulative effect of accounting change(4) -- -- --
------- ------- -------
Net income $ 10.2 $ 8.7 $ 13.7
======= ======= =======
Basic net income per limited partner unit
Basic net income per limited partner unit
before accounting change
Diluted net income per limited partner unit
Diluted net income per limited partner unit
before accounting change
Weighted average number of units
outstanding-basic
Weighted average number of units
outstanding-diluted
BALANCE SHEET DATA:
Working capital (deficit) $ 11.2 $ 7.1 $ 10.3
Total assets 262.8 261.1 245.8
Long-term debt 1.8 1.7 1.9
Total liabilities 110.2 108.3 87.0
Net Parent investment 151.6 152.8 158.8
Partners' capital (deficit) -- -- --
OTHER OPERATING DATA:
Tons sold 9.4 15.1 12.4
Tons produced 8.8 13.4 10.9
Revenues per ton sold(5) $ 23.15 $ 23.97 $ 25.31
Cost per ton sold(6) $ 19.01 $ 20.14 $ 21.18
OTHER FINANCIAL DATA:
EBITDA(7) $ 39.4 $ 52.5 $ 51.7
Net cash provided by (used in)
operating activities 32.9 50.5 53.2
Net cash used in investing activities (21.5) (35.6) (22.4)
Net cash provided by (used in)
financing activities (11.4) (14.9) (30.8)
Maintenance capital expenditures(8) 15.5 17.2 15.2
</Table>
24
(1) The unaudited selected pro forma financial and operating data for the year
ended December 31, 1999, is based on the historical financial statements of
the partnership from our commencement of operations on August 20, 1999,
through December 31, 1999, and our predecessor for the period from January
1, 1999, through August 19, 1999. The pro forma results of operations
reflect certain pro forma adjustments to the historical results of
operations as if we had been formed on January 1, 1999. The pro forma
adjustments include (a) pro forma interest on debt assumed by us and (b)
the elimination of income tax expense as income taxes will be borne by the
partners and not by us. The pro forma adjustments do not include
approximately $1.0 million of general and administrative expenses that we
believe would have been incurred as a result of its being a public entity.
(2) During the fourth quarter 2000, we adopted the Financial Accounting
Standards Board Emerging Issues Task Force Issue No. 00-10 "Accounting for
Shipping and Handling Fees and Costs" (EITF No. 00-10). We record the cost
of transporting coal to customers through third party carriers and our
corresponding direct reimbursement of these costs through customer
billings. This activity is separately presented as transportation revenue
and expense rather than offsetting these amounts in the consolidated and
combined statements of income. There was no cumulative effect of the
accounting change on net income and prior periods presented have been
reclassified to comply with EITF No. 00-10.
(3) Represents income from the final resolution of an arbitrated dispute with
respect to the termination of a long-term contract, net of impairment
charges relating to certain transloading facility assets, partially offset
by expenses associated with other litigation matters in 2000 and the net
loss incurred during the temporary closing of one of our mining complexes
in the second half of 1998.
(4) Represents the cumulative effect of the change in the method of estimating
coal workers' pneumoconiosis ("black lung") benefits liability effective
January 1, 2001. See "Item 7. Management Discussion and Analysis of
Financial Condition and Results of Operations. - Critical Accounting
Policies. and Item 8. Financial Statements and Supplementary Data. - Note
3. Accounting Change."
(5) Revenues per ton sold is based on the total of coal sales and other sales
and operating revenues divided by tons sold.
(6) Cost per ton sold is based on the total of operating expenses, outside
purchases and general and administrative expenses divided by tons sold.
(7) EBITDA is defined as income before net interest expense, income taxes and
depreciation, depletion and amortization. EBITDA should not be considered
as an alternative to net income, income before income taxes, cash flows
from operating activities or any other measure of financial performance
presented in accordance with generally accepted accounting principles.
EBITDA has not been adjusted for unusual items nor the cumulative effect of
an accounting change. EBITDA is not intended to represent cash flow and
does not represent the measure of cash available for distribution, but
provides additional information for evaluating our ability to make the
MQDs. Our method of computing EBITDA also may not be the same method used
to compute similar measures reported by other companies, or EBITDA may be
computed differently by us in different contexts (i.e., public reporting
versus computation under financing arrangements).
(8) Our maintenance capital expenditures, as defined under the terms of our
partnership agreement, are defined as those capital expenditures required
to maintain, over the long term, the operating capacity of our capital
assets. Maintenance capital expenditures for our predecessor reflect our
historical designation of maintenance capital expenditures.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
GENERAL
The following discussion of our financial condition and results of
operations and our predecessor should be read in conjunction with the historical
financial statements and notes thereto included elsewhere in this Annual Report
on Form 10-K. For more detailed information regarding the basis of presentation
for the following
25
financial information, see "Item 8. Financial Statements and Supplementary Data.
- - Note 1. Organization and Presentation and Note 2. Summary of Significant
Accounting Policies."
CRITICAL ACCOUNTING POLICIES
From our Summary of Significant Accounting Policies, we have identified the
following accounting policies that require the exercise of our most difficult,
complex and subjective levels of judgment. Our judgments in the following areas
are principally based on estimates and assumptions that affect the reported
amounts and disclosures in the consolidated and combined financial statements.
See "Item 8. Financial Statements and Supplementary Data." Actual results that
are influenced by future events could materially differ from the current
estimates.
LONG-LIVED ASSETS
We review the carrying value of long-lived assets whenever events or
changes in circumstances indicate that the carrying amount may not be
recoverable based upon estimated undiscounted future cash flows. The amount of
an impairment is measured by the difference between the carrying value and the
fair value of the asset, which is based on cash flows from that asset,
discounted at a rate commensurate with the risk involved.
RECLAMATION AND MINE CLOSING COSTS
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. We record the liability
for the estimated cost of future mine reclamation and closing procedures on a
present value basis when incurred and the associated cost is capitalized by
increasing the carrying amount of the related long-lived asset. Those costs
relate to sealing portals at underground mines and to reclaiming the final pit
and support acreage at surface mines. Other costs common to both types of mining
are related to removing or covering refuse piles and settling ponds, and
dismantling preparation plants, other facilities and roadway infrastructure. We
had accrued liabilities of $16.5 million and $16.0 million for these costs at
December 31, 2001 and 2000, respectively.
WORKERS' COMPENSATION AND PNEUMOCONIOSIS ("BLACK LUNG") BENEFITS
We provide income replacement and medical treatment for work related
traumatic injury claims as required by the applicable state law. We provide for
these claims through self-insurance programs. The liability for traumatic injury
claims is the estimated present value of current workers' compensation benefits
based on an annual actuarial study performed by an independent actuary. The
actuarial calculations are based on a blend of actuarial projection methods and
numerous assumptions including development patterns, mortality, medical costs
and interest rates. We had accrued liabilities of $22.1 million and $20.6
million for these costs at December 31, 2001 and 2000, respectively.
Coal mining companies are subject to the Federal Coal Mine Health and
Safety Act of 1969, as amended, and various state statues for the payment of
medical and disability benefits to eligible recipients related to coal worker's
pneumoconiosis ("black lung"). We provide for these claims through a
self-insurance programs. Our estimated black lung liability is based on an
annual actuarial study performed by an independent actuary. The actuarial
calculations are based on numerous assumptions including disability incidence,
medical costs, mortality, death benefits, dependents and interest rates. We had
accrued liabilities of $15.1 million and $22.1 million for these benefits at
December 31, 2001 and 2000, respectively.
Effective January 1, 2001, we changed our method of estimating black lung
benefits to the service cost method described in Statement of Financial
Accounting Standards ("SFAS") No. 106, "Employer's
26
Accounting for Postretirement Benefits Other Than Pensions," which method is
permitted under SFAS No. 112 "Employers' Accounting for Postemployment
Benefits." Recently, governmental regulations regarding the federal black lung
benefits claims approval process were issued. These new regulations specifically
define the black lung disability as progressive and also expand the definition
of pneumoconiosis to mandate consideration of diseases that are caused by
factors other than exposure to coal dust. We believe the change to the SFAS No.
106 measurement methodology better matches black lung costs over the service
lives of the miners who ultimately receive the black lung benefits and is more
reflective of the recently enacted regulations, which place significant emphasis
on coal miners' future years of employment in the coal industry. We previously
accrued the black lung benefits liability at the present value of the
actuarially determined current and future estimated black lung benefit payments
utilizing the methodology prescribed under SFAS No. 5 "Accounting for
Contingencies," which was also permitted by SFAS No. 112.
BUSINESS
We are a diversified producer and marketer of coal to major U.S. utilities
and industrial users. In 2001, our total production was 15.7 million tons and
our total sales were 17.0 million tons. The coal we produced in 2001 was
approximately 28.7% low-sulfur coal, 17.2% medium-sulfur coal and 54.1%
high-sulfur coal.
At December 31, 2001, we had approximately 400.6 million tons of proven and
probable coal reserves in Illinois, Indiana, Kentucky, Maryland and West
Virginia. We believe we control adequate reserves to implement our currently
contemplated mining plans. In addition, there are substantial unleased reserves
on adjacent properties that we intend to acquire or lease as our mining
operations approach these areas.
In 2001, approximately 83% of our sales tonnage was consumed by electric
utilities with the balance consumed by cogeneration plants and industrial users.
Our largest customers in 2001 were Seminole, TVA, and VEPCO. We have had
relationships with these customers for at least 15 years. In 2001, approximately
78% of our sales tonnage, including approximately 75% of our medium- and
high-sulfur coal sales tonnage, was sold under long-term contracts. The balance
of our sales were made on the spot market. Our long-term contracts contribute to
our stability and profitability by providing greater predictability of sales
volumes and sales prices. In 2001, approximately 91% of our medium- and
high-sulfur coal was sold to utility plants with installed pollution control
devices, also known as scrubbers, to remove sulfur dioxide.
We recently entered into long-term agreements with SSO to host and operate
its coal synfuel production facility, supply coal feedstock, assist with coal
synfuel marketing, and provide other services through December 31, 2007. These
agreements provide us with coal sales or service fees from SSO based on the
synfuel facility throughput tonnage, which amount is dependent on the ability of
the facility's owners to use certain qualifying tax credits applicable to the
facility. The term of each agreement is subject to early cancellation provisions
customary for transactions of these types, including the unavailability of coal
synfuel tax credits, the termination of associated coal synfuel sales contracts,
and the occurrence of certain force majeure events. Therefore, the continuation
of the operating revenues associated with the coal synfuel production facility
cannot be assured. However, we have put in place "back up" coal supply
agreements with each coal synfuel customer, which automatically provide for sale
of our coal to them in the event they do not receive coal synfuel.
One of our business strategies is to continue to make productivity
improvements to remain a low cost producer in each region in which we operate.
Our principal expenses related to the production of coal are labor and benefits,
equipment, materials and supplies, maintenance, royalties and excise taxes.
Unlike most of our competitors in the eastern U.S., we employ a totally
union-free workforce. Many of the benefits of the union-free workforce are not
necessarily reflected in direct costs, but we believe are related to higher
productivity. In addition, while we do not pay our customers' transportation
costs, they may be substantial and often the determining factor in a coal
consumer's contracting decision. Our mining operations are located near
27
many of the major eastern utility generating plants and on major coal hauling
railroads in the eastern U.S. We believe this gives us a transportation cost
advantage compared to many of our competitors.
RESULTS OF OPERATIONS
2001 COMPARED WITH 2000
Coal sales. Coal sales for 2001 increased 21.5% to $422.0 million from
$347.2 million for 2000. The increase of $74.8 million was primarily
attributable to higher sales prices and volume reflecting increased utility
demand, increased activity in the domestic coal brokerage market due to
favorable spot price levels and additional revenues from the new Gibson County
Coal mining complex, which opened in late 2000. Tons sold increased 13.3% to
17.0 million for 2001 from 15.0 million in 2000. Tons produced increased 14.9%
to 15.7 million for 2001 from 13.7 million for 2000.
Transportation revenues. Transportation revenues for 2001 increased 33.9%
to $18.1 million from $13.5 million for 2000. The increase of $4.6 million was
primarily attributable to the increase in tons sold. We reflect reimbursement of
the cost of transporting coal to customers through third party carriers as
transportation revenues and the corresponding expense as transportation expense
in the consolidated statements of income. No margin is realized on
transportation revenues.
Other sales and operating revenues. Other sales and operating revenues
increased to $6.2 million for 2001 from $2.8 million for 2000. The increase of
$3.4 million is attributable to additional service fees associated with
increased volumes at a third party coal synfuel production facility at our
Hopkins County Coal mining complex. See the discussion immediately above under
"Business."
Operating expenses. Operating expenses increased 19.7% to $308.0 million
for 2001 from $257.4 million for 2000. The increase of $50.6 million resulted
from increased sales volumes as well as additional operating expenses associated
with a full year of operation at Gibson County Coal, which opened in late 2000,
and difficult mining conditions encountered at several operations. Those
difficult mining conditions placed an undue burden on equipment scheduled for
replacement, resulting in unanticipated equipment failures and higher
maintenance costs.
Transportation expenses. See "Transportation Revenues" above concerning the
increase in transportation expenses.
Outside purchases. Outside purchases increased to $31.8 million for 2001
from $16.9 million for 2000. The increase of $14.9 million resulted from
increased activity in the domestic coal brokerage market due to improved profit
margins on spot coal sales, which resulted in increased volumes at higher
purchase prices. The higher brokerage volumes are largely attributable to
short-term opportunities in the domestic coal brokerage markets, which are not
expected to be material in the future.
General and administrative. General and administrative expenses increased
16.8% to $17.7 million for 2001 from $15.2 million for 2000. The increase of
$2.5 million was primarily attributable to higher accruals related to the
Short-Term Incentive Plan, combined with additional restricted units granted
under the Long-Term Incentive Plan. The Long-Term Incentive Plan accrual is
impacted by the increased market value of the common units.
Depreciation, depletion and amortization. Depreciation, depletion and
amortization expenses increased 16.1% to $45.5 million for 2001 from $39.1
million for 2000. The increase of $6.4 million primarily resulted from
additional depreciation expense associated with a full year of operation at
Gibson County Coal, which opened in late 2000.
28
Interest expense. Interest expense was comparable for 2001 and 2000 at
$16.8 million and $16.6 million, respectively.
Cumulative effect of accounting change. Effective January 1, 2001, we
changed our method of estimating our black lung benefits liability. See the
discussion immediately above under "Workers' Compensation and Pneumoconiosis
("Black Lung") Benefits."
EBITDA (income before net interest expense, income taxes, depreciation,
depletion and amortization) increased 11.3% to $79.4 million for 2001 compared
with $71.3 million for 2000. The $8.1 million increase was primarily
attributable to higher sales prices and volumes reflecting increased utility
demand during 2001 and a full year of operations at Gibson County Coal, which
opened in late 2000, and the increased revenue from the third party coal synfuel
facility at Hopkins County Coal.
EBITDA should not be considered as an alternative to net income, income
before income taxes, cash flows from operating activities or any other measure
of financial performance presented in accordance with generally accepted
accounting principles. EBITDA has not been adjusted for unusual items nor the
cumulative effect of an accounting change. EBITDA is not intended to represent
cash flow and does not represent the measure of cash available for distribution,
but provides additional information for evaluating our ability to pay MQDs. Our
method of computing EBITDA also may not be the same method used to compute
similar measures reported by other companies, or EBITDA may be computed
differently by us in different contexts (i.e., public reporting versus
computation under financing agreements).
2000 COMPARED WITH 1999
In comparing 2000 to 1999, the partnership and predecessor periods for 1999
have been combined. Since we maintained the historical cost basis of our
predecessor's net assets, we believe that the combined partnership and
predecessor results for 2000 are comparable with 1999. The interest expense
associated with the debt incurred concurrent with the closing of our initial
public offering is applicable only to the partnership period. See "Item 8.
Financial Statements and Supplementary Data. - Note 1. Organization and
Presentation."
Coal sales. Coal sales for 2000 increased 0.4% to $347.2 million from
$345.9 million for 1999. The increase of $1.3 million was primarily attributable
to higher sales volumes in the Illinois Basin operations and at the restructured
Pontiki operation, which were directly offset by planned reduced participation
in coal export brokerage markets. Tons produced decreased 2.9% to 13.7 million
for 2000 from 14.1 million for 1999.
Transportation revenues. Transportation revenues for 2000 decreased 29.4%
to $13.5 million from $19.1 million for 1999. The decrease of $5.6 million was
primarily attributable to planned reduced participation in coal export brokerage
markets, which generally have higher transportation costs. No margin is realized
on transportation revenues.
Other sales and operating revenues. Other sales and operating revenues
increased to $2.8 million for 2000 from $0.9 million for 1999. The increase of
$1.9 million resulted from the introduction of a third party coal synfuel
production facility at the Hopkins County Coal mining complex.
Operating expenses. Operating expenses increased 6.3% to $257.4 million for
2000 from $242.0 million for 1999. The increase of $15.4 million was a result
of: (a) start-up expenses related to the opening of the newly developed Gibson
County Coal mining complex during the fourth quarter of 2000, (b) higher sales
volumes in the Illinois Basin operations, (c) increased production volumes at
the restructured Pontiki operation, and (d) prolonged adverse mining conditions
related to a sandstone intrusion at the Mettiki longwall mine.
29
Transportation expenses. See "Transportation Revenues" above concerning the
decrease in transportation expenses.
Outside purchases. Outside purchases declined 30.2% to $16.9 million for
2000 from $24.2 million for 1999. The decrease of $7.3 million was the result of
lower coal export brokerage volumes. See "Coal sales" above concerning the
decrease in coal export brokerage volumes.
General and administrative. General and administrative expenses were
comparable for 2000 and 1999 at $15.2 million.
Depreciation, depletion and amortization. Depreciation, depletion and
amortization expenses were comparable for 2000 and 1999 at $39.1 million and
$39.7 million, respectively.
Interest expense. Interest expense was $16.6 million for 2000 compared to
$6.0 million for 1999. The increase reflected the full year impact of interest
on the $180 million principal amount of 8.31% senior notes and $50 million of
borrowings on the term loan facility in connection with our initial public
offering and concurrent transactions occurring on August 20, 1999. See "Item 8.
Financial Statements and Supplementary Data. - Note 1. Organization and
Presentation."
Unusual items. We were involved in litigation with Seminole with respect to
Seminole's termination of a long-term contract for the transloading of coal from
rail to barge through our Mt. Vernon terminal in Indiana. The final resolution
between the parties, reached in conjunction with an arbitrator's decision
rendered during the third quarter of 2000, included both cash payments and
amendments to an existing coal supply contract. We recorded income of $12.2
million, which is net of litigation expenses of approximately $0.9 million and
an impairment charge of $2.4 million relating to the facility's assets.
Additionally, we recorded an expense of $2.7 million consisting of $0.7 million
relating to a settlement and $2.0 million attributable to contingencies
associated with third party claims arising out of our mining operations. The net
effect of these unusual items was $9.5 million. See "Item 8. Financial
Statements. - Note 4. Unusual Items."
Income before income taxes. Income before income taxes was $15.6 million
for 2000 compared to $21.0 million for 1999. The decrease of $5.4 million was
primarily attributable to: (a) start-up expenses related to the opening of the
new Gibson County Coal mining complex during the fourth quarter of 2000, (b)
increased operating expenses as a result of prolonged adverse mining conditions
encountered at the Mettiki longwall mining complex and (c) additional interest
expense associated with the debt incurred concurrent with the closing of our
initial public offering, partially offset by unusual items recorded during 2000.
See "Unusual items" described above.
Income tax expense. Our earnings or loss for federal income tax purposes
will be included in the tax returns of the individual partners. Accordingly, no
recognition is given to income taxes in our accompanying financial statements.
Our predecessor was included in the consolidated federal income tax return of
Alliance Resource Holdings. Federal and state income taxes were calculated as if
our predecessor had filed its return on a separate company basis utilizing an
effective income tax rate of 31%.
EBITDA (income before net interest expense, income taxes, depreciation,
depletion and amortization) increased 6.9% to $71.3 million for 2000 compared
with $66.7 million for 1999. The $4.6 million increase was primarily
attributable to increased production and sales volumes at the restructured
Pontiki mine and the unusual items recorded during 2000 (see "Unusual items"
described above), partially offset by increased operating expenses as a result
of adverse mining conditions at the Mettiki longwall mining complex.
EBITDA should not be considered as an alternative to net income, income
before income taxes, cash flows from operating activities or any other measure
of financial performance presented in accordance with
30
generally accepted accounting principles. EBITDA has not been adjusted for
unusual items. EBITDA is not intended to represent cash flow and does not
represent the measure of cash available for distribution, but provides
additional information for evaluating our ability to pay MQDs. Our method of
computing EBITDA also may not be the same method used to compute similar
measures reported by other companies, or EBITDA may be computed differently by
us in different contexts (i.e., public reporting versus computation under
financing agreements).
LIQUIDITY AND CAPITAL RESOURCES
LIQUIDITY
We generally satisfy our working capital requirements and fund our capital
expenditures and debt service obligations from cash generated from operations
and borrowings under our revolving credit facility. We believe that the cash
generated from operations and our borrowing capacity will be sufficient to meet
our working capital requirements, anticipated capital expenditures (other than
major capital improvements or acquisitions), scheduled debt payments and minimum
distribution payments. Nevertheless, our ability to satisfy our obligations and
planned expenditures will depend upon our future operating performance, which
will be affected by prevailing economic conditions in the coal industry, some of
which are beyond our control.
CASH FLOWS
Cash provided by operating activities was $63.7 million in 2001 compared to
$71.4 million in 2000. The decrease in cash provided by operating activities was
principally attributable to a decrease in the benefit of working capital
reductions from 2000 to 2001.
Net cash used in investing activities was $26.2 million in 2001 compared to
net cash used in investing activities of $41.0 million in 2000. The decreased
use of cash is principally attributable to the liquidation of marketable
securities, which was partially offset by increased capital expenditures related
to the extension of our Pattiki mine into adjacent coal reserves and the
addition of a new mining unit at our Dotiki mine.
Net cash used in financing activities was $35.2 million for 2001 compared
to net cash used in financing activities of $31.4 million for 2000. Cash used in
financing activities during 2001 and 2000 was a direct result of four MQDs of
$0.50 per unit on common and subordinated units outstanding. Additionally,
during 2001 we made a scheduled debt payment of $3.75 million.
We have various commitments primarily related to long-term debt, operating
lease commitments related to buildings and equipment, obligations for estimated
reclamation and mining closing costs and capital project commitments. We expect
to fund these commitments with cash generated from operations, proceeds from
marketable securities and borrowings under our revolving credit facility. The
following table provides details regarding our contractual cash obligations as
of December 31, 2001:
31
<Table>
<Caption>
Less
Contractual than 1 1-3 4-5 After 5
Obligations Total year years years years
----------- -------- -------- -------- -------- --------
Long-Term Debt $226,250 $ 15,000 $ 31,250 $ 36,000 $144,000
Operating Leases 26,898 3,297 6,336 6,174 11,091
Other Long-Term Obligations
(excluding discount effect of $12.1
million for reclamation liability) 28,649 1,078 3,591 6,056 17,924
Capital projects 15,339 15,339 -- -- --
-------- -------- -------- -------- --------
$297,136 $ 34,714 $ 41,177 $ 48,230 $173,015
-------- -------- -------- -------- --------
</Table>
CAPITAL EXPENDITURES
Capital expenditures increased to $53.7 million in 2001 compared to $46.2
million in 2000. See "Cash Flow" above concerning the increase in capitalized
expenditures. During the year 2000, we approved an extension of our existing
Pattiki mine into adjacent coal reserves. The extension involves capital
expenditures of approximately $30.0 million during the 2000-2003 period and is
expected to allow the Pattiki mine to continue its existing production level for
the next 15 years. Additionally during August 2001, Dotiki began construction of
a new mine shaft and ancillary facilities, which is expected to be operational
in late 2002 and will provide a new access for miners and supplies. We have
contractual commitments of $15.3 million related to these capital projects.
We currently expect that our average annual maintenance capital
expenditures will be approximately $29.0 million. We have raised this average
from 2001 primarily because of our additional operations at Gibson County Coal.
We currently expect to fund our anticipated capital expenditures with cash
generated from operations and borrowings under our revolving credit facility
described below.
NOTES OFFERING AND CREDIT FACILITY
Concurrently with the closing of our initial public offering, the special
general partner issued and the intermediate partnership assumed the obligations
with respect to $180 million principal amount of 8.31% senior notes due August
20, 2014 (Senior Notes). The special general partner also entered into, and the
intermediate partnership assumed the obligations under, a $100 million credit
facility (Credit Facility). The Credit Facility consists of three tranches,
including a $50 million term loan facility, a $25 million working capital
facility and a $25 million revolving credit facility. We had borrowings
outstanding of $46.3 million and $50 million under the term loan facility and no
borrowings outstanding under either the working capital facility or the
revolving credit facility at December 31, 2001, and 2000, respectively. The
weighted average interest rates on the term loan facility at December 31, 2001,
and 2000, were 3.40% and 7.77%, respectively. The Credit Facility expires August
2004. The Senior Notes and Credit Facility are guaranteed by all of the
subsidiaries of the intermediate partnership. The Senior Notes and Credit
Facility contain various restrictive and affirmative covenants, including the
amount of distributions by the intermediate partnership and the incurrence of
other debt. We were in compliance with the covenants of both the credit facility
and senior notes at December 31, 2001 and 2000.
We entered into agreements with three banks to provide letters of credit in
an aggregate amount of $25.0 million to maintain surety bonds to secure its
obligations for reclamation liabilities and workers' compensation benefits. At
December 31, 2001, we had $15.0 million in letters of credit outstanding. The
special general partner guarantees the letters of credit.
RELATED PARTY TRANSACTIONS
We purchase coal from affiliates, lease a coal preparation plant and
handling facilities at our Gibson County Coal mining complex, lease coal
reserves from our special general partner and its affiliates, provide
32
general and administrative services to an affiliate, and receive reclamation
services at our Dotiki mine from an affiliate. Our special general partner
guarantees our letters of credit and we have a put/call option to purchase a
mine operation from Alliance Resource Holdings. See "Item 8. Financial
Statements and Supplementary Data. - Note 14. Related Party Transactions" and
"Item 13. Certain Relationships and Related Party Transactions."
ACCRUALS OF OTHER LIABILITIES
We had accruals for other liabilities, including current obligations,
totaling $61.0 million and $67.1 million at December 31, 2001 and 2000. These
accruals were chiefly comprised of workers' compensation benefits, black lung
benefits, and costs associated with reclamation and mine closing. These
obligations are self-insured. The accruals of these items were based on
estimates of future expenditures based on current legislation, related
regulations and other developments. Thus, from time to time, our results of
operations may be significantly effected by changes to these liabilities. See
"Item 8. Financial Statements and Supplementary Data. - Note 12. Reclamation and
Mine Closing Costs and Note 13. Pneumoconiosis ("Black Lung") Benefits."
INFLATION
Inflation in the U.S. has been relatively low in recent years and did not
have a material impact on our results of operations for the years ended December
31, 2001, 2000 or 1999.
RECENT ACCOUNTING PRONOUNCEMENTS
Effective January 1, 2001, we adopted Statement of Financial Accounting
Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging
Activities," which establishes accounting and reporting standards for derivative
instruments and for hedging activities. It requires that all derivatives be
recognized as either assets or liabilities in the statement of financial
position and be measured at fair value. We have no identified derivative
instruments or hedging activities. Accordingly, this standard had no material
effect on our consolidated financial statements upon adoption.
In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 141, "Business Combinations" and No. 142 "Goodwill and Intangible Assets."
SFAS No. 141 eliminates the pooling-of-interests method of accounting for
business combinations and requires that all business combinations be accounted
for under the purchase method. In addition, it further clarifies the criteria
for recognition of intangible assets separately from goodwill. This statement is
effective for business combinations initiated after June 30, 2001. SFAS No. 142
discontinues the practice of amortizing goodwill and indefinite lived intangible
assets and initiates an annual review for impairment. This statement is
effective January 1, 2002, for all goodwill and other intangible assets included
in an entity's statement of financial position at that date, regardless of when
those assets were initially recognized. SFAS 141 and 142 are not expected to
have a material impact on our financial statements.
In August 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations," which requires the fair value of a liability for an
asset retirement obligation to be recognized in the period in which it is
incurred. When the liability is initially recorded, a cost is capitalized by
increasing the carrying amount of the related long-lived asset. Over time, the
liability is accreted to its present value each period, and the capitalized cost
is depreciated over the useful life of the related asset. To settle the
liability, the obligation for its recorded amount is paid or a gain or loss upon
settlement is incurred. Since we historically adhered to accounting principles
similar to SFAS No. 143 in accounting for its reclamation and mine closing
costs, we do not believe that adoption of SFAS No. 143, effective January 1,
2003, will have a material impact on our financial statements.
33
In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," which is effective for fiscal
years beginning after December 15, 2001 and is not expected to have a material
impact on our financial statements upon adoption on January 1, 2002.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We have significant long-term coal supply agreements. Virtually all of the
long-term coal supply agreements are subject to price adjustment provisions,
which permit an increase or decrease periodically in the contract price to
principally reflect changes in specified price indices or items such as taxes,
royalties or actual production costs. For additional discussion of coal supply
agreements, see "Item 1. Business. - Coal Marketing and Sales" and "Item 8.
Financial Statements and Supplementary Data. - Note 16. Concentration of Credit
Risk and Major Customers."
Almost all of our predecessor's transactions were, and all of our
transactions are, denominated in U.S. dollars, and as a result, we do not have
material exposure to currency exchange-rate risks.
We do not engage in any interest rate, foreign currency exchange rate or
commodity price-hedging transactions.
The intermediate partnership assumed obligations under the Credit Facility.
Borrowings under the Credit Facility are at variable rates and as a result we
have interest rate exposure.
The table below provides information about our market sensitive financial
instruments and constitutes a "forward-looking statement." The fair values of
long-term debt are estimated using discounted cash flow analyses, based upon our
current incremental borrowing rates for similar types of borrowing arrangements
as of December 31, 2001, and 2000. The carrying amounts and fair values of
financial instruments are as follows (in thousands):
<Table>
<Caption>
FAIR VALUE
EXPECTED MATURITY DATES DECEMBER 31,
AS OF DECEMBER 31, 2001 2002 2003 2004 2005 2006 THEREAFTER TOTAL 2001
- ----------------------- -------- -------- -------- -------- -------- ---------- --------- -----------
Senior Notes-fixed rate $ -- $ -- $ -- $ 18,000 $ 18,000 $ 144,000 $ 180,000 $ 180,000
Weighted Average interest rate 8.31% 8.31% 8.31%
Term Loan-floating rate $ 15,000 $ 16,250 $ 15,000 $ -- $ -- $ 46,250 $ 46,250
Weighted Average interest rate 3.40% 3.40% 3.40%
</Table>
<Table>
<Caption>
FAIR VALUE
EXPECTED MATURITY DATES DECEMBER 31,
AS OF DECEMBER 31, 2000 2001 2002 2003 2004 2005 THEREAFTER TOTAL 2000
- ----------------------- -------- -------- -------- -------- -------- ---------- --------- -----------
Senior Notes-fixed rate $ -- $ -- $ -- $ -- $ 18,000 $ 162,000 $ 180,000 $ 180,000
Weighted Average interest rate 8.31% 8.31%
Term Loan-floating rate $ 3,750 $ 15,000 $ 16,250 $ 15,000 $ -- $ -- $ 50,000 $ 50,000
Weighted Average interest rate 7.77% 7.77% 7.77% 7.77%
</Table>
34
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEPENDENT AUDITORS' REPORT
To the Board of Directors of the Managing
General Partner and the Partners of
Alliance Resource Partners, L.P.:
We have audited the accompanying consolidated balance sheets of Alliance
Resource Partners, L.P. and subsidiaries (the "Partnership") as of December 31,
2001 and 2000, the related consolidated and combined statements of income and
cash flows for the years ended December 31, 2001 and 2000, the period from the
Partnership's commencement of operations (on August 20, 1999) to December 31,
1999, and the Predecessor period from January 1, 1999 to August 19, 1999, and
the statement of Partners' capital (deficit) for the years ended December 31,
2001 and 2000, and the period from the Partnership's commencement of operations
(on August 20, 1999) to December 31, 1999. Our audits also included the
financial statement schedule listed in the Index at Item 14. These financial
statements and financial statement schedule are the responsibility of the
Partnership's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated and combined financial statements present
fairly, in all material respects, the financial position of the Partnership at
December 31, 2001 and 2000 and the results of their operations and their cash
flows for the years ended December 31, 2001 and 2000, the period from the
Partnership's commencement of operations (on August 20, 1999) to December 31,
1999, and the Predecessor period from January 1, 1999 to August 19, 1999 in
conformity with accounting principles generally accepted in the United States of
America. Also, in our opinion, such financial statement schedule, when
considered in relation to the basic consolidated and combined financial
statements taken as a whole, presents fairly in all material respects the
information set forth therein.
As discussed in Note 3 to the consolidated and combined financial statements,
the Partnership changed its method of estimating coal workers pneumoconiosis
benefits liability effective January 1, 2001.
/s/ Deloitte & Touche LLP
Tulsa, Oklahoma
January 28, 2002, except for Note 15 as
to which the date is March 14, 2002
35
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2001 AND 2000
(IN THOUSANDS, EXCEPT UNIT DATA)
- --------------------------------------------------------------------------------
<Table>
<Caption>
DECEMBER 31,
--------------------------
ASSETS 2001 2000
--------- ---------
CURRENT ASSETS:
Cash and cash equivalents $ 9,176 $ 6,933
Trade receivables, less allowance of $763 and $0, respectively 31,124 35,898
Due from affiliates -- 208
Marketable securities (at cost, which approximates fair value) 10,085 37,398
Inventories 11,600 10,842
Advance royalties 5,353 2,865
Prepaid expenses and other assets 2,020 1,168
--------- ---------
Total current assets 69,358 95,312
PROPERTY, PLANT AND EQUIPMENT, AT COST 367,050 320,445
LESS ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION (169,960) (135,782)
--------- ---------
197,090 184,663
OTHER ASSETS:
Advance royalties 9,756 10,009
Coal supply agreements, net 12,031 16,324
Other long-term assets 2,670 2,858
--------- ---------
$ 290,905 $ 309,166
========= =========
LIABILITIES AND PARTNERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 25,237 $ 25,558
Due to affiliates 2,595 --
Accrued taxes other than income taxes 5,660 4,863
Accrued payroll and related expenses 8,284 6,975
Accrued interest 5,402 5,439
Workers' compensation and pneumoconiosis benefits 4,194 4,415
Other current liabilities 5,324 5,710
Current maturities, long-term debt 15,000 3,750
--------- ---------
Total current liabilities 71,696 56,710
LONG-TERM LIABILITIES:
Long-term debt, excluding current maturities 211,250 226,250
Pneumoconiosis benefits 14,615 21,651
Workers' compensation 18,409 16,748
Reclamation and mine closing 15,387 14,940
Due to affiliates 3,624 1,278
Other liabilities 2,865 3,376
--------- ---------
Total liabilities 337,846 340,953
COMMITMENTS AND CONTINGENCIES
PARTNERS' CAPITAL (DEFICIT):
Common Unitholders 8,982,780 units outstanding 141,448 149,642
Subordinated Unitholder 6,422,531 units outstanding 110,935 116,794
General Partners (298,510) (298,223)
Minimum pension liability (814) --
--------- ---------
Total Partners' capital (deficit) (46,941) (31,787)
--------- ---------
$ 290,905 $ 309,166
========= =========
</Table>
See notes to consolidated and combined financial statements.
36
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED AND COMBINED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 2001 AND 2000, AND THE PERIOD FROM THE
PARTNERSHIP'S COMMENCEMENT OF OPERATIONS (ON AUGUST 20, 1999) TO DECEMBER 31,
1999, AND THE PREDECESSOR PERIOD FROM JANUARY 1, 1999 TO AUGUST 19, 1999
(IN THOUSANDS, EXCEPT UNIT AND PER UNIT DATA)
- --------------------------------------------------------------------------------
<Table>
<Caption>
PARTNERSHIP PREDECESSOR
------------------------------------------------------ ---------------
FROM
COMMENCEMENT FOR THE
YEAR ENDED OF OPERATIONS PERIOD FROM
DECEMBER 31, (ON AUGUST 20, 1999) JANUARY 1, 1999
------------------------------- TO TO
2001 2000 DECEMBER 31, 1999 AUGUST 19, 1999
------------ ------------ -------------------- ---------------
SALES AND OPERATING REVENUES:
Coal sales $ 421,996 $ 347,209 $ 128,860 $ 217,033
Transportation revenues 18,090 13,511 4,907 14,223
Other sales and operating revenues 6,214 2,749 358 577
------------ ------------ ------------ ------------
Total revenues 446,300 363,469 134,125 231,833
------------ ------------ ------------ ------------
EXPENSES:
Operating expenses 307,977 257,365 89,945 152,066
Transportation expenses 18,090 13,511 4,907 14,223
Outside purchases 31,840 16,874 6,429 17,738
General and administrative 17,728 15,176 6,245 8,912
Depreciation, depletion and amortization 45,451 39,141 15,081 24,622
Interest expense (net of interest income and
interest capitalized of $1,928, $3,015 and
$999 for the Partnership's respective periods) 16,805 16,563 5,887 100
Unusual items -- (9,466) -- --
------------ ------------ ------------ ------------
Total operating expenses 437,891 349,164 128,494 217,661
------------ ------------ ------------ ------------
INCOME FROM OPERATIONS 8,409 14,305 5,631 14,172
OTHER INCOME 752 1,276 641 531
------------ ------------ ------------ ------------
INCOME BEFORE INCOME TAXES AND
CUMULATIVE EFFECT OF ACCOUNTING CHANGE 9,161 15,581 6,272 14,703
INCOME TAX EXPENSE -- -- -- 4,498
------------ ------------ ------------ ------------
INCOME BEFORE CUMULATIVE EFFECT OF
ACCOUNTING CHANGE 9,161 15,581 6,272 $ 10,205
CUMULATIVE EFFECT OF ACCOUNTING CHANGE 7,939 -- -- --
------------ ------------ ------------ ------------
NET INCOME $ 17,100 $ 15,581 $ 6,272 $ 10,205
============ ============ ============ ============
GENERAL PARTNERS' INTEREST IN NET INCOME $ 342 $ 312 $ 125
============ ============ ============
LIMITED PARTNERS' INTEREST IN NET INCOME $ 16,758 $ 15,269 $ 6,147
============ ============ ============
BASIC NET INCOME PER LIMITED PARTNER UNIT $ 1.09 $ 0.99 $ 0.40
============ ============ ============
BASIC NET INCOME PER LIMITED PARTNER UNIT
BEFORE ACCOUNTING CHANGE $ 0.58 $ 0.99 $ 0.40
============ ============ ============
DILUTED NET INCOME PER LIMITED
PARTNER UNIT $ 1.07 $ 0.98 $ 0.40
============ ============ ============
DILUTED NET INCOME PER LIMITED PARTNER
UNIT BEFORE ACCOUNTING CHANGE $ 0.57 $ 0.98 $ 0.40
============ ============ ============
PRO FORMA NET INCOME ASSUMING ACCOUNTING
CHANGE IS APPLIED RETROACTIVELY $ 17,100 $ 14,907 $ 6,395 $ 10,071
============ ============ ============ ============
WEIGHTED AVERAGE NUMBER
OF UNITS OUTSTANDING - BASIC 15,405,311 15,405,311 15,405,311
============ ============ ============
WEIGHTED AVERAGE NUMBER
OF UNITS OUTSTANDING - DILUTED 15,684,550 15,551,062 15,405,311
============ ============ ============
</Table>
See notes to consolidated and combined financial statements.
37
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2001 AND 2000, THE PERIOD FROM THE
PARTNERSHIP'S COMMENCEMENT OF OPERATIONS (ON AUGUST 20, 1999) TO DECEMBER 31,
1999, AND THE PREDECESSOR PERIOD FROM JANUARY 1, 1999 TO AUGUST 19, 1999
(IN THOUSANDS)
- --------------------------------------------------------------------------------
<Table>
<Caption>
PARTNERSHIP PREDECESSOR
----------------------------------------------- ---------------
FROM
COMMENCEMENT FOR THE
YEAR ENDED OF OPERATIONS PERIOD FROM
DECEMBER 31, (ON AUGUST 20, 1999) JANUARY 1, 1999
-------------------------- TO TO
2001 2000 DECEMBER 31, 1999 AUGUST 19, 1999
--------- --------- ------------------- ---------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 17,100 $ 15,581 $ 6,272 $ 10,205
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 45,451 39,141 15,081 24,622
Cumulative effect of accounting change (7,939) -- -- --
Impairment of transloading facility -- 2,439 -- --
Deferred income taxes -- -- -- 639
Reclamation and mine closings 943 1,074 348 457
Coal inventory adjustment to market 212 579 729 --
Other (257) 391 186 (114)
Changes in operating assets and liabilities:
Trade receivables 4,774 (2,842) (33,048) (6,521)
Income tax receivable/payable -- -- -- 651
Inventories (970) 9,709 (1,433) (371)
Advance royalties (2,235) (3,011) 366 1,153
Accounts payable (321) 6,181 (7,410) (129)
Due to affiliates 5,149 264 3,252 --
Accrued taxes other than income taxes 797 289 (630) 678
Accrued payroll and related benefits 1,309 (1,836) 844 (828)
Accrued pneumoconiosis benefits 903 (4) (1,122) 544
Workers' compensation 1,661 1,052 2,222 (460)
Other (2,926) 2,366 452 2,370
--------- --------- --------- ---------
Total net adjustments 46,551 55,792 (20,163) 22,691
--------- --------- --------- ---------
Net cash provided by (used in) operating activities 63,651 71,373 (13,891) 32,896
--------- --------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of property, plant and equipment (53,714) (46,151) (17,173) (21,984)
Proceeds from sale of property, plant and equipment 183 210 125 447
Purchase of marketable securities (33,527) (72,523) (51,287) --
Proceeds from the maturity of marketable securities 60,840 77,464 24,434 --
--------- --------- --------- ---------
Net cash used in investing activities (26,218) (41,000) (43,901) (21,537)
--------- --------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from initial public offering (Note 1) -- -- 137,872 --
Cash contribution by General Partner -- -- 5,917 --
Distributions upon formation (Note 1) -- -- (64,750) --
Payment of formation costs -- -- (4,140) --
Deferred financing cost -- -- (3,517) --
Borrowings under revolving credit facility 1,100 29,500 -- --
Payments under revolving credit facility (1,100) (29,500) -- --
Payments on long-term debt (3,750) -- (1,975) --
Distributions to Partners (31,440) (31,440) (3,615) --
Return of capital to Parent -- -- -- (11,359)
--------- --------- --------- ---------
Net cash provided by (used in) financing activities (35,190) (31,440) 65,792 (11,359)
--------- --------- --------- ---------
NET CHANGE IN CASH AND CASH EQUIVALENTS 2,243 (1,067) 8,000 --
CASH AND CASH EQUIVALENTS AT
BEGINNING OF PERIOD 6,933 8,000 -- --
--------- --------- --------- ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 9,176 $ 6,933 $ 8,000 $ --
========= ========= ========= =========
</Table>
See notes to consolidated and combined financial statements.
38
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL (DEFICIT)
FOR THE YEARS ENDED DECEMBER 31, 2001 AND 2000, AND THE PERIOD FROM THE
PARTNERSHIP'S COMMENCEMENT OF OPERATIONS (ON AUGUST 20, 1999) TO DECEMBER 31,
1999
(IN THOUSANDS, EXCEPT UNIT DATA)
- --------------------------------------------------------------------------------
<Table>
<Caption>
NUMBER OF LIMITED TOTAL
PARTNER UNITS MINIMUM PARTNERS'
----------------------- GENERAL PENSION CAPITAL
COMMON SUBORDINATED COMMON SUBORDINATED PARTNERS LIABILITY (DEFICIT)
--------- ------------ --------- --------- --------- --------- ---------
Balance at commencement of
operations (on August 20, 1999) -- -- $ -- $ 1 $ -- $ -- $ 1
Issuance of units to public 7,750,000 -- 133,732 -- -- -- 133,732
Contribution of net assets of
Predecessor 1,232,780 6,422,531 23,455 122,186 (24,612) (459) 120,570
Managing General Partner
contribution -- -- -- -- 5,917 -- 5,917
Amount retained by Special
General Partner from
debt borrowings assumed
by the Partnership -- -- -- -- (214,514) -- (214,514)
Distribution at time of
formation -- -- -- -- (64,750) -- (64,750)
Distribution to Partners -- -- (2,066) (1,477) (72) -- (3,615)
Comprehensive income:
Net income from
commencement of
operations (on August 20,
1999) to December 31, 1999 -- -- 3,584 2,563 125 -- 6,272
Minimum pension liability -- -- -- -- -- 459 459
--------- --------- --------- --------- --------- --------- ---------
Total comprehensive income -- -- 3,584 2,563 125 459 6,731
--------- --------- --------- --------- --------- --------- ---------
Balance at December 31, 1999 8,982,780 6,422,531 158,705 123,273 (297,906) -- (15,928)
Net income -- -- 8,903 6,366 312 -- 15,581
Distribution to Partners -- -- (17,966) (12,845) (629) -- (31,440)
--------- --------- --------- --------- --------- --------- ---------
Balance at December 31, 2000 8,982,780 6,422,531 149,642 116,794 (298,223) -- (31,787)
Comprehensive income:
Net income -- -- 9,772 6,986 342 -- 17,100
Minimum pension liability -- -- -- -- -- (814) (814)
--------- --------- --------- --------- --------- --------- ---------
Total comprehensive income -- -- 9,772 6,986 342 (814) 16,286
Distribution to Partners -- -- (17,966) (12,845) (629) -- (31,440)
--------- --------- --------- --------- --------- --------- ---------
Balance at December 31, 2001 8,982,780 6,422,531 $ 141,448 $ 110,935 $(298,510) $ (814) $ (46,941)
========= ========= ========= ========= ========= ========= =========
</Table>
See notes to consolidated and combined financial statements.
39
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS FOR THE YEARS
ENDED DECEMBER 31, 2001 AND 2000, AND THE PERIOD FROM THE PARTNERSHIP'S
COMMENCEMENT OF OPERATIONS (ON AUGUST 20, 1999) TO DECEMBER 31, 1999,
AND THE PREDECESSOR PERIOD FROM JANUARY 1, 1999 TO AUGUST 19, 1999
- --------------------------------------------------------------------------------
1. ORGANIZATION AND PRESENTATION
Alliance Resource Partners, L.P., a Delaware limited partnership (the
"Partnership") was formed on May 17, 1999, to acquire, own and operate
certain coal production and marketing assets of Alliance Resource
Holdings, Inc., a Delaware corporation ("ARH") (formerly known as Alliance
Coal Corporation), consisting of substantially all of ARH's operating
subsidiaries, but excluding ARH.
Prior to August 20, 1999, (a) MAPCO Coal Inc., a Delaware corporation and
direct wholly-owned subsidiary of ARH merged with and into Alliance Coal,
LLC, a Delaware limited liability company ("Alliance Coal"), which prior
to August 20, 1999 was also a wholly-owned subsidiary of ARH, (b) several
other indirect corporate subsidiaries of ARH were merged with and into
corresponding limited liability companies, each of which is a wholly-owned
subsidiary of Alliance Coal, and (c) two indirect limited liability
company subsidiaries of ARH became subsidiaries of Alliance Coal as a
result of the merger described in clause (a) above. Collectively, the coal
production and marketing assets and operating subsidiaries of ARH acquired
by the Partnership, but excluding ARH, are referred to as the Alliance
Resource Group (the "Predecessor"). The Delaware limited partnerships and
limited liability companies and corporation that comprise the Partnership
are as follows: Alliance Resource Partners, L.P., Alliance Resource
Operating Partners, L.P. (the "Intermediate Partnership"), Alliance Coal,
LLC (the holding company for operations), Alliance Land, LLC, Alliance
Properties, LLC, Alliance Service, Inc., Backbone Mountain, LLC, Excel
Mining, LLC, Gibson County Coal, LLC, Hopkins County Coal, LLC, MC Mining,
LLC, Mettiki Coal, LLC, Mettiki Coal (WV), LLC, Mt. Vernon Transfer
Terminal, LLC, Pontiki Coal, LLC, Webster County Coal, LLC, and White
County Coal, LLC.
The accompanying consolidated financial statements include the accounts
and operations of the limited partnerships and limited liability companies
disclosed above and present the financial position as of December 31, 2001
and 2000 and the results of their operations, cash flows and changes in
partners' capital (deficit) for the years ended December 31, 2001 and 2000
and the period from commencement of operations on August 20, 1999 to
December 31, 1999. The accompanying combined financial statements include
the accounts and operations of the Predecessor for the period indicated.
All material intercompany transactions and accounts of the Partnership and
Predecessor have been eliminated.
Initial Public Offering and Concurrent Transactions
On August 20, 1999, the Partnership completed its initial public offering
(the "IPO") of 7,750,000 Common Units ("Common Units") representing
limited partner interests in the Partnership at a price of $19.00 per
unit.
Concurrently with the closing of the IPO, the Partnership entered into a
contribution and assumption agreement (the "Contribution Agreement") dated
August 20, 1999 among the Partnership and the other parties named therein,
whereby, among other things, ARH contributed its 100% member interest in
Alliance Coal, which is the sole member of thirteen subsidiary operating
limited liability companies, to the Intermediate Partnership, and the
Intermediate Partnership holds a 99.999% non-managing member interest in
Alliance Coal. The Partnership and the Intermediate Partnership are
managed by Alliance
40
Resource Management GP, LLC, a Delaware limited liability company (the
"Managing GP"), which as a result of the consummation of the transactions
under the Contribution Agreement, holds (a) a 0.99% and 1.0001% managing
general partner interest in the Partnership and the Intermediate
Partnership, respectively, and (b) a 0.001% managing member interest in
Alliance Coal. Also, as a result of the consummation of the transactions
completed under the Contribution Agreement, Alliance Resource GP, LLC, a
Delaware limited liability company and wholly-owned subsidiary of ARH (the
"Special GP"), holds (a) 1,232,780 Common Units, (b) 6,422,531
Subordinated Units convertible into Common Units in the future upon the
occurrence of certain events and (c) a 0.01% special general partner
interest in each of the Partnership and the Intermediate Partnership.
Concurrently with the closing of the IPO, the Special GP issued and the
Intermediate Partnership assumed the obligations under a $180 million
principal amount of 8.31% senior notes due August 20, 2014. The Special GP
also entered into and the Intermediate Partnership assumed the obligations
under a $100 million credit facility.
Consistent with guidance provided by the Emerging Issues Task Force in
Issue No. 87-21, "Change of Accounting Basis in Master Limited Partnership
Transactions," the Partnership maintained the historical cost basis of the
$121 million of net assets received under the Contribution Agreement.
Pro Forma Results of Operations (Unaudited)
For the year ended December 31, 1999, the pro forma total revenues would
have been approximately $346,828,000, the pro forma net income would have
been approximately $7,567,000 and net income per limited partner unit
would have been $0.48. The pro forma results of operations are derived
from the historical financial statements of the Partnership from the
commencement of operations on August 20, 1999 through December 31, 1999
and the Predecessor for the period from January 1, 1999 through August 19,
1999. The pro forma results of operations reflect certain pro forma
adjustments to the historical results of operations as if the Partnership
had been formed on January 1, 1999. The pro forma adjustments include pro
forma interest on debt assumed by the Partnership and the elimination of
income tax expense as income taxes will be borne by the partners and not
the Partnership.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ESTIMATES - The preparation of consolidated and combined financial
statements in conformity with generally accepted accounting principles
requires management to make estimates and assumptions that affect the
reported amounts and disclosures in the consolidated and combined
financial statements. Actual results could differ from those estimates.
FAIR VALUE OF FINANCIAL INSTRUMENTS - The carrying amounts for accounts
receivable, marketable securities, and accounts payable approximate fair
value because of the short maturity of those instruments. At December 31,
2001 and 2000, the estimated fair value of long-term debt was
approximately $226 million and $230 million, respectively. The fair value
of long-term debt is based on interest rates that are currently available
to the Partnership for issuance of debt with similar terms and remaining
maturities.
CASH AND CASH EQUIVALENTS - Cash and cash equivalents include cash on hand
and on deposit, including highly liquid investments with maturities of
three months or less.
CASH MANAGEMENT - The Partnership reclassified outstanding checks of
$3,352,000 and $4,698,000 at December 31, 2001 and 2000, respectively, to
accounts payable in the consolidated balance sheets.
41
MARKETABLE SECURITIES - At December 31, 2001, the Partnership has an
investment in a Federal Agency Note, which matures February 1, 2002 and is
classified as an available-for-sale security. At December 31, 2000, the
Partnership had investments in six-month U.S. Treasury Notes that were
classified as available-for-sale securities. At December 31, 2001 and
2000, the cost of marketable securities approximates fair value and no
effect of unrealized gains (losses) is reflected in Partners' capital
(deficit).
INVENTORIES - Coal inventories are stated at the lower of cost or market
on a first-in, first-out basis. Supply inventories are stated at the lower
of cost or market on an average cost basis.
PROPERTY, PLANT AND EQUIPMENT - Additions and replacements constituting
improvements are capitalized. Maintenance, repairs, and minor replacements
are expensed as incurred. Depreciation and amortization are computed
principally on the straight-line method based upon the estimated useful
lives of the assets or the estimated life of each mine, whichever is less
ranging from 5 to 20 years. Depreciable lives for mining equipment and
processing facilities range from 2 to 20 years. Depreciable lives for land
and land improvements and depletable lives for mineral rights range from 5
to 20 years. Depreciable lives for buildings, office equipment and
improvements range from 2 to 20 years. Gains or losses arising from
retirements are included in current operations. Depletion of mineral
rights is provided on the basis of tonnage mined in relation to estimated
recoverable tonnage. At December 31, 2001 and 2000, land and mineral
rights include $2,178,000 representing the carrying value of coal reserves
attributable to properties where the Partnership is not currently engaged
in mining operations or leasing to third parties, and therefore, the coal
reserves are not currently being depleted.
LONG-LIVED ASSETS - The Partnership reviews the carrying value of
long-lived assets and certain identifiable intangibles whenever events or
changes in circumstances indicate that the carrying amount may not be
recoverable based upon estimated undiscounted future cash flows. The
amount of an impairment is measured by the difference between the carrying
value and the fair value of the asset, which is based on cash flows from
that asset, discounted at a rate commensurate with the risk involved.
During 2000, the Partnership recorded an impairment loss of approximately
$2,439,000 relating to certain transloading facility assets, associated
with Seminole Electric Cooperative, Inc.'s ("Seminole") termination of a
long-term contract for transloading of coal from rail to barge. Because
this facility's revenues were primarily attributable to the Seminole
long-term contract, the carrying value of the transloading facility and
associated equipment, net of salvage value, was recorded as an impairment
and is included as an unusual item in 2000 in the accompanying
consolidated and combined statements of income.
ADVANCE ROYALTIES - Rights to coal mineral leases are often acquired
through advance royalty payments. Management assesses the recoverability
of royalty prepayments based on estimated future production and
capitalizes these amounts accordingly. Royalty prepayments expected to be
recouped within one year are classified as a current asset. As mining
occurs on those leases, the royalty prepayments are included in the cost
of mined coal. Royalty prepayments estimated to be nonrecoverable are
expensed.
COAL SUPPLY AGREEMENTS - The Predecessor purchased the coal operations of
MAPCO Inc. effective August 1, 1996, in a business combination using the
purchase method of accounting. A portion of the acquisition costs was
allocated to coal supply agreements. This allocated cost is being
amortized on the basis of coal shipped in relation to total coal to be
supplied during the respective contract terms. The amortization periods
end on various dates from September 2002 to December 2005. Accumulated
amortization for coal supply agreements was $26,432,000 and $22,139,000 at
December 31, 2001 and 2000, respectively.
42
RECLAMATION AND MINE CLOSING COSTS - The liability for the estimated cost
of future mine reclamation and closing procedures is recorded on a present
value basis when incurred and the associated cost is capitalized by
increasing the carrying amount of the related long-lived asset. Those
costs relate to sealing portals at underground mines and to reclaiming the
final pit and support acreage at surface mines. Other costs common to both
types of mining are related to removing or covering refuse piles and
settling ponds, and dismantling preparation plants, other facilities and
roadway infrastructure. Ongoing reclamation costs principally involve
restoration of disturbed land and are expensed as incurred during the
mining process.
WORKERS' COMPENSATION AND PNEUMOCONIOSIS ("BLACK LUNG") BENEFITS - The
Partnership is self-insured for workers' compensation benefits, including
black lung benefits. The Partnership accrues a workers' compensation
liability for the estimated present value of workers' compensation and
black lung benefits based on actuarial valuations. Effective January 1,
2001, the Partnership changed its method of estimating the black lung
benefits liability (Note 3).
INCOME TAXES - No provision for income taxes related to the operations of
the Partnership is included in the accompanying consolidated financial
statements because, as a Partnership, it is not subject to federal or
state income tax and the tax effect of its activities accrues to the
unitholders. Net income for financial statement purposes may differ
significantly from taxable income reportable to unitholders as a result of
differences between the tax bases and financial reporting bases of assets
and liabilities and the taxable income allocation requirements under the
Partnership agreement.
The Predecessor was included in the combined U.S. income tax returns of
ARH. The Predecessor provided for income taxes on its separate taxable
income and other tax attributes. Deferred income taxes are computed based
on recognition of future tax expense or benefits, measured by enacted tax
rates that are attributable to taxable or deductible temporary differences
between financial statement and income tax reporting bases of assets and
liabilities.
REVENUE RECOGNITION - Revenues from coal sales are recognized when title
passes to the customer as the coal is shipped. Non-coal sales revenues
primarily consist of fees associated with agreements to host and operate a
third-party coal synfuel facility and assist with the coal synfuel
marketing and other related services. These non-coal sales revenues are
recognized as the services are performed. Transportation revenues are
recognized in connection with the Partnership incurring the corresponding
costs of transporting the coal to customers through third-party carriers
since the Partnership is directly reimbursed for these costs through
customer billings.
NET INCOME PER UNIT - Basic net income per limited partner unit is
determined by dividing net income, after deducting the General Partners'
2% interest, by the weighted average number of outstanding Common Units
and Subordinated Units (a total of 15,405,311 units as of December 31,
2001 and 2000). Diluted net income per unit is based on the combined
weighted average number of Common Units, Subordinated Units and common
unit equivalents outstanding, which primarily include restricted units
granted under the Long-Term Incentive Plan (Note 11).
SEGMENT REPORTING - The Partnership has no reportable segments due to its
operations consisting solely of producing and marketing coal. The
Partnership has disclosed major customer sales information (Note 16) and
geographic areas of operation (Note 17).
NEW ACCOUNTING STANDARDS - Effective January 1, 2001, the Partnership
adopted Statement of Financial Accounting Standards ("SFAS") No. 133,
"Accounting for Derivative Instruments and Hedging Activities," which
establishes accounting and reporting standards for derivative instruments
and for hedging activities. It requires that all derivatives be recognized
as either assets or liabilities in the
43
statement of financial position and be measured at fair value. The
Partnership currently has no identified derivative instruments or hedging
activities. Accordingly, this standard had no effect on the Partnership's
consolidated financial statements upon adoption.
In June 2001, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 141, "Business Combinations" and No. 142 "Goodwill and Intangible
Assets." SFAS No. 141 eliminates the pooling-of-interests method of
accounting for business combinations and requires that all business
combinations be accounted for under the purchase method. In addition, it
further clarifies the criteria for recognition of intangible assets
separately from goodwill. This statement is effective for business
combinations initiated after June 30, 2001. SFAS No. 142 discontinues the
practice of amortizing goodwill and indefinite lived intangible assets and
initiates an annual review for impairment. This statement is effective
January 1, 2002, for all goodwill and other intangible assets included in
an entity's statement of financial position at that date, regardless of
when those assets were initially recognized. SFAS 141 and 142 are not
expected to have a material impact on the Partnership's financial
statements.
In August 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations," which requires the fair value of a liability for
an asset retirement obligation to be recognized in the period in which it
is incurred. When the liability is initially recorded, a cost is
capitalized by increasing the carrying amount of the related long-lived
asset. Over time, the liability is accreted to its present value each
period, and the capitalized cost is depreciated over the useful life of
the related asset. To settle the liability, the obligation for its
recorded amount is paid or a gain or loss upon settlement is incurred.
Since the Partnership has historically adhered to accounting principles
similar to SFAS No. 143 in accounting for its reclamation and mine closing
costs, the Partnership does not believe that adoption of SFAS No. 143,
effective January 1, 2003, will have a material impact on its financial
statements.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," which is effective for
fiscal years beginning after December 15, 2001, and is not expected to
have a material impact on the Partnership's financial statements upon
adoption on January 1, 2002.
RECLASSIFICATIONS - Certain reclassifications have been made to the 1999
combined and consolidated financial statements to conform to the
classifications used in 2001 and 2000.
3. ACCOUNTING CHANGE
The Partnership changed its method of estimating coal workers'
pneumoconiosis ("black lung") benefits liability effective January 1, 2001
to the service cost method described in SFAS No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions," which method
is permitted under SFAS No. 112 "Employers' Accounting for Postemployment
Benefits." The Partnership previously accrued the black lung benefits
liability at the present value of the actuarially determined current and
future estimated black lung benefit payments utilizing the methodology
prescribed under SFAS No. 5 "Accounting for Contingencies," which was also
permitted by SFAS No. 112. Recently, governmental regulations regarding
the black lung benefits claims approval process were enacted. These new
regulations specifically define the black lung disability as progressive
and also expand the definition of pneumoconiosis to mandate consideration
of diseases that are caused by factors other than exposure to coal dust.
The Partnership believes the change to the SFAS No. 106 measurement
methodology better matches black lung costs over the service lives of the
miners who ultimately receive the black lung benefits and is more
reflective of the recently enacted regulations, which place significant
emphasis on coal miners' future years of employment in the coal industry.
44
The adjustment of $7,939,000 to apply retroactively the new method of
estimating the black lung liability is included in net income for the year
ended December 31, 2001. The effect of the change for the year ended
December 31, 2001 was to decrease income before cumulative effect of a
change in accounting principle $435,000 ($(0.03) per basic and diluted
limited partner unit) and increase net income $7,504,000 ($0.48 and $0.47
per basic and diluted partner unit, respectively). Assuming the
retroactive application of the service cost method of estimating the black
lung liability, the pro forma net income for the year ended December 31,
2000, and the period from the Partnership's commencement of operations on
August 20, 1999 to December 31, 1999, would have been approximately
$14,907,000 and $6,395,000 or $0.95 and $0.41 per basic limited partner
unit and $0.94 and $0.41 per diluted limited partner unit, respectively,
as compared to reported net income of $15,581,000 and $6,272,000 or $0.99
and $0.40 per basic limited partner unit and $0.98 and $0.40 per diluted
limited partner unit, respectively. Pro forma net income for the
Predecessor period from January 1, 1999 to August 19, 1999 would have been
$10,071,000 compared to reported net income of $10,205,000.
4. UNUSUAL ITEMS
The Partnership was involved in litigation with Seminole with respect to
Seminole's termination of a long-term contract for the transloading of
coal from rail to barge through the Mt. Vernon terminal in Indiana. The
final resolution between the parties, reached in conjunction with an
arbitrator's decision rendered during the third quarter of 2000, included
both cash payments and amendments to an existing coal supply contract. The
Partnership recorded income of $12,141,000, which is net of litigation
expenses of approximately $881,000 and an impairment charge of $2,439,000
relating to the facility's assets. Additionally, during the third quarter
of 2000, the Partnership recorded an expense of $2,675,000, consisting of
$675,000 relating to a settlement and $2,000,000 attributable to
contingencies associated with third party claims arising out of the
Partnership's mining operations. The net effect of these unusual items is
$9,466,000 recorded in the year ended December 31, 2000.
5. INVENTORIES
Inventories consist of the following at December 31, (in thousands):
<Table>
<Caption>
2001 2000
------- -------
Coal $ 4,184 $ 5,140
Supplies 7,416 5,702
------- -------
$11,600 $10,842
======= =======
</Table>
45
6. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consists of the following at December 31,
(in thousands):
<Table>
<Caption>
2001 2000
---------- ----------
Mining equipment and processing facilities $ 299,480 $ 267,287
Land and mineral rights 17,691 17,686
Buildings, office equipment and improvements 29,359 24,224
Construction in progress 20,520 11,248
---------- ----------
367,050 320,445
Less accumulated depreciation, depletion and amortization (169,960) (135,782)
---------- ----------
$ 197,090 $ 184,663
========== ==========
</Table>
7. LONG-TERM DEBT
Long-term debt consists of the following at December 31, (in thousands):
<Table>
<Caption>
2001 2000
--------- ---------
Senior notes $ 180,000 $ 180,000
Term loan 46,250 50,000
--------- ---------
226,250 230,000
Less current maturities (15,000) (3,750)
--------- ---------
$ 211,250 $ 226,250
========= =========
</Table>
In connection with the closing of the IPO, the Special GP issued and the
Intermediate Partnership assumed obligations with respect to a $180
million principal amount of senior notes pursuant to a Note Purchase
Agreement with a group of institutional investors in a private placement
offering. The senior notes are payable in ten annual installments of $18
million beginning in August 2005 and bear interest at 8.31%, payable
semiannually.
The Special GP also entered into, and the Intermediate Partnership assumed
obligations under, a $100 million credit facility. The credit facility
consists of three tranches, including a $50 million term loan facility, a
$25 million working capital facility and a $25 million revolving credit
facility. In connection with the closing of the IPO, the Special GP
borrowed $50 million under the term loan facility and the Special GP and
Intermediate Partnership initially purchased $50 million of U.S. Treasury
Notes, which secured the term loan through September 19, 2002. These
investments were subject to certain provisions of the credit facility,
which restricted the use of these investments for financing a required
level of capital expenditures through August 2001. During 2001, the
Partnership had satisfied the capital expenditure requirements and
consequently, the Partnership's use of these investments was not
restricted. The Partnership liquidated these investments during 2001. The
Partnership has outstanding borrowings of $46.3 million under the term
loan facility at December 31, 2001.
The working capital facility can be used to provide working capital and,
if necessary, to fund distributions to unitholders. The revolving credit
facility can be used for general business purposes, including capital
expenditures and acquisitions. The rate of interest charged is adjusted
quarterly based on a pricing grid, which is a function of the ratio of the
Partnership's debt to cash flow. The credit facility provides the
Partnership the option of borrowing at either (1) the London Interbank
Offered Rate
46
("LIBOR") or (2) the "Base Rate" which is equal to the greater of (a) the
Chase Prime Rate, or (b) the Federal Funds Rate plus 1/2 of 1%, plus, in
either option, an applicable margin. The weighted average interest rates
on the term loan facility at December 31, 2001 and 2000 were 3.40% and
7.77%, respectively. In accordance with the pricing grid, a commitment fee
ranging from 0.375% to 0.500% per annum is paid quarterly on the unused
portion of the working capital and revolving credit facilities. There were
no amounts outstanding under the Partnership's working capital facility or
revolving credit facility as of December 31, 2001 and 2000. The credit
facility expires in August 2004.
The senior notes and credit facility are guaranteed by all subsidiaries of
the Intermediate Partnership. The senior notes and credit facility contain
various restrictive and affirmative covenants, including limitations on
the amount of distributions by the Intermediate Partnership and the
incurrence of other debt. The Partnership was in compliance with the
covenants of both the credit facility and senior notes at December 31,
2001 and 2000.
The Partnership incurred debt issuance costs aggregating approximately
$3,517,000, which have been deferred and are being amortized as a
component of interest expense over the terms of the notes.
The Partnership entered into agreements with three banks to provide
letters of credit in an aggregate amount of $25.0 million. At December 31,
2001, the Partnership had $15.0 million in letters of credit outstanding.
The Special GP guarantees the letters of credit (Note 14).
Aggregate maturities of long-term debt are payable as follows
(in thousands):
<Table>
<Caption>
YEAR ENDING
DECEMBER 31,
2002 $ 15,000
2003 16,250
2004 15,000
2005 18,000
2006 18,000
Thereafter 144,000
--------
$226,250
========
</Table>
8. DISTRIBUTIONS OF AVAILABLE CASH
The Partnership will distribute 100% of its available cash within 45 days
after the end of each quarter to unitholders of record and to the General
Partners. Available cash is generally defined as all cash and cash
equivalents of the Partnership on hand at the end of each quarter less
reserves established by the Managing GP in its reasonable discretion for
future cash requirements. These reserves are retained to provide for the
conduct of the Partnership's business, the payment of debt principal and
interest and to provide funds for future distributions.
Distributions of available cash to the holder of Subordinated Units are
subject to the prior rights of holders of Common Units to receive the
minimum quarterly distribution ("MQD") for each quarter during the
subordination period and to receive any arrearages in the distribution of
the MQD on the Common Units for the prior quarters during the
subordination period. The MQD is $0.50 per unit ($2.00 per unit on an
annual basis). Upon expiration of the subordination period, which will
generally not occur before September 30, 2004, all Subordinated Units will
be converted on a one-for-one basis into Common Units and will then
participate, on a pro rata basis with all other Common Units in future
47
distributions of available cash. However, under certain circumstances, up
to 50% of the Subordinated Units may convert into Common Units on or after
September 30, 2003. Common Units will accrue arrearages with respect to
distributions for any quarter during the subordination period, but
Subordinated Units will not accrue any arrearages with respect to
distributions for any quarter.
If quarterly distributions of available cash exceed the MQD or the target
distributions levels, the General Partners will receive distributions
based on specified increasing percentages of the available cash that
exceeds the MQD or target distribution levels. The target distribution
levels are based on the amounts of available cash from the Partnership's
operating surplus distributed for a given quarter that exceed
distributions for the MQD and common unit arrearages, if any.
For the 42-day period from the Partnership's commencement of operations
(on August 20, 1999) through September 30, 1999, the Partnership paid a
pro-rata MQD distribution of $0.23 per unit on its outstanding Common and
Subordinated Units. For each of the quarters ended December 31, 1999
through September 30, 2001, quarterly distributions of $0.50 per unit were
paid to the common and subordinated unitholders. On January 29, 2002, the
Partnership declared a MQD, for the period from October 1, 2001 to
December 31, 2001, of $0.50 per unit, totaling approximately $7,703,000 on
its outstanding Common and Subordinated Units, payable on February 14,
2002 to all unitholders of record on February 4, 2002.
9. INCOME TAXES
The Predecessor recognized a deferred tax asset for the future tax
benefits attributable to deductible temporary differences and other credit
carryforwards, including alternative minimum tax credit carryforwards.
Realization of these future tax benefits was dependent on the
Predecessor's ability to generate future taxable income, which was not
assured. Management of the Predecessor believed that future taxable income
would be sufficient to recognize only a portion of the tax benefits and
had established a valuation allowance.
Concurrent with the closing of the IPO on August 20, 1999, and in
connection with the Contribution Agreement, ARH retained the current and
deferred income taxes of the Predecessor.
Income before income taxes is derived from domestic operations.
Significant components of income taxes are as follows (in thousands):
<Table>
<Caption>
FOR THE
PERIOD FROM
JANUARY 1, 1999
TO
AUGUST 19, 1999
---------------
Current:
Federal $3,376
State 483
------
3,859
Deferred:
Federal 595
State 44
------
639
Income tax expense $4,498
======
</Table>
48
A reconciliation of the statutory U.S. federal income tax rate and the
Predecessor's effective income tax rate is as follows:
<Table>
<Caption>
FOR THE
PERIOD FROM
JANUARY 1, 1999
TO
AUGUST 19, 1999
---------------
Statutory rate 35%
Increase (decrease) resulting from:
Excess of tax over book depletion (21)
Alternative minimum tax credit carryforwards 3
State income taxes, net of federal benefit 3
Valuation allowance 10
Other 1
---
Effective income tax rate 31%
===
</Table>
10. NET INCOME PER LIMITED PARTNER UNIT
A reconciliation of net income and weighted average units used in
computing basic and diluted earnings per unit is as follows (in thousands,
except per unit data):
<Table>
<Caption>
FROM
COMMENCEMENT
YEAR ENDED OF OPERATIONS
DECEMBER 31, (ON AUGUST 20, 1999)
------------------------- TO
2001 2000 DECEMBER 31, 1999
---- ---- -----------------
Net income per limited partner unit $ 16,758 $ 15,269 $ 6,147
Weighted average limited partner units - basic 15,405 15,405 15,405
Basic net income per limited partner unit $ 1.09 $ 0.99 $ 0.40
========== ========== ==========
Basic net income per limited partner unit
before accounting change $ 0.58 $ 0.99 $ 0.40
========== ========== ==========
Weighted average limited partner units - basic 15,405 15,405 15,405
Units contingently issuable:
Restricted units for Long-Term Incentive Plan 263 142 --
Directors' compensation units deferred 9 4 --
Supplemental Executive Retirement Plan 8 -- --
---------- ---------- ----------
Weighted average limited partner units, assuming
dilutive effect of restricted units 15,685 15,551 15,405
---------- ---------- ----------
Diluted net income per limited partner unit $ 1.07 $ 0.98 $ 0.40
========== ========== ==========
Diluted net income per limited partner unit before
accounting change $ 0.57 $ 0.98 $ 0.40
========== ========== ==========
</Table>
49
11. EMPLOYEE BENEFIT PLANS
LONG-TERM INCENTIVE PLAN - Effective January 1, 2000, the Managing GP
adopted the Long-Term Incentive Plan (the "LTIP") for certain employees
and directors of the Managing GP and its affiliates who perform services
for the Partnership. Annual grant levels and vesting provisions for
designated participants are recommended by the President and Chief
Executive Officer of the Managing GP, subject to the review and approval
of the Compensation Committee. Grants are made either of restricted units,
which are "phantom" units that entitle the grantee to receive a Common
Unit or an equivalent amount of cash upon the vesting of a phantom unit,
or options to purchase Common Units. Common Units to be delivered upon the
vesting of restricted units or to be issued upon exercise of a unit option
will be acquired by the Managing GP in the open market at a price equal to
the then prevailing price, or directly from ARH or any other third party,
including units newly issued by the Partnership, units already owned by
the Managing GP, or any combination of the foregoing. The Partnership
agreement provides that the Managing GP be reimbursed for all costs
incurred in acquiring these Common Units or in paying cash in lieu of
Common Units upon vesting of the restricted units. The aggregate number of
units reserved for issuance under the LTIP is 600,000. Effective January
1, 2000 and 2001 the Compensation Committee approved grants of 142,100 and
129,200 restricted units, respectively, which vest at the end of the
subordination period, which will generally not end before September 30,
2004. During 2001, 8,500 units were forfeited. During 2001 and 2000, the
Managing GP billed the Partnership approximately $1,929,000 and $538,000,
respectively, attributable to the LTIP. The Partnership has recorded this
amount as compensation expense. Effective January 1, 2002, the
Compensation Committee approved additional grants of 131,885 restricted
units, which also vest at the end of the subordination period.
DEFINED CONTRIBUTION PLANS - The Partnership's employees currently
participate in a defined contribution profit sharing and savings plan
sponsored by the Partnership, which is the same plan sponsored by the
Predecessor. This plan covers substantially all full-time employees. Plan
participants may elect to make voluntary contributions to this plan up to
a specified amount of their compensation. The Partnership makes
contributions based on matching 75% of employee contributions up to 3% of
their annual compensation as well as an additional nonmatching
contribution of 3/4 of 1% of their compensation. Additionally, the
Partnership contributes a defined percentage of eligible earnings for
certain employees not covered by the defined benefit plan described below.
The Partnership's expense for its plan was approximately $1,935,000 and
$1,590,000 for the years ended December 31, 2001 and 2000, respectively,
and $715,000 for the period from August 20, 1999 to December 31, 1999. The
Predecessor's expense for the plan was $1,226,000 for the period from
January 1, 1999 to August 19, 1999.
DEFINED BENEFIT PLANS - Certain employees at the mining operations
participate in a defined benefit plan sponsored by the Partnership, which
is the same plan sponsored by the Predecessor. The benefit formula is a
fixed dollar unit based on years of service.
50
The following sets forth changes in benefit obligations and plan assets
for the years ended December 31, 2001 and 2000 and the funded status of
the plans reconciled with amounts reported in the Partnership's
consolidated financial statements at December 31, 2001 and 2000,
respectively (dollars in thousands):
<Table>
<Caption>
2001 2000
-------- --------
CHANGE IN BENEFIT OBLIGATIONS:
Benefit obligations at beginning of year $ 10,135 $ 7,774
Service cost 2,050 1,971
Interest cost 755 596
Actuarial (gain) loss 384 (136)
Benefits paid (122) (70)
-------- --------
Benefit obligation at end of year 13,202 10,135
-------- --------
CHANGE IN PLAN ASSETS:
Fair value of plan assets at beginning of year 9,500 8,265
Employer contribution 1,500 1,100
Actual return (loss) on plan assets (370) 205
Benefits paid (122) (70)
-------- --------
Fair value of plan assets at end of year 10,508 9,500
-------- --------
Funded status (2,694) (635)
Unrecognized prior service cost 235 284
Unrecognized actuarial (gain) loss 814 (828)
-------- --------
Net amount recognized $ (1,645) $ (1,179)
======== ========
WEIGHTED-AVERAGE ASSUMPTIONS AS OF DECEMBER 31:
Discount rate 7.25% 7.50%
Expected return on plan assets 9.00% 9.00%
COMPONENTS OF NET PERIODIC BENEFIT COST:
Service cost $ 2,050 $ 1,971
Interest cost 755 596
Expected return on plan assets (888) (737)
Prior service cost 48 48
Net gain -- (49)
-------- --------
Net periodic benefit cost $ 1,965 $ 1,829
======== ========
Effect on minimum pension liability $ 814 $ --
======== ========
</Table>
12. RECLAMATION AND MINE CLOSING COSTS
The majority of the Partnership's operations are governed by various state
statutes and the Federal Surface Mining Control and Reclamation Act of
1977, which establish reclamation and mine closing standards. These
regulations, among other requirements, require restoration of property in
accordance with specified standards and an approved reclamation plan. The
Partnership has estimated the costs and timing of future reclamation and
mine closing costs and recorded those estimates on a present value basis
using a 6% discount rate.
51
Discounting resulted in reducing the accrual for reclamation and mine
closing costs by $12,184,000 and $10,420,000 at December 31, 2001 and
2000, respectively. Estimated payments of reclamation and mine closing
costs as of December 31, 2001 are as follows (in thousands):
<Table>
<Caption>
Year ending December 31,
2002 $ 1,078
2003 1,743
2004 1,848
2005 3,538
2006 2,518
Thereafter 17,924
-------
Aggregate undiscounted
reclamation and mine
closing 28,649
Effect of discounting 12,184
-------
Total reclamation and mine
closing costs 16,465
Less current portion 1,078
-------
Reclamation and mine
closing costs $15,387
=======
</Table>
The following table presents the activity affecting the reclamation and
mine closing liability (in thousands):
<Table>
<Caption>
PARTNERSHIP PREDECESSOR
---------------------------------------------------------- ---------------
FROM
COMMENCEMENT FOR THE
YEAR ENDED OF OPERATIONS PERIOD FROM
DECEMBER 31, (ON AUGUST 20, 1999) JANUARY 1, 1999
------------------------------------ TO TO
2001 2000 DECEMBER 31, 1999 AUGUST 19, 1999
--------------- --------------- ----------------- ---------------
Beginning balance $ 16,018 $ 14,796 $ 13,856 $ 13,800
Accrual 943 1,074 348 457
Payments (454) (764) (394) (401)
Allocation of liability
associated with
acquisition and mine
development (42) 912 986 --
--------------- --------------- --------------- ---------------
Ending balance $ 16,465 $ 16,018 $ 14,796 $ 13,856
=============== =============== =============== ===============
</Table>
13. PNEUMOCONIOSIS ("BLACK LUNG") BENEFITS
Certain mine operating entities of the Partnership are liable under state
statutes and the Federal Coal Mine Health and Safety Act of 1969, as
amended, to pay black lung benefits to eligible employees and former
employees and their dependents.
The Partnership changed its method of estimating black lung benefits
liability effective January 1, 2001 to the service cost method (Note 3).
Under the service cost method the calculation of the actuarial present
value of the estimated black lung obligation is based on an actuarial
study performed by independent actuaries. Actuarial gains or losses are
amortized over the remaining service period of active miners. The discount
rate used to calculate the estimated present value of future obligations
was 5.5% and 6.0% at December 31, 2001 and 2000, respectively.
52
The reconciliation of changes in benefit obligations at December 31, 2001
is as follows (in thousands):
<Table>
Benefit obligations at beginning of year, including cumulative effect of
accounting change of $7,939 effective January 1, 2001 (Note 3) $ 13,712
Service cost 464
Interest cost 705
Benefits paid (266)
--------
Benefit obligations at end of year $ 14,615
========
</Table>
The Partnership previously accrued the black lung benefits liability based
upon the actuarially computed present and future claims. The cost or
reduction of cost due to change in the estimate of black lung benefits
charged (credited) to operations for the year ended December 31, 2000, the
period from the Partnership's commencement of operations on August 20,
1999 to December 31, 1999, and the Predecessor period from January 1, 1999
to August 19, 1999, was $123,000, $(1,028,000), and $726,000,
respectively.
The U.S. Department of Labor has issued revised regulations that will
alter the claims process for the federal black lung benefit recipients.
Both the coal and insurance industries are currently challenging through
litigation certain provisions of the revised regulations. The revised
regulations are expected to result in an increase in the incidence and
recovery of black lung claims.
14. RELATED PARTY TRANSACTIONS
The Partnership Agreement provides that the Managing GP and its affiliates
be reimbursed for all direct and indirect expenses it incurs or payments
it makes on behalf of the Partnership, including management's salaries and
related benefits, and accounting, budget, planning, treasury, public
relations, land administration, environmental, permitting, payroll,
benefits, disability, workers' compensation management, legal and
information technology services. The Managing GP may determine in its sole
discretion the expenses that are allocable to the Partnership. Total costs
billed by the Managing GP and its affiliates to the Partnership were
approximately $6,503,000, $3,899,000 and $1,283,000 for the years ended
December 31, 2001 and 2000, and the period from the Partnership's
commencement of operations on August 20, 1999 to December 31, 1999,
respectively.
ARH allocated certain direct and indirect general and administrative
expenses to the Predecessor. These allocations were primarily based on the
relative size of the direct mining operating costs incurred by each of the
mine locations of the Predecessor. The allocations of general and
administrative expenses to the Predecessor were approximately $2,982,000
for the period from January 1, 1999 to August 19, 1999. Management is of
the opinion that the allocations used were reasonable and appropriate.
During November 1999, the Managing GP was authorized by its Board of
Directors to purchase up to 1.0 million Common Units of the Partnership.
As of December 31, 2001 and 2000, the Managing GP owned 164,000 Common
Units that were purchased in the open market at prevailing market prices.
During September 2000, the Special GP acquired coal reserves and the right
to acquire additional coal reserves that are (a) contiguous to the
Partnership's Webster County Coal, LLC ("WCC") mining complex ("Providence
No. 3 Reserves") and (b) contiguous to the Partnership's Hopkins County
Coal, LLC ("HCC") mining complex ("Elk Creek Reserves"). Such coal
reserves and the rights to acquire additional coal reserves were
transferred to SGP Land, LLC ("SGP Land"), a newly formed wholly-owned
subsidiary of the Special GP.
53
Concurrent with such coal reserve acquisitions, the Special GP, through
affiliates, was negotiating for the purchase of (a) the capital stock of
Roberts Bros. Coal Co., Inc., Warrior Coal Mining Company, and Warrior
Coal Corporation, and (b) the related coal reserves ("Warrior Reserves")
owned by Cardinal Trust, LLC (collectively the "Warrior Group"). The
Warrior Group's operating assets are located adjacent to the Providence
No. 3 Reserves and these operating assets, excluding the Warrior Reserves,
were purchased by a newly formed affiliate of the Special GP, Warrior
Coal, LLC ("Warrior Coal") in January, 2001. SGP Land acquired the Warrior
Reserves, which are located between the Providence No. 3 Reserves and HCC
in January, 2001.
SGP Land entered into a mineral lease and sublease with WCC for a portion
of each of the Providence No. 3 Reserves and the Warrior Reserves, and
granted an option to HCC to lease and/or sublease the Elk Creek Reserves.
Under the terms of the WCC lease and sublease, WCC has an annual minimum
royalty obligation of $2.7 million, payable in advance, from 2000 to 2013
or until $37.8 million of cumulative annual minimum and/or earned royalty
payments have been paid. WCC paid an annual minimum royalty of $2.7
million in 2001 and 2000. Under the terms of the HCC option to lease and
sublease, HCC paid option fees of $684,000 and $645,000 in 2001 and 2000,
respectively. The anticipated annual minimum royalty obligation is
$684,000 payable in advance, from 2002 to 2009.
During 2000, ARH and the Managing GP were approached with the opportunity
to purchase certain mining assets of Warrior Coal located adjacent to the
Partnership's western Kentucky operation. Warrior Coal is an underground
mining complex that utilizes continuous mining units employing room and
pillar mining techniques. Warrior Coal produces approximately 1.5 million
tons per year, controls reserves that will provide for a minimum of ten
years of mining, and has the possibility of controlling additional
reserves in the future.
In accordance with the right of first refusal provision in the Omnibus
Agreement between ARH and the Partnership's Managing GP, ARH offered the
Managing GP the opportunity to purchase Warrior Coal. At the time, the
Managing GP declined the opportunity to purchase Warrior Coal as the
Partnership had previously committed to major capital expenditures at two
existing operations. As a condition to not exercising its right of first
refusal, the Partnership requested that ARH enter into a put and call
arrangement for Warrior Coal. After further discussions, ARH and the
Partnership, with the approval of the Conflicts Committee of the Managing
GP, entered into an Amended and Restated Put and Call Option Agreement
("Put/Call Agreement") in January 2001. Concurrently ARH, through an
indirect wholly-owned subsidiary, acquired Warrior Coal in January 2001
for $10 million.
The Put/Call Agreement preserved an opportunity for the Partnership to
acquire Warrior Coal during a specified time period in the future,
although at a price significantly greater than the price paid by ARH.
Under the terms of the Put/Call Agreement, ARH can require the Partnership
to purchase Warrior Coal during the period from January 2 to January 11,
2003. The put option price is approximately $12.5 million. The Partnership
can also require ARH to sell Warrior Coal to the Partnership during the
period from April 12, 2003 to December 31, 2006. The call option price
ranges between $13.6 million and $22.2 million depending on when the call
option is exercised.
The option provisions of the Put/Call Agreement are subject to certain
conditions, among others, including (a) the non-occurrence of a material
adverse change in the business and financial condition of Warrior Coal,
(b) the prohibition of any dividends or other distributions to Warrior
Coal's shareholders, (c) the maintenance of Warrior Coal's assets in good
working condition, (d) the prohibition on the sale of any equity interest
in Warrior Coal except for the options contained in the Put/Call
Agreement, and (e) the prohibition on the sale or transfer of Warrior
Coal's assets except those made in the ordinary course of its business.
The Put/Call Agreement option prices reflect negotiated sale and purchase
amounts that both parties determined would allow each party to satisfy
acceptable minimum investment returns in the event either the put or call
options are exercised. The Partnership has not made a final determination
concerning the potential exercise of its call option and has not been
advised by ARH concerning ARH's intention to exercise its put option. The
Partnership has developed financial projections for Warrior Coal based on
due diligence procedures it customarily performs when considering the
acquisition of a coal mine. The assumptions underlying the financial
projections made by the Partnership for Warrior Coal include (a) annual
production levels ranging from 1.5 million to 1.8 million tons, (b) coal
prices at or below current coal prices and (c) a discount rate of 12
percent. Based on these financial projections, at this time, the
Partnership believes that the fair value of Warrior Coal is equal to or
greater than the put option exercise price.
54
The Partnership provides management and administrative services to Warrior
Coal and SGP Land under an administrative service agreement. Under this
agreement, the Partnership has recognized approximately $1,019,000 as a
reduction of general and administrative expenses during the year ended
December 31, 2001. Accounts receivable from Warrior Coal of $108,000,
offsets a portion of the due to affiliates at December 31, 2001.
During 2001, the Partnership entered into an agreement with Warrior Coal
to perform certain reclamation procedures for the Partnership. The total
estimated cost of the reclamation procedures covered by this agreement is
$475,000 of which approximately $315,000 remains to be expended in 2002
for the expected completion of reclamation procedures by Warrior Coal.
During 2001, the Partnership made coal purchases of approximately
$3,135,000 from Warrior Coal. Accounts payable to Warrior Coal of
$1,876,000 is included in the amount due to affiliates at December 31,
2001. During December 2001, the Partnership entered into coal supply
agreements with Warrior Coal for the purchase of 1.8 million tons for the
year ending December 31, 2002.
The Partnership has a noncancelable operating lease arrangement with the
Special GP for the coal preparation plant and ancillary facilities at the
Gibson County Coal, LLC mining complex. Based on the terms of the lease,
the Partnership will make monthly payments of approximately $216,000
through January, 2010. Lease expense incurred for the years ended December
31, 2001 and 2000 was $2,592,000 and $14,000, respectively.
In 2001, SGP Land, as a successor in interest to an unaffiliated
third-party, entered into an amended mineral lease with MC Mining, LLC
("MC Mining"). Under the terms of the lease, MC Mining has and will pay an
annual minimum royalty obligation of $300,000 until $6.0 million of
cumulative annual minimum and/or earned royalty payments have been paid.
MC Mining paid royalties of $705,000 for the year ended December 31, 2001.
During 2001, the Partnership entered into agreements with three banks to
provide letters of credit in an aggregate amount of $25.0 million to
maintain surety bonds to secure its obligations for reclamation
liabilities and workers' compensation benefits. At December 31, 2001 the
Partnership had $15.0 million in letters of credit outstanding. The
Special GP guarantees these letters of credit, and as a result the
Partnership has agreed to compensate the Special GP for a guarantee fee
equal to 0.30% per annum of the face amount of the letters of credit
outstanding. The Partnership paid approximately $8,800 in guarantee fees
to the Special GP for the year ended December 31, 2001.
55
15. COMMITMENTS AND CONTINGENCIES
COMMITMENTS - The Partnership leases buildings and equipment under
operating lease agreements which provide for the payment of both minimum
and contingent rentals. The Partnership also has a noncancelable lease
with the Special GP (Note 14). Future minimum lease payments under
operating leases are as follows (in thousands):
<Table>
<Caption>
AFFILIATE OTHERS TOTAL
--------- ------ -------
Year ending December 31,
2002 $ 2,595 $ 702 $ 3,297
2003 2,595 568 3,163
2004 2,595 578 3,173
2005 2,595 578 3,173
2006 2,595 406 3,001
Thereafter 10,595 496 11,091
------- ------ --------
$23,570 $3,328 $ 26,898
======= ======= ========
</Table>
Lease expense under all operating leases was $4,224,000, $1,409,000,
$801,000, and $496,000 for the years ended December 31, 2001 and 2000, the
period from the Partnership's commencement of operations on August 20,
1999 to December 31, 1999, and the Predecessor period from January 1, 1999
to August 19, 1999, respectively.
CONTRACTUAL COMMITMENTS - In connection with the expansion of an existing
mine into adjacent coal reserves and construction of a new mine shaft at
another existing mine, the Partnership has remaining contractual
commitments of approximately $15.3 million at December 31, 2001.
GENERAL LITIGATION - The Partnership is involved in various lawsuits,
claims and regulatory proceedings, including those conducted by the Mine
Safety and Health Administration, incidental to its business. The
Partnership provides for costs related to litigation and regulatory
proceedings, including civil fines issued as part of the outcome of such
proceedings, when a loss is probable and the amount is reasonably
determinable. The Partnership also recorded an expense of $2,675,000
consisting of $675,000 relating to a settlement and $2,000,000
attributable to contingencies associated with third party claims arising
out of its mining operations, which is reflected in "Unusual items" in the
accompanying consolidated and combined statements of income for the year
ended December 31, 2000. In the opinion of management, the outcome of such
matters to the extent not previously provided for or covered under
insurance, will not have a material adverse effect on the Partnership's
business, financial position or results of operations, although management
cannot give any assurance to that effect.
OTHER - During September 2001, the Partnership completed its annual
property insurance renewal. Recent insurance carrier losses worldwide have
created a tightening market reducing available capacity for underwriting
property insurance. As a result, the Partnership, and its affiliates
retained a 12.5% participating interest along with its insurance carriers
in the commercial property program. The aggregate maximum limit in the
commercial property program is $75,000,000 per occurrence, of which, the
Partnership is responsible for a maximum limit of $9,375,000 per
occurrence of the amount covered by property insurance. While the
Partnership does not have a significant history of material insurance
claims, the ultimate amount of claims incurred, if any, are dependent on
future developments. As a result, the Partnership's participation in the
commercial property program could have a material adverse effect on the
Partnership's financial condition and results of operations.
56
On March 14, 2002, PSI Energy Inc. ("PSI") notified Gibson County Coal LLC
that they intended to withhold approximately $644,819 (excluding interest
thereon, if any) in payments due to Gibson County Coal over a three-month
period beginning in March through May 2002. This amount relates to alleged
penalties associated with a contract specification addressing the hardness
of coal provided to PSI. Gibson County Coal and PSI have had on-going
discussions since March 2001 concerning the procedures for and testing of
the coal supplied by the Gibson County mining complex and have been unable
to-date to resolve their differences. Although Gibson County Coal is
pursuing on-going discussions with PSI regarding a potential resolution of
certain issues concerning contractual interpretation, the Partnership
cannot assure that this matter can be resolved without resort to
mediation, arbitration, and/or litigation. Gibson County Coal strongly
disagrees with PSI's position.
16. CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS
The Partnership has significant long-term coal supply agreements, some of
which contain price adjustment provisions designed to reflect changes in
market conditions, labor and other production costs and, when the coal is
sold other than FOB the mine, changes in truck rates. Total revenues to
major customers, including transportation revenues (Note 2), which exceed
ten percent (seven percent for Customer D in 2001) of total revenues are
as follows (in thousands):
<Table>
<Caption>
PARTNERSHIP PREDECESSOR
--------------------------------------- -----------
FROM
COMMENCEMENT FOR THE
YEAR ENDED OF OPERATIONS PERIOD FROM
DECEMBER 31, (ON AUGUST 20, 1999) JANUARY 1, 1999
----------------- TO TO
2001 2000 DECEMBER 31, 1999 AUGUST 19, 1999
---- ------- -------------------- ---------------
Customer A $74,091 $58,498 $16,090 $31,328
Customer B 63,241 67,234 23,104 38,875
Customer C 47,492 61,007 26,993 40,752
Customer D 32,614 38,713 11,926 19,582
</Table>
Trade accounts receivable from these customers totaled approximately $14.9
million at December 31, 2001. The Partnership's bad debt experience has
historically been insignificant, however the Partnership established an
allowance of $763,000 during 2001, due to the Partnership's total credit
exposure to Enron Corp., which filed for bankruptcy protection during
December, 2001. Financial conditions of its customers could result in a
material change to this estimate in future periods. The coal supply
agreements with customers A, B, C and D expire in 2010, 2006, 2001 and
2006, respectively.
57
17. GEOGRAPHIC INFORMATION
Included in the consolidated and combined financial statements are the
following revenues and long-lived assets relating to geographic locations
(in thousands):
<Table>
<Caption>
PARTNERSHIP PREDECESSOR
--------------------------------------------- -----------------
FROM
COMMENCEMENT FOR THE
YEAR ENDED OF OPERATIONS PERIOD FROM
DECEMBER 31, (ON AUGUST 20, 1999) JANUARY 1, 1999
------------ TO TO
2001 2000 DECEMBER 31, 1999 AUGUST 19, 1999
-------- -------- -------------------- ----------------
Revenues:
United States $446,300 $363,469 $134,125 $221,339
Other foreign countries -- -- -- 10,494
-------- -------- -------- --------
$446,300 $363,469 $134,125 $231,833
======== ======== ======== ========
Long-lived assets:
United States $218,877 $210,996 $203,697 $200,057
Other foreign countries -- -- -- --
-------- -------- -------- --------
$218,877 $210,996 $203,697 $200,057
======== ======== ======== ========
</Table>
18. SUPPLEMENTAL CASH FLOW INFORMATION
The Partnership's and Predecessor's supplemental disclosure of cash flow
information and other non-cash investing and financing activities were as
follows (in thousands):
<Table>
<Caption>
PARTNERSHIP PREDECESSOR
-------------------------------------------------------- ---------------
FROM
COMMENCEMENT FOR THE
YEAR ENDED OF OPERATIONS PERIOD FROM
DECEMBER 31, (ON AUGUST 20, 1999) JANUARY 1, 1999
----------------------------- TO TO
2001 2000 DECEMBER 31, 1999 AUGUST 19, 1999
---- ---- -------------------- ---------------
Cash paid for:
Interest $ 18,070 $ 19,043 $ 1,173 $ --
Income taxes paid through
Parent (Note 9) -- -- -- 3,504
Noncash investing and
financing activities:
Debt transferred from
Special GP -- -- 230,000 --
Marketable securities
transferred from Special GP -- -- 15,486 --
</Table>
58
19. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
A summary of the quarterly operating results for the Partnership is as
follows (in thousands, except unit and per unit data):
<Table>
<Caption>
QUARTER ENDED
----------------------------------------------------------------
MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31,
2001(1) 2001 2001 2001
------------ ------------ ------------ ------------
Revenues $ 106,752 $ 110,722 $ 117,894 $ 110,932
Operating income 8,456 4,012 11,943 803
Net income (loss) 12,375 (46) 7,816 (3,045)
Basic net income (loss) per limited partner unit $ 0.79 $ (0.01) $ 0.50 $ (0.19)
Basic net income (loss) per limited partner unit
before accounting change $ 0.28 $ (0.01) $ 0.50 $ (0.19)
Diluted net income (loss) per limited
partner unit $ 0.77 $ (0.01) $ 0.49 $ (0.19)
Diluted net income (loss) per limited
partner unit before accounting change $ 0.28 $ (0.01) $ 0.49 $ (0.19)
Weighted average number of units
outstanding - basic 15,405,311 15,405,311 15,405,311 15,405,311
Weighted average number of units
outstanding - diluted 15,680,594 15,681,411 15,678,013 15,708,968
</Table>
<Table>
<Caption>
QUARTER ENDED
----------------------------------------------------------------
MARCH 31 JUNE 30, SEPTEMBER 30, DECEMBER 31,
2000 2000 2000 (2) 2000
------------ ------------ ------------ ------------
Revenues $ 89,420 $ 86,652 $ 96,459 $ 90,938
Operating income 6,191 5,912 15,669 3,096
Net income (loss) 2,366 2,098 11,560 (443)
Basic net income (loss) per limited partner unit $ 0.15 $ 0.13 $ 0.74 $ (0.03)
Diluted net income (loss) per limited
partner unit $ 0.15 $ 0.13 $ 0.73 $ (0.03)
Weighted average number of units
outstanding - basic 15,405,311 15,405,311 15,405,311 15,405,311
Weighted average number of units
outstanding - diluted 15,550,489 15,550,845 15,552,017 15,553,372
</Table>
(1) The Partnership changed its method of estimating black lung benefits
liability effective January 1, 2001. The cumulative effect of this
change resulted in the reduction of this liability and a corresponding
increase in net income of $7,939,000 for the quarter (Note 3).
(2) The Partnership recorded income of $12.2 million, which is net of
litigation expenses and costs relating to the impairment of certain
transloading facility assets. Additionally, the Partnership recorded
an expense of $2.7 million related to litigation matters settled and
contingencies associated with other litigation matters. The net effect
of these unusual items for the quarter was $9.5 million (Note 4).
Operating income in the above table represents income from operations
before interest expense.
* * * * * *
59
SCHEDULE II
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
YEAR ENDED DECEMBER 31, 2001
- --------------------------------------------------------------------------------
<Table>
<Caption>
BALANCE AT ADDITIONS BALANCE AT
BEGINNING CHARGED TO END OF
OF YEAR INCOME DEDUCTIONS YEAR
---------- ---------- ---------- ----------
(IN THOUSANDS)
2001
Allowance for doubtful accounts $ -- $ 763 $ -- $ 763
====== ====== ====== ======
</Table>
A table for fiscal years ended December 31, 2000 and 1999 has been omitted
because there was no allowance for doubtful accounts.
60
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE MANAGING GENERAL PARTNER
As is commonly the case with publicly-traded limited partnerships, we are
managed and operated by our managing general partner. The following table shows
information for the directors and executive officers of the managing general
partner. Executive officers and directors are elected for one-year terms.
<Table>
<Caption>
NAME AGE POSITION WITH OUR MANAGING GENERAL PARTNER
---- --- ------------------------------------------
Joseph W. Craft III 51 President, Chief Executive Officer and Director
Robert G. Sachse 53 Executive Vice President and Director
Thomas L. Pearson 48 Senior Vice President - Law and Administration,
General Counsel and Secretary
Michael L. Greenwood 46 Senior Vice President - Chief Financial Officer
and Treasurer
Charles R. Wesley 47 Senior Vice President - Operations
Gary J. Rathburn 51 Senior Vice President - Marketing
John J. MacWilliams 46 Director
Preston R. Miller, Jr. 53 Director
John P. Neafsey 62 Director
John H. Robinson 51 Director
Paul R. Tregurtha 66 Director
</Table>
Joseph W. Craft III has worked for us since 1980. Prior to the formation of
Alliance Resource Holdings, Mr. Craft was a Senior Vice President of MAPCO Inc.,
serving as General Counsel and Chief Financial Officer, and since 1986 as
President of MAPCO Coal Inc. Mr. Craft has held his current positions since
August 1996. Prior to working with us, Mr. Craft was an attorney at Falcon Coal
Corporation and Diamond Shamrock Coal Corporation. Mr. Craft has held numerous
industry leadership positions, including past Chairman of the National Coal
Council, a Board and Executive Committee member of the National Mining
Association, and a Director of the Center for Energy and Economic Development.
Mr. Craft holds a Bachelor of Science degree in Accounting and a Juris Doctor
degree from the University of Kentucky. Mr. Craft also is
61
a graduate of the Senior Executive Program of the Alfred P. Sloan School of
Management at Massachusetts Institute of Technology.
Robert G. Sachse joined us as Executive Vice President and Vice Chairman in
August 2000. Prior to working with us, Mr. Sachse was Executive Vice President
and Chief Operating Officer of MAPCO Inc. from 1996 to 1998 when MAPCO Inc.
merged with The Williams Companies, Inc. Mr. Sachse held various positions with
MAPCO Coal Inc. from 1982 to 1991, and was promoted to President of MAPCO
Natural Gas Liquids in 1992. Mr. Sachse holds a Bachelor of Science degree from
Trinity University and a Juris Doctor degree from the University of Tulsa.
Thomas L. Pearson has worked for us since 1989. Prior to the formation of
Alliance Resource Holdings, Mr. Pearson was Assistant General Counsel of MAPCO
Inc. and served as General Counsel and Secretary of MAPCO Coal Inc. from
1989-1996. Mr. Pearson has held his current positions since August 1996. Prior
to working with us, Mr. Pearson was General Counsel and Secretary of McLouth
Steel Products Corporation, one of the largest integrated steel producers in the
United States; and Corporate Counsel of Midland-Ross Corporation, a
multi-national company with numerous international joint venture companies and
projects. Previously, he was an attorney with the law firm Arter & Hadden in
Cleveland, Ohio. Mr. Pearson is or has been active in a number of educational,
charitable and business organizations, including the following: Vice Chairman,
Legal Affairs Committee, National Mining Association; Member, Dean's Committee,
The University of Iowa College of Law; and Contributions Committee, Greater
Cleveland United Way. Mr. Pearson holds a Bachelor of Arts degree in History and
Communications from DePauw University and a Juris Doctor degree from The
University of Iowa.
Michael L. Greenwood has worked for us since 1986. Prior to the formation of
Alliance Resource Holdings, Mr. Greenwood served in various financial management
capacities, including General Manager - Finance of MAPCO Coal Inc., General
Manager of Planning and Financial Analysis, and Manager - Mergers and
Acquisitions of MAPCO Inc. Mr. Greenwood has held his current positions since
August 1996. Prior to working for us, Mr. Greenwood held financial planning and
business development management positions in the energy industry with Davis
Investments, The Williams Companies, Inc. and Penn Central Corporation. Mr.
Greenwood holds a Bachelor of Science degree in Business Administration from
Oklahoma State University and a Master of Business Administration degree from
the University of Tulsa. Mr. Greenwood has also completed executive programs at
Northwestern University, Southern Methodist University and The Center for
Creative Leadership.
Charles R. Wesley has worked for us since 1974. Mr. Wesley joined Webster
County Coal Corporation in 1974 as an engineering co-op student and worked
through the ranks to become General Superintendent. In 1992 he became Vice
President of Operations for Mettiki Coal Corporation. He has held his current
position since August 1996. Mr. Wesley has served the industry as past President
of the West Kentucky Mining Institute and National Mine Rescue Association Post
11. He also served on the board of the Kentucky Mining Institute. Mr. Wesley
holds a Bachelor of Science degree in Mining Engineering from the University of
Kentucky.
Gary J. Rathburn has worked for us since 1980 when he joined MAPCO Coal Inc.
as Manager of Brokerage Coals. Since 1980, Mr. Rathburn has managed all phases
of the marketing group involving transportation and distribution, international
sales and the brokering of coal. He has held his current position since August
1996. Prior to working for us, Mr. Rathburn was employed by Eastern Associated
Coal Corporation in its International Sales and Brokerage groups. Mr. Rathburn
has been active in industry groups such as the Maryland Coal Association, The
North Carolina Coal Institute and the National Mining Association. Mr. Rathburn
was a Director of The National Coal Association and Chairman of the Coal
Exporters Association for several years. Mr. Rathburn holds a Bachelor of Arts
degree in Political Science
62
from the University of Pittsburgh and has participated in industry-related
programs at the World Trade Institute, Princeton University and the Colorado
School of Mines.
John J. MacWilliams has served as a Director since June 1996. Mr.
MacWilliams has been a General Partner of J.P. Morgan Partners, LLC since June
of 2000. Previously he was a General Partner of the Beacon Group, LP (The Beacon
Group) from May 1993 through May 2000. Prior to the formation of The Beacon
Group, Mr. MacWilliams was an Executive Director of Goldman Sachs International
in London, where he was responsible for heading the firm's International
Structured Financing Group. Prior to moving to London, Mr. MacWilliams was a
Vice President in the Investment Banking Division of Goldman, Sachs & Co. in New
York. Prior to joining Goldman Sachs, Mr. MacWilliams was an attorney at Davis
Polk & Wardwell in New York, where he worked on international bank financings,
partnership financings, and mergers and acquisitions. Mr. MacWilliams is also a
director of Campagnie Generale de Geophysique. Mr. MacWilliams holds a Bachelor
of Arts degree from Stanford University, Master of Science degree from
Massachusetts Institute of Technology, and a Juris Doctor degree from Harvard
Law School.
Preston R. Miller, Jr. has served as a Director since June 1996. Mr. Miller
has been a General Partner of J.P. Morgan Partners, LLC since June of 2000.
Previously he was a General Partner of the Beacon Group from June 1993 through
May 2000. Prior to the formation of The Beacon Group, Mr. Miller was employed
for fourteen years by Goldman, Sachs & Co. in New York City, where he was a Vice
President in the Structured Finance Group and had global responsibility for the
coverage of the independent power industry, asset-backed power generation, and
oil and gas financings. Mr. Miller also has a background in credit analysis, and
was head of the revenue bond rating group at Standard & Poor's Corp. prior to
joining Goldman Sachs. Mr. Miller holds a Bachelor of Arts degree from Yale
University and a Master of Public Administration degree from Harvard University.
John P. Neafsey has served as Chairman since June 1996. Mr. Neafsey has
served as President of JN Associates, an investment consulting firm, since
January 1994. Mr. Neafsey served as President and CEO of Greenwich Capital
Markets from 1990 to 1993 and Director since its founding in 1983. In addition,
Mr. Neafsey held numerous other positions during his twenty-three years at The
Sun Company, including: Executive Vice President responsible for Canadian
operations, Sun Coal Company and Helios Capital Corporation; Chief Financial
Officer; and other executive management positions with numerous subsidiary
companies. Mr. Neafsey is or has been active in a number of educational,
charitable and business organizations, including the following: Director, The
West Pharmaceutical Services Company, Longhorn Partners Pipeline Inc. and the
Provident Mutual Life Insurance Company; Trustee Emeritus and Presidential
Counselor, Cornell University; and Overseer of Cornell-Weill Medical Center. Mr.
Neafsey holds Bachelor and Master of Science degrees in Engineering and a Master
of Business Administration degree from Cornell University.
John H. Robinson has served as a Director since December 1999. In April
2000, Mr. Robinson joined Amey, plc, a British support services business, as
Executive Director of its newly-formed Technology Services Division. Mr.
Robinson previously served as Vice Chairman of Black & Veatch, a global
engineer-constructor firm, from January 1997 through March 2000. He was also the
Chairman of Black & Veatch UK Ltd. and was responsible for guiding strategic
development of the firm, having begun his career there in 1973. He is a Director
of Coeur Precious Metals Mining Corporation. Mr. Robinson holds Bachelor and
Master of Science degrees in Engineering from the University of Kansas and has
completed the Owner/President Management Program at the Harvard School of
Business.
Paul R. Tregurtha has served as a Director since December 1999. Mr.
Tregurtha serves as Chairman and Chief Executive Officer of Mormac Marine Group,
Inc. and Chairman of Moran Transportation Company. He is a director and
principal officer of several companies involved in water transportation and
natural resources, including The Interlake Steamship Company and Lakes Shipping
Company. Mr. Tregurtha is also
63
a director of FleetBoston Financial and FPL Group, Inc., the parent of Florida
Power & Light Company. Mr. Tregurtha holds a Bachelor of Science degree in
Mechanical Engineering from Cornell University, where he serves as Trustee
Emeritus, and a Master of Business Administration degree from the Harvard School
of Business.
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Securities and Exchange Act of 1934, as amended,
requires directors, executive officers and persons who beneficially own more
than ten percent of a registered class of our equity securities to file with the
SEC initial reports of ownership and reports or changes in ownership of such
equity securities. Such persons are also required to furnish us with copies of
all Section 16(a) forms that they file. Based solely upon a review of the copies
of the forms furnished to it, or written representations from certain reporting
persons, we believe that during 2001 none of our officers and directors was
delinquent with respect to any of the filing requirements under Rule 16(a).
REIMBURSEMENT OF EXPENSES OF THE MANAGING GENERAL PARTNER AND ITS AFFILIATES
The managing general partner does not receive any management fee or other
compensation in connection with its management of us. However, our managing
general partner and its affiliates, including Alliance Resource Holdings,
perform services for us and are reimbursed by us for all expenses incurred on
our behalf, including the costs of employee, officer and director compensation
and benefits properly allocable to us, as well as all other expenses necessary
or appropriate to the conduct of our business, and properly allocable to us. Our
partnership agreement provides that the managing general partner will determine
the expenses that are allocable to us in any reasonable manner determined by the
managing general partner in its sole discretion.
ITEM 11. EXECUTIVE COMPENSATION
EXECUTIVE COMPENSATION
The following table sets forth certain compensation information for all
executive officers of our managing general partner who received salary and bonus
compensation in excess of $100,000 in 2001 and 2000. We were formed in May 1999
but did not commence business until August 1999. Therefore 1999 compensation
information is for the period from commencement of our operations (on August 20,
1999) to December 31, 1999.
64
SUMMARY COMPENSATION TABLE
<Table>
<Caption>
ANNUAL COMPENSATION LONG TERM
----------------------------------- COMPENSATION
OTHER ANNUAL RESTRICTED ALL OTHER
BONUS COMPENSATION STOCK AWARDS COMPENSATION
NAME AND PRINCIPAL POSITION YEAR SALARY (1) (2) (3) (4)
- --------------------------- ---- -------- ------ ------------ ------------ ------------
Joseph W. Craft III, 2001 $314,700 $130,000 $5,250 $781,875 $50,562
President, Chief Executive Officer 2000 292,950 94,200 -- 678,150 63,695
and Director 1999 106,313 70,040 700 -- 21,495
Thomas L. Pearson, 2001 192,000 63,000 1,167 140,738 31,914
Senior Vice President-Law and 2000 177,000 45,000 1,550 122,067 43,856
Administration, General Counsel and 1999 64,234 28,306 -- -- 12,385
Secretary
Michael L. Greenwood, 2001 162,650 50,000 -- 140,738 24,531
Senior Vice President-Chief 2000 151,400 45,000 -- 122,067 26,009
Financial Officer and Treasurer 1999 54,944 28,306 -- -- 7,972
Charles R. Wesley, 2001 202,000 65,000 925 156,375 33,286
Senior Vice President-Operations 2000 187,000 47,600 1,500 135,630 32,802
1999 67,863 35,565 -- -- 12,383
Gary J. Rathburn, 2001 167,000 70,000 3,000 140,738 26,702
Senior Vice President-Marketing 2000 152,000 45,000 1,500 122,067 28,008
1999 55,161 28,306 -- -- 9,407
</Table>
(1) Amounts awarded under the Short-Term Incentive Plan. See "Short-Term
Incentive Plan" below.
(2) Amounts reimbursed for income tax preparation and financial planning
services.
(3) Awards under the Long-Term Incentive Plan. The amount represents the value
of restricted units at the date of issuance. The total number of restricted
units and their aggregate market value as of December 31, 2001, were: Mr.
Craft, 95,000 units valued at $2,574,500; Mr. Pearson, 17,100 units valued
at $463,410; Mr. Greenwood, 17,100 units valued at $463,410; Mr. Wesley,
19,000 units valued at $514,900; Mr. Rathburn, 17,100 units valued at
$463,410. Units granted under the Long-Term Incentive Plan do not vest until
the end of the subordination period, which will generally not end before
September 30, 2004. See "Long-Term Incentive Plan" below.
(4) Amounts represent (a) the managing general partner's matching contributions
to its 401(k) Plan and (b) the managing general partner's contribution its
Supplemental Executive Retirement Plan.
COMPENSATION OF DIRECTORS
Under the managing general partner's Directors Compensation Program
(Directors Plan) each non-employee Director is paid an annual retainer of
$21,500. The annual retainer is payable in common units to be paid on a
quarterly basis in advance determined by dividing the pro rata annual retainer
payable on such date by the closing sales price per common unit averaged over
the immediately preceding ten trading days. Each non-employee director may elect
to defer all or a portion of his or her compensation under the Deferred
Compensation Plan for Directors.
In addition, each non-employee director participates in the Long-Term
Incentive Plan. The directors restricted units vest in accordance with the
procedure described below. Messrs. MacWilliams and Miller have declined
compensation under the Directors and Long-Term Incentive Plans.
65
Mr. Sachse has a consulting agreement with the managing general partner for
a term of three years, effective August 14, 2000. The consulting agreement
provides that Mr. Sachse will serve as Executive Vice President of the managing
general partner and devote his services on a part-time basis. In addition to
compensation received under the Directors Plan and Long-Term Incentive Plan
described above, Mr. Sachse is entitled to receive an annual fee of $150,000
payable in arrears monthly. Mr. Sachse also is entitled to receive quarterly
payments in arrears of $7,500 less the market value of 250 common units
calculated by the closing sales price per common unit averaged over the
immediately preceding ten trading days. A copy of the consulting agreement with
Mr. Sachse is an exhibit hereto.
EMPLOYMENT AGREEMENTS
The executive officers of the managing general partner and some additional
members of senior management will enter into employment agreements among the
executive officer or member of senior management, on the one hand, and the
managing general partner on the other. We reimburse the managing general partner
for the compensation and benefits costs under these agreements. This summary of
the terms of the employment agreements does not purport to be complete, but
outlines their material provisions. A form of the agreements with each of
Messrs. Craft, Pearson, Greenwood, Wesley and Rathburn is an exhibit hereto.
Each of the employment agreements had an initial term that expired on
December 31, 2001, but automatically extend for successive one-year terms unless
either party gives 12 months prior notice to the other party. The employment
agreements provide for a base salary, subject to review annually, of $321,950,
$192,000, $166,400, $207,000 and $167,000 for Messrs. Craft, Pearson, Greenwood,
Wesley and Rathburn, respectively. The employment agreements provide for
continued salary payments, bonus and benefits for a period of three years, in
the case of Mr. Craft, and 18 months, in the case of Messrs. Pearson, Greenwood,
Wesley and Rathburn, following termination of employment, except in the case of
a change of control of the managing general partner.
In the case of a "change of control" as defined in the agreements, in lieu
of the continuation of salary and benefits, that executive will be entitled to a
lump sum payment in an amount equal to three times base salary plus bonus, in
the case of Mr. Craft, and two times base salary plus bonus in the case of
Messrs. Pearson, Greenwood, Wesley and Rathburn. Unless the executive waives his
or her right to the continuation of base salary and bonus, the agreements
provide for a noncompetition period of 18 months. The noncompetition period does
not apply after a change in control. Amounts paid by the managing general
partner pursuant to the employment agreements will be reimbursed by us.
The executives who are subject to employment agreements also participate in
the Short- and Long-Term Incentive Plans of the managing general partner
described below along with other members of management. They also are entitled
to participate in the other employee benefit plans and programs that the
managing general partner provides for its employees.
LONG-TERM INCENTIVE PLAN
Effective January 1, 2000, the managing general partner adopted the
Long-Term Incentive Plan (LTIP) for certain employees and directors of the
managing general partner and its affiliates who perform services for us. The
summary of the LTIP contained herein does not purport to be complete, but
outlines its material provisions.
The LTIP is administered by the compensation committee of the managing
general partner's Board of Directors. Annual grant levels for designated
participants are recommended by the President and CEO of the managing general
partner, subject to the review and approval of the compensation committee. We
will reimburse the managing general partner for all costs incurred pursuant to
the programs described below.
66
Grants are made either of restricted units, which are "phantom" units that
entitle the grantee to receive a common unit or an equivalent amount of cash
upon the vesting of a phantom unit, or options to purchase common units. Common
units to be delivered upon the vesting of restricted units or to be issued upon
exercise of a unit option will be acquired by the managing general partner in
the open market at a price equal to the then prevailing price, or directly from
Alliance Resource Holdings or any other third party, including units newly
issued by us, or use units already owned by the managing general partner, or any
combination of the foregoing. The managing general partner is entitled to
reimbursement by us for the cost incurred in acquiring these common units or in
paying cash in lieu of common units upon vesting of the restricted units. If we
issue new common units upon payment of the restricted units or unit options
instead of purchasing them, the total number of common units outstanding will
increase. The aggregate number of units reserved for issuance under the LTIP is
600,000. Effective January 1, 2000 and 2001, the compensation committee approved
initial grants of 142,100 and 129,200 restricted units, vesting at the end of
the subordination period, which generally will not end before September 30,
2004. During 2001, 8,500 units were forfeited. Effective as of January 1, 2002,
the compensation committee approved additional grants of 131,885 restricted
units, which vest at the end of the subordination period.
Restricted Units. Restricted units will vest over a period of time as
determined by the compensation committee. However, if a grantee's employment is
terminated for any reason prior to the vesting of any restricted units, those
restricted units will be automatically forfeited, unless the compensation
committee, in its sole discretion, provides otherwise. In addition, vested
restricted units will not be payable before the end of the subordination period,
which will generally not end before September 30, 2004.
The issuance of the common units pursuant to the restricted unit plan is
intended to serve as a means of incentive compensation for performance and not
primarily as an opportunity to participate in the equity appreciation in respect
of the common units. Therefore, no consideration will be payable by the plan
participants upon receipt of the common units, and we receive no remuneration
for these units. Following the subordination period, the compensation committee,
in it discretion, may grant distribution equivalent rights with respect to
restricted units.
Unit Options. We have not made any grants of unit options. The compensation
committee may, in the future, determine to make unit option grants to employees
and directors containing the specific terms that they determine. When granted,
unit options will have an exercise price set by the compensation committee which
may be above, below or equal to the fair market value of a common unit on the
date of grant. Unit options, if any, granted during the subordination period
will become exercisable upon, and in the same proportions as, the conversion of
the subordinated units to common units, or at a later date as determined by the
compensation committee in its sole discretion.
The managing general partner's Board of Directors, in its discretion, may
terminate the LTIP at any time with respect to any common units for which a
grant has not previously been made. The managing general partner's Board of
Directors will also have the right to alter or amend the LTIP or any part of it
from time to time, subject to unitholder approval as required by the exchange
upon which the common units may be listed at that time; provided, however, that
no change in any outstanding grant may be made that would materially impair the
rights of the participant without the consent of the affected participant. In
addition, the managing general partner may, in its discretion, establish such
additional compensation and incentive arrangements as it deems appropriate to
motivate and reward its employees. The managing general partner is reimbursed
for all compensation expenses incurred on our behalf.
SHORT-TERM INCENTIVE PLAN
Effective January 1, 1999, the managing general partner adopted a Short-Term
Incentive Plan (STIP) for management and other salaried employees. The STIP is
designed to enhance the financial performance by
67
rewarding management and our salaried employees and those of the managing
general partner with cash awards for our achieving an annual financial
performance objective. The annual performance objective for each year is
recommended by the President and CEO of the managing general partner and
approved by the compensation committee of its Board of Directors prior to
January 1 of that year. The STIP is administered by the compensation committee.
Individual participants and payments each year are determined by and in the
discretion of the compensation committee, and the managing general partner is
able to amend the plan at any time. The managing general partner is entitled to
reimbursement by us for the costs incurred under the STIP.
SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN
Effective January 1, 1997, the managing general partner adopted a
supplemental executive retirement plan (SERP) for certain officers and key
employees. The purpose of the SERP is to enhance our ability to retain specific
officers and key employees, by providing them with the deferred compensation
benefits contained in the SERP. The intent of the SERP is to provide each
participant with retirement benefits that are comparable in value to those of
similar retirement programs administered by other companies, as well as to align
each participant's supplemental benefits under the SERP with the interests of
the our unitholders. All allocations made to participants under the SERP are
made in the form of phantom units. The SERP is administered by the compensation
committee. The managing general partner is able to amend or terminate the plan
at any time. The managing general partner is entitled to reimbursement by us for
its costs incurred under the SERP.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth certain information as of March 1, 2002,
regarding the beneficial ownership of common and subordinated units held by (a)
each person known by the managing general partner to be the beneficial owner of
5% or more of the common and subordinated units, (b) each director and executive
officer of the managing general partner and (c) all directors and executive
officers of the managing general partner as a group. The managing general
partner is owned by funds affiliated with The Beacon Group and members of
management. The special general partner is a wholly-owned subsidiary of Alliance
Resource Holdings. The address of Alliance Resource Holdings, the managing
general partner and the special general partner is 1717 South Boulder Avenue,
Tulsa, Oklahoma 74119.
<Table>
<Caption>
PERCENTAGE OF PERCENTAGE OF PERCENTAGE
COMMON COMMON SUBORDINATED SUBORDINATED OF TOTAL
UNITS UNITS UNITS UNITS UNITS
BENEFICIALLY BENEFICIALLY BENEFICIALLY BENEFICIALLY BENEFICIALLY
NAME OF BENEFICIAL OWNER OWNED(8) OWNED OWNED OWNED OWNED
- ------------------------ ------------ ------------- ------------ ------------- ------------
Alliance Resource GP, LLC(2) 1,232,780 13.72% 6,422,531 100% 49.7%
Alliance Resource Management GP, LLC(3) 164,000 1.83% -- -- 1.1%
Joseph W. Craft III(1)(7) 85,468 * -- -- *
Robert G. Sachse(1) 2,998 * -- -- *
Thomas L. Pearson(1) 15,897 * -- -- *
Michael L. Greenwood(1) 33,204 * -- -- *
Charles R. Wesley(1) 25,479 * -- -- *
Gary J. Rathburn(1) 13,721 * -- -- *
John J. MacWilliams(4) 1,396,780 15.55% 6,422,531 100% 50.8%
Preston R. Miller, Jr.(4) 1,396,780 15.55% 6,422,531 100% 50.8%
John P. Neafsey(1) 13,204 * -- -- *
John H. Robinson(5) 3,421 * -- -- *
Paul R. Tregurtha(6) 3,421 * -- -- *
All directors and executive officers as
a group (11 persons) 1,593,593 17.74% 6,422,531 100% 52.0%
</Table>
* Less than one percent.
68
(1) The address of Messrs. Craft, Sachse, Pearson, Greenwood, Wesley, Rathburn
and Neafsey is 1717 South Boulder Avenue, Tulsa, Oklahoma 74119.
(2) Alliance Resource Holdings may be deemed to beneficially own the common
units and the subordinated units held by the special general partner, as a
result of Alliance Resource Holdings' ownership of all of the membership
interests in the special general partner. MPC Partners, LP (MPC Partners),
an affiliate of the Beacon Group, may also be deemed to beneficially own the
common units and the subordinated units held by the special general partner
as a result of MPC Partners' ownership of 86.2% of Alliance Resource
Holding's outstanding common stock.
(3) The managing general partner is an affiliate of the special general partner,
and as a consequence the special general partner may be deemed to
beneficially own the common units held by the managing general partner.
(4) Messrs. MacWilliams and Miller may also be deemed to share beneficial
ownership of the common units and the subordinated units held by the special
general partner and the managing general partner by virtue of their status
as partners of The Beacon Group, an affiliate of MPC Partners. Messrs.
MacWilliams and Miller disclaim beneficial ownership of the common and
subordinated units held by the special general partner and the managing
general partner. The address of Messrs. MacWilliams and Miller is Beacon
Group Energy Funds, 222 Berkeley St., 17th floor, Boston, Massachusetts
10020.
(5) The address of Mr. Robinson is 24 Hanover Square, London, England W1S1JD.
(6) The address of Mr. Tregurtha is 3 Landmark Square, Stamford, Connecticut
06901.
(7) Mr. Craft may also be deemed to share beneficial ownership of an additional
13,500 common units held by a private foundation for which he serves as a
trustee. Mr. Craft disclaims beneficial ownership of the common units held
by the private foundation.
(8) The amounts set forth do not include any restricted units granted under the
LTIP.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The special general partner owns 1,232,780 common units and 6,422,531
subordinated units representing an aggregate 48.7% limited partner interest in
us. In addition, the general partners own, on a combined basis, an aggregate 2%
general partner interest in us, the intermediate partnership and the
subsidiaries. The managing general partner's ability, as managing general
partner, to manage and operate us and its ownership of 164,000 common units
together with the special general partner's ownership of 1,232,780 common units
and 6,422,531 subordinated units, effectively gives the general partners the
ability to veto some of our actions and to control our management.
UNIT PURCHASE PROGRAM BY THE MANAGING GENERAL PARTNER
The managing general partner authorized a common unit purchase program in
November 1999 for the purchase of up to the greater of one million common units
or $15 million of common units. As of December 31, 2001, the managing general
partner has purchased 164,000 common units. The common units purchased by the
managing general partner retain their rights to receive quarterly distributions
of available cash.
TRANSACTIONS BETWEEN THE PARTNERSHIP, SPECIAL GENERAL PARTNER AND ALLIANCE
RESOURCE HOLDINGS
During September 2000, the special general partner acquired coal reserves
and the right to acquire additional coal reserves (a) contiguous to our Dotiki
mine (Providence No. 3 Reserves) and (b) contiguous to Hopkins County Coal (Elk
Creek Reserves). Such coal reserves and the rights to acquire additional coal
69
reserves were transferred to SGP Land, LLC (SGP Land), a newly formed
wholly-owned subsidiary of the special general partner.
Concurrent with such coal reserve acquisitions, the special general partner,
through affiliates, was negotiating for the purchase of (a) the capital stock of
Roberts Bros. Coal Co., Inc., Warrior Coal Mining Company, and Warrior Coal
Corporation, and (b) the related coal reserves (Warrior Reserves) owned by
Cardinal Trust, LLC (collectively, the Warrior Group). The Warrior Group's
operating assets are located adjacent to the Providence No. 3 Reserves and these
operating assets, excluding the Warrior Reserves, were purchased by a newly
formed affiliate of the special general partner, Warrior Coal, LLC (Warrior
Coal) in January 2001. SGP Land acquired the Warrior Reserves, which are located
between the Providence No. 3 Reserves and Hopkins County Coal.
SGP Land entered into a mineral lease and sublease with Webster County Coal
for a portion of each of the Providence No. 3 Reserves and the Warrior Reserves,
and granted an option to Hopkins County Coal to lease and/or sublease the Elk
Creek Reserves. Under the terms of the Webster County Coal lease and sublease,
Webster County Coal has an annual minimum royalty obligation of $2.7 million,
payable in advance, from 2000 to 2013, or until $37.8 million of cumulative
annual minimum and/or earned royalty payments have been paid. Webster County
Coal paid an annual minimum royalty of $2.7 million in 2001 and 2000. Under the
terms of the Hopkins County Coal option to lease and sub-lease, Hopkins County
Coal paid option fees of $684,000 and $645,000 during 2001 and 2000,
respectively. The anticipated annual minimum royalty obligation is $684,000
payable in advance, from 2002 to 2009.
During 2000, Alliance Resource Holdings and our managing general partner
were approached with the opportunity to purchase certain mining assets of
Warrior Coal located adjacent to our western Kentucky operations. Warrior Coal
is an underground mining complex that utilizes continuous mining units employing
room and pillar mining techniques. Warrior Coal produces approximately 1.5
million tons per year, controls reserves that will provide for a minimum of ten
years of mining, and has the possibility of controlling additional reserves in
the future.
In accordance with the right of first refusal provision in the omnibus
agreement between Alliance Resource Holdings and our managing general partner,
Alliance Resource Holdings offered the managing general partner the opportunity
to purchase Warrior Coal. At the time, the managing general partner declined the
opportunity to purchase Warrior Coal as we had previously committed to major
capital expenditures at two existing operations. As a condition to not
exercising our right of first refusal, our managing general partner requested
that Alliance Resource Holdings enter into a put and call arrangement for
Warrior Coal. After further discussions, we and Alliance Resource Holdings, with
the approval of the conflicts committee of our managing general partner, entered
into an Amended and Restated Put and Call Option Agreement ("Put/Call
Agreement") in January 2001. Concurrently, Alliance Resource Holdings, through
an indirect wholly-owned subsidiary, acquired Warrior Coal in January 2001 for
$10 million.
The Put/Call Agreement preserved an opportunity for us to acquire Warrior
Coal during a specified time period in the future, although at a price
significantly greater than the price paid by Alliance Resource Holdings. Under
the terms of the Put/Call Agreement, Alliance Resource Holdings can require us
to purchase Warrior Coal during the period from January 2 to January 11, 2003.
The put option price is approximately $12.5 million. We can also require
Alliance Resource Holdings to sell Warrior Coal to us during the period from
April 12, 2003 to December 31, 2006. The call option price ranges between $13.6
million and $22.2 million depending on when the call option is exercised.
The option provisions of the Put/Call Agreement are subject to certain
conditions, among others, including (a) the non-occurrence of a material adverse
change in the business and financial condition of Warrior Coal, (b) the
prohibition of any dividends or other distributions to Warrior Coal's
shareholders, (c) the maintenance of Warrior Coal's assets in good working
condition, (d) the prohibition on the sale of any equity interest in Warrior
Coal except for the options contained in the Put/Call Agreement, and (e) the
prohibition on the sale or transfer of Warrior Coal's assets except those made
in the ordinary course of its business.
The Put/Call Agreement option prices reflect negotiated sale and purchase
amounts that both parties determined would allow each party to satisfy
acceptable minimum investment
70
returns in the event either the put or call options are exercised. We have not
made a final determination concerning the potential exercise of our call option
and have not been advised by Alliance Resource Holdings concerning Alliance
Resource Holdings' intention to exercise its put option. We have developed
financial projections for Warrior Coal based on due diligence procedures we
customarily perform when considering the acquisition of a coal mine. The
assumptions underlying the financial projections made by us for Warrior Coal
include (a) annual production levels ranging from 1.5 million to 1.8 million
tons, (b) coal prices at or below current coal prices and (c) a discount rate
of 12 percent. Based on these financial projections, at this time, we believe
that the fair value of Warrior Coal is equal to or greater than the put option
exercise price.
We provide management and administrative services to Warrior Coal and SGP
Land under an administrative service agreement. Under this agreement, we
recognized approximately $1.0 million as a reduction to our general and
administrative expenses. Accounts receivable from Warrior Coal of $108,000
offsets a portion of the due to affiliates at December 31, 2001. This
transaction was reviewed and approved by the conflicts committee.
During 2001, we entered into an agreement with Warrior Coal to perform
certain reclamation procedures for us. The total estimated cost of the
reclamation procedures covered by this agreement is $475,000 of which
approximately $315,000 remains to be expended in 2002 for the expected
completion of the reclamation procedures by Warrior Coal.
During 2001, we made coal purchases of approximately $3.1 million from
Warrior Coal. Accounts payable to Warrior Coal were $1.9 million and are
included in the amount due to affiliates in our consolidated balance sheet as of
December 31, 2001. During December 2001, we entered into coal supply agreements
with Warrior Coal for the purchase of up to 1.8 million tons for the year ending
December 31, 2002. This transaction was reviewed and approved by the Conflicts
Committee.
We have a noncancelable operating lease arrangement with the special general
partner for a coal preparation plant and ancillary facilities at Gibson County
Coal. This transaction was reviewed and approved by the Conflicts Committee.
Under the terms of the lease, we began making monthly payments commencing
January 1, 2001, of approximately $216,000, which will continue through January
2010.
During 2001, SGP Land, as successor-in-interest to an unaffiliated third
party, entered into an amended mineral lease with MC Mining, LLC (MC Mining).
Under the terms of the of the lease, MC Mining pays an annual minimum royalty
obligation of $300,000 until $6.0 million of cumulative annual minimum and/or
earned royalty payments have been paid. This transaction was reviewed and
approved by the Conflicts Committee. MC Mining paid royalties of $705,000 for
the year ended December 31, 2001.
During 2001, we entered into agreements with three banks to provide letters
of credit in an aggregate amount of $25.0 million to maintain surety bonds to
secure its obligations for reclamation liabilities and workers' compensation
benefits. At December 31, 2001 we had $15.0 million in letters of credit
outstanding. The special general partner guarantees these letters of credit, and
as a result we have agreed to compensate the Special GP for a fee equal to 0.30%
per annum of the face amount of the letters of credit outstanding. We paid
approximately $8,800 in guarantee fees to the Special GP for the year ended
December 31, 2001. This transaction was reviewed and approved by the Conflicts
Committee.
We may enter into similar arrangements in the future to support the
acquisition of additional reserve properties or to develop facilities at our
existing mining complexes.
OTHER RELATED PARTY TRANSACTIONS
J.P. Morgan Chase & Co. (Chase) is paying agent, co-administrative agent and
a lender under our Credit Facility. In 2001, we made interest and principal
payments and principle to Chase on outstanding borrowings and paid Chase
customary fees for their other services. We expect that these relationships will
continue in 2002. The Beacon Group is an affiliate of Chase. Messrs. MacWilliams
and Miller are General Partners of the Beacon Group and Directors of the
managing general partner.
71
FleetBoston is a lender under our Credit Facility. In 2001, we made interest
and principal payments to FleetBoston on outstanding borrowings. We expect this
relationship to continue in 2002. Mr. Tregurtha, director of the managing
general partner, also serves as a director for FleetBoston.
OMNIBUS AGREEMENT
Concurrent with the closing of our initial public offering, we entered into
an omnibus agreement with Alliance Resource Holdings and the general partners,
which governs potential competition among us and the other parties to this
agreement. Alliance Resource Holdings agreed, and caused its controlled
affiliates to agree, for so long as management and funds managed by The Beacon
Group and its affiliates control the managing general partner, not to engage in
the business of mining, marketing or transporting coal in the U.S. unless it
first offers us the opportunity to engage in a potential activity or acquire a
potential business, and the Board of Directors of the managing general partner,
with the concurrence of its conflicts committee, elects to cause us not to
pursue such opportunity or acquisition. In addition, Alliance Resource Holdings
has the ability to purchase businesses, the majority value of which is not
mining, marketing or transporting coal, provided Alliance Resource Holdings
offers us the opportunity to purchase the coal assets following their
acquisition. The restriction does not apply to the assets retained and business
conducted by Alliance Resource Holdings at the closing of our initial public
offering. Except as provided above, Alliance Resource Holdings and its
controlled affiliates are prohibited from engaging in activities in which they
compete directly with us. In addition, The Beacon Group, and the funds it
manages, are prohibited from owning or engaging in businesses which compete with
us. In addition to its non-competition provisions, this agreement contains
provisions which indemnify us against liabilities associated with certain assets
and businesses of Alliance Resource Holdings which were disposed of or
liquidated prior to consummating our initial public offering.
72
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a)(1) Financial Statements.
The response to this portion of Item 14 is submitted as a separate
section herein under Part II, Item 8. - Financial Statements and
Supplementary Data.
(a)(2) Financial Statement Schedules.
Schedule II - Valuation and Qualifying Accounts - Year ended
December 31, 2001, is set forth under Part II Item 8. - Financial
Statements and Supplementary Data. All other schedules are omitted
because they are not applicable or the information is shown in the
financial statements or notes thereto.
(a)(3) Index of Exhibits.
3.1 Amended and Restated Agreement of Limited Partnership of
Alliance Resource Partners, L.P. (Incorporated by reference
to Exhibit 3.1 of the Registrant's Annual Report on Form
10-K for the year ended December 31, 1999, File No.
000-26823).
3.2 Amended and Restated Agreement of Limited Partnership of
Alliance Resource Operating Partners, L.P. (Incorporated by
reference to Exhibit 3.2 of the Registrant's Annual Report
on Form 10-K for the year ended December 31, 1999, File No.
000-26823).
3.3 Certificate of Limited Partnership of Alliance Resource
Partners, L.P. (Incorporated by reference to Exhibit 3.6 of
the Registrant's Registration Statement on Form S-1 filed
with the Commission on May 20, 1999 (Reg. No. 333-78845)).
3.4 Certificate of Limited Partnership of Alliance Resource
Operating Partners, L.P. (Incorporated by reference to
Exhibit 3.8 of the Registrant's Registration Statement on
Form S-1/A filed with the Commission on July 20, 1999 (Reg.
No. 333-78845)).
3.5 Certificate of Formation of Alliance Resource Management
GP, LLC (Incorporated by reference to Exhibit 3.7 of the
Registrant's Registration Statement on Form S-1/A filed
with the Commission on July 23, 1999 (Reg. No. 333-78845)).
3.6 Amended and Restated Operating Agreement of Alliance
Resource Management GP, LLC (Incorporated by reference to
Exhibit 3.4 of the Registrant's Registration Statement on
Form S-3 filed with the Commission on April 1, 2002 (Reg.
No. 333-85282)).
3.7 Amendment No. 1 to Amended and Restated Operating Agreement
of Alliance Resource Management GP, LLC (Incorporated by
reference to Exhibit 3.5 of the Registrant's Registration
Statement on Form S-3 filed with the Commission on April
1, 2002 (Reg. No. 333-85282)).
73
3.8 Amendment No. 2 to Amended and Restated Operating Agreement
of Alliance Resource Management GP, LLC (Incorporated by
reference to Exhibit 3.6 of the Registrant's Registration
Statement on Form S-3 filed with the Commission on April 1,
2002 (Reg. No. 333-85282)).
4.1 Form of Common Unit Certificate (Included as Exhibit A to
the Amended and Restated Agreement of Limited Partnership
of Alliance Resource Partners, L.P.)
10.1 Credit Agreement, dated as of August 16, 1999, among
Alliance Resource GP, LLC, JP Morgan Chase Bank (formerly
The Chase Manhattan Bank) (as paying agent), Deutsche Bank
AG, New York Branch (as documentation agent), Citicorp USA,
Inc. and JP Morgan Chase Bank (as co-administrative agents)
and the lenders named therein. (Incorporated by reference
to Exhibit 10.1 of the Registrant's Annual Report on Form
10-K for the year ended December 31, 1999, File No.
000-26823).
*10.2 Amendment No. 1 dated December 7, 2001, to the Credit
Agreement, dated as of August 16, 1999, among Alliance
Resource GP, LLC, JP Morgan Chase Bank (formerly The Chase
Manhattan Bank) (as paying agent), Deutsche Bank AG, New
York Branch (as documentation agent), Citicorp USA, Inc.
and JP Morgan Chase Bank (as co-administrative agents) and
the lenders named therein.
10.3 Note Purchase Agreement, dated as of August 16, 1999, among
Alliance Resource GP, LLC and the purchasers named therein.
(Incorporated by reference to Exhibit 10.20 of the
Registrant's Annual Report on Form 10-K for the year ended
December 31, 1999, File No. 000-26823).
10.4 Letter of Credit Facility Agreement dated as of June 29,
2001, between Alliance Resource Partners, L.P. and Bank of
Oklahoma, National Association. (Incorporated by reference
to Exhibit 10.20 of the Registrant's Quarterly Report on
Form 10-Q for the quarter ended September 30, 2001, File
No. 000-26823).
10.5 Promissory Note Agreement dated as of July 31, 2001,
between Alliance Resource Partners, L.P. and Bank of
Oklahoma, N. A. (Incorporated by reference to Exhibit 10.21
of the Registrant's Quarterly Report on Form 10-Q for the
quarter ended September 30, 2001, File No. 000-26823).
10.6 Guarantee Agreement, dated as of July 31, 2001, between
Alliance Resource GP, LLC and Bank of Oklahoma, N.A.
(Incorporated by reference to Exhibit 10.22 of the
Registrant's Quarterly Report on Form 10-Q for the quarter
ended September 30, 2001, File No. 000-26823).
10.7 Letter of Credit Facility Agreement dated as of August 30,
2001, between Alliance Resource Partners, L.P. and Fifth
Third Bank. (Incorporated by reference to Exhibit 10.23 of
the Registrant's Quarterly Report on Form 10-Q for the
quarter ended September 30, 2001, File No. 000-26823).
10.8 Guarantee Agreement, dated as of August 30, 2001, between
Alliance Resource GP, LLC and Firth Third Bank.
(Incorporated by reference to Exhibit 10.24 of the
Registrant's Quarterly Report on Form 10-Q for the quarter
ended September 30, 2001, File No. 000-26823).
74
10.9 Letter of Credit Facility Agreement dated as of October 2,
2001, between Alliance Resource Partners, L.P. and Bank of
the Lakes, National Association. (Incorporated by reference
to Exhibit 10.25 of the Registrant's Quarterly Report on
Form 10-Q for the quarter ended September 30, 2001, File
No. 000-26823).
10.10 Promissory Note Agreement dated as of October 2, 2001,
between Alliance Resource Partners, L.P. and Bank of the
Lakes, N.A. (Incorporated by reference to Exhibit 10.26 of
the Registrant's Quarterly Report on Form 10-Q for the
quarter ended September 30, 2001, File No. 000-26823).
10.11 Guarantee Agreement, dated as of October 2, 2001, between
Alliance Resource GP, LLC and Bank of the Lakes, N.A.
(Incorporated by reference to Exhibit 10.27 of the
Registrant's Quarterly Report on Form 10-Q for the quarter
ended September 30, 2001, File No. 000-26823).
10.12 Guaranty Fee Agreement dated as of July 31, 2001, between
Alliance Resource Partners, L.P. and Alliance Resource GP,
LLC. (Incorporated by reference to Exhibit 10.28 of the
Registrant's Quarterly Report on Form 10-Q for the quarter
ended September 30, 2001, File No. 000-26823).
10.13 Contribution and Assumption Agreement, dated August 16,
1999, among Alliance Resource Holdings, Inc., Alliance
Resource Management GP, LLC, Alliance Resource GP, LLC,
Alliance Resource Partners, L.P., Alliance Resource
Operating Partners, L.P. and the other parties named
therein. (Incorporated by reference to Exhibit 10.3 of the
Registrant's Annual Report on Form 10-K for the year ended
December 31, 1999, File No. 000-26823).
10.14 Omnibus Agreement, dated August 16, 1999, among Alliance
Resource Holdings, Inc., Alliance Resource Management GP,
LLC, Alliance Resource GP, LLC and Alliance Resource
Partners, L.P. (Incorporated by reference to Exhibit 10.4
of the Registrant's Annual Report on Form 10-K for the year
ended December 31, 1999, File No. 000-26823).
10.15 Alliance Resource Management GP, LLC 2000 Long-Term
Incentive Plan (as amended). (Incorporated by reference to
Exhibit 10.11 of the Registrant's Annual Report on Form
10-K for the year ended December 31, 1999, File No.
000-26823).
10.16 Alliance Resource Management GP, LLC Short-Term Incentive
Plan. (Incorporated by reference to Exhibit 10.12 of the
Registrant's Annual Report on Form 10-K for the year ended
December 31, 1999, File No. 000-26823).
10.17 Alliance Resource Management GP, LLC Supplemental Executive
Retirement Plan. (Incorporated by reference to Exhibit 99.2
of the Registrant's Registration Statement on Form S-8
filed with the Commission on April 1, 2002 (Reg. No.
333-85258)).
10.18 Alliance Resource Management GP, LLC Deferred Compensation
Plan for Directors. (Incorporated by reference to Exhibit
99.3 of the Registrant's Registration Statement on Form S-8
filed with the Commission on April 1, 2002 (Reg.
No. 333-85258)).
75
10.19 Restated and Amended Coal Supply Agreement, dated February
1, 1986, among Seminole Electric Cooperative, Inc., Webster
County Coal Corporation and White County Coal Corporation.
(Incorporated by reference to Exhibit 10.9 of the
Registrant's Registration Statement on Form S-1/A filed
with the Commission on July 20, 1999 (Reg. No. 333-78845)).
10.20 Amendment No. 1 to the Restated and Amended Coal Supply
Agreement effective April 1, 1996, between MAPCO Coal Inc.,
Webster County Coal Corporation, White County Coal
Corporation, and Seminole Electric Cooperative, Inc.
(Incorporated by reference to Exhibit 10.14 of the
Registrant's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2000, File No. 000-26823).
10.21 Interim Coal Supply Agreement effective May 1, 2000,
between Alliance Coal, LLC and Seminole Electric
Cooperative, Inc. (Incorporated by reference to Exhibit
10.15 of the Registrant's Quarterly Report on Form 10-Q for
the quarter ended June 30, 2000, File No. 000-26823).
10.22 Contract for Purchase and Sale of Coal, dated January 31,
1995, between Tennessee Valley Authority and Webster County
Coal Corporation. (Incorporated by reference to Exhibit
10.10 of the Registrant's Registration Statement on Form
S-1/A filed with the Commission on July 20, 1999 (Reg. No.
333-78845)).
10.23 Assignment/Transfer Agreement between Andalex Resources,
Inc., Hopkins County Coal LLC, Webster County Coal
Corporation and Tennessee Valley Authority, dated January
23, 1998, with Exhibit A - Contract for Purchase and Sale
of Coal between Tennessee Valley Authority and Andalex
Resources, Inc., dated January 31, 1995. (Incorporated by
reference to Exhibit 10.11 of the Registrant's Registration
Statement on Form S-1/A filed with the Commission on July
20, 1999 (Reg. No. 333-78845)).
10.24 Contract for Purchase and Sale of Coal, dated July 7, 1998,
between Tennessee Valley Authority and Webster County Coal
Corporation. (Incorporated by reference to Exhibit 10.12 of
the Registrant's Registration Statement on Form S-1/A filed
with the Commission on July 20, 1999 (Reg. No. 333-78845)).
10.25 Contract for Purchase and Sale of Coal, dated July 7, 1998,
between Tennessee Valley Authority and White County Coal
Corporation. (Incorporated by reference to Exhibit 10.13 of
the Registrant's Registration Statement on Form S-1/A filed
with the Commission on July 20, 1999 (Reg. No. 333-78845)).
10.26 Agreement for Supply of Coal to the Mt. Storm Power
Station, dated January 15, 1996, between Virginia Electric
and Power Company and Mettiki Coal Corporation.
(Incorporated by reference to Exhibit 10. (t) to MAPCO
Inc.'s Annual Report on Form 10-K, filed April 1, 1996,
File No. 1-5254).
*10.27 Coal Feedstock Supply Agreement dated October 26, 2001,
between Synfuel Solutions Operating LLC and Hopkins County
Coal, LLC (Portions of this agreement have been omitted
based on a request for confidential treatment. Those
omitted portions have been filed with the SEC).
76
*10.28 Amendment No. 1 to Coal Feedstock Supply Agreement dated
February 28, 2002, between Synfuel Solutions Operating LLC
and Hopkins County Coal, LLC (Portions of this agreement
have been omitted based on a request for confidential
treatment. Those omitted portions have been filed with the
SEC).
10.29 Amended and Restated Put and Call Option Agreement dated
February 12, 2001 between ARH Warrior Holdings, Inc. and
Alliance Resource Partners, L.P. (Incorporated by reference
to Exhibit 10.17 of the Registrant's Annual Report on Form
10-K for the year ended December 31, 2000, File No.
000-26823).
10.30 Consulting Agreement for Mr. Sachse dated January 1, 2001.
(Incorporated by reference to Exhibit 10.18 of the
Registrant's Annual Report on Form 10-K for the year ended
December 31, 2000, File No. 000-26823).
10.31 Form of Employee Agreement for Messrs. Craft, Pearson,
Greenwood, Wesley and Rathburn. (Incorporated by reference
to Exhibit 10.6 of the Registrant's Registration Statement
on Form S-1/A filed with the Commission on August 9, 1999
(Reg. No. 333-78845)).
18.1 Preferability Letter on Accounting Change. (Incorporated by
reference to Exhibit 18.1 of the Registrant's Amended
Quarterly Report on Form 10-Q/A for the quarter ended March
31, 2001, File No. 000-26823).
*21.1 List of Subsidiaries
*23.1 Consent of Deloitte & Touche LLP regarding Form S-3,
Registration No. 333-85282
*23.2 Consent of Deloitte & Touche LLP regarding Form S-8
Registration No. 333-85258
* Filed here with
(b) Reports on Form 8-K:
None.
77
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized, in Tulsa, Oklahoma, on March 29, 2002.
ALLIANCE RESOURCE PARTNERS, L.P.
By: Alliance Resource Management GP, LLC
its managing general partner
/s/ Michael L. Greenwood
-------------------------------------
Michael L. Greenwood
Senior Vice President,
Chief Financial Officer
and Treasurer
(Principal Financial Officer and
Principal Accounting Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
<Table>
<Caption>
SIGNATURE TITLE DATE
--------- ----- ----
/s/ Joseph W. Craft III President, Chief Executive March 29, 2002
- ------------------------------ Officer and Director
Joseph W. Craft III (Principal Executive Officer)
/s/ Michael L. Greenwood Senior Vice President, March 29, 2002
- ------------------------------ Chief Financial Officer
Michael L. Greenwood and Treasurer
(Principal Financial Officer and
Principal Accounting Officer)
/s/ John J. MacWilliams Director March 29, 2002
- ------------------------------
John J. MacWilliams
/s/ Preston R. Miller, Jr. Director March 29, 2002
- ------------------------------
Preston R. Miller, Jr.
/s/ John P. Neafsey Director March 29, 2002
- ------------------------------
John P. Neafsey
/s/ John H. Robinson Director March 29, 2002
- ------------------------------
John H. Robinson
/s/ Robert G. Sachse Executive Vice President and Director March 29, 2002
- ------------------------------
Robert G. Sachse
/s/ Paul R. Tregurtha Director March 29, 2002
- ------------------------------
Paul R. Tregurtha
</Table>
78
INDEX TO EXHIBITS
<Table>
<Caption>
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
3.1 Amended and Restated Agreement of Limited Partnership of Alliance
Resource Partners, L.P. (Incorporated by reference to Exhibit 3.1 of
the Registrant's Annual Report on Form 10-K for the year ended
December 31, 1999, File No. 000-26823).
3.2 Amended and Restated Agreement of Limited Partnership of Alliance
Resource Operating Partners, L.P. (Incorporated by reference to
Exhibit 3.2 of the Registrant's Annual Report on Form 10-K for the
year ended December 31, 1999, File No. 000-26823).
3.3 Certificate of Limited Partnership of Alliance Resource Partners, L.P.
(Incorporated by reference to Exhibit 3.6 of the Registrant's
Registration Statement on Form S-1 filed with the Commission on May
20, 1999 (Reg. No. 333-78845)).
3.4 Certificate of Limited Partnership of Alliance Resource Operating
Partners, L.P. (Incorporated by reference to Exhibit 3.8 of the
Registrant's Registration Statement on Form S-1/A filed with the
Commission on July 20, 1999 (Reg. No. 333-78845)).
3.5 Certificate of Formation of Alliance Resource Management GP, LLC
(Incorporated by reference to Exhibit 3.7 of the Registrant's
Registration Statement on Form S-1/A filed with the Commission on July
23, 1999 (Reg. No. 333-78845)).
3.6 Amended and Restated Operating Agreement of Alliance Resource
Management GP, LLC (Incorporated by reference to Exhibit 3.4 of the
Registrant's Registration Statement on Form S-3 filed with the
Commission on April 1, 2002 (Reg. No. 333-85282)).
3.7 Amendment No. 1 to Amended and Restated Operating Agreement of
Alliance Resource Management GP, LLC (Incorporated by reference to
Exhibit 3.5 of the Registrant's Registration Statement on Form S-3
filed with the Commission on April 1, 2002 (Reg. No. 333-85282)).
3.8 Amendment No. 2 to Amended and Restated Operating Agreement of
Alliance Resource Management GP, LLC (Incorporated by reference to
Exhibit 3.6 of the Registrant's Registration Statement on Form S-3
filed with the Commission on April 1, 2002 (Reg. No. 333-85282)).
4.1 Form of Common Unit Certificate (Included as Exhibit A to the Amended
and Restated Agreement of Limited Partnership of Alliance Resource
Partners, L.P.).
10.1 Credit Agreement, dated as of August 16, 1999, among Alliance Resource
GP, LLC, JP Morgan Chase Bank (formerly The Chase Manhattan Bank) (as
paying agent), Deutsche Bank AG, New York Branch (as documentation
agent), Citicorp USA, Inc. and JP Morgan Chase Bank (as
co-administrative agents) and the lenders named therein. (Incorporated
by reference to Exhibit 10.1 of the Registrant's Annual Report on Form
10-K for the year ended December 31, 1999, File No. 000-26823).
*10.2 Amendment No. 1, dated December 7, 2001, to the Credit Agreement,
dated as of August 16, 1999, among Alliance Resource GP, LLC, JP
Morgan Chase Bank
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(formerly The Chase Manhattan Bank) (as paying agent), Deutsche Bank
AG, New York Branch (as documentation agent), Citicorp USA, Inc. and
JP Morgan Chase Bank (as co-administrative agents) and the lenders
named therein.
10.3 Note Purchase Agreement, dated as of August 16, 1999, among Alliance
Resource GP, LLC and the purchasers named therein. (Incorporated by
reference to Exhibit 10.2 of the Registrant's Annual Report on Form
10-K for the year ended December 31, 1999, File No. 000-26823).
10.4 Letter of Credit Facility Agreement dated as of June 29, 2001, between
Alliance Resource Partners, L.P. and Bank of Oklahoma, National
Association. (Incorporated by reference to Exhibit 10.20 of the
Registrant's Quarterly Report on Form 10-Q for the quarter ended
September 30, 2001, File No. 000-26823).
10.5 Promissory Note Agreement dated as of July 31, 2001, between Alliance
Resource Partners, L.P. and Bank of Oklahoma, N. A. (Incorporated by
reference to Exhibit 10.21 of the Registrant's Quarterly Report on
Form 10-Q for the quarter ended September 30, 2001, File No.
000-26823).
10.6 Guarantee Agreement, dated as of July 31, 2001, between Alliance
Resource GP, LLC and Bank of Oklahoma, N.A. (Incorporated by reference
to Exhibit 10.22 of the Registrant's Quarterly Report on Form 10-Q for
the quarter ended September 30, 2001, File No. 000-26823).
10.7 Letter of Credit Facility Agreement dated as of August 30, 2001,
between Alliance Resource Partners, L.P. and Fifth Third Bank.
(Incorporated by reference to Exhibit 10.23 of the Registrant's
Quarterly Report on Form 10-Q for the quarter ended September 30,
2001, File No. 000-26823).
10.8 Guarantee Agreement, dated as of August 30, 2001, between Alliance
Resource GP, LLC and Firth Third Bank. (Incorporated by reference to
Exhibit 10.24 of the Registrant's Quarterly Report on Form 10-Q for
the quarter ended September 30, 2001, File No. 000-26823).
10.9 Letter of Credit Facility Agreement dated as of October 2, 2001,
between Alliance Resource Partners, L.P. and Bank of the Lakes,
National Association. (Incorporated by reference to Exhibit 10.25 of
the Registrant's Quarterly Report on Form 10-Q for the quarter ended
September 30, 2001, File No. 000-26823).
10.10 Promissory Note Agreement dated as of October 2, 2001, between
Alliance Resource Partners, L.P. and Bank of the Lakes, N.A.
(Incorporated by reference to Exhibit 10.26 of the Registrant's
Quarterly Report on Form 10-Q for the quarter ended September 30,
2001, File No. 000-26823).
10.11 Guarantee Agreement, dated as of October 2, 2001, between Alliance
Resource GP, LLC and Bank of the Lakes, N.A. (Incorporated by
reference to Exhibit 10.27 of the Registrant's Quarterly Report on
Form 10-Q for the quarter ended September 30, 2001, File No.
000-26823).
10.12 Guaranty Fee Agreement dated as of July 31, 2001, between Alliance
Resource Partners, L.P. and Alliance Resource GP, LLC. (Incorporated
by reference to Exhibit 10.28 of the Registrant's Quarterly Report on
Form 10-Q for the quarter ended September 30, 2001, File No.
000-26823).
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10.13 Contribution and Assumption Agreement, dated August 16, 1999, among
Alliance Resource Holdings, Inc., Alliance Resource Management GP,
LLC, Alliance Resource GP, LLC, Alliance Resource Partners, L.P.,
Alliance Resource Operating Partners, L.P. and the other parties named
therein. (Incorporated by reference to Exhibit 10.3 of the
Registrant's Annual Report on Form 10-K for the year ended December
31, 1999, File No. 000-26823).
10.14 Omnibus Agreement, dated August 16, 1999, among Alliance Resource
Holdings, Inc., Alliance Resource Management GP, LLC, Alliance
Resource GP, LLC and Alliance Resource Partners, L.P. (Incorporated by
reference to Exhibit 10.4 of the Registrant's Annual Report on Form
10-K for the year ended December 31, 1999, File No. 000-26823).
10.15 Alliance Resource Management GP, LLC 2000 Long-Term Incentive Plan (as
amended). (Incorporated by reference to Exhibit 10.11 of the
Registrant's Annual Report on Form 10-K for the year ended December
31, 1999, File No. 000-26823).
10.16 Alliance Resource Management GP, LLC Short-Term Incentive Plan.
(Incorporated by reference to Exhibit 10.12 of the Registrant's Annual
Report on Form 10-K for the year ended December 31, 1999, File No.
000-26823).
10.17 Alliance Resource Management GP, LLC Supplemental Executive Retirement
Plan. (Incorporated by reference to Exhibit 99.2 of the Registrant's
Registration Statement on Form S-8 filed with the Commission on April
1, 2002 (Reg. No. 333-85258)).
10.18 Alliance Resource Management GP, LLC Deferred Compensation Plan for
Directors. (Incorporated by reference to Exhibit 99.3 of the
Registrant's Registration Statement on Form S-8 filed with the
Commission on April 1, 2002 (Reg. No. 333-85258)).
10.19 Restated and Amended Coal Supply Agreement, dated February 1, 1986,
among Seminole Electric Cooperative, Inc., Webster County Coal
Corporation and White County Coal Corporation. (Incorporated by
reference to Exhibit 10.9 of the Registrant's Registration Statement
on Form S-1/A filed with the Commission on July 20, 1999 (Reg. No.
333-78845)).
10.20 Amendment No. 1 to the Restated and Amended Coal Supply Agreement
effective April 1, 1996 between MAPCO Coal Inc., Webster County Coal
Corporation, White County Coal Corporation, and Seminole Electric
Cooperative, Inc. (Incorporated by reference to Exhibit 10.14 of the
Registrant's Quarterly Report on Form 10-Q for the quarter ended June
30, 2000, File No. 000-26823).
10.21 Interim Coal Supply Agreement effective May 1, 2000 between Alliance
Coal, LLC and Seminole Electric Cooperative, Inc. (Incorporated by
reference to Exhibit 10.15 of the Registrant's Quarterly Report on
Form 10-Q for the quarter ended June 30, 2000, File No. 000-26823).
10.22 Contract for Purchase and Sale of Coal, dated January 31, 1995,
between Tennessee Valley Authority and Webster County Coal
Corporation. (Incorporated by reference to Exhibit 10.10 of the
Registrant's Registration Statement on Form S-1/A filed with the
Commission on July 20, 1999 (Reg. No. 333-78845)).
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10.23 Assignment/Transfer Agreement between Andalex Resources, Inc., Hopkins
County Coal LLC, Webster County Coal Corporation and Tennessee Valley
Authority, dated January 23, 1998, with Exhibit A - Contract for
Purchase and Sale of Coal between Tennessee Valley Authority and
Andalex Resources, Inc., dated January 31, 1995. (Incorporated by
reference to Exhibit 10.11 of the Registration Statement on Form S-1/A
filed with the Commission on July 20, 1999 (Reg. No. 333-78845)).
10.24 Contract for Purchase and Sale of Coal, dated July 7, 1998, between
Tennessee Valley Authority and Webster County Coal Corporation.
(Incorporated by reference to Exhibit 10.12 of the Registrant's
Registration Statement on Form S-1/A filed with the Commission on July
20, 1999 (Reg. No. 333-78845)).
10.25 Contract for Purchase and Sale of Coal, dated July 7, 1998, between
Tennessee Valley Authority and White County Coal Corporation.
(Incorporated by reference to Exhibit 10.13 of the Registrant's
Registration Statement on Form S-1/A filed with the Commission on July
20, 1999 (Reg. No. 333-78845)).
10.26 Agreement for Supply of Coal to the Mt. Storm Power Station, dated
January 15, 1996, between Virginia Electric and Power Company and
Mettiki Coal Corporation. (Incorporated by reference to Exhibit 10.
(t) to MAPCO Inc.'s Annual Report on Form 10-K, filed April 1, 1996,
File No. 1-5254).
*10.27 Coal Feedstock Supply Agreement dated October 26, 2001, between
Synfuel Solutions Operating LLC and Hopkins County Coal, LLC (Portions
of this agreement have been omitted based on a request for
confidential treatment. Those omitted portions have been filed with
the SEC).
*10.28 Amendment No. 1 to Coal Feedstock Supply Agreement dated February 28,
2002, between Synfuel Solutions Operating LLC and Hopkins County Coal,
LLC (Portions of this agreement have been omitted based on a request
for confidential treatment. Those omitted portions have been filed
with the SEC).
10.29 Amended and Restated Put and Call Option Agreement dated February 12,
2001 between ARH Warrior Holdings, Inc. and Alliance Resource
Partners, L.P. (Incorporated by reference to Exhibit 10.17 of the
Registrant's Annual Report on Form 10-K for the year ended December
31, 2000, File No. 000-26823).
10.30 Consulting Agreement for Mr. Sachse dated January 1, 2001.
(Incorporated by reference to Exhibit 10.18 of the Registrant's Annual
Report on Form 10-K for the year ended December 31, 2000, File No.
000-26823).
10.31 Form of Employment Agreement for Messrs. Craft, Pearson, Greenwood,
Wesley and Rathburn. (Incorporated by reference to Exhibit 10.6 of the
Registrant's Registration Statement on Form S-1/A filed with the
Commission on August 9, 1999 (Reg. No. 333-78845)).
18.1 Preferability Letter on Accounting Change. (Incorporated by reference
to Exhibit 18.1 of the Registrant's Amended Quarterly Report on Form
10-Q/A for the quarter ended March 31, 2001, File No. 000-26823).
*21.1 List of Subsidiaries.
*23.1 Consent of Deloitte & Touche LLP regarding Form S-3, Registration No.
333-85282
*23.2 Consent of Deloitte & Touche LLP regarding Form S-8, Registration No.
333-85258
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* Filed here with
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