1
================================================================================
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
---------------
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM _____________TO_____________
COMMISSION FILE NO.: 0-26823
---------------
ALLIANCE RESOURCE PARTNERS, L.P.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 73-1564280
(STATE OR OTHER JURISDICTION OF (IRS EMPLOYER IDENTIFICATION NO.)
INCORPORATION OR ORGANIZATION)
1717 SOUTH BOULDER AVENUE, SUITE 600, TULSA, OKLAHOMA 74119
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES AND ZIP CODE)
(918) 295-7600
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: Common Units
representing limited partner interests
---------------
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
The aggregate value of the Common Units held by non-affiliates of the
registrant (treating all executive officers and directors of the registrant, for
this purpose, as if they may be affiliates of the registrant) was approximately
$147,150,647 on March 26, 2001, based on $19.81 per unit, the closing price of
the Common Units as reported on the Nasdaq National Market on such date.
As of March 26, 2001, 8,982,780 Common Units and 6,422,531 Subordinated
Units are outstanding.
DOCUMENTS INCORPORATED BY REFERENCE: None
================================================================================
2
TABLE OF CONTENTS
PAGE
PART I
ITEM 1. BUSINESS .................................................................................... 2
ITEM 2. PROPERTIES .................................................................................. 13
ITEM 3. LEGAL PROCEEDINGS............................................................................ 16
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITIES
HOLDERS ..................................................................................... 17
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON UNITS AND
RELATED UNITHOLDER MATTERS .................................................................. 17
ITEM 6. SELECTED FINANCIAL DATA ..................................................................... 18
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS ............................................... 19
ITEM 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK ........................................................................... 25
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ................................................. 27
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE ...................................................... 49
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE
MANAGING GENERAL PARTNER .................................................................... 49
ITEM 11. EXECUTIVE COMPENSATION ...................................................................... 52
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT ....................................................................... 55
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS .............................................. 57
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND
REPORTS ON FORM 8-K ......................................................................... 59
1
3
FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K contains forward-looking statements. These
statements are based on the beliefs of Alliance Resource Partners, L.P.
(Partnership) as well as assumptions made by and information currently available
to the Partnership. When used in this document, the words "anticipate,"
"believe," "expect," "estimate," "forecast," "project," and similar expressions
identify forward-looking statements. These statements reflect the Partnership's
current views with respect to future events and are subject to various risks,
uncertainties and assumptions including, but not limited to (a) the
Partnership's dependence on significant customer contracts and the terms of
those contracts, (b) the Partnership's productivity levels and margins that it
earns from the sale of coal, (c) the effects of any unanticipated increases in
labor costs, adverse changes in work rules, or unexpected cash payments
associated with post-mine reclamation, workers' compensation claims, and
environmental litigation or cleanup, (d) the risk of major mine-related
accidents or interruptions, and (e) the effects of any adverse change in the
domestic coal industry, electric utility industry, or general economic
conditions. If one or more of these risks or uncertainties materialize, or
should underlying assumptions prove incorrect, actual results may vary
materially from those described in this Annual Report on Form 10-K. Except as
required by applicable securities laws, the Partnership does not intend to
update these forward-looking statements.
PART I
ITEM 1. BUSINESS
GENERAL
We are a diversified producer and marketer of coal to major United States
utilities and industrial users. We began mining operations in 1971 and, since
then, have grown through acquisitions and internal development to become the
eighth largest coal producer in the eastern United States. At December 31, 2000,
we had approximately 466 million tons of reserves in Illinois, Indiana,
Kentucky, Maryland and West Virginia. In 2000, we produced 13.7 million tons of
coal and sold 15.0 million tons of coal. The coal we produced in 2000 was 20.4%
low-sulfur coal, 19.0% medium-sulfur coal and 60.6% high-sulfur coal. In 2000,
approximately 96% of our medium- and high-sulfur coal was sold to utility plants
with installed pollution control devices, also known as "scrubbers," to remove
sulfur dioxide.
We currently operate seven mining complexes in Illinois, Indiana, Kentucky
and Maryland. Six of our mining complexes are underground and one has both
surface and underground mines. Our mining activities are organized into three
operating regions: (a) the Illinois Basin operations, (b) the East Kentucky
operations, and (c) the Maryland operations.
We and our subsidiary, Alliance Resource Operating Partners, L.P.
(Intermediate Partnership), were formed to acquire, own and operate
substantially all of the coal production and marketing assets of Alliance
Resource Holdings, Inc. (ARH), a Delaware corporation formerly known as Alliance
Coal Corporation. We completed our initial public offering (IPO) on August 20,
1999, at which time ARH contributed substantially all of its operating assets
and liabilities to the Intermediate Partnership.
Our managing general partner, Alliance Resource Management GP, LLC (Managing
GP) and our special general partner, Alliance Resource GP, LLC (Special GP)
(collectively, the Special GP and the Managing GP are the General Partners) own
an aggregate 2% general partner interests in the Partnership. Our limited
partners, including the General Partners as holders of Common Units and
Subordinated Units, own an aggregate 98% of the limited partner interests in the
Partnership.
2
4
The coal production and marketing assets of ARH acquired by the Partnership
are referred to as the "Predecessor." All 1999 operating data contained herein
includes the results of the Partnership and the Predecessor.
MINING OPERATIONS
We produce a diverse range of steam coals with varying sulfur and heat
contents, which enables us to satisfy the broad range of specifications demanded
by our customers. The following chart illustrates our production by region for
the last five years.
OPERATING REGION AND MINES 2000 1999 1998 1997 1996
---------- ---------- ---------- ---------- ----------
(TONS IN MILLIONS)
Illinois Basin Operations:
Dotiki, Pattiki, Hopkins County, Gibson County 8.4 8.5 7.9 5.2 4.3
East Kentucky Operations:
Pontiki, MC Mining 2.7 2.8 2.5 2.8 2.0
Maryland Operations:
Mettiki 2.6 2.8 3.0 2.9 2.7
---------- ---------- ---------- ---------- ----------
Total 13.7 14.1 13.4 10.9 9.0
========== ========== ========== ========== ==========
Illinois Basin Operations
Our Illinois Basin mining operations are located in western Kentucky,
southern Illinois and southern Indiana. We have approximately 835 employees in
the Illinois Basin and currently operate four mining complexes.
Webster County Coal, LLC. Webster County Coal operates the Dotiki mine,
which is an underground mining complex, located 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. Our primary customers for coal
produced at Dotiki are Seminole Electric Cooperative, Inc. (Seminole), Tennessee
Valley Authority (TVA) and Western Kentucky Energy Corp. (WKE), which purchase
our coal pursuant to long-term contracts for use in their scrubbed generating
units. During 2000, Webster County Coal entered into a mineral lease and
sublease with an affiliate of the Special GP. See "Item 13. Certain
Relationships and Related Transactions."
White County Coal, LLC. White County Coal operates the Pattiki mine, which
is an underground mining complex, located in White County, Illinois. We began
construction of the mine in 1980 and have operated it since its inception. Our
Pattiki operation utilizes continuous mining units employing room-and-pillar
mining techniques. We are in the process of extending our Pattiki mine into
adjacent coal reserves. This extension involves capital expenditures of
approximately $30 million during the 2000-2003 period and allows the Pattiki
mine to continue its existing productive capacity for the next 15 years. The
preparation plant has a throughput capacity of 1,000 tons of raw coal an hour.
Production from the mine is shipped via the CSX railroad. Our primary customers
for coal produced at Pattiki are Seminole and TVA, which purchase our coal
pursuant to long-term contracts for use in their scrubbed generating units.
Hopkins County Coal, LLC. Hopkins County Coal is a mining complex located in
Hopkins County, Kentucky. The operation has three surface mines, two of which
are currently idle, and one underground mine. We acquired Hopkins County Coal in
January 1998. The surface operations utilize dragline mining, and the
underground operation utilizes a continuous mining unit employing
room-and-pillar mining techniques. The preparation plant has a throughput
capacity of 1,000 tons of raw coal an hour. Production from the complex is
shipped via the CSX and the Paducah & Louisville railroads and by truck. Our
primary customers for coal
3
5
produced at Hopkins County Coal include Louisville Gas & Electric, TVA and WKE,
which purchase our coal pursuant to long-term contracts for use in their
scrubbed generating units. During 2000, Hopkins County Coal entered into an
option to lease and sub-lease reserves with an affiliate of the Special GP. See
"Item 13. Certain Relationships and Related Transactions."
Gibson County Coal, LLC. Gibson County Coal is an underground mining complex
located in Gibson County, Indiana. We began construction of the mine in 1999 and
commenced production in November 2000. The Gibson County mining complex utilizes
continuous mining units employing room-and-pillar mining techniques. The
preparation plant is leased from the Special GP and has a throughput capacity
of 700 tons of raw coal an hour. Production from Gibson County Coal is a
low-sulfur coal, shipped via truck to our primary customer, PSI Energy Inc., a
subsidiary of Cinergy Corporation. Gibson County Coal also has approximately
104.2 million tons of undeveloped recoverable reserves, which are not
contiguous to the reserves currently being mined.
East Kentucky Operations
Our East Kentucky mining operations are located in the Central Appalachia
coal fields. Our East Kentucky mines produce low-sulfur coal. We have
approximately 360 employees and operate two mining complexes in East Kentucky.
Pontiki Coal, LLC. Pontiki is an underground mining complex located 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. 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 and by truck. Our primary customers
for coal produced at Pontiki are James River Cogeneration Company, the successor
to Cogentrix of Virginia, Inc., and AEI Coal Sales Company, Inc. (AEI).
MC Mining, LLC. MC Mining is an underground mining complex located in Pike
County, Kentucky, acquired in 1989. Since we began operations in late 1996, MC
Mining was operated by an unaffiliated contract mining company. However, during
the fourth quarter 2000, the contract mining agreement was terminated and MC
Mining entered into an intercompany support services agreement with Excel
Mining. Selected employees of the contractor and other qualified individuals
were hired by Excel Mining, which is responsible for conducting all mining
operations. The operation utilizes 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 and by truck. MC Mining sells its low-sulfur production
primarily in the spot market.
Toptiki Coal, LLC. Toptiki was a surface and underground mining complex
located in Martin County, Kentucky. After conducting surface mining operations
through 1982 and underground operations through 1996, we discontinued mining at
the complex and have since sold our member interest in Toptiki for an immaterial
amount.
Maryland Operations
Our Maryland mining operation is located in the Northern Appalachia coal
fields. We have approximately 235 employees and operate one mining complex in
Maryland.
Mettiki Coal, LLC. Mettiki is an underground longwall mining complex located
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
4
6
mine for future longwall mining operation areas. The preparation plant has a
throughput capacity of 1,350 tons of raw coal an hour. Production from the mine
is shipped via truck and the CSX railroad. 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. We also process coal at Mettiki for Anker Energy Corporation and one of
its affiliates.
Mettiki Coal (WV), LLC. Mettiki (WV) has approximately 20.1 million tons of
undeveloped recoverable reserves in Grant and Tucker Counties, West Virginia
adjacent to Mettiki in Garrett County, Maryland. We currently conduct no mining
operations at Mettiki (WV).
OTHER OPERATIONS
Mt. Vernon Transfer Terminal, LLC
Mt. Vernon terminal is a rail-to-barge loading terminal on the Ohio River in
Mt. Vernon, Indiana. The terminal has a capacity of 5.5 million tons per year
with existing ground storage. The terminal was used from 1983 through 1998 for
shipments from Pattiki and Dotiki under our coal supply agreement with Seminole.
Seminole now transports these shipments directly by CSX railroad. We currently
use the facility as needed for spot shipments to customers other than Seminole
and continue to explore our opportunities and options regarding the terminal.
Coal Brokerage
We buy coal from outside producers throughout the eastern United States,
which we then resell, both directly and indirectly, to utility and industrial
customers. We purchased and sold 200,000 tons of outside coal in 2000. We have a
policy of matching our outside coal purchases and sales to minimize market risks
associated with buying and reselling coal.
Additional Services
We develop and market additional services in order to establish ourselves as
the supplier of choice for our customers. Examples of the kind of services we
have offered to date include ash and scrubber sludge removal, coal yard
maintenance, and arranging alternate transportation services. We will continue
to think proactively in providing additional services for customers and believe
that this approach will give us a competitive advantage in obtaining coal supply
contracts in the future.
COAL MARKETING AND SALES
As is customary in the coal industry, we have entered into long-term
contracts with many of our customers. These arrangements are mutually
beneficial. Our utility customers secure a fuel supply for their power plants
for years into the future. Our long-term contracts contribute to both our
customers and our stability and profitability by providing greater
predictability of sales volumes and sales prices. In 2000, approximately 85% of
our sales tonnage was sold under long-term contracts with maturities ranging
from 2000 to 2012. Our total nominal commitment under significant long-term
contracts was approximately 74.8 million tons at December 31, 2000. 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%. 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,
5
7
among others, price adjustment features, price and contract reopener terms,
permitted sources of supply, force majeure provisions, coal qualities, and
quantities. Virtually all of our long-term contracts are subject to price
adjustment provisions which permit an increase or decrease periodically in the
contract price to reflect changes in specified price indices or items such as
taxes, royalties or actual production costs. These provisions, however, may not
assure that the contract price will reflect every change in production or other
costs. Failure of the parties to agree on a price pursuant to an adjustment or a
reopener provision can lead to early termination of a contract. Some of the
long-term contracts also permit the contract to be reopened to renegotiate terms
and conditions other than the pricing terms, and where a mutually acceptable
agreement on terms and conditions cannot be concluded, either party may have the
option to terminate the contract. The long-term contracts typically stipulate
procedures for quality control, sampling and weighing. Most contain provisions
requiring us to deliver coal within ranges for specific coal characteristic such
as heat, sulfur, ash, moisture, grindability, volatility and other qualities.
Failure to meet these specifications can result in economic penalties or
termination of the contracts. While most of the contracts specify the approved
seams and/or approved locations from which the coal is to be mined, some
contracts allow the coal to be sourced from more than one mine or location.
Although the volume to be delivered pursuant to a long-term contract is
stipulated, the buyers often have the option to vary the volume within specified
limits.
RELIANCE ON MAJOR CUSTOMERS
Our four largest customers are AEI, Seminole, TVA and VEPCO. Sales to these
customers in the aggregate accounted for approximately 62% of our 2000 total
revenues, and sales to each of these customers accounted for more than 10% of
our 2000 total revenues. Three of these customers have purchased coal regularly
from us for more than 15 years. A national bond rating agency has recently
reported that the parent company of one of our significant customers is in
default on a significant amount of its outstanding debt. All of the accounts
receivable under the long-term contract with our customer are current. Our
management does not anticipate that this event will have a material impact on
our financial condition or results of operations.
COMPETITION
The United States coal industry is highly competitive with numerous
producers in all coal producing regions. We compete with other large producers
and hundreds of small producers in the United States. The largest coal company
is estimated to have sold approximately 16% of the total 2000 tonnage sold in
the United States market. We compete with other coal producers primarily on the
basis of coal price at the mine, coal quality (including sulfur content),
transportation cost from the mine to the customer, and the reliability of
supply. Continued demand for our coal and the prices that we obtain are also
affected by demand for electricity, environmental and government regulations,
technological developments, and the availability and price of alternative fuel
supplies, including nuclear, natural gas, oil, and hydroelectric power.
TRANSPORTATION
Our coal is transported to our customers by rail, truck and barge. Depending
on the proximity of the customer to the mine and the transportation available
for delivering coal to that customer, transportation costs can range from 10% to
60% of the delivered cost of a customer's coal. As a consequence, the
availability and cost of transportation constitute important factors in the
marketability of coal. We believe our mines are located in favorable geographic
locations that minimize transportation costs for our customers.
Customers pay the transportation costs from the contractual F.O.B. point to
the customer's plant. At our Gibson and Mettiki mines, a contractor operates a
truck delivery system that transports the coal from the mine to the primary
customer's power plant.
In 2000, the largest volume transporter of our coal production was the CSX
railroad, which moved approximately 50% of our tonnage over its rail system. The
practices of, and rates set by, the railroad serving a particular mine or
customer might affect, either adversely or favorably, our marketing efforts with
respect to coal produced from the relevant mine.
6
8
REGULATION AND LAWS
The coal mining industry is subject to regulation by federal, state and
local authorities on matters such as:
- employee health and safety;
- mine permits and other licensing requirements;
- air quality standards;
- water pollution;
- storage of petroleum products and substances which are regarded as
hazardous under applicable laws or which, if spilled, could reach
waterways or wetlands;
- plant and wildlife protection;
- reclamation and restoration of mining properties after mining is
completed;
- the discharge of materials into the environment;
- management of solid wastes generated by mining operations;
- protection of wetlands;
- management of electrical equipment containing polychlorinated
biphenyls (PCBs);
- surface subsidence from underground mining;
- the effects that mining has on groundwater quality and availability;
and
- legislatively mandated benefits for current and retired coal miners.
In addition, the utility industry is subject to extensive regulation
regarding the environmental impact of its power generation activities, which
could affect demand for our coal. The possibility exists that new legislation or
regulations, or new interpretations of existing laws or regulations, may be
adopted that may have a significant impact on our mining operations or our
customers' ability to use coal, and may require us or our customers to change
our or their operations significantly or to incur substantial costs.
We are committed to conducting mining operations in compliance with all
applicable federal, state and local laws and regulations. However, because of
extensive and comprehensive regulatory requirements, violations during mining
operations are not unusual in the industry and, notwithstanding our compliance
efforts, we do not believe these violations can be eliminated completely. None
of the violations to date or the monetary penalties assessed at our operations
have been material.
While it is not possible to quantify the costs of compliance with all
applicable federal and state laws, those costs have been and are expected to
continue to be significant. Capital expenditures for environmental matters have
not been material in recent years. We have accrued for the present value
estimated cost of reclamation and mine closing, including the cost of treating
mine water discharge, when necessary. The accrual for reclamation and mine
closing costs is based upon permit requirements and the costs and timing of
reclamation and mine closing procedures. Although management believes it has
made adequate provisions for all expected reclamation and other costs associated
with mine closures, future operating results would be adversely affected if we
later determine these accruals to be insufficient. Compliance with these laws
has substantially increased the cost of coal mining for all domestic coal
producers.
Mining Permits and Approvals. Numerous governmental permits or approvals are
required for mining operations. We may be required to prepare and present to
federal, state or local authorities data pertaining to the effect or impact that
any proposed production of coal may have upon the environment. All requirements
imposed by any of these authorities may be costly and time-consuming, and may
delay commencement or continuation of mining operations. Future legislation and
administrative regulations may emphasize more heavily the protection of the
environment and, as a consequence, our activities may be more closely regulated.
Legislation and regulations, as well as future interpretations of existing laws,
may require substantial increases in equipment and operating costs and delays,
interruptions or a termination of operations, the extent of which cannot be
predicted.
7
9
Before commencing mining on a particular property, we must obtain mining
permits and approvals by state regulatory authorities of a reclamation plan for
restoring, upon the completion of mining, the mined property to its approximate
prior condition, productive use or other permitted condition. Typically, we
commence actions to obtain permits between 18 and 24 months before we plan to
mine a new area. In our experience, permits generally are approved within 12
months after a completed application is submitted. We have not experienced
difficulties in obtaining mining permits in the areas where our reserves are
currently located. However, we cannot assure you that we will not experience
difficulty in obtaining mining permits in the future.
Under some circumstances, substantial fines and penalties, including
revocation of mining permits, may be imposed under the laws described above.
Monetary sanctions and, in severe circumstances, criminal sanctions may be
imposed for failure to comply with these laws. Regulations also provide that a
mining permit can be refused or revoked if the permit applicant or permittee
owns or controls, directly or indirectly through other entities, mining
operations which have outstanding permit violations. Although we have been cited
for violations in the ordinary course of our business, we have never had a
permit suspended or revoked because of any violation, and the penalties assessed
for these violations have not been material.
Mine Health and Safety Laws. Stringent safety and health standards have been
imposed by federal legislation since 1969 when the Coal Mine Health and Safety
Act of 1969 (CMHSA) was adopted. CMHSA resulted in increased operating costs and
reduced productivity. The federal Mine Safety and Health Act of 1977, which
significantly expanded the enforcement of health and safety standards of CMHSA,
imposes comprehensive safety and health standards on all mining operations.
Regulations are comprehensive and affect numerous aspects of mining operations,
including training of mine personnel, mining procedures, blasting, the equipment
used in mining operations and other matters. The Mine Safety and Health
Administration monitors compliance with these federal laws and regulations. In
addition, as part of CMHSA and the Mine Safety and Health Act of 1977, the Black
Lung Benefits Act requires payments of benefits by all businesses that conduct
current mining operations to a coal miner with black lung disease and to some
survivors of a miner who dies from this disease. Most of the states where we
operate also have state programs for mine safety and health regulation and
enforcement. In combination, federal and state safety and health regulation in
the coal mining industry is perhaps the most comprehensive and rigorous system
for protection of employee safety and health affecting any segment of any
industry. Even the most minute aspects of mine operations, particularly
underground mine operations, are subject to extensive regulation. This
regulation has a significant effect on our operating costs. However, our
competitors in all of the areas in which we operate are subject to the same laws
and regulations.
Black Lung Benefits Act (BLBA). The federal BLBA levies a tax on production
of $1.10 per ton for underground-mined coal and $0.55 per ton for surface-mined
coal, but not to exceed 4.4% of the applicable sales price, in order to
compensate miners who are totally disabled due to black lung disease and some
survivors of miners who died from this disease, and who were last employed as
miners prior to 1970 or subsequently where no responsible coal mine operator has
been identified for claims. In addition, BLBA provides that some claims for
which coal operators had previously been responsible will be obligations of the
government trust funded by the tax. The Revenue Act of 1987 extended the
termination date of this tax from January 1, 1996, to the earlier of January 1,
2014, or the date on which the government trust becomes solvent. For miners last
employed as miners after 1969 and who are determined to have contracted black
lung, we self-insure against potential cost using actuarially determined
estimates of the cost of present and future claims. We are also liable under
state statutes for black lung claims.
The U.S. Department of Labor has issued revised regulations that could alter
the claims process for the federal black lung benefit recipients, which among
other things:
- simplify administrative procedures for the adjudication of claims;
- propose preference for the miner's treating physician under certain
circumstances;
- allow previously denied claims to be refiled and litigated under a
different standard;
8
10
- limit the amount of evidence all parties may submit for consideration;
- create a rebuttable presumption that medical treatment for any pulmonary
condition is caused or aggravated by the miner's work; and
- expand the definition of pneumoconiosis and total disability.
Because the revised regulations are expected to result in an increase in the
incidence and recovery of black lung claims, both the coal and insurance
industries are currently challenging through litigation certain provisions of
the revised regulations. A federal judge has granted a limited stay of the new
black lung regulations at the request of the Bush administration. Under the
preliminary injunction, claims will continue to be processed under the new
regulations, but no final decisions will be made on claims for black lung
benefits filed after the new regulations became effective. The outcome of the
litigation and the impact of the revised regulations if eventually implemented
on the Partnership's liability for black lung claims cannot be determined at
this time. In addition, Congress and state legislatures regularly consider
various items of black lung legislation, which if enacted, could adversely
affect our business financial condition and results of operations.
Workers' Compensation. We are required to compensate employees for
work-related injuries. Several states in which we operate consider changes in
workers compensation laws from time to time.
Coal Industry Retiree Health Benefits Act (CIRHBA). The federal CIRHBA was
enacted to provide for the funding of health benefits for some United Mine
Workers of America retirees. The act merged previously established union benefit
plans into a single fund into which "signatory operators" and "related persons"
are obligated to pay annual premiums for beneficiaries. The act also created a
second benefit fund for miners who retired between July 21, 1992, and September
30, 1994, and whose former employers are no longer in business. Because of our
union-free status, we are not required to make payments to retired miners under
CIRHBA, with the exception of limited payments made on behalf of predecessors of
MC Mining, LLC. However, in connection with the sale of the coal assets acquired
by ARH in 1996, MAPCO Inc. agreed to retain all liabilities under CIRHBA.
Surface Mining Control and Reclamation Act (SMCRA). The federal SMCRA
establishes operational, reclamation and closure standards for all aspects of
surface mining as well as many aspects of deep mining. The act requires that
comprehensive environmental protection and reclamation standards be met during
the course of and upon completion of mining activities. In conjunction with
mining the property, we reclaim and restore the mined areas by grading, shaping
and preparing the soil for seeding. Upon completion of the mining, reclamation
generally is completed by seeding with grasses or planting trees for a variety
of uses, as specified in the approved reclamation plan. We believe that we are
in compliance in all material respects with applicable regulations relating to
reclamation.
SMCRA and similar state statutes, require, among other things, that mined
property be restored in accordance with specified standards and approved
reclamation plans. The act requires us to restore the surface to approximate the
original contours as contemporaneously as practicable with the completion of
surface mining operations. The mine operator must submit a bond or otherwise
secure the performance of these reclamation obligations. The earliest a
reclamation bond can be released is five years after reclamation has been
achieved. Federal law and some states impose on mine operators the
responsibility for replacing certain water supplies damaged by mining operations
and repairing or compensating for damage occurring on the surface as a result of
mine subsidence, a consequence of longwall mining and possibly other mining
operations. In addition, the Abandoned Mine Lands Program, which is part of
SMCRA, imposes a tax on all current mining operations, the proceeds of which are
used to restore mines closed before 1977. The maximum tax is $0.35 per ton on
surface-mined coal and $0.15 per ton on underground-mined coal. We have accrued
for the estimated costs of reclamation and mine closing, including the cost of
treating mine water discharge when necessary.
9
11
Under SMCRA, responsibility for unabated violations, unpaid civil penalties
and unpaid reclamation fees of independent contract mine operators and other
third parties can be imputed to other companies which are deemed, according to
the regulations, to have "owned" or "controlled" the third party violator.
Sanctions against the "owner" or "controller" are quite severe and can include
being blocked from receiving new permits and revocation of any permits that have
been issued since the time of the violations or, in the case of civil penalties
and reclamation fees, since the time their amounts became due. We are not aware
of any currently pending or asserted claims relating to the "ownership" or
"control" theories discussed above. However, we cannot assure you that such
claims will not develop in the future.
Clean Air Act (CAA). The federal CAA and similar state laws, which regulate
emissions into the air, affect coal mining and processing operations primarily
through permitting and emissions control requirements. The CAA also indirectly
affects coal mining operations by extensively regulating the air emissions of
coal-fired electric power generating plants. For example, the CAA requires
reduction of sulfur dioxide (SO2) emissions from electric power generation
plants in two phases. Only some facilities were subject to the Phase I
requirements. Beginning in year 2000, Phase II requires nearly all facilities to
reduce emissions. The effected utilities are able to meet these requirements by:
- switching to lower sulfur fuels;
- installing pollution control devices such as scrubbers;
- reducing electricity generating levels; or
- purchasing or trading so-called pollution "credits."
Specific emissions sources receive these "credits" that utilities and
industrial concerns can trade or sell to allow other units to emit higher levels
of SO2. In addition, the CAA requires a study of utility power plant emissions
of some toxic substances and their eventual regulation, if warranted. The
effect of the CAA cannot be completely ascertained at this time, although the
SO2 emissions reduction requirement is projected generally to increase the
demand for lower sulfur coal and potentially decrease demand for higher sulfur
coal.
The CAA also indirectly affects coal mining operations by requiring
utilities that currently are major sources of nitrogen oxides (NOx) in moderate
or higher ozone nonattainment areas to install reasonably available control
technology for NOx, which are precursors of ozone. In October 1998, the U.S.
Environmental Protection Agency (EPA) issued a rule requiring 22 eastern states
and the District of Columbia to make substantial reductions in NOx emissions by
the year 2003, which was substantially upheld by the U.S. Court of Appeals for
the D.C. Circuit on March 3, 2000. On March 5, 2001, the U.S. Supreme Court
declined to review that decision, in response to a petition by seven states and
the power and coal industries. EPA expects that effected states will achieve
reductions by requiring power plants to make substantial reductions in their NOx
emissions. This in turn will require power plants to install reasonably
available control technology and additional control measures. Installation of
reasonably available control technology and additional measures required under
EPA regulations will make it more costly to operate coal-fired plants and,
depending on the requirements of individual state implementation plans and the
development of revised new source performance standards, could make coal a less
attractive fuel alternative in the planning and building of utility power plants
in the future. Any reduction in coal's share of the capacity for power
generation could have a material adverse effect on our business, financial
condition and results of operations. The effect these regulations, or other
requirements that may be imposed in the future, could have on the coal industry
in general and on our business in particular cannot be predicted with certainty.
We cannot assure you that the implementation of the CAA, the new National
Ambient Air Quality Standards (NAAQS) discussed below, or any other current or
future regulatory provision, will not materially adversely affect us.
In addition, EPA has already issued and is considering further regulations
relating to fugitive dust and emissions of other coal-related pollutants such as
mercury, nickel, dioxin and fine particulates. For example, in July 1997 EPA
adopted new, more stringent NAAQS for particulate matter, which may require some
states to change existing implementation plans. These NAAQS are expected to be
implemented by 2003. These NAAQS were effectively affirmed by the U.S. Supreme
Court on February 27, 2001. That decision upheld
10
12
the constitutionality of EPA's NAAQS statutory authority, finding that EPA acted
properly in not considering costs in setting the NAAQS, and remanded the case to
the U.S. Court of Appeals for the D.C. Circuit to dispose of any remaining
challenges to the rules. Because coal mining operations and utilities emit
particulate matter, our mining operations and utility customers are likely to be
directly effected when the revisions to the NAAQS are implemented by the states.
EPA has filed suit against a number of our customers over implementation of
new source performance standards and preconstruction review requirements for new
sources and major modifications under the prevention of significant
deterioration and nonattainment regulations. This issue surrounds the issue of
what constitutes regular maintenance versus new construction. Some of our
customers have agreed to or proposed settlements with EPA while others are
preparing for litigation. These and other regulatory developments may restrict
our ability to develop new mines, or could require us or our customers to modify
existing operations.
Framework Convention On Global Climate Change (Kyoto Protocol). The United
States and more than 160 other nations are signatories to the Kyoto Protocol
which is intended to limit or capture emissions of greenhouse gases, such as
carbon dioxide. The Kyoto Protocol established a binding set of emissions
targets for developed nations. The specific limits vary from country to country.
Under the terms of the Kyoto Protocol, the United States would be required to
reduce emissions to 93% of 1990 levels over a five-year budget period from 2008
through 2012. The Clinton Administration signed the Kyoto Protocol in November
1998. Although the U.S. Senate has not ratified the Kyoto Protocol and no
comprehensive regulations focusing on greenhouse gas emissions have been
enacted, efforts to control greenhouse gas emissions could result in reduced use
of coal if electric power generators switch to lower carbon sources of fuel.
These restrictions, if established through regulation or legislation, could have
a material adverse effect on our business, financial condition and results of
operations.
Clean Water Act (CWA). The federal CWA affects coal mining operations by
imposing restrictions on effluent discharge into waters. Regular monitoring, as
well as compliance with reporting requirements and performance standards, are
preconditions for the issuance and renewal of permits governing the discharge of
pollutants into water. We are also subject to CWA Section 404, which imposes
permitting and mitigation requirements associated with the dredging and filling
of wetlands. The CWA and equivalent state legislation, where such equivalent
state legislation exists, affect coal mining operations that impact wetlands. We
believe we have obtained all necessary wetlands permits required under Section
404. However, mitigation requirements under those existing, and possible future,
wetlands permits may vary considerably. In addition, we are currently
interpreting the effect of a January 9, 2001, U.S. Supreme Court ruling
concerning the definition of isolated wetlands. This issue should not cause any
increase in post-mine reclamation accruals. In fact, this decision is expected
to decrease the regulatory burden on mining operations that disturb intermittent
streams and other isolated wetlands. For that reason, the setting of post-mine
reclamation accruals for such mitigation projects is difficult to ascertain with
certainty. We believe that we have obtained all permits required under the CWA
as traditionally interpreted by the responsible agencies. Although more
stringent permitting requirements may be imposed in the future, we are not able
to accurately predict the impact, if any, of any such permitting requirements.
However, each individual state is required to submit to EPA their biennial
CWA Section 303(d) lists identifying all waterbodies not meeting state specified
water quality standards. For each listed waterbody, the state is required to
begin developing a Total Maximum Daily Load (TMDL) to:
- determine the maximum pollutant loading the waterbody can assimilate
without violating water quality standards,
- identify all current pollutant sources and loadings to that waterbody,
- calculate the pollutant loading reduction necessary to achieve water
quality standards, and
- establish a means of allocating that burden among and between the point
and non-point sources contributing pollutants to the waterbody.
11
13
We are currently participating in stakeholders meetings and in negotiations
with states and EPA to establish reasonable TMDLs that will accommodate
expansion. These and other regulatory developments may restrict our ability to
develop new mines, or could require us or our customers to modify existing
operations, the extent of which we cannot accurately or reasonably predict.
Safe Drinking Water Act (SDWA). The federal SDWA and its state equivalents
affect coal mining operations by imposing requirements on the underground
injection of fine coal slurries, fly ash, and flue gas scrubber sludge, and by
requiring a permit to conduct such underground injection activities. The
inability to obtain these permits could have a material impact on our ability to
inject materials such as fine coal refuse, fly ash, or flue gas scrubber sludge
into the inactive areas of some of our old underground mine workings.
In addition to establishing the underground injection control program, the
federal SDWA also imposes regulatory requirements on owners and operators of
"public water systems." This regulatory program could impact our reclamation
operations where subsidence, or other mining-related problems, require the
provision of drinking water to effected adjacent homeowners. However, the
federal SDWA defines a "public water system" for purposes of regulatory
jurisdiction as a system for the provision to the public of water for human
consumption through pipes or other constructed conveyances, if the system has at
least fifteen service connections or regularly serves at least twenty-five
individuals. It is unlikely that any of our reclamation activities would require
the provision of such a "public water system." While we have at least one
drinking water supply source for our employees and contractors that is subject
to SDWA regulation, the SDWA is unlikely to have a material impact on our
operations.
Comprehensive Environmental Response, Compensation and Liability Act
(CERCLA). The federal CERCLA and similar state laws affect coal mining
operations by, among other things, imposing cleanup requirements for threatened
or actual releases of hazardous substances that may endanger public health or
welfare or the environment. Under CERCLA, and similar state laws, joint and
several liability may be imposed on waste generators, site owners and operators
and others regardless of fault or the legality of the original disposal
activity. Some products used by coal companies in operations, such as chemicals,
generate waste containing hazardous substances, which are governed by the
statute. Thus, coal mines that we currently own or have previously owned or
operated, and sites to which we sent waste materials, may be subject to
liability under CERCLA and similar state laws. We have been, on rare occasions,
the subject of administrative proceedings, litigation and investigations
relating to CERCLA matters, none of which has had a material adverse effect on
our financial condition or results of operations. We cannot assure you that we
will not become involved in future proceedings, litigation or investigations, or
that liabilities arising out of any such proceedings will not be material.
Toxic Substances Control Act (TSCA). The federal TSCA regulates, among other
things, electrical equipment containing PCBs in excess of 50 parts-per-million.
Specifically, TSCA's PCB rules require that all PCB-containing equipment be
properly labeled, stored, and disposed of, and require the on-site maintenance
of annual records regarding the presence and use of equipment containing PCBs in
excess of 50 parts-per-million. Because the regulated PCB-containing electrical
equipment in use in our operations is owned by the utilities that serve the
operations where they are located, and because the use of PCB-containing fluids
in such equipment is in the process of being phased out, we do not believe TSCA
will have a material impact on our operations.
Resource Conservation and Recovery Act (RCRA). The federal RCRA affects coal
mining operations by imposing requirements for the generation, transportation,
treatment, storage, disposal and cleanup of hazardous wastes. Many mining wastes
are excluded from the regulatory definition of hazardous wastes, and coal mining
operations covered by SMCRA permits are exempted from regulation under RCRA by
statute.
Coal Combustion By-Products. In 2000, EPA declined to impose hazardous
wastes regulatory controls on the disposal of some coal combustion by-products,
including the practice of using coal combustion by-products as minefill.
However, EPA is currently evaluating the possibility of placing additional solid
waste
12
14
burdens on the disposal of these types of materials, but it may be several years
before these standards will be developed.
While we cannot predict the ultimate outcome of the EPA's assessment, we
believe that the beneficial uses of coal combustion by-products we employ do not
constitute poor practices due to, among other things, the fact that our CWA
discharge permits for treated acid mine drainage contain parameters for
pollutants of concern, such as metals, and those permits require monitoring and
reporting of effluent quality data. Small quantities of regulated hazardous
wastes are generated at some of our facilities. However, we do not believe that
the cost of complying with applicable regulations for those wastes will have a
material impact.
OTHER ENVIRONMENTAL, HEALTH AND SAFETY REGULATION
In addition to the laws and regulations described above, we are subject to
regulations regarding underground and above ground storage tanks where we may
store petroleum or other substances. Some monitoring equipment that we use is
subject to licensing under the federal Atomic Energy Act. Water supply wells
located on our property are subject to federal, state and local regulation. The
costs of compliance with these requirements should not have a material adverse
effect on our business, financial condition or results of operations.
EMPLOYEES
We have approximately 1,530 employees, including some 100 corporate
employees and some 1,430 employees involved in active mining operations. Our
work-force is entirely union-free. Relations with our employees are generally
good, and there have been no recent work stoppages or union organizing campaigns
among our employees.
ITEM 2. PROPERTIES
COAL RESERVES
As of December 31, 2000, we had approximately 466 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. Proven and probable
reserves are reserves that we can economically produce using current extraction
technology from acreage we own or lease.
The following table sets forth production data and reserve information, as
of December 31, 2000, about each of our mining complexes.
13
15
Typical Clean Coal Quality Proven and Probable Reserve
2000 ---------------------------------- ----------------------------------------
Saleable Heat
Production Content(2)
(tons in (BTU Sulfur(2) Ash(2) Low Medium High
Location Mine Type millions) per pound) (%) (%) Sulfur(1) Sulfur(1) Sulfur(1) Total
- -------- --------- --------- ---------- --------- ------ --------- --------- --------- -----
(tons in millions)
Webster and Hopkins Underground 3.9 12,500 2.9 8.1 107.4 107.4
County, KY
White County, IL Underground 2.3 11,700 3.0 7.9 81.3 81.3
Hopkins County, KY Surface/
Underground 2.1 11,300 3.2 12.4 35.0 35.0
Gibson County, IN Underground 0.1 11,600 1.0 7.0 39.4 39.4
Gibson County, IN Underground 0.0 11,600 2.1(3) NA 10.9 44.1 49.2 104.2
===== ===== ====== ====== =====
8.4 50.3 44.1 272.9 367.3
===== ===== ====== ====== =====
Martin County, KY Underground 1.9 12,800 0.7 6.7 19.7 19.7
Pike County, KY Underground 0.8 12,800 0.7 7.2 23.1 23.1
===== ===== ====== ====== =====
2.7 42.8 0.0 0.0 42.8
===== ===== ====== ====== =====
Garrett County, MD Underground 2.6 13,000 1.6 10.0 36.0 36.0
Grant and Tucker Underground 0.0 13,000 1.6 10.0 20.1 20.1
County, WV
===== ===== ====== ====== =====
2.6 0.0 56.1 0.0 56.1
===== ===== ====== ====== =====
93.1 100.2 272.9 466.2
===== ===== ====== ====== =====
13.7 20.0% 21.5% 58.5% 100.0
===== ===== ====== ====== =====
(1) 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%.
(2) Fully washed quality. Actual shipped quality varies according to the
blending of washed and raw coal.
(3) Sulfur (%) represents a weighted average.
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. Reserve estimates will change from time to time in reflection of
mining activities, analysis of new engineering and geological data, acquisition
or divestment of reserve holdings, modification of mining plans or mining
methods, and other factors.
We estimate that approximately 62 million tons of our reserves, or
approximately 67% of our low-sulfur reserves and 13% of our total reserves at
December 31, 2000, meet compliance standards for Phase II of the Clean Air Act
Amendments. Compliance coal consists of coal that emits less than 1.2 pounds of
SO2 per million Btu.
We lease almost all of our reserves and generally have the right to maintain
the lease in force until the exhaustion of minable and merchantable coal located
within the leased premises or a larger coal reserve area. These leases provide
for royalties to be paid to the lessor at a fixed amount per ton or as a
percentage of the sales price. Many leases require payment of minimum royalties,
payable either at the time of the execution of the lease or in periodic
installments, even if no mining activities have begun. These minimum royalties
are normally credited against the production royalties owed to a lessor once
coal production has commenced.
In connection with our corporate reorganization and subsequent IPO, we
obtained the consents of our lessors or determined that obtaining such consents
was not required. Although we believe we have obtained all necessary consents,
in the event that we have failed to obtain a necessary consent, our operations
may be adversely impacted if we experience any disruption of our mining
operations as a consequence.
14
16
For economic and other operational reasons, a portion of our reserves
described above may be mined only after the construction of additional mining
facilities. The extent to which we will eventually mine our reserves will depend
on the price and demand for coal of the quality and type we control, the price
and supply of alternative fuels, and future mining practices and regulations.
RISK FACTORS
If any of the following risks were actually to occur, our business,
financial condition or results of operations could be materially adversely
effected and the trading price of our Common Units could decline.
Risks Inherent in Our Business
- Competition within the coal industry may adversely affect our ability to
sell coal, and excess production capacity in the industry could put
downward pressure on coal prices in the future.
- Current conditions in the coal industry may change and make it more
difficult for us to extend existing or enter into new long-term
contracts. This could affect the stability and profitability of our
operations.
- Some of our long-term contracts contain provisions allowing for the
renegotiation of prices and, in some instances, the termination of the
contract or the suspension of purchases by customers.
- Some of our long-term contracts require us to supply all of our
customers coal needs. If these customers' coal requirements decline, our
revenues under these contracts will also drop.
- A substantial portion of our coal has a high-sulfur content. This coal
may become more difficult to sell because the CAA may impact the ability
of electric utilities to burn high-sulfur coal through the regulation of
emissions.
- We depend on a few customers for a significant portion of our revenues,
and the loss of one or more significant customers could have a material
adverse effect on our business, financial condition or results of
operations.
- Any future litigation relating to disputes with our customers may result
in substantial costs, liabilities and loss of revenues.
- Any loss of the benefit from state tax credits may affect adversely our
business financial condition or results of operations.
- Coal mining is subject to inherent risks that are beyond our control,
and we cannot assure you that these risks will be fully covered under
our insurance policies.
- We depend on third party service providers to assist us in producing a
portion of our coal. If these providers' services were no longer
available, our ability to produce and sell coal may be effected
adversely.
- Any significant increase in transportation costs or disruption of the
transportation of our coal may impair our ability to sell coal.
- We may not be able to grow successfully through future acquisitions, and
we may not be able to effectively integrate the various businesses or
properties we do acquire.
- Our business may be adversely effected if we are unable to replace our
coal reserves.
- The estimates of our reserves may prove inaccurate, and you should not
place undue reliance on these estimates.
- Our indebtedness may limit our ability to borrow additional funds, make
distributions to Unitholders or capitalize on business opportunities.
- We are required to obtain and maintain bonds to secure our obligations
to return mined property to its approximate original condition. The
failure to do so may result in fines and the loss of mining permits.
Risks Inherent in an Investment in the Partnership
- Unitholders have limited voting rights and do not control our Managing
GP.
- We may issue additional Common Units without the approval of Common
Unitholders, which would dilute existing Unitholders' interests.
15
17
- The issuance of additional Common Units, including upon conversion of
Subordinated Units, will increase the risk that we will be unable to pay
the full minimum quarterly distribution on all Common Units.
- Cost reimbursements to our General Partners may be substantial and will
reduce our cash available for distribution.
- Our Managing GP has a limited call right that may require Unitholders to
sell their Common Units at an undesirable time or price.
- Unitholders may not have limited liability under some circumstances.
- Cash distributions are not guaranteed and may fluctuate with our
performance. In addition, our Managing GP's discretion in establishing
reserves may negatively impact your receipt of cash distributions.
Regulatory Risks
- We are subject to federal, state and local regulations on numerous
matters. These regulations increase our costs of doing business and may
discourage customers from buying our coal.
- We are subject to black lung benefits and workers' compensation
obligations, which could increase if new legislation is enacted.
- The CAA affects our customers and could significantly influence their
purchasing decisions.
- The passage of legislation responsive to the Kyoto Protocol could result
in a reduced use of coal by electric power generators. This reduction in
use could adversely affect our revenues and results of operations.
- The CWA imposes limitations and monitoring and reporting obligations on
our discharge of pollutants into water.
- We are subject to reclamation, mine closure and real property
restoration regulation obligations, which could increase if new
legislation is enacted.
- We and our customers could incur significant costs under federal and
state Superfund and waste management statutes.
Tax Risks to Common Unitholders
- The Internal Revenue Service (IRS) could in the future choose to treat
us as a corporation, which would substantially reduce the cash available
for distribution to Unitholders.
- We have not requested an IRS ruling with respect to our tax treatment.
- You may be required to pay taxes on income from us even if you receive
no cash distributions.
- Tax gain or loss on disposition of Common Units could be different than
expected.
- Common Unitholders, other than individuals who are U.S. residents, may
have adverse tax consequences from owning Common Units.
- We have registered with the IRS as a tax shelter. This may increase the
risk of an IRS audit of us or a Common Unitholder.
- We treat a purchaser of Common Units as having the same tax benefits as
the seller; the IRS may challenge this treatment, which could adversely
affect the value of the Common Units.
- Common Unitholders will likely be subject to state and local taxes as a
result of an investment in units.
ITEM 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, pricing, quantity, and the existence of force majeure conditions.
Although we are not currently involved in any litigation involving our long-term
coal supply contracts, we cannot assure you that disputes will not occur in the
future 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
16
18
under "General Litigation" under "Item 8. Financial Statements and Supplementary
Data. - Note 15. Commitments and Contingencies" is hereby incorporated by
reference.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITIES HOLDERS
None.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON UNITS AND RELATED UNITHOLDER MATTERS
The Common Units representing limited partner interests are listed on the
Nasdaq National Market under the symbol "ARLP." The Common Units began trading
on August 20, 1999, when the market price for the IPO of the Common Units was
$19.00 per unit. On March 26, 2001 the closing market price for the Common Units
was $19.81 per unit. There were approximately 6,100 record holders and
beneficial owners at December 31, 2000 (held in street name) of the
Partnership's Common Units.
The following table sets forth, the range of high and low sales price per
Common Unit and the amount of cash distribution declared with respect to the
Units, for each quarterly period since commencement of operations on August 20,
1999.
HIGH LOW DISTRIBUTIONS PER UNIT
---- --- -----------------------
3rd Quarter 1999 (from $ 19.06 $ 13.50 $0.23 (paid November 12, 1999 for the period from
August 20, 1999) August 20, 1999, through September 30, 1999)
4th Quarter 1999 $ 14.75 $ 12.00 $0.50 (paid February 14, 2000)
1st Quarter 2000 $ 14.50 $ 12.13 $0.50 (paid May 15, 2000)
2nd Quarter 2000 $ 15.13 $ 12.63 $0.50 (paid August 14, 2000)
3rd Quarter 2000 $ 17.75 $ 14.25 $0.50 (paid November 14, 2000)
4th Quarter 2000 $ 18.25 $ 15.00 $0.50 (paid February 14, 2001)
The Partnership has also issued 6,422,531 Subordinated Units, all of which
are held by the Special GP, for which there is no established public trading
market.
The Partnership will distribute to its partners (including holders of
Subordinated Units), on a quarterly basis, all of its Available Cash. Available
Cash generally means, with respect to any quarter of the Partnership, all cash
on hand at the end of each quarter less cash reserves in an amount necessary or
appropriate in the reasonable discretion of the Managing GP to (a) provide for
the proper conduct of the Partnership's business, (b) comply with applicable law
of any debt instrument or other agreement of the Partnership or any of its
affiliates, or (c) provide funds for distributions to unitholders and the
General Partners for any one or more of the next four quarters. Available Cash
is defined in the Partnership Agreement listed as an exhibit to this Annual
Report on Form 10-K. The Partnership Agreement defines minimum quarterly
distributions (MQDs) as $0.50 for each full fiscal quarter. Distributions of
Available Cash to the holder of the Subordinated Units are subject to the prior
rights of the holders of the Common Units to receive MQDs for each quarter
during the subordination period, and to receive any arrearages in the
distribution of the MQDs on the Common Units for prior quarters during the
subordination period. The subordination period will generally not end before
September 30, 2004. Under certain circumstances, up to half of the Subordinated
17
19
Units may convert into Common Units before the end of the subordination period,
which will generally not occur before September 30, 2003.
ITEM 6. SELECTED FINANCIAL DATA
On August 20, 1999, the Partnership completed its IPO whereby the
Partnership became the successor to the business of the Predecessor. Our
selected pro forma and historical financial data below was derived from the
audited consolidated financial statements of the Partnership as of December 31,
2000 and 1999, 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, the audited combined financial statements of the Predecessor, as of August
19, 1999, and for the period from January 1, 1999 to August 19, 1999, as of and
for the years ended December 31, 1998, and 1997, and as of and for the five
months ended December 31, 1996. The Predecessor purchased the coal operations of
MAPCO Inc. effective August 1, 1996, in a business combination using the
purchase method of accounting and the purchase price was allocated to the assets
acquired and liabilities assumed based on their fair values. Accordingly, the
audited financial data for periods prior to August 1, 1996, is not necessarily
comparable to subsequent periods. The amounts in the table below, except for the
per unit data and the per ton information, are in millions.
Partnership
-----------------------------------------------------
From
Commencement
of Operations (on
Pro Forma August 20, 1999)
Year Ended Year Ended to
December 31, December 31, December 31,
2000 1999(1) 1999
------------- ------------- --------------
Statements of Income:
Sales and operating revenues
Coal sales $ 347.2 $ 345.9 $ 128.8
Transportation revenues(2) 13.5 19.1 4.9
Other sales and operating revenues 2.8 0.9 0.4
------------- ------------- -------------
Total revenues 363.5 365.9 134.1
------------- ------------- -------------
Expenses
Operating expenses 257.4 242.0 89.9
Transportation expenses(2) 13.5 19.1 4.9
Outside purchases 16.9 24.2 6.4
General and administrative 15.2 15.1 6.2
Depreciation, depletion and amortization 39.1 39.7 15.1
Interest expense 16.6 19.4 5.9
Unusual items(3) (9.5) -- --
------------- ------------- -------------
Total expenses 349.2 359.5 128.4
------------- ------------- -------------
Income from operations 14.3 6.4 5.7
Other income (expense) 1.3 1.2 0.6
------------- ------------- -------------
Income before income taxes 15.6 7.6 6.3
Income tax expense (benefit) -- -- --
------------- ------------- -------------
Net income $ 15.6 $ 7.6 $ 6.3
============= ============= =============
Basic net income per limited
partner unit $ 0.99 $ 0.48 $ 0.40
============= ============= =============
Diluted net income per limited
partner unit $ 0.98 $ 0.48 $ 0.40
============= ============= =============
Weighted average number of units
outstanding-basic 15,405,311 15,405,311 15,405,311
============= ============= =============
Weighted average number of units
outstanding-diluted 15,551,062 15,405,311 15,405,311
============= ============= =============
Balance Sheet Data:
Working capital(4) $ 38.6 $ -- $ 61.2
Total assets 309.2 -- 314.8
Long-term debt 226.3 -- 230.0
Total liabilities 341.0 -- 330.7
Net Parent investment -- -- --
Partners' capital (deficit) (31.8) -- (15.9)
Other Operating Data:
Tons sold 15.0 15.0 5.6
Tons produced 13.7 14.1 5.3
Revenues per ton sold(5) $ 23.33 $ 23.12 $ 23.07
Cost per ton sold(6) $ 19.30 $ 18.75 $ 18.30
Other Financial Data:
EBITDA(7) $ 71.3 $ 66.7 $ 27.3
Net cash provided by (used in) operating activities 71.4 -- (13.9)
Net cash used in investing activities (41.0) -- (43.9)
Net cash provided by (used in) financing activities (31.4) -- 65.8
Maintenance capital expenditures(8) 21.2 6.0 6.0
Predecessor
---------------------------------------------------------------------------------
For the
period from Five Seven
January 1, 1999 Year Ended Months Months
to December 31, Ended Ended
August 19, ---------------------------- December 31, July 31,
1999 1998 1997 1996 1996
--------------- ----------- ----------- ----------- -----------
Statements of Income:
Sales and operating revenues
Coal sales $ 217.0 $ 357.4 $ 305.3 $ 133.9 $ 184.1
Transportation revenues(2) 14.2 41.4 42.7 20.4 29.0
Other sales and operating revenues 0.6 4.5 8.5 4.4 7.5
----------- ----------- ----------- ----------- -----------
Total revenues 231.8 403.3 356.5 158.7 220.6
----------- ----------- ----------- ----------- -----------
Expenses
Operating expenses 152.1 237.6 197.4 79.2 110.7
Transportation expenses(2) 14.2 41.4 42.7 20.4 29.0
Outside purchases 17.7 51.2 49.8 34.7 45.7
General and administrative 8.9 15.3 15.4 5.9 7.3
Depreciation, depletion and amortization 24.6 39.8 33.7 11.9 7.7
Interest expense 0.1 0.2 -- -- --
Unusual items(3) -- 5.2 -- -- --
----------- ----------- ----------- ----------- -----------
Total expenses 217.6 390.7 339.0 152.1 200.4
----------- ----------- ----------- ----------- -----------
Income from operations 14.2 12.6 17.5 6.6 20.2
Other income (expense) 0.5 (0.1) 0.5 0.3 --
----------- ----------- ----------- ----------- -----------
Income before income taxes 14.7 12.5 18.0 6.9 20.2
Income tax expense (benefit) 4.5 3.8 4.3 (0.9) 5.5
----------- ----------- ----------- ----------- -----------
Net income $ 10.2 $ 8.7 $ 13.7 $ 7.8 $ 14.7
=========== =========== =========== =========== ===========
Basic net income per limited
partner unit
Diluted net income per limited
partner unit
Weighted average number of units
outstanding-basic
Weighted average number of units
outstanding-diluted
Balance Sheet Data:
Working capital(4) $ 11.2 $ 7.1 $ 10.3 $ 15.9 $ 24.6
Total assets 262.8 261.1 245.8 262.0 270.7
Long-term debt 1.8 1.7 1.9 -- --
Total liabilities 110.2 108.3 87.0 85.8 85.0
Net Parent investment 151.6 152.8 158.8 176.2 185.7
Partners' capital (deficit) -- -- -- -- --
Other Operating Data:
Tons sold 9.4 15.1 12.4 5.1 6.9
Tons produced 8.8 13.4 10.9 3.9 5.3
Revenues per ton sold(5) $ 23.15 $ 23.97 $ 25.31 $ 27.12 $ 27.77
Cost per ton sold(6) $ 19.01 $ 20.14 $ 21.18 $ 23.49 $ 23.72
Other Financial Data:
EBITDA(7) $ 39.4 $ 52.5 $ 51.7 $ 18.8 $ 27.9
Net cash provided by (used in) operating
activities 32.9 50.5 53.2 23.0 16.7
Net cash used in investing activities (21.5) (35.6) (22.4) (13.0) (16.7)
Net cash provided by (used in) financing
activities (11.4) (14.9) (30.8) (10.0) --
Maintenance capital expenditures(8) 15.5 17.2 15.2 2.7 10.8
(1) The unaudited selected pro forma financial and operating data for the year
ended December 31, 1999, is based on the historical financial statements of
the Partnership from the Partnership's commencement of operations on
18
20
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 (a) pro forma interest on debt
assumed by the Partnership and (b) the elimination of income tax expense as
income taxes will be borne by the partners and not the Partnership. The pro
forma adjustments do not include approximately $1.0 million of general and
administrative expenses that the Partnership believed would have been
incurred as a result of its being a public entity.
(2) During the fourth quarter 2000, the Partnership adopted the Financial
Accounting Standards Board Emerging Issues Task Force Issue No. 00-10
"Accounting for Shipping and Handling Fees and Costs" (EITF No. 00-10). The
Partnership records the cost of transporting coal to customers through
third party carriers and the corresponding Partnership's direct
reimbursement of these costs through customer billings. This activity is
separately presented as transportation revenue and expense rather than
offsetting these amounts in the consolidated and combined statements of
income. There was no cumulative effect of the accounting change on net
income and prior periods presented have been reclassified to comply with
EITF No. 00-10.
(3) Represents income from the final resolution of an arbitrated dispute with
respect to the termination of a long-term contract, net of impairment
charges relating to certain transloading facility assets, partially offset
by expenses associated with other litigation matters in 2000 and the net
loss incurred during the temporary closing of one of our mining complexes
in the second half of 1998.
(4) Excludes accounts receivable from affiliates for the Predecessor prior to
July 31, 1996.
(5) Revenues per ton sold is based on the total of coal sales and other sales
and operating revenues divided by tons sold.
(6) Cost per ton sold is based on the total of operating expenses, outside
purchases and general and administrative expenses divided by tons sold.
(7) EBITDA is defined as income from operations before interest expense, income
taxes and depreciation, depletion and amortization. EBITDA should not be
considered as an alternative to net income, income before income taxes,
cash flows from operating activities or any other measure of financial
performance presented in accordance with generally accepted accounting
principles. EBITDA has not been adjusted for unusual items. EBITDA is not
intended to represent cash flow and does not represent the measure of cash
available for distribution, but provides additional information for
evaluating our ability to make the MQDs. The Partnership's method of
computing EBITDA also may not be the same method used to compute similar
measures reported by other companies, or EBITDA may be computed differently
by the Partnership in different contexts (i.e., public reporting versus
computation under financing arrangements).
(8) Maintenance capital expenditures for the Partnership, as defined under the
terms of the Partnership Agreement, are defined as those capital
expenditures required to maintain, over the long term, the operating
capacity of our capital assets. Maintenance capital expenditures for the
Predecessor reflect our historical designation of maintenance capital
expenditures.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
GENERAL
The following discussion of the financial condition and results of
operations for the Partnership and its Predecessor should be read in conjunction
with the historical financial statements and notes thereto included elsewhere in
this Annual Report on Form 10-K. For more detailed information regarding the
basis of presentation for the following financial information, see "Item 8.
Financial Statements and Supplementary Data. -- Note 1.
Organization and Presentation."
We are a diversified producer and marketer of coal to major U.S. utilities
and industrial users. In 2000, our total production was 13.7 million tons and
our total sales were 15.0 million tons. The coal we produced in 2000 was
approximately 20.4% low-sulfur coal, 19.0% medium-sulfur coal and 60.6%
high-sulfur coal.
19
21
At December 31, 2000, we had approximately 466 million tons of proven and
probable coal reserves in Illinois, Indiana, Kentucky, Maryland and West
Virginia. We believe we control adequate reserves to implement our currently
contemplated mining plans. In addition, there are substantial unleased reserves
on adjacent properties that we intend to acquire or lease as our mining
operations approach these areas.
In 2000, approximately 73% of our sales tonnage was consumed by electric
utilities with the balance consumed by cogeneration plants and industrial users.
Our largest customers in 2000 were AEI, Seminole, TVA, and VEPCO. We have had
relationships with three of these customers for at least 15 years. In 2000,
approximately 85% of our sales tonnage, including approximately 86% of our
medium- and high-sulfur coal sales tonnage, was sold under long-term contracts.
The balance of our sales were made on the spot market. Our long-term contracts
contribute to our stability and profitability by providing greater
predictability of sales volumes and sales prices. In 2000, approximately 96% of
our medium- and high-sulfur coal was sold to utility plants with installed
pollution control devices, also known as scrubbers, to remove sulfur dioxide.
One of our business strategies is to continue to make productivity
improvements to remain a low cost producer in each region in which we operate.
Our principal expenses related to the production of coal are labor and benefits,
equipment, materials and supplies, maintenance, royalties and excise taxes.
Unlike most of our competitors in the eastern U.S., we employ a totally
union-free workforce. Many of the benefits of the union-free workforce are not
necessarily reflected in direct costs, but we believe are related to higher
productivity. In addition, while we do not pay our customers' transportation
costs, they may be substantial and often the determining factor in a coal
consumer's contracting decision. Our mining operations are located near many of
the major eastern utility generating plants and on major coal hauling railroads
in the eastern U.S. We believe this gives us a transportation cost advantage
compared to many of our competitors.
RESULTS OF OPERATIONS
In comparing 2000 to 1999 and 1999 to 1998, the Partnership and Predecessor
periods for 1999 have been combined. Since the Partnership maintained the
historical basis of the Predecessor's net assets, management believes that the
combined Partnership and Predecessor results for 1999 are comparable with 1998.
The interest expense associated with the debt incurred concurrent with the
closing of the IPO is applicable only to the Partnership period. See "Item 8.
Financial Statements and Supplementary Data. -- Note 1. Organization and
Presentation."
2000 Compared with 1999
Coal sales. Coal sales for 2000 increased 0.4% to $347.2 million from $345.9
million for 1999. The increase of $1.3 million was primarily attributable to
higher sales volumes in the Illinois Basin operations and at the restructured
Pontiki operation, which were directly offset by planned reduced participation
in low margin, coal export brokerage markets. The brokerage business is not
expected to be material in the future. Tons sold remained consistent at 15.0
million for 2000 and 1999. Tons produced decreased 2.9% to 13.7 million for 2000
from 14.1 million for 1999.
Transportation revenues. Transportation revenues for 2000 decreased 29.4% to
$13.5 million from $19.1 million for 1999. The decrease of $5.6 million was
primarily attributable to planned reduced participation in coal export brokerage
markets, which generally have higher transportation costs. No margin is realized
on transportation revenues.
Other sales and operating revenues. Other sales and operating revenues
increased to $2.8 million for 2000 from $0.9 million for 1999. The increase of
$1.9 million resulted from the introduction of a third party coal synfuel
production facility at the Hopkins County Coal mining complex. Hopkins County
Coal provided the coal feedstock and received various fees for operating the
third party's coal synfuel facility and providing other services. We assisted
the third party with marketing the coal synfuel and received a fee for such
20
22
services. Synfuel shipments continue in 2001 on a month to month basis,
currently contemplated through mid-2001, with customer interest through 2003.
However, future shipments are dependent upon, among other things, receiving a
new favorable private letter ruling from the IRS. In late October 2000, the IRS
issued Rev. Proc. 2000-47, suspending issuance of private letter rulings for
most coal synfuel plants while a review is conducted concerning whether current
tax rules adequately address the evolving synfuel industry. The IRS requested
public comment on Rev. Proc. 2000-47 by November 27, 2000. The IRS indicated it
will provide substantial guidance in the form of a general revenue ruling or a
tax regulation to address tax credits granted under Section 29 of the Internal
Revenue Code. Until such guidance is received from the IRS, we cannot give any
assurance that future benefits will be received from the coal synfuel production
facility.
Operating expenses. Operating expenses increased 6.3% to $257.4 million for
2000 from $242.0 million for 1999. The increase of $15.4 million was a result
of: (a) start-up expenses related to the opening of the newly developed Gibson
County Coal mining complex during the fourth quarter of 2000, (b) higher sales
volumes in the Illinois Basin operations, (c) increased production volumes at
the restructured Pontiki operation, and (d) prolonged adverse mining conditions
at the Mettiki longwall mine.
Transportation expenses. See "Transportation Revenues" above concerning the
decrease in transportation expenses.
Outside purchases. Outside purchases declined 30.2% to $16.9 million for
2000 from $24.2 million for 1999. The decrease of $7.3 million was the result of
lower coal export brokerage volumes. See "Coal sales" above concerning the
decrease in coal export brokerage volumes.
General and administrative. General and administrative expenses were
comparable for 2000 and 1999 at $15.2 million.
Depreciation, depletion and amortization. Depreciation, depletion and
amortization expense were comparable for 2000 and 1999 at $39.1 million and
$39.7 million, respectively.
Interest expense. Interest expense was $16.6 million for 2000 compared to
$6.0 million for 1999. The increase reflected the full year impact of interest
on the $180 million principal amount of 8.31% senior notes and $50 million of
borrowings on the term loan facility in connection with the IPO and concurrent
transactions occurring on August 20, 1999. See "Item 8. Financial Statements and
Supplementary Data. -- Note 1. Organization and Presentation."
Unusual items. The Partnership was involved in litigation with Seminole with
respect to Seminole's termination of a long-term contract for the transloading
of coal from rail to barge through the Mt. Vernon terminal in Indiana. The final
resolution between the parties, reached in conjunction with an arbitrator's
decision rendered during the third quarter, included both cash payments and
amendments to an existing coal supply contract. The Partnership recorded income
of $12.2 million, which is net of litigation expenses and impairment charges
relating to certain Mt. Vernon transloading facility assets. Additionally, the
Partnership recorded an expense of $2.7 million related to other litigation
matters. The net effect of these unusual items was $9.5 million. See "Item 8.
Financial Statements. -- Note 4. Unusual Items."
Income before income taxes. Income before income taxes was $15.6 million for
2000 compared to $21.0 million for 1999. The decrease of $5.4 million was
primarily attributable to: (a) start-up expenses related to the opening of the
new Gibson County coal mining complex during the fourth quarter of 2000, (b)
increased operating expenses as a result of prolonged adverse mining conditions
encountered at the Mettiki longwall mining complex and (c) additional interest
expense associated with the debt incurred concurrent with the closing of the
IPO, partially offset by unusual items recorded during 2000. See "Unusual items"
described above.
21
23
Income tax expense. The Partnership's earnings or loss for federal income
taxes purposes will be included in the tax returns of the individual partners.
Accordingly, no recognition is given to income taxes in the accompanying
financial statements of the Partnership. The Predecessor was included in the
consolidated federal income tax return of ARH. Federal and state income taxes
were calculated as if the Predecessor had filed its return on a separate company
basis utilizing an effective income tax rate of 31%.
EBITDA (income from operations before net interest expense, income taxes,
depreciation and depletion and amortization) increased 6.9% to $71.3 million for
2000 compared with $66.7 million for 1999. The $4.6 million increase was
primarily attributable to the unusual items recorded during 2000, see "Unusual
items" described above, and the increased production and sales volumes at the
restructured Pontiki mine, which was partially offset by increased operating
expenses as a result of adverse mining conditions at the Mettiki longwall mining
complex.
EBITDA should not be considered as an alternative to net income, income
before income taxes, cash flows from operating activities or any other measure
of financial performance presented in accordance with generally accepted
accounting principles. EBITDA has not been adjusted for unusual items. EBITDA is
not intended to represent cash flow and does not represent the measure of cash
available for distribution, but provides additional information for evaluating
the Partnership's ability to make MQDs. The Partnership's method of computing
EBITDA also may not be the same method used to compute similar measures reported
by other companies, or EBITDA may be computed differently by the Partnership in
different contexts (i.e., public reporting versus computation under financing
agreements).
1999 Compared with 1998
Coal sales. Coal sales for 1999 declined 3.2% to $345.9 million from $357.4
million for 1998. The decrease of $11.5 million was primarily attributable to
lower coal export brokerage volumes partially offset by improved results from
the restructured Pontiki mining complex and full-year benefits from the capital
invested at Hopkins County Coal. The lower brokerage volumes were largely
attributable to reduced participation in coal export brokerage markets. The
brokerage business is not expected to be material in the future. Because coal
brokerage operations generate lower margins than direct coal sales, changes in
the levels of brokerage activity have a greater impact on revenues and outside
purchases than on margins. Tons sold decreased less than 1.0% to 15.0 million
tons for 1999 from 15.1 million tons for 1998. Tons produced increased 5.1% to
14.1 million tons for 1999 from 13.4 million tons for 1998.
Transportation revenues. Transportation revenues for 1999 decreased 53.9% to
$19.1 million from $41.4 million for 1998. The decrease of $22.3 million was
primarily attributable to planned reduced participation in coal export brokerage
markets, which generally have higher transportation costs. No margin is realized
on transportation revenues.
Other sales and operating revenues. Other sales and operating revenues
declined 79.0% to $0.9 million for 1999 from $4.5 million from 1998. The
decrease of $3.6 million was primarily due to lower volumes at the Mt. Vernon
facility due to the dispute with Seminole. See "Item 8. Financial Statements and
Supplementary Data. -- Note 4. Unusual Items."
Transportation expenses. See "Transportation Revenues" above concerning the
decrease in transportation expenses.
Operating expenses. Operating expenses were comparable for 1999 and 1998 at
$242.0 million and $237.6 million, an increase of 1.9%.
Outside purchases. Outside purchases declined 52.8% to $24.2 million for
1999 from $51.2 million for 1998. The decrease of $27.0 million was the result
of lower coal export brokerage volumes. See coal sales above concerning the
decrease in coal export brokerage volumes.
22
24
General and administrative. General and administrative expenses were
comparable for 1999 and 1998 at $15.2 million and $15.3 million, a decrease of
less than 1.0%.
Depreciation, depletion and amortization. Depreciation, depletion and
amortization expense were comparable for 1999 and 1998 at $39.7 million and
$39.8 million, a decrease of less than 1.0%.
Interest expense. Interest expense was $6.0 million for 1999 compared to
$0.2 million for 1998. The increase reflected the interest on the $180 million
principal amount of 8.31% senior notes and $50 million of borrowings on the term
loan facility in connection with the IPO and concurrent transactions occurring
on August 20, 1999. See "Item 8. Financial Statements and Supplementary Data. --
Note 1. Organization and Presentation."
Unusual items. In response to market conditions, the Pontiki mining complex
ceased operations and terminated substantially all of its workforce in September
1998. During the idle status period, which ended in November 1998, Pontiki
incurred a net loss of approximately $5.2 million consisting of estimated
amounts for increased workers' compensation claims of $1.2 million and severance
payments consistent with the Worker Adjustment and Retraining Notification Act
of $1.2 million, as well as the costs associated with maintaining an idled mine
of $2.8 million.
Income before income taxes. Income before income taxes increased 67.3% to
$21.0 million for 1999 compared to $12.5 million for 1998. The increase of $8.5
million was primarily attributable to improved productivity, which included the
benefits of the restructured operation at Pontiki following the idle status
period of the mine, which resulted in the $5.2 million unusual item recorded in
1998 as discussed above, and the capital investments at the Hopkins County
operation, partially offset by the losses incurred at Mt. Vernon due to the
dispute with Seminole.
Income tax expense. The Partnership's earnings or loss for federal income
taxes purposes are included in the tax returns of the individual partners.
Accordingly, no recognition is given to income taxes in the accompanying
financial statements of the Partnership. The Predecessor is included in the
consolidated federal income tax return of ARH. Federal and state income taxes
are calculated as if the Predecessor had filed its return on a separate company
basis utilizing an effective income tax rate of 31%.
EBITDA. (income from operations before net interest expense, income taxes,
depreciation, and depletion and amortization) increased 26.9% to $66.7 million
for 1999 compared with $52.5 million for 1998. The $14.2 million increase was
attributable to the same factors that contributed to the increase in income
before income taxes.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
Cash provided by operating activities was $71.4 million in 2000 compared to
$19.0 million in 1999. The increase in cash provided by operating activities was
principally attributable to the decrease in coal inventory of approximately
$10.0 million and the Special GP retaining approximately $37.9 million of trade
receivables in conjunction with the IPO and concurrent transactions that
occurred on August 20, 1999.
Net cash used in investing activities of $41.0 million in 2000 was
principally attributable to capital expenditures. Net cash used in investing
activities of $65.4 million for 1999 was principally attributable to capital
expenditures and the purchase of U.S. Treasuries in conjuction with the IPO and
concurrent transactions that occurred on August 20, 1999.
23
25
Net cash used in financing activities was $31.4 million for 2000 compared to
net cash provided by financing activities of $54.4 million for 1999. Cash used
in financing activities during 2000 was a direct result of four MQDs paid in
2000 of $0.50 per unit on Common and Subordinated Units outstanding. The net
cash provided by financing activities in 1999 was principally attributable to
net cash provided by the IPO and concurrent transactions that occurred on August
20, 1999.
Capital Expenditures
Capital expenditures increased to $46.2 million in 2000 compared to $39.2
million in 1999. The increase was primarily attributable to the development of
the new Gibson County Coal mining complex, which commenced production in
November 2000. During 2000, the Partnership liquidated approximately $7.1
million of U.S. Treasury Notes to fund various qualifying capital expenditures
with the remaining expenditures funded through cash generated from operations.
The Partnership approved an extension of its existing Pattiki mine into adjacent
coal reserves. The extension involves capital expenditures of approximately
$30.0 million during the 2000-2003 period and is expected to allow the Pattiki
mine to continue its existing production level for the next 15 years.
We currently expect that our average annual maintenance capital expenditures
will be approximately $23.5 million. We currently expect to fund our anticipated
capital expenditures with cash generated from operations and the utilization of
the revolving credit facility described below.
Notes Offering and Credit Facility
Concurrently with the closing of the IPO, the Special GP issued and the
Intermediate Partnership assumed the obligations with respect to $180 million
principal amount of 8.31% senior notes due August 20, 2014 (Senior Notes). The
Special GP also entered into, and the Intermediate Partnership assumed the
obligations under a $100 million credit facility (Credit Facility). The Credit
Facility consists of three tranches, including a $50 million term loan facility,
a $25 million working capital facility and a $25 million revolving credit
facility. The Partnership has borrowings outstanding of $50 million under the
term loan facility, but no borrowings outstanding under either the working
capital facility or the revolving credit facility at December 31, 2000, and
1999. The weighted average interest rates on the term loan facility at December
31, 2000, and 1999, was 7.77% and 7.07%, respectively. The Credit Facility
expires August 2004. The Senior Notes and Credit Facility are guaranteed by
Alliance Coal, LLC and all of its subsidiaries. In addition, the Credit Facility
is further secured by a pledge of treasury securities, which, upon written
notice, are released for purposes of financing qualified capital expenditures of
the Intermediate Partnership or its subsidiaries. The Senior Notes and Credit
Facility contain various restrictive and affirmative covenants, including the
amount of distributions by the Intermediate Partnership and the incurrence of
other debt.
Accruals of Other Liabilities
We had accruals for deferred credits and other liabilities, including
current obligations, totaling $67.1 million and $61.9 million at December 31,
2000 and 1999. These accruals were chiefly comprised of workers' compensation
benefits, black lung benefits, and costs associated with reclamation and mine
closing. These obligations are self-insured and were funded at the time the
expense was incurred. The accruals of these items were based on estimates of
future expenditures based on current legislation and related regulations and
other developments. Thus, from time to time, the Partnership's results of
operations may be significantly effected by changes to these deferred credits
and other liabilities. See "Item 8. Financial Statements and Supplementary
Data. -- Note 12. Reclamation and Mine Closing Costs and Note 13.
Pneumoconiosis ("Black Lung") Benefits."
We are required to pay black lung benefits to eligible and former employees
under the BLBA. We also are liable under various state statutes for similar
claims. We provide self-insured accruals for these benefits. We had accrued
liabilities of $22.2 million for these benefits at December 31, 2000, and 1999.
24
26
We accrue for reclamation and mine closing costs. We estimate the costs and
timing of future reclamation and mine closing costs and record those estimates
on a present value basis. We had accrued liabilities of $16.0 million and $14.8
million at December 31, 2000 and 1999 for these costs.
We accrue for workers' compensation claims resulting from traumatic injuries
based on actuarial valuations and periodically adjust these estimates based on
the estimated costs of claims made. We had accrued liabilities of $20.6 million
and $19.5 million at December 31, 2000 and 1999 for these costs.
INFLATION
Inflation in the U.S. has been relatively low in recent years and did not
have a material impact on our results of operations for the years ended December
31, 2000, 1999 or 1998.
RECENT ACCOUNTING PRONOUNCEMENTS
Effective January 1, 2001, the Partnership adopted Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities," which establishes accounting and reporting standards for derivative
instruments and for hedging activities. It requires that all derivatives be
recognized as either assets or liabilities in the statement of financial
position and be measured at fair value. The Partnership currently has no
identified derivative instruments or hedging activities. Accordingly, this
standard had no material effect on the Partnership's consolidated financial
statements upon adoption.
During the fourth quarter 2000, the Partnership adopted Financial Accounting
Standards Board Emerging Issues Task Force Issue No. 00-10 "Accounting for
Shipping and Handling Fees and Costs." Accordingly, the Partnership reflects the
cost of transporting coal to customers through third party carriers as
transportation expenses and the corresponding reimbursement of these costs
through customer billings as transportation revenues in the consolidated and
combined statements of income. These amounts were previously offset. There was
no cumulative effect on net income and the prior periods' consolidated and
combined statements of income have been reclassified to comply with this
presentation.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Almost all of the Predecessor's transactions were, and almost all of the
Partnership's transactions are, denominated in U.S. dollars, and as a result,
the Partnership does not have material exposure to currency exchange-rate risks.
The Partnership does not, engage in any interest rate, foreign currency
exchange rate or commodity price-hedging transactions.
The Intermediate Partnership assumed obligations under the Credit Facility.
Borrowings under the Credit Facility are at variable rates and as a result the
Partnership has interest rate exposure.
The table below provides information about the Partnership's market
sensitive financial instruments and constitutes a "forward-looking statement."
The fair values of long-term debt are estimated using discounted cash flow
analyses, based upon the Partnership's current incremental borrowing rates for
similar types of borrowing arrangements as of December 31, 2000 and 1999. The
carrying amounts and fair values of financial instruments are as follows (in
thousands):
25
27
FAIR VALUE
EXPECTED MATURITY DATES DECEMBER 31,
AS OF DECEMBER 31, 2000 2001 2002 2003 2004 2005 THEREAFTER TOTAL 2000
------- ------- --------- --------- -------- ---------- --------- ----------
Senior Notes-fixed rate $ -- $ -- $ -- $ -- $ 18,000 $ 162,000 $ 180,000 $ 180,000
Weighted Average interest rate 8.31% 8.31%
Term Loan-floating rate $ 3,750 $15,000 $ 16,250 $ 15,000 $ -- $ -- $ 50,000 $ 50,000
Weighted Average interest rate 7.77% 7.77% 7.77% 7.77%
FAIR VALUE
EXPECTED MATURITY DATES DECEMBER 31,
AS OF DECEMBER 31, 1999 2000 2001 2002 2003 2004 THEREAFTER TOTAL 1999
------- -------- --------- --------- -------- ---------- --------- ----------
Senior Notes-fixed rate $ -- $ -- $ -- $ -- $ -- $180,000 $180,000 $165,000
Weighted Average interest rate 8.31%
Term Loan-floating rate $ -- $ 3,750 $ 15,000 $ 16,250 $ 15,000 $ -- $ 50,000 $ 50,000
Weighted Average interest rate 7.07% 7.07% 7.07% 7.07%
26
28
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,
2000 and 1999, the related consolidated and combined statements of income and
cash flows for the year ended December 31, 2000 and the period from the
Partnership's commencement of operations (on August 20, 1999) to December 31,
1999 and the Predecessor period from January 1, 1999 to August 19, 1999 and the
year ended December 31, 1998 and the statement of Partners' capital (deficit)
for the year ended December 31, 2000 and the period from the Partnership's
commencement of operations (on August 20, 1999) to December 31, 1999. These
financial statements are the responsibility of the Partnership's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated and combined financial statements present
fairly, in all material respects, the financial position of the Partnership at
December 31, 2000 and 1999 and the results of their operations and their cash
flows for the year ended December 31, 2000 and the period from the Partnership's
commencement of operations (on August 20, 1999) to December 31, 1999 and the
Predecessor period from January 1, 1999 to August 19, 1999 and the year ended
December 31, 1998 in conformity with accounting principles generally accepted in
the United States of America.
/s/ Deloitte & Touche LLP
Tulsa, Oklahoma
January 24, 2001
27
29
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS DECEMBER 31, 2000 AND 1999 (IN THOUSANDS, EXCEPT
UNIT DATA)
- --------------------------------------------------------------------------------
DECEMBER 31,
-----------------------------
ASSETS 2000 1999
------------ ------------
CURRENT ASSETS:
Cash and cash equivalents $ 6,933 $ 8,000
Trade receivables 35,898 33,056
Due from affiliates 208 --
Marketable securities (at cost, which approximates fair value) 37,398 42,339
Inventories 10,842 21,130
Advance royalties 2,865 1,557
Prepaid expenses and other assets 1,168 923
------------ ------------
Total current assets 95,312 107,005
PROPERTY, PLANT AND EQUIPMENT AT COST 320,445 278,221
LESS ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION (135,782) (102,709)
------------ ------------
184,663 175,512
OTHER ASSETS:
Advance royalties 10,009 8,306
Coal supply agreements, net 16,324 19,879
Other long-term assets 2,858 4,112
------------ ------------
$ 309,166 $ 314,814
============ ============
LIABILITIES AND PARTNERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 25,558 $ 19,377
Due to affiliates -- 334
Accrued taxes other than income taxes 4,863 4,574
Accrued payroll and related expenses 6,975 8,811
Accrued interest 5,439 5,491
Workers' compensation and pneumoconiosis benefits 4,415 4,317
Other current liabilities 5,710 2,937
Current maturities, long-term debt 3,750 --
------------ ------------
Total current liabilities 56,710 45,841
LONG-TERM LIABILITIES:
Long-term debt, excluding current maturities 226,250 230,000
Accrued pneumoconiosis benefits 21,651 21,655
Workers' compensation 16,748 15,696
Reclamation and mine closing 14,940 13,407
Due to affiliates 1,278 472
Other liabilities 3,376 3,671
------------ ------------
Total liabilities 340,953 330,742
COMMITMENTS AND CONTINGENCIES
PARTNERS' CAPITAL (DEFICIT):
Common Unitholders 8,982,780 units outstanding 149,642 158,705
Subordinated Unitholder 6,422,531 units outstanding 116,794 123,273
General Partners (298,223) (297,906)
------------ ------------
Total Partners' capital (deficit) (31,787) (15,928)
------------ ------------
$ 309,166 $ 314,814
============ ============
See notes to consolidated and combined financial statements.
28
30
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED AND COMBINED STATEMENTS OF INCOME
FOR THE YEAR ENDED DECEMBER 31, 2000 AND THE PERIOD FROM THE PARTNERSHIP'S
COMMENCEMENT OF OPERATIONS (ON AUGUST 20, 1999) TO DECEMBER 31, 1999 AND THE
PREDECESSOR PERIOD FROM JANUARY 1, 1999 TO AUGUST 19, 1999 AND THE YEAR ENDED
DECEMBER 31, 1998 (IN THOUSANDS, EXCEPT UNIT AND PER UNIT DATA)
- --------------------------------------------------------------------------------
PARTNERSHIP PREDECESSOR
--------------------------------- -----------------------------------
FROM
COMMENCEMENT FOR THE
OF OPERATIONS PERIOD FROM
YEAR ENDED (ON AUGUST 20, 1999) JANUARY 1, 1999 YEAR ENDED
DECEMBER 31, TO TO DECEMBER 31,
2000 DECEMBER 31, 1999 AUGUST 19, 1999 1998
------------ ----------------- --------------- ------------
SALES AND OPERATING REVENUES:
Coal sales $ 347,209 $ 128,860 $ 217,033 $ 357,440
Transportation revenues 13,511 4,907 14,223 41,408
Other sales and operating revenues 2,749 358 577 4,453
------------ ------------ ------------ ------------
Total revenues 363,469 134,125 231,833 403,301
------------ ------------ ------------ ------------
EXPENSES:
Operating expenses 257,365 89,945 152,066 237,576
Transportation expenses 13,511 4,907 14,223 41,408
Outside purchases 16,874 6,429 17,738 51,151
General and administrative 15,176 6,245 8,912 15,301
Depreciation, depletion and amortization 39,141 15,081 24,622 39,838
Interest expense (net of interest income and interest
capitalized of $3,015 and $999 for the year ended
December 31, 2000 and 1999 partnership period) 16,563 5,887 100 169
Unusual items (9,466) -- -- 5,211
------------ ------------ ------------ ------------
Total operating expenses 349,164 128,494 217,661 390,654
------------ ------------ ------------ ------------
INCOME FROM OPERATIONS 14,305 5,631 14,172 12,647
OTHER INCOME (EXPENSE) 1,276 641 531 (113)
------------ ------------ ------------ ------------
INCOME BEFORE INCOME TAXES 15,581 6,272 14,703 12,534
INCOME TAX EXPENSE -- -- 4,498 3,866
------------ ------------ ------------ ------------
NET INCOME $ 15,581 $ 6,272 $ 10,205 $ 8,668
============ ============ ============ ============
GENERAL PARTNERS' INTEREST
IN NET INCOME $ 312 $ 125
============ ============
LIMITED PARTNERS' INTEREST
IN NET INCOME $ 15,269 $ 6,147
============ ============
BASIC NET INCOME PER LIMITED
PARTNER UNIT $ 0.99 $ 0.40
============ ============
DILUTED NET INCOME PER LIMITED
PARTNER UNIT $ 0.98 $ 0.40
============ ============
WEIGHTED AVERAGE NUMBER
OF UNITS OUTSTANDING - BASIC 15,405,311 15,405,311
============ ============
WEIGHTED AVERAGE NUMBER
OF UNITS OUTSTANDING - DILUTED 15,551,062 15,405,311
============ ============
See notes to consolidated and combined financial statements.
29
31
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOW FOR THE YEAR ENDED DECEMBER
31, 2000 AND THE PERIOD FROM THE PARTNERSHIP'S COMMENCEMENT OF OPERATIONS (ON
AUGUST 20, 1999) TO DECEMBER 31, 1999 AND THE PREDECESSOR PERIOD FROM JANUARY 1,
1999 TO AUGUST 19, 1999 AND THE YEAR ENDED DECEMBER 31, 1998 (IN THOUSANDS)
- --------------------------------------------------------------------------------
PARTNERSHIP PREDECESSOR
--------------------------------- ----------------------------------
FROM
COMMENCEMENT FOR THE
OF OPERATIONS PERIOD FROM
YEAR ENDED (ON AUGUST 20, 1999) JANUARY 1, 1999 YEAR ENDED
DECEMBER 31, TO TO DECEMBER 31,
2000 DECEMBER 31, 1999 AUGUST 19, 1999 1998
----------- ----------------- ---------------- -------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income 15,581 $ 6,272 $ 10,205 $ 8,668
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 39,141 15,081 24,622 39,838
Impairment of transloading facility 2,439 -- -- --
Deferred income taxes -- -- 639 (1,750)
Reclamation and mine closings 1,074 348 457 705
Coal inventory adjustment to market 579 729 -- 1,743
Other 391 186 (114) 34
Changes in operating assets and liabilities, net of
effects from 1998 purchase of coal business:
Trade receivables (2,842) (33,048) (6,521) 229
Income tax receivable/payable -- -- 651 2,482
Inventories 9,709 (1,433) (371) (6,563)
Advance royalties (3,011) 366 1,153 579
Accounts payable 6,181 (7,410) (129) 2,296
Due to affiliates 264 3,252 -- --
Accrued taxes other than income taxes 289 (630) 678 1,137
Accrued payroll and related benefits (1,836) 844 (828) 491
Accrued pneumoconiosis benefits (4) (1,122) 544 839
Workers' compensation 1,052 2,222 (460) 817
Other 2,366 452 2,370 (1,048)
----------- ------------ ------------ ------------
Total net adjustments 55,792 (20,163) 22,691 41,829
----------- ------------ ------------ ------------
Net cash provided by (used in) operating
activities 71,373 (13,891) 32,896 50,497
----------- ------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of property, plant and equipment (46,151) (17,173) (21,984) (27,669)
Proceeds from sale of property, plant and equipment 210 125 447 185
Purchase of marketable securities (72,523) (51,287) -- --
Proceeds from the maturity of marketable securities 77,464 24,434 -- --
Payment for purchase of business -- -- -- (7,310)
Direct acquisition costs -- -- -- (821)
----------- ------------ ------------ ------------
Net cash used in investing activities (41,000) (43,901) (21,537) (35,615)
----------- ------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from initial public offering (Note 1) -- 137,872 -- --
Cash contribution by General Partner -- 5,917 -- --
Distributions upon formation (Note 1) -- (64,750) -- --
Payment of formation costs -- (4,140) -- --
Deferred financing cost -- (3,517) -- --
Borrowings under revolving credit facility 29,500 -- -- --
Payments under revolving credit facility (29,500) -- -- --
Payments on long-term debt -- (1,975) -- (350)
Distributions to Partners (31,440) (3,615) -- --
Dividend to Parent -- -- -- (8,642)
Return of capital to Parent -- -- (11,359) (5,890)
----------- ------------ ------------ ------------
Net cash provided by (used in) financing
activities (31,440) 65,792 (11,359) (14,882)
----------- ------------ ------------ ------------
NET CHANGE IN CASH AND CASH EQUIVALENTS (1,067) 8,000 -- --
CASH AND CASH EQUIVALENTS AT
BEGINNING OF PERIOD 8,000 -- -- --
----------- ------------ ------------ ------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD 6,933 $ 8,000 $ -- $ --
=========== ============ ============ ============
See notes to consolidated and combined financial statements.
30
32
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL (DEFICIT)
FOR THE YEAR ENDED DECEMBER 31, 2000 AND THE PERIOD FROM THE PARTNERSHIP'S
COMMENCEMENT OF OPERATIONS (ON AUGUST 20, 1999) TO DECEMBER 31, 1999 (IN
THOUSANDS, EXCEPT UNIT DATA)
- --------------------------------------------------------------------------------
NUMBER OF LIMITED TOTAL
PARTNER UNITS MINIMUM PARTNERS'
------------------------- GENERAL PENSION CAPITAL
COMMON SUBORDINATED COMMON SUBORDINATED PARTNERS LIABILITY (DEFICIT)
--------- ------------ --------- ------------ --------- --------- ---------
Balance at commencement of
operations (on August 20, 1999) -- -- $ -- $ 1 $ -- $ -- $ 1
Issuance of units to public 7,750,000 -- 133,732 -- -- -- 133,732
Contribution of net assets of
Predecessor 1,232,780 6,422,531 23,455 122,186 (24,612) (459) 120,570
Managing General Partner
contribution -- -- -- -- 5,917 -- 5,917
Amount retained by Special
General Partner from
debt borrowings assumed
by the Partnership -- -- -- -- (214,514) -- (214,514)
Distribution at time of formation -- -- -- -- (64,750) -- (64,750)
Distribution to Partners -- -- (2,066) (1,477) (72) -- (3,615)
Comprehensive income:
Net income from
commencement of
operations (on August 20,
1999) to December 31, 1999 -- -- 3,584 2,563 125 -- 6,272
Minimum pension liability -- -- -- -- -- 459 459
--------- --------- --------- --------- --------- --------- ---------
Total comprehensive income -- -- 3,584 2,563 125 459 6,731
--------- --------- --------- --------- --------- --------- ---------
Balance at December 31, 1999 8,982,780 6,422,531 158,705 123,273 (297,906) -- (15,928)
Net income -- -- 8,903 6,366 312 -- 15,581
Distribution to Partners -- -- (17,966) (12,845) (629) -- (31,440)
--------- --------- --------- --------- --------- --------- ---------
Balance at December 31, 2000 8,982,780 6,422,531 $ 149,642 $ 116,794 $(298,223) $ -- $ (31,787)
========= ========= ========= ========= ========= ========= =========
See notes to consolidated and combined financial statements.
31
33
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS FOR THE YEAR ENDED
DECEMBER 31, 2000 AND THE PERIOD FROM THE PARTNERSHIP'S COMMENCEMENT OF
OPERATIONS (ON AUGUST 20, 1999) TO DECEMBER 31, 1999 AND THE PREDECESSOR PERIOD
FROM JANUARY 1, 1999 TO AUGUST 19, 1999 AND THE YEAR ENDED DECEMBER 31, 1998
- --------------------------------------------------------------------------------
1. ORGANIZATION AND PRESENTATION
Alliance Resource Partners, L.P., a Delaware limited partnership (the
"Partnership") was formed on May 17, 1999, to acquire, own and operate
certain coal production and marketing assets of Alliance Resource
Holdings, Inc., a Delaware corporation ("ARH") (formerly known as Alliance
Coal Corporation), consisting of substantially all of ARH's operating
subsidiaries, but excluding ARH.
Prior to August 20, 1999, (a) MAPCO Coal Inc., a Delaware corporation and
direct wholly-owned subsidiary of ARH merged with and into Alliance Coal,
LLC, a Delaware limited liability company ("Alliance Coal"), which prior
to August 20, 1999 was also a wholly-owned subsidiary of ARH, (b) several
other indirect corporate subsidiaries of ARH were merged with and into
corresponding limited liability companies, each of which is a wholly-owned
subsidiary of Alliance Coal, and (c) two indirect limited liability
company subsidiaries of ARH became subsidiaries of Alliance Coal as a
result of the merger described in clause (a) above. Collectively, the coal
production and marketing assets and operating subsidiaries of ARH acquired
by the Partnership, but excluding ARH, are referred to as the Alliance
Resource Group (the "Predecessor"). The Delaware limited partnerships and
limited liability companies that comprise the Partnership are as follows:
Alliance Resource Partners, L.P., Alliance Resource Operating Partners,
L.P. (the "Intermediate Partnership"), Alliance Coal, LLC (the holding
company for operations), Alliance Land, LLC, Alliance Properties, LLC,
Backbone Mountain, LLC, Excel Mining, LLC, Gibson County Coal, LLC,
Hopkins County Coal, LLC, MC Mining, LLC, Mettiki Coal, LLC, Mettiki Coal
(WV), LLC, Mt. Vernon Transfer Terminal, LLC, Pontiki Coal, LLC, Webster
County Coal, LLC, and White County Coal, LLC.
The accompanying consolidated financial statements include the accounts
and operations of the limited partnerships and limited liability companies
disclosed above and present the financial position as of December 31, 2000
and 1999 and the results of their operations, cash flows and changes in
partners' capital (deficit) for the year ended December 31, 2000 and the
period from commencement of operations on August 20, 1999 to December 31,
1999. The accompanying combined financial statements include the accounts
and operations of the Predecessor for the periods indicated. All material
intercompany transactions and accounts of the Partnership and Predecessor
have been eliminated.
Initial Public Offering and Concurrent Transactions
On August 20, 1999, the Partnership completed its initial public offering
(the "IPO") of 7,750,000 Common Units ("Common Units") representing
limited partner interests in the Partnership at a price of $19.00 per
unit.
Concurrently with the closing of the IPO, the Partnership entered into a
contribution and assumption agreement (the "Contribution Agreement") dated
August 20, 1999 among the Partnership and the other parties named therein,
whereby, among other things, ARH contributed its 100% member interest in
Alliance Coal, which is the sole member of thirteen subsidiary operating
limited liability companies, to the Intermediate Partnership, and the
Intermediate Partnership holds a 99.999% non-managing member interest in
Alliance Coal. The Partnership and the Intermediate Partnership are
managed by Alliance Resource Management GP, LLC, a Delaware limited
liability company (the "Managing GP"), which as
32
34
a result of the consummation of the transactions under the Contribution
Agreement, holds (a) a 0.99% and 1.0001% managing general partner interest
in the Partnership and the Intermediate Partnership, respectively, and (b)
a 0.001% managing member interest in Alliance Coal. Also, as a result of
the consummation of the transactions completed under the Contribution
Agreement, Alliance Resource GP, LLC, a Delaware limited liability company
and wholly-owned subsidiary of ARH (the "Special GP"), holds (a) 1,232,780
Common Units, (b) 6,422,531 Subordinated Units convertible into Common
Units in the future upon the occurrence of certain events and (c) a 0.01%
special general partner interest in each of the Partnership and the
Intermediate Partnership.
Concurrently with the closing of the IPO, the Special GP issued and the
Intermediate Partnership assumed the obligations under a $180 million
principal amount of 8.31% senior notes due August 20, 2014. The Special GP
also entered into and the Intermediate Partnership assumed the obligations
under a $100 million credit facility.
Consistent with guidance provided by the Emerging Issues Task Force in
Issue No. 87-21 "Change of Accounting Basis in Master Limited Partnership
Transactions," the Partnership maintained the historical cost of the $121
million of net assets received under the Contribution Agreement.
Pro Forma Results of Operations (Unaudited)
For the years ended December 31, 1999 and 1998, the pro forma total
revenues would have been approximately $346,828,000 and $361,893,000,
respectively. For the years ended December 31, 1999 and 1998, the pro
forma net income (loss) would have been approximately $7,567,000 and
$(6,740,000) and net income (loss) per limited partner unit would have
been $0.48 and $(0.43), respectively. The pro forma results of operations
for the years ended December 31, 1999 and 1998, are derived from the
historical financial statements of the Partnership from the commencement
of operations on August 20, 1999 through December 31, 1999 and the
Predecessor for the period from January 1, 1999 through August 19, 1999,
and January 1, 1998 through December 31, 1998. The pro forma results of
operations reflect certain pro forma adjustments to the historical results
of operations as if the Partnership had been formed on January 1, 1998.
The pro forma adjustments include (i) pro forma interest on debt assumed
by the Partnership and (ii) the elimination of income tax expense as
income taxes will be borne by the partners and not the Partnership.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ESTIMATES - The preparation of consolidated and combined financial
statements in conformity with generally accepted accounting principles
requires management to make estimates and assumptions that affect the
reported amounts and disclosures in the consolidated and combined
financial statements. Actual results could differ from those estimates.
FAIR VALUE OF FINANCIAL INSTRUMENTS - The carrying amounts for accounts
receivable, marketable securities and accounts payable approximate fair
value because of the short maturity of those instruments. At December 31,
2000 and 1999, the estimated fair value of long-term debt was
approximately $230 million and $215 million, respectively. The fair value
of long-term debt is based on interest rates that are currently available
to the Partnership for issuance of debt with similar terms and remaining
maturities.
CASH MANAGEMENT - The Partnership reclassified outstanding checks of
$4,698,000 and $3,844,000 at December 31, 2000 and 1999, respectively, to
accounts payable in the consolidated balance sheets.
MARKETABLE SECURITIES - The Partnership has investments in six month U.S.
Treasury Notes that are classified as available-for-sale debt securities.
These investments are subject to certain provisions of the credit facility
(Note 7), which could restrict the use of these investments for financing
a required level of
33
35
capital expenditures within the second anniversary of the credit
facility's effective date. At December 31, 2000, the Partnership has
satisfied the capital expenditure requirements and consequently, the
Partnership's use of the investments is not restricted. At December 31,
2000 and 1999, the cost of these investments approximates fair value and
no effect of unrealized gains (losses) is reflected in Partners' capital
(deficit).
INVENTORIES - Coal inventories are stated at the lower of cost or market
on a first-in, first-out basis. Supply inventories are stated at the lower
of cost or market on an average cost basis.
PROPERTY, PLANT AND EQUIPMENT - Additions and replacements constituting
improvements are capitalized. Maintenance, repairs, and minor replacements
are expensed as incurred. Depreciation and amortization are computed
principally on the straight-line method based upon the estimated useful
lives of the assets or the estimated life of each mine (9 to 15 years at
the revaluation date of August 1, 1996), whichever is less and for 5 years
on certain assets related to the 1998 business acquisition. Depreciable
lives for mining equipment and processing facilities range from 1 to 15
years. Depreciable lives for land and land improvements and depletable
lives for mineral rights range from 5 to 15 years. Depreciable lives for
buildings, office equipment and improvements range from 1 to 13 years.
Gains or losses arising from retirements are included in current
operations. Depletion of mineral rights is provided on the basis of
tonnage mined in relation to estimated recoverable tonnage.
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, which is
included as an unusual item in the accompanying consolidated and combined
statements of operations.
ADVANCE ROYALTIES - Rights to coal mineral leases are often acquired
through advance royalty payments. Management assesses the recoverability
of royalty prepayments based on estimated future production and
capitalizes these amounts accordingly. Royalty prepayments expected to be
recouped within one year are classified as a current asset. As mining
occurs on those leases, the royalty prepayments are included in the cost
of mined coal. Royalty prepayments estimated to be nonrecoverable are
expensed.
COAL SUPPLY AGREEMENTS - The Predecessor purchased the coal operations of
MAPCO Inc. effective August 1, 1996, in a business combination using the
purchase method of accounting. A portion of the acquisition costs was
allocated to coal supply agreements. This allocated cost is being
amortized on the basis of coal shipped in relation to total coal to be
supplied during the respective contract term. The amortization periods end
on various dates from September 2002 to December 2005. Accumulated
amortization for coal supply agreements was $22,139,000 and $18,584,000 at
December 31, 2000 and 1999, respectively.
RECLAMATION AND MINE CLOSING COSTS - Estimates of the cost of future mine
reclamation and closing procedures of currently active mines are recorded
on a present value basis. Those costs relate to sealing portals at
underground mines and to reclaiming the final pit and support acreage at
surface mines. Other costs common to both types of mining are related to
removing or covering refuse piles and settling ponds and dismantling
preparation plants and other facilities and roadway infrastructure.
Ongoing reclamation costs principally involve restoration of disturbed
land and are expensed as incurred during the mining process.
WORKERS' COMPENSATION AND PNEUMOCONIOSIS ("BLACK LUNG") BENEFITS - The
Partnership is self-insured for workers' compensation benefits, including
black lung benefits. The Partnership accrues
34
36
a workers' compensation liability for the estimated present value of
current and, in the case of black lung benefits, future workers'
compensation benefits based on actuarial valuations.
INCOME TAXES - No provision for income taxes related to the operations of
the Partnership is included in the accompanying consolidated financial
statements because, as a Partnership, it is not subject to federal or
state income tax and the tax effect of its activities accrues to the
unitholders. Net income for financial statement purposes may differ
significantly from taxable income reportable to unitholders as a result of
differences between the tax bases and financial reporting bases of assets
and liabilities and the taxable income allocation requirements under the
Partnership agreement.
The Predecessor is included in the combined U.S. income tax returns of
ARH. The Predecessor has provided for income taxes on its separate taxable
income and other tax attributes. Deferred income taxes are computed based
on recognition of future tax expense or benefits, measured by enacted tax
rates, that are attributable to taxable or deductible temporary
differences between financial statement and income tax reporting bases of
assets and liabilities.
REVENUE RECOGNITION - Revenues are recognized when coal is shipped from
the mine. Revenues not arising from coal sales, which primarily consist of
transloading fees, are included in operating revenues and are recognized
as services are performed.
NET INCOME PER UNIT - Basic net income per limited partner unit is
determined by dividing net income, after deducting the General Partners'
2% interest, by the weighted average number of outstanding Common Units
and Subordinated Units (a total of 15,405,311 units as of December 31,
2000 and 1999). Diluted net income per unit is based on the combined
weighted average number of Common Units, Subordinated Units and common
unit equivalents outstanding which primarily include restricted units
granted under the Long-Term Incentive Plan (Note 11).
SEGMENT REPORTING - The Partnership has no reportable segments due to its
operations consisting solely of producing and marketing coal. The
Partnership has disclosed major customer sales information (Note 16) and
geographic areas of operation (Note 17).
NEW ACCOUNTING STANDARDS - Effective January 1, 2001, the Partnership
adopted Statement of Financial Accounting Standards No. 133, "Accounting
for Derivative Instruments and Hedging Activities," which establishes
accounting and reporting standards for derivative instruments and for
hedging activities. It requires that all derivatives be recognized as
either assets or liabilities in the statement of financial position and be
measured at fair value. The Partnership currently has no identified
derivative instruments or hedging activities. Accordingly, this standard
had no material effect on the Partnership's consolidated financial
statements upon adoption.
During the fourth quarter 2000, the Partnership adopted Financial
Accounting Standards Board Emerging Issues Task Force Issue No. 00-10
"Accounting for Shipping and Handling Fees and Costs." Accordingly, the
Partnership reflects the cost of transporting coal to customers through
third party carriers as transportation expenses and the corresponding
reimbursement of these costs through customer billings as transportation
revenues in the consolidated and combined statements of income. These
amounts were previously offset. There was no cumulative effect on net
income and the prior periods' consolidated and combined statements of
income have been reclassified to comply with this presentation.
RECLASSIFICATIONS - Certain reclassifications have been made to the 1999
and 1998 combined and consolidated financial statements to conform to the
classifications used in 2000.
35
37
3. BUSINESS ACQUISITION
Effective January 23, 1998, the Predecessor acquired substantially all of
the assets and assumed certain liabilities, excluding working capital, of
an unrelated coal company's west Kentucky coal operations, now Hopkins
County Coal, LLC, for cash of approximately $7,310,000 and direct
acquisition costs of $821,000. The acquisition was accounted for using the
purchase method of accounting. Accordingly, the purchase price was
allocated to the assets acquired and liabilities assumed based on their
estimated fair values of $25,320,000 and $17,189,000, respectively. The
results of operations are included in the Partnership's consolidated and
combined financial statements from the acquisition date and are not
considered significant.
4. UNUSUAL ITEMS
The Unusual items for the years ended December 31, 2000 and 1998 are as
follows (in thousands):
YEAR ENDED
DECEMBER 31,
-------------------------------
2000 1998
------------ ------------
Gain on settlement of transloading facility dispute $ (12,141) $ --
Litigation matters 2,675 --
Temporary mine closings -- 5,211
------------ ------------
$ (9,466) $ 5,211
============ ============
The Partnership was involved in litigation with Seminole Electric
Cooperative, Inc. ("Seminole") with respect to Seminole's termination of a
long-term contract for the transloading of coal from rail to barge through
the Partnership's 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 and impairment
charges relating to certain transloading facility assets.
The Partnership recorded an expense of $2,675,000 related to litigation
matters settled and contingencies associated with other litigation
matters.
In response to market conditions, one of the Predecessor's operating mines
ceased operations and terminated all of its workforce in September 1998.
Management planned to maintain the mine in an indefinite idle status
pending improvement in market conditions. Shortly after the mine closure,
management executed a long-term coal supply contract for the mine and the
mine resumed production in late 1998. During the idle status period, the
mine incurred a net loss of approximately $5,211,000 consisting of
estimated amounts for increased workers' compensation claims of $1,200,000
and severance payments consistent with the federal Worker Adjustment and
Retraining Notification, or "WARN" Act, of $1,200,000 as well as the costs
associated with maintaining the idled mine of $2,811,000.
36
38
5. INVENTORIES
Inventories consist of the following at December 31, (in thousands):
2000 1999
---------- ----------
Coal $ 5,140 $ 15,180
Supplies 5,702 5,950
---------- ----------
$ 10,842 $ 21,130
========== ==========
6. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consists of the following at December 31,
(in thousands):
2000 1999
--------- ---------
Mining equipment and processing facilities $ 267,287 $ 236,252
Land and mineral rights 17,686 17,282
Buildings, office equipment and improvements 24,224 17,780
Construction in progress 11,248 6,907
--------- ---------
320,445 278,221
Less accumulated depreciation, depletion and amortization (135,782) (102,709)
--------- ---------
$ 184,663 $ 175,512
========= =========
7. LONG-TERM DEBT
Long-term debt consists of the following at December 31, (in thousands):
2000 1999
--------- ---------
Senior notes $ 180,000 $ 180,000
Term loan 50,000 50,000
--------- ---------
230,000 230,000
Less current maturities (3,750) --
--------- ---------
$ 226,250 $ 230,000
========= =========
The Special GP issued and the Intermediate Partnership assumed obligations
with respect to a $180 million principal amount of senior notes pursuant
to a Note Purchase Agreement with a group of institutional investors in a
private placement offering. The senior notes are payable in ten annual
installments of $18 million beginning in August 2005 and bear interest at
8.31%, payable semiannually.
The Special GP also entered into and the Intermediate Partnership assumed
obligations, under a $100 million credit facility consisting of three
tranches, including a $50 million term loan facility, a $25 million
working capital facility and a $25 million revolving credit facility. In
connection with the closing of the IPO, the Special GP borrowed $50
million under the term loan facility and the Special GP and Intermediate
Partnership purchased $50 million of U.S. Treasury Notes, which secure the
term loan. The U.S. Treasury Notes may be liquidated for the sole purpose
of funding capital expenditures. Through December 31, 2000, the
Partnership had liquidated approximately $15.5 million of U.S. Treasury
Notes to fund various qualifying capital expenditures.
37
39
The working capital facility can be used to provide working capital and,
if necessary, to fund distributions to unitholders. The revolving credit
facility can be used for general business purposes, including capital
expenditures and acquisitions. The rate of interest charged is adjusted
quarterly based on a pricing grid, which is a function of the ratio of the
Partnership's debt to cash flow. The credit facility provides the
Partnership the option of borrowing at either (1) the London Interbank
Offered Rate ("LIBOR") or (2) the "Base Rate" which is equal to the
greater of (a) the Chase Prime Rate, or (b) the Federal Funds Rate plus
1/2 of 1%, plus, in either option, an applicable margin. The weighted
average interest rates on the term loan facility at December 31, 2000 and
1999 were 7.77% and 7.07%, respectively. In accordance with the pricing
grid, a commitment fee ranging from 0.375% to 0.500% per annum is paid
quarterly on the unused portion of the working capital and revolving
credit facilities. There were no amounts outstanding under the
Partnership's working capital facility or revolving credit facility as of
December 31, 2000 and 1999. The credit facility expires in August 2004.
The senior notes and credit facility are guaranteed by Alliance Coal, LLC
and all of its subsidiaries. In addition, the credit facility is further
secured by a pledge of treasury securities, which upon written notice, are
released for purposes of financing qualifying capital expenditures of the
Intermediate Partnership or its subsidiaries. The senior notes and credit
facility contain various restrictive and affirmative covenants, including
the amount of distributions by the Intermediate Partnership and the
incurrence of other debt. The Partnership was in compliance with the
covenants of both the credit facility and senior notes at December 31,
2000.
The Partnership incurred debt issuance costs aggregating approximately
$3,517,000, which have been deferred and are being amortized as a
component of interest expense over the term of the notes.
Aggregate maturities of long-term debt are as follows (in thousands):
YEAR ENDING
DECEMBER 31,
2001 $ 3,750
2002 15,000
2003 16,250
2004 15,000
2005 18,000
Thereafter 162,000
--------
$230,000
========
8. DISTRIBUTIONS OF AVAILABLE CASH
The Partnership will distribute 100% of its available cash within 45 days
after the end of each quarter to unitholders of record and to the General
Partners. Available cash is generally defined as all cash and cash
equivalents of the Partnership on hand at the end of each quarter less
reserves established by the Managing GP in its reasonable discretion for
future cash requirements. These reserves are retained to provide for the
conduct of the Partnership's business, the payment of debt principal and
interest and to provide funds for future distributions.
Distributions of available cash to the holder of Subordinated Units are
subject to the prior rights of holders of Common Units to receive the
minimum quarterly distribution ("MQD") for each quarter during the
subordination period and to receive any arrearages in the distribution of
the MQD on the Common Units for the prior quarters during the
subordination period. The MQD is $0.50 per unit ($2.00 per unit on an
annual basis). Upon expiration of the subordination period, which will
generally not occur before September 30, 2004, all Subordinated Units will
be converted on a one-for-one basis into Common Units and will then
participate, on a pro rata basis with all other Common Units in future
38
40
distributions of available cash. However, under certain circumstances, up
to 50% of the Subordinated Units may convert into Common Units on or after
September 30, 2003. Common Units will not accrue arrearages with respect
to distributions for any quarter after the subordination period and
Subordinated Units will not accrue any arrearages with respect to
distributions for any quarter.
If quarterly distributions of available cash exceed the MQD or the target
distributions levels, the General Partners will receive distributions
based on specified increasing percentages of the available cash that
exceeds the MQD or target distribution levels. The target distribution
levels are based on the amounts of available cash from the Partnership's
operating surplus distributed for a given quarter that exceed
distributions for the MQD and common unit arrearages, if any.
For the 42-day period from the Partnership's commencement of operations
(on August 20, 1999) through September 30, 1999, the Partnership paid a
pro-rata MQD distribution of $0.23 per unit on its outstanding Common and
Subordinated Units. For each of the quarters ended December 31, 1999
through September 30, 2000, quarterly distributions of $0.50 per unit were
paid to the common and subordinated unitholders. On January 24, 2001, the
Partnership declared a MQD, for the period from October 1, 2000 to
December 31, 2000, of $0.50 per unit, totaling approximately $7,703,000 on
its outstanding Common and Subordinated Units, payable on February 14,
2001 to all unitholders of record on January 31, 2001.
9. INCOME TAXES
The Predecessor recognized a deferred tax asset for the future tax
benefits attributable to deductible temporary differences and other credit
carryforwards, including alternative minimum tax credit carryforwards.
Realization of these future tax benefits was dependent on the
Predecessor's ability to generate future taxable income, which was not
assured. Management of the Predecessor believed that future taxable income
would be sufficient to recognize only a portion of the tax benefits and
had established a valuation allowance.
Concurrent with the closing of the IPO on August 20, 1999, and in
connection with the Contribution Agreement, ARH retained the current and
deferred income taxes of the Predecessor.
Income before income taxes is derived from domestic operations.
Significant components of income taxes are as follows (in thousands):
FOR THE
PERIOD FROM
JANUARY 1, 1999 YEAR ENDED
TO DECEMBER 31,
AUGUST 19, 1999 1998
--------------- ------------
Current:
Federal $ 3,376 $ 4,815
State 483 801
------------ ------------
3,859 5,616
Deferred:
Federal 595 (1,531)
State 44 (219)
------------ ------------
639 (1,750)
------------ ------------
Income tax expense $ 4,498 $ 3,866
============ ============
39
41
A reconciliation of the statutory U.S. federal income tax rate and the
Predecessor's effective income tax rate is as follows:
FOR THE
PERIOD FROM
JANUARY 1, 1999 YEAR ENDED
TO DECEMBER 31,
AUGUST 19, 1999 1998
--------------- ------------
Statutory rate 35% 35%
Increase (decrease) resulting from:
Excess of tax over book depletion (21) (29)
Alternative minimum tax credit
carryforwards 3 6
State income taxes, net of federal
benefit 3 4
Valuation allowance 10 14
Other 1 1
--------- ---------
Effective income tax rate 31% 31%
========= =========
10. NET INCOME PER LIMITED PARTNER UNIT
A reconciliation of net income and weighted average units used in
computing basic and diluted earnings per unit is as follows (in thousands,
except per unit data):
FROM
COMMENCEMENT
YEAR OF OPERATIONS
ENDED (ON AUGUST 20, 1999)
DECEMBER 31, TO
2000 DECEMBER 31, 1999
------------ -----------------
Net income per limited partner unit $ 15,269 $ 6,147
Weighted average limited partner units - basic 15,405 15,405
Basic net income per limited partner unit $ 0.99 $ 0.40
============ ============
Weighted average limited partner units - basic 15,405 15,405
Units contingently issuable:
Restricted units for Long-Term Incentive Plan 142 --
Directors' compensation units deferred 4 --
------------ ------------
Weighted average limited partner units,
assuming dilutive effect of restricted units 15,551 15,405
------------ ------------
Diluted net income per limited partner unit $ 0.98 $ 0.40
============ ============
40
42
11. EMPLOYEE BENEFIT PLANS
LONG-TERM INCENTIVE PLAN - Effective January 1, 2000, the Managing GP
adopted the Long-Term Incentive Plan (the "LTIP") for certain employees
and directors of the Managing GP and its affiliates who perform services
for the Partnership. Annual grant levels and vesting provisions for
designated participants are recommended by the President and Chief
Executive Officer of the Managing GP, subject to the review and approval
of the Compensation Committee. Grants are made either of restricted units,
which are "phantom" units that entitle the grantee to receive a Common
Unit or an equivalent amount of cash upon the vesting of a phantom unit,
or options to purchase Common Units. Common Units to be delivered upon the
vesting of restricted units will be acquired by the Managing GP in the
open market at a price equal to the then prevailing price, or directly
from ARH or any other third party. The Partnership agreement provides that
the Managing GP be reimbursed for all costs incurred in acquiring these
Common Units or in paying cash in lieu of Common Units upon vesting of the
restricted units. The aggregate number of units reserved for issuance
under the LTIP is 600,000. Effective January 1, 2000, the Compensation
Committee approved initial grants of 142,100 restricted units, which vest
at the end of the subordination period, which will generally not end
before September 30, 2004. During 2000, the Managing GP billed the
Partnership approximately $538,000 attributable to the LTIP. The
Partnership has recorded this amount as compensation expense. Effective
January 1, 2001, the Compensation Committee approved additional grants of
131,490 restricted units, which also vest at the end of the subordination
period.
DEFINED CONTRIBUTION PLANS - The Partnership's employees currently
participate in a defined contribution profit sharing and savings plan
sponsored by the Partnership, which is the same plan sponsored by the
Predecessor. This plan covers substantially all full-time employees. Plan
participants may elect to make voluntary contributions to this plan up to
a specified amount of their compensation. The Partnership makes
contributions based on matching 75% of employee contributions up to 3% of
their annual compensation as well as an additional nonmatching
contribution of 3/4 of 1% of their compensation. Additionally, the
Partnership contributes a defined percentage of eligible earnings for
certain employees not covered by the defined benefit plan described below.
The Partnership's expense for its plan was approximately $1,590,000 for
the year ended December 31, 2000 and $715,000 for the period from August
20, 1999 to December 31, 1999. The Predecessor's expense for the plan was
$1,226,000 for the period from January 1, 1999 to August 19, 1999, and
$1,944,000 for the year ended December 31, 1998.
DEFINED BENEFIT PLANS - Certain employees at the mining operations
participate in a defined benefit plan sponsored by the Partnership, which
is the same plan sponsored by the Predecessor. The benefit formula is a
fixed dollar unit based on years of service.
41
43
The following sets forth changes in benefit obligations and plan assets
for the years ended December 31, 2000 and 1999 and the funded status of
the plans reconciled with amounts reported in the Partnership's
consolidated and the Predecessor's combined financial statements at
December 31, 2000 and 1999, respectively. The Partnership and Predecessor
periods for 1999 have been combined. Since the Partnership maintained the
historical basis of the Predecessor's net assets, management believes that
the combined Partnership and Predecessor amounts for 1999 are comparable
with 2000 (dollars in thousands):
2000 1999
------------ ------------
CHANGE IN BENEFIT OBLIGATIONS:
Benefit obligations at beginning of year $ 7,774 $ 6,742
Service cost 1,971 2,107
Interest cost 596 452
Actuarial (gain) loss (136) (1,435)
Benefits paid (70) (92)
------------ ------------
Benefit obligation at end of year 10,135 7,774
------------ ------------
CHANGE IN PLAN ASSETS:
Fair value of plan assets at beginning of year 8,265 2,911
Employer contribution 1,100 4,736
Actual return on plan assets 205 710
Benefits paid (70) (92)
------------ ------------
Fair value of plan assets at end of year 9,500 8,265
------------ ------------
Funded status (635) 491
Unrecognized prior service cost 284 332
Unrecognized actuarial (gain) loss (828) (1,273)
------------ ------------
Net amount recognized $ (1,179) $ (450)
============ ============
WEIGHTED-AVERAGE ASSUMPTIONS AS OF DECEMBER 31:
Discount rate 7.50% 7.75%
Expected return on plan assets 9.00% 9.00%
COMPONENTS OF NET PERIODIC BENEFIT COST:
Service cost $ 1,971 $ 2,107
Interest cost 596 452
Expected return on plan assets (737) (413)
Prior service cost 48 48
Net gain (49) --
------------ ------------
Net periodic benefit cost $ 1,829 $ 2,194
============ ============
Effect on minimum pension liability $ -- $ (459)
============ ============
12. RECLAMATION AND MINE CLOSING COSTS
The majority of the Partnership's operations are governed by various state
statutes and the federal Surface Mining Control and Reclamation Act of
1977, which establish reclamation and mine closing standards. These
regulations, among other requirements, require restoration of property in
accordance with specified standards and an approved reclamation plan. The
Partnership has estimated the costs and
42
44
timing of future reclamation and mine closing costs and recorded those
estimates on a present value basis using a 6% discount rate.
Discounting resulted in reducing the accrual for reclamation and mine
closing costs by $10,420,000 and $5,489,000 at December 31, 2000 and 1999,
respectively. Estimated payments of reclamation and mine closing costs as
of December 31, 2000 are as follows (in thousands):
2001 $ 1,078
2002 1,191
2003 1,594
2004 2,147
2005 2,511
Thereafter 17,917
----------
Aggregate undiscounted reclamation and mine closing 26,438
Effect of discounting 10,420
----------
Total reclamation and mine closing costs 16,018
Less current portion 1,078
----------
Reclamation and mine closing costs $ 14,940
==========
The following table presents the activity affecting the reclamation and
mine closing liability (in thousands):
PARTNERSHIP PREDECESSOR
-------------------------------------- -----------------------------------
FROM
COMMENCEMENT FOR THE
YEAR OF OPERATIONS PERIOD FROM YEAR
ENDED (ON AUGUST 20, 1999) JANUARY 1,1999 ENDED
DECEMBER 31, TO TO DECEMBER 31,
2000 DECEMBER 31, 1999 AUGUST 19, 1999 1998
------------- ------------------- --------------- -------------
Beginning balance $ 14,796 $ 13,856 $ 13,800 $ 5,439
Accrual 1,074 348 457 705
Payments (764) (394) (401) (1,544)
Allocation of liability associated
with acquisition and mine
development 912 986 -- 9,200
------------- ------------- ------------- -------------
Ending balance $ 16,018 $ 14,796 $ 13,856 $ 13,800
============= ============= ============= =============
13. PNEUMOCONIOSIS ("BLACK LUNG") BENEFITS
Certain mine operating entities of the Partnership are liable under state
statutes and the federal Coal Mine Health and Safety Act of 1969, as
amended, to pay black lung benefits to eligible employees and former
employees and their dependents. These subsidiaries provide self-insurance
accruals, determined by independent actuaries, at the present value of the
actuarially computed present and future liabilities for such benefits. The
actuarial studies utilize a 6% discount rate and various assumptions as to
the frequency of future claims, inflation, employee turnover and life
expectancies.
The cost or reduction of cost due to change in the estimate of black lung
benefits charged (credited) to operations for the year ended December 31,
2000, the period from the Partnership's commencement of operations on
August 20, 1999 to December 31, 1999 and for the Predecessor period from
January 1, 1999
43
45
to August 19, 1999, and the year ended December 31, 1998 was $123,000,
$(1,028,000), $726,000, and $1,139,000, respectively.
The U.S. Department of Labor has issued revised regulations that could
alter the claims process for the federal black lung benefit recipients.
The revised regulations are expected to result in an increase in the
incidence and recovery of black lung claims. Both the coal and insurance
industries are currently challenging through litigation certain provisions
of the revised regulations. The impact of the revised regulations on the
Partnership's liability for future black lung claims cannot be determined
at this time.
14. RELATED PARTY TRANSACTIONS
The Partnership Agreement provides that the Managing GP and its affiliates
be reimbursed for all direct and indirect expenses it incurs or payments
it makes on behalf of the Partnership, including management's salaries and
related benefits, accounting, budget and planning, treasury, public
relations, land administration, environmental and permitting management,
payroll and benefits management, disability and workers' compensation
management, legal and information technology services. The Managing GP may
determine in its sole discretion the expenses that are allocable to the
Partnership. Total costs reimbursed to the Managing GP and its affiliates
by the Partnership were approximately $3,899,000 and $1,283,000 for the
year ended December 31, 2000 and the period from the Partnership's
commencement of operations on August 20, 1999 to December 31, 1999,
respectively.
ARH allocated certain direct and indirect general and administrative
expenses to the Predecessor. These allocations were primarily based on the
relative size of the direct mining operating costs incurred by each of the
mine locations of the Predecessor. The allocations of general and
administrative expenses to the Predecessor were approximately $2,982,000
and $2,595,000 for the period from January 1, 1999 to August 19, 1999 and
for the year ended December 31, 1998, respectively. Management is of the
opinion that the allocations used are reasonable and appropriate.
During November 1999, the Managing GP was authorized by its Board of
Directors to purchase up to 1.0 million Common Units of the Partnership.
As of December 31, 2000 and 1999 the Managing GP had purchased 164,000
Common Units in the open market at prevailing market prices.
In September 2000, the Special GP acquired coal reserves and the right to
acquire additional coal reserves that are (a) contiguous to the Webster
County Coal, LLC ("WCC") mining complex ("Providence No. 3 Reserves") and
(b) contiguous to the Hopkins County Coal, LLC ("HCC") mining complex
("Elk Creek Reserves"). Such coal reserves and the rights to acquire
additional coal reserves were transferred to SGP Land, LLC ("SGP Land"), a
newly formed wholly-owned subsidiary of the Special GP.
Concurrent with such coal reserve acquisitions, the Special GP, through
affiliates, was negotiating for the purchase of (a) the capital stock of
Roberts Bros. Coal Co., Inc., Warrior Coal Mining Company, and Warrior
Coal Corporation, and (b) the related coal reserves ("Warrior Reserves")
owned by Cardinal Trust, LLC (collectively the "Warrior Group"). The
Warrior Group's operating assets are located adjacent to the Providence
No. 3 Reserves and were purchased by a newly formed affiliate of the
Special GP, Warrior Coal, LLC ("Warrior Coal"). SGP Land acquired the
Warrior Reserves, which are located between the Providence No. 3 Reserves
and HCC. The acquisition of the Warrior Group closed 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
44
46
royalty obligation of $2.7 million, payable in advance, from 2000 to 2013
or until $37.8 million of cumulative annual minimum and/or earned royalty
payments have been paid. WCC paid the first annual minimum royalty of $2.7
million in 2000. Under the terms of the HCC option to lease and sublease,
HCC paid an option fee of $645,000 in 2000. The anticipated annual minimum
royalty obligation is $684,000 payable in advance, from 2001 to 2009.
The Partnership and ARH Warrior Holdings, Inc. ("ARH Warrior Holdings"),
the parent company of Warrior Coal, have entered into an Amended and
Restated Put and Call Option Agreement ("Put/Call Agreement") with the
Partnership. Under the terms of the Put/Call Agreement, ARH Warrior
Holdings can require the Partnership to purchase Warrior Coal from ARH
Warrior Holdings during the period from January 2, 2003 to January 11,
2003, with a put option price of the sum of $10 million and interest on
the $10 million at 12 percent, compounded annually. The Partnership can
also require ARH Warrior Holdings to sell Warrior Coal to the Partnership
during the period from April 12, 2003 to December 31, 2006, with a call
option price of the sum of (a) $10 million, (b) interest on the $10
million at 12 percent, compounded annually and (c) 25 percent of the
interest determined in (b).
Separately, on December 29, 2000, the Partnership entered into a
noncancelable operating lease arrangement with the Special GP for a
"build-to-suit" coal preparation plant and ancillary facilities at the
Gibson County Coal, LLC mining complex that was constructed and is
currently owned by the Special GP. This lease arrangement qualified for
sale-leaseback accounting treatment, and consequently, the Partnership has
removed the corresponding asset and liability associated with the coal
preparation plant from its consolidated balance sheet. Based on the terms
of the lease, the Partnership will make monthly payments of approximately
$216,000 for 121 months. Lease expense incurred for the year ended
December 31, 2000 was approximately $14,000.
15. COMMITMENTS AND CONTINGENCIES
COMMITMENTS - The Partnership leases buildings and equipment under
operating lease agreements which provide for the payment of both minimum
and contingent rentals. The Partnership also has a noncancelable lease
with the Special GP (Note 14). Future minimum lease payments under
operating leases are as follows (in thousands):
AFFILIATE OTHERS TOTAL
--------- --------- ---------
Year ending December 31,
2001 $ 2,595 $ 452 $ 3,047
2002 2,595 408 3,003
2003 2,595 274 2,869
2004 2,595 284 2,879
2005 2,595 284 2,879
Thereafter 13,190 780 13,970
--------- --------- ---------
$ 26,165 $ 2,482 $ 28,647
========= ========= =========
Lease expense under all operating leases was $1,409,000, $801,000,
$496,000, and $1,169,000 for the year ended December 31, 2000, the period
from the Partnership's commencement of operations on August 20, 1999 to
December 31, 1999 and the Predecessor period from January 1, 1999 to
August 19, 1999, and the year ended December 31, 1998, respectively.
CONTRACTUAL COMMITMENTS - In connection with the expansion of an existing
mine into adjacent coal reserves, the Partnership has entered into
contractual commitments for mine development of approximately $22.5
million at December 31, 2000.
GENERAL LITIGATION - The Partnership is involved in various lawsuits,
claims and regulatory proceedings, including those conducted by the Mine
Safety and Health Administration, incidental to its business. The
Partnership provides for costs related to litigation and regulatory
proceedings, including civil fines
45
47
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 related to litigation matters settled and
contingencies associated with other litigation matters, which is reflected
in "Unusual items" in the accompanying consolidated and combined
statements of income. In the opinion of management, the outcome of such
matters to the extent not previously provided for or covered under
insurance, will not have a material adverse effect on the Partnership's
business, financial position or results of operations, although management
cannot give any assurance to that effect.
16. CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS
The Partnership has significant long-term coal supply agreements, some of
which contain price adjustment provisions designed to reflect changes in
market conditions, labor and other production costs and, when the coal is
sold other than FOB the mine, changes in railroad and/or barge freight
rates. Total revenues to major customers, including transportation
revenues (Note 2), which exceed ten percent of total revenues are as
follows (in thousands):
PARTNERSHIP PREDECESSOR
-------------------------------------- ---------------------------------
FROM
COMMENCEMENT FOR THE
YEAR OF OPERATIONS PERIOD FROM YEAR
ENDED (ON AUGUST 20, 1999) JANUARY 1, 1999 ENDED
DECEMBER 31, TO TO DECEMBER 31,
2000 DECEMBER 31, 1999 AUGUST 19, 1999 1998
------------- ------------------- ---------------- -------------
Customer A $ 67,234 $ 23,104 $ 38,875 $ 62,642
Customer B 61,007 26,993 40,752 57,233
Customer C 58,498 16,090 31,328 74,076
Customer D 38,713 11,926 19,582 --
Trade accounts receivable from these customers totaled approximately $18.1
million at December 31, 2000. The Partnership's bad debt experience has
historically been insignificant. Based on current evaluations, Partnership
management believes that no allowance is required to absorb potential
uncollectible balances. However, changes in the financial conditions of
its customers could result in a material change to this estimate in future
periods. The coal supply agreements with customers A, B, C and D expire in
2006, 2001, 2010 and 2006, respectively.
46
48
17. GEOGRAPHIC INFORMATION
Included in the consolidated and combined financial statements are the
following revenues and long-lived assets relating to geographic locations
(in thousands):
PARTNERSHIP PREDECESSOR
------------------------------------ ----------------------------------
FROM
COMMENCEMENT FOR THE
YEAR OF OPERATIONS PERIOD FROM YEAR
ENDED (ON AUGUST 20, 1999) JANUARY 1, 1999 ENDED
DECEMBER 31, TO TO DECEMBER 31,
2000 DECEMBER 31, 1999 AUGUST 19, 1999 1998
------------ ------------------- --------------- ------------
Revenues:
United States $ 363,469 $ 134,125 $ 221,339 $ 348,055
Other foreign countries -- -- 10,494 55,246
------------ ------------ ------------ ------------
$ 363,469 $ 134,125 $ 231,833 $ 403,301
============ ============ ============ ============
Long-lived assets:
United States $ 210,996 $ 203,697 $ 200,057 $ 204,078
Other foreign countries -- -- -- --
------------ ------------ ------------ ------------
$ 210,996 $ 203,697 $ 200,057 $ 204,078
============ ============ ============ ============
18. SUPPLEMENTAL CASH FLOW INFORMATION
The Partnership's and Predecessor's supplemental disclosure of cash flow
information and other non-cash investing and financing activities were as
follows (in thousands):
PARTNERSHIP PREDECESSOR
------------------------------------ ------------------------------
FROM
COMMENCEMENT FOR THE
YEAR OF OPERATIONS PERIOD FROM YEAR
ENDED (ON AUGUST 20, 1999) JANUARY 1, 1999 ENDED
DECEMBER 31, TO TO DECEMBER 31,
2000 DECEMBER 31, 1999 AUGUST 19, 1999 1998
----------- ------------------- --------------- ------------
Cash paid for:
Interest $ 19,043 $ 1,173 $ -- $ --
Income taxes paid through
Parent (Note 9) -- -- 3,504 3,135
Noncash investing and financing activities:
Debt transferred from Special GP -- 230,000 -- --
Marketable securities transferred
from Special GP -- 15,486 -- --
19. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
On August 20, 1999, the Partnership completed its IPO in which the
Partnership became the successor to the business of the Predecessor.
Accordingly, no recognition has been given to income taxes in the
financial statements of the Partnership as income taxes will be borne by
the partners and not the Partnership. Additionally, interest expense
associated with the debt incurred concurrent with the closing of the IPO
is applicable only to the Partnership period. Accordingly, the quarterly
operating results prior to August 20, 1999 are not necessarily comparable
to subsequent periods.
47
49
A summary of the quarterly operating results for the Partnership and
Predecessor is as follows (in thousands, except unit and per unit data):
PARTNERSHIP
QUARTER ENDED
------------------------------------------------------------------------
MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31,
2000 2000 2000(1) 2000
------------ ------------ ------------ ------------
Revenues $ 89,420 $ 86,652 $ 96,459 $ 90,938
Operating income 6,191 5,912 15,669 3,096
Net income (loss) 2,366 2,098 11,560 (443)
Basic net income (loss) per limited Partner unit $ 0.15 $ 0.13 $ 0.74 $ (0.03)
Diluted net income (loss) per limited
Partner unit $ 0.15 $ 0.13 $ 0.73 $ (0.03)
Weighted average number of units
outstanding - basic 15,405,311 15,405,311 15,405,311 15,405,311
Weighted average number of units
outstanding - diluted 15,550,489 15,550,845 15,552,017 15,553,372
PREDECESSOR PARTNERSHIP
------------------------------------------------- ----------------------------------------
FROM
COMMENCEMENT
QUARTER ENDED JULY 1, 1999 OF OPERATIONS
----------------------------- TO (ON AUGUST 20, 1999)
MARCH 31, JUNE 30, AUGUST 19, TO QUARTER ENDED
1999 1999 1999 SEPTEMBER 30, 1999 DECEMBER 31, 1999
------------- ------------- ------------- ------------------ -----------------
Revenues $ 87,876 $ 93,395 $ 50,562 $ 45,758 $ 88,367
Operating income 4,273 6,995 3,004 5,019 6,499
Net income 2,969 4,934 2,302 3,509 2,763
Basic and diluted net
income per unit -- -- -- $ 0.22 $ 0.18
Weighted average number
of units outstanding - basic
and diluted -- -- -- 15,405,311 15,405,311
(1) The Partnership recorded income of $12.2 million, which is net of
litigation expenses and costs relating to the impairment of certain
transloading facility assets. Additionally, the Partnership recorded an
expense of $2.7 million related to litigation matters settled and
contingencies associated with other litigation matters. The net effect of
these unusual items for the quarter was $9.5 million (Note 4).
Operating income in the above table represents income from operations before
interest expense.
******
48
50
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE MANAGING GENERAL PARTNER
As is commonly the case with publicly-traded limited partnerships, we are
managed and operated by our Managing GP. The following table shows information
for the directors and executive officers of the Managing GP. Executive officers
and directors are elected for one-year terms.
NAME AGE POSITION WITH OUR MANAGING GENERAL PARTNER
- --------------------- ---- -------------------------------------------
Joseph W. Craft III 50 President, Chief Executive Officer and Director
Robert G. Sachse 52 Executive Vice President and Director
Thomas L. Pearson 47 Senior Vice President - Law and Administration,
General Counsel and Secretary
Michael L. Greenwood 45 Senior Vice President - Chief Financial Officer
and Treasurer
Charles R. Wesley 46 Senior Vice President - Operations
Gary J. Rathburn 50 Senior Vice President - Marketing
John J. MacWilliams 45 Director
Preston R. Miller, Jr. 52 Director
John P. Neafsey 61 Director
John H. Robinson 50 Director
Paul R. Tregurtha 65 Director
Joseph W. Craft III has worked for us since 1980. Prior to the formation of
ARH, Mr. Craft was a Senior Vice President of MAPCO Inc., serving as General
Counsel and Chief Financial Officer, and since 1986 as President of MAPCO Coal
Inc. Mr. Craft has held his current positions since August 1996. Prior to
working with us, Mr. Craft was an attorney at Falcon Coal Corporation and
Diamond Shamrock Coal Corporation. Mr. Craft has held numerous industry
leadership positions, including past Chairman of the National Coal Council, a
Board and Executive Committee member of the National Mining Association, and a
Director of the Center for Energy and Economic Development. Mr. Craft holds a
Bachelor of Science degree in Accounting and a Juris Doctor degree from the
University of Kentucky. Mr. Craft also is a graduate of the Senior Executive
Program of the Alfred P. Sloan School of Management at Massachusetts Institute
of Technology.
Robert G. Sachse joined us as Executive Vice President and Vice Chairman in
August 2000. Prior to working with us, Mr. Sachse was Executive Vice President
and Chief Operating Officer of MAPCO Inc. from 1996 to 1998 until MAPCO Inc.
merged with The Williams Companies, Inc. Mr. Sachse held various positions with
MAPCO Coal Inc. from 1982 to 1991, and was promoted to President of MAPCO
Natural Gas
49
51
Liquids in 1992. Mr. Sachse holds a Bachelor of Science degree from Trinity
University and a Juris Doctor degree from the University of Tulsa.
Thomas L. Pearson has worked for us since 1989. Prior to the formation of
ARH, Mr. Pearson was Assistant General Counsel of MAPCO Inc. and served as
General Counsel and Secretary of MAPCO Coal Inc. from 1989-1996. Mr. Pearson has
held his current positions since September 1996. Prior to working with us, Mr.
Pearson was General Counsel and Secretary of McLouth Steel Products Corporation,
one of the largest integrated steel producers in the United States; and
Corporate Counsel of Midland-Ross Corporation, a multi-national company with
numerous international joint venture companies and projects. Previously, he was
an attorney with the Arter & Hadden law firm in Cleveland, Ohio. Mr. Pearson is
or has been active in a number of educational, charitable and business
organizations, including the following: Vice Chairman, Legal Affairs Committee,
National Mining Association; Member, Dean's Committee, The University of Iowa
College of Law; and Contributions Committee, Greater Cleveland United Way. Mr.
Pearson holds a Bachelor of Arts degree in History and Communications from
DePauw University and a Juris Doctor degree from The University of Iowa.
Michael L. Greenwood has worked for us since 1986. Prior to the formation of
ARH, Mr. Greenwood served in various financial management capacities, including
General Manager - Finance of MAPCO Coal Inc., General Manager of Planning and
Financial Analysis, and Manager - Mergers and Acquisitions of MAPCO Inc. Mr.
Greenwood has held his current positions since September 1996. Prior to working
for us, Mr. Greenwood held financial planning and business development
management positions in the energy industry with Davis Investments, The Williams
Companies, Inc. and Penn Central Corporation. Mr. Greenwood holds a Bachelor of
Science degree in Business Administration from Oklahoma State University and a
Master of Business Administration degree from the University of Tulsa. Mr.
Greenwood has also completed executive programs at Northwestern University,
Southern Methodist University and The Center for Creative Leadership.
Charles R. Wesley has worked for us since 1974. Mr. Wesley joined Webster
County Coal Corporation in 1974 as an engineering co-op student and worked
through the ranks to become General Superintendent. In 1992 he became Vice
President of Operations for Mettiki Coal Corporation. He has held his current
position since September 1996. Mr. Wesley has served the industry as past
President of the West Kentucky Mining Institute and National Mine Rescue
Association Post 11. He also served on the board of the Kentucky Mining
Institute. Mr. Wesley holds a Bachelor of Science degree in Mining Engineering
from the University of Kentucky.
Gary J. Rathburn has worked for us since 1980 when he joined MAPCO Coal Inc.
as Manager of Brokerage Coals. Since 1980, Mr. Rathburn has managed all phases
of the marketing group involving transportation and distribution, international
sales and the brokering of coal. He has held his current position since
September 1996. Prior to working for us, Mr. Rathburn was employed by Eastern
Associated Coal Corporation in its International Sales and Brokerage groups. Mr.
Rathburn has been active in industry groups such as the Maryland Coal
Association, The North Carolina Coal Institute and the National Mining
Association. Mr. Rathburn was a Director of The National Coal Association and
Chairman of the Coal Exporters Association for several years. Mr. Rathburn holds
a Bachelor of Arts degree in Political Science from the University of Pittsburgh
and has participated in industry-related programs at the World Trade Institute,
Princeton University and the Colorado School of Mines.
John J. MacWilliams has served as a Director since June 1996. Mr.
MacWilliams has been a General Partner of The Beacon Group, LP (The Beacon
Group) since May 1993. Prior to the formation of The Beacon Group, Mr.
MacWilliams was an Executive Director of Goldman Sachs International in London,
where he was responsible for heading the firm's International Structured
Financing Group. Prior to moving to London, Mr. MacWilliams was a Vice President
in the Investment Banking Division of Goldman, Sachs & Co. in New York. Prior to
joining Goldman Sachs, Mr. MacWilliams was an attorney at Davis Polk & Wardwell
in New York, where he worked on international bank financings, partnership
financings, and mergers and
50
52
acquisitions. Mr. MacWilliams is also a director of Campagnie Generale
Geophysique. Mr. MacWilliams holds a Bachelor of Arts degree from Stanford
University, Master of Science degree from Massachusetts Institute of Technology,
and a Juris Doctor degree from Harvard Law School.
Preston R. Miller, Jr. has served as a Director since June 1996. Mr. Miller
has been a General Partner of The Beacon Group since June 1993. Prior to the
formation of The Beacon Group, Mr. Miller was employed for fourteen years by
Goldman, Sachs & Co. in New York City, where he was a Vice President in the
Structured Finance Group and had global responsibility for the coverage of the
independent power industry, asset-backed power generation, and oil and gas
financings. Mr. Miller also has a background in credit analysis, and was head of
the revenue bond rating group at Standard & Poor's Corp. prior to joining
Goldman Sachs. Mr. Miller holds a Bachelor of Arts degree from Yale University
and a Master of Public Administration degree from Harvard University.
John P. Neafsey has served as Chairman since June 1996. Mr. Neafsey has
served as President of JN Associates, an investment consulting firm, since
January 1994. Mr. Neafsey served as President and CEO of Greenwich Capital
Markets from 1990 to 1993 and Director since its founding in 1983. In addition,
Mr. Neafsey held numerous other positions during his twenty-three years at The
Sun Company, including: Executive Vice President responsible for Canadian
operations, Sun Coal Company and Helios Capital Corporation; Chief Financial
Officer; and other executive management positions with numerous subsidiary
companies. Mr. Neafsey is or has been active in a number of educational,
charitable and business organizations, including the following: Director, The
West Pharmaceutical Services Company, Longhorn Partners Pipeline Inc. and the
Provident Mutual Life Insurance Company; Trustee, Cornell University; and
Overseer of Cornell-Weill Medical Center. Mr. Neafsey holds Bachelor and Master
of Science degrees in Engineering and a Master of Business Administration degree
from Cornell University.
John H. Robinson has served as a Director since December 1999. In April
2000, Mr. Robinson joined Amey, plc, a British support services business, as
Executive Director of its newly-formed Technology Services Division. Mr.
Robinson previously served as Vice Chairman of Black & Veatch, a global
engineer-constructor firm, from January 1997 through March 2000. He was also the
Chairman of Black & Veatch UK Ltd. and was responsible for guiding strategic
development of the firm, having begun his career there in 1973. He is a Director
of Coeur Precious Metals, Protection One and Commerce Bancshares. Mr. Robinson
holds Bachelor and Master of Science degrees in Engineering from the University
of Kansas and has completed the Owner/President Management Program at the
Harvard School of Business.
Paul R. Tregurtha has served as a Director since December 1999. Mr.
Tregurtha serves as Chairman and Chief Executive Officer of Mormac Marine Group,
Inc. and Moran Transportation Company, and Chairman of MAC Acquisitions, Inc. He
is a director and principal officer of several companies involved in water
transportation and natural resources, including The Interlake Steamship Company
and Lakes Shipping Company. Mr. Tregurtha is also a director of FleetBoston
Financial and FPL Group, Inc., the parent of Florida Power & Light Company. Mr.
Tregurtha holds a Bachelor of Science degree in Mechanical Engineering from
Cornell University, where he serves as Trustee Emeritus, and a Master of
Business Administration degree from the Harvard School of Business.
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE.
Section 16(a) of the Securities and Exchange Act of 1934, as amended,
requires directors, executive officers and persons who beneficially own more
than ten percent of a registered class of the Partnership's equity securities to
file with the SEC initial reports of ownership and reports or changes in
ownership of such equity securities. Such persons are also required to furnish
the Partnership with copies of all Section 16(a) forms that they file. Based
solely upon a review of the copies of the forms furnished to it, or written
representations from certain reporting persons, the Partnership believes that
during 2000 none of its officers and directors was delinquent with respect to
any of the filing requirements under Rule 16(a) other than (a) Mr. Craft did not
file a Form 4 for the months of August and September 1999, regarding purchases
made by a
51
53
private foundation for which he serves as a trustee and disclaims beneficial
ownership, and (b) Mr. Neafsey did not timely file a Form 4 for the month of
August 2000, but has since filed this Form 4.
REIMBURSEMENT OF EXPENSES OF THE MANAGING GP AND ITS AFFILIATES
The Managing GP does not receive any management fee or other compensation in
connection with its management of us. However, our Managing GP and its
affiliates, including ARH, perform services for us and are reimbursed by us for
all expenses incurred on our behalf, including the costs of employee, officer
and director compensation and benefits properly allocable to us, as well as all
other expenses necessary or appropriate to the conduct of our business, and
properly allocable to us. Our Partnership Agreement provides that the Managing
GP will determine the expenses that are allocable to us in any reasonable manner
determined by the Managing GP in its sole discretion.
ITEM 11. EXECUTIVE COMPENSATION
EXECUTIVE COMPENSATION
The following table sets forth certain compensation information for all
executive officers of our Managing GP who received salary and bonus compensation
in excess of $100,000 in 2000. The Partnership was formed in May 1999 but did
not commence business until August 1999. Therefore 1999 compensation information
is for the Partnership period from commencement of operations (on August 20,
1999) to December 31, 1999.
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION LONG TERM
---------------------------------------- COMPENSATION
OTHER ANNUAL RESTRICTED ALL OTHER
BONUS COMPENSATION STOCK AWARDS COMPENSATION
NAME AND PRINCIPAL POSITION YEAR SALARY (1) (2) (3) (4)
- ------------------------------------- -------- -------- ---------- ------------ ------------ ------------
Joseph W. Craft III, 2000 $292,950 $ 94,200 $ -- $678,150 $ 63,695
President, Chief Executive Officer 1999 106,313 70,040 700 -- 21,495
and Director
Thomas L. Pearson, 2000 177,000 45,000 1,550 122,067 43,856
Senior Vice President-Law and 1999 64,234 28,306 -- -- 12,385
Administration, General Counsel and
Secretary
Michael L. Greenwood, 2000 151,400 45,000 -- 122,067 26,009
Senior Vice President-Chief 1999 54,944 28,306 -- -- 7,972
Financial Officer and Treasurer
Charles R. Wesley, 2000 187,000 47,600 1,500 135,630 32,802
Senior Vice President-Operations 1999 67,863 35,565 -- -- 12,383
Gary J. Rathburn, 2000 152,000 45,000 1,500 122,067 28,008
Senior Vice President-Marketing 1999 55,161 28,306 -- -- 9,407
(1) Amount awarded under the Short-Term Incentive Plan. See "Short-Term
Incentive Plan" below.
(2) Amount reimbursed for income tax preparation.
(3) Awards under the Long-Term Incentive Plan. The amount represents the value
of restricted units at the date of issuance. The total number of restricted
units and their market value as of December 31, 2000, were: Mr. Craft,
50,000 units valued at $900,000; Mr. Pearson, 9,000 units valued at
$162,000; Mr. Greenwood, 9,000 units valued at $162,000; Mr. Wesley, 10,000
units valued at $180,000; Mr. Rathburn, 9,000 units valued at $162,000.
52
54
Units granted under the Long-Term Incentive Plan do not vest until the
end of the subordination period, which will generally not end before
September 30, 2004. See "Long-Term Incentive Plan" below.
(4) Amount represents (a) the Managing General Partner's matching contributions
to its 401(k) Plan and (b) the Managing General Partner's contribution to a
Supplemental Executive Retirement Plan.
COMPENSATION OF DIRECTORS
Under the Managing GP's Directors Compensation Program (Directors Plan) each
non-employee Director is paid an annual retainer of $20,000. The annual retainer
is payable in Common Units of the Partnership to be paid on a quarterly basis in
advance determined by dividing the pro rata annual retainer payable on such date
by the closing sales price per Common Unit averaged over the immediately
preceding ten trading days. Each non-employee director may elect to defer all or
a portion of his or her compensation under the Deferred Compensation Plan for
Directors.
In addition each non-employee director participates in the Long-Term
Incentive Plan. The directors restricted units vest in accordance with the same
procedure as is described below. Messrs. MacWilliams and Miller have declined
compensation under the Directors and Long-Term Incentive Plans.
Mr. Sachse has a consulting agreement with the Managing GP, for a term of
three years, effective August 14, 2000. The consulting agreement provides that
Mr. Sachse will serve as Executive Vice President of the Managing GP and devote
his services on a part-time basis. In addition to compensation received under
the Directors Plan and Long-Term Incentive Plan described above, Mr. Sachse is
entitled to receive an annual fee of $150,000 payable in arrears monthly. Mr.
Sachse also is entitled to receive quarterly payments in arrears of the cash
difference between $7,500 less the market value of 250 Common Units of the
Partnership calculated by the closing sales price per Common Unit averaged over
the immediately preceding ten trading days. A copy of the consulting agreement
with Mr. Sachse is filed as an exhibit hereto.
EMPLOYMENT AGREEMENTS
The executive officers of the Managing GP and some additional members of
senior management will enter into employment agreements among the executive
officer or member of senior management, on the one hand, and the Managing GP and
ARH, on the other. We reimburse the Managing GP for the compensation and
benefits costs under these agreements. This summary of the terms of the
employment agreements does not purport to be complete, but outlines their
material provisions. A form of the agreements with each of Messrs. Craft,
Pearson, Greenwood, Wesley and Rathburn are filed as exhibits.
Each of the employment agreements has an initial term that expires on
December 31, 2001, but will automatically be extended for successive one-year
terms unless either party gives 12 months prior notice to the other party. The
employment agreements provide for a base salary, subject to review annually, of
$292,950, $177,000, $151,400, $187,000 and $152,000 for Messrs. Craft, Pearson,
Greenwood, Wesley and Rathburn, respectively. The employment agreements provide
for continued salary payments, bonus and benefits for a period of three years,
in the case of Mr. Craft, and 18 months, in the case of Messrs. Pearson,
Greenwood, Wesley and Rathburn, following termination of employment, except in
the case of a change of control of the Managing GP.
In the case of a "change of control" as defined in the agreements, in lieu
of the continuation of salary and benefits, that executive will be entitled to a
lump sum payment in an amount equal to three times base salary plus bonus, in
the case of Mr. Craft, and two times base salary plus bonus in the case of
Messrs. Pearson, Greenwood, Wesley and Rathburn. Unless the executive waives his
or her right to the continuation of base salary and bonus, the agreements
provide for a noncompetition period of 18 months. The noncompetition period does
not apply after a change in control. Amounts paid by the Managing GP pursuant to
the employment agreements will be reimbursed by the Partnership.
53
55
The executives who are subject to employment agreements also participate in
the Short- and Long-Term Incentive Plans of the Managing GP described below
along with other members of management. They also are entitled to participate in
the other employee benefit plans and programs that the Managing GP provides for
its employees.
LONG-TERM INCENTIVE PLAN
Effective January 1, 2000, the Managing GP adopted the Long-Term Incentive
Plan (LTIP) for certain employees and directors of the Managing GP and its
affiliates who perform services for us. The summary of the LTIP contained herein
does not purport to be complete, but outlines its material provisions.
The LTIP is administered by the Compensation Committee of the Managing GP's
Board of Directors. Annual grant levels for designated participants are
recommended by the President and CEO of the Managing GP, subject to the review
and approval of the Compensation Committee. We will reimburse the Managing GP
for all costs incurred pursuant to the programs described below. 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 us, or use units already owned by the Managing
GP, or any combination of the foregoing. The Managing GP is entitled to
reimbursement by us for the cost incurred in acquiring these Common Units or in
paying cash in lieu of Common Units upon vesting of the restricted units. If we
issue new Common Units upon payment of the restricted units or unit options
instead of purchasing them, the total number of Common Units outstanding will
increase. The aggregate number of units reserved for issuance under the LTIP is
600,000. Effective January 1, 2000, the Compensation Committee approved initial
grants of 142,100 restricted units, which vest at the end of the subordination
period, which will generally not end before September 30, 2004. Effective as of
January 1, 2001, the Compensation Committee approved additional grants of
131,490 restricted units, which also vest at the end of the subordination
period.
Restricted Units. Restricted units will vest over a period of time as
determined by the Compensation Committee. However, if a grantee's employment is
terminated for any reason prior to the vesting of any restricted units, those
restricted units will be automatically forfeited, unless the Compensation
Committee, in its sole discretion, provides otherwise. In addition, vested
restricted units will not be payable before the end of the subordination period,
which will generally not end before September 30, 2004.
The issuance of the Common Units pursuant to the restricted unit plan is
intended to serve as a means of incentive compensation for performance and not
primarily as an opportunity to participate in the equity appreciation in respect
of the Common Units. Therefore, no consideration will be payable by the plan
participants upon receipt of the Common Units, and we receive no remuneration
for these units. Following the subordination period, the Compensation Committee,
in it discretion, may grant distribution equivalent rights with respect to
restricted units.
Unit Options. We have not made any grants of unit options. The Compensation
Committee may, in the future, determine to make unit option grants to employees
and directors containing the specific terms that they determine. When granted,
unit options will have an exercise price set by the Compensation Committee which
may be above, below or equal to the fair market value of a Common Unit on the
date of grant. Unit options, if any, granted during the subordination period
will become exercisable upon, and in the same proportions as, the conversion of
the Subordinated Units to Common Units, or at a later date as determined by the
Compensation Committee in its sole discretion.
The Managing GP's Board of Directors, in its discretion, may terminate the
LTIP at any time with respect to any Common Units for which a grant has not
previously been made. The Managing GP's Board of
54
56
Directors will also have the right to alter or amend the LTIP or any part of it
from time to time, subject to unitholder approval as required by the exchange
upon which the Common Units may be listed at that time; provided, however, that
no change in any outstanding grant may be made that would materially impair the
rights of the participant without the consent of the affected participant. In
addition, the Managing GP may, in its discretion, establish such additional
compensation and incentive arrangements as it deems appropriate to motivate and
reward its employees. The Managing GP is reimbursed for all compensation
expenses incurred on our behalf.
SHORT-TERM INCENTIVE PLAN
Effective January 1, 1999, the Managing GP adopted a Short-Term Incentive
Plan (STIP) for management and other salaried employees. The STIP is designed to
enhance the financial performance by rewarding management and salaried employees
of the Managing GP and Partnership with cash awards for the Partnership
achieving an annual financial performance objective. The annual performance
objective for each year is recommended by the President and CEO of the Managing
GP and approved by the Compensation Committee of its Board of Directors prior to
January 1 of that year. The STIP is administered by the Compensation Committee.
Individual participants and payments each year are determined by and in the
discretion of the Compensation Committee, and the Managing GP is able to amend
the plan at any time. The Managing GP is entitled to reimbursement by us for the
costs incurred under the STIP.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth certain information as of March 1, 2001,
regarding the beneficial ownership of Common and Subordinated Units held by (a)
each person known by the Managing GP to be the beneficial owner of 5% or more of
the Common and Subordinated Units, (b) each director and executive officer of
the Managing GP and (c) all directors and executive officers of the Managing GP
as a group. The Managing GP is owned by funds affiliated with The Beacon Group
and members of management. The Special GP is a wholly-owned subsidiary of ARH.
The address of ARH, the Managing GP and the Special GP, is 1717 South Boulder
Avenue, Tulsa, Oklahoma 74119.
PERCENTAGE OF PERCENTAGE OF PERCENTAGE
COMMON COMMON SUBORDINATED SUBORDINATED OF TOTAL
UNITS UNITS UNITS UNITS UNITS
BENEFICIALLY BENEFICIALLY BENEFICIALLY BENEFICIALLY BENEFICIALLY
NAME OF BENEFICIAL OWNER OWNED(8) OWNED OWNED OWNED OWNED
- ------------------------ ----------- ------------- ------------ ------------ ------------
Alliance Resource GP, LLC(2) 1,232,780 13.72% 6,422,531 100% 49.7%
Alliance Resource Management GP, LLC(3) 164,000 1.83% -- -- 1.1%
Joseph W. Craft III(1)(7) 73,500 (*) -- -- (*)
Robert G. Sachse(1) 646 -- -- -- --
Thomas L. Pearson(1) 9,971 (*) -- -- (*)
Michael L. Greenwood(1) 29,950 (*) -- -- (*)
Charles R. Wesley(1) 20,000 (*) -- -- (*)
Gary J. Rathburn(1) 8,000 (*) -- -- (*)
John J. MacWilliams(4) 1,396,780 15.55% 6,422,531 100% 50.8%
Preston R. Miller, Jr.(4) 1,396,780 15.55% 6,422,531 100% 50.8%
John P. Neafsey(1) 12,257 (*) -- -- (*)
John H. Robinson(5) 2,257 (*) -- -- (*)
Paul R. Tregurtha(6) 2,257 (*) -- -- (*)
All directors and executive officers as
a group (11 persons) 1,555,618 17.32% 6,422,531 100% 51.8%
* Less than one percent.
(1) The address of Messrs. Craft, Sachse, Pearson, Greenwood, Wesley, Rathburn
and Neafsey is 1717 South Boulder Avenue, Tulsa, Oklahoma 74119.
55
57
(2) ARH may be deemed to beneficially own the Common Units and the Subordinated
Units held by the Special GP, as a result of ARH's ownership of all of the
membership interests in the Special GP. MPC Partners, LP (MPC Partners) may
also be deemed to beneficially own the Common Units and the Subordinated
Units held by the Special GP as a result of MPC Partners' ownership of
86.2% of ARH's outstanding common stock.
(3) The Managing GP is an affiliate of the Special GP, and as a consequence,
the Special GP may be deemed to beneficially own the Common Units held by
the Managing GP.
(4) Messrs. MacWilliams and Miller may also be deemed to share beneficial
ownership of the Common Units and the Subordinated Units held by the
Special GP and the Managing GP by virtue of their status as partners of The
Beacon Group, an affiliate of MPC Partners. Messrs. MacWilliams and Miller
disclaim beneficial ownership of the Common and Subordinated Units held by
the Special GP and the Managing GP. The address of Messrs. MacWilliams and
Miller is Beacon Group Energy Funds, an affiliate of JP Morgan Partners,
1221 Avenue of the Americas, 4th floor, New York, New York 10020.
(5) The address of Mr. Robinson is 24 Hanover Square, London, England W1S1JD.
(6) The address of Mr. Tregurtha is 3 Landmark Square, Stamford, Connecticut
06901.
(7) Mr. Craft owns 60,000 Common Units and may also be deemed to share
beneficial ownership of 13,500 Common Units held by a private foundation
for which he serves as a trustee. Mr. Craft disclaims beneficial ownership
of the Common Units held by the private foundation.
(8) The amounts set forth do not include any restricted units granted under
the LTIP.
56
58
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The Special GP owns 1,232,780 Common Units and 6,422,531 Subordinated Units
representing an aggregate 48.7% limited partner interest in the Partnership. In
addition, the General Partners own, on a combined basis, an aggregate 2% general
partner interest in the Partnership, the Intermediate Partnership and the
subsidiaries. The Managing GP's ability, as managing general partner, to manage
and operate the Partnership and its ownership of 164,000 Common Units together
with the Special GP's ownership of 1,232,780 Common Units and 6,422,531
Subordinated Units, effectively gives the General Partners the ability to veto
some actions of the Partnership and to control the management of the
Partnership.
UNIT PURCHASE PROGRAM BY THE MANAGING GP
The Managing GP authorized a Common Unit purchase program in November 1999
for the purchase of up to the greater of one million Common Units or $15 million
of Common Units. As of December 31, 2000, the Managing GP has purchased 164,000
Common Units. The Common Units purchased by the Managing GP retain their rights
to receive quarterly distributions of Available Cash.
TRANSACTIONS BETWEEN THE PARTNERSHIP, SPECIAL GP AND ARH
In September 2000, the Special GP acquired coal reserves and the right to
acquire additional coal reserves (a) contiguous to our Dotiki mine (Providence
No. 3 Reserves) and (b) contiguous to Hopkins County Coal (Elk Creek Reserves).
Such coal reserves and the rights to acquire additional coal reserves were
transferred to SGP Land, LLC (SGP Land), a newly formed wholly-owned subsidiary
of the Special GP.
Concurrent with such coal reserve acquisitions, the Special GP, through
affiliates, was negotiating for the purchase of (a) the capital stock of Roberts
Bros. Coal Co., Inc., Warrior Coal Mining Company, and Warrior Coal Corporation,
and (b) the related coal reserves (Warrior Reserves) owned by Cardinal Trust,
LLC (collectively, the Warrior Group). The Warrior Group's operating assets are
located adjacent to the Providence No. 3 Reserves and were purchased by a newly
formed affiliate of the Special GP, Warrior Coal, LLC (Warrior Coal). SGP Land
acquired the Warrior Reserves, which are immediately between the Providence No.
3 Reserves and Hopkins County Coal. The acquisition of the Warrior Group closed
in January 2001.
SGP Land entered into a mineral lease and sublease with Webster County Coal
for a portion of each of the Providence No. 3 Reserves and the Warrior Reserves,
and granted an option to Hopkins County Coal to lease and/or sublease the Elk
Creek Reserves. Under the terms of the Webster County Coal lease and sublease,
Webster County Coal has an annual minimum royalty obligation of $2.7 million,
payable in advance, from 2000 to 2013, or until $37.8 million of cumulative
annual minimum and/or earned royalty payments have been paid. Webster County
Coal paid the first annual minimum royalty of $2.7 million in 2000. Under the
terms of the Hopkins County Coal option to lease and sub-lease, Hopkins County
Coal paid an option fee of $645,000 in 2000. The anticipated annual minimum
royalty obligation is $684,000 payable in advance, from 2001 to 2009.
Consistent with the terms of the Omnibus Agreement discussed below, the
above transactions were initially offered to the Partnership. However, the Board
of Directors of the Managing GP, with the concurrence of its Conflicts
Committee, elected not to pursue these transactions. However, the Partnership
and ARH Warrior Holdings, Inc. (ARH Warrior Holdings), the parent company of
Warrior Coal, entered into an Amended and Restated Put and Call Option Agreement
(Put/Call Agreement), filed as an exhibit hereto, which provides as follows:
57
59
(a) ARH Warrior Holdings can require the Partnership to purchase
Warrior Coal from ARH Warrior Holdings during the period from January
2, 2003 to January 11, 2003, with a put option price of the sum of (i)
$10 million, and (ii) interest on the $10 million at 12 percent,
compounded annually; and
(b) the Partnership can require ARH Warrior Holdings to sell Warrior
Coal to the Partnership during the period from April 12, 2003 to
December 31, 2006, with a call option price of the sum of (i) $10
million, (ii) interest on the $10 million at 12 percent, compounded
annually, and (iii) 25 percent of the interest determined in (ii).
Separately, we entered into a noncancelable operating lease arrangement with
the Special GP for a coal preparation plant and ancillary facilities at Gibson
County Coal. This transaction was reviewed and approved by the Conflicts
Committee. Under the terms of the lease, the Partnership began making monthly
payments commencing January 1, 2001, of approximately $216,000 for 121 months.
We may enter into similar arrangements in the future to support the
acquisition of additional reserve properties or to develop facilities at our
existing mining complexes.
OMNIBUS AGREEMENT
Concurrent with the closing of the IPO, we entered into an Omnibus Agreement
with ARH and the General Partners, which governs potential competition among us
and the other parties to this agreement. ARH agreed, and caused its controlled
affiliates to agree, for so long as management and funds managed by The Beacon
Group and its affiliates control the Managing GP, not to engage in the business
of mining, marketing or transporting coal in the U.S. unless it first offers the
Partnership the opportunity to engage in a potential activity or acquire a
potential business, and the Board of Directors of the Managing GP, with the
concurrence of its Conflicts Committee, elects to cause us not to pursue such
opportunity or acquisition. In addition, ARH has the ability to purchase
businesses, the majority value of which is not mining, marketing or transporting
coal, provided ARH offers the Partnership the opportunity to purchase the coal
assets following their acquisition. The restriction does not apply to the assets
retained and business conducted by ARH at the closing of the IPO. Except as
provided above, ARH and its controlled affiliates are prohibited from engaging
in activities in which they compete directly with the Partnership. In addition,
The Beacon Group, and the funds it manages, are prohibited from owning or
engaging in businesses which compete with the Partnership. In addition to its
non-competition provisions, this agreement contains provisions which indemnify
the Partnership against liabilities associated with certain assets and
businesses of ARH which were disposed of or liquidated prior to consummating the
IPO.
OTHER RELATED TRANSACITONS
J.P. Morgan Chase & Co. (Chase) is paying agent, co-administrative agent and
a lender under our Credit Facility. In 2000, we made interest payments to Chase
on outstanding borrowings and paid Chase customary fees for their other
services. We expect that these relationships will continue in 2001. The Beacon
Group is an affiliate of Chase. Messrs. MacWilliams and Miller are General
Partners of the Beacon Group and Directors of the Managing GP.
58
60
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a)(1) Financial Statements.
The response to this portion of Item 14 is submitted as a separate
section herein under Part II, Item 8 - Financial Statements and
Supplementary Data.
(a)(2) Financial Statement Schedules.
No schedules are required to be presented by Alliance Resource
Partners.
(a)(3) Index of Exhibits.
3.1 Amended and Restated Agreement of Limited Partnership of
Alliance Resource Partners, L.P. (Incorporated by reference to
Exhibit 3.1 of the Registrant's Annual Report on Form 10-K for
the year ended December 31, 1999).
3.2 Amended and Restated Agreement of Limited Partnership of
Alliance Resource Operating Partners, L.P. (Incorporated by
reference to Exhibit 3.2 of the Registrant's Annual Report on
Form 10-K for the year ended December 31, 1999).
3.3 Certificate of Limited Partnership of Alliance Resource
Partners, L.P. (Incorporated by reference to Exhibit 3.6 of
the Registrant's Registration Statement on Form S-1 filed with
the Commission on May 20, 1999).
3.4 Certificate of Limited Partnership of Alliance Resource
Operating Partners, L.P. (Incorporated by reference to Exhibit
3.8 of the Registrant's Statement on Form S-1/A filed with the
Commission on July 20, 1999).
4.1 Form of Common Unit Certificate (Included as Exhibit A to the
Amended and Restated Agreement of Limited Partnership of
Alliance Resource Partners, L.P.)
10.1 Credit Agreement, dated as of August 16, 1999, among Alliance
Resource GP, LLC, The Chase Manhattan Bank (as paying agent),
Deutsche Bank AG, New York Branch (as documentation agent),
Citicorp USA, Inc. and The Chase Manhattan Bank (as
co-administrative agents) and the lenders named therein.
(Incorporated by reference to Exhibit 10.1 of the Registrant's
Annual Report 10-K for the year ended December 31, 1999).
10.2 Note Purchase Agreement, dated as of August 16, 1999, among
Alliance Resource GP, LLC and the purchasers named therein.
(Incorporated by reference to Exhibit 10.2 of the Registrant's
Annual Report on Form 10-K for the year ended December 31,
1999).
10.3 Contribution and Assumption Agreement, dated August 16, 1999,
among Alliance Resource Holdings, Inc., Alliance Resource
Management GP, LLC, Alliance Resource GP, LLC, Alliance
Resource Partners, L.P., Alliance Resource Operating Partners,
L.P. and the other parties named therein. (Incorporated by
59
61
reference to Exhibit 10.3 of the Registrant's Annual Report on
Form 10-K for the year ended December 31, 1999).
10.4 Omnibus Agreement, dated August 16, 1999, among Alliance
Resource Holdings, Inc., Alliance Resource Management GP, LLC,
Alliance Resource GP, LLC and Alliance Resource Partners, L.P.
(Incorporated by reference to Exhibit 10.4 of the Registrant's
Annual Report on Form 10-K for the year ended December 31,
1999).
10.5 Alliance Resource Management GP, LLC 2000 Long-Term Incentive
Plan (as amended). (Incorporated by reference to Exhibit 10.11
of the Registrant's Annual Report on Form 10-K for the year
ended December 31, 1999).
10.6 Alliance Resource Management GP, LLC Short-Term Incentive
Plan. (Incorporated by reference to Exhibit 10.12 of the
Registrant's Annual Report on Form 10-K for the year ended
December 31, 1999).
10.7 Restated and Amended Coal Supply Agreement, dated February 1,
1986, among Seminole Electric Cooperative, Inc., Webster
County Coal Corporation and White County Coal Corporation.
(Incorporated by reference to Exhibit 10.9 of the Registrant's
Registration Statement on Form S-1/A filed with the Commission
on July 20, 1999).
10.8 Amendment No. 1 to the Restated and Amended Coal Supply
Agreement effective April 1, 1996, between MAPCO Coal Inc.,
Webster County Coal Corporation, White County Coal
Corporation, and Seminole Electric Cooperative, Inc.
(Incorporated by reference to Exhibit 10.14 of the
Registrant's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2000).
10.9 Interim Coal Supply Agreement effective May 1, 2000, between
Alliance Coal, LLC and Seminole Electric Cooperative, Inc.
(Incorporated by reference to Exhibit 10.15 of the
Registrant's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2000).
10.10 Contract for Purchase and Sale of Coal, dated January 31,
1995, between Tennessee Valley Authority and Webster County
Coal Corporation. (Incorporated by reference to Exhibit 10.10
of the Registrant's Registration Statement on Form S-1/A filed
with the Commission on July 20, 1999).
10.11 Assignment/Transfer Agreement between Andalex Resources, Inc.,
Hopkins County Coal LLC, Webster County Coal Corporation and
Tennessee Valley Authority, dated January 23, 1998, with
Exhibit A - Contract for Purchase and Sale of Coal between
Tennessee Valley Authority and Andalex Resources, Inc., dated
January 31, 1995. (Incorporated by reference to Exhibit 10.11
of the Registrant's Registration Statement on Form S-1/A filed
with the Commission on July 20, 1999).
10.12 Contract for Purchase and Sale of Coal, dated July 7, 1998,
between Tennessee Valley Authority and Webster County Coal
Corporation. (Incorporated by reference to Exhibit 10.12 of
the Registrant's Registration Statement on Form S-1/A filed
with the Commission on July 20, 1999).
60
62
10.13 Contract for Purchase and Sale of Coal, dated July 7, 1998,
between Tennessee Valley Authority and White County Coal
Corporation. (Incorporated by reference to Exhibit 10.13 of
the Registrant's Registration Statement on Form S-1/A filed
with the Commission on July 20, 1999).
10.14 Agreement for Supply of Coal to the Mt. Storm Power Station,
dated January 15, 1996, between Virginia Electric and Power
Company and Mettiki Coal Corporation. (Incorporated by
reference to Exhibit 10. (t) to MAPCO Inc.'s Annual Report on
Form 10-K, filed April 1, 1996, File No. 1-5254).
*10.15 Coal Sales Agreement, dated October 3, 1998, between Pontiki
Coal Corporation and A.E.I. Coal Sales, Inc. (Portions of this
agreement have been omitted based on a request for
confidential treatment. Those omitted portions have been filed
with the Securities and Exchange Commission).
*10.16 Amendment No. 1 to Coal Sales Agreement dated February 28,
2001, between Pontiki Coal, LLC and AEI Coal Sales Company,
Inc. (Portions of this agreement have been omitted based upon
a request for confidential treatment. Those omitted portions
have been field with the Securities and Exchange Commission).
*10.17 Amended and Restated Put and Call Option Agreement dated
February 12, 2001 between ARH Warrior Holdings, Inc. and
Alliance Resource Partners, L.P.
*10.18 Consulting Agreement for Mr. Sachse dated January 1, 2001.
10.19 Form of Employment Agreement for Messrs. Craft, Pearson,
Greenwood, Wesley and Rathburn. (Incorporated by reference to
Exhibit 10.6 of the Registrant's Registration Statement on
Form S-1/A filed with the Commission on August 9, 1999).
*21.1 List of Subsidiaries
* Filed here within
(b) Reports on Form 8-K:
None.
61
63
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized, in Tulsa, Oklahoma, on March 14, 2001.
ALLIANCE RESOURCE PARTNERS, L.P.
By: Alliance Resource Management GP, LLC
its managing general partner
/s/ Michael L. Greenwood
------------------------------------
Michael L. Greenwood
Senior Vice President,
Chief Financial Officer
and Treasurer
(Principal Financial Officer and
Principal Accounting Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
SIGNATURE TITLE DATE
--------- ----- ----
/s/ Joseph W. Craft III President, Chief Executive March 14, 2001
- --------------------------- Officer and Director
Joseph W. Craft III (Principal Executive Officer)
/s/ Michael L. Greenwood Senior Vice President, March 14, 2001
- --------------------------- Chief Financial Officer
Michael L. Greenwood and Treasurer
(Principal Financial Officer and
Principal Accounting Officer)
/s/ John J. MacWilliams Director March 14, 2001
- ---------------------------
John J. MacWilliams
/s/ Preston R. Miller, Jr. Director March 14, 2001
- ---------------------------
Preston R. Miller, Jr.
/s/ John P. Neafsey Director March 14, 2001
- ---------------------------
John P. Neafsey
/s/ John H. Robinson Director March 14, 2001
- ---------------------------
John H. Robinson
/s/ Robert G. Sachse Executive Vice President and March 14, 2001
- --------------------------- Director
Robert G. Sachse
/s/ Paul R. Tregurtha Director March 14, 2001
- ---------------------------
Paul R. Tregurtha
62
64
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
------ -----------
3.1 Amended and Restated Agreement of Limited Partnership of
Alliance Resource Partners, L.P. (Incorporated by reference to
Exhibit 3.1 of the Registrant's Annual Report on Form 10-K for
the year ended December 31, 1999).
3.2 Amended and Restated Agreement of Limited Partnership of
Alliance Resource Operating Partners, L.P. (Incorporated by
reference to Exhibit 3.2 of the Registrant's Annual Report on
Form 10-K for the year ended December 31, 1999).
3.3 Certificate of Limited Partnership of Alliance Resource
Partners, L.P. (Incorporated by reference to Exhibit 3.6 of the
Registrant's Registration Statement on Form S-1 filed with the
Commission on May 20, 1999).
3.4 Certificate of Limited Partnership of Alliance Resource
Operating Partners, L.P. (Incorporated by reference to Exhibit
3.8 of the Registrant's Statement on Form S-1/A filed with the
Commission on July 20, 1999).
4.1 Form of Common Unit Certificate (Included as Exhibit A to the
Amended and Restated Agreement of Limited Partnership of
Alliance Resource Partners, L.P.).
10.1 Credit Agreement, dated as of August 16, 1999, among Alliance
Resource GP, LLC, The Chase Manhattan Bank (as paying agent),
Deutsche Bank AG, New York Branch (as documentation agent),
Citicorp USA, Inc. and The Chase Manhattan Bank (as
co-administrative agents) and the lenders named therein.
(Incorporated by reference to Exhibit 10.1 of the Registrant's
Annual Report on Form 10-K for the year ended December 31,
1999).
10.2 Note Purchase Agreement, dated as of August 16, 1999, among
Alliance Resource GP, LLC and the purchasers named therein.
(Incorporated by reference to Exhibit 10.2 of the Registrant's
Annual Report on Form 10-K for the year ended December 31,
1999).
10.3 Contribution and Assumption Agreement, dated August 16, 1999,
among Alliance Resource Holdings, Inc., Alliance Resource
Management GP, LLC, Alliance Resource GP, LLC, Alliance Resource
Partners, L.P., Alliance Resource Operating Partners, L.P. and
the other parties named therein. (Incorporated by reference to
Exhibit 10.3 of the Registrant's Annual Report on Form 10-K for
the year ended December 31, 1999).
10.4 Omnibus Agreement, dated August 16, 1999, among Alliance
Resource Holdings, Inc., Alliance Resource Management GP, LLC,
Alliance Resource GP, LLC and Alliance Resource Partners, L.P.
(Incorporated by reference to Exhibit 10.4 of the Registrant's
Annual Report on Form 10-K for the year ended December 31,
1999).
10.5 Alliance Resource Management GP, LLC 2000 Long-Term Incentive
Plan (as amended). (Incorporated by reference to Exhibit 10.11
of the Registrant's Annual Report on Form 10-K for the year
ended December 31, 1999).
10.6 Alliance Resource Management GP, LLC Short-Term Incentive Plan.
(Incorporated by reference to Exhibit 10.12 of the Registrant's
Annual Report on Form 10-K for the year ended December 31,
1999).
63
65
10.7 Restated and Amended Coal Supply Agreement, dated February 1,
1986, among Seminole Electric Cooperative, Inc., Webster County
Coal Corporation and White County Coal Corporation.
(Incorporated by reference to Exhibit 10.9 of the Registrant's
Registration Statement on Form S-1/A filed with the Commission
on July 20, 1999).
10.8 Amendment No. 1 to the Restated and Amended Coal Supply
Agreement effective April 1, 1996 between MAPCO Coal Inc.,
Webster County Coal Corporation, White County Coal Corporation,
and Seminole Electric Cooperative, Inc. (Incorporated by
reference to Exhibit 10.14 of the Registrant's Quarterly Report
on Form 10-Q for the quarter ended June 30, 2000).
10.9 Interim Coal Supply Agreement effective May 1, 2000 between
Alliance Coal, LLC and Seminole Electric Cooperative, Inc.
(Incorporated by reference to Exhibit 10.15 of the Registrant's
Quarterly Report on Form 10-Q for the quarter ended June 30,
2000).
10.10 Contract for Purchase and Sale of Coal, dated January 31, 1995,
between Tennessee Valley Authority and Webster County Coal
Corporation. (Incorporated by reference to Exhibit 10.10 of the
Registrant's Registration Statement on Form S-1/A filed with the
Commission on July 20, 1999).
10.11 Assignment/Transfer Agreement between Andalex Resources, Inc.,
Hopkins County Coal LLC, Webster County Coal Corporation and
Tennessee Valley Authority, dated January 23, 1998, with Exhibit
A - Contract for Purchase and Sale of Coal between Tennessee
Valley Authority and Andalex Resources, Inc., dated January 31,
1995. (Incorporated by reference to Exhibit 10.11 of the
Registration Statement on Form S-1/A filed with the Commission
on July 20, 1999).
10.12 Contract for Purchase and Sale of Coal, dated July 7, 1998,
between Tennessee Valley Authority and Webster County Coal
Corporation. (Incorporated by reference to Exhibit 10.12 of the
Registrant's Registration Statement on Form S-1/A filed with the
Commission on July 20, 1999).
10.13 Contract for Purchase and Sale of Coal, dated July 7, 1998,
between Tennessee Valley Authority and White County Coal
Corporation. (Incorporated by reference to Exhibit 10.13 of the
Registrant's Registration Statement on Form S-1/A filed with the
Commission on July 20, 1999).
10.14 Agreement for Supply of Coal to the Mt. Storm Power Station,
dated January 15, 1996, between Virginia Electric and Power
Company and Mettiki Coal Corporation. (Incorporated by reference
to Exhibit 10. (t) to MAPCO Inc.'s Annual Report on Form 10-K,
filed April 1, 1996, File No. 1-5254).
*10.15 Coal Sales Agreement, dated October 3, 1998, between Pontiki
Coal Corporation and A.E.I. Coal Sales, Inc. (Portions of this
agreement have been omitted based on a request for confidential
treatment. Those omitted portions have been filed with the
Securities and Exchange Commission).
*10.16 Amendment No. 1 to Coal Sales Agreement dated February 28, 2001,
between Pontiki Coal, LLC and AEI Coal Sales Company, Inc.
(Portions of this agreement have been omitted based on a request
for confidential treatment. Those omitted portions have been
filed with the Securities and Exchange Commission).
*10.17 Amended and Restated Put and Call Option Agreement dated
February 12, 2001 between ARH Warrior Holdings, Inc. and
Alliance Resource Partners, L.P.
64
66
*10.18 Consulting Agreement for Mr. Sachse dated January 1, 2001.
10.19 Form of Employment Agreement for Messrs. Craft, Pearson,
Greenwood, Wesley and Rathburn. (Incorporated by reference to
Exhibit 10.6 of the Registrant's Registration Statement on Form
S-1/A filed with the Commission on August 9, 1999).
*21.1 List of Subsidiaries.
*Filed here within
65