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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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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, 2001
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM _____________TO_____________
COMMISSION FILE NO.: 0-26823
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ALLIANCE RESOURCE PARTNERS, L.P.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 73-1564280
(STATE OR OTHER JURISDICTION OF (IRS EMPLOYER IDENTIFICATION NO.)
INCORPORATION OR ORGANIZATION)
1717 SOUTH BOULDER AVENUE, SUITE 600, TULSA, OKLAHOMA 74119
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES AND ZIP CODE)
(918) 295-7600
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
common units representing limited partner interests
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Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
The aggregate value of the common units held by non-affiliates of the
registrant (treating all executive officers and directors of the registrant, for
this purpose, as if they may be affiliates of the registrant) was approximately
$178,670,542 on March 28, 2002, based on $24.18 per unit, the closing price of
the common units as reported on the Nasdaq National Market on such date.
As of March 28, 2002, 8,982,780 common units and 6,422,531 subordinated
units are outstanding.
DOCUMENTS INCORPORATED BY REFERENCE: None
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This Form 10-K/A for the year ended December 31, 2001 reflects a
modification for a typographical error relating to the "Pro Forma Net Income
Assuming Accounting Change Is Applied Retroactively" for the year ended December
31, 2001 as presented in the Consolidated and Combined Statements of Income for
the Years Ended December 31, 2001 and 2000, and the Period From the
Partnership's Commencement of Operations (On August 20, 1999) to December 31,
1999, and the Predecessor Period from January 1, 1999 to August 19, 1999.
Additionally, we have corrected a misclassification of 3.1 million tons of coal
reserves between Mettiki and Mettiki (WV) as set forth in the table of coal
reserves under Item 2. Properties, and as described in the "Maryland Operations"
discussion under Item 1. Business.
PART I
ITEM 1. BUSINESS
GENERAL
We are a diversified producer and marketer of coal to major United States
utilities and industrial users. We began mining operations in 1971 and, since
then, have grown through acquisitions and internal development to become the
eighth largest coal producer in the eastern United States. At December 31, 2001,
we had approximately 400.7 million tons of reserves in Illinois, Indiana,
Kentucky, Maryland and West Virginia. In 2001, we produced 15.7 million tons of
coal and sold 17.0 million tons of coal. The coal we produced in 2001 was 28.7%
low-sulfur coal, 17.2% medium-sulfur coal and 54.1% high-sulfur coal. In 2001,
approximately 91% of our medium- and high-sulfur coal was sold to utility plants
with installed pollution control devices, also known as "scrubbers," to remove
sulfur dioxide. We classify low-sulfur coal as coal with a sulfur content of
less than 1%, medium-sulfur coal as coal with a sulfur content between 1% and 2%
and high-sulfur coal as coal with a sulfur content of greater than 2%.
We currently operate seven mining complexes in Illinois, Indiana, Kentucky
and Maryland. Six of our mining complexes are underground and one has multiple
surface operations and a single underground mine. Our mining activities are
organized into three operating regions: (a) the Illinois Basin operations, (b)
the East Kentucky operations, and (c) the Maryland operations.
We and our subsidiary, Alliance Resource Operating Partners, L.P. (referred
to as the intermediate partnership), were formed to acquire, own and operate
substantially all of the coal production and marketing assets of Alliance
Resource Holdings, Inc., a Delaware corporation formerly known as Alliance Coal
Corporation. We completed our initial public offering on August 20, 1999, at
which time Alliance Resource Holdings contributed substantially all of its
operating assets and liabilities to the intermediate partnership.
Our managing general partner, Alliance Resource Management GP, LLC, and our
special general partner, Alliance Resource GP, LLC (collectively referred to as
our general partners) own an aggregate 2% general partner interests in us. Our
limited partners, including the general partners as holders of common units and
subordinated units, own an aggregate 98% of the limited partner interests in us.
The coal production and marketing assets of Alliance Resource Holdings
acquired by us are referred to as our "predecessor." All 1999 operating data
contained herein includes our results and our predecessor's results.
MINING OPERATIONS
We produce a diverse range of steam coals with varying sulfur and heat
contents, which enables us to satisfy the broad range of specifications required
by our customers. The following chart summarizes our production by region for
the last five years.
OPERATING REGION AND MINES 2001 2000 1999 1998 1997
-------------------------- ---- ---- ---- ---- ----
(TONS IN MILLIONS)
Illinois Basin Operations:
Dotiki, Pattiki, Hopkins County, Gibson County 10.2 8.4 8.5 7.9 5.2
East Kentucky Operations:
Pontiki, MC Mining 2.8 2.7 2.8 2.5 2.8
Maryland Operations:
Mettiki 2.7 2.6 2.8 3.0 2.9
---- ---- ---- ---- ----
Total 15.7 13.7 14.1 13.4 10.9
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ILLINOIS BASIN OPERATIONS
Our Illinois Basin mining operations are located in western Kentucky,
southern Illinois and southern Indiana. We have approximately 975 employees in
the Illinois Basin and currently operate four mining complexes.
Webster County Coal, LLC. Webster County Coal operates the Dotiki mine,
which is an underground mining complex, located near Providence, Kentucky in
Webster and Hopkins Counties, Kentucky. The mine was opened in 1966, and we
purchased the mine in 1971. Our Dotiki operation utilizes continuous mining
units employing room-and-pillar mining techniques. The preparation plant has a
throughput capacity of 1,000 tons of raw coal an hour.
Production from the mine is shipped via the CSX railroad, the Paducah &
Louisville railroad and by truck on U.S. and state highways. Our primary
customers for coal produced at Dotiki are Seminole Electric Cooperative, Inc.
(Seminole), Tennessee Valley Authority (TVA) and Western Kentucky Energy Corp.
(WKE), which purchase our coal pursuant to long-term contracts for use in their
scrubbed generating units. During August 2001, Dotiki began construction of a
new mine shaft and ancillary facilities, which is expected to be operational in
late 2002 and will provide a new access for miners and supplies.
White County Coal, LLC. White County Coal operates the Pattiki mine, which
is an underground mining complex, located near New Harmony, Indiana in White
County, Illinois. We began construction of the mine in 1980 and have operated it
since its inception. Our Pattiki operation utilizes continuous mining units
employing room-and-pillar mining techniques. We are in the process of extending
our Pattiki mine into adjacent coal reserves, which will include two new shafts
and ancillary facilities. This extension involves capital expenditures of
approximately $30 million during the 2000-2003 period and allows the Pattiki
mining complex to continue and expand its existing productive capacity for the
next 15 years. The preparation plant has a throughput capacity of 1,000 tons of
raw coal an hour.
Production from the mine is shipped via the CSX railroad. Our primary
customers for coal produced at Pattiki are Seminole and Cincinnati Gas &
Electric Company, which purchase our coal pursuant to long-term contracts for
use in their scrubbed generating units.
Hopkins County Coal, LLC. Hopkins County Coal is a mining complex located
near Madisonville, Kentucky in Hopkins County, Kentucky. We acquired Hopkins
County Coal in January 1998, and consistent with our acquisition plans,
purchased new mining equipment and completed extensive equipment rebuilds during
1998. The operation has three surface mines, one of which is currently idle, and
one underground mine. The surface operations utilize dragline mining, and the
underground operation utilizes a continuous mining unit employing
room-and-pillar mining techniques. The preparation plant has a throughput
capacity of 1,000 tons of raw coal an hour.
Production from the complex is shipped via the CSX and the Paducah &
Louisville railroads and by truck on U.S. and state highways. Our primary
customers for coal produced at Hopkins County Coal have been Louisville Gas &
Electric Company (LG&E), TVA and WKE, which have purchased our coal pursuant to
long-term contracts for use in their scrubbed generating units. As discussed
under "Other Operations; Coal Synfuel" below, we now sell most of Hopkins County
Coal's production to the synfuel facility owner, which in turn sells coal
synfuel to LG&E, TVA and other potential customers. We have put in place
"back-up" coal supply agreements with these customers, which automatically
provide for sale of our coal to them in the event they do not receive coal
synfuel.
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Gibson County Coal, LLC. Gibson County Coal is an underground mining
complex located near Princeton, Indiana in Gibson County, Indiana. In October
1999, we announced the award of engineering and construction contracts for the
development of dual mine slopes and a mine shaft to support mining operations.
Subsequent contracts were awarded by our special general partner for the
construction of a coal preparation plant and handling facilities, providing us
access to these facilities under a long-term operating lease agreement. The mine
began production with a single mining unit in November 2000. The Gibson County
mining complex utilizes multiple continuous mining units employing
room-and-pillar mining techniques. The preparation plant has a throughput
capacity of 700 tons of raw coal an hour.
Production from Gibson County Coal is a low-sulfur coal, shipped via truck
approximately 10 miles on U.S. and state highways to our primary customer, PSI
Energy Inc. (PSI), a subsidiary of Cinergy Corporation. In 1997, we acquired an
additional 99.9 million tons of undeveloped recoverable reserves in Gibson
County, which are not contiguous to the reserves currently being mined. We refer
to these reserves as the Gibson County "South" reserves.
EAST KENTUCKY OPERATIONS
Our East Kentucky mining operations are located in the Central Appalachia
coal fields. Our East Kentucky mines produce low-sulfur coal. We have
approximately 435 employees and operate two mining complexes in East Kentucky.
Pontiki Coal, LLC. Pontiki is an underground mining complex located near
Inez, Kentucky in Martin County, Kentucky. We constructed the mine in 1977.
Pontiki owns the mining complex and reserves and Excel Mining LLC, an affiliate
of Pontiki, is responsible for conducting all mining operations. Substantially
all of the coal produced at Pontiki meets or exceeds the compliance requirements
of Phase II of the Clean Air Act amendments. Our Pontiki operation utilizes
continuous mining units employing room-and-pillar mining techniques. The
preparation plant has a throughput capacity of 800 tons of raw coal an hour.
Production from the mine is shipped via the Norfolk Southern railroad or by
truck via U.S. and state highways to various docks on the Big Sandy River in
Kentucky. Our primary customers for coal produced at Pontiki are James River
Cogeneration Company, the successor to Cogentrix of Virginia, Inc., and AEI Coal
Sales Company, Inc.
MC Mining, LLC. MC Mining is an underground mining complex located near
Pikeville, Kentucky in Pike County, Kentucky. MC Mining was acquired in 1989.
When we began operations in late 1996, MC Mining was operated by an unaffiliated
contract mining company. During 2000, the contract mining agreement was
terminated and MC Mining entered into an intercompany support services agreement
with Excel Mining. Selected employees of the contractor and other qualified
individuals were hired by Excel Mining, which is responsible for conducting all
mining operations. The operation utilizes continuous mining units employing
room-and-pillar mining techniques. The preparation plant has a throughput
capacity of 800 tons of raw coal an hour.
Production from the mine is shipped via the CSX railroad or by truck via
U.S. and state highways to various docks on the Big Sandy River. MC Mining sells
its low-sulfur production primarily in the spot market.
MARYLAND OPERATIONS
Our Maryland mining operation is located in the Northern Appalachia coal
fields. We have approximately 235 employees and operate one mining complex in
Maryland.
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Mettiki Coal, LLC. Mettiki is an underground longwall mining complex
located near Oakland, Maryland in Garrett County, Maryland. We constructed
Mettiki in 1977 and have operated it since its inception. The operation utilizes
a longwall miner for the majority of the coal extraction as well as continuous
mining units used to prepare the mine for future longwall mining. The
preparation plant has a throughput capacity of 1,350 tons of raw coal an hour.
Our primary customer for coal produced at Mettiki is Virginia Electric and
Power Company (VEPCO), which purchases the coal pursuant to a long-term contract
for use in the generating units at its Mt. Storm, West Virginia power plant,
located less than 20 miles away. Our coal is trucked to Mt. Storm over a private
haul road, which links to a state highway. Mettiki is also served by the CSX
railroad. We also process coal at Mettiki for Anker Energy Corporation and one
of its affiliates.
Mettiki Coal (WV), LLC. Mettiki (WV) has approximately 18.9 million tons of
undeveloped recoverable reserves in Grant and Tucker Counties, West Virginia
adjacent to Mettiki in Garrett County, Maryland. We currently conduct no mining
operations at Mettiki (WV).
OTHER OPERATIONS
MT. VERNON TRANSFER TERMINAL, LLC
The Mt. Vernon terminal is a rail-to-barge loading terminal on the Ohio
River in Mt. Vernon, Indiana. The terminal has a capacity of 5.5 million tons
per year with existing ground storage. The terminal was used from 1983 through
1998 for shipments from Pattiki and Dotiki under our coal supply agreement with
Seminole. Seminole now transports these shipments to its generating units
directly by CSX railroad. We recently entered into coal supply agreements that
are intended to ship approximately 1.4 million tons through the Mt. Vernon
terminal in 2002.
COAL SYNFUEL
We recently entered into long-term agreements with Synfuel Solutions
Operating LLC (SSO) to host and operate its coal synfuel facility at Hopkins
County Coal, supply coal feedstock, assist with the coal synfuel marketing and
provide other services through December 31, 2007. These agreements provide us
with coal sales and service fees from SSO based on the synfuel facility
throughput tonnage, which amounts are dependent on the ability of the facility's
owners to use certain qualifying tax credits applicable to the facility. A
portion of these services will be performed by a newly formed subsidiary,
Alliance Service, Inc., which is subject to federal and state income tax. As
discussed above in "Mining Operations; Illinois Basin; Hopkins County Coal", we
now sell most of the coal produced at our Hopkins County Coal mining complex to
SSO, while Alliance Coal Sales, an unincorporated sales business unit of
Alliance Coal, assists SSO with the sale of its coal synfuel to our customers
pursuant to a sales agency agreement. The term of each of these agreements is
subject to early cancellation provisions customary for transactions of these
types, including the unavailability of synfuel tax credits, the termination of
associated coal synfuel sales contracts, and the occurrence of certain force
majeure events. Therefore, the continuation of the operating revenues associated
with the coal synfuel production facility cannot be assured. However, we have
put in place "back up" coal supply agreements with each coal synfuel customer,
which automatically provide for sale of our coal to them in the event they do
not receive coal synfuel.
COAL BROKERAGE
We buy coal from outside producers throughout the eastern United States,
which we then resell, both directly and indirectly, to utility and industrial
customers. We purchased and sold approximately 535,000 tons
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of outside coal in 2001. We have a policy of matching our outside coal purchases
and sales to minimize market risks associated with buying and reselling coal.
ADDITIONAL SERVICES
We develop and market additional services in order to establish ourselves
as the supplier of choice for our customers. Examples of the kind of services we
have offered to date include ash and scrubber sludge removal, coal yard
maintenance, and arranging alternate transportation services.
COAL MARKETING and SALES
As is customary in the coal industry, we have entered into long-term
contracts with many of our customers. These arrangements are mutually
beneficial. Our utility customers secure a fuel supply for their power plants
for years into the future. Our long-term contracts contribute to both our
customers' and our stability and profitability by providing greater
predictability of sales volumes and sales prices. In 2001, approximately 78% of
our sales tonnage, accounting for 75% of our total revenue, was sold under
long-term contracts (contracts having a term of greater than one year) with
maturities ranging from 2001 to 2012. Our total nominal commitment under
significant long-term contracts was approximately 84.6 million tons at December
31, 2001 and is expected to be delivered as follows: 15.4 million tons in 2002,
12.6 million tons in 2003, 11.9 million tons in 2004 and 11.6 million tons in
2005 and 2006, and 21.5 million tons thereafter during the remaining terms of
the relevant coal supply agreements. The total commitment of coal under contract
is an approximate number because, in some instances, our contracts contain
provisions that could cause the nominal total commitment to increase or decrease
by as much as 20%. The contractual time commitments for customers to nominate
future purchase volumes under these contracts are sufficient to allow us to
balance our sales commitments with production capacity. In addition, the nominal
total commitment can otherwise change because of price reopener provisions
contained in certain of these long-term contracts. We believe our long-term
contract position compares favorably to those of our competitors.
The terms of long-term contracts are the results of both bidding procedures
and extensive negotiations with the customer. As a result, the terms of these
contracts vary significantly in many respects, including, among others, price
adjustment features, price and contract reopener terms, permitted sources of
supply, force majeure provisions, coal qualities, and quantities. Virtually all
of our long-term contracts are subject to price adjustment provisions which
permit an increase or decrease periodically in the contract price to reflect
changes in specified price indices or items such as taxes, royalties or actual
production costs. These provisions, however, may not assure that the contract
price will reflect every change in production or other costs. Failure of the
parties to agree on a price pursuant to an adjustment or a reopener provision
can lead to early termination of a contract. Some of the long-term contracts
also permit the contract to be reopened to renegotiate terms and conditions
other than the pricing terms, and where a mutually acceptable agreement on terms
and conditions cannot be concluded, either party may have the option to
terminate the contract. The long-term contracts typically stipulate procedures
for quality control, sampling and weighing. Most contain provisions requiring us
to deliver coal within stated ranges for specific coal characteristics such as
heat, sulfur, ash, moisture, grindability, volatility and other qualities.
Failure to meet these specifications can result in economic penalties or
termination of the contracts. While most of the contracts specify the approved
seams and/or approved locations from which the coal is to be mined, some
contracts allow the coal to be sourced from more than one mine or location.
Although the volume to be delivered pursuant to a long-term contract is
stipulated, the buyers often have the option to vary the volume within specified
limits.
RELIANCE on MAJOR CUSTOMERS
Our three largest customers in 2001 were Seminole, TVA and VEPCO. Sales to
these customers in the aggregate accounted for approximately 41% of our 2001
total revenues, and sales to each of these customers
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accounted for more than 10% of our 2001 total revenues. Each of these customers
has purchased coal regularly from us for more than 15 years. In addition, under
the agreements we have entered into with SSO to supply coal feedstock and other
services, we now sell most of the coal produced at our Hopkins County Coal
facility to SSO. SSO, through Alliance Coal Sales, acting as its agent, in turn
sells coal synfuel to our former customers at Hopkins County Coal, including
TVA. As a result, in 2002 it is likely that our coal sales to SSO will account
for more than 10% of our revenues, while our sales to TVA will no longer account
for more than 10% of our revenues.
On February 28, 2002, a major customer of our Pontiki mine (not one of the
three major customers discussed above) voluntarily filed for Chapter 11
bankruptcy protection. Accompanying the bankruptcy filing was a pre-packaged
plan of reorganization unanimously approved by certain creditor classes. The
customer has represented in its bankruptcy filing and public press releases that
all existing trade claims will be paid in full and a vast majority of its
contracts will be continued without any adverse impact. All of the accounts
receivable under the long-term contract with this customer are current.
Management does not anticipate that this event will have a material impact on
our financial condition or results of operations.
COMPETITION
The United States coal industry is highly competitive with numerous
producers in all coal producing regions. We compete with other large producers
and hundreds of small producers in the United States. The largest coal company
is estimated to have sold approximately 15% of the total 2001 tonnage sold in
the United States market. We compete with other coal producers primarily on the
basis of coal price at the mine, coal quality (including sulfur content),
transportation cost from the mine to the customer, and the reliability of
supply. Continued demand for our coal and the prices that we obtain are also
affected by demand for electricity, environmental and government regulations,
technological developments, and the availability and price of alternative fuel
supplies, including nuclear, natural gas, oil, and hydroelectric power.
TRANSPORTATION
Our coal is transported to our customers by rail, truck and barge.
Depending on the proximity of the customer to the mine and the transportation
available for delivering coal to that customer, transportation costs can range
from 10% to 80% of the delivered cost of a customer's coal. As a consequence,
the availability and cost of transportation constitute important factors in the
marketability of coal. We believe our mines are located in favorable geographic
locations that minimize transportation costs for our customers.
Customers pay the transportation costs from the contractual F.O.B. point
(free-on-board point), which is consistent with practice in the industry and is
generally from the mine to the customer's plant. In 2001, the largest volume
transporter of our coal production was the CSX railroad, which moved
approximately 50% of our tonnage over its rail system. The practices of, and
rates set by, the railroad serving a particular mine or customer might affect,
either adversely or favorably, our marketing efforts with respect to coal
produced from the relevant mine. At our Gibson and Mettiki mines, a contractor
operates a truck delivery system that transports the coal from the mine to the
primary customer's power plant.
REGULATION AND LAWS
The coal mining industry is subject to regulation by federal, state and
local authorities on matters such as:
- employee health and safety;
- mine permits and other licensing requirements;
- air quality standards;
- water pollution;
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- storage of petroleum products and substances which are regarded as
hazardous under applicable laws or which, if spilled, could reach
waterways or wetlands;
- storage and handling of explosives;
- plant and wildlife protection;
- reclamation and restoration of mining properties after mining is
completed;
- the discharge of materials into the environment;
- management of solid wastes generated by mining operations;
- protection of wetlands;
- management of electrical equipment containing polychlorinated biphenyls
(PCBs);
- surface subsidence from underground mining;
- the effects (if any) that mining has on groundwater quality and
availability; and
- legislatively mandated benefits for current and retired coal miners.
In addition, the utility industry is subject to extensive regulation
regarding the environmental impact of its power generation activities, which
could affect demand for our coal. The possibility exists that new legislation or
regulations, or new interpretations of existing laws or regulations, may be
adopted that may have a significant impact on our mining operations or our
customers' ability to use coal, or may require us or our customers to change our
or their operations significantly or to incur substantial costs.
We are committed to conducting mining operations in compliance with all
applicable federal, state and local laws and regulations. However, because of
extensive and comprehensive regulatory requirements, violations during mining
operations are not unusual in the industry and, notwithstanding our compliance
efforts, we do not believe these violations can be eliminated completely. None
of the violations to date or the monetary penalties assessed at our operations
have been material.
While it is not possible to quantify the costs of compliance with all
applicable federal and state laws, those costs have been and are expected to
continue to be significant. Capital expenditures for environmental matters have
not been material in recent years. We have accrued for the present value
estimated cost of reclamation and mine closing, including the cost of treating
mine water discharge, when necessary. The accrual for reclamation and mine
closing costs is based upon permit requirements and the costs and timing of
reclamation and mine closing procedures. Although management believes it has
made adequate provisions for all expected reclamation and other costs associated
with mine closures, future operating results would be adversely affected if we
later determine these accruals to be insufficient. Compliance with these laws
has substantially increased the cost of coal mining for all domestic coal
producers.
MINING PERMITS AND APPROVALS
Numerous governmental permits or approvals are required for mining
operations. We may be required to prepare and present to federal, state or local
authorities data pertaining to the effect or impact that any proposed production
of coal may have upon the environment. All requirements imposed by any of these
authorities may be costly and time-consuming, and may delay commencement or
continuation of mining operations. Future legislation and administrative
regulations may emphasize more heavily the protection of the environment and, as
a consequence, our activities may be more closely regulated. Legislation and
regulations, as well as future interpretations of existing laws, may require
substantial increases in equipment and operating costs, or delays, interruptions
or termination of operations, the extent of any of which cannot be predicted.
Before commencing mining on a particular property, we must obtain mining
permits and approvals by state regulatory authorities of a reclamation plan for
restoring, upon the completion of mining, the mined property to its approximate
prior condition, productive use or other permitted condition. Typically, we
commence actions to obtain permits between 18 and 24 months before we plan to
mine a new area. In our experience, permits generally are approved within 12
months after a completed application is submitted. We
7
have not experienced material or significant difficulties in obtaining mining
permits in the areas where our reserves are currently located. However, we
cannot assure you that we will not experience difficulty in obtaining mining
permits in the future.
On January 29, 2002, the West Virginia Department of Environmental
Protection (West Virginia DEP) denied a permit application for the mining of
approximately 3.1 million tons of Mettiki (WV)'s non-reserve coal deposits.
Mettiki planned to mine the tons covered by the denied permit from its existing
underground infrastructure because this portion of Mettiki (WV)'s non-reserve
coal deposits are contiguous to Mettiki's reserves located in Maryland. We have
appealed the permit denial by the West Virginia DEP to the West Virginia Surface
Mining Board and hearings have been scheduled during May 2002.
Under some circumstances, substantial fines and penalties, including
revocation of mining permits, may be imposed under the laws described above.
Monetary sanctions and, in severe circumstances, criminal sanctions may be
imposed for failure to comply with these laws. Regulations also provide that a
mining permit can be refused or revoked if the permit applicant or permittee
owns or controls, directly or indirectly through other entities, mining
operations which have outstanding environmental violations. Although we have
been cited for violations in the ordinary course of our business, we have never
had a permit suspended or revoked because of any violation, and the penalties
assessed for these violations have not been material.
MINE HEALTH AND SAFETY LAWS
Stringent safety and health standards have been imposed by federal
legislation since 1969 when the Coal Mine Health and Safety Act of 1969 (CMHSA)
was adopted. CMHSA resulted in increased operating costs and reduced
productivity. The Federal Mine Safety and Health Act of 1977, which
significantly expanded the enforcement of health and safety standards of CMHSA,
imposes comprehensive safety and health standards on all mining operations.
Regulations are comprehensive and affect numerous aspects of mining operations,
including training of mine personnel, mining procedures, blasting, the equipment
used in mining operations and other matters. The Mine Safety and Health
Administration monitors compliance with these federal laws and regulations. In
addition, as part of CMHSA and the Mine Safety and Health Act of 1977, the Black
Lung Benefits Act requires payments of benefits by all businesses that conduct
current mining operations to a coal miner with black lung disease and to some
survivors of a miner who dies from this disease. Most of the states where we
operate also have state programs for mine safety and health regulation and
enforcement. In combination, federal and state safety and health regulation in
the coal mining industry is perhaps the most comprehensive and rigorous system
for protection of employee safety and health affecting any segment of any
industry. Even the most minute aspects of mine operations, particularly
underground mine operations, are subject to extensive regulation. This
regulation has a significant effect on our operating costs. For example, new
regulations governing exposures to diesel particulate matter in underground
mines will likely increase our compliance costs in 2002. However, our
competitors in all of the areas in which we operate are subject to the same laws
and regulations.
BLACK LUNG BENEFITS ACT (BLBA)
The Federal BLBA levies a tax on production of $1.10 per ton for
underground-mined coal and $0.55 per ton for surface-mined coal, but not to
exceed 4.4% of the applicable sales price, in order to compensate miners who are
totally disabled due to black lung disease and some survivors of miners who died
from this disease, and who were last employed as miners prior to 1970 or
subsequently where no responsible coal mine operator has been identified for
claims. In addition, BLBA provides that some claims for which coal operators had
previously been responsible will be obligations of the government trust funded
by the tax. The Revenue Act of 1987 extended the termination date of this tax
from January 1, 1996, to the earlier of January 1, 2014, or the date on which
the government trust becomes solvent. For miners last employed as miners after
1969 and who are determined to have contracted black lung, we self-insure
against potential cost using actuarially
8
determined estimates of the cost of present and future claims. We are also
liable under state statutes for black lung claims.
The U.S. Department of Labor published revised regulations in December
2000, that became effective in January 2001, that will alter the claims process
for federal black lung benefit recipients, which among other things:
- simplify administrative procedures for the adjudication of claims;
- propose preference for the miner's treating physician under certain
circumstances;
- allow previously denied claims to be refiled and litigated under a
different standard;
- limit the amount of evidence all parties may submit for consideration;
- create a rebuttable presumption that medical treatment for any
pulmonary condition is caused or aggravated by the miner's work; and
- expand the definition of pneumoconiosis and total disability.
Because the revised regulations are expected to result in an increase in
the incidence and recovery of black lung claims, both the coal and insurance
industries are currently challenging certain provisions of the revised
regulations through litigation. A federal judge upheld these regulations in
August 2001. An appeal was filed in August 2001. In addition, Congress and state
legislatures regularly consider various items of black lung legislation, which,
if enacted, could adversely affect our business financial condition and results
of operations.
WORKERS' COMPENSATION
We are required to compensate employees for work-related injuries. Several
states in which we operate consider changes in workers compensation laws from
time to time.
COAL INDUSTRY RETIREE HEALTH BENEFITS ACT (CIRHBA)
The Federal CIRHBA was enacted to provide for the funding of health
benefits for some United Mine Workers of America retirees. The act merged
previously established union benefit plans into a single fund into which
"signatory operators" and "related persons" are obligated to pay annual premiums
for beneficiaries. The act also created a second benefit fund for miners who
retired between July 21, 1992, and September 30, 1994, and whose former
employers are no longer in business. Because of our union-free status, we are
not required to make payments to retired miners under CIRHBA, with the exception
of limited payments made on behalf of predecessors of MC Mining, LLC. However,
in connection with the sale of the coal assets acquired by Alliance Resource
Holdings in 1996, MAPCO Inc. agreed to retain, and be responsible for, all
liabilities under CIRHBA.
SURFACE MINING CONTROL AND RECLAMATION ACT (SMCRA)
The Federal SMCRA establishes operational, reclamation and closure
standards for all aspects of surface mining as well as many aspects of deep
mining. The act requires that comprehensive environmental protection and
reclamation standards be met during the course of and upon completion of mining
activities. In conjunction with mining the property, we reclaim and restore the
mined areas by grading, shaping and preparing the soil for seeding. Upon
completion of the mining, reclamation generally is completed by seeding with
grasses or planting trees for a variety of uses, as specified in the approved
reclamation plan. We believe that we are in compliance in all material respects
with applicable regulations relating to reclamation.
SMCRA and similar state statutes, require, among other things, that mined
property be restored in accordance with specified standards and approved
reclamation plans. The act requires us to restore the surface to approximate the
original contours as contemporaneously as practicable with the completion of
surface
9
mining operations. The mine operator must submit a bond or otherwise secure the
performance of these reclamation obligations. The earliest a reclamation bond
can be released is five years after reclamation has been achieved. Federal law
and some states impose on mine operators the responsibility for replacing
certain water supplies damaged by mining operations and repairing or
compensating for damage occurring on the surface as a result of mine subsidence,
a consequence of longwall mining and possibly other mining operations. In
addition, the Abandoned Mine Lands Program, which is part of SMCRA, imposes a
tax on all current mining operations, the proceeds of which are used to restore
mines closed before 1977. The maximum tax is $0.35 per ton on surface-mined coal
and $0.15 per ton on underground-mined coal. We have accrued for the estimated
costs of reclamation and mine closing, including the cost of treating mine water
discharge when necessary. In addition, states from time to time have increased
and may continue to increase their fees and taxes to fund reclamation of
orphaned mine sites and acid mine drainage control on a statewide basis.
Under SMCRA, responsibility for unabated violations, unpaid civil penalties
and unpaid reclamation fees of independent contract mine operators and other
third parties can be imputed to other companies which are deemed, according to
the regulations, to have "owned" or "controlled" the third party violator.
Sanctions against the "owner" or "controller" are quite severe and can include
being blocked from receiving new permits and revocation of any permits that have
been issued since the time of the violations or, in the case of civil penalties
and reclamation fees, since the time their amounts became due. We are not aware
of any currently pending or asserted claims against us relating to the
"ownership" or "control" theories discussed above. However, we cannot assure you
that such claims will not develop in the future.
CLEAN AIR ACT (CAA)
The Federal CAA and similar state laws, which regulate emissions into the
air, affect coal mining and processing operations primarily through permitting
and emissions control requirements. The CAA also indirectly affects coal mining
operations by extensively regulating the air emissions of coal-fired electric
power generating plants. For example, the CAA requires reduction of sulfur
dioxide (SO2) emissions from electric power generation plants in two phases.
Only some facilities were subject to the Phase I requirements. Beginning in year
2000, Phase II requires nearly all facilities to reduce emissions. The effected
utilities are able to meet these requirements by:
- switching to lower sulfur fuels;
- installing pollution control devices such as scrubbers;
- reducing electricity generating levels; or
- purchasing or trading so-called pollution "credits."
Specific emissions sources receive these "credits" that utilities and
industrial concerns can trade or sell to allow other units to emit higher levels
of SO2. In addition, the CAA requires a study of utility power plant emissions
of some toxic substances and their eventual regulation, if warranted. The effect
of the CAA cannot be completely ascertained at this time, although the SO2
emissions reduction requirement is projected generally to increase the demand
for lower sulfur coal and potentially decrease demand for higher sulfur coal.
The CAA also indirectly affects coal mining operations by requiring
utilities that currently are major sources of nitrogen oxides (NOx) in moderate
or higher ozone nonattainment areas to install reasonably available control
technology for NOx, which are precursors of ozone. In October 1998, the U.S.
Environmental Protection Agency (EPA) issued a rule requiring 22 eastern states
and the District of Columbia to make substantial reductions in NOx emissions by
the year 2003, which was substantially upheld by the U.S. Court of Appeals for
the D.C. Circuit on March 3, 2000. On March 5, 2001, the U.S. Supreme Court
declined to review that decision, in response to a petition by seven states and
the power and coal industries. This deadline was recently extended by EPA to
2004. EPA expects that affected states will achieve reductions by requiring
power plants to make substantial reductions in their NOx emissions. This in turn
will
10
require power plants to install reasonably available control technology and
additional control measures. Installation of reasonably available control
technology and additional measures required under EPA regulations will make it
more costly to operate coal-fired plants and, depending on the requirements of
individual state implementation plans and the development of revised new source
performance standards, could make coal a less attractive fuel alternative in the
planning and building of utility power plants in the future. Any reduction in
coal's share of the capacity for power generation could have a material adverse
effect on our business, financial condition and results of operations. The
effect these regulations, or other requirements that may be imposed in the
future, could have on the coal industry in general and on our business in
particular cannot be predicted with certainty. We cannot assure you that the
implementation of the CAA, the new National Ambient Air Quality Standards
(NAAQS) discussed below, or any other current or future regulatory provision,
will not materially adversely affect us.
In addition, EPA has already issued and is considering further regulations
relating to fugitive dust and emissions of other coal-related pollutants such as
mercury, nickel, dioxin and fine particulates. For example, in July 1997 EPA
adopted new, more stringent NAAQS for particulate matter, which may require some
states to change existing implementation plans. These NAAQS are expected to be
implemented by 2003. These NAAQS were effectively affirmed by the U.S. Supreme
Court on February 27, 2001, subject to the resolution of certain issues pending
on remand. That decision upheld the constitutionality of EPA's NAAQS statutory
authority, finding that EPA acted properly in not considering costs in setting
the NAAQS, and remanded the case to the U.S. Court of Appeals for the D.C.
Circuit to dispose of any remaining challenges to the rules. On March 26, 2002,
the U.S. Court of Appeals for the D.C. Circuit upheld EPA's NAAQS. Because coal
mining operations and utilities emit particulate matter, our mining operations
and utility customers are likely to be directly affected when the revisions to
the NAAQS are implemented by the states. Both Congress and EPA are considering
additional controls on other air pollutants emitted by electric utilities. Any
such controls, if adopted, could adversely affect the market for coal.
EPA has filed suit against a number of our customers over implementation of
new source performance standards and preconstruction review requirements for new
sources and major modifications under the prevention of significant
deterioration and nonattainment regulations. This issue surrounds the issue of
what constitutes regular maintenance versus new construction. Some of our
customers have agreed to or proposed settlements with EPA while others are
preparing for litigation. These and other regulatory developments may restrict
the size of our market, and the type of coal in demand. This in turn could
adversely affect our ability to develop new mines, or could require us or our
customers to modify existing operations.
FRAMEWORK CONVENTION ON GLOBAL CLIMATE CHANGE (KYOTO PROTOCOL)
The United States and more than 160 other nations are signatories to the
Kyoto Protocol which is intended to limit or capture emissions of greenhouse
gases, such as carbon dioxide. The Kyoto Protocol established a binding set of
emissions targets for developed nations. The specific limits vary from country
to country. Under the terms of the Kyoto Protocol, the United States would be
required to reduce emissions to 93% of 1990 levels over a five-year budget
period from 2008 through 2012. The Clinton Administration signed the Kyoto
Protocol in November 1998. Although the U.S. Senate has not ratified the Kyoto
Protocol and no comprehensive regulations focusing on greenhouse gas emissions
have been enacted, efforts to control greenhouse gas emissions could result in
reduced use of coal if electric power generators switch to lower carbon sources
of fuel.
In March 2001, President Bush expressed his opposition to the Kyoto
Protocol and stated that he did not believe that the government should impose
mandatory carbon dioxide emission reductions on power plants. In February 2002,
President Bush proposed voluntary actions to reduce greenhouse gas intensity of
the United States. Greenhouse gas intensity measures the ratio of greenhouse gas
emissions, such as carbon dioxide, to economic output. The President's climate
change initiative calls for a reduction in greenhouse gas intensity
11
over the next ten years, which is approximately equivalent to the reduction that
has occurred over each of the past two decades. These restrictions, if
established through regulation or legislation, could have a material adverse
effect on our business, financial condition and results of operations.
CLEAN WATER ACT (CWA)
The Federal CWA affects coal mining operations by imposing restrictions on
effluent discharge into waters. Regular monitoring, as well as compliance with
reporting requirements and performance standards, are preconditions for the
issuance and renewal of permits governing the discharge of pollutants into
water. We are also subject to CWA Section 404, which imposes permitting and
mitigation requirements associated with the dredging and filling of wetlands.
The CWA and equivalent state legislation, where such equivalent state
legislation exists, affect coal mining operations that impact wetlands. We
believe we have obtained all necessary wetlands permits required under CWA
Section 404. However, mitigation requirements under those existing, and possible
future, wetlands permits may vary considerably. In January 2001, the U.S Supreme
Court issued a decision narrowing the CWA jurisdiction over isolated wetlands
not connected to navigable waters. It is not yet known how this will affect
wetland mitigation and protection programs under federal and state laws. At this
time we do not anticipate any increase in such requirements or in post-mining
reclamation accrual requirements. For that reason, the setting of post-mine
reclamation accruals for such mitigation projects is difficult to ascertain with
certainty. We believe that we have obtained all permits required under the CWA
as traditionally interpreted by the responsible agencies. Although more
stringent permitting requirements may be imposed in the future, we are not able
to accurately predict the impact, if any, of any such permitting requirements.
However, each individual state is required to submit to EPA their biennial
CWA Section 303(d) lists identifying all waterbodies not meeting state specified
water quality standards. For each listed waterbody, the state is required to
begin developing a Total Maximum Daily Load (TMDL) to:
- determine the maximum pollutant loading the waterbody can assimilate
without violating water quality standards,
- identify all current pollutant sources and loadings to that waterbody,
- calculate the pollutant loading reduction necessary to achieve water
quality standards, and
- establish a means of allocating that burden among and between the point
and non-point sources contributing pollutants to the waterbody.
We are currently participating in stakeholders meetings and in negotiations
with states and EPA to establish reasonable TMDLs that will accommodate
expansion. These and other regulatory developments may restrict our ability to
develop new mines, or could require us or our customers to modify existing
operations, the extent of which we cannot accurately or reasonably predict.
SAFE DRINKING WATER ACT (SDWA)
The Federal SDWA and its state equivalents affect coal mining operations by
imposing requirements on the underground injection of fine coal slurries, fly
ash, and flue gas scrubber sludge, and by requiring a permit to conduct such
underground injection activities. The inability to obtain these permits could
have a material impact on our ability to inject materials such as fine coal
refuse, fly ash, or flue gas scrubber sludge into the inactive areas of some of
our old underground mine workings.
In addition to establishing the underground injection control program, the
Federal SDWA also imposes regulatory requirements on owners and operators of
"public water systems." This regulatory program could impact our reclamation
operations where subsidence, or other mining-related problems, require the
provision of drinking water to affected adjacent homeowners. However, the
Federal SDWA defines a "public water system" for purposes of regulatory
jurisdiction as a system for the provision to the public of water for human
12
consumption through pipes or other constructed conveyances, if the system has at
least fifteen service connections or regularly serves at least twenty-five
individuals. It is unlikely that any of our reclamation activities would require
the provision of such a "public water system." While we have drinking water
supply sources for our employees and contractors that are subject to SDWA
regulation, the SDWA is unlikely to have a material impact on our operations.
COMPREHENSIVE ENVIRONMENTAL RESPONSE, COMPENSATION AND LIABILITY ACT
(CERCLA)
The Federal CERCLA and similar state laws affect coal mining operations by,
among other things, imposing cleanup requirements for threatened or actual
releases of hazardous substances that may endanger public health or welfare or
the environment. Under CERCLA, and similar state laws, joint and several
liability may be imposed on waste generators, site owners and operators and
others regardless of fault or the legality of the original disposal activity.
Some products used by coal companies in operations, such as chemicals, generate
waste containing hazardous substances, which are governed by the statute. Thus,
coal mines that we currently own or have previously owned or operated, and sites
to which we sent waste materials, may be subject to liability under CERCLA and
similar state laws. We have been, on rare occasions, the subject of
administrative proceedings, litigation and investigations relating to CERCLA
matters, none of which has had a material adverse effect on our financial
condition or results of operations. We cannot assure you that we will not become
involved in future proceedings, litigation or investigations, or that
liabilities arising out of any such proceedings will not be material.
TOXIC SUBSTANCES CONTROL ACT (TSCA)
The Federal TSCA regulates, among other things, electrical equipment
containing PCBs in excess of 50 parts-per-million. Specifically, TSCA's PCB
rules require that all PCB-containing equipment be properly labeled, stored, and
disposed of, and require the on-site maintenance of annual records regarding the
presence and use of equipment containing PCBs in excess of 50 parts-per-million.
Because the regulated PCB-containing electrical equipment in use in our
operations is owned by the utilities that serve the operations where they are
located, and because the use of PCB-containing fluids in such equipment is in
the process of being phased out, we do not believe TSCA will have a material
impact on our operations.
RESOURCE CONSERVATION AND RECOVERY ACT (RCRA)
The Federal RCRA affects coal mining operations by imposing requirements
for the generation, transportation, treatment, storage, disposal and cleanup of
hazardous wastes. Many mining wastes are excluded from the regulatory definition
of hazardous wastes, and coal mining operations covered by SMCRA permits are
exempted from regulation under RCRA by statute. RCRA also allows EPA to require
corrective action at sites where there is a release of hazardous substances. In
addition, each state has its own laws regarding the proper management and
disposal of waste material. While these laws impose ongoing compliance
obligations, we do not believe that these costs will have a material impact on
our operations.
COAL COMBUSTION BY-PRODUCTS
In 2000, EPA declined to impose hazardous wastes regulatory controls on the
disposal of some coal combustion by-products, including the practice of using
coal combustion by-products as minefill. However, EPA is currently evaluating
the possibility of placing additional solid waste burdens on the disposal of
these types of materials, but it may be several years before these standards
will be developed.
While we cannot predict the ultimate outcome of EPA's assessment, we
believe the beneficial uses of coal combustion by-products (like the practice of
placing this by-product in abandoned mine areas) that we employ do not
constitute poor environmental practices because among other things, our CWA
discharge permits for treated acid mine drainage contain parameters for
pollutants of concern,
13
such as metals, and those permits require monitoring and reporting of effluent
quality data. Small quantities of regulated hazardous wastes are generated at
some of our facilities. However, we do not believe that the cost of complying
with applicable regulations for those wastes will have a material impact on our
operations.
OTHER ENVIRONMENTAL, HEALTH AND SAFETY REGULATION
In addition to the laws and regulations described above, we are subject to
regulations regarding underground and above ground storage tanks where we may
store petroleum or other substances. Some monitoring equipment that we use is
subject to licensing under the Federal Atomic Energy Act. Water supply wells
located on our property are subject to federal, state and local regulation. The
costs of compliance with these requirements should not have a material adverse
effect on our business, financial condition or results of operations.
EMPLOYEES
We have approximately 1,745 employees, including approximately 100
corporate employees and approximately 1,645 employees involved in active mining
operations. Our work-force is entirely union-free. Relations with our employees
are generally good.
ITEM 2. PROPERTIES
COAL RESERVES
We must obtain permits from applicable state regulatory authorities before
beginning to mine particular reserves. Applications for permits require
extensive engineering and data analysis and presentation, and must address a
variety of environmental, health, and safety matters associated with a proposed
mining operation. These matters include the manner and sequencing of coal
extraction, the storage, use and disposal of waste and other substances and
other impacts on the environment, the construction of overburden fills and water
containment areas, and reclamation of the area after coal extraction. We are
required to post bonds to secure performance under our permits. As is typical in
the coal industry, we strive to obtain mining permits within a time frame that
allows us to mine reserves as planned on an uninterrupted basis. We begin
preparing applications for permits for areas that we intend to mine sufficiently
in advance of our planned mining activities to allow adequate time to complete
the permitting process. Regulatory authorities have considerable discretion in
the timing of permit issuance, and the public has rights to comment on and
otherwise engage in the permitting process, including intervention in the
courts. For the reserves set forth in the table below, we are not currently
aware of matters which would significantly hinder our ability to obtain future
mining permits on a timely basis.
Our reported coal reserves are those that we believe can be economically
and legally extracted or produced at the time of the filing of this Annual
Report on Form 10-K. In determining whether our reserves meet this economical
and legal standard, we take into account, among other things, our potential
ability or inability to obtain a mining permit, the possible necessity of
revising a mining plan, changes in estimated future costs, changes in future
cash flows caused by changes in mining permits, variations in quantity and
quality of coal, and varying levels of demand and their effects on selling
prices.
As of December 31, 2001, we had approximately 400.7 million tons of coal
reserves. All of the estimates of reserves which are presented in this Annual
Report on Form 10-K are of proven and probable reserves.
The following table sets forth reserve information, as of December 31,
2001, about each of our mining complexes.
14
Heat Proven and Probable Reserves
Content ------------------------------- Reserve Assignment
Mine (Btus Pounds SO2 per MMbtu --------------------
Operations Type per pound) <1.2 1.2 - 2.5 >2.5 Total Assigned Unassigned
---------- ----------- ---------- ---- --------- ---- ----- -------- ----------
(tons in millions)
Illinois Basin Operations
Dotiki Underground 12,500 -- -- 88.9 88.9 88.9 --
Pattiki Underground 11,700 -- -- 53.9 53.9 53.9 --
Hopkins County Underground 11,300 -- -- 21.4 21.4 1.4 20.0
Coal / Surface -- -- 11.6 11.6 11.6 --
Gibson County Underground 11,600 -- 36.2 -- 36.2 36.2 --
Coal (North)
Gibson County Underground 11,600 -- 55.0 44.9 99.9 -- 99.9
Coal (South)
---- ----- ----- ----- ----- -----
Region Total -- 91.2 220.7 311.9 192.0 119.9
---- ----- ----- ----- ----- -----
East Kentucky Operations
Pontiki/Excel Underground 12,800 16.0 1.9 -- 17.9 17.9 --
MC Mining/Excel Underground 12,800 22.0 -- -- 22.0 22.0 --
---- ----- ----- ----- ----- -----
Region Total 38.0 1.9 -- 39.9 39.9 --
---- ----- ----- ----- ----- -----
Maryland Operations
Mettiki Underground 13,000 -- 15.0 15.0 30.0 15.0 15.0
Mettiki(WV) Underground 13,000 -- -- 18.9 18.9 13.3 5.6
---- ----- ----- ----- ----- -----
-- 15.0 33.9 48.9 28.3 20.6
---- ----- ----- ----- ----- -----
Total 38.0 108.1 254.6 400.7 260.2 140.5
==== ===== ===== ===== ===== =====
% of Total 9.5% 27.0% 63.5% 100.0% 64.9% 35.1%
==== ==== ==== ===== ==== ====
Our reserve estimates are prepared from geological data assembled and
analyzed by our staff of geologists and engineers. This data is obtained through
our extensive, ongoing exploration drilling and in-mine channel sampling
programs. Our drill spacing criteria adhere to standards as defined by the U.S.
Geological Survey. The maximum acceptable distance from seam data points varies
with the geologic nature of the coal seam being studied, but generally the
standard for (a) proven reserves is that points of observation are no greater
than 1/2 mile apart, and are projected to extend as a 1/4 mile wide belt around
each point of measurement and (b) probable reserves is that the points of
observation are between 1/2 and 1 1/2 miles apart and are projected to extend as
a 1/2 mile wide belt that lies 1/4 mile from the points of measurement.
Reserve estimates will change from time to time in reflection of mining
activities, analysis and new engineering and geological data, acquisition or
divestment of reserve holdings, modification of mining plans or mining methods,
and other factors. Weir International Mining Consultants performed an overview
audit of all of our reserves as of March 31, 1999 in conjunction with our
initial public offering.
Reserves represent that part of a mineral deposit that can be economically
and legally extracted or produced, and reflects estimated losses involved in
producing a saleable product. All of our reserves are steam coal. The 38.0
million tons of reserves listed as <1.2 pounds of SO2 per MMbtu are compliance
coal.
Assigned reserves are those reserves that have been designated for mining
by a specific operation.
Unassigned reserves are those reserves that have not yet been designated
for mining by a specific operation.
BTU values are reported on an as shipped, fully washed, basis. Shipments
that are either fully or partially raw will have a lower BTU value.
15
A permit application related to the 18.9 million tons of reserves
controlled by Mettiki (WV) has been submitted to the West Virginia Department of
Environmental Protection ("West Virginia DEP"). The West Virginia DEP has not
advised us concerning the status of the permit application. In regard to a
different permit application concerning other coal reserves, on January 29,
2002, the West Virginia DEP denied such permit application related to 3.1
million tons of coal that are not contiguous to the 18.9 million tons of
reserves. Consequently, the 3.1 million tons is classified as a non-reserve coal
deposit and not included in our reported reserves. The permit denial has been
appealed to the West Virginia Surface Mining Board.
We control certain leases for coal deposits that are nearby, but not
contiguous to our primary reserve bases. The tons controlled by these leases are
classified as non-reserve coal deposits and are not included in our reported
reserves. These non-reserve coal deposits are as follows: Dotiki - 2.6 million
tons, Pattiki - 5.8 million tons, Gibson County North - 2.0 million tons, and
Gibson County South - 4.3 million tons.
We lease almost all of our reserves and generally have the right to
maintain the lease in force until the exhaustion of minable and merchantable
coal located within the leased premises or a larger coal reserve area. These
leases provide for royalties to be paid to the lessor at a fixed amount per ton
or as a percentage of the sales price. Many leases require payment of minimum
royalties, payable either at the time of the execution of the lease or in
periodic installments, even if no mining activities have begun. These minimum
royalties are normally credited against the production royalties owed to a
lessor once coal production has commenced.
The following table sets forth production data about each of our mining
complexes.
Tons Produced
------------------
Operations 2001 2000 1999 Transportation Equipment
---------- ---- ---- ---- ----------------- ---------
(tons in millions)
Illinois Basin Operations
Dotiki 4.6 3.9 3.6 CSX; truck; barge CM
Pattiki 1.9 2.3 2.3 CSX; truck; barge CM
Hopkins County Coal 2.0 2.1 2.6 CSX, PAL; truck DL; CM
Gibson County Coal (North) 1.7 0.1 -- Truck CM
---- ---- ----
Region Total 10.2 8.4 8.5
---- ---- ----
East Kentucky Operations
Pontiki/Excel 1.7 1.9 1.8 NS; truck CM
MC Mining/Excel 1.1 0.8 1.0 NS; truck CM
---- ---- ----
Region Total 2.8 2.7 2.8
---- ---- ----
Maryland Operations
Mettiki 2.7 2.6 2.8 Truck; CSX LW; CM
---- ---- ----
Total 15.7 13.7 14.1
---- ---- ----
CSX -- CSX Railroad
PAL -- Paducah and Louisville Railroad
NS -- Norfolk & Southern Railroad
CM -- Continuous Miner
DL -- Dragline with Stripping Shovel, Front End Loaders and Dozers
LW -- Longwall
RISK FACTORS
If any of the following risks were actually to occur, our business,
financial condition or results of operations could be materially adversely
affected and the trading price of our common units could decline.
16
RISKS INHERENT IN OUR BUSINESS
- Competition within the coal industry may adversely affect our ability
to sell coal, and excess production capacity in the industry could put
downward pressure on coal prices.
- We expect most newly constructed power plants to be fueled by natural
gas. Any change in consumption patterns by utilities away from the use
of coal could affect our ability to sell the coal we produce.
- From time to time conditions in the coal industry may make it more
difficult for us to extend existing or enter into new long-term
contracts. This could affect the stability and profitability of our
operations.
- Some of our long-term contracts contain provisions allowing for the
renegotiation of prices and, in some instances, the termination of the
contract or the suspension of purchases by customers.
- Some of our long-term contracts require us to supply all of our
customers coal needs. If these customers' coal requirements decline,
our revenues under these contracts will also drop.
- A substantial portion of our coal has a high-sulfur content. This coal
may become more difficult to sell because the Clean Air Act may impact
the ability of electric utilities to burn high-sulfur coal through the
regulation of emissions.
- We depend on a few customers for a significant portion of our revenues,
and the loss of one or more significant customers could impact our
ability to sell the coal we produce.
- Litigation relating to disputes with our customers may result in
substantial costs, liabilities and loss of revenues.
- The term of each of the agreements associated with the coal synfuel
facility at Hopkins County Coal is subject to early cancellation
provisions customary for transactions of these types, including the
unavailability of synfuel tax credits, the termination of associated
coal synfuel sales contracts, and the occurrence of certain force
majeure events. Therefore, the continuation of the operating revenues
associated with the coal synfuel production facility cannot be assured.
- Any loss of the benefit from state tax credits may affect adversely our
ability to pay distributions.
- Coal mining is subject to inherent risks that are beyond our control
and these risks may not be fully covered under our insurance policies.
- Any significant increase in transportation costs or disruption of the
transportation of our coal may impair our ability to sell coal.
- We may not be able to grow successfully through future acquisitions,
and we may not be able to effectively integrate the various businesses
or properties we do acquire.
- Our business may be adversely affected if we are unable to replace our
coal reserves.
- The estimates of our reserves may prove inaccurate, and unitholders
should not place undue reliance on these estimates.
17
- Cash distributions are not guaranteed and may fluctuate with our
performance. In addition, our managing general partner's discretion in
establishing reserves may negatively impact a unitholder's receipt of
cash distributions.
- Our indebtedness may limit our ability to borrow additional funds, make
distributions to unitholders or capitalize on business opportunities.
RISKS INHERENT IN AN INVESTMENT IN THE PARTNERSHIP
- Unitholders have limited voting rights and do not control our managing
general partner.
- We may issue additional common units without the approval of common
unitholders, which would dilute existing unitholders' interests.
- The issuance of additional common units, including upon conversion of
subordinated units, will increase the risk that we will be unable to
pay the full minimum quarterly distribution on all common units.
- Cost reimbursements to our general partners may be substantial and will
reduce our cash available for distribution.
- Our managing general partner has a limited call right that may require
unitholders to sell their common units at an undesirable time or price.
- Unitholders may not have limited liability under some circumstances.
REGULATORY RISKS
- Federal and state laws require bonds to secure our obligations related
to (a) the statutory requirement that we return mined property to its
approximate original condition and (b) workers compensation. We may
have difficulty maintaining our surety bonds for mine reclamation as
well as workers' compensation and black lung benefits. As of December
31, 2001, we had $64.1 million of surety bonds in place. Our failure to
maintain, or inability to acquire, surety bonds that are required by
state and federal law would have a material adverse effect on us.
- We are subject to federal, state and local regulations on health,
safety, environmental and numerous other matters. These regulations
increase our costs of doing business, or discourage customers from
buying our coal.
- We have black lung benefits and workers' compensation obligations that
could increase if new legislation is enacted.
- The Clean Air Act affects our customers and could significantly
influence their purchasing decisions. New regulations under the Clean
Air Act could also reduce demand for our coal.
- The passage of legislation responsive to the Kyoto Protocol could
result in a reduced use of coal by electric power generators. Any such
reduction in use could adversely affect our revenues and results of
operations.
18
- We are subject to the Clean Water Act which imposes limitations, and
monitoring and reporting obligations, on our discharge of pollutants
into water. Those limitations and obligations may become more stringent
and result in restricted operations and increased costs.
- We are subject to the Safe Drinking Water Act, which imposes various
requirements on us.
- We are subject to reclamation, mine closure and real property
restoration regulatory obligations and must accrue for the estimated
cost of complying with these regulations.
- We could incur significant costs under federal and state Superfund and
waste management statutes.
TAX RISKS TO COMMON UNITHOLDERS
- The IRS could choose to treat us as a corporation, which would
substantially reduce the cash available for distribution to
unitholders.
- We have not requested an IRS ruling with respect to our tax treatment.
- You may be required to pay taxes on income from us even if you receive
no cash distributions.
- Tax gain or loss on disposition of common units could be different than
expected.
- Common unitholders, other than individuals who are U.S. residents, may
experience adverse tax consequences from owning common units.
- We have registered with the IRS as a tax shelter. This may increase the
risk of an IRS audit of us or a common unitholder.
- We treat a purchaser of common units as having the same tax benefits as
the seller. The IRS may challenge this treatment, which could adversely
affect the value of common units.
- Common unitholders will likely be subject to state and local taxes as a
result of an investment in common units.
ITEM 3. LEGAL PROCEEDINGS
We are subject to various types of litigation in the ordinary course of our
business. Disputes with our customers over the provisions of long-term coal
supply contracts arise occasionally and generally relate to, among other things,
coal quality, quantity, pricing, and the existence of force majeure conditions.
Other than the contract dispute with PSI described under "Other" in Item 8.
Financial Statements and Supplementary Data. - Note 15. Commitments and
Contingencies, we are not involved in any litigation involving our long-term
coal supply contracts. However, we cannot assure you that disputes will not
occur or that we will be able to resolve those disputes in a satisfactory
manner. We are not engaged in any litigation which we believe is material to our
operations, including under the various environmental protection statutes to
which we are subject. The information under "General Litigation" under "Item 8.
Financial Statements and Supplementary Data. - Note 15. Commitments and
Contingencies" is incorporated herein by this reference.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITIES HOLDERS
None.
19
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEPENDENT AUDITORS' REPORT
To the Board of Directors of the Managing
General Partner and the Partners of
Alliance Resource Partners, L.P.:
We have audited the accompanying consolidated balance sheets of Alliance
Resource Partners, L.P. and subsidiaries (the "Partnership") as of December 31,
2001 and 2000, the related consolidated and combined statements of income and
cash flows for the years ended December 31, 2001 and 2000, the period from the
Partnership's commencement of operations (on August 20, 1999) to December 31,
1999, and the Predecessor period from January 1, 1999 to August 19, 1999, and
the statement of Partners' capital (deficit) for the years ended December 31,
2001 and 2000, and the period from the Partnership's commencement of operations
(on August 20, 1999) to December 31, 1999. Our audits also included the
financial statement schedule listed in the Index at Item 14. These financial
statements and financial statement schedule are the responsibility of the
Partnership's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated and combined financial statements present
fairly, in all material respects, the financial position of the Partnership at
December 31, 2001 and 2000 and the results of their operations and their cash
flows for the years ended December 31, 2001 and 2000, the period from the
Partnership's commencement of operations (on August 20, 1999) to December 31,
1999, and the Predecessor period from January 1, 1999 to August 19, 1999 in
conformity with accounting principles generally accepted in the United States of
America. Also, in our opinion, such financial statement schedule, when
considered in relation to the basic consolidated and combined financial
statements taken as a whole, presents fairly in all material respects the
information set forth therein.
As discussed in Note 3 to the consolidated and combined financial statements,
the Partnership changed its method of estimating coal workers pneumoconiosis
benefits liability effective January 1, 2001.
/s/ Deloitte & Touche LLP
Tulsa, Oklahoma
January 28, 2002, except for Note 15 as
to which the date is March 14, 2002
20
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2001 AND 2000
(IN THOUSANDS, EXCEPT UNIT DATA)
--------------------------------------------------------------------------------
DECEMBER 31,
--------------------------
ASSETS 2001 2000
--------- ---------
CURRENT ASSETS:
Cash and cash equivalents $ 9,176 $ 6,933
Trade receivables, less allowance of $763 and $0, respectively 31,124 35,898
Due from affiliates -- 208
Marketable securities (at cost, which approximates fair value) 10,085 37,398
Inventories 11,600 10,842
Advance royalties 5,353 2,865
Prepaid expenses and other assets 2,020 1,168
--------- ---------
Total current assets 69,358 95,312
PROPERTY, PLANT AND EQUIPMENT, AT COST 367,050 320,445
LESS ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION (169,960) (135,782)
--------- ---------
197,090 184,663
OTHER ASSETS:
Advance royalties 9,756 10,009
Coal supply agreements, net 12,031 16,324
Other long-term assets 2,670 2,858
--------- ---------
$ 290,905 $ 309,166
========= =========
LIABILITIES AND PARTNERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 25,237 $ 25,558
Due to affiliates 2,595 --
Accrued taxes other than income taxes 5,660 4,863
Accrued payroll and related expenses 8,284 6,975
Accrued interest 5,402 5,439
Workers' compensation and pneumoconiosis benefits 4,194 4,415
Other current liabilities 5,324 5,710
Current maturities, long-term debt 15,000 3,750
--------- ---------
Total current liabilities 71,696 56,710
LONG-TERM LIABILITIES:
Long-term debt, excluding current maturities 211,250 226,250
Pneumoconiosis benefits 14,615 21,651
Workers' compensation 18,409 16,748
Reclamation and mine closing 15,387 14,940
Due to affiliates 3,624 1,278
Other liabilities 2,865 3,376
--------- ---------
Total liabilities 337,846 340,953
COMMITMENTS AND CONTINGENCIES
PARTNERS' CAPITAL (DEFICIT):
Common Unitholders 8,982,780 units outstanding 141,448 149,642
Subordinated Unitholder 6,422,531 units outstanding 110,935 116,794
General Partners (298,510) (298,223)
Minimum pension liability (814) --
--------- ---------
Total Partners' capital (deficit) (46,941) (31,787)
--------- ---------
$ 290,905 $ 309,166
========= =========
See notes to consolidated and combined financial statements.
21
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED AND COMBINED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 2001 AND 2000, AND THE PERIOD FROM THE
PARTNERSHIP'S COMMENCEMENT OF OPERATIONS (ON AUGUST 20, 1999) TO DECEMBER 31,
1999, AND THE PREDECESSOR PERIOD FROM JANUARY 1, 1999 TO AUGUST 19, 1999
(IN THOUSANDS, EXCEPT UNIT AND PER UNIT DATA)
--------------------------------------------------------------------------------
PARTNERSHIP PREDECESSOR
------------------------------------------------------ ---------------
FROM
COMMENCEMENT FOR THE
YEAR ENDED OF OPERATIONS PERIOD FROM
DECEMBER 31, (ON AUGUST 20, 1999) JANUARY 1, 1999
------------------------------- TO TO
2001 2000 DECEMBER 31, 1999 AUGUST 19, 1999
------------ ------------ -------------------- ---------------
SALES AND OPERATING REVENUES:
Coal sales $ 421,996 $ 347,209 $ 128,860 $ 217,033
Transportation revenues 18,090 13,511 4,907 14,223
Other sales and operating revenues 6,214 2,749 358 577
------------ ------------ ------------ ------------
Total revenues 446,300 363,469 134,125 231,833
------------ ------------ ------------ ------------
EXPENSES:
Operating expenses 307,977 257,365 89,945 152,066
Transportation expenses 18,090 13,511 4,907 14,223
Outside purchases 31,840 16,874 6,429 17,738
General and administrative 17,728 15,176 6,245 8,912
Depreciation, depletion and amortization 45,451 39,141 15,081 24,622
Interest expense (net of interest income and
interest capitalized of $1,928, $3,015 and
$999 for the Partnership's respective periods) 16,805 16,563 5,887 100
Unusual items -- (9,466) -- --
------------ ------------ ------------ ------------
Total operating expenses 437,891 349,164 128,494 217,661
------------ ------------ ------------ ------------
INCOME FROM OPERATIONS 8,409 14,305 5,631 14,172
OTHER INCOME 752 1,276 641 531
------------ ------------ ------------ ------------
INCOME BEFORE INCOME TAXES AND
CUMULATIVE EFFECT OF ACCOUNTING CHANGE 9,161 15,581 6,272 14,703
INCOME TAX EXPENSE -- -- -- 4,498
------------ ------------ ------------ ------------
INCOME BEFORE CUMULATIVE EFFECT OF
ACCOUNTING CHANGE 9,161 15,581 6,272 $ 10,205
CUMULATIVE EFFECT OF ACCOUNTING CHANGE 7,939 -- -- --
------------ ------------ ------------ ------------
NET INCOME $ 17,100 $ 15,581 $ 6,272 $ 10,205
============ ============ ============ ============
GENERAL PARTNERS' INTEREST IN NET INCOME $ 342 $ 312 $ 125
============ ============ ============
LIMITED PARTNERS' INTEREST IN NET INCOME $ 16,758 $ 15,269 $ 6,147
============ ============ ============
BASIC NET INCOME PER LIMITED PARTNER UNIT $ 1.09 $ 0.99 $ 0.40
============ ============ ============
BASIC NET INCOME PER LIMITED PARTNER UNIT
BEFORE ACCOUNTING CHANGE $ 0.58 $ 0.99 $ 0.40
============ ============ ============
DILUTED NET INCOME PER LIMITED
PARTNER UNIT $ 1.07 $ 0.98 $ 0.40
============ ============ ============
DILUTED NET INCOME PER LIMITED PARTNER
UNIT BEFORE ACCOUNTING CHANGE $ 0.57 $ 0.98 $ 0.40
============ ============ ============
PRO FORMA NET INCOME ASSUMING ACCOUNTING
CHANGE IS APPLIED RETROACTIVELY $ 9,161 $ 14,907 $ 6,395 $ 10,071
============ ============ ============ ============
WEIGHTED AVERAGE NUMBER
OF UNITS OUTSTANDING - BASIC 15,405,311 15,405,311 15,405,311
============ ============ ============
WEIGHTED AVERAGE NUMBER
OF UNITS OUTSTANDING - DILUTED 15,684,550 15,551,062 15,405,311
============ ============ ============
See notes to consolidated and combined financial statements.
22
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2001 AND 2000, THE PERIOD FROM THE
PARTNERSHIP'S COMMENCEMENT OF OPERATIONS (ON AUGUST 20, 1999) TO DECEMBER 31,
1999, AND THE PREDECESSOR PERIOD FROM JANUARY 1, 1999 TO AUGUST 19, 1999
(IN THOUSANDS)
--------------------------------------------------------------------------------
PARTNERSHIP PREDECESSOR
----------------------------------------------- ---------------
FROM
COMMENCEMENT FOR THE
YEAR ENDED OF OPERATIONS PERIOD FROM
DECEMBER 31, (ON AUGUST 20, 1999) JANUARY 1, 1999
-------------------------- TO TO
2001 2000 DECEMBER 31, 1999 AUGUST 19, 1999
--------- --------- ------------------- ---------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 17,100 $ 15,581 $ 6,272 $ 10,205
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 45,451 39,141 15,081 24,622
Cumulative effect of accounting change (7,939) -- -- --
Impairment of transloading facility -- 2,439 -- --
Deferred income taxes -- -- -- 639
Reclamation and mine closings 943 1,074 348 457
Coal inventory adjustment to market 212 579 729 --
Other (257) 391 186 (114)
Changes in operating assets and liabilities:
Trade receivables 4,774 (2,842) (33,048) (6,521)
Income tax receivable/payable -- -- -- 651
Inventories (970) 9,709 (1,433) (371)
Advance royalties (2,235) (3,011) 366 1,153
Accounts payable (321) 6,181 (7,410) (129)
Due to affiliates 5,149 264 3,252 --
Accrued taxes other than income taxes 797 289 (630) 678
Accrued payroll and related benefits 1,309 (1,836) 844 (828)
Accrued pneumoconiosis benefits 903 (4) (1,122) 544
Workers' compensation 1,661 1,052 2,222 (460)
Other (2,926) 2,366 452 2,370
--------- --------- --------- ---------
Total net adjustments 46,551 55,792 (20,163) 22,691
--------- --------- --------- ---------
Net cash provided by (used in) operating activities 63,651 71,373 (13,891) 32,896
--------- --------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of property, plant and equipment (53,714) (46,151) (17,173) (21,984)
Proceeds from sale of property, plant and equipment 183 210 125 447
Purchase of marketable securities (33,527) (72,523) (51,287) --
Proceeds from the maturity of marketable securities 60,840 77,464 24,434 --
--------- --------- --------- ---------
Net cash used in investing activities (26,218) (41,000) (43,901) (21,537)
--------- --------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from initial public offering (Note 1) -- -- 137,872 --
Cash contribution by General Partner -- -- 5,917 --
Distributions upon formation (Note 1) -- -- (64,750) --
Payment of formation costs -- -- (4,140) --
Deferred financing cost -- -- (3,517) --
Borrowings under revolving credit facility 1,100 29,500 -- --
Payments under revolving credit facility (1,100) (29,500) -- --
Payments on long-term debt (3,750) -- (1,975) --
Distributions to Partners (31,440) (31,440) (3,615) --
Return of capital to Parent -- -- -- (11,359)
--------- --------- --------- ---------
Net cash provided by (used in) financing activities (35,190) (31,440) 65,792 (11,359)
--------- --------- --------- ---------
NET CHANGE IN CASH AND CASH EQUIVALENTS 2,243 (1,067) 8,000 --
CASH AND CASH EQUIVALENTS AT
BEGINNING OF PERIOD 6,933 8,000 -- --
--------- --------- --------- ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 9,176 $ 6,933 $ 8,000 $ --
========= ========= ========= =========
See notes to consolidated and combined financial statements.
23
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL (DEFICIT)
FOR THE YEARS ENDED DECEMBER 31, 2001 AND 2000, AND THE PERIOD FROM THE
PARTNERSHIP'S COMMENCEMENT OF OPERATIONS (ON AUGUST 20, 1999) TO DECEMBER 31,
1999
(IN THOUSANDS, EXCEPT UNIT DATA)
--------------------------------------------------------------------------------
NUMBER OF LIMITED TOTAL
PARTNER UNITS MINIMUM PARTNERS'
----------------------- GENERAL PENSION CAPITAL
COMMON SUBORDINATED COMMON SUBORDINATED PARTNERS LIABILITY (DEFICIT)
--------- ------------ --------- --------- --------- --------- ---------
Balance at commencement of
operations (on August 20, 1999) -- -- $ -- $ 1 $ -- $ -- $ 1
Issuance of units to public 7,750,000 -- 133,732 -- -- -- 133,732
Contribution of net assets of
Predecessor 1,232,780 6,422,531 23,455 122,186 (24,612) (459) 120,570
Managing General Partner
contribution -- -- -- -- 5,917 -- 5,917
Amount retained by Special
General Partner from
debt borrowings assumed
by the Partnership -- -- -- -- (214,514) -- (214,514)
Distribution at time of
formation -- -- -- -- (64,750) -- (64,750)
Distribution to Partners -- -- (2,066) (1,477) (72) -- (3,615)
Comprehensive income:
Net income from
commencement of
operations (on August 20,
1999) to December 31, 1999 -- -- 3,584 2,563 125 -- 6,272
Minimum pension liability -- -- -- -- -- 459 459
--------- --------- --------- --------- --------- --------- ---------
Total comprehensive income -- -- 3,584 2,563 125 459 6,731
--------- --------- --------- --------- --------- --------- ---------
Balance at December 31, 1999 8,982,780 6,422,531 158,705 123,273 (297,906) -- (15,928)
Net income -- -- 8,903 6,366 312 -- 15,581
Distribution to Partners -- -- (17,966) (12,845) (629) -- (31,440)
--------- --------- --------- --------- --------- --------- ---------
Balance at December 31, 2000 8,982,780 6,422,531 149,642 116,794 (298,223) -- (31,787)
Comprehensive income:
Net income -- -- 9,772 6,986 342 -- 17,100
Minimum pension liability -- -- -- -- -- (814) (814)
--------- --------- --------- --------- --------- --------- ---------
Total comprehensive income -- -- 9,772 6,986 342 (814) 16,286
Distribution to Partners -- -- (17,966) (12,845) (629) -- (31,440)
--------- --------- --------- --------- --------- --------- ---------
Balance at December 31, 2001 8,982,780 6,422,531 $ 141,448 $ 110,935 $(298,510) $ (814) $ (46,941)
========= ========= ========= ========= ========= ========= =========
See notes to consolidated and combined financial statements.
24
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS FOR THE YEARS
ENDED DECEMBER 31, 2001 AND 2000, AND THE PERIOD FROM THE PARTNERSHIP'S
COMMENCEMENT OF OPERATIONS (ON AUGUST 20, 1999) TO DECEMBER 31, 1999,
AND THE PREDECESSOR PERIOD FROM JANUARY 1, 1999 TO AUGUST 19, 1999
--------------------------------------------------------------------------------
1. ORGANIZATION AND PRESENTATION
Alliance Resource Partners, L.P., a Delaware limited partnership (the
"Partnership") was formed on May 17, 1999, to acquire, own and operate
certain coal production and marketing assets of Alliance Resource
Holdings, Inc., a Delaware corporation ("ARH") (formerly known as Alliance
Coal Corporation), consisting of substantially all of ARH's operating
subsidiaries, but excluding ARH.
Prior to August 20, 1999, (a) MAPCO Coal Inc., a Delaware corporation and
direct wholly-owned subsidiary of ARH merged with and into Alliance Coal,
LLC, a Delaware limited liability company ("Alliance Coal"), which prior
to August 20, 1999 was also a wholly-owned subsidiary of ARH, (b) several
other indirect corporate subsidiaries of ARH were merged with and into
corresponding limited liability companies, each of which is a wholly-owned
subsidiary of Alliance Coal, and (c) two indirect limited liability
company subsidiaries of ARH became subsidiaries of Alliance Coal as a
result of the merger described in clause (a) above. Collectively, the coal
production and marketing assets and operating subsidiaries of ARH acquired
by the Partnership, but excluding ARH, are referred to as the Alliance
Resource Group (the "Predecessor"). The Delaware limited partnerships and
limited liability companies and corporation that comprise the Partnership
are as follows: Alliance Resource Partners, L.P., Alliance Resource
Operating Partners, L.P. (the "Intermediate Partnership"), Alliance Coal,
LLC (the holding company for operations), Alliance Land, LLC, Alliance
Properties, LLC, Alliance Service, Inc., Backbone Mountain, LLC, Excel
Mining, LLC, Gibson County Coal, LLC, Hopkins County Coal, LLC, MC Mining,
LLC, Mettiki Coal, LLC, Mettiki Coal (WV), LLC, Mt. Vernon Transfer
Terminal, LLC, Pontiki Coal, LLC, Webster County Coal, LLC, and White
County Coal, LLC.
The accompanying consolidated financial statements include the accounts
and operations of the limited partnerships and limited liability companies
disclosed above and present the financial position as of December 31, 2001
and 2000 and the results of their operations, cash flows and changes in
partners' capital (deficit) for the years ended December 31, 2001 and 2000
and the period from commencement of operations on August 20, 1999 to
December 31, 1999. The accompanying combined financial statements include
the accounts and operations of the Predecessor for the period indicated.
All material intercompany transactions and accounts of the Partnership and
Predecessor have been eliminated.
Initial Public Offering and Concurrent Transactions
On August 20, 1999, the Partnership completed its initial public offering
(the "IPO") of 7,750,000 Common Units ("Common Units") representing
limited partner interests in the Partnership at a price of $19.00 per
unit.
Concurrently with the closing of the IPO, the Partnership entered into a
contribution and assumption agreement (the "Contribution Agreement") dated
August 20, 1999 among the Partnership and the other parties named therein,
whereby, among other things, ARH contributed its 100% member interest in
Alliance Coal, which is the sole member of thirteen subsidiary operating
limited liability companies, to the Intermediate Partnership, and the
Intermediate Partnership holds a 99.999% non-managing member interest in
Alliance Coal. The Partnership and the Intermediate Partnership are
managed by Alliance
25
Resource Management GP, LLC, a Delaware limited liability company (the
"Managing GP"), which as a result of the consummation of the transactions
under the Contribution Agreement, holds (a) a 0.99% and 1.0001% managing
general partner interest in the Partnership and the Intermediate
Partnership, respectively, and (b) a 0.001% managing member interest in
Alliance Coal. Also, as a result of the consummation of the transactions
completed under the Contribution Agreement, Alliance Resource GP, LLC, a
Delaware limited liability company and wholly-owned subsidiary of ARH (the
"Special GP"), holds (a) 1,232,780 Common Units, (b) 6,422,531
Subordinated Units convertible into Common Units in the future upon the
occurrence of certain events and (c) a 0.01% special general partner
interest in each of the Partnership and the Intermediate Partnership.
Concurrently with the closing of the IPO, the Special GP issued and the
Intermediate Partnership assumed the obligations under a $180 million
principal amount of 8.31% senior notes due August 20, 2014. The Special GP
also entered into and the Intermediate Partnership assumed the obligations
under a $100 million credit facility.
Consistent with guidance provided by the Emerging Issues Task Force in
Issue No. 87-21, "Change of Accounting Basis in Master Limited Partnership
Transactions," the Partnership maintained the historical cost basis of the
$121 million of net assets received under the Contribution Agreement.
Pro Forma Results of Operations (Unaudited)
For the year ended December 31, 1999, the pro forma total revenues would
have been approximately $346,828,000, the pro forma net income would have
been approximately $7,567,000 and net income per limited partner unit
would have been $0.48. The pro forma results of operations are derived
from the historical financial statements of the Partnership from the
commencement of operations on August 20, 1999 through December 31, 1999
and the Predecessor for the period from January 1, 1999 through August 19,
1999. The pro forma results of operations reflect certain pro forma
adjustments to the historical results of operations as if the Partnership
had been formed on January 1, 1999. The pro forma adjustments include pro
forma interest on debt assumed by the Partnership and the elimination of
income tax expense as income taxes will be borne by the partners and not
the Partnership.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ESTIMATES - The preparation of consolidated and combined financial
statements in conformity with generally accepted accounting principles
requires management to make estimates and assumptions that affect the
reported amounts and disclosures in the consolidated and combined
financial statements. Actual results could differ from those estimates.
FAIR VALUE OF FINANCIAL INSTRUMENTS - The carrying amounts for accounts
receivable, marketable securities, and accounts payable approximate fair
value because of the short maturity of those instruments. At December 31,
2001 and 2000, the estimated fair value of long-term debt was
approximately $226 million and $230 million, respectively. The fair value
of long-term debt is based on interest rates that are currently available
to the Partnership for issuance of debt with similar terms and remaining
maturities.
CASH AND CASH EQUIVALENTS - Cash and cash equivalents include cash on hand
and on deposit, including highly liquid investments with maturities of
three months or less.
CASH MANAGEMENT - The Partnership reclassified outstanding checks of
$3,352,000 and $4,698,000 at December 31, 2001 and 2000, respectively, to
accounts payable in the consolidated balance sheets.
26
MARKETABLE SECURITIES - At December 31, 2001, the Partnership has an
investment in a Federal Agency Note, which matures February 1, 2002 and is
classified as an available-for-sale security. At December 31, 2000, the
Partnership had investments in six-month U.S. Treasury Notes that were
classified as available-for-sale securities. At December 31, 2001 and
2000, the cost of marketable securities approximates fair value and no
effect of unrealized gains (losses) is reflected in Partners' capital
(deficit).
INVENTORIES - Coal inventories are stated at the lower of cost or market
on a first-in, first-out basis. Supply inventories are stated at the lower
of cost or market on an average cost basis.
PROPERTY, PLANT AND EQUIPMENT - Additions and replacements constituting
improvements are capitalized. Maintenance, repairs, and minor replacements
are expensed as incurred. Depreciation and amortization are computed
principally on the straight-line method based upon the estimated useful
lives of the assets or the estimated life of each mine, whichever is less
ranging from 5 to 20 years. Depreciable lives for mining equipment and
processing facilities range from 2 to 20 years. Depreciable lives for land
and land improvements and depletable lives for mineral rights range from 5
to 20 years. Depreciable lives for buildings, office equipment and
improvements range from 2 to 20 years. Gains or losses arising from
retirements are included in current operations. Depletion of mineral
rights is provided on the basis of tonnage mined in relation to estimated
recoverable tonnage. At December 31, 2001 and 2000, land and mineral
rights include $2,178,000 representing the carrying value of coal reserves
attributable to properties where the Partnership is not currently engaged
in mining operations or leasing to third parties, and therefore, the coal
reserves are not currently being depleted.
LONG-LIVED ASSETS - The Partnership reviews the carrying value of
long-lived assets and certain identifiable intangibles whenever events or
changes in circumstances indicate that the carrying amount may not be
recoverable based upon estimated undiscounted future cash flows. The
amount of an impairment is measured by the difference between the carrying
value and the fair value of the asset, which is based on cash flows from
that asset, discounted at a rate commensurate with the risk involved.
During 2000, the Partnership recorded an impairment loss of approximately
$2,439,000 relating to certain transloading facility assets, associated
with Seminole Electric Cooperative, Inc.'s ("Seminole") termination of a
long-term contract for transloading of coal from rail to barge. Because
this facility's revenues were primarily attributable to the Seminole
long-term contract, the carrying value of the transloading facility and
associated equipment, net of salvage value, was recorded as an impairment
and is included as an unusual item in 2000 in the accompanying
consolidated and combined statements of income.
ADVANCE ROYALTIES - Rights to coal mineral leases are often acquired
through advance royalty payments. Management assesses the recoverability
of royalty prepayments based on estimated future production and
capitalizes these amounts accordingly. Royalty prepayments expected to be
recouped within one year are classified as a current asset. As mining
occurs on those leases, the royalty prepayments are included in the cost
of mined coal. Royalty prepayments estimated to be nonrecoverable are
expensed.
COAL SUPPLY AGREEMENTS - The Predecessor purchased the coal operations of
MAPCO Inc. effective August 1, 1996, in a business combination using the
purchase method of accounting. A portion of the acquisition costs was
allocated to coal supply agreements. This allocated cost is being
amortized on the basis of coal shipped in relation to total coal to be
supplied during the respective contract terms. The amortization periods
end on various dates from September 2002 to December 2005. Accumulated
amortization for coal supply agreements was $26,432,000 and $22,139,000 at
December 31, 2001 and 2000, respectively.
27
RECLAMATION AND MINE CLOSING COSTS - The liability for the estimated cost
of future mine reclamation and closing procedures is recorded on a present
value basis when incurred and the associated cost is capitalized by
increasing the carrying amount of the related long-lived asset. Those
costs relate to sealing portals at underground mines and to reclaiming the
final pit and support acreage at surface mines. Other costs common to both
types of mining are related to removing or covering refuse piles and
settling ponds, and dismantling preparation plants, other facilities and
roadway infrastructure. Ongoing reclamation costs principally involve
restoration of disturbed land and are expensed as incurred during the
mining process.
WORKERS' COMPENSATION AND PNEUMOCONIOSIS ("BLACK LUNG") BENEFITS - The
Partnership is self-insured for workers' compensation benefits, including
black lung benefits. The Partnership accrues a workers' compensation
liability for the estimated present value of workers' compensation and
black lung benefits based on actuarial valuations. Effective January 1,
2001, the Partnership changed its method of estimating the black lung
benefits liability (Note 3).
INCOME TAXES - No provision for income taxes related to the operations of
the Partnership is included in the accompanying consolidated financial
statements because, as a Partnership, it is not subject to federal or
state income tax and the tax effect of its activities accrues to the
unitholders. Net income for financial statement purposes may differ
significantly from taxable income reportable to unitholders as a result of
differences between the tax bases and financial reporting bases of assets
and liabilities and the taxable income allocation requirements under the
Partnership agreement.
The Predecessor was included in the combined U.S. income tax returns of
ARH. The Predecessor provided for income taxes on its separate taxable
income and other tax attributes. Deferred income taxes are computed based
on recognition of future tax expense or benefits, measured by enacted tax
rates that are attributable to taxable or deductible temporary differences
between financial statement and income tax reporting bases of assets and
liabilities.
REVENUE RECOGNITION - Revenues from coal sales are recognized when title
passes to the customer as the coal is shipped. Non-coal sales revenues
primarily consist of fees associated with agreements to host and operate a
third-party coal synfuel facility and assist with the coal synfuel
marketing and other related services. These non-coal sales revenues are
recognized as the services are performed. Transportation revenues are
recognized in connection with the Partnership incurring the corresponding
costs of transporting the coal to customers through third-party carriers
since the Partnership is directly reimbursed for these costs through
customer billings.
NET INCOME PER UNIT - Basic net income per limited partner unit is
determined by dividing net income, after deducting the General Partners'
2% interest, by the weighted average number of outstanding Common Units
and Subordinated Units (a total of 15,405,311 units as of December 31,
2001 and 2000). Diluted net income per unit is based on the combined
weighted average number of Common Units, Subordinated Units and common
unit equivalents outstanding, which primarily include restricted units
granted under the Long-Term Incentive Plan (Note 11).
SEGMENT REPORTING - The Partnership has no reportable segments due to its
operations consisting solely of producing and marketing coal. The
Partnership has disclosed major customer sales information (Note 16) and
geographic areas of operation (Note 17).
NEW ACCOUNTING STANDARDS - Effective January 1, 2001, the Partnership
adopted Statement of Financial Accounting Standards ("SFAS") No. 133,
"Accounting for Derivative Instruments and Hedging Activities," which
establishes accounting and reporting standards for derivative instruments
and for hedging activities. It requires that all derivatives be recognized
as either assets or liabilities in the
28
statement of financial position and be measured at fair value. The
Partnership currently has no identified derivative instruments or hedging
activities. Accordingly, this standard had no effect on the Partnership's
consolidated financial statements upon adoption.
In June 2001, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 141, "Business Combinations" and No. 142 "Goodwill and Intangible
Assets." SFAS No. 141 eliminates the pooling-of-interests method of
accounting for business combinations and requires that all business
combinations be accounted for under the purchase method. In addition, it
further clarifies the criteria for recognition of intangible assets
separately from goodwill. This statement is effective for business
combinations initiated after June 30, 2001. SFAS No. 142 discontinues the
practice of amortizing goodwill and indefinite lived intangible assets and
initiates an annual review for impairment. This statement is effective
January 1, 2002, for all goodwill and other intangible assets included in
an entity's statement of financial position at that date, regardless of
when those assets were initially recognized. SFAS 141 and 142 are not
expected to have a material impact on the Partnership's financial
statements.
In August 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations," which requires the fair value of a liability for
an asset retirement obligation to be recognized in the period in which it
is incurred. When the liability is initially recorded, a cost is
capitalized by increasing the carrying amount of the related long-lived
asset. Over time, the liability is accreted to its present value each
period, and the capitalized cost is depreciated over the useful life of
the related asset. To settle the liability, the obligation for its
recorded amount is paid or a gain or loss upon settlement is incurred.
Since the Partnership has historically adhered to accounting principles
similar to SFAS No. 143 in accounting for its reclamation and mine closing
costs, the Partnership does not believe that adoption of SFAS No. 143,
effective January 1, 2003, will have a material impact on its financial
statements.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," which is effective for
fiscal years beginning after December 15, 2001, and is not expected to
have a material impact on the Partnership's financial statements upon
adoption on January 1, 2002.
RECLASSIFICATIONS - Certain reclassifications have been made to the 1999
combined and consolidated financial statements to conform to the
classifications used in 2001 and 2000.
3. ACCOUNTING CHANGE
The Partnership changed its method of estimating coal workers'
pneumoconiosis ("black lung") benefits liability effective January 1, 2001
to the service cost method described in SFAS No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions," which method
is permitted under SFAS No. 112 "Employers' Accounting for Postemployment
Benefits." The Partnership previously accrued the black lung benefits
liability at the present value of the actuarially determined current and
future estimated black lung benefit payments utilizing the methodology
prescribed under SFAS No. 5 "Accounting for Contingencies," which was also
permitted by SFAS No. 112. Recently, governmental regulations regarding
the black lung benefits claims approval process were enacted. These new
regulations specifically define the black lung disability as progressive
and also expand the definition of pneumoconiosis to mandate consideration
of diseases that are caused by factors other than exposure to coal dust.
The Partnership believes the change to the SFAS No. 106 measurement
methodology better matches black lung costs over the service lives of the
miners who ultimately receive the black lung benefits and is more
reflective of the recently enacted regulations, which place significant
emphasis on coal miners' future years of employment in the coal industry.
29
The adjustment of $7,939,000 to apply retroactively the new method of
estimating the black lung liability is included in net income for the year
ended December 31, 2001. The effect of the change for the year ended
December 31, 2001 was to decrease income before cumulative effect of a
change in accounting principle $435,000 ($(0.03) per basic and diluted
limited partner unit) and increase net income $7,504,000 ($0.48 and $0.47
per basic and diluted partner unit, respectively). Assuming the
retroactive application of the service cost method of estimating the black
lung liability, the pro forma net income for the year ended December 31,
2000, and the period from the Partnership's commencement of operations on
August 20, 1999 to December 31, 1999, would have been approximately
$14,907,000 and $6,395,000 or $0.95 and $0.41 per basic limited partner
unit and $0.94 and $0.41 per diluted limited partner unit, respectively,
as compared to reported net income of $15,581,000 and $6,272,000 or $0.99
and $0.40 per basic limited partner unit and $0.98 and $0.40 per diluted
limited partner unit, respectively. Pro forma net income for the
Predecessor period from January 1, 1999 to August 19, 1999 would have been
$10,071,000 compared to reported net income of $10,205,000.
4. UNUSUAL ITEMS
The Partnership was involved in litigation with Seminole with respect to
Seminole's termination of a long-term contract for the transloading of
coal from rail to barge through the Mt. Vernon terminal in Indiana. The
final resolution between the parties, reached in conjunction with an
arbitrator's decision rendered during the third quarter of 2000, included
both cash payments and amendments to an existing coal supply contract. The
Partnership recorded income of $12,141,000, which is net of litigation
expenses of approximately $881,000 and an impairment charge of $2,439,000
relating to the facility's assets. Additionally, during the third quarter
of 2000, the Partnership recorded an expense of $2,675,000, consisting of
$675,000 relating to a settlement and $2,000,000 attributable to
contingencies associated with third party claims arising out of the
Partnership's mining operations. The net effect of these unusual items is
$9,466,000 recorded in the year ended December 31, 2000.
5. INVENTORIES
Inventories consist of the following at December 31, (in thousands):
2001 2000
------- -------
Coal $ 4,184 $ 5,140
Supplies 7,416 5,702
------- -------
$11,600 $10,842
======= =======
30
6. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consists of the following at December 31,
(in thousands):
2001 2000
---------- ----------
Mining equipment and processing facilities $ 299,480 $ 267,287
Land and mineral rights 17,691 17,686
Buildings, office equipment and improvements 29,359 24,224
Construction in progress 20,520 11,248
---------- ----------
367,050 320,445
Less accumulated depreciation, depletion and amortization (169,960) (135,782)
---------- ----------
$ 197,090 $ 184,663
========== ==========
7. LONG-TERM DEBT
Long-term debt consists of the following at December 31, (in thousands):
2001 2000
--------- ---------
Senior notes $ 180,000 $ 180,000
Term loan 46,250 50,000
--------- ---------
226,250 230,000
Less current maturities (15,000) (3,750)
--------- ---------
$ 211,250 $ 226,250
========= =========
In connection with the closing of the IPO, the Special GP issued and the
Intermediate Partnership assumed obligations with respect to a $180
million principal amount of senior notes pursuant to a Note Purchase
Agreement with a group of institutional investors in a private placement
offering. The senior notes are payable in ten annual installments of $18
million beginning in August 2005 and bear interest at 8.31%, payable
semiannually.
The Special GP also entered into, and the Intermediate Partnership assumed
obligations under, a $100 million credit facility. The credit facility
consists of three tranches, including a $50 million term loan facility, a
$25 million working capital facility and a $25 million revolving credit
facility. In connection with the closing of the IPO, the Special GP
borrowed $50 million under the term loan facility and the Special GP and
Intermediate Partnership initially purchased $50 million of U.S. Treasury
Notes, which secured the term loan through September 19, 2002. These
investments were subject to certain provisions of the credit facility,
which restricted the use of these investments for financing a required
level of capital expenditures through August 2001. During 2001, the
Partnership had satisfied the capital expenditure requirements and
consequently, the Partnership's use of these investments was not
restricted. The Partnership liquidated these investments during 2001. The
Partnership has outstanding borrowings of $46.3 million under the term
loan facility at December 31, 2001.
The working capital facility can be used to provide working capital and,
if necessary, to fund distributions to unitholders. The revolving credit
facility can be used for general business purposes, including capital
expenditures and acquisitions. The rate of interest charged is adjusted
quarterly based on a pricing grid, which is a function of the ratio of the
Partnership's debt to cash flow. The credit facility provides the
Partnership the option of borrowing at either (1) the London Interbank
Offered Rate
31
("LIBOR") or (2) the "Base Rate" which is equal to the greater of (a) the
Chase Prime Rate, or (b) the Federal Funds Rate plus 1/2 of 1%, plus, in
either option, an applicable margin. The weighted average interest rates
on the term loan facility at December 31, 2001 and 2000 were 3.40% and
7.77%, respectively. In accordance with the pricing grid, a commitment fee
ranging from 0.375% to 0.500% per annum is paid quarterly on the unused
portion of the working capital and revolving credit facilities. There were
no amounts outstanding under the Partnership's working capital facility or
revolving credit facility as of December 31, 2001 and 2000. The credit
facility expires in August 2004.
The senior notes and credit facility are guaranteed by all subsidiaries of
the Intermediate Partnership. The senior notes and credit facility contain
various restrictive and affirmative covenants, including limitations on
the amount of distributions by the Intermediate Partnership and the
incurrence of other debt. The Partnership was in compliance with the
covenants of both the credit facility and senior notes at December 31,
2001 and 2000.
The Partnership incurred debt issuance costs aggregating approximately
$3,517,000, which have been deferred and are being amortized as a
component of interest expense over the terms of the notes.
The Partnership entered into agreements with three banks to provide
letters of credit in an aggregate amount of $25.0 million. At December 31,
2001, the Partnership had $15.0 million in letters of credit outstanding.
The Special GP guarantees the letters of credit (Note 14).
Aggregate maturities of long-term debt are payable as follows
(in thousands):
YEAR ENDING
DECEMBER 31,
2002 $ 15,000
2003 16,250
2004 15,000
2005 18,000
2006 18,000
Thereafter 144,000
--------
$226,250
========
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
32
distributions of available cash. However, under certain circumstances, up
to 50% of the Subordinated Units may convert into Common Units on or after
September 30, 2003. Common Units will accrue arrearages with respect to
distributions for any quarter during the subordination period, but
Subordinated Units will not accrue any arrearages with respect to
distributions for any quarter.
If quarterly distributions of available cash exceed the MQD or the target
distributions levels, the General Partners will receive distributions
based on specified increasing percentages of the available cash that
exceeds the MQD or target distribution levels. The target distribution
levels are based on the amounts of available cash from the Partnership's
operating surplus distributed for a given quarter that exceed
distributions for the MQD and common unit arrearages, if any.
For the 42-day period from the Partnership's commencement of operations
(on August 20, 1999) through September 30, 1999, the Partnership paid a
pro-rata MQD distribution of $0.23 per unit on its outstanding Common and
Subordinated Units. For each of the quarters ended December 31, 1999
through September 30, 2001, quarterly distributions of $0.50 per unit were
paid to the common and subordinated unitholders. On January 29, 2002, the
Partnership declared a MQD, for the period from October 1, 2001 to
December 31, 2001, of $0.50 per unit, totaling approximately $7,703,000 on
its outstanding Common and Subordinated Units, payable on February 14,
2002 to all unitholders of record on February 4, 2002.
9. INCOME TAXES
The Predecessor recognized a deferred tax asset for the future tax
benefits attributable to deductible temporary differences and other credit
carryforwards, including alternative minimum tax credit carryforwards.
Realization of these future tax benefits was dependent on the
Predecessor's ability to generate future taxable income, which was not
assured. Management of the Predecessor believed that future taxable income
would be sufficient to recognize only a portion of the tax benefits and
had established a valuation allowance.
Concurrent with the closing of the IPO on August 20, 1999, and in
connection with the Contribution Agreement, ARH retained the current and
deferred income taxes of the Predecessor.
Income before income taxes is derived from domestic operations.
Significant components of income taxes are as follows (in thousands):
FOR THE
PERIOD FROM
JANUARY 1, 1999
TO
AUGUST 19, 1999
---------------
Current:
Federal $3,376
State 483
------
3,859
Deferred:
Federal 595
State 44
------
639
Income tax expense $4,498
======
33
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
TO
AUGUST 19, 1999
---------------
Statutory rate 35%
Increase (decrease) resulting from:
Excess of tax over book depletion (21)
Alternative minimum tax credit carryforwards 3
State income taxes, net of federal benefit 3
Valuation allowance 10
Other 1
---
Effective income tax rate 31%
===
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 ENDED OF OPERATIONS
DECEMBER 31, (ON AUGUST 20, 1999)
------------------------- TO
2001 2000 DECEMBER 31, 1999
---- ---- -----------------
Net income per limited partner unit $ 16,758 $ 15,269 $ 6,147
Weighted average limited partner units - basic 15,405 15,405 15,405
Basic net income per limited partner unit $ 1.09 $ 0.99 $ 0.40
========== ========== ==========
Basic net income per limited partner unit
before accounting change $ 0.58 $ 0.99 $ 0.40
========== ========== ==========
Weighted average limited partner units - basic 15,405 15,405 15,405
Units contingently issuable:
Restricted units for Long-Term Incentive Plan 263 142 --
Directors' compensation units deferred 9 4 --
Supplemental Executive Retirement Plan 8 -- --
---------- ---------- ----------
Weighted average limited partner units, assuming
dilutive effect of restricted units 15,685 15,551 15,405
---------- ---------- ----------
Diluted net income per limited partner unit $ 1.07 $ 0.98 $ 0.40
========== ========== ==========
Diluted net income per limited partner unit before
accounting change $ 0.57 $ 0.98 $ 0.40
========== ========== ==========
34
11. EMPLOYEE BENEFIT PLANS
LONG-TERM INCENTIVE PLAN - Effective January 1, 2000, the Managing GP
adopted the Long-Term Incentive Plan (the "LTIP") for certain employees
and directors of the Managing GP and its affiliates who perform services
for the Partnership. Annual grant levels and vesting provisions for
designated participants are recommended by the President and Chief
Executive Officer of the Managing GP, subject to the review and approval
of the Compensation Committee. Grants are made either of restricted units,
which are "phantom" units that entitle the grantee to receive a Common
Unit or an equivalent amount of cash upon the vesting of a phantom unit,
or options to purchase Common Units. Common Units to be delivered upon the
vesting of restricted units or to be issued upon exercise of a unit option
will be acquired by the Managing GP in the open market at a price equal to
the then prevailing price, or directly from ARH or any other third party,
including units newly issued by the Partnership, units already owned by
the Managing GP, or any combination of the foregoing. The Partnership
agreement provides that the Managing GP be reimbursed for all costs
incurred in acquiring these Common Units or in paying cash in lieu of
Common Units upon vesting of the restricted units. The aggregate number of
units reserved for issuance under the LTIP is 600,000. Effective January
1, 2000 and 2001 the Compensation Committee approved grants of 142,100 and
129,200 restricted units, respectively, which vest at the end of the
subordination period, which will generally not end before September 30,
2004. During 2001, 8,500 units were forfeited. During 2001 and 2000, the
Managing GP billed the Partnership approximately $1,929,000 and $538,000,
respectively, attributable to the LTIP. The Partnership has recorded this
amount as compensation expense. Effective January 1, 2002, the
Compensation Committee approved additional grants of 131,885 restricted
units, which also vest at the end of the subordination period.
DEFINED CONTRIBUTION PLANS - The Partnership's employees currently
participate in a defined contribution profit sharing and savings plan
sponsored by the Partnership, which is the same plan sponsored by the
Predecessor. This plan covers substantially all full-time employees. Plan
participants may elect to make voluntary contributions to this plan up to
a specified amount of their compensation. The Partnership makes
contributions based on matching 75% of employee contributions up to 3% of
their annual compensation as well as an additional nonmatching
contribution of 3/4 of 1% of their compensation. Additionally, the
Partnership contributes a defined percentage of eligible earnings for
certain employees not covered by the defined benefit plan described below.
The Partnership's expense for its plan was approximately $1,935,000 and
$1,590,000 for the years ended December 31, 2001 and 2000, respectively,
and $715,000 for the period from August 20, 1999 to December 31, 1999. The
Predecessor's expense for the plan was $1,226,000 for the period from
January 1, 1999 to August 19, 1999.
DEFINED BENEFIT PLANS - Certain employees at the mining operations
participate in a defined benefit plan sponsored by the Partnership, which
is the same plan sponsored by the Predecessor. The benefit formula is a
fixed dollar unit based on years of service.
35
The following sets forth changes in benefit obligations and plan assets
for the years ended December 31, 2001 and 2000 and the funded status of
the plans reconciled with amounts reported in the Partnership's
consolidated financial statements at December 31, 2001 and 2000,
respectively (dollars in thousands):
2001 2000
-------- --------
CHANGE IN BENEFIT OBLIGATIONS:
Benefit obligations at beginning of year $ 10,135 $ 7,774
Service cost 2,050 1,971
Interest cost 755 596
Actuarial (gain) loss 384 (136)
Benefits paid (122) (70)
-------- --------
Benefit obligation at end of year 13,202 10,135
-------- --------
CHANGE IN PLAN ASSETS:
Fair value of plan assets at beginning of year 9,500 8,265
Employer contribution 1,500 1,100
Actual return (loss) on plan assets (370) 205
Benefits paid (122) (70)
-------- --------
Fair value of plan assets at end of year 10,508 9,500
-------- --------
Funded status (2,694) (635)
Unrecognized prior service cost 235 284
Unrecognized actuarial (gain) loss 814 (828)
-------- --------
Net amount recognized $ (1,645) $ (1,179)
======== ========
WEIGHTED-AVERAGE ASSUMPTIONS AS OF DECEMBER 31:
Discount rate 7.25% 7.50%
Expected return on plan assets 9.00% 9.00%
COMPONENTS OF NET PERIODIC BENEFIT COST:
Service cost $ 2,050 $ 1,971
Interest cost 755 596
Expected return on plan assets (888) (737)
Prior service cost 48 48
Net gain -- (49)
-------- --------
Net periodic benefit cost $ 1,965 $ 1,829
======== ========
Effect on minimum pension liability $ 814 $ --
======== ========
12. RECLAMATION AND MINE CLOSING COSTS
The majority of the Partnership's operations are governed by various state
statutes and the Federal Surface Mining Control and Reclamation Act of
1977, which establish reclamation and mine closing standards. These
regulations, among other requirements, require restoration of property in
accordance with specified standards and an approved reclamation plan. The
Partnership has estimated the costs and timing of future reclamation and
mine closing costs and recorded those estimates on a present value basis
using a 6% discount rate.
36
Discounting resulted in reducing the accrual for reclamation and mine
closing costs by $12,184,000 and $10,420,000 at December 31, 2001 and
2000, respectively. Estimated payments of reclamation and mine closing
costs as of December 31, 2001 are as follows (in thousands):
Year ending December 31,
2002 $ 1,078
2003 1,743
2004 1,848
2005 3,538
2006 2,518
Thereafter 17,924
-------
Aggregate undiscounted
reclamation and mine
closing 28,649
Effect of discounting 12,184
-------
Total reclamation and mine
closing costs 16,465
Less current portion 1,078
-------
Reclamation and mine
closing costs $15,387
=======
The following table presents the activity affecting the reclamation and
mine closing liability (in thousands):
PARTNERSHIP PREDECESSOR
---------------------------------------------------------- ---------------
FROM
COMMENCEMENT FOR THE
YEAR ENDED OF OPERATIONS PERIOD FROM
DECEMBER 31, (ON AUGUST 20, 1999) JANUARY 1, 1999
------------------------------------ TO TO
2001 2000 DECEMBER 31, 1999 AUGUST 19, 1999
--------------- --------------- ----------------- ---------------
Beginning balance $ 16,018 $ 14,796 $ 13,856 $ 13,800
Accrual 943 1,074 348 457
Payments (454) (764) (394) (401)
Allocation of liability
associated with
acquisition and mine
development (42) 912 986 --
--------------- --------------- --------------- ---------------
Ending balance $ 16,465 $ 16,018 $ 14,796 $ 13,856
=============== =============== =============== ===============
13. PNEUMOCONIOSIS ("BLACK LUNG") BENEFITS
Certain mine operating entities of the Partnership are liable under state
statutes and the Federal Coal Mine Health and Safety Act of 1969, as
amended, to pay black lung benefits to eligible employees and former
employees and their dependents.
The Partnership changed its method of estimating black lung benefits
liability effective January 1, 2001 to the service cost method (Note 3).
Under the service cost method the calculation of the actuarial present
value of the estimated black lung obligation is based on an actuarial
study performed by independent actuaries. Actuarial gains or losses are
amortized over the remaining service period of active miners. The discount
rate used to calculate the estimated present value of future obligations
was 5.5% and 6.0% at December 31, 2001 and 2000, respectively.
37
The reconciliation of changes in benefit obligations at December 31, 2001
is as follows (in thousands):
Benefit obligations at beginning of year, including cumulative effect of
accounting change of $7,939 effective January 1, 2001 (Note 3) $ 13,712
Service cost 464
Interest cost 705
Benefits paid (266)
--------
Benefit obligations at end of year $ 14,615
========
The Partnership previously accrued the black lung benefits liability based
upon the actuarially computed present and future claims. The cost or
reduction of cost due to change in the estimate of black lung benefits
charged (credited) to operations for the year ended December 31, 2000, the
period from the Partnership's commencement of operations on August 20,
1999 to December 31, 1999, and the Predecessor period from January 1, 1999
to August 19, 1999, was $123,000, $(1,028,000), and $726,000,
respectively.
The U.S. Department of Labor has issued revised regulations that will
alter the claims process for the federal black lung benefit recipients.
Both the coal and insurance industries are currently challenging through
litigation certain provisions of the revised regulations. The revised
regulations are expected to result in an increase in the incidence and
recovery of black lung claims.
14. RELATED PARTY TRANSACTIONS
The Partnership Agreement provides that the Managing GP and its affiliates
be reimbursed for all direct and indirect expenses it incurs or payments
it makes on behalf of the Partnership, including management's salaries and
related benefits, and accounting, budget, planning, treasury, public
relations, land administration, environmental, permitting, payroll,
benefits, disability, workers' compensation management, legal and
information technology services. The Managing GP may determine in its sole
discretion the expenses that are allocable to the Partnership. Total costs
billed by the Managing GP and its affiliates to the Partnership were
approximately $6,503,000, $3,899,000 and $1,283,000 for the years ended
December 31, 2001 and 2000, and the period from the Partnership's
commencement of operations on August 20, 1999 to December 31, 1999,
respectively.
ARH allocated certain direct and indirect general and administrative
expenses to the Predecessor. These allocations were primarily based on the
relative size of the direct mining operating costs incurred by each of the
mine locations of the Predecessor. The allocations of general and
administrative expenses to the Predecessor were approximately $2,982,000
for the period from January 1, 1999 to August 19, 1999. Management is of
the opinion that the allocations used were reasonable and appropriate.
During November 1999, the Managing GP was authorized by its Board of
Directors to purchase up to 1.0 million Common Units of the Partnership.
As of December 31, 2001 and 2000, the Managing GP owned 164,000 Common
Units that were purchased in the open market at prevailing market prices.
During September 2000, the Special GP acquired coal reserves and the right
to acquire additional coal reserves that are (a) contiguous to the
Partnership's Webster County Coal, LLC ("WCC") mining complex ("Providence
No. 3 Reserves") and (b) contiguous to the Partnership's Hopkins County
Coal, LLC ("HCC") mining complex ("Elk Creek Reserves"). Such coal
reserves and the rights to acquire additional coal reserves were
transferred to SGP Land, LLC ("SGP Land"), a newly formed wholly-owned
subsidiary of the Special GP.
38
Concurrent with such coal reserve acquisitions, the Special GP, through
affiliates, was negotiating for the purchase of (a) the capital stock of
Roberts Bros. Coal Co., Inc., Warrior Coal Mining Company, and Warrior
Coal Corporation, and (b) the related coal reserves ("Warrior Reserves")
owned by Cardinal Trust, LLC (collectively the "Warrior Group"). The
Warrior Group's operating assets are located adjacent to the Providence
No. 3 Reserves and these operating assets, excluding the Warrior Reserves,
were purchased by a newly formed affiliate of the Special GP, Warrior
Coal, LLC ("Warrior Coal") in January, 2001. SGP Land acquired the Warrior
Reserves, which are located between the Providence No. 3 Reserves and HCC
in January, 2001.
SGP Land entered into a mineral lease and sublease with WCC for a portion
of each of the Providence No. 3 Reserves and the Warrior Reserves, and
granted an option to HCC to lease and/or sublease the Elk Creek Reserves.
Under the terms of the WCC lease and sublease, WCC has an annual minimum
royalty obligation of $2.7 million, payable in advance, from 2000 to 2013
or until $37.8 million of cumulative annual minimum and/or earned royalty
payments have been paid. WCC paid an annual minimum royalty of $2.7
million in 2001 and 2000. Under the terms of the HCC option to lease and
sublease, HCC paid option fees of $684,000 and $645,000 in 2001 and 2000,
respectively. The anticipated annual minimum royalty obligation is
$684,000 payable in advance, from 2002 to 2009.
During 2000, ARH and the Managing GP were approached with the opportunity
to purchase certain mining assets of Warrior Coal located adjacent to the
Partnership's western Kentucky operation. Warrior Coal is an underground
mining complex that utilizes continuous mining units employing room and
pillar mining techniques. Warrior Coal produces approximately 1.5 million
tons per year, controls reserves that will provide for a minimum of ten
years of mining, and has the possibility of controlling additional
reserves in the future.
In accordance with the right of first refusal provision in the Omnibus
Agreement between ARH and the Partnership's Managing GP, ARH offered the
Managing GP the opportunity to purchase Warrior Coal. At the time, the
Managing GP declined the opportunity to purchase Warrior Coal as the
Partnership had previously committed to major capital expenditures at two
existing operations. As a condition to not exercising its right of first
refusal, the Partnership requested that ARH enter into a put and call
arrangement for Warrior Coal. After further discussions, ARH and the
Partnership, with the approval of the Conflicts Committee of the Managing
GP, entered into an Amended and Restated Put and Call Option Agreement
("Put/Call Agreement") in January 2001. Concurrently ARH, through an
indirect wholly-owned subsidiary, acquired Warrior Coal in January 2001
for $10 million.
The Put/Call Agreement preserved an opportunity for the Partnership to
acquire Warrior Coal during a specified time period in the future,
although at a price significantly greater than the price paid by ARH.
Under the terms of the Put/Call Agreement, ARH can require the Partnership
to purchase Warrior Coal during the period from January 2 to January 11,
2003. The put option price is approximately $12.5 million. The Partnership
can also require ARH to sell Warrior Coal to the Partnership during the
period from April 12, 2003 to December 31, 2006. The call option price
ranges between $13.6 million and $22.2 million depending on when the call
option is exercised.
The option provisions of the Put/Call Agreement are subject to certain
conditions, among others, including (a) the non-occurrence of a material
adverse change in the business and financial condition of Warrior Coal,
(b) the prohibition of any dividends or other distributions to Warrior
Coal's shareholders, (c) the maintenance of Warrior Coal's assets in good
working condition, (d) the prohibition on the sale of any equity interest
in Warrior Coal except for the options contained in the Put/Call
Agreement, and (e) the prohibition on the sale or transfer of Warrior
Coal's assets except those made in the ordinary course of its business.
The Put/Call Agreement option prices reflect negotiated sale and purchase
amounts that both parties determined would allow each party to satisfy
acceptable minimum investment returns in the event either the put or call
options are exercised. The Partnership has not made a final determination
concerning the potential exercise of its call option and has not been
advised by ARH concerning ARH's intention to exercise its put option. The
Partnership has developed financial projections for Warrior Coal based on
due diligence procedures it customarily performs when considering the
acquisition of a coal mine. The assumptions underlying the financial
projections made by the Partnership for Warrior Coal include (a) annual
production levels ranging from 1.5 million to 1.8 million tons, (b) coal
prices at or below current coal prices and (c) a discount rate of 12
percent. Based on these financial projections, at this time, the
Partnership believes that the fair value of Warrior Coal is equal to or
greater than the put option exercise price.
39
The Partnership provides management and administrative services to Warrior
Coal and SGP Land under an administrative service agreement. Under this
agreement, the Partnership has recognized approximately $1,019,000 as a
reduction of general and administrative expenses during the year ended
December 31, 2001. Accounts receivable from Warrior Coal of $108,000,
offsets a portion of the due to affiliates at December 31, 2001.
During 2001, the Partnership entered into an agreement with Warrior Coal
to perform certain reclamation procedures for the Partnership. The total
estimated cost of the reclamation procedures covered by this agreement is
$475,000 of which approximately $315,000 remains to be expended in 2002
for the expected completion of reclamation procedures by Warrior Coal.
During 2001, the Partnership made coal purchases of approximately
$3,135,000 from Warrior Coal. Accounts payable to Warrior Coal of
$1,876,000 is included in the amount due to affiliates at December 31,
2001. During December 2001, the Partnership entered into coal supply
agreements with Warrior Coal for the purchase of 1.8 million tons for the
year ending December 31, 2002.
The Partnership has a noncancelable operating lease arrangement with the
Special GP for the coal preparation plant and ancillary facilities at the
Gibson County Coal, LLC mining complex. Based on the terms of the lease,
the Partnership will make monthly payments of approximately $216,000
through January, 2010. Lease expense incurred for the years ended December
31, 2001 and 2000 was $2,592,000 and $14,000, respectively.
In 2001, SGP Land, as a successor in interest to an unaffiliated
third-party, entered into an amended mineral lease with MC Mining, LLC
("MC Mining"). Under the terms of the lease, MC Mining has and will pay an
annual minimum royalty obligation of $300,000 until $6.0 million of
cumulative annual minimum and/or earned royalty payments have been paid.
MC Mining paid royalties of $705,000 for the year ended December 31, 2001.
During 2001, the Partnership entered into agreements with three banks to
provide letters of credit in an aggregate amount of $25.0 million to
maintain surety bonds to secure its obligations for reclamation
liabilities and workers' compensation benefits. At December 31, 2001 the
Partnership had $15.0 million in letters of credit outstanding. The
Special GP guarantees these letters of credit, and as a result the
Partnership has agreed to compensate the Special GP for a guarantee fee
equal to 0.30% per annum of the face amount of the letters of credit
outstanding. The Partnership paid approximately $8,800 in guarantee fees
to the Special GP for the year ended December 31, 2001.
40
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):
AFFILIATE OTHERS TOTAL
--------- ------ -------
Year ending December 31,
2002 $ 2,595 $ 702 $ 3,297
2003 2,595 568 3,163
2004 2,595 578 3,173
2005 2,595 578 3,173
2006 2,595 406 3,001
Thereafter 10,595 496 11,091
------- ------ --------
$23,570 $3,328 $ 26,898
======= ======= ========
Lease expense under all operating leases was $4,224,000, $1,409,000,
$801,000, and $496,000 for the years ended December 31, 2001 and 2000, the
period from the Partnership's commencement of operations on August 20,
1999 to December 31, 1999, and the Predecessor period from January 1, 1999
to August 19, 1999, respectively.
CONTRACTUAL COMMITMENTS - In connection with the expansion of an existing
mine into adjacent coal reserves and construction of a new mine shaft at
another existing mine, the Partnership has remaining contractual
commitments of approximately $15.3 million at December 31, 2001.
GENERAL LITIGATION - The Partnership is involved in various lawsuits,
claims and regulatory proceedings, including those conducted by the Mine
Safety and Health Administration, incidental to its business. The
Partnership provides for costs related to litigation and regulatory
proceedings, including civil fines issued as part of the outcome of such
proceedings, when a loss is probable and the amount is reasonably
determinable. The Partnership also recorded an expense of $2,675,000
consisting of $675,000 relating to a settlement and $2,000,000
attributable to contingencies associated with third party claims arising
out of its mining operations, which is reflected in "Unusual items" in the
accompanying consolidated and combined statements of income for the year
ended December 31, 2000. In the opinion of management, the outcome of such
matters to the extent not previously provided for or covered under
insurance, will not have a material adverse effect on the Partnership's
business, financial position or results of operations, although management
cannot give any assurance to that effect.
OTHER - During September 2001, the Partnership completed its annual
property insurance renewal. Recent insurance carrier losses worldwide have
created a tightening market reducing available capacity for underwriting
property insurance. As a result, the Partnership, and its affiliates
retained a 12.5% participating interest along with its insurance carriers
in the commercial property program. The aggregate maximum limit in the
commercial property program is $75,000,000 per occurrence, of which, the
Partnership is responsible for a maximum limit of $9,375,000 per
occurrence of the amount covered by property insurance. While the
Partnership does not have a significant history of material insurance
claims, the ultimate amount of claims incurred, if any, are dependent on
future developments. As a result, the Partnership's participation in the
commercial property program could have a material adverse effect on the
Partnership's financial condition and results of operations.
41
On March 14, 2002, PSI Energy Inc. ("PSI") notified Gibson County Coal LLC
that they intended to withhold approximately $644,819 (excluding interest
thereon, if any) in payments due to Gibson County Coal over a three-month
period beginning in March through May 2002. This amount relates to alleged
penalties associated with a contract specification addressing the hardness
of coal provided to PSI. Gibson County Coal and PSI have had on-going
discussions since March 2001 concerning the procedures for and testing of
the coal supplied by the Gibson County mining complex and have been unable
to-date to resolve their differences. Although Gibson County Coal is
pursuing on-going discussions with PSI regarding a potential resolution of
certain issues concerning contractual interpretation, the Partnership
cannot assure that this matter can be resolved without resort to
mediation, arbitration, and/or litigation. Gibson County Coal strongly
disagrees with PSI's position.
16. CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS
The Partnership has significant long-term coal supply agreements, some of
which contain price adjustment provisions designed to reflect changes in
market conditions, labor and other production costs and, when the coal is
sold other than FOB the mine, changes in truck rates. Total revenues to
major customers, including transportation revenues (Note 2), which exceed
ten percent (seven percent for Customer D in 2001) of total revenues are
as follows (in thousands):
PARTNERSHIP PREDECESSOR
--------------------------------------- -----------
FROM
COMMENCEMENT FOR THE
YEAR ENDED OF OPERATIONS PERIOD FROM
DECEMBER 31, (ON AUGUST 20, 1999) JANUARY 1, 1999
----------------- TO TO
2001 2000 DECEMBER 31, 1999 AUGUST 19, 1999
---- ------- -------------------- ---------------
Customer A $74,091 $58,498 $16,090 $31,328
Customer B 63,241 67,234 23,104 38,875
Customer C 47,492 61,007 26,993 40,752
Customer D 32,614 38,713 11,926 19,582
Trade accounts receivable from these customers totaled approximately $14.9
million at December 31, 2001. The Partnership's bad debt experience has
historically been insignificant, however the Partnership established an
allowance of $763,000 during 2001, due to the Partnership's total credit
exposure to Enron Corp., which filed for bankruptcy protection during
December, 2001. Financial conditions of its customers could result in a
material change to this estimate in future periods. The coal supply
agreements with customers A, B, C and D expire in 2010, 2006, 2001 and
2006, respectively.
42
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 ENDED OF OPERATIONS PERIOD FROM
DECEMBER 31, (ON AUGUST 20, 1999) JANUARY 1, 1999
------------ TO TO
2001 2000 DECEMBER 31, 1999 AUGUST 19, 1999
-------- -------- -------------------- ----------------
Revenues:
United States $446,300 $363,469 $134,125 $221,339
Other foreign countries -- -- -- 10,494
-------- -------- -------- --------
$446,300 $363,469 $134,125 $231,833
======== ======== ======== ========
Long-lived assets:
United States $218,877 $210,996 $203,697 $200,057
Other foreign countries -- -- -- --
-------- -------- -------- --------
$218,877 $210,996 $203,697 $200,057
======== ======== ======== ========
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 ENDED OF OPERATIONS PERIOD FROM
DECEMBER 31, (ON AUGUST 20, 1999) JANUARY 1, 1999
----------------------------- TO TO
2001 2000 DECEMBER 31, 1999 AUGUST 19, 1999
---- ---- -------------------- ---------------
Cash paid for:
Interest $ 18,070 $ 19,043 $ 1,173 $ --
Income taxes paid through
Parent (Note 9) -- -- -- 3,504
Noncash investing and
financing activities:
Debt transferred from
Special GP -- -- 230,000 --
Marketable securities
transferred from Special GP -- -- 15,486 --
43
19. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
A summary of the quarterly operating results for the Partnership is as
follows (in thousands, except unit and per unit data):
QUARTER ENDED
----------------------------------------------------------------
MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31,
2001(1) 2001 2001 2001
------------ ------------ ------------ ------------
Revenues $ 106,752 $ 110,722 $ 117,894 $ 110,932
Operating income 8,456 4,012 11,943 803
Net income (loss) 12,375 (46) 7,816 (3,045)
Basic net income (loss) per limited partner unit $ 0.79 $ (0.01) $ 0.50 $ (0.19)
Basic net income (loss) per limited partner unit
before accounting change $ 0.28 $ (0.01) $ 0.50 $ (0.19)
Diluted net income (loss) per limited
partner unit $ 0.77 $ (0.01) $ 0.49 $ (0.19)
Diluted net income (loss) per limited
partner unit before accounting change $ 0.28 $ (0.01) $ 0.49 $ (0.19)
Weighted average number of units
outstanding - basic 15,405,311 15,405,311 15,405,311 15,405,311
Weighted average number of units
outstanding - diluted 15,680,594 15,681,411 15,678,013 15,708,968
QUARTER ENDED
----------------------------------------------------------------
MARCH 31 JUNE 30, SEPTEMBER 30, DECEMBER 31,
2000 2000 2000 (2) 2000
------------ ------------ ------------ ------------
Revenues $ 89,420 $ 86,652 $ 96,459 $ 90,938
Operating income 6,191 5,912 15,669 3,096
Net income (loss) 2,366 2,098 11,560 (443)
Basic net income (loss) per limited partner unit $ 0.15 $ 0.13 $ 0.74 $ (0.03)
Diluted net income (loss) per limited
partner unit $ 0.15 $ 0.13 $ 0.73 $ (0.03)
Weighted average number of units
outstanding - basic 15,405,311 15,405,311 15,405,311 15,405,311
Weighted average number of units
outstanding - diluted 15,550,489 15,550,845 15,552,017 15,553,372
(1) The Partnership changed its method of estimating black lung benefits
liability effective January 1, 2001. The cumulative effect of this
change resulted in the reduction of this liability and a corresponding
increase in net income of $7,939,000 for the quarter (Note 3).
(2) The Partnership recorded income of $12.2 million, which is net of
litigation expenses and costs relating to the impairment of certain
transloading facility assets. Additionally, the Partnership recorded
an expense of $2.7 million related to litigation matters settled and
contingencies associated with other litigation matters. The net effect
of these unusual items for the quarter was $9.5 million (Note 4).
Operating income in the above table represents income from operations
before interest expense.
* * * * * *
44
SCHEDULE II
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
YEAR ENDED DECEMBER 31, 2001
--------------------------------------------------------------------------------
BALANCE AT ADDITIONS BALANCE AT
BEGINNING CHARGED TO END OF
OF YEAR INCOME DEDUCTIONS YEAR
---------- ---------- ---------- ----------
(IN THOUSANDS)
2001
Allowance for doubtful accounts $ -- $ 763 $ -- $ 763
====== ====== ====== ======
A table for fiscal years ended December 31, 2000 and 1999 has been omitted
because there was no allowance for doubtful accounts.
45
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 November 25, 2002.
ALLIANCE RESOURCE PARTNERS, L.P.
By: Alliance Resource Management GP, LLC
its managing general partner
/s/ Dale G. Wilkerson
-------------------------------------
Dale G. Wilkerson
Vice President and Controller
(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 November 25, 2002
------------------------------ Officer and Director
Joseph W. Craft III (Principal Executive Officer)
/s/ Dale G. Wilkerson Vice President and Controller November 25, 2002
------------------------------ (Principal Accounting Officer)
Dale G. Wilkerson
/s/ John J. MacWilliams Director November 25, 2002
------------------------------
John J. MacWilliams
/s/ Preston R. Miller, Jr. Director November 25, 2002
------------------------------
Preston R. Miller, Jr.
/s/ John P. Neafsey Director November 25, 2002
------------------------------
John P. Neafsey
/s/ John H. Robinson Director November 25, 2002
------------------------------
John H. Robinson
/s/ Robert G. Sachse Executive Vice President and Director November 25, 2002
------------------------------
Robert G. Sachse
/s/ Paul R. Tregurtha Director November 25, 2002
------------------------------
Paul R. Tregurtha
CERTIFICATION
I, Joseph W. Craft III certify that:
1. I have reviewed this annual report on Form 10-K/A of Alliance
Resource Partners, L.P.;
2. Based on my knowledge, this annual report does not contain any
untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not
misleading with respect to the period covered by this annual
report; and
3. Based on my knowledge, the financial statements, and other
financial information included in this annual report, fairly
present in all material respects the financial condition, results
of operations and cash flows of the registrant as of, and for, the
periods presented in this annual report.
Date: November 25, 2002
/s/ Joseph W. Craft III
------------------------------
Joseph W. Craft III
President, Chief Executive
Officer and Director
CERTIFICATION
I, Dale G. Wilkerson certify that:
1. I have reviewed this annual report on Form 10-K/A of Alliance
Resource Partners, L.P.;
2. Based on my knowledge, this annual report does not contain any
untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not
misleading with respect to the period covered by this annual
report; and
3. Based on my knowledge, the financial statements, and other
financial information included in this annual report, fairly
present in all material respects the financial condition, results
of operations and cash flows of the registrant as of, and for, the
periods presented in this annual report.
Date: November 25, 2002
/s/ Dale G. Wilkerson
------------------------------
Dale G. Wilkerson
Vice President and Controller
(Principal Accounting Officer)