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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_______________
FORM 10-K/A
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000
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
_______________
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
_______________
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
$147,150,647 on March 26, 2001, based on $19.81 per unit, the closing price of
the Common Units as reported on the Nasdaq National Market on such date.
As of March 26, 2001, 8,982,780 Common Units and 6,422,531 Subordinated
Units are outstanding.
DOCUMENTS INCORPORATED BY REFERENCE: None
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This Amendment No. 1 to our Annual Report on Form 10-K/A (Form 10-K/A) amends
Item. 1 "Business", Item 2. "Properties", Item. 7 "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and Item. 8
"Financial Statements and Supplementary Data" of our Annual Report on Form 10-K
for the year ended December 31, 2000 (Original Form 10-K), as filed with the
Securities and Exchange Commission (SEC) on March 27, 2001. Each of these Items
is hereby amended by deleting the corresponding Item contained in the Original
Form 10-K in its entirety and replacing it with the Item contained in this
Form 10-K/A.
We are filing this Form 10-K/A in response to comments from the SEC. As
requested by the SEC, we have revised the amount of proven and probable coal we
had as of December 31, 2000 from 466.0 million tons to 412.2 million tons and
provided additional information concerning (a) the determination of our coal
reserves, (b) our long-term coal supply agreements, (c) our operations at
individual mines, (d) our expenses related to the impairment of certain
transloading facility assets, (e) our expenses associated with third party
claims arising out of mining operations and (f) the put and call option
agreement with our affiliate, Alliance Resource Holdings, Inc.
Other than as specified above, no information included in the Original Form 10-K
has been amended by this Form 10-K/A. This Form 10-K/A continues to speak as of
the date that the Original Form 10-K was filed with the SEC, and we have not
updated the disclosure herein to reflect any information or events subsequent to
the filing of the Original Form 10-K, except for issues related to a permit
application in West Virginia discussed in Item 2. "Properties."
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FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K contains forward-looking statements.
These statements are based on the beliefs of Alliance Resource Partners, L.P.
(Partnership) as well as assumptions made by and information currently available
to the Partnership. When used in this document, the words "anticipate,"
"believe," "expect," "estimate," "forecast," "project," and similar expressions
identify forward-looking statements. These statements reflect the Partnership's
current views with respect to future events and are subject to various risks,
uncertainties and assumptions including, but not limited to (a) the
Partnership's dependence on significant customer contracts and the terms of
those contracts, (b) the Partnership's productivity levels and margins that it
earns from the sale of coal, (c) the effects of any unanticipated increases in
labor costs, adverse changes in work rules, or unexpected cash payments
associated with post-mine reclamation, workers' compensation claims, and
environmental litigation or cleanup, (d) the risk of major mine-related
accidents or interruptions, and (e) the effects of any adverse change in the
domestic coal industry, electric utility industry, or general economic
conditions. If one or more of these risks or uncertainties materialize, or
should underlying assumptions prove incorrect, actual results may vary
materially from those described in this Annual Report on Form 10-K. Except as
required by applicable securities laws, the Partnership does not intend to
update these forward-looking statements.
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,
2000, we had approximately 412.2 million tons of reserves in Illinois, Indiana,
Kentucky, Maryland and West Virginia. In 2000, we produced 13.7 million tons of
coal and sold 15.0 million tons of coal. The coal we produced in 2000 was 20.4%
low-sulfur coal, 19.0% medium-sulfur coal and 60.6% high-sulfur coal. In 2000,
approximately 96% 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
both surface and underground mines. 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.
(Intermediate Partnership), were formed to acquire, own and operate
substantially all of the coal production and marketing assets of Alliance
Resource Holdings, Inc. (ARH), a Delaware corporation formerly known as Alliance
Coal Corporation. We completed our initial public offering (IPO) on August 20,
1999, at which time ARH contributed substantially all of its operating assets
and liabilities to the Intermediate Partnership.
Our managing general partner, Alliance Resource Management GP, LLC
(Managing GP) and our special general partner, Alliance Resource GP, LLC
(Special GP) (collectively, the Special GP and the Managing GP are the General
Partners) own an aggregate 2% general partner interests in the Partnership. 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 the
Partnership.
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The coal production and marketing assets of ARH acquired by the
Partnership are referred to as the "Predecessor." All 1999 operating data
contained herein includes the results of the Partnership and the Predecessor.
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 demanded
by our customers. The following chart illustrates our production by region for
the last five years.
OPERATING REGION AND MINES 2000 1999 1998 1997 1996
---- ---- ---- ---- ----
(TONS IN MILLIONS)
Illinois Basin Operations:
Dotiki, Pattiki, Hopkins County, Gibson County 8.4 8.5 7.9 5.2 4.3
East Kentucky Operations:
Pontiki, MC Mining 2.7 2.8 2.5 2.8 2.0
Maryland Operations:
Mettiki 2.6 2.8 3.0 2.9 2.7
---- ---- ---- ---- ----
Total 13.7 14.1 13.4 10.9 9.0
==== ==== ==== ==== ====
Illinois Basin Operations
Our Illinois Basin mining operations are located in western Kentucky,
southern Illinois and southern Indiana. We have approximately 835 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 2000, Webster County Coal entered into a
mineral lease and sublease with an affiliate of the Special GP. See "Item 13.
Certain Relationships and Related Transactions."
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. This extension
involves capital expenditures of approximately $30 million during the 2000-2003
period and allows the Pattiki mine to continue 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 TVA, 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. The operation
has three surface mines, two of which are currently idle, and one underground
mine. Of the two idle mines, one was idled in May 2000 in response to reduced
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demand, primarily reflecting numerous unplanned outages by two large utility
customers. This production capacity is anticipated to remain idled until market
conditions warrant increased production. 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 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. Our primary customers for coal produced at
Hopkins County Coal include Louisville Gas & Electric, TVA and WKE, which
purchase our coal pursuant to long-term contracts for use in their scrubbed
generating units. During 2000, Hopkins County Coal entered into an option to
lease and sub-lease reserves with an affiliate of the Special GP. See "Item 13.
Certain Relationships and Related Transactions."
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 GP for the construction of a
coal preparation plant and handling facilities, providing us access to those
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 will utilize multiple continuous mining units employing room-and-pillar
mining techniques. The preparation plant is leased from the Special GP and 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., 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 360 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 a 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. (AEI).
MC Mining, LLC. MC Mining is an underground mining complex located near
Pikeville, Kentucky in Pike County, Kentucky. MC Mining was acquired in 1989.
Since we began operations in late 1996, MC Mining was operated by an
unaffiliated contract mining company. However, during the fourth quarter 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
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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.
Toptiki Coal, LLC. Toptiki was a surface and underground mining complex
located in Martin County, Kentucky. After conducting surface mining operations
through 1982 and underground operations through 1996, we discontinued mining at
the complex and have since sold our member interest in Toptiki for an immaterial
amount.
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.
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 operation
areas. 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
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 directly by CSX railroad. We
currently use the facility as needed for spot shipments to customers other than
Seminole and continue to explore our opportunities and options regarding the
terminal.
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 200,000 tons of outside coal in 2000. We have a
policy of matching our outside coal purchases and sales to minimize market risks
associated with buying and reselling coal.
5
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. We will
continue to think proactively in providing additional services for customers and
believe that this approach will give us a competitive advantage in obtaining
coal supply contracts in the future.
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 2000, approximately 85% of
our sales tonnage, accounting for 86% of out total revenue, was sold under
long-term contracts (contracts having a term of greater than one year) with
maturities ranging from 2000 to 2012. Our total nominal commitment under
significant long-term contracts was approximately 74.8 million tons at December
31, 2000 and is expected to be delivered as follows: 12.0 million tons in 2001,
8.8 million tons in 2002, 8.1 million tons in 2003 to 2005 and 29.7 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 ranges for specific coal characteristic 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 four largest customers are AEI, Seminole, TVA and VEPCO. Sales to
these customers in the aggregate accounted for approximately 62% of our 2000
total revenues, and sales to each of these customers accounted for more than 10%
of our 2000 total revenues. Three of these customers have purchased coal
regularly from us for more than 15 years. A national bond rating agency has
recently reported that the parent company of one of our significant customers is
in default on a significant amount of its outstanding debt. All of the accounts
receivable under the long-term contract with our customer are current. Our
management does not anticipate that this event will have a material impact on
our financial condition or results of operations.
6
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 16% of the total 2000 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 60% 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
to the customer's plant. At our Gibson County and Mettiki mines, a contractor
operates a truck delivery system that transports the coal from the mine to the
primary customer's power plant.
In 2000, 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.
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;
- storage of petroleum products and substances which are regarded
as hazardous under applicable laws or which, if spilled, could
reach waterways or wetlands;
- 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 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
7
significant impact on our mining operations or our customers' ability to use
coal, and 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 and delays,
interruptions or a termination of operations, the extent 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 have not experienced
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.
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 permit 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
8
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. 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
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 has issued revised regulations that could
alter the claims process for the 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 through litigation certain provisions of
the revised regulations. A federal judge has granted a limited stay of the new
black lung regulations at the request of the Bush administration. Under the
preliminary injunction, claims will continue to be processed under the new
regulations, but no final decisions will be made on claims for black lung
benefits filed after the new regulations became effective. The outcome of the
litigation and the impact of the revised regulations if eventually implemented
on the Partnership's liability for black lung claims cannot be determined at
this time. 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
9
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 ARH in 1996, MAPCO Inc. agreed to retain 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 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.
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 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
10
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. EPA expects that effected states will achieve
reductions by requiring power plants to make substantial reductions in their NOx
emissions. This in turn will 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. 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. Because coal mining operations and utilities emit
particulate matter, our mining operations and utility customers are likely to be
directly effected when the revisions to the NAAQS are implemented by the states.
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
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. These restrictions, if established through regulation or legislation,
could have a material adverse effect on our business, financial condition and
results of operations.
11
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 Section
404. However, mitigation requirements under those existing, and possible future,
wetlands permits may vary considerably. In addition, we are currently
interpreting the effect of a January 9, 2001, U.S Supreme Court ruling
concerning the definition of isolated wetlands. This issue should not cause any
increase in post-mine reclamation accruals. In fact, this decision is expected
to decrease the regulatory burden on mining operations that disturb intermittent
streams and other isolated wetlands. 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 effected 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
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 at least one
drinking water supply source for our employees and contractors that is 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
12
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.
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 the 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 practices due to, among other things, the fact that our CWA
discharge permits for treated acid mine drainage contain parameters for
pollutants of concern, 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.
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.
13
EMPLOYEES
We have approximately 1,530 employees, including some 100 corporate
employees and some 1,430 employees involved in active mining operations. Our
work-force is entirely union-free. Relations with our employees are generally
good, and there have been no recent work stoppages or union organizing campaigns
among our employees.
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 filing this Annual Report on
Form 10-K/A. 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, 2000, we had approximately 412.2 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,
2000, about each of our mining complexes.
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 -- -- 92.1 92.1 92.1 --
Pattiki Underground 11,700 -- -- 53.6 53.6 53.6 --
Hopkins County Underground 11,300 -- -- 22.1 22.1 2.1 20.0
Coal / Surface -- -- 12.7 12.7 12.7 --
Gibson County Underground 11,600 -- 37.4 -- 37.4 37.4 --
Coal (North)
Gibson County Underground 11,600 -- 55.0 44.9 99.9 -- 99.9
Coal (South)
----- ----- ----- ----- ----- -----
Region Total -- 92.4 225.4 317.8 197.9 119.9
----- ----- ----- ----- ----- -----
East Kentucky Operations
Pontiki/Excel Underground 12,800 17.8 1.9 -- 19.7 19.7 --
MC Mining/Excel Underground 12,800 23.1 -- -- 23.1 23.1 --
----- ----- ----- ----- ----- -----
Region Total 40.9 1.9 -- 42.8 42.8 --
----- ----- ----- ----- ----- -----
Maryland Operations
Mettiki Underground 13,000 -- 15.0 20.8 35.8 20.8 15.0
Mettiki (WV) Underground 13,000 -- -- 15.8 15.8 10.2 5.6
----- ----- ----- ----- ----- -----
-- 15.0 36.6 51.6 31.0 20.6
----- ----- ----- ----- ----- -----
Total 40.9 109.3 262.0 412.2 271.7 140.5
===== ===== ===== ===== ===== =====
% of Total 9.9% 26.5% 63.6% 100.0% 65.9% 34.1%
===== ===== ===== ===== ===== =====
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
14
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 40.9 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.
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
difference permit application concerning other non-reserve coal deposits, on
January 29, 2002, the West Virginia DEP denied such permit application related
to 3.1 million tons of non-reserve coal deposits 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.
In connection with our corporate reorganization and subsequent initial
public offering, we obtained the consents of our lessors or determined that
obtaining such consents was not required. Although we believe we have obtained
all necessary consents, in the event that we have failed to obtain a necessary
consent, our operations may be adversely impacted if we experience any
disruption of our mining operations as a consequence.
The following table sets forth production data about each of our mining
complexes.
15
Tons Produced
---------------------------
Operations 2000 1999 1998 Transportation Equipment
---------- ---- ---- ---- -------------- ---------
(tons in millions)
Illinois Basin Operations
Dotiki 3.9 3.6 3.5 CSX; truck; barge CM
Pattiki 2.3 2.3 2.1 CSX; truck; barge CM
Hopkins County Coal 2.1 2.6 2.3 CSX, PAL; truck DL; CM
Gibson County Coal (North) 0.1 -- -- Truck CM
---- ---- ----
Region Total 8.4 8.5 7.9
==== ==== ====
East Kentucky Operations
Pontiki/Excel 1.9 1.8 1.6 NS; truck CM
MC Mining/Excel 0.8 1.0 0.9 NS; truck CM
==== ==== ====
Region Total 2.7 2.8 2.5
==== ==== ====
Maryland Operations
Mettiki 2.6 2.8 3.0 Truck; CSX LW; CM
==== ==== ====
Total 13.7 14.1 13.4
==== ==== ====
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
effected and the trading price of our Common Units could decline.
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 in the
future.
- Current conditions in the coal industry may change and 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 CAA 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 have a material adverse effect on our business, financial
condition or results of operations.
- Any future litigation relating to disputes with our customers
may result in substantial costs, liabilities and loss of
revenues.
- Any loss of the benefit from state tax credits may affect
adversely our business financial condition or results of
operations.
- Coal mining is subject to inherent risks that are beyond our
control, and we cannot assure you that these risks will be fully
covered under our insurance policies.
16
- We depend on third party service providers to assist us in
producing a portion of our coal. If these providers' services
were no longer available, our ability to produce and sell coal
may be effected adversely.
- 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 effected if we are unable to
replace our coal reserves.
- The estimates of our reserves may prove inaccurate, and you
should not place undue reliance on these estimates. - Our
indebtedness may limit our ability to borrow additional funds,
make distributions to Unitholders or capitalize on business
opportunities.
- We are required to obtain and maintain bonds to secure our
obligations to return mined property to its approximate original
condition. The failure to do so may result in fines and the loss
of mining permits.
Risks Inherent in an Investment in the Partnership
- Unitholders have limited voting rights and do not control our
Managing GP.
- 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 GP 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.
- Cash distributions are not guaranteed and may fluctuate with our
performance. In addition, our Managing GP's discretion in
establishing reserves may negatively impact your receipt of cash
distributions.
Regulatory Risks
- We are subject to federal, state and local regulations on
numerous matters. These regulations increase our costs of doing
business and may discourage customers from buying our coal.
- We are subject to black lung benefits and workers' compensation
obligations, which could increase if new legislation is enacted.
- The CAA affects our customers and could significantly influence
their purchasing decisions.
- The passage of legislation responsive to the Kyoto Protocol
could result in a reduced use of coal by electric power
generators. This reduction in use could adversely affect
our revenues and results of operations.
- The CWA imposes limitations and monitoring and reporting
obligations on our discharge of pollutants into water.
- We are subject to reclamation, mine closure and real property
restoration regulation obligations, which could increase if new
legislation is enacted.
- We and our customers could incur significant costs under federal
and state Superfund and waste management statutes.
Tax Risks to Common Unitholders
- The Internal Revenue Service (IRS) could in the future choose to
treat us as a corporation, which would substantially reduce the
cash available for distribution to Unitholders.
17
- 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 have 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 the Common Units.
- Common Unitholders will likely be subject to state and local
taxes as a result of an investment in units.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
GENERAL
The following discussion of the financial condition and results of
operations for the Partnership and its 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 financial information, see "Item 8.
Financial Statements and Supplementary Data. -- Note 1. Organization and
Presentation."
We are a diversified producer and marketer of coal to major U.S.
utilities and industrial users. In 2000, our total production was 13.7 million
tons and our total sales were 15.0 million tons. The coal we produced in 2000
was approximately 20.4% low-sulfur coal, 19.0% medium-sulfur coal and 60.6%
high-sulfur coal.
At December 31, 2000, we had approximately 412.2 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 2000, approximately 73% of our sales tonnage was consumed by electric
utilities with the balance consumed by cogeneration plants and industrial users.
Our largest customers in 2000 were AEI, Seminole, TVA, and VEPCO. We have had
relationships with three of these customers for at least 15 years. In 2000,
approximately 85% of our sales tonnage, including approximately 86% 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 2000, approximately 96% 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.
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 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.
18
RESULTS OF OPERATIONS
In comparing 2000 to 1999 and 1999 to 1998, the Partnership and
Predecessor periods for 1999 have been combined. Since the Partnership
maintained the historical basis of the Predecessor's net assets, management
believes that the combined Partnership and Predecessor results for 1999 are
comparable with 1998. The interest expense associated with the debt incurred
concurrent with the closing of the IPO is applicable only to the Partnership
period. See "Item 8. Financial Statements and Supplementary Data. -- Note 1.
Organization and Presentation."
2000 Compared with 1999
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 low margin, coal export brokerage markets. The brokerage business is not
expected to be material in the future. Tons sold remained consistent at 15.0
million for 2000 and 1999. 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. Hopkins County
Coal provided the coal feedstock and received various fees for operating the
third party's coal synfuel facility and providing other services. We assisted
the third party with marketing the coal synfuel and received a fee for such
services. Synfuel shipments continue in 2001 on a month to month basis,
currently contemplated through mid-2001, with customer interest through 2003.
However, future shipments are dependent upon, among other things, receiving a
new favorable private letter ruling from the IRS. In late October 2000, the IRS
issued Rev. Proc. 2000-47, suspending issuance of private letter rulings for
most coal synfuel plants while a review is conducted concerning whether current
tax rules adequately address the evolving synfuel industry. The IRS requested
public comment on Rev. Proc. 2000-47 by November 27, 2000. The IRS indicated it
will provide substantial guidance in the form of a general revenue ruling or a
tax regulation to address tax credits granted under Section 29 of the Internal
Revenue Code. Until such guidance is received from the IRS, we cannot give any
assurance that future benefits will be received from the coal synfuel production
facility.
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.
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.
19
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 expense 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 the IPO and
concurrent transactions occurring on August 20, 1999. See "Item 8. Financial
Statements and Supplementary Data. -- Note 1. Organization and Presentation."
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 $12.2 million, which is net of litigation expense
of approximately $0.9 million and an impairment charge of $2.4 million relating
to the facility's assists. Additionally, the Partnership 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 the
IPO, partially offset by unusual items recorded during 2000. See "Unusual items"
described above.
Income tax expense. The Partnership's earnings or loss for federal
income taxes purposes will be included in the tax returns of the individual
partners. Accordingly, no recognition is given to income taxes in the
accompanying financial statements of the Partnership. The Predecessor was
included in the consolidated federal income tax return of ARH. Federal and state
income taxes were calculated as if the Predecessor had filed its return on a
separate company basis utilizing an effective income tax rate of 31%.
EBITDA (income from operations before net interest expense, income
taxes, depreciation and 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 the unusual items recorded during 2000, see
"Unusual items" described above, and the increased production and sales volumes
at the restructured Pontiki mine, which was 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 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
the Partnership's ability to make MQDs. The Partnership's 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 the Partnership in
different contexts (i.e., public reporting versus computation under financing
agreements).
20
1999 Compared with 1998
Coal sales. Coal sales for 1999 declined 3.2% to $345.9 million from
$357.4 million for 1998. The decrease of $11.5 million was primarily
attributable to lower coal export brokerage volumes partially offset by improved
results from the restructured Pontiki mining complex and full-year benefits from
the capital invested at Hopkins County Coal. The lower brokerage volumes were
largely attributable to reduced participation in coal export brokerage markets.
The brokerage business is not expected to be material in the future. Because
coal brokerage operations generate lower margins than direct coal sales, changes
in the levels of brokerage activity have a greater impact on revenues and
outside purchases than on margins. Tons sold decreased less than 1.0% to 15.0
million tons for 1999 from 15.1 million tons for 1998. Tons produced increased
5.1% to 14.1 million tons for 1999 from 13.4 million tons for 1998.
Transportation revenues. Transportation revenues for 1999 decreased
53.9% to $19.1 million from $41.4 million for 1998. The decrease of $22.3
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
declined 79.0% to $0.9 million for 1999 from $4.5 million from 1998. The
decrease of $3.6 million was primarily due to lower volumes at the Mt. Vernon
facility due to the dispute with Seminole. See "Item 8. Financial Statements and
Supplementary Data. -- Note 4. Unusual Items."
Transportation expenses. See "Transportation Revenues" above concerning
the decrease in transportation expenses.
Operating expenses. Operating expenses were comparable for 1999 and 1998
at $242.0 million and $237.6 million, an increase of 1.9%.
Outside purchases. Outside purchases declined 52.8% to $24.2 million for
1999 from $51.2 million for 1998. The decrease of $27.0 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 1999 and 1998 at $15.2 million and $15.3 million, a decrease of
less than 1.0%.
Depreciation, depletion and amortization. Depreciation, depletion and
amortization expense were comparable for 1999 and 1998 at $39.7 million and
$39.8 million, a decrease of less than 1.0%.
Interest expense. Interest expense was $6.0 million for 1999 compared to
$0.2 million for 1998. The increase reflected the 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 the IPO and concurrent transactions occurring
on August 20, 1999. See "Item 8. Financial Statements and Supplementary Data. --
Note 1. Organization and Presentation."
Unusual items. In response to market conditions, the Pontiki mining
complex ceased operations and terminated substantially all of its workforce in
September 1998. During the idle status period, which ended in November 1998,
Pontiki incurred a net loss of approximately $5.2 million consisting of
estimated amounts for increased workers' compensation claims of $1.2 million and
severance payments consistent with the Worker Adjustment and Retraining
Notification Act of $1.2 million, as well as the costs associated with
maintaining an idled mine of $2.8 million.
Income before income taxes. Income before income taxes increased 67.3%
to $21.0 million for 1999 compared to $12.5 million for 1998. The increase of
$8.5 million was primarily attributable to improved
21
productivity, which included the benefits of the restructured operation at
Pontiki following the idle status period of the mine, which resulted in the $5.2
million unusual item recorded in 1998 as discussed above, and the capital
investments at the Hopkins County operation, partially offset by the losses
incurred at Mt. Vernon due to the dispute with Seminole.
Income tax expense. The Partnership's earnings or loss for federal
income taxes purposes are included in the tax returns of the individual
partners. Accordingly, no recognition is given to income taxes in the
accompanying financial statements of the Partnership. The Predecessor is
included in the consolidated federal income tax return of ARH. Federal and state
income taxes are calculated as if the Predecessor had filed its return on a
separate company basis utilizing an effective income tax rate of 31%.
EBITDA. (income from operations before net interest expense, income
taxes, depreciation, and depletion and amortization) increased 26.9% to $66.7
million for 1999 compared with $52.5 million for 1998. The $14.2 million
increase was attributable to the same factors that contributed to the increase
in income before income taxes.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
Cash provided by operating activities was $71.4 million in 2000 compared
to $19.0 million in 1999. The increase in cash provided by operating activities
was principally attributable to the decrease in coal inventory of approximately
$10.0 million and the Special GP retaining approximately $37.9 million of trade
receivables in conjunction with the IPO and concurrent transactions that
occurred on August 20, 1999.
Net cash used in investing activities of $41.0 million in 2000 was
principally attributable to capital expenditures. Net cash used in investing
activities of $65.4 million for 1999 was principally attributable to capital
expenditures and the purchase of U.S. Treasuries in conjuction with the IPO and
concurrent transactions that occurred on August 20, 1999.
Net cash used in financing activities was $31.4 million for 2000
compared to net cash provided by financing activities of $54.4 million for 1999.
Cash used in financing activities during 2000 was a direct result of four MQDs
paid in 2000 of $0.50 per unit on Common and Subordinated Units outstanding. The
net cash provided by financing activities in 1999 was principally attributable
to net cash provided by the IPO and concurrent transactions that occurred on
August 20, 1999.
Capital Expenditures
Capital expenditures increased to $46.2 million in 2000 compared to
$39.2 million in 1999. The increase was primarily attributable to the
development of the new Gibson County Coal mining complex, which commenced
production in November 2000. During 2000, the Partnership liquidated
approximately $7.1 million of U.S. Treasury Notes to fund various qualifying
capital expenditures with the remaining expenditures funded through cash
generated from operations. The Partnership approved an extension of its 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.
We currently expect that our average annual maintenance capital
expenditures will be approximately $23.5 million. We currently expect to fund
our anticipated capital expenditures with cash generated from operations and the
utilization of the revolving credit facility described below.
22
Notes Offering and Credit Facility
Concurrently with the closing of the IPO, the Special GP 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 GP 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. The Partnership has borrowings outstanding of $50 million under the
term loan facility, but no borrowings outstanding under either the working
capital facility or the revolving credit facility at December 31, 2000, and
1999. The weighted average interest rates on the term loan facility at December
31, 2000, and 1999, was 7.77% and 7.07%, respectively. The Credit Facility
expires August 2004. The Senior Notes and Credit Facility are guaranteed by
Alliance Coal, LLC and all of its subsidiaries. In addition, the Credit Facility
is further secured by a pledge of treasury securities, which, upon written
notice, are released for purposes of financing qualified capital expenditures of
the Intermediate Partnership or its subsidiaries. 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.
Accruals of Other Liabilities
We had accruals for deferred credits and other liabilities, including
current obligations, totaling $67.1 million and $61.9 million at December 31,
2000 and 1999. 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 and were funded at the time the
expense was incurred. The accruals of these items were based on estimates of
future expenditures based on current legislation and related regulations and
other developments. Thus, from time to time, the Partnership's results of
operations may be significantly effected by changes to these deferred credits
and other liabilities. See "Item 8. Financial Statements and Supplementary Data.
- -- Note 12. Reclamation and Mine Closing Costs and Note 13. Pneumoconiosis
("Black Lung") Benefits."
We are required to pay black lung benefits to eligible and former
employees under the BLBA. We also are liable under various state statutes for
similar claims. We provide self-insured accruals for these benefits. We had
accrued liabilities of $22.2 million for these benefits at December 31, 2000,
and 1999.
We accrue for reclamation and mine closing costs. We estimate the costs
and timing of future reclamation and mine closing costs and record those
estimates on a present value basis. We had accrued liabilities of $16.0 million
and $14.8 million at December 31, 2000 and 1999 for these costs.
We accrue for workers' compensation claims resulting from traumatic
injuries based on actuarial valuations and periodically adjust these estimates
based on the estimated costs of claims made. We had accrued liabilities of $20.6
million and $19.5 million at December 31, 2000 and 1999 for these costs.
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, 2000, 1999 or 1998.
RECENT ACCOUNTING PRONOUNCEMENTS
Effective January 1, 2001, the Partnership adopted Statement of
Financial Accounting Standards 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. The Partnership currently has
no identified derivative instruments or hedging activities. Accordingly, this
standard had no material effect on the Partnership's consolidated financial
statements upon adoption.
23
During the fourth quarter 2000, the Partnership adopted Financial Accounting
Standards Board Emerging Issues Task Force Issue No. 00-10 "Accounting for
Shipping and Handling Fees and Costs." Accordingly, the Partnership reflects the
cost of transporting coal to customers through third party carriers as
transportation expenses and the corresponding reimbursement of these costs
through customer billings as transportation revenues in the consolidated and
combined statements of income. These amounts were previously offset. There was
no cumulative effect on net income and the prior periods' consolidated and
combined statements of income have been reclassified to comply with this
presentation.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Partnership has 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 the Predecessor's transactions were, and all of the
Partnership's transactions are, denominated in U.S. dollars, and as a result,
the Partnership does not have material exposure to currency exchange-rate risks.
The Partnership does 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 the Partnership has interest rate exposure.
The table below provides information about the Partnership's 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 the Partnership's current incremental borrowing rates for
similar types of borrowing arrangements as of December 31, 2000 and 1999. The
carrying amounts and fair values of financial instruments are as follows (in
thousands):
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%
Fair Value
Expected Maturity Dates December 31,
as of December 31, 1999 2000 2001 2002 2003 2004 Thereafter Total 1999
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
Senior Notes-fixed rate $ -- $ -- $ -- $ -- $ -- $ 180,000 $ 180,000 $ 165,000
Weighted Average
interest rate 8.31%
Term Loan-floating rate $ -- $ 3,750 $ 15,000 $ 16,250 $ 15,000 $ -- $ 50,000 $ 50,000
Weighted Average
interest rate 7.07% 7.07% 7.07% 7.07%
24
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,
2000 and 1999, the related consolidated and combined statements of income and
cash flows 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 and the Predecessor period from January 1, 1999 to August 19, 1999 and the
year ended December 31, 1998 and the statement of Partners' capital (deficit)
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. These
financial statements 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, 2000 and 1999 and the results of their operations and their cash
flows 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 and the
Predecessor period from January 1, 1999 to August 19, 1999 and the year ended
December 31, 1998 in conformity with accounting principles generally accepted in
the United States of America.
/s/ Deloitte & Touche LLP
Tulsa, Oklahoma
January 24, 2001
25
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2000 AND 1999
(IN THOUSANDS, EXCEPT UNIT DATA)
- --------------------------------------------------------------------------------
DECEMBER 31,
--------------------------
ASSETS 2000 1999
--------- ---------
CURRENT ASSETS:
Cash and cash equivalents $ 6,933 $ 8,000
Trade receivables 35,898 33,056
Due from affiliates 208 --
Marketable securities (at cost, which approximates fair value) 37,398 42,339
Inventories 10,842 21,130
Advance royalties 2,865 1,557
Prepaid expenses and other assets 1,168 923
--------- ---------
Total current assets 95,312 107,005
PROPERTY, PLANT AND EQUIPMENT AT COST 320,445 278,221
LESS ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION (135,782) (102,709)
--------- ---------
184,663 175,512
OTHER ASSETS:
Advance royalties 10,009 8,306
Coal supply agreements, net 16,324 19,879
Other long-term assets 2,858 4,112
--------- ---------
$ 309,166 $ 314,814
========= =========
LIABILITIES AND PARTNERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 25,558 $ 19,377
Due to affiliates -- 334
Accrued taxes other than income taxes 4,863 4,574
Accrued payroll and related expenses 6,975 8,811
Accrued interest 5,439 5,491
Workers' compensation and pneumoconiosis benefits 4,415 4,317
Other current liabilities 5,710 2,937
Current maturities, long-term debt 3,750 --
--------- ---------
Total current liabilities 56,710 45,841
LONG-TERM LIABILITIES:
Long-term debt, excluding current maturities 226,250 230,000
Accrued pneumoconiosis benefits 21,651 21,655
Workers' compensation 16,748 15,696
Reclamation and mine closing 14,940 13,407
Due to affiliates 1,278 472
Other liabilities 3,376 3,671
--------- ---------
Total liabilities 340,953 330,742
COMMITMENTS AND CONTINGENCIES
PARTNERS' CAPITAL (DEFICIT):
Common Unitholders 8,982,780 units outstanding 149,642 158,705
Subordinated Unitholder 6,422,531 units outstanding 116,794 123,273
General Partners (298,223) (297,906)
--------- ---------
Total Partners' capital (deficit) (31,787) (15,928)
--------- ---------
$ 309,166 $ 314,814
========= =========
See notes to consolidated and combined financial statements.
26
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED AND COMBINED STATEMENTS OF 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 AND THE PREDECESSOR PERIOD FROM
JANUARY 1, 1999 TO AUGUST 19, 1999 AND THE YEAR ENDED DECEMBER 31, 1998
(IN THOUSANDS, EXCEPT UNIT AND PER UNIT DATA)
PARTNERSHIP PREDECESSOR
--------------------------------- ------------------------------
FROM
COMMENCEMENT FOR THE
OF OPERATIONS PERIOD FROM
YEAR ENDED (ON AUGUST 20, 1999) JANUARY 1, 1999 YEAR ENDED
DECEMBER 31, TO TO DECEMBER 31,
2000 DECEMBER 31, 1999 AUGUST 19, 1999 1998
------------ -------------------- --------------- ------------
SALES AND OPERATING REVENUES:
Coal sales $ 347,209 $ 128,860 $ 217,033 $ 357,440
Transportation revenues 13,511 4,907 14,223 41,408
Other sales and operating revenues 2,749 358 577 4,453
------------ ------------ ------------ ------------
Total revenues 363,469 134,125 231,833 403,301
------------ ------------ ------------ ------------
EXPENSES:
Operating expenses 257,365 89,945 152,066 237,576
Transportation expenses 13,511 4,907 14,223 41,408
Outside purchases 16,874 6,429 17,738 51,151
General and administrative 15,176 6,245 8,912 15,301
Depreciation, depletion and amortization 39,141 15,081 24,622 39,838
Interest expense (net of interest income and interest
capitalized of $3,015 and $999 for the year ended
December 31, 2000 and 1999 partnership period) 16,563 5,887 100 169
Unusual items (9,466) -- -- 5,211
------------ ------------ ------------ ------------
Total operating expenses 349,164 128,494 217,661 390,654
------------ ------------ ------------ ------------
INCOME FROM OPERATIONS 14,305 5,631 14,172 12,647
OTHER INCOME (EXPENSE) 1,276 641 531 (113)
------------ ------------ ------------ ------------
INCOME BEFORE INCOME TAXES 15,581 6,272 14,703 12,534
INCOME TAX EXPENSE -- -- 4,498 3,866
------------ ------------ ------------ ------------
NET INCOME $ 15,581 $ 6,272 $ 10,205 $ 8,668
============ ============ ============ ============
GENERAL PARTNERS' INTEREST
IN NET INCOME $ 312 $ 125
============ ============
LIMITED PARTNERS' INTEREST
IN NET INCOME $ 15,269 $ 6,147
============ ============
BASIC NET INCOME PER LIMITED
PARTNER UNIT $ 0.99 $ 0.40
============ ============
DILUTED NET INCOME PER LIMITED
PARTNER UNIT $ 0.98 $ 0.40
============ ============
WEIGHTED AVERAGE NUMBER
OF UNITS OUTSTANDING - BASIC 15,405,311 15,405,311
============ =============
WEIGHTED AVERAGE NUMBER
OF UNITS OUTSTANDING - DILUTED 15,551,062 15,405,311
============ =============
See notes to consolidated and combined financial statements.
27
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOW
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 AND THE PREDECESSOR PERIOD FROM
JANUARY 1, 1999 TO AUGUST 19, 1999 AND THE YEAR ENDED DECEMBER 31, 1998
(IN THOUSANDS)
PARTNERSHIP PREDECESSOR
--------------------------------- ------------------------------
FROM
COMMENCEMENT FOR THE
OF OPERATIONS PERIOD FROM
YEAR ENDED (ON AUGUST 20, 1999) JANUARY 1, 1999 YEAR ENDED
DECEMBER 31, TO TO DECEMBER 31,
2000 DECEMBER 31, 1999 AUGUST 19, 1999 1998
------------ -------------------- --------------- ------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 15,581 $ 6,272 $ 10,205 $ 8,668
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 39,141 15,081 24,622 39,838
Impairment of transloading facility 2,439 -- -- --
Deferred income taxes -- -- 639 (1,750)
Reclamation and mine closings 1,074 348 457 705
Coal inventory adjustment to market 579 729 -- 1,743
Other 391 186 (114) 34
Changes in operating assets and liabilities,
net of effects from 1998 purchase of
coal business:
Trade receivables (2,842) (33,048) (6,521) 229
Income tax receivable/payable -- -- 651 2,482
Inventories 9,709 (1,433) (371) (6,563)
Advance royalties (3,011) 366 1,153 579
Accounts payable 6,181 (7,410) (129) 2,296
Due to affiliates 264 3,252 -- --
Accrued taxes other than income taxes 289 (630) 678 1,137
Accrued payroll and related benefits (1,836) 844 (828) 491
Accrued pneumoconiosis benefits (4) (1,122) 544 839
Workers' compensation 1,052 2,222 (460) 817
Other 2,366 452 2,370 (1,048)
------------ ------------ ------------ ------------
Total net adjustments 55,792 (20,163) 22,691 41,829
------------ ------------ ------------ ------------
Net cash provided by (used in)
operating activities 71,373 (13,891) 32,896 50,497
------------ ------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of property, plant and equipment (46,151) (17,173) (21,984) (27,669)
Proceeds from sale of property, plant and equipment 210 125 447 185
Purchase of marketable securities (72,523) (51,287) -- --
Proceeds from the maturity of marketable securities 77,464 24,434 -- --
Payment for purchase of business -- -- -- (7,310)
Direct acquisition costs -- -- -- (821)
------------ ------------ ------------ ------------
Net cash used in investing activities (41,000) (43,901) (21,537) (35,615)
------------ ------------ ------------ ------------
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 29,500 -- -- --
Payments under revolving credit facility (29,500) -- -- --
Payments on long-term debt -- (1,975) -- (350)
Distributions to Partners (31,440) (3,615) -- --
Dividend to Parent -- -- -- (8,642)
Return of capital to Parent -- -- (11,359) (5,890)
------------ ------------ ------------ ------------
Net cash provided by (used in)
financing activities (31,440) 65,792 (11,359) (14,882)
------------ ------------ ------------ ------------
NET CHANGE IN CASH AND CASH EQUIVALENTS (1,067) 8,000 -- --
CASH AND CASH EQUIVALENTS AT
BEGINNING OF PERIOD 8,000 -- -- --
------------ ------------ ------------ ------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 6,933 $ 8,000 $ -- $ --
============ ============ ============ ============
See notes to consolidated and combined financial statements.
28
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL (DEFICIT)
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 (IN
THOUSANDS, EXCEPT UNIT DATA)
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)
========= ========= ========= ========= ========= ========= =========
See notes to consolidated and combined financial statements.
29
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
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 AND THE PREDECESSOR PERIOD FROM JANUARY 1, 1999 TO
AUGUST 19, 1999 AND THE YEAR ENDED DECEMBER 31, 1998
- --------------------------------------------------------------------------------
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 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, 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, 2000 and 1999 and the results of their operations, cash
flows and changes in partners' capital (deficit) for the year ended
December 31, 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 periods 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 Resource Management GP,
LLC, a Delaware limited liability company (the "Managing GP"), which as
30
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 of the $121 million of net assets received under the Contribution
Agreement.
Pro Forma Results of Operations (Unaudited)
For the years ended December 31, 1999 and 1998, the pro forma total
revenues would have been approximately $346,828,000 and $361,893,000,
respectively. For the years ended December 31, 1999 and 1998, the pro
forma net income (loss) would have been approximately $7,567,000 and
$(6,740,000) and net income (loss) per limited partner unit would have
been $0.48 and $(0.43), respectively. The pro forma results of
operations for the years ended December 31, 1999 and 1998, 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, and January 1, 1998 through December 31, 1998. 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, 1998. The pro forma adjustments include (i) pro forma
interest on debt assumed by the Partnership and (ii) 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, 2000 and 1999, the estimated fair value of long-term debt was
approximately $230 million and $215 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 MANAGEMENT - The Partnership reclassified outstanding checks of
$4,698,000 and $3,844,000 at December 31, 2000 and 1999, respectively,
to accounts payable in the consolidated balance sheets.
MARKETABLE SECURITIES - The Partnership has investments in six month
U.S. Treasury Notes that are classified as available-for-sale debt
securities. These investments are subject to certain provisions of the
credit facility (Note 7), which could restrict the use of these
investments for financing a required level of
31
capital expenditures within the second anniversary of the credit
facility's effective date. At December 31, 2000, the Partnership has
satisfied the capital expenditure requirements and consequently, the
Partnership's use of the investments is not restricted. At December 31,
2000 and 1999, the cost of these investments 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
(9 to 15 years at the revaluation date of August 1, 1996), whichever is
less and for 5 years on certain assets related to the 1998 business
acquisition. Depreciable lives for mining equipment and processing
facilities range from 1 to 15 years. Depreciable lives for land and land
improvements and depletable lives for mineral rights range from 5 to 15
years. Depreciable lives for buildings, office equipment and
improvements range from 1 to 13 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, 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 the three months ended September 30, 2000, the
Partnership recorded an impairment loss of approximately $2,439,000
relating to certain transloading facility assets, associated with
Seminole Electric's Cooperative, Inc. ("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 the accompanying
consolidated 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 term. The amortization periods
end on various dates from September 2002 to December 2005. Accumulated
amortization for coal supply agreements was $22,139,000 and $18,584,000
at December 31, 2000 and 1999, respectively.
RECLAMATION AND MINE CLOSING COSTS - Estimates of the cost of future
mine reclamation and closing procedures of currently active mines are
recorded on a present value basis. Those costs relate to sealing portals
at underground mines and to reclaiming the final pit and support acreage
at surface mines. Other
32
costs common to both types of mining are related to removing or covering
refuse piles and settling ponds and dismantling preparation plants and
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 current and,
in the case of black lung benefits, future workers' compensation
benefits based on actuarial valuations.
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 is included in the combined U.S. income tax returns of
ARH. The Predecessor has 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. Revenues not arising from
coal sales, which primarily consist of transloading fees, are included
in operating revenues and are recognized as services are performed.
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,
2000 and 1999). 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 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. The Partnership currently has no identified
derivative instruments or hedging activities. Accordingly, this standard
had no material effect on the Partnership's consolidated financial
statements upon adoption.
During the fourth quarter 2000, the Partnership adopted Financial
Accounting Standards Board Emerging Issues Task Force Issue No. 00-10
"Accounting for Shipping and Handling Fees and Costs." Accordingly, the
Partnership reflects the cost of transporting coal to customers through
third party carriers as transportation expenses and the corresponding
reimbursement of these costs through customer billings as transportation
revenues in the consolidated and combined statements of income. These
amounts were previously offset. There was no cumulative effect on net
income and the prior
33
periods' consolidated and combined statements of income have been
reclassified to comply with this presentation.
RECLASSIFICATIONS - Certain reclassifications have been made to the 1999
and 1998 combined and consolidated financial statements to conform to
the classifications used in 2000.
3. BUSINESS ACQUISITION
Effective January 23, 1998, the Predecessor acquired substantially all
of the assets and assumed certain liabilities, excluding working
capital, of an unrelated coal company's west Kentucky coal operations,
now Hopkins County Coal, LLC, for cash of approximately $7,310,000 and
direct acquisition costs of $821,000. The acquisition was accounted for
using the purchase method of accounting. Accordingly, the purchase price
was allocated to the assets acquired and liabilities assumed based on
their estimated fair values of $25,320,000 and $17,189,000,
respectively. The results of operations are included in the
Partnership's consolidated and combined financial statements from the
acquisition date and are not considered significant.
4. UNUSUAL ITEMS
The Unusual items for the years ended December 31, 2000 and 1998 are as
follows (in thousands):
YEAR ENDED
DECEMBER 31,
---------------------
2000 1998
-------- --------
Gain on settlement of transloading facility dispute $(12,141) $ --
Litigation matters 2,675 --
Temporary mine closings -- 5,211
-------- --------
$ (9,466) $ 5,211
======== ========
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. 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.
In response to market conditions, one of the Predecessor's operating
mines ceased operations and terminated all of its workforce in September
1998. Management planned to maintain the mine in an indefinite idle
status pending improvement in market conditions. Shortly after the mine
closure, management executed a long-term coal supply contract for the
mine and the mine resumed production in late 1998. During the idle
status period, the mine incurred a net loss of approximately $5,211,000
consisting of estimated amounts for increased workers' compensation
claims of $1,200,000 and severance payments consistent with the federal
Worker Adjustment and Retraining Notification, or "WARN" Act, of
$1,200,000 as well as the costs associated with maintaining the idled
mine of $2,811,000.
34
5. INVENTORIES
Inventories consist of the following at December 31, (in thousands):
2000 1999
------- -------
Coal $ 5,140 $15,180
Supplies 5,702 5,950
------- -------
$10,842 $21,130
======= =======
6. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consists of the following at December 31,
(in thousands):
2000 1999
--------- ---------
Mining equipment and processing facilities $ 267,287 $ 236,252
Land and mineral rights 17,686 17,282
Buildings, office equipment and improvements 24,224 17,780
Construction in progress 11,248 6,907
--------- ---------
320,445 278,221
Less accumulated depreciation, depletion and amortization (135,782) (102,709)
--------- ---------
$ 184,663 $ 175,512
========= =========
7. LONG-TERM DEBT
Long-term debt consists of the following at December 31, (in thousands):
2000 1999
--------- ---------
Senior notes $ 180,000 $ 180,000
Term loan 50,000 50,000
--------- ---------
230,000 230,000
Less current maturities (3,750) --
--------- ---------
$ 226,250 $ 230,000
========= =========
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 consisting 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 purchased $50 million of U.S. Treasury Notes,
which secure the term loan. The U.S. Treasury Notes may be liquidated
for the sole purpose of funding capital expenditures. Through December
31, 2000, the Partnership had liquidated approximately $15.5 million of
U.S. Treasury Notes to fund various qualifying capital expenditures.
35
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 ("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, 2000
and 1999 were 7.77% and 7.07%, 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, 2000 and 1999. The credit facility expires in August
2004.
The senior notes and credit facility are guaranteed by Alliance Coal,
LLC and all of its subsidiaries. In addition, the credit facility is
further secured by a pledge of treasury securities, which upon written
notice, are released for purposes of financing qualifying capital
expenditures of the Intermediate Partnership or its subsidiaries. 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. The
Partnership was in compliance with the covenants of both the credit
facility and senior notes at December 31, 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 term of the notes.
Aggregate maturities of long-term debt are as follows (in thousands):
YEAR ENDING
DECEMBER 31,
2001 $ 3,750
2002 15,000
2003 16,250
2004 15,000
2005 18,000
Thereafter 162,000
--------
$230,000
========
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
36
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 not accrue arrearages with
respect to distributions for any quarter after the subordination period
and 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, 2000, quarterly distributions of $0.50 per unit
were paid to the common and subordinated unitholders. On January 24,
2001, the Partnership declared a MQD, for the period from October 1,
2000 to December 31, 2000, of $0.50 per unit, totaling approximately
$7,703,000 on its outstanding Common and Subordinated Units, payable on
February 14, 2001 to all unitholders of record on January 31, 2001.
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):
FOR THE
PERIOD FROM
JANUARY 1, 1999 YEAR ENDED
TO DECEMBER 31,
AUGUST 19, 1999 1998
--------------- ----------
Current:
Federal $ 3,376 $ 4,815
State 483 801
------- -------
3,859 5,616
Deferred:
Federal 595 (1,531)
State 44 (219)
------- -------
639 (1,750)
------- -------
Income tax expense $ 4,498 $ 3,866
======= =======
37
A reconciliation of the statutory U.S. federal income tax rate and the
Predecessor's effective income tax rate is as follows:
FOR THE
PERIOD FROM
JANUARY 1, 1999 YEAR ENDED
TO DECEMBER 31,
AUGUST 19, 1999 1998
--------------- ----------
Statutory rate 35% 35%
Increase (decrease) resulting from:
Excess of tax over book depletion (21) (29)
Alternative minimum tax credit
carryforwards 3 6
State income taxes, net of federal
benefit 3 4
Valuation allowance 10 14
Other 1 1
--- ---
Effective income tax rate 31% 31%
=== ===
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):
FROM
COMMENCEMENT
YEAR OF OPERATIONS
ENDED (ON AUGUST 20, 1999)
DECEMBER 31, TO
2000 DECEMBER 31, 1999
------------ --------------------
Net income per limited partner unit $15,269 $ 6,147
Weighted average limited partner units - basic 15,405 15,405
Basic net income per limited partner unit $ 0.99 $ 0.40
======= =======
Weighted average limited partner units - basic 15,405 15,405
Units contingently issuable:
Restricted units for Long-Term Incentive Plan 142 --
Directors' compensation units deferred 4 --
------- -------
Weighted average limited partner units,
assuming dilutive effect of restricted units 15,551 15,405
------- -------
Diluted net income per limited partner unit $ 0.98 $ 0.40
======= =======
38
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 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. 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, the Compensation Committee approved initial grants of
142,100 restricted units, which vest at the end of the subordination
period, which will generally not end before September 30, 2004. During
2000, the Managing GP billed the Partnership approximately $538,000
attributable to the LTIP. The Partnership has recorded this amount as
compensation expense. Effective January 1, 2001, the Compensation
Committee approved additional grants of 131,490 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
$1,590,000 for the year ended December 31, 2000 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, and $1,944,000 for the year ended December 31, 1998.
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.
39
The following sets forth changes in benefit obligations and plan assets
for the years ended December 31, 2000 and 1999 and the funded status of
the plans reconciled with amounts reported in the Partnership's
consolidated and the Predecessor's combined financial statements at
December 31, 2000 and 1999, respectively. The Partnership and
Predecessor periods for 1999 have been combined. Since the Partnership
maintained the historical basis of the Predecessor's net assets,
management believes that the combined Partnership and Predecessor
amounts for 1999 are comparable with 2000 (dollars in thousands):
2000 1999
-------- --------
CHANGE IN BENEFIT OBLIGATIONS:
Benefit obligations at beginning of year $ 7,774 $ 6,742
Service cost 1,971 2,107
Interest cost 596 452
Actuarial (gain) loss (136) (1,435)
Benefits paid (70) (92)
-------- --------
Benefit obligation at end of year 10,135 7,774
-------- --------
CHANGE IN PLAN ASSETS:
Fair value of plan assets at beginning of year 8,265 2,911
Employer contribution 1,100 4,736
Actual return on plan assets 205 710
Benefits paid (70) (92)
-------- --------
Fair value of plan assets at end of year 9,500 8,265
-------- --------
Funded status (635) 491
Unrecognized prior service cost 284 332
Unrecognized actuarial (gain) loss (828) (1,273)
-------- --------
Net amount recognized $ (1,179) $ (450)
======== ========
WEIGHTED-AVERAGE ASSUMPTIONS AS OF DECEMBER 31:
Discount rate 7.50 % 7.75 %
Expected return on plan assets 9.00 % 9.00 %
COMPONENTS OF NET PERIODIC BENEFIT COST:
Service cost $ 1,971 $ 2,107
Interest cost 596 452
Expected return on plan assets (737) (413)
Prior service cost 48 48
Net gain (49) --
-------- --------
Net periodic benefit cost $ 1,829 $ 2,194
======== ========
Effect on minimum pension liability $ -- $ (459)
======== ========
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
40
timing of future reclamation and mine closing costs and recorded those
estimates on a present value basis using a 6% discount rate.
Discounting resulted in reducing the accrual for reclamation and mine
closing costs by $10,420,000 and $5,489,000 at December 31, 2000 and
1999, respectively. Estimated payments of reclamation and mine closing
costs as of December 31, 2000 are as follows (in thousands):
2001 $ 1,078
2002 1,191
2003 1,594
2004 2,147
2005 2,511
Thereafter 17,917
-------
Aggregate undiscounted reclamation and mine closing 26,438
Effect of discounting 10,420
-------
Total reclamation and mine closing costs 16,018
Less current portion 1,078
-------
Reclamation and mine closing costs $14,940
=======
The following table presents the activity affecting the reclamation and
mine closing liability (in thousands):
PARTNERSHIP PREDECESSOR
------------------------------------ -----------------------------------
FROM
COMMENCEMENT FOR THE
YEAR OF OPERATIONS PERIOD FROM YEAR
ENDED (ON AUGUST 20, 1999) JANUARY 1, 1999 ENDED
DECEMBER 31, TO TO DECEMBER 31,
2000 DECEMBER 31, 1999 AUGUST 19, 1999 1998
------------ -------------------- --------------- ------------
Beginning balance $ 14,796 $ 13,856 $ 13,800 $ 5,439
Accrual 1,074 348 457 705
Payments (764) (394) (401) (1,544)
Allocation of liability associated
with acquisition and mine
development 912 986 -- 9,200
-------- -------- -------- --------
Ending balance $ 16,018 $ 14,796 $ 13,856 $ 13,800
======== ======== ======== ========
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. These subsidiaries provide
self-insurance accruals, determined by independent actuaries, at the
present value of the actuarially computed present and future liabilities
for such benefits. The actuarial studies utilize a 6% discount rate and
various assumptions as to the frequency of future claims, inflation,
employee turnover and life expectancies.
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 for the
Predecessor period from January 1,
41
1999 to August 19, 1999, and the year ended December 31, 1998 was
$123,000, $(1,028,000), $726,000, and $1,139,000, respectively.
The U.S. Department of Labor has issued revised regulations that could
alter the claims process for the federal black lung benefit recipients.
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 through litigation certain
provisions of the revised regulations. The impact of the revised
regulations on the Partnership's liability for future black lung claims
cannot be determined at this time.
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, accounting, budget and
planning, treasury, public relations, land administration, environmental
and permitting management, payroll and benefits management, disability
and 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 reimbursed
to the Managing GP and its affiliates by the Partnership were
approximately $3,899,000 and $1,283,000 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, 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
and $2,595,000 for the period from January 1, 1999 to August 19, 1999
and for the year ended December 31, 1998, respectively. Management is of
the opinion that the allocations used are 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, 2000 and 1999 the Managing GP had purchased 164,000
Common Units in the open market at prevailing market prices.
In September 2000, the Special GP acquired coal reserves and the right
to acquire additional coal reserves that are (a) contiguous to the
Webster County Coal, LLC ("WCC") mining complex ("Providence No. 3
Reserves") and (b) contiguous to the 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.
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 the first annual minimum royalty of $2.7 million in 2000. Under
the terms of the
42
HCC option to lease and sublease, HCC paid an option fee of $645,000 in
2000. The anticipated annual minimum royalty obligation is $684,000
payable in advance, from 2001 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.
Separately, on December 29, 2000, the Partnership entered into a
noncancelable operating lease arrangement with the Special GP for a
"build-to-suit" coal preparation plant and ancillary facilities at the
Gibson County Coal, LLC mining complex that was constructed and is
currently owned by the Special GP. This lease arrangement qualified for
sale-leaseback accounting treatment, and consequently, the Partnership
has removed the corresponding asset and liability associated with the
coal preparation plant from its consolidated balance sheet. Based on the
terms of the lease, the Partnership will make monthly payments of
approximately $216,000 for 121 months. Lease expense incurred for the
year ended December 31, 2000 was approximately $14,000.
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):
43
AFFILIATE OTHERS TOTAL
--------- ------ -----
Year ending December 31,
2001 $ 2,595 $ 452 $ 3,047
2002 2,595 408 3,003
2003 2,595 274 2,869
2004 2,595 284 2,879
2005 2,595 284 2,879
Thereafter 13,190 780 13,970
------- ------- -------
$26,165 $ 2,482 $28,647
======= ======= =======
Lease expense under all operating leases was $1,409,000, $801,000,
$496,000, and $1,169,000 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, and the year ended December 31, 1998,
respectively.
CONTRACTUAL COMMITMENTS - In connection with the expansion of an
existing mine into adjacent coal reserves, the Partnership has entered
into contractual commitments for mine development of approximately $22.5
million at December 31, 2000.
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 our mining operations, which is reflected in "Unusual items" in
the accompanying consolidated and combined statements of income. 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.
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 railroad and/or barge
freight rates. Total revenues to major customers, including
transportation revenues (Note 2), which exceed ten percent of total
revenues are as follows (in thousands):
PARTNERSHIP PREDECESSOR
-------------------------------------- --------------------------------------
FROM
COMMENCEMENT FOR THE
YEAR OF OPERATIONS PERIOD FROM YEAR
ENDED (ON AUGUST 20, 1999) JANUARY 1, 1999 ENDED
DECEMBER 31, TO TO DECEMBER 31,
2000 DECEMBER 31, 1999 AUGUST 19, 1999 1998
------------ ----------------- --------------- ------------
Customer A $67,234 $23,104 $38,875 $62,642
Customer B 61,007 26,993 40,752 57,233
Customer C 58,498 16,090 31,328 74,076
Customer D 38,713 11,926 19,582 --
44
Trade accounts receivable from these customers totaled approximately
$18.1 million at December 31, 2000. The Partnership's bad debt
experience has historically been insignificant. Based on current
evaluations, Partnership management believes that no allowance is
required to absorb potential uncollectible balances. However, changes in
the 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 2006, 2001, 2010 and 2006,
respectively.
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):
PARTNERSHIP PREDECESSOR
----------------------------------- ------------------------------------
FROM
COMMENCEMENT FOR THE
YEAR OF OPERATIONS PERIOD FROM YEAR
ENDED (ON AUGUST 20, 1999) JANUARY 1, 1999 ENDED
DECEMBER 31, TO TO DECEMBER 31,
2000 DECEMBER 31, 1999 AUGUST 19, 1999 1998
------------ ----------------- --------------- ------------
Revenues:
United States $363,469 $134,125 $221,339 $348,055
Other foreign countries -- -- 10,494 55,246
-------- -------- -------- --------
$363,469 $134,125 $231,833 $403,301
======== ======== ======== ========
Long-lived assets:
United States $210,996 $203,697 $200,057 $204,078
Other foreign countries -- -- -- --
-------- -------- -------- --------
$210,996 $203,697 $200,057 $204,078
======== ======== ======== ========
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):
PARTNERSHIP PREDECESSOR
--------------------------------- --------------------------------
FROM
COMMENCEMENT FOR THE
YEAR OF OPERATIONS PERIOD FROM YEAR
ENDED (ON AUGUST 20, 1999) JANUARY 1, 1999 ENDED
DECEMBER 31, TO TO DECEMBER 31,
2000 DECEMBER 31, 1999 AUGUST 19, 1999 1998
------------ ----------------- --------------- ------------
Cash paid for:
Interest $ 19,043 $ 1,173 $ -- $ --
Income taxes paid through
Parent (Note 9) -- -- 3,504 3,135
Non-cash investing and financing activities:
Debt transferred from Special GP -- 230,000 -- --
Marketable securities transferred -- --
from Special GP -- 15,486 -- --
19. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
On August 20, 1999, the Partnership completed its IPO in which the
Partnership became the successor to the business of the Predecessor.
Accordingly, no recognition has been given to income taxes in the
45
financial statements of the Partnership as income taxes will be borne by
the partners and not the Partnership. Additionally, interest expense
associated with the debt incurred concurrent with the closing of the IPO
is applicable only to the Partnership period. Accordingly, the quarterly
operating results prior to August 20, 1999 are not necessarily
comparable to subsequent periods.
A summary of the quarterly operating results for the Partnership and
Predecessor is as follows (in thousands, except unit and per unit data):
PARTNERSHIP
QUARTER ENDED
------------------------------------------------------------------
MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31,
2000 2000 2000 (1) 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
PREDECESSOR PARTNERSHIP
------------------------------------------- ------------------------------------
FROM
COMMENCEMENT
OF OPERATIONS
QUARTER ENDED JULY 1, 1999 (ON AUGUST 20, 1999)
-------------------------- TO TO QUARTER ENDED
MARCH 31, JUNE 30, AUGUST 19, SEPTEMBER 30, DECEMBER 31,
1999 1999 1999 1999 1999
----------- ----------- ------------ -------------------- -------------
Revenues $ 87,876 $ 93,395 $ 50,562 $ 45,758 $ 88,367
Operating income 4,273 6,995 3,004 5,019 6,499
Net income 2,969 4,934 2,302 3,509 2,763
Basic and diluted net
income per unit -- -- -- $ 0.22 $ 0.18
Weighted average number
of units outstanding - basic
and diluted -- -- -- 15,405,311 15,405,311
(1) 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.
******
46
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The Special GP owns 1,232,780 Common Units and 6,422,531 Subordinated
Units representing an aggregate 48.7% limited partner interest in the
Partnership. In addition, the General Partners own, on a combined basis, an
aggregate 2% general partner interest in the Partnership, the Intermediate
Partnership and the subsidiaries. The Managing GP's ability, as managing general
partner, to manage and operate the Partnership and its ownership of 164,000
Common Units together with the Special GP's ownership of 1,232,780 Common Units
and 6,422,531 Subordinated Units, effectively gives the General Partners the
ability to veto some actions of the Partnership and to control the management of
the Partnership.
UNIT PURCHASE PROGRAM BY THE MANAGING GP
The Managing GP 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, 2000, the Managing GP has purchased
164,000 Common Units. The Common Units purchased by the Managing GP retain their
rights to receive quarterly distributions of Available Cash.
TRANSACTIONS BETWEEN THE PARTNERSHIP, SPECIAL GP AND ARH
In September 2000, the Special GP 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 reserves
were transferred to SGP Land, LLC (SGP Land), a newly formed wholly-owned
subsidiary of the Special GP.
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 immediately 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 the first annual minimum royalty of $2.7 million in 2000. Under the
terms of the Hopkins County Coal option to lease and sub-lease, Hopkins County
Coal paid an option fee of $645,000 in 2000. The anticipated annual minimum
royalty obligation is $684,000 payable in advance, from 2001 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
47
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.
Separately, we entered into a noncancelable operating lease arrangement
with the Special GP 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, the Partnership began making monthly
payments commencing January 1, 2001, of approximately $216,000 for 121 months.
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 2000, we made interest payments to
Chase on outstanding borrowings and paid Chase customary fees for their other
services. We expect that these relationships will continue in 2001. The Beacon
Group is an affiliate of Chase. Messrs. MacWilliams and Miller are General
Partners of the Beacon Group and Directors of the Managing GP.
OMNIBUS AGREEMENT
Concurrent with the closing of the IPO, we entered into an Omnibus
Agreement with ARH and the General Partners, which governs potential competition
among us and the other parties to this agreement. ARH 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 GP, not to engage in
the business of mining, marketing or transporting coal in the U.S. unless it
first offers the Partnership the opportunity to engage in a potential activity
or acquire a potential business, and the Board of Directors of the Managing GP,
with the concurrence of its Conflicts Committee, elects to cause us not to
pursue such opportunity or acquisition. In addition, ARH has the ability to
purchase businesses, the majority value of which is not mining, marketing or
transporting coal, provided ARH offers the Partnership the opportunity to
purchase the coal assets following their acquisition. The restriction does not
apply to the assets retained and business conducted by ARH at the closing of the
IPO. Except as provided above, ARH and its controlled affiliates are prohibited
from engaging
48
in activities in which they compete directly with the Partnership. In addition,
The Beacon Group, and the funds it manages, are prohibited from owning or
engaging in businesses which compete with the Partnership. In addition to its
non-competition provisions, this agreement contains provisions which indemnify
the Partnership against liabilities associated with certain assets and
businesses of ARH which were disposed of or liquidated prior to consummating the
IPO.
49
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 28th, 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.
SIGNATURE TITLE DATE
--------- ----- ----
/s/ Joseph W. Craft III President, Chief Executive March 28, 2002
- ---------------------------------- Officer and Director
Joseph W. Craft III (Principal Executive Officer)
/s/ Michael L. Greenwood Senior Vice President, March 28, 2002
- ---------------------------------- Chief Financial Officer
Michael L. Greenwood and Treasurer
(Principal Financial Officer and
Principal Accounting Officer)
/s/ John J. MacWilliams Director March 28, 2002
- ----------------------------------
John J. MacWilliams
/s/ Preston R. Miller, Jr. Director March 28, 2002
- ----------------------------------
Preston R. Miller, Jr.
/s/ John P. Neafsey Director March 28, 2002
- ----------------------------------
John P. Neafsey
/s/ John H. Robinson Director March 28, 2002
- ----------------------------------
John H. Robinson
/s/ Robert G. Sachse Executive Vice President and Director March 28, 2002
- ----------------------------------
Robert G. Sachse
/s/ Paul R. Tregurtha Director March 28, 2002
- ----------------------------------
Paul R. Tregurtha
50