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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, 2002
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM _____________TO_____________
COMMISSION FILE NO.: 0-26823
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ALLIANCE RESOURCE PARTNERS, L.P.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 73-1564280
(STATE OR OTHER JURISDICTION OF (IRS EMPLOYER IDENTIFICATION NO.)
INCORPORATION OR ORGANIZATION)
1717 SOUTH BOULDER AVENUE, SUITE 600, TULSA, OKLAHOMA 74119
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES AND ZIP CODE)
(918) 295-7600
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: common units
representing limited partner interests
---------------
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. [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2).
Yes [X] No [ ]
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
$176,108,377 as of June 28, 2002, the last business day of the registrant's most
recently completed second fiscal quarter, based on $23.74 per unit, the closing
price of the common units as reported on the Nasdaq National Market on such
date.
As of March 18, 2003, 11,481,262 common units and 6,422,531 subordinated
units were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE: None
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TABLE OF CONTENTS
PAGE
PART I
ITEM 1. BUSINESS .......................................... 4
ITEM 2. PROPERTIES .......................................... 19
ITEM 3. LEGAL PROCEEDINGS..................................... 21
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITIES
HOLDERS .......................................... 22
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON UNITS AND
RELATED UNITHOLDER MATTERS............................ 22
ITEM 6. SELECTED FINANCIAL DATA............................... 23
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS......... 25
ITEM 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK..................................... 41
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA........... 42
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE................ 66
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE
MANAGING GENERAL PARTNER.............................. 66
ITEM 11. EXECUTIVE COMPENSATION................................ 69
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANGEMENT.................................. 73
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS........ 75
ITEM 14. CONTROLS AND PROCEDURES............................... 76
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND
REPORTS ON FORM 8-K................................... 76
1
FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K contains forward-looking statements. These
statements are based on our beliefs as well as assumptions made by, and
information currently available to, us. When used in this document, the words
"anticipate," "believe," "continue," "estimate," "expect," "forecast", "may,"
"project", "will," and similar expressions identify forward-looking statements.
These statements reflect our current views with respect to future events and are
subject to various risks, uncertainties and assumptions. Specific factors which
could cause actual results to differ from those in the forward-looking
statements include:
- competition in coal markets and our ability to respond to the
competition;
- fluctuations in coal prices, which could adversely affect our
operating results and cash flows;
- deregulation of the electric utility industry or the effects of any
adverse change in the domestic coal industry, electric utility
industry, or general economic conditions;
- dependence on significant customer contracts, including renewing
customer contracts upon expiration of existing contracts;
- customer bankruptcies and/or cancellations of, or breaches to,
existing contracts;
- customer delays or defaults in making payments;
- fluctuations in coal demand, prices and availability due to labor
and transportation costs and disruptions, equipment availability,
governmental regulations and other factors;
- our productivity levels and margins that we earn on our coal sales;
- any unanticipated increases in labor costs, adverse changes in work
rules, or unexpected cash payments associated with post-mine
reclamation and workers' compensation claims;
- any unanticipated increases in transportation costs and risk of
transportation delays or interruptions;
- greater than expected environmental regulation, costs and
liabilities;
- a variety of operational, geologic, permitting, labor and
weather-related factors;
- risk of major mine-related accidents or interruptions;
- results of litigation;
- difficulty maintaining our surety bonds for mine reclamation as
well as workers' compensation and black lung benefits; and
- difficulty obtaining commercial property insurance, and risks
associated with our 15.48% participation (excluding any applicable
deductible) in the commercial insurance property program.
2
If one or more of these or other risks or uncertainties materialize, or
should underlying assumptions prove incorrect, our actual results may differ
materially from those described in any forward-looking statement. When
considering forward-looking statements, you should also keep in mind the risk
factors described in "Risk Factors" below. The risk factors could also cause our
actual results to differ materially from those contained in any forward-looking
statement. We disclaim any obligation to update the above list or to announce
publicly the result of any revisions to any of the forward-looking statements to
reflect future events or developments.
You should consider the information above when reading any
forward-looking statements contained:
- in this Annual Report on Form 10-K;
- other reports filed by us with the SEC;
- our press releases; and
- written or oral statements made by us or any of our officers or
other authorized persons acting on our behalf.
3
PART I
ITEM 1. BUSINESS
GENERAL
We are a diversified producer and marketer of coal to major United States
utilities and industrial users. We began mining operations in 1971 and, since
then, have grown through acquisitions and internal development to become the
eighth largest coal producer in the eastern United States. At December 31, 2002,
we had approximately 416.5 million tons of reserves in Illinois, Indiana,
Kentucky, Maryland and West Virginia. In 2002, we produced 16.4 million tons of
coal and sold 18.3 million tons of coal. The coal we produced in 2002 was 29.9%
low-sulfur coal, 17.7% medium-sulfur coal and 52.4% high-sulfur coal. In 2002,
approximately 89% of our medium- and high-sulfur coal was sold to utility plants
with installed pollution control devices, also known as "scrubbers," to remove
sulfur dioxide. We classify low-sulfur coal as coal with a sulfur content of
less than 1%, medium-sulfur coal as coal with a sulfur content between 1% and
2%, and high-sulfur coal as coal with a sulfur content of greater than 2%.
At December 31, 2002, we operated seven mining complexes in Illinois,
Indiana, Kentucky and Maryland. Six of these mining complexes are underground
and one has multiple surface operations and a single underground mine. Our
mining activities are organized into three operating regions: (a) the Illinois
Basin operations, (b) the East Kentucky operations, and (c) the Maryland
operations.
We and our subsidiary, Alliance Resource Operating Partners, L.P. (referred
to as the intermediate partnership), are Delaware limited partnerships formed to
acquire, own and operate certain coal production and marketing assets of
Alliance Resource Holdings, Inc., (Alliance Resource Holdings) a Delaware
corporation formerly known as Alliance Coal Corporation. We completed our
initial public offering in August 1999, at which time Alliance Resource Holdings
contributed certain assets in exchange for cash, common and subordinated units,
general partner interests, the right to receive incentive distributions as
defined in the partnership agreement, and the assumption of related
indebtedness.
Our managing general partner, Alliance Resource Management GP, LLC, and our
special general partner, Alliance Resource GP, LLC (collectively referred to as
our general partners) own an aggregate 2% general partner interest in us. Our
limited partners, including the general partners as holders of common units and
subordinated units, own an aggregate 98% of the limited partner interests in us.
The coal production and marketing assets of Alliance Resource Holdings
acquired by us, but not Alliance Resource Holdings, are referred to as our
"Predecessor." All 1999 operating data contained herein includes our results and
our Predecessor's results.
RECENT DEVELOPMENTS
Common Unit Offering
On February 14, 2003, we completed a public offering of 2,250,000 common
units from which we received net proceeds of approximately $48.5 million before
expenses and, on March 14, 2003, we received net proceeds of approximately $6.2
million before expenses from the exercise of the underwriters option to purchase
an additional 288,000 common units. We used the net proceeds to fund the
purchase of Warrior Coal, LLC (Warrior) and for working capital and general
partnership purposes.
4
Warrior Acquisition
In February 2003, we acquired Warrior from an affiliate, ARH Warrior
Holdings, Inc. (ARH Warrior Holdings), in accordance with the terms of an
Amended and Restated Put and Call Option Agreement. We paid $12.7 million to ARH
Warrior Holdings, and repaid Warrior's borrowings of $17.0 million under a
revolving credit agreement between an affiliate of ARH Warrior Holdings and
Warrior.
Warrior operates an underground mining complex located near Madisonville, in
Hopkins County, Kentucky, between and adjacent to our other western Kentucky
operations. The Warrior complex was opened initially in 1985. Warrior utilizes
continuous mining units employing room-and-pillar mining techniques producing
high-sulfur coal. Warrior's preparation plant has a throughput capacity of 700
tons of raw coal an hour. In 2002, Warrior had approximately 170 employees and
produced some 1.6 million tons of coal, leaving approximately 22.8 million tons
of proven and probable reserves at December 31, 2002. Since 2001, Warrior has
invested approximately $17.0 million in non-partnership capital in new
infrastructure. We plan to add an additional continuous mining unit, early in
the second quarter 2003, to supplant other operations in the Illinois Basin that
will be depleting. Warrior's production level for 2003 is expected to increase
to 2.6 million tons.
Production from Warrior in 2002 and into 2003 has been shipped via truck on
U.S. and state highways primarily to Hopkins for resale to our customer Synfuel
Solutions Operating LLC (SSO) for use as feedstock in the production of coal
synfuel, as discussed under "Hopkins Complex" and "Coal Synfuel" below.
Following the planned move of SSO's coal synfuel production facility to Warrior
in the second quarter of 2003, it is expected that Warrior will sell
substantially all of its production to SSO. At that time, we anticipate Warrior
will purchase supplemental production from our neighboring Hopkins County Coal,
LLC (Hopkins) and Webster County Coal, LLC (Dotiki) complexes for resale to SSO.
SSO advises it plans to ship coal synfuel to electric utilities that have been
purchasers of our coal. We maintain "back-up" coal supply agreements with these
long-term customers for our coal, which automatically provide for the sale of
our coal to them in the event they do not purchase coal synfuel from SSO.
Because we acquired Warrior in 2003, the remainder of this 2002 Annual
Report on Form 10-K excludes further discussion of Warrior, except as otherwise
noted.
Management Buy-out of Beacon Group Funds' Interests
Prior to May 8, 2002, the majority of the outstanding equity interests in
our general partners was owned by two investment funds controlled by The Beacon
Group, LP (The Beacon Group) and its affiliates. On May 8, 2002, our management
purchased these interests, which consisted of:
- a 74.1% interest in our managing general partner for $4.8 million in cash;
and
- a 91.3% interest in Alliance Resource Holdings, the parent of our special
general partner (which owns 1,232,780 common units and 6,422,531
subordinated units) for approximately $103.4 million, consisting of
approximately $46.7 million in cash and approximately $56.7 million in
promissory notes.
As a result, our management now owns all of the interests in our managing
general partner and Alliance Resource Holdings. The acquisitions were not funded
or secured with any of our assets.
The promissory notes require two installment payments, including a $30.9
million payment due on March 1, 2004 and a $25.8 million payment due on March 1,
2005. In September 2002, management prepaid approximately $29.9 million due
under the first promissory note with borrowings from a commercial bank facility.
Our management expects to pay off the remaining balance under the promissory
notes from
5
borrowings from commercial lending institutions, cash generated from operations
of Alliance Resource Holdings, and/or from quarterly distributions paid by us on
the common and subordinated units held by our special general partner.
Management's payment obligations under the promissory notes are secured
under a security and pledge agreement by a pledge to The Beacon Group's funds of
all of the outstanding capital stock of Alliance Resource Holdings and other
equity interests in affiliated entities owned directly or indirectly by our
management.
MINING OPERATIONS
We produce a diverse range of steam coals with varying sulfur and heat
contents, which enables us to satisfy the broad range of specifications required
by our customers. The following chart summarizes our production by region for
the last five years.
OPERATING REGION AND COMPLEXES 2002 2001 2000 1999 1998
--------------------------------- ---- ---- ---- ---- ----
(TONS IN MILLIONS)
Illinois Basin Operations:
Dotiki, Gibson, Hopkins, Pattiki Complexes 10.5 10.2 8.4 8.5 7.9
East Kentucky Operations:
MC Mining, Pontiki Complexes 3.0 2.8 2.7 2.8 2.5
Maryland Operations:
Mettiki Complex 2.9 2.7 2.6 2.8 3.0
---- ---- ---- ---- ----
Total 16.4 15.7 13.7 14.1 13.4
==== ==== ==== ==== ====
We have no reportable segments because our operations solely consist of
producing and marketing coal and providing rental and service fees associated
with producing and marketing coal synfuel.
ILLINOIS BASIN OPERATIONS
Our Illinois Basin mining operations are located in western Kentucky,
southern Illinois and southern Indiana. We have approximately 975 employees in
the Illinois Basin and currently operate four mining complexes. Additionally, we
host a coal synfuel facility at one of our mining complexes.
Dotiki Complex. Webster County Coal, LLC operates Dotiki, which is an
underground mining complex located near the city of Providence in Webster
County, Kentucky. The complex was opened in 1966, and we purchased the mine in
1971. Our Dotiki complex 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 of high-sulfur coal from the complex is shipped via the CSX and
PAL railroads and by truck on U.S. and state highways. Our primary customers for
coal produced at Dotiki are and Louisville Gas & Electric (LG&E), Seminole
Electric Cooperative, Inc. (Seminole), Tennessee Valley Authority (TVA) and
Western Kentucky Energy Corp., all of which purchase our coal pursuant to
long-term contracts for use in their scrubbed generating units. During August
2001, Dotiki began construction of a new mine shaft and ancillary facilities,
which are expected to be operational during the second quarter of 2003 and will
provide a new access to the coal reserves for miners and supplies.
Pattiki Complex. White County Coal, LLC operates Pattiki, which is an
underground mining complex located near the city of Carmi, in White County,
Illinois. We began construction of the complex in 1980 and have operated it
since its inception. Our Pattiki complex utilizes continuous mining units
employing room-and-pillar mining techniques. During 2001 and 2002, we extended
Pattiki into adjacent coal reserves, through
6
the construction of two new shafts and ancillary facilities. This extension
involves capital expenditures of approximately $30 million principally expended
during the 2000-2002 period and is expected to allow Pattiki to continue and
expand its existing productive capacity for the next 15 years. The preparation
plant has a throughput capacity of 1,000 tons of raw coal an hour.
Production of high-sulfur coal from the complex is shipped via the CSX
railroad. Our primary customers for coal produced at Pattiki are Seminole and
TVA, both of which purchase our coal pursuant to long-term contracts for use in
their scrubbed generating units.
Hopkins Complex. Hopkins County Coal, LLC operates a mining complex located
near the city of Madisonville in Hopkins County, Kentucky. We acquired the
complex in January 1998. The complex has three surface mines, one of which is
currently idle, and one underground mine. The underground mine is expected to be
depleted in the first quarter of 2003. 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 of high-sulfur coal from the complex is shipped via the CSX and
PAL railroads and by truck on U.S. and state highways. As discussed below, we
sell most of Hopkins' production to SSO, whose coal synfuel production facility
is located currently at Hopkins. SSO has in turn sold coal synfuel to utilities
that have been purchasers of our coal. . We have maintained "back-up" coal
supply agreements with these customers, which automatically provide for the sale
of our coal to these customers in the event they do not purchase coal synfuel
from SSO.
Gibson Complex. Gibson County Coal, LLC (Gibson) operates an underground
mining complex located near the city of Princeton in Gibson County, Indiana. The
mine began production in November 2000. Our Gibson complex utilizes continuous
mining units employing room-and-pillar mining techniques. The preparation plant
has a throughput capacity of 700 tons of raw coal an hour. We refer to the
reserves mined at this location as the Gibson "North" reserves. We also control
undeveloped reserves in Gibson County, which are not contiguous to the reserves
currently being mined. We refer to these as the Gibson "South" reserves.
Production from Gibson is a low-sulfur coal, shipped via truck approximately
10 miles on U.S. and state highways to Gibson's primary customer, PSI Energy
Inc. (PSI), a subsidiary of Cinergy Corporation. We are involved in a contract
dispute with PSI concerning the procedures for and testing of a certain coal
quality specification. Please read "Item 3. Legal Proceedings" and "Item 8.
Financial Statements and Supplementary Data - Note 15. Commitments and
Contingencies."
Coal Synfuel. We entered into long-term agreements with SSO to host and
operate its coal synfuel facility currently located at Hopkins, supply the
facility with coal feedstock, assist SSO with the marketing of coal synfuel and
provide other services. These agreements expire on December 31, 2007 and provide
us with coal sales, rental and service fees from SSO based on the synfuel
facility throughput tonnages. These amounts are dependent on the ability of
SSO's members to use certain qualifying tax credits applicable to the facility.
As discussed above in "Mining Operations; Illinois Basin; Hopkins Complex," we
sell most of the coal produced at Hopkins to SSO, while Alliance Coal Sales, a
division of Alliance Coal, LLC (Alliance Coal), assists SSO with the sale of its
coal synfuel to our customers pursuant to a sales agency agreement. The term of
each of these agreements is subject to early cancellation provisions customary
for transactions of these types, including the unavailability of synfuel tax
credits, the termination of associated coal synfuel sales contracts, and the
occurrence of certain force majeure events. Therefore, the continuation of the
operating revenues associated with the coal synfuel production facility cannot
be assured. However, we have maintained "back up" coal supply agreements with
each coal synfuel customer that automatically provide for sale of our coal to
these customers in the event they do not purchase coal synfuel from SSO. Hopkins
purchased approximately 1.4 million tons of coal from Warrior in 2002, which was
resold to SSO as feedstock for coal synfuel
7
production. In conjunction with a decision to relocate the coal synfuel
production facility to Warrior, agreements for providing certain of these
services were assigned to Alliance Service, Inc. (Alliance Service), a
wholly-owed subsidiary of Alliance Coal, in December 2002. Alliance Service is
subject to federal and state income taxes.
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 430 employees and operate two mining complexes in East Kentucky.
Pontiki Complex. Pontiki Coal, LLC (Pontiki) owns an underground mining
complex located near the city of Inez in Martin County, Kentucky. We constructed
the mine in 1977. Pontiki owns the mining complex and leases the reserves, and
Excel Mining, LLC (Excel), an affiliate of Pontiki, is responsible for
conducting all mining operations. Substantially all of the coal produced at
Pontiki meets or exceeds the compliance requirements of Phase II of the Clean
Air Act amendments. Our Pontiki operation utilizes continuous mining units
employing room-and-pillar mining techniques. The preparation plant has a
throughput capacity of 800 tons of raw coal an hour.
Production from the mine is shipped via the Norfolk Southern railroad or by
truck via U.S. and state highways to various docks on the Big Sandy River in
Kentucky. Pontiki ships its low-sulfur production primarily to electric
utilities located in the southeastern United States.
MC Mining Complex. MC Mining, LLC (MC Mining) owns an underground mining
complex located near the city of Pikeville in Pike County, Kentucky. MC Mining
was acquired in 1989. When we began production in late 1996, MC Mining was
operated by an unaffiliated contract mining company. During 2000, the contract
mining agreement was terminated, and MC Mining entered into an intercompany
support services agreement with Excel. Selected employees of the contractor and
other qualified individuals were hired by Excel, which is responsible for
conducting all mining operations. The complex utilizes continuous mining units
employing room-and-pillar mining techniques. The preparation plant has a
throughput capacity of 800 tons of raw coal an hour.
Production from the mine is shipped via the CSX railroad or by truck via
U.S. and state highways to various docks on the Big Sandy River. MC Mining sells
its low-sulfur production primarily in the spot market.
MARYLAND OPERATIONS
Our Maryland mining operation is located in the Northern Appalachia coal
fields. We have approximately 225 employees and operate one mining complex in
Maryland.
Mettiki Complex. Mettiki Coal, LLC (Mettiki) operates an underground
longwall mining complex located near the city of Oakland in Garrett County,
Maryland. We constructed Mettiki in 1977 and have operated it since its
inception. The operation utilizes a longwall miner for the majority of the coal
extraction as well as continuous mining units used to prepare the mine for
future longwall mining. The preparation plant has a throughput capacity of 1,350
tons of raw coal an hour.
Our primary customer for the medium-sulfur coal produced at Mettiki is
Virginia Electric and Power Company (VEPCO), which purchases the coal pursuant
to a long-term contract for use in the generating units at its Mt. Storm, West
Virginia power plant, located less than 20 miles away. Our coal is trucked to
Mt. Storm over a private haul road, which links to a state highway. Mettiki is
also served by the CSX railroad.
8
Mettiki Coal (WV). Mettiki Coal (WV), LLC has approximately 18.9 million
tons of undeveloped recoverable reserves in Grant and Tucker Counties, West
Virginia close to Mettiki in Garrett County, Maryland. We currently do not
conduct mining operations at Mettiki (WV).
OTHER OPERATIONS
MT. VERNON TRANSFER TERMINAL, LLC
The Mt. Vernon terminal is a rail-to-barge loading terminal on the Ohio
River at 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 agreements with
Seminole. Seminole now transports these shipments to its generating units
directly by the CSX railroad. During 2002, the terminal loaded approximately 1.2
million tons for Pattiki and Dotiki customers other than Seminole.
COAL BROKERAGE
We buy coal from outside producers principally throughout the eastern United
States, which we then resell, both directly and indirectly, to utility and
industrial customers. We purchased and sold approximately 502,000 tons of
outside coal from non-affiliates in 2002. 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. Revenues from
these services represented less than one-half of one percent of our total
revenues.
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 2002, approximately 88% of
both our sales tonnage and total coal sales, respectively, were sold under
long-term contracts (contracts having a term of greater than one year) with
maturities ranging from 2002 to 2012. Our total nominal commitment under
significant long-term contracts was approximately 71.4 million tons at December
31, 2002 and is expected to be delivered as follows: 14.2 million tons in 2003,
12.5 million tons in 2004, 11.6 million tons in 2005, 11.6 million tons in 2006,
4.4 million tons in 2007, and 17.1 million tons thereafter during the remaining
terms of the relevant coal supply agreements. The total commitment of coal under
contract is an approximate number because, in some instances, our contracts
contain provisions that could cause the nominal total commitment to increase or
decrease by as much as 20%. The contractual time commitments for customers to
nominate future purchase volumes under these contracts are sufficient to allow
us to balance our sales commitments with prospective production capacity. In
addition, the nominal total commitment can otherwise change because of price
reopener provisions contained in certain of these long-term contracts.
The terms of long-term contracts are the results of both bidding procedures
and extensive negotiations with each customer. As a result, the terms of these
contracts vary significantly in many respects, including, among others, price
adjustment features, price and contract reopener terms, permitted sources of
supply, force
9
majeure provisions, coal qualities, and quantities. Virtually all of our
long-term contracts are subject to price adjustment provisions, which permit an
increase or decrease periodically in the contract price to reflect changes in
specified price indices or items such as taxes, royalties or actual production
costs. These provisions, however, may not assure that the contract price will
reflect every change in production or other costs. Failure of the parties to
agree on a price pursuant to an adjustment or a reopener provision can lead to
early termination of a contract. Some of the long-term contracts also permit the
contract to be reopened to renegotiate terms and conditions other than the
pricing terms, and where a mutually acceptable agreement on terms and conditions
cannot be concluded, either party may have the option to terminate the contract.
The long-term contracts typically stipulate procedures for quality control,
sampling and weighing. Most contain provisions requiring us to deliver coal
within stated ranges for specific coal characteristics such as heat, sulfur,
ash, moisture, grindability, volatility and other qualities. Failure to meet
these specifications can result in economic penalties or termination of the
contracts. While most of the contracts specify the approved seams and/or
approved locations from which the coal is to be mined, some contracts allow the
coal to be sourced from more than one mine or location. Although the volume to
be delivered pursuant to a long-term contract is stipulated, the buyers often
have the option to vary the volume within specified limits.
RELIANCE ON MAJOR CUSTOMERS
Our three largest customers in 2002 were Seminole, SSO and VEPCO. Sales to
these customers in the aggregate accounted for approximately 49% of our 2002
total revenues, and sales to each of these customers accounted for more than 10%
of our 2002 total revenues.
In February 2002, a major customer of our Pontiki Complex, AEI Coal Sales
Company, Inc., and numerous of its affiliates voluntarily filed for Chapter 11
bankruptcy protection. In May 2002, those companies emerged from bankruptcy
proceedings under a joint plan of reorganization under a new name for their
parent entity, Horizon Natural Resources Company (Horizon). We did not incur any
losses associated with this bankruptcy filing. Subsequently, in November 2002,
Horizon and its numerous affiliates again voluntarily filed for Chapter 11
bankruptcy protection. We believe that our payment terms with this customer
protect us from any significant bad debt exposure and at December 31, 2002 we
did not have any accounts receivable from this customer. Although Horizon has
not indicated that it will reject Pontiki's coal supply agreement or other
contracts and leases we have with Horizon, that is possible. If any of our
customers file for bankruptcy and reject their coal supply or other contracts,
or if they otherwise default on their obligations to us, we may not be able to
enter into new contracts on similar terms to replace the lost revenue, and our
business, financial condition or results of operations could be adversely
affected.
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 18% of the total 2002 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
50% of the delivered cost of a customer's coal. As a consequence, the
availability and
10
cost of transportation constitute important factors in the marketability of
coal. We believe our mines are located in favorable geographic locations that
minimize transportation costs for our customers.
Customers pay the transportation costs from the contractual F.O.B. point
(free-on-board point), which is consistent with practice in the industry and is
generally from the mine to the customer's plant. In 2002, the largest volume
transporter of our coal production was the CSX railroad, which moved
approximately 39% of our tonnage over its rail system. The practices of, and
rates set by, the railroad serving a particular mine or customer might affect,
either adversely or favorably, our marketing efforts with respect to coal
produced from the relevant mine. At our Gibson and Mettiki complexes, a
contractor operates a truck delivery system that transports the coal to our
primary customer's power plant.
REGULATION AND LAWS
The coal mining industry is subject to regulation by federal, state and
local authorities on matters such as:
- employee health and safety;
- mine permits and other licensing requirements;
- air quality standards;
- water quality standards;
- 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;
- storage and handling of explosives;
- wetlands protection;
- management of electrical equipment containing polychlorinated biphenyls
(PCBs);
- surface subsidence from underground mining;
- the effects (if any) that mining has on groundwater quality and
availability; and
- legislatively mandated benefits for current and retired coal miners.
In addition, the utility industry is subject to extensive regulation
regarding the environmental impact of its power generation activities, which
could affect demand for our coal. The possibility exists that new legislation or
regulations, or new interpretations of existing laws or regulations, may be
adopted that may have a significant impact on our mining operations or our
customers' ability to use coal, or may require us or our customers to change our
or their operations significantly or to incur substantial costs.
We are committed to conducting mining operations in compliance with
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 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 closings, including the cost of treating mine water
discharge, when necessary. The accruals for reclamation and mine closing costs
are 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
11
adversely affected if we later determine these accruals to be insufficient.
Compliance with these laws has substantially increased the cost of coal mining
for all domestic coal producers.
MINING PERMITS AND APPROVALS
Numerous governmental permits or approvals are required for mining
operations. We may be required to prepare and present to federal, state or local
authorities data pertaining to the effect or impact that any proposed production
of coal may have upon the environment. All requirements imposed by any of these
authorities may be costly and time-consuming, and may delay commencement or
continuation of mining operations. Future legislation and administrative
regulations may emphasize more heavily the protection of the environment and, as
a consequence, our activities may be more closely regulated. Legislation and
regulations, as well as future interpretations of existing laws, may require
substantial increases in equipment and operating costs, or delays, interruptions
or terminations of operations, the extent of any of which cannot be predicted.
Before commencing mining on a particular property, we must obtain mining
permits and approvals by state regulatory authorities of a reclamation plan for
restoring, upon the completion of mining, the mined property to its approximate
prior condition, productive use or other permitted condition. Typically, we
commence actions to obtain permits between 18 and 24 months before we plan to
mine a new area. In our experience, permits generally are approved within 12
months after a completed application is submitted. Generally, we have not
experienced material or significant difficulties in obtaining mining permits in
the areas where our reserves are currently located. However, we cannot assure
you that we will not experience difficulty in obtaining mining permits in the
future.
In March 2000, we submitted a permit application to the West Virginia
Department of Environmental Protection (West Virginia DEP) requesting approval
for the mining of approximately 3.1 million tons of coal deposits controlled by
Mettiki (WV) but contiguous with our Mettiki Coal Reserves in Maryland. In
January 2002, the West Virginia DEP denied the permit. We appealed the permit
denial to the West Virginia Surface Mining Board (Mining Board) and, in July
2002, the Mining Board approved a permit that currently allows us to mine
approximately 1.2 million tons of coal from this coal deposit area in West
Virginia. In February 2003, we submitted a revised permit application requesting
approval for the mining of an additional 600,000 tons of this West Virginia coal
deposit. We cannot assure you that this revised permit application will be
approved.
Under some circumstances, substantial fines and penalties, including
revocation of mining permits, may be imposed under the laws described above.
Monetary sanctions and, in severe circumstances, criminal sanctions may be
imposed for failure to comply with these laws. Regulations also provide that a
mining permit can be refused or revoked if the permit applicant or permittee
owns or controls, directly or indirectly through other entities, mining
operations which have outstanding environmental violations. Although like other
coal companies 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. The Federal Mine Safety and Health Act of 1977, and regulations
adopted pursuant thereto, significantly expanded the enforcement of health and
safety standards and imposed comprehensive safety and health standards on
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
12
and regulations. In addition, as part of CMHSA and the Mine Safety and Health
Act of 1977, the Black Lung Benefits Act requires payments of benefits by all
businesses that conduct current mining operations to a coal miner with black
lung disease and to some survivors of a miner who dies from this disease. Most
of the states where we operate also have state programs for mine safety and
health regulation and enforcement. In combination, federal and state safety and
health regulation in the coal mining industry is perhaps the most comprehensive
and rigorous system for protection of employee safety and health affecting any
segment of any industry. Even the most minute aspects of mine operations,
particularly underground mine operations, are subject to extensive regulation.
This regulation has a significant effect on our operating costs. For example,
new regulations governing exposures to diesel particulate matter in underground
mines has recently increased our compliance costs. 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 the
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 issued revised regulations effective January
2001 altering the claims process for federal black lung benefit recipients,
which among other things:
- simplify administrative procedures for the adjudication of claims;
- propose preference for the miner's treating physician under certain
circumstances;
- allow previously denied claims to be refiled and litigated under a
different standard;
- limit the amount of evidence all parties may submit for consideration;
- create a rebuttable presumption that medical treatment for any
pulmonary condition is caused or aggravated by the miner's work; and
- expand the definition of pneumoconiosis and total disability.
The revised regulations are expected to result in an increase in the
incidence and recovery of black lung claims. 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.
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 challenged certain provisions of the revised regulations through
litigation. A federal judge upheld these regulations in August 2001. In June
2002, the U.S. Court of Appeals, District of Columbia Circuit, affirmed in part,
reversed in part, and remanded to the District Court for further proceedings
consistent with its opinion. The amount of the increase in the incidence and
recovery of black lung claims will be determined by the future application of
the revised regulations in the numerous administrative and judicial processes
involved in the adjudication of black lung claims. Concerning our requirement to
maintain bonds to secure our black lung claim obligations, see the discussion of
surety bonds below under Surface Mining Control and Reclamation Act.
13
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. We self-insure the potential cost using actuarially determined
estimates of the cost of present and future claims. Concerning our requirement
to maintain bonds to secure our workers compensation obligations, see the
discussion of surety bonds below under Surface Mining Control and Reclamation
Act.
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. However, in connection
with the sale of the coal assets acquired by Alliance Resource Holdings in 1996,
MAPCO Inc. agreed to retain, and be responsible for, all liabilities under
CIRHBA.
SURFACE MINING CONTROL AND RECLAMATION ACT (SMCRA)
The Federal SMCRA establishes operational, reclamation and closure standards
for all aspects of surface mining as well as many aspects of deep mining. The
act requires that comprehensive environmental protection and reclamation
standards be met during the course of and upon completion of mining activities.
In conjunction with mining the property, we reclaim and restore the mined areas
by grading, shaping and preparing the soil for seeding. Upon completion of the
mining, reclamation generally is completed by seeding with grasses or planting
trees for a variety of uses, as specified in the approved reclamation plan. We
believe 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. The Federal Office of Surface Mining Reclamation and Enforcement is
currently studying the adequacy of bonding requirements for treatment of
long-term pollution discharges and whether other forms of financial assurances
may be permitted. In addition, the Abandoned Mine Lands Program, which is part
of SMCRA, imposes a tax on all current mining operations, the proceeds of which
are used to restore mines closed before 1977. The maximum tax is $0.35 per ton
on surface-mined coal and $0.15 per ton on underground-mined coal. We have
accrued for the estimated costs of reclamation and mine closing, including the
cost of treating mine water discharge when necessary. In addition, states from
time to time have increased and may continue to increase their fees and taxes to
fund reclamation of orphaned mine sites and acid mine drainage control on a
statewide basis, as West Virginia did in 2002.
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
14
against the "owner" or "controller" are quite severe and can include being
blocked from receiving new permits and revocation of any permits that have been
issued since the time of the violations or, in the case of civil penalties and
reclamation fees, since the time their amounts became due. We are not aware of
any currently pending or asserted claims against us relating to the "ownership"
or "control" theories discussed above. However, we cannot assure you that such
claims will not develop in the future.
Our underground mining operations could be adversely affected by a recent
decision which interprets SMCRA to prohibit subsidence from underground mining
on certain federal lands, near occupied dwellings, public or community
buildings, public roads, schools, churches, and cemeteries, or adversely
affecting public parks or certain historic properties. The U.S. District Court's
decision has been stayed until the U.S. Court of Appeals, District of Columbia
Circuit, has ruled on the appeal filed by the United States and by the National
Mining Association, both of which claim that the District Court misinterpreted
the statute, which exempts subsidence from such prohibitions applicable only to
surface mines. If the decision is not overturned by the U.S. Court of Appeals or
Congress, and depending on how the decision is interpreted and applied by the
regulatory authorities, it could effectively increase our permitting and mining
costs, restrict our ability to mine certain reserves, and limit the use of
longwall mining technologies.
Federal and state laws require bonds to secure our obligations to reclaim
lands used for mining, to pay federal and state workers' compensation, and to
satisfy other miscellaneous obligations. These bonds are typically renewable on
a yearly basis. It has become increasingly difficult for us to secure new surety
bonds without the posting of partial collateral. In addition, surety bond costs
have increased while the market terms of surety bonds have generally become less
favorable to us. Surety bonds issuers and holders may not continue to renew
bonds or may demand additional collateral upon those renewals. Our failure to
maintain, or inability to acquire, surety bonds that are required by state and
federal laws would have a material adverse effect on us.
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 (SO(2)) emissions from electric power generation plants in two phases.
Only some facilities were subject to the Phase I requirements. Beginning in
2000, Phase II requires nearly all facilities to reduce emissions. The affected
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 SO(2). In addition, the CAA requires a study of utility power plant emissions
of some toxic substances and their eventual regulation, if warranted. We cannot
accurately predict the effect of these provisions of the CAA on us in future
years.
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
2003. This deadline was recently extended by EPA to
15
2004. EPA expects that affected states will achieve reductions by requiring
power plants to make substantial reductions in their NOx emissions. This in turn
will 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 currently
expected to be implemented by 2004. Because coal mining operations and utilities
emit particulate matter, our mining operations and utility customers are likely
to be directly affected when the revisions to the NAAQS are implemented by the
states. Both Congress and EPA are considering additional controls on other air
pollutants emitted by electric utilities. Any such controls, if adopted, could
adversely affect the market for coal.
EPA has filed suit against a number of our customers over implementation of
new source performance standards and preconstruction review requirements for new
sources and major modifications under the prevention of significant
deterioration and nonattainment regulations. This issue addresses what
activities constitute routine maintenance, repair and replacement versus new
construction. Some of our customers have agreed to or proposed settlements with
EPA while others are preparing for litigation. These and other regulatory
developments may restrict the size of our market, and the type of coal in
demand. This in turn could adversely affect our ability to develop new mines, or
could require us or our customers to modify existing operations.
FRAMEWORK CONVENTION ON GLOBAL CLIMATE CHANGE (KYOTO PROTOCOL)
The United States and more than 160 other nations are signatories to the
Kyoto Protocol which is intended to limit or capture emissions of greenhouse
gases, such as carbon dioxide. The purpose of the Kyoto Protocol is to establish
a binding set of emissions targets for developed nations. The specific limits
would 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.
In March 2001, President Bush expressed his opposition to the Kyoto Protocol
and stated he did not believe the government should impose mandatory carbon
dioxide emission reductions on power plants. In February 2002, President Bush
proposed voluntary actions to reduce greenhouse gas intensity in the United
States. Greenhouse gas intensity measures the ratio of greenhouse gas emissions,
such as carbon dioxide, to economic output. The President's climate change
initiative calls for an 18% reduction in the ratio of greenhouse gas emissions
to gross domestic product from 2002 to 2012, which is approximately equivalent
to the reduction that has occurred over each of the past two decades. The United
States has not ratified the Kyoto Protocol and it will not become binding until
it is ratified by countries representing at least 55% of the total carbon
dioxide emissions for 1990. As of December 31, 2002, countries representing 44%
of 1990 carbon dioxide emissions had ratified the Kyoto Protocol.
16
While the United States has yet to adopt comprehensive federal legislation
addressing greenhouse gas emissions, many states have proposed and adopted laws
that have had the purpose or effect of decreasing greenhouse gas emissions. Such
state initiatives have included state renewable energy portfolio standards,
renewable energy incentives for producers of electricity, and carbon dioxide
emission caps for newly constructed electricity generating facilities. Future
federal and state initiatives to control greenhouse gas emissions could result
in electric power generators switching to lower carbon sources of fuel, which
would reduce the demand for our coal. These actions could have a material
adverse effect in 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. Section 404 of CWA imposes permitting and mitigation requirements
associated with the dredging and filling of wetlands and streams. The CWA and
equivalent state legislation, where such equivalent state legislation exists,
affect coal mining operations that impact wetlands and streams. We believe we
have obtained all necessary wetlands permits required under CWA Section 404.
However, mitigation requirements under existing and possible future wetlands
permits may vary considerably. At this time we do not anticipate any increase in
such requirements or in post-mining reclamation accrual requirements. For that
reason, the setting of post-mine reclamation accruals for such mitigation
projects is difficult to ascertain with certainty. We believe that we have
obtained all permits required under the CWA as traditionally interpreted by the
responsible agencies. Although more stringent permitting requirements may be
imposed in the future, we are not able to accurately predict the impact, if any,
of any such permitting requirements.
Each individual state is required to submit to EPA their biennial CWA
Section 303(d) lists identifying all waterbodies not meeting state specified
water quality standards. For each listed waterbody, the state is required to
begin developing a Total Maximum Daily Load (TMDL) to:
- determine the maximum pollutant loading the waterbody can assimilate
without violating water quality standards,
- identify all current pollutant sources and loadings to that waterbody,
- calculate the pollutant loading reduction necessary to achieve water
quality standards, and
- establish a means of allocating that burden among and between the point
and non-point sources contributing pollutants to the waterbody.
We are currently participating in stakeholders meetings and in negotiations
with states and EPA to establish reasonable TMDLs that will accommodate
expansion. These and other regulatory developments may restrict our ability to
develop new mines, or could require our customers or us 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 permits 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
17
impact our reclamation operations where subsidence, or other mining-related
problems, require the provision of drinking water to affected adjacent
homeowners. However, it is unlikely that any of our reclamation activities would
fall within the definition of a "public water system." Accordingly, the SDWA is
unlikely to have a material impact on our operations.
COMPREHENSIVE ENVIRONMENTAL RESPONSE, COMPENSATION AND LIABILITY ACT
(CERCLA)
The Federal CERCLA, also known as the "Superfund" law, and analogous state
laws, impose liability, without regard to fault or the legality of the original
conduct, on certain classes of persons that are considered to have contributed
to the release of a "hazardous substance" into the environment. These persons
include the owner or operator of the site where the release occurred and
companies that disposed or arranged for the disposal of the hazardous substances
found at the site. Persons who are or were responsible for releases of hazardous
substances under CERCLA may be subject to joint and several liability for the
costs of cleaning up the hazardous substances that have been released into the
environment and for damages to natural resources. Some products used by coal
companies in operations generate waste containing hazardous substances. We are
currently unaware of any material liability associated with the release or
disposal of hazardous substances from our past or present mine sites.
RESOURCE CONSERVATION AND RECOVERY ACT (RCRA)
The Federal RCRA affects coal mining operations by imposing requirements for
the generation, transportation, treatment, storage, disposal and cleanup of
hazardous wastes. Many mining wastes are excluded from the regulatory definition
of hazardous wastes, and coal mining operations covered by SMCRA permits are
exempted from regulation under RCRA by statute. RCRA also allows EPA to require
corrective action at sites where there is a release of hazardous substances. In
addition, each state has its own laws regarding the proper management and
disposal of waste material. While these laws impose ongoing compliance
obligations, we do not believe that these costs will have a material impact on
our operations.
COAL COMBUSTION BY-PRODUCTS
In 2000, EPA declined to impose hazardous wastes regulatory controls on the
disposal of some coal combustion by-products, including the practice of using
coal combustion by-products as mine fill. However, EPA is currently evaluating
the possibility of placing additional solid waste burdens on the disposal of
these types of materials, but it may be several years before these standards
will be developed.
While we cannot predict the ultimate outcome of EPA's assessment, we believe
the beneficial uses of coal combustion by-products that we employ (such as the
practice of placing by-products in abandoned mine areas) do not constitute poor
environmental practices because, among other things, our CWA discharge permits
for treated acid mine drainage contain parameters for pollutants of concern,
such as metals, and those permits require monitoring and reporting of effluent
quality data.
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.
Also, the Safe Explosives Act (SEA), a portion of the Homeland Security Act
of 2002, became law on November 25, 2002. The SEA covers all importers,
manufacturers, dealers, and users of explosives. As regular users of explosives,
mining companies are likely to be under special scrutiny in its enforcement.
18
Knowing or willful violations of SEA may result in fines, imprisonment, or both.
In addition, violations of SEA may result in revocation of user permits and
seizure or forfeiture of explosive materials. The SEA becomes effective in two
phases on January 24 and May 24, 2003.
The costs of compliance with these requirements should not have a material
adverse effect on our business, financial condition or results of operations.
EMPLOYEES
To conduct our operations, our managing general partner and its affiliates
employ approximately 1,745 employees, including approximately 100 corporate
employees and approximately 1,645 employees involved in active mining
operations. With the acquisition of Warrior completed in February 2003, our
total number of employees will increase to approximately 1,920 employees. Our
work-force is entirely union-free. Relations with our employees are generally
good.
ITEM 2. PROPERTIES
COAL RESERVES
We must obtain permits from applicable state regulatory authorities before
beginning to mine particular reserves. Applications for permits require
extensive engineering and data analysis and presentation, and must address a
variety of environmental, health, and safety matters associated with a proposed
mining operation. These matters include the manner and sequencing of coal
extraction, the storage, use and disposal of waste and other substances and
other impacts on the environment, the construction of water containment areas,
and reclamation of the area after coal extraction. We are required to post bonds
to secure performance under our permits. As is typical in the coal industry, we
strive to obtain mining permits within a time frame that allows us to mine
reserves as planned on an uninterrupted basis. We begin preparing applications
for permits for areas that we intend to mine sufficiently in advance of our
planned mining activities to allow adequate time to complete the permitting
process. Regulatory authorities have considerable discretion in the timing of
permit issuance, and the public has rights to comment on and otherwise engage in
the permitting process, including intervention in the courts. For the reserves
set forth in the table below, we are not currently aware of matters which would
significantly hinder our ability to obtain future mining permits on a timely
basis.
Our reported coal reserves are those we believe can be economically and
legally extracted or produced at the time of the filing of this Annual Report on
Form 10-K. In determining whether our reserves meet this economical and legal
standard, we take into account, among other things, our potential ability or
inability to obtain a mining permit, the possible necessity of revising a mining
plan, changes in estimated future costs, changes in future cash flows caused by
changes in mining permits, variations in quantity and quality of coal, and
varying levels of demand and their effects on selling prices.
At December 31, 2002, we had approximately 416.5 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 (as defined below). For
information on location of our mines, please read "Mining Operations" under
"Item 1. Business."
The following table sets forth reserve information, at December 31, 2002,
about each of our mining complexes:
19
Heat Proven and Probable Reserves
Content --------------------------------------------- Reserve Assignment
Mine (Btus Pounds SO2 per MMbtu ------------------
Operations Type per pound) <1.2 1.2 - 2.5 >2.5 Total Assigned Unassigned
---------- ---- ---------- ---- --------- ---- ----- -------- ----------
(tons in millions)
Illinois Basin Operations
Dotiki Underground 12,500 - - 100.7 100.7 100.7 -
Pattiki Underground 11,700 - - 49.6 49.6 49.6 -
Hopkins Underground 11,300 - - 20.7 20.7 0.7 20.0
/ Surface - - 10.9 10.9 10.9 -
Gibson (North) Underground 11,600 - 34.9 - 34.9 34.9 -
Gibson (South) Underground 11,600 - 55.0 44.9 99.9 -- 99.9
---- ----- ----- ----- ----- -----
Region Total - 89.9 226.8 316.7 196.8 119.9
---- ----- ----- ----- ----- -----
East Kentucky Operations
Pontiki Underground 12,800 13.4 12.2 - 25.6 25.6 -
MC Mining Underground 12,800 26.2 - - 26.2 26.2 -
---- ----- ----- ----- ----- -----
Region Total 39.6 12.2 - 51.8 51.8 -
---- ----- ----- ----- ----- -----
Maryland Operations
Mettiki Underground 13,000 - 15.8 13.3 29.1 13.3 15.8
Mettiki (WV) Underground 13,000 - - 18.9 18.9 18.9 -
---- ----- ----- ----- ----- -----
- 15.8 32.2 48.0 32.2 15.8
---- ----- ----- ----- ----- -----
Total 39.6 117.9 259.0 416.5 280.8 135.7
==== ===== ===== ===== ===== =====
% of Total 9.5% 28.3% 62.2% 100.0% 67.4% 32.6%
==== ===== ===== ===== ===== =====
Our reserve estimates are prepared from geological data assembled and
analyzed by our staff of geologists and engineers. This data is obtained through
our extensive, ongoing exploration drilling and in-mine channel sampling
programs. Our drill spacing criteria adhere to standards as defined by the U.S.
Geological Survey. The maximum acceptable distance from seam data points varies
with the geologic nature of the coal seam being studied, but generally the
standard for (a) proven reserves is that points of observation are no greater
than 1/2 mile apart and are projected to extend as a 1/4 mile wide belt around
each point of measurement and (b) probable reserves is that points of
observation are between 1/2 and 1 1/2 miles apart and are projected to extend as
a 1/2 mile wide belt that lies 1/4 mile from the points of measurement.
Reserve estimates will change from time to time to reflect mining
activities, additional analysis, new engineering and geological data,
acquisition or divestment of reserve holdings, modification of mining plans or
mining methods, and other factors. Weir International Mining Consultants
performed an overview audit of all of our reserves at March 31, 1999 in
conjunction with our initial public offering.
Reserves represent that part of a mineral deposit that can be economically
and legally extracted or produced, and reflect estimated losses involved in
producing a saleable product. All of our reserves are steam coal. The 39.6
million tons of reserves listed as <1.2 pounds of SO2 per MMbtu are compliance
coal.
Assigned reserves are those reserves that have been designated for mining by
a specific operation.
Unassigned reserves are those reserves that have not yet been designated for
mining by a specific operation.
BTU values are reported on an as shipped, fully washed, basis. Shipments
that are either fully or partially raw will have a lower BTU value.
A permit application relating to 18.9 million tons of reserves controlled by
Mettiki (WV) has been submitted to the West Virginia DEP. We are in the process
of responding to various comments submitted by
20
the West Virginia DEP concerning the permit application. In regard to a
different permit application concerning other coal deposits and reserves, please
read "Item 1. Business; Regulation and Laws; Mining Permits and Approvals"
above.
We control certain leases for coal deposits that are near, but not
contiguous to, our primary reserve bases. The tons controlled by these leases
are classified as non-reserve coal deposits and are not included in our reported
reserves. These non-reserve coal deposits are as follows: Dotiki - 14.1 million
tons, Pattiki - 3.5 million tons, Gibson (North) - 4.1 million tons, and Gibson
(South) - 4.3 million tons.
We lease almost all of our reserves and generally have the right to maintain
leases in force until the exhaustion of minable and merchantable coal located
within the leased premises or a larger coal reserve area. These leases provide
for royalties to be paid to the lessor at a fixed amount per ton or as a
percentage of the sales price. Many leases require payment of minimum royalties,
payable either at the time of the execution of the lease or in periodic
installments, even if no mining activities have begun. These minimum royalties
are normally credited against the production royalties owed to a lessor once
coal production has commenced.
The following table sets forth production data about each of our mining
complexes:
Tons Produced
-------------
Operations 2002 2001 2000 Transportation Equipment
---------- ---- ---- ---- -------------- ---------
(tons in millions)
Illinois Basin Operations
Dotiki 4.5 4.6 3.9 CSX, PAL; truck; barge CM
Pattiki 1.9 1.9 2.3 CSX; truck; barge CM
Hopkins 2.2 2.0 2.1 CSX, PAL; truck DL; CM
Gibson (North) 1.9 1.7 0.1 Truck CM
---- ---- ----
Region Total 10.5 10.2 8.4
---- ---- ----
East Kentucky Operations
Pontiki 1.7 1.7 1.9 NS; truck CM
MC Mining 1.3 1.1 0.8 NS; truck CM
---- ---- ----
Region Total 3.0 2.8 2.7
---- ---- ----
Maryland Operations
Mettiki 2.9 2.7 2.6 Truck; CSX LW; CM
---- ---- ----
Total 16.4 15.7 13.7
==== ==== ====
CSX - CSX Railroad
PAL - Paducah & Louisville Railroad
NS - Norfolk & Southern Railroad
CM - Continuous Miner
DL - Dragline with Stripping Shovel, Front End Loaders and Dozers
LW - Longwall
ITEM 3. LEGAL PROCEEDINGS
We are subject to various types of litigation in the ordinary course of our
business. Disputes with our customers over the provisions of long-term coal
supply contracts arise occasionally and generally relate to, among other things,
coal quality, quantity, pricing, and the existence of force majeure conditions.
Other than the contract dispute with PSI described under "Other" in "Item 8.
Financial Statements and Supplementary Data. - Note 15. Commitments and
Contingencies," we are not involved in any litigation involving any of our
long-term coal supply contracts. However, we cannot assure you that disputes
will not occur or that we will
21
be able to resolve those disputes in a satisfactory manner. We are not engaged
in any litigation that we believe is material to our operations, including under
the various environmental protection statutes to which we are subject. The
information under "General Litigation" under "Item 8. Financial Statements and
Supplementary Data. - Note 15. Commitments and Contingencies" is incorporated
herein by this reference.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITIES HOLDERS
None.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON UNITS AND RELATED
UNITHOLDER MATTERS
The common units representing limited partners' interests are listed on the
Nasdaq National Market under the symbol "ARLP." The common units began trading
on August 20, 1999. On March 18, 2003, the closing market price for the common
units was $21.88 per unit. There were approximately 10,120 record holders and
beneficial owners (held in street name) of common units at December 31, 2002.
The following table sets forth, the range of high and low sales price per
common unit and the amount of cash distribution declared and paid with respect
to the units, for the two most recent fiscal years:
HIGH LOW DISTRIBUTIONS PER UNIT
---- --- ----------------------
1st Quarter 2001 $22.50 $16.63 $0.50 (paid May 15, 2001)
2nd Quarter 2001 $29.99 $20.63 $0.50 (paid August 14, 2001)
3rd Quarter 2001 $25.20 $21.73 $0.50 (paid November 14, 2001)
4th Quarter 2001 $27.45 $22.65 $0.50 (paid February 14, 2002)
1st Quarter 2002 $28.25 $21.71 $0.50 (paid May 15, 2002)
2nd Quarter 2002 $24.70 $21.85 $0.50 (paid August 14, 2002)
3rd Quarter 2002 $25.00 $17.00 $0.50 (paid November 14, 2002)
4th Quarter 2002 $25.20 $20.00 $0.525 (paid February 14, 2003)
We have also issued 6,422,531 subordinated units, all of which are held by
the special general partner, for which there is no established public trading
market.
We will distribute to our partners (including holders of subordinated
units), on a quarterly basis, all of our available cash. "Available cash"
generally means, with respect to any quarter, all cash on hand at the end of
each quarter less cash reserves in the amount necessary or appropriate in the
reasonable discretion of the managing general partner to (a) provide for the
proper conduct of our business, (b) comply with applicable law of any debt
instrument or other agreement of ours or any of its affiliates, and (c) provide
funds for distributions to unitholders and the general partners for any one or
more of the next four quarters. Available cash is defined in our partnership
agreement. Our partnership agreement defines the minimum quarterly distribution
(MQD) 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 the MQD for
22
each quarter during the subordination period and to receive any arrearages in
the distribution of the MQD on the common units for prior quarters during the
subordination period.
The subordination period will end if certain financial tests contained in
the partnership agreement are met for three consecutive four-quarter periods
(testing period), but no sooner than September 30, 2004. During the first
quarter after the end of the subordination period, all of the subordinated units
will convert into common units. Early conversion of a portion of the
subordinated units may occur if the testing period is satisfied before September
30, 2003. We are now in the testing period and, if we continue to meet the
requirements, 50% of the subordinated units will convert into common units
before the end of the subordination period, which will generally not occur
before September 30, 2003, and the remainder will convert in the fourth quarter
of 2004. Our ability to meet these requirements is subject to a number of
economic and operational contingencies. See "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations--Risk Inherent in Our
Business" and "Forward Looking Statements" at the beginning of this report.
ITEM 6. SELECTED FINANCIAL DATA
On August 20, 1999, we completed our initial public offering whereby we
became the successor to the business of our Predecessor. Our selected pro forma
financial data for the year ended December 31, 1999 and our historical financial
data below were derived from our audited consolidated financial statements as of
December 31, 2002, 2001, 2000 and 1999, for the years ended December 31, 2002,
2001 and 2000 and the period from our commencement of operations (on August 20,
1999) to December 31, 1999, the audited combined financial statements of our
Predecessor, as of August 19, 1999, and for the period from January 1, 1999 to
August 19, 1999, and as of and for the year ended December 31, 1998.
23
(in millions, except per unit and per ton data) Partnership Producer
------------------------------------------------------ -----------------
From
Commencement
of Operations (on
Pro Forma August 20, 1999)
Year Ended December 31, Year Ended to
----------------------- December 31, December 31,
2002 2001 2000 1999 (1) 1999
---- ---- ---- -------- ----
STATEMENTS OF INCOME:
Sales and operating revenues
Coal sales $ 478.4 $ 422.0 $ 347.2 $ 345.9 $ 128.8
Transportation revenues (2) 19.0 18.1 13.5 19.1 4.9
Other sales and operating revenues 20.3 6.2 2.8 0.9 0.4
----------- ----------- ----------- ----------- -----------
Total revenues 517.7 446.3 363.5 365.9 134.1
----------- ----------- ----------- ----------- -----------
Expenses
Operating expenses 333.1 308.0 257.4 242.0 89.9
Transportation expenses (2) 19.0 18.1 13.5 19.1 4.9
Outside purchases 46.7 31.8 16.9 24.2 6.4
General and administrative 19.4 17.7 15.2 15.1 6.2
Depreciation, depletion and amortization 47.2 45.5 39.1 39.7 15.1
Interest expense 16.3 16.8 16.6 19.4 5.9
Unusual items (3) - - (9.5) - -
----------- ----------- ----------- ----------- -----------
Total expenses 481.7 437.9 349.2 359.5 128.4
----------- ----------- ----------- ----------- -----------
Income from operations 36.0 8.4 14.3 6.4 5.7
Other income (expense) 0.5 0.8 1.3 1.2 0.6
----------- ----------- ----------- ----------- -----------
Income before income taxes and
Cumulative effect of accounting change 36.5 9.2 15.6 7.6 6.3
Income tax expense 0.2 - - - -
----------- ----------- ----------- ----------- -----------
Income before cumulative effect of
accounting change 36.3 9.2 15.6 7.6 6.3
Cumulative effect of accounting change (4) - 7.9 - - -
----------- ----------- ----------- ----------- -----------
Net income $ 36.3 $ 17.1 $ 15.6 $ 7.6 $ 6.3
=========== =========== =========== =========== ===========
Basic net income per limited partner unit $ 2.31 $ 1.09 $ 0.99 $ 0.48 $ 0.40
=========== =========== =========== =========== ===========
Basic net income per limited partner unit
before accounting change $ 2.31 $ 0.58 $ 0.99 $ 0.48 $ 0.40
=========== =========== =========== =========== ===========
Diluted net income per limited partner unit $ 2.24 $ 1.07 $ 0.98 $ 0.48 $ 0.40
=========== =========== =========== =========== ===========
Diluted net income per limited partner unit
before accounting change $ 2.24 $ 0.57 $ 0.98 $ 0.48 $ 0.40
=========== =========== =========== =========== ===========
Weighted average number of units
outstanding-basic 15,405,311 15,405,311 15,405,311 15,405,311 15,405,311
=========== =========== =========== =========== ===========
Weighted average number of units
outstanding-diluted 15,842,708 15,684,550 15,551,062 15,405,311 15,405,311
=========== =========== =========== =========== ===========
BALANCE SHEET DATA:
Working capital (deficit) $ (16.1) $ (2.3) $ 38.6 $ - $ 61.2
Total assets 288.4 290.9 309.2 - 314.8
Long-term debt 195.0 211.3 226.3 - 230.0
Total liabilities 335.0 337.8 341.0 - 330.7
Net Parent investment - - - - -
Partners' capital (deficit) (46.6) (46.9) (31.8) - (15.9)
OTHER OPERATING DATA:
Tons sold 18.3 17.0 15.0 15.0 5.6
Tons produced 16.4 15.7 13.7 14.1 5.3
Revenues per ton sold (5) $ 27.25 $ 25.19 $ 23.33 $ 23.12 $ 23.07
Cost per ton sold (6) $ 21.81 $ 21.03 $ 19.30 $ 18.75 $ 18.30
OTHER FINANCIAL DATA:
Net cash provided by (used in) operating activities 87.6 63.7 71.4 - (13.9)
Net cash used in investing activities (41.3) (26.2) (41.0) - (43.9)
Net cash provided by (used in) financing activities (46.4) (35.2) (31.4) - 65.8
EBITDA (7) $ 100.0 $ 79.4 $ 71.3 $ 66.7 $ 27.3
Adjusted EBITDA (8) $ 100.0 $ 71.5 $ 61.8 $ 66.7 $ 27.3
Maintenance capital expenditures (9) 29.0 24.4 21.2 6.0 6.0
(in millions, except per unit and per ton data) Predecessor
-----------------------------
For the
period from
January 1, 1999 Year Ended
to December 31,
August 19, ------------
1999 1998
---- ----
STATEMENTS OF INCOME:
Sales and operating revenues
Coal sales $ 217.0 $357.4
Transportation revenues (2) 14.2 41.4
Other sales and operating revenues 0.6 4.5
------- ------
Total revenues 231.8 403.3
------- ------
Expenses
Operating expenses 152.1 237.6
Transportation expenses (2) 14.2 41.4
Outside purchases 17.7 51.2
General and administrative 8.9 15.3
Depreciation, depletion and amortization 24.6 39.8
Interest expense 0.1 0.2
Unusual items (3) - 5.2
------- ------
Total expenses 217.6 390.7
------- ------
Income from operations 14.2 12.6
Other income (expense) 0.5 (0.1)
Income before income taxes and ------- ------
Cumulative effect of accounting change 14.7 12.5
Income tax expense 4.5 3.8
------- ------
Income before cumulative effect of
accounting change 10.2 8.7
Cumulative effect of accounting change (4) - -
------- ------
Net income $ 10.2 $ 8.7
======= ======
Basic net income per limited partner unit
Basic net income per limited partner unit
before accounting change
Diluted net income per limited partner unit
Diluted net income per limited partner unit
before accounting change
Weighted average number of units
outstanding-basic
Weighted average number of units
outstanding-diluted
BALANCE SHEET DATA:
Working capital (deficit) $ 11.2 $ 7.1
Total assets 262.8 261.1
Long-term debt 1.8 1.7
Total liabilities 110.2 108.3
Net Parent investment 151.6 152.8
Partners' capital (deficit) - -
OTHER OPERATING DATA:
Tons sold 9.4 15.1
Tons produced 8.8 13.4
Revenues per ton sold (5) $ 23.15 $23.97
Cost per ton sold (6) $ 19.01 $20.14
OTHER FINANCIAL DATA:
Net cash provided by (used in) operating activities 32.9 50.5
Net cash used in investing activities (21.5) (35.6)
Net cash provided by (used in) financing activities (11.4) (14.9)
EBITDA (7) $ 39.4 $ 52.5
Adjusted EBITDA (8) $ 39.4 $ 57.7
Maintenance capital expenditures (9) 15.5 17.2
(1) The unaudited selected pro forma financial and operating data for the year
ended December 31, 1999, is based on the historical financial statements of
the partnership from our commencement of operations on August 20, 1999,
through December 31, 1999, and our Predecessor for the period from January
1, 1999, through August 19, 1999. The pro forma results of operations
reflect certain pro forma adjustments to the historical results of
operations as if we had been formed on January 1, 1999. The pro forma
adjustments include (a) pro forma interest on debt assumed by us and (b)
the elimination of income tax expense as income taxes will be borne by the
partners and not by us. The pro forma adjustments do not include
approximately $1.0 million of general and administrative expenses that we
believe would have been incurred as a result of its being a public entity.
(2) During the fourth quarter 2000, we adopted the Financial Accounting
Standards Board Emerging Issues Task Force Issue No. 00-10 "Accounting for
Shipping and Handling Fees and Costs" (EITF No. 00-10). We record the cost
of transporting coal to customers through third party carriers and our
corresponding direct reimbursement of these costs through customer
billings. This activity is separately presented as transportation revenue
and expense rather than offsetting these amounts in the consolidated and
combined statements of income. There was no cumulative effect of
24
the accounting change on net income and prior periods presented have been
reclassified to comply with EITF No. 00-10.
(3) Represents income from the final resolution of an arbitrated dispute with
respect to the termination of a long-term contract, net of impairment
charges relating to certain transloading facility assets, partially offset
by expenses associated with other litigation matters in 2000, and the net
loss incurred during the temporary closing of one of our mining complexes
in the second half of 1998.
(4) Represents the cumulative effect of the change in the method of estimating
coal workers' pneumoconiosis ("black lung") benefits liability effective
January 1, 2001. See "Item 7. Management Discussion and Analysis of
Financial Condition and Results of Operations. - Critical Accounting
Policies" and "Item 8. Financial Statements and Supplementary Data. - Note
3. Accounting Change."
(5) Revenues per ton sold is based on the total of coal sales and other sales
and operating revenues divided by tons sold.
(6) Cost per ton sold is based on the total of operating expenses, outside
purchases and general and administrative expenses divided by tons sold.
(7) EBITDA is defined as income before net interest expense, income taxes and
depreciation, depletion and amortization. EBITDA should not be considered
as an alternative to net income, income from operations, 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 the cumulative effect of an accounting
change. EBITDA is not intended to represent cash flow and does not
represent the measure of cash available for distribution. The Partnership's
method of computing EBITDA 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). The table below
shows how the Partnership calculated EBITDA.
(8) Adjusted EBITDA has been adjusted for the cumulative effect of an
accounting change or unusual items, as applicable. The table below shows
how the Partnership calculated Adjusted EBITDA.
Partnership
----------------------------------------------------------------------
From
Commencement
of Operations (on
Pro Forma August 20, 1999)
Year Ended December 31, Year Ended to
----------------------- December 31, December 31,
2002 2001 2000 1999 (1) 1999
---- ---- ---- -------- ----
(in millions)
Net income $ 36.3 $ 17.1 $ 15.6 $ 7.6 $ 6.3
Interest expense 16.3 16.8 16.6 19.4 5.9
Income taxes 0.2 - - - -
Depreciation, depletion and amortization 47.2 45.5 39.1 39.7 15.1
------ ------ ------- ----- ------
EBITDA 100.0 79.4 71.3 66.7 27.3
Cumulative effect of accounting change - (7.9) - - -
Unusual items change - - (9.5) - -
------ ------ ------- ----- ------
Adjusted EBITDA $100.0 $ 71.5 $ 61.8 $66.7 $ 27.3
====== ====== ======= ===== ======
Predecessor
------------------------------
For the
period from
January 1, 1999 Year Ended
to December 31,
August 19, ------------
1999 1998
---- ----
(in millions)
Net income $ 10.2 $ 8.7
Interest expense 0.1 0.2
Income taxes 4.5 3.8
Depreciation, depletion and amortization 24.6 39.8
------ ------
EBITDA 39.4 52.5
Cumulative effect of accounting change - -
Unusual items - 5.2
------ ------
Adjusted EBITDA $ 39.4 $ 57.7
====== ======
(9) Our maintenance capital expenditures, as defined under the terms of our
partnership agreement, are defined as those capital expenditures required
to maintain, over the long term, the operating capacity of our capital
assets. Maintenance capital expenditures for our Predecessor reflect our
historical designation of maintenance capital expenditures.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
GENERAL
The following discussion of our financial condition and results of
operations and our Predecessor should be read in conjunction with the historical
financial statements and notes thereto included elsewhere in this
25
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 and
Note 2. Summary of Significant Accounting Policies."
CRITICAL ACCOUNTING POLICIES
From our Summary of Significant Accounting Policies, we have identified the
following accounting policies that require the exercise of our most difficult,
complex and subjective levels of judgment. Our judgments in the following areas
are principally based on estimates and assumptions that affect the reported
amounts and disclosures in the consolidated financial statements. See "Item 8.
Financial Statements and Supplementary Data." Actual results that are influenced
by future events could materially differ from the current estimates.
LONG-LIVED ASSETS
We review the carrying value of long-lived assets whenever events or changes
in circumstances indicate that the carrying amount may not be recoverable based
upon estimated undiscounted future cash flows. The amount of an impairment is
measured by the difference between the carrying value and the fair value of the
asset, which is based on cash flows from that asset, discounted at a rate
commensurate with the risk involved. Events or changes in circumstance that
could cause the Partnership to perform such a review include, but are not
limited to, the loss of a major coal supply agreement, a significant decline in
demand for the Partnership's coal and an adverse change in geologic conditions.
RECLAMATION AND MINE CLOSING COSTS
The Federal SMCRA and similar state statutes require that mine property be
restored in accordance with specified standards and an approved reclamation
plan. We record the liability for the estimated cost of future mine reclamation
and closing procedures on a present value basis when incurred, and the
associated cost is capitalized by increasing the carrying amount of the related
long-lived asset. Those costs relate to sealing portals at underground mines and
to reclaiming the final pit and support acreage at surface mines. Other costs
common to both types of mining are related to removing or covering refuse piles
and settling ponds, and dismantling preparation plants, other facilities and
roadway infrastructure. We had accrued liabilities of $19.3 million and $16.5
million for these costs at December 31, 2002 and 2001, respectively.
WORKERS' COMPENSATION AND PNEUMOCONIOSIS ("BLACK LUNG") BENEFITS
We provide income replacement and medical treatment for work-related
traumatic injury claims as required by applicable state laws. We provide for
these claims through self-insurance programs. The liability for traumatic injury
claims is the estimated present value of current workers' compensation benefits,
based on an annual actuarial study performed by an independent actuary. The
actuarial calculations are based on a blend of actuarial projection methods and
numerous assumptions including development patterns, mortality, medical costs
and interest rates. We had accrued liabilities of $24.5 million and $22.1
million for these costs at December 31, 2002 and 2001, respectively. A
one-percentage-point reduction in the discount rate would have increased the
liability at December 31, 2002 approximately $0.9 million, which would have a
corresponding increase in operating expenses.
Coal mining companies are subject to the Federal Coal Mine Health and Safety
Act of 1969, as amended, and various state statues for the payment of medical
and disability benefits to eligible recipients related to coal worker's
pneumoconiosis ("black lung"). We provide for these claims through
self-insurance programs. Our estimated black lung liability is based on an
annual actuarial study performed by an independent actuary. The actuarial
calculations are based on numerous assumptions including disability incidence,
medical costs,
26
mortality, death benefits, dependents and interest rates. We had accrued
liabilities of $16.6 million and $15.1 million for these benefits at December
31, 2002 and 2001, respectively. A one-percentage-point reduction in the
discount rate would have increased the expense recognized for the year ended
December 31, 2002 by approximately $0.3 million. Under the service cost method
used to estimate our black lung benefits liability, actuarial gains or losses
attributable to changes in actuarial assumptions such as the discount rate are
amortized over the remaining service period of active miners.
Effective January 1, 2001, we changed our method of estimating black lung
benefits to the service cost method described in Statement of Financial
Accounting Standards ("SFAS") No. 106, "Employer's Accounting for Postretirement
Benefits Other Than Pensions," which method is permitted under SFAS No. 112
"Employers' Accounting for Postemployment Benefits." In January 2001,
governmental regulations regarding the federal black lung benefits claims
approval process became effective. These new regulations specifically define the
black lung disability as progressive and also expand the definition of
pneumoconiosis to mandate consideration of diseases that are caused by factors
other than exposure to coal dust. We believe the change to the SFAS No. 106
measurement methodology better matches black lung costs over the service lives
of the miners who ultimately receive the black lung benefits and is more
reflective of the recently enacted regulations, which place significant emphasis
on coal miners' future years of employment in the coal industry. We previously
accrued the black lung benefits liability at the present value of the
actuarially determined current and future estimated black lung benefit payments
utilizing the methodology prescribed under SFAS No. 5 "Accounting for
Contingencies," which was also permitted by SFAS No. 112.
BUSINESS
We are a diversified producer and marketer of coal to major U.S. utilities
and industrial users. In 2002, our total production was 16.4 million tons and
our total sales were 18.3 million tons. The coal we produced in 2002 was
approximately 29.9% low-sulfur coal, 17.7% medium-sulfur coal and 52.4%
high-sulfur coal.
At December 31, 2002, we had approximately 416.5 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 currently intend to acquire or lease as our
mining operations approach these areas.
In 2002, approximately 87% of our sales tonnage was consumed by electric
utilities with the balance consumed by cogeneration plants and industrial users.
Our largest customers in 2002 were Seminole, SSO, and VEPCO. In 2002,
approximately 88% 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 in the spot market. Our long-term contracts
contribute to our stability and profitability by providing greater
predictability of sales volumes and sales prices. In 2002, approximately 89% 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 have entered into long-term agreements with SSO to host and operate its
coal synfuel production facility currently located at Hopkins, supply the
facility with coal feedstock, assist SSO with the marketing of coal synfuel and
provide it with other services. These agreements expire on December 31, 2007 and
provide us with coal sales, and rental and service fees from SSO based on the
synfuel facility throughput tonnages. These amounts are dependent on the ability
of SSO's members to use certain qualifying tax credits applicable to the
facility. The term of each of these agreements is subject to early cancellation
provisions customary for transactions of these types, including the
unavailability of coal synfuel tax credits, the termination of associated coal
synfuel sales contracts, and the occurrence of certain force majeure events.
Therefore, the continuation of the operating revenues associated with the coal
synfuel production facility cannot be assured. However, we have maintained "back
up" coal supply agreements with each coal synfuel customer that
27
automatically provide for sale of our coal to these customers in the event they
do not purchase coal synfuel from SSO. In conjunction with a decision to
relocate the coal synfuel production facility to Warrior, agreements for
providing certain of these services were assigned to Alliance Service, a
wholly-owned subsidiary of Alliance Coal, in December 2002. Alliance Service is
subject to federal and state income taxes.
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
2002 COMPARED WITH 2001
Coal sales. Coal sales for 2002 increased 13.4% to $478.4 million from
$422.0 million for 2001. The increase of $56.4 million was primarily
attributable to higher price sales contracts secured during the second half of
last year, increased tons associated with coal feedstock for coal synfuel
production, and higher productivity and sales from Gibson. These increases were
partially offset by a decrease in the domestic coal brokerage market. Tons sold
increased 7.6% to 18.3 million for 2002 from 17.0 million in 2001. Tons produced
increased 4.5% to 16.4 million for 2002 from 15.7 million for 2001.
Transportation revenues. Transportation revenues for 2002 increased 5.0% to
$19.0 million from $18.1 million for 2001. The increase of $0.9 million was
primarily attributable to the increase in tons sold. We reflect reimbursement of
the cost of transporting coal to customers through third party carriers as
transportation revenues and the corresponding expense as transportation expense
in the consolidated statements of income. No margin is realized on
transportation revenues.
Other sales and operating revenues. Other sales and operating revenues
increased to $20.3 million for 2002 from $6.2 million for 2001. The increase of
$14.1 million is attributable to additional rental and service fees associated
with increased volumes at a third-party coal synfuel production facility at
Hopkins. See the discussion above under "Business."
Operating expenses. Operating expenses increased 8.2% to $333.1 million for
2002 from $308.0 million for 2001. The increase of $25.1 million is primarily
the result of increased operating costs associated with increased sales volumes
and coal synfuel production.
Transportation expenses. See "Transportation Revenues" above concerning the
increase in transportation expenses.
Outside purchases. Outside purchases increased to $46.7 million for 2002
from $31.8 million for 2001. The increase of $14.9 million is primarily the
result of outside purchases necessary to fulfill feedstock contract commitments
at Hopkins, offset by a decrease in the activity in the domestic coal brokerage
market.
General and administrative. General and administrative expenses increased
9.5% to $19.4 million for 2002 from $17.7 million for 2001. The increase of $1.7
million was primarily attributable to higher accruals
28
related to the Short-Term Incentive Plan, combined with additional restricted
units granted under the Long-Term Incentive Plan.
Depreciation, depletion and amortization. Depreciation, depletion and
amortization expenses increased 3.9% to $47.2 million for 2002 from $45.5
million for 2001. The increase of $1.7 million primarily resulted from
additional depreciation expense associated with the new Gibson Complex.
Interest expense. Interest expense decreased 2.8% to $16.3 million for 2002
from $16.8 million for 2001. The decrease of $0.5 million primarily reflects
debt reduction due to scheduled debt payments.
Income taxes. Although we are not a taxable entity for federal or state
income tax purposes, our subsidiary, Alliance Service is subject to federal and
state income taxes. In conjunction with a decision to relocate the coal synfuel
facility, agreements for a portion of the services provided to the coal synfuel
producer were assigned to Alliance Service in December 2002. Income taxes were
not incurred in 2001. In 2003, income taxes are estimated to be between $1.3
million and $1.8 million.
EBITDA (income before net interest expense, income taxes, depreciation,
depletion and amortization) increased 26.0% to $100.0 million for 2002 compared
with $79.4 million for 2001. The 2001 results include the benefit of a
cumulative effect of accounting change totaling $7.9 million related to a change
in the method of estimating the black lung benefits liability. Excluding the
benefit of the accounting change during 2001, EBITDA for 2002 increased $28.5
million or 40.1%. The $28.5 million increase in EBITDA, after excluding the
effect of the accounting change, is primarily attributable to higher price sales
contracts, increased volumes associated with coal synfuel related agreements,
and higher sales volume at Gibson. For an explanation of EBITDA and a
reconciliation of EBITDA to net income, please read footnotes 7 and 8 to "Item
6. Selected Financial Data."
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 or the
cumulative effect of an accounting change. EBITDA is not intended to represent
cash flow and does not represent the measure of cash available for distribution.
Our method of computing EBITDA also may not be the same method used to compute
similar measures reported by other companies, or EBITDA may be computed
differently by us in different contexts (i.e., public reporting versus
computation under financing agreements).
2001 COMPARED WITH 2000
Coal sales. Coal sales for 2001 increased 21.5% to $422.0 million from
$347.2 million for 2000. The increase of $74.8 million was primarily
attributable to higher price sales contracts and volumes reflecting increased
utility demand, increased activity in the domestic coal brokerage market due to
favorable spot price levels and additional revenues from the new Gibson Complex,
which opened in late 2000. Tons sold increased 13.3% to 17.0 million for 2001
from 15.0 million in 2000. Tons produced increased 14.9% to 15.7 million for
2001 from 13.7 million for 2000.
Transportation revenues. Transportation revenues for 2001 increased 33.9% to
$18.1 million from $13.5 million for 2000. The increase of $4.6 million was
primarily attributable to the increase in tons sold. We reflect reimbursement of
the cost of transporting coal to customers through third party carriers as
transportation revenues and the corresponding expense as transportation expense
in the consolidated statements of income. No margin is realized on
transportation revenues.
Other sales and operating revenues. Other sales and operating revenues
increased to $6.2 million for 2001 from $2.8 million for 2000. The increase of
$3.4 million is attributable to additional service fees associated
29
with increased volumes at a third party coal synfuel production facility at
Hopkins. See the discussion immediately above under "Business."
Operating expenses. Operating expenses increased 19.7% to $308.0 million for
2001 from $257.4 million for 2000. The increase of $50.6 million resulted from
increased sales volumes as well as additional operating expenses associated with
a full year of operation at Gibson, which opened in late 2000, and difficult
mining conditions encountered at several operations. Those difficult mining
conditions placed an undue burden on equipment scheduled for replacement,
resulting in unanticipated equipment failures and higher maintenance costs.
Transportation expenses. See "Transportation Revenues" above concerning the
increase in transportation expenses.
Outside purchases. Outside purchases increased to $31.8 million for 2001
from $16.9 million for 2000. The increase of $14.9 million resulted from
increased activity in the domestic coal brokerage market due to improved profit
margins on spot coal sales, which resulted in increased volumes at higher
purchase prices. The higher brokerage volumes are largely attributable to
short-term opportunities in the domestic coal brokerage markets, which are not
expected to be material in the future.
General and administrative. General and administrative expenses increased
16.8% to $17.7 million for 2001 from $15.2 million for 2000. The increase of
$2.5 million was primarily attributable to higher accruals related to the
Short-Term Incentive Plan, combined with additional restricted units granted
under the Long-Term Incentive Plan. The Long-Term Incentive Plan accrual is
impacted by the increased market value of our common units.
Depreciation, depletion and amortization. Depreciation, depletion and
amortization expenses increased 16.1% to $45.5 million for 2001 from $39.1
million for 2000. The increase of $6.4 million primarily resulted from
additional depreciation expense associated with a full year of operation at
Gibson, which opened in late 2000.
Interest expense. Interest expense was comparable for 2001 and 2000 at $16.8
million and $16.6 million, respectively.
Cumulative effect of accounting change. Effective January 1, 2001, we
changed our method of estimating our black lung benefits liability. See the
discussion above under "Workers' Compensation and Pneumoconiosis ("Black Lung")
Benefits."
EBITDA (income before net interest expense, income taxes, depreciation,
depletion and amortization) increased 11.3% to $79.4 million for 2001 compared
with $71.3 million for 2000. Excluding the net benefits of the change in
accounting method in 2001 and the unusual items in 2000, EBITDA for 2001 was
$71.4 million, compared to $61.8 million for 2000. The $9.6 million increase was
primarily attributable to higher price sales contracts and volumes reflecting
increased utility demand during 2001 and a full year of operations at Gibson,
which opened in late 2000, and the increased revenue from the third party coal
synfuel facility at Hopkins. For an explanation of EBITDA and a reconciliation
of EBITDA to net income, please read footnotes 7 and 8 to "Item 6. Selected
Financial Data."
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 or the
cumulative effect of an accounting change. EBITDA is not intended to represent
cash flow and does not represent the measure of cash available for distribution.
Our method of computing EBITDA also may not be the same
30
method used to compute similar measures reported by other companies, or EBITDA
may be computed differently by us in different contexts (i.e., public reporting
versus computation under financing agreements).
OUTLOOK
Ongoing Acquisition Activities
Consistent with our business strategy, from time-to-time we engage in
discussions with potential sellers regarding the possible purchase by us of coal
production and marketing assets.
Sarbanes-Oxley Act and New SEC Rules
Several regulatory and legislative initiatives were introduced in 2002 in
response to developments during 2001 and 2002 regarding accounting issues at
large public companies, resulting in disruptions in the capital markets and
ensuing calls for action to prevent repetition of those events. We support the
actions called for under these initiatives and believe these steps will
ultimately be successful in accomplishing the stated objectives. However,
implementation of reforms in connection with these initiatives will add to the
costs of doing business for all publicly-traded entities, including us. These
costs will have an adverse impact on future income and cash flow, especially in
the near term as legal, financial and consultant costs are incurred to analyze
the new requirements, formalize current practices and implement required changes
to ensure that we maintain compliance with these new rules. We are not able to
estimate the magnitude of increase in our costs that will result from such
reforms.
LIQUIDITY AND CAPITAL RESOURCES
LIQUIDITY
We generally satisfy our working capital requirements and fund our capital
expenditures and debt service obligations from cash generated from operations
and borrowings under our revolving credit facility. We believe that the cash
generated from operations and our borrowing capacity will be sufficient to meet
our working capital requirements, anticipated capital expenditures (other than
major capital improvements or acquisitions), scheduled debt payments and MQD
payments. To further develop available financing alternatives, in October 2002,
we entered into a master lease agreement. Under the master lease agreement,
lease terms and rental payments are negotiated individually when specific pieces
of equipment are leased. We had no equipment leased under the master equipment
lease at December 31, 2002. Selected pieces of equipment will be leased in 2003
when the lease terms are considered favorable. Our credit facilities limit the
amount of total operating lease obligations to $10 million payable in any period
of 12 consecutive months. Our ability to satisfy our obligations and planned
expenditures will depend upon our future operating performance, which will be
affected by prevailing economic conditions in the coal industry, some of which
are beyond our control.
CASH FLOWS
Cash provided by operating activities was $87.6 million in 2002, compared to
$63.7 million in 2001. The increase in cash provided by operating activities was
principally attributable to operating income and working capital changes during
2002 compared to 2001.
Net cash used in investing activities was $41.3 million in 2002, compared to
net cash used in investing activities of $26.2 million in 2001. The increased
use of cash is principally attributable to reduced liquidation of marketable
securities, net of purchases, during 2002 compared to 2001.
31
Net cash used in financing activities was $46.4 million for 2002, compared
to net cash used in financing activities of $35.2 million for 2001. Cash used in
financing activities during 2002 and 2001 was a direct result of eight quarterly
distributions of $0.50 per unit on common and subordinated units outstanding.
The quarterly cash distribution was increased to $0.525 per unit with respect to
the fourth quarter of 2002, which was paid in February 2003. We expect to
maintain this level of quarterly cash distribution during 2003. Additionally,
during 2002 and 2001, we made scheduled debt payments of $15.0 million and $3.75
million, respectively.
We have various commitments primarily related to long-term debt, operating
lease commitments related to buildings and equipment, obligations for estimated
reclamation and mining closing costs, capital project commitments, and pension
funding. We expect to fund these commitments with cash generated from
operations, proceeds from marketable securities, and borrowings under our
revolving credit facility. The following table provides details regarding our
contractual cash obligations as of December 31, 2002:
Less
Contractual than 1 2-3 4-5 After 5
Obligations Total year years years years
----------- ----- ---- ----- ----- -----
Long-Term Debt $211,250 $ 16,250 $ 33,000 $ 36,000 $126,000
Operating Leases 24,633 3,375 6,777 6,268 8,213
Other Long-Term Obligations
(excluding discount effect of $12.4
million for reclamation liability) 31,754 1,186 6,428 2,430 21,710
Capital projects 6,010 6,010 - - -
Pension liability 5,645 5,300 345 - -
-------- -------- -------- -------- --------
$279,292 $ 32,121 $ 46,550 $ 44,698 $155,923
======== ======== ======== ======== ========
CAPITAL EXPENDITURES
Capital expenditures decreased to $51.5 million in 2002, compared to $53.7
million in 2001. The decrease is principally attributable to capital
expenditures related to capital for a new service shaft at Dotiki and extension
into the Pattiki II coal reserve, offset by the completion of Gibson during
2001.
In February 2003, we acquired Warrior from an affiliate, ARH Warrior
Holdings, pursuant to the terms of a previously existing agreement. Warrior owns
an underground mining complex located between and adjacent to our other Western
Kentucky operations near Madisonville, Kentucky. The operation utilizes
continuous mining units employing room-and-pillar mining techniques producing
high-sulfur coal. Since January 2002, substantially all of the coal produced by
Warrior has been sold to Hopkins for subsequent resale to SSO for use as
feedstock in the production of coal synfuel. Since 2001, Warrior invested in new
infrastructure capital projects that are expected to improve Warrior's
productivity and significantly increase Warrior's annual production capacity. We
plan to transfer an additional continuous mining unit to Warrior in the second
quarter of 2003, to supplant other operations of the Partnership that will be
depleting.
We paid $12.7 million to ARH Warrior Holdings in accordance with the terms
of an Amended and Restated Put and Call Option Agreement. In addition, we repaid
Warrior's borrowings of $17.0 million under the revolving credit agreement
between an affiliate of ARH Warrior Holdings and Warrior. We funded the Warrior
acquisition through a portion of the proceeds received from the issuance of
2,250,000 common units in February 2003.
As a result of the Warrior acquisition, we currently project that our
average annual maintenance capital expenditures will increase to $32 million,
which figure includes capital equipment that may be leased under the master
equipment lease discussed above. We also currently expect to fund our
anticipated capital
32
expenditures, with the exception of the Warrior acquisition described above,
with cash generated from operations and borrowings under our revolving credit
facility described below.
UNIVERSAL SHELF
In April 2002, we filed with the Securities and Exchange Commission a
universal shelf registration statement allowing us to issue from time-to-time up
to an aggregate of $250 million of debt or equity securities. At March 15, 2003,
we had approximately $192.9 million available under this registration statement.
NOTES OFFERING AND CREDIT FACILITY
Concurrently with the closing of our initial public offering, the special
general partner issued and the intermediate partnership assumed the obligations
with respect to $180 million principal amount of 8.31% senior notes due August
20, 2014 (Senior Notes). The special general partner also entered into, and the
intermediate partnership assumed the obligations under, a $100 million credit
facility (Credit Facility). The Credit Facility consists of three tranches,
including a $50 million term loan facility, a $25 million working capital
facility, and a $25 million revolving credit facility. We had borrowings
outstanding of $31.3 million and $46.3 million under the term loan facility and
no borrowings outstanding under either the working capital facility or the
revolving credit facility at December 31, 2002, and 2001, respectively. The
interest rates on the term loan facility at December 31, 2002, and 2001, were
4.31% and 3.40%, respectively. The Credit Facility expires August 2004. The
Senior Notes and Credit Facility are guaranteed by all of the subsidiaries of
the intermediate partnership. The Senior Notes and Credit Facility contain
various restrictive and affirmative covenants, including the amount of
distributions by the intermediate partnership and the incurrence of other debt.
We were in compliance with the covenants of both the Credit Facility and Senior
Notes at December 31, 2002 and 2001.
We have entered into agreements with three banks to provide letters of
credit in an aggregate amount of $35.0 million to maintain surety bonds to
secure its obligations for reclamation liabilities and workers' compensation
benefits. At December 31, 2002, we had $21.6 million in letters of credit
outstanding. The special general partner guarantees the letters of credit.
RELATED PARTY TRANSACTIONS
Administrative Services
Our partnership agreement provides that our managing general partner and its
affiliates be reimbursed for all direct and indirect expenses it incurs or
payments it makes on our behalf; including, but not limited to, management's
salaries and related benefits, and accounting, budget, planning, treasury,
public relations, land administration, environmental, permitting, payroll,
benefits, disability, workers' compensation management, legal and information
technology services. Our managing general partner may determine in its sole
discretion the expenses that are allocable to us. Total costs billed by our
managing general partner and its affiliates to us were approximately $6,559,000,
$6,503,000, and $3,899,000 for the years ended December 31, 2002, 2001 and 2000,
respectively.
Warrior Coal Acquisition
On February 14, 2003, we acquired Warrior from an affiliate, ARH Warrior
Holdings a subsidiary of Alliance Resource Holdings, pursuant to an Amended and
Restated Put and Call Option Agreement (Put/Call Agreement). Warrior purchased
the capital stock of Roberts Bros. Coal Co., Inc., Warrior Coal Mining Company,
Warrior Coal Corporation and certain assets of Christian Coal Corp. and Richland
Mining Co., Inc.
33
in January 2001. Our managing general partner had previously declined the
opportunity to purchase these assets as we had previously committed to major
capital expenditures at two existing operations. As a condition to not
exercising its right of first refusal, we requested that ARH Warrior Holdings
enter into a put and call arrangement for Warrior. We and ARH Warrior Holdings,
with the approval of the Conflicts Committee of our managing general partner,
entered into the Put/Call Agreement in January 2001. Concurrently, ARH Warrior
Holdings acquired Warrior in January 2001 for $10.0 million.
The Put/Call Agreement preserved the opportunity for us to acquire Warrior
during a specified time period at a price significantly greater than the price
paid by ARH Warrior Holdings. Under the terms of the Put/Call Agreement, ARH
Warrior Holdings exercised its put option requiring us to purchase Warrior at a
put option price of approximately $12.7 million.
The option provisions of the Put/Call Agreement were subject to certain
conditions (unless otherwise waived), including, among others, (a) the
non-occurrence of a material adverse change in the business and financial
condition of Warrior, (b) the prohibition of any dividends or other
distributions to Warrior's shareholders, (c) the maintenance of Warrior's assets
in good working condition, (d) the prohibition on the sale of any equity
interest in Warrior except for the options contained in the Put/Call Agreement,
and (e) the prohibition on the sale or transfer of Warrior's assets except those
made in the ordinary course of its business.
The Put/Call Agreement option prices reflected negotiated sale and purchase
amounts that both parties determined would allow each party to satisfy
acceptable minimum investment returns in the event either the put or call
options were exercised. In January 2001 and in December 2002, we developed
financial projections for Warrior based on due diligence procedures we
customarily perform when considering the acquisition of a coal mine. The
assumptions underlying the financial projections made by us for Warrior
included, among others, (a) annual production levels ranging from 1.5 million to
1.8 million tons, (b) coal prices at or below the then current coal prices and
(c) a discount rate of 12 percent. Based on these financial projections, as of
December 31, 2002 and 2001, we believe that the fair value of Warrior was equal
to or greater than the put option exercise price.
The put option price of $12.7 million was paid to ARH Warrior Holdings in
accordance with the terms of the Put/Call Agreement, under which the put option
period was extended through February 28, 2003. In addition, we repaid Warrior's
borrowings of $17.0 million under the revolving credit agreement between the
special general partner and Warrior. The primary borrowings under the revolving
credit agreement financed new infrastructure capital projects at Warrior that
are expected to improve productivity and significantly increase capacity. We
funded the Warrior acquisition through a portion of the proceeds received from
the issuance of 2,250,000 common units. Based upon our current financial
projections, we continue to believe that the fair value of Warrior is equal to
or greater than the put option exercise price. Because the Warrior acquisition
was between entities under common control, it will be accounted for at
historical cost in a manner similar to that used in a pooling of interests.
Under the terms of the Put/Call Agreement, we assumed certain other
obligations, including a mineral lease and sublease with SGP Land, LLC (SGP
Land), a subsidiary of our special general partner, covering coal reserves that
have been and will continue to be mined by Warrior. The terms and conditions of
the mineral lease and sub-lease remain unchanged.
During 2002 and 2001, we provided management and administrative services to
Warrior under an administrative service agreement. Under this agreement, we
recognized approximately $929,000 and $1,019,000 as a reduction of general and
administrative expenses during the years ended December 31, 2002 and 2001,
respectively.
34
During 2001, we entered into an agreement with Warrior to perform certain
reclamation procedures for us. The total estimated cost of the reclamation
procedures covered by this agreement is $475,000 of which approximately $97,000
and $160,000 was paid to Warrior for the years ended December 31, 2002 and
2001, respectively.
During 2002 and 2001, we made coal purchases of approximately $36,700,000 and
$3,135,000, respectively, from Warrior. Accounts payable to Warrior of
$3,400,000 and $1,876,000 is included in the amount due to affiliates at
December 31, 2002 and 2001, respectively. During 2002, we made coal sales of
approximately $3.5 million to Warrior. Accounts receivable from Warrior of $1.4
million offsets a portion of the amount due to affiliates at December 31, 2002.
SGP Land
We have a mineral lease and sublease with SGP Land requiring annual minimum
royalty payments of $2.7 million, payable in advance through 2013 or until $37.8
million of cumulative annual minimum and/or earned royalty payments have been
paid. We paid annual minimum royalties of $2.7 million during each of the three
years in the period ended December 31, 2002.
We also have an option to lease and/or sublease certain reserves from SGP
Land, which reserves are contiguous to Hopkins. Under the terms of the option to
lease and sublease, we paid option fees of $684,000 during the years ended
December 31, 2002 and 2001. The anticipated annual minimum royalty obligation is
$684,000, payable in advance, from 2003 through 2009.
In 2001, SGP Land, as successor in interest to an unaffiliated third party,
entered into an amended mineral lease with MC Mining. Under the terms of the
lease, MC Mining has paid and will continue to pay an annual minimum royalty
obligation of $300,000 until $6.0 million of cumulative annual minimum and/or
earned royalty payments have been paid. MC Mining paid royalties of $568,000 and
$705,000 for the years ended December 31, 2002 and 2001, respectively.
Special General Partner
Effective January 2001, Gibson entered into a noncancelable operating lease
arrangement with the Special GP for its coal preparation plant and ancillary
facilities. Based on the terms of the lease, Gibson has paid and will continue
to make monthly payments of approximately $216,000 through January 2011. Lease
expense incurred for the three years in the period ended December 31, 2002 was
$2,595,000.
We have entered into agreements with three banks to provide letters of
credit in an aggregate amount of $35.0 million to maintain surety bonds to
secure our obligations for reclamation liabilities and workers' compensation
benefits. At December 31, 2002, we had $21.6 million in outstanding letters of
credit. Our special general partner guarantees these letters of credit, and as a
result we have agreed to compensate our special general partner a guarantee fee
equal to 0.30% per annum of the face amount of the letters of credit
outstanding. We paid approximately $48,200 and $8,800 in guarantee fees to our
special general partner for the years ended December 31, 2002 and 2001,
respectively.
ACCRUALS OF OTHER LIABILITIES
We had accruals for other liabilities, including current obligations,
totaling $70.8 million and $61.0 million at December 31, 2002 and 2001. These
accruals were chiefly comprised of workers' compensation benefits, black lung
benefits, and costs associated with reclamation and mine closings. These
obligations are self-insured. The accruals of these items were based on
estimates of future expenditures based on current legislation, related
regulations and other developments. Thus, from time to time, our results of
operations may
35
be significantly affected by changes to these liabilities. See "Item 8.
Financial Statements and Supplementary Data. - Note 12. Reclamation and Mine
Closing Costs" and "Note 13. Pneumoconiosis ("Black Lung") Benefits."
PENSION PLAN
We maintain a defined benefit pension plan (Pension Plan), which covers
certain employees at the mining operations.
Our pension expense was approximately $2,200,000 and $2,000,000 for the
years ended December 31, 2002 and 2001, respectively. The pension expense is
based upon a number of actuarial assumptions, including an expected long-term
rate of return on our Pension Plan assets of 9.0% and a discount rate of 7.25%
and 7.50% for the years ended December 31, 2002 and 2001, respectively.
Additionally, we base our determination of pension expense on an unsmoothed
market-related valuation of assets equal to the fair value of assets, which
immediately recognizes all investment gains or losses.
In developing our expected long-term rate of return assumption, we
evaluated input from our investment manager, including their review of asset
class return expectations by economists, and our actuary. Historically, we have
assumed that our investment managers will generate long-term returns of at least
9.0%. Effective January 1, 2003, we adjusted our assumption of long-term return
to at least 8.0%. Our advisors base the projected returns on broad equity and
bond indices. Our expected long-term rate of return on Pension Plan assets is
based on an asset allocation assumption of 80.0% with equity managers, with an
expected long-term rate of return of 10.7%, and 20.0% with fixed income
managers, with an expected long-term rate of return of 5.3%. We regularly review
our actual asset allocation and periodically rebalance our investments to our
targeted allocation when considered appropriate.
The discount rate that we utilize for determining our future pension
obligation is based on a review of currently available high-quality fixed-income
investments that receive one of the two highest ratings given by a recognized
rating agency. We have historically used the average monthly yield for December
of an Aa-rated utility bond index as the primary benchmark for establishing the
discount rate. The duration of the bonds that comprise this index is comparable
to the duration of the benefit obligation in the Pension Plan. The discount rate
determined on this basis decreased from 7.25% at December 31, 2001 to 6.75% at
December 31, 2002.
We estimate that our Pension Plan expense and cash contributions will be
approximately $3,180,000 and $5,300,000, respectively in 2003. Future actual
pension expense and contributions will depend on future investment performance,
changes in future discount rates and various other factors related to the
employees participating in the Pension Plan.
Lowering the expected long-term rate of return assumption by 1.0% (from
9.0% to 8.0%) at December 31, 2001 would have increased our pension expense for
the year ended December 31, 2002 by approximately $120,000. Lowering the
discount rate assumption by 0.5% (from 7.25% to 6.75%) at December 31, 2001
would have increased our pension expense for the year ended December 31, 2002 by
approximately $130,000.
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 three years in the
period ended December 31, 2002.
36
RECENT ACCOUNTING PRONOUNCEMENTS
Effective January 1, 2002, we adopted Statement of Financial Accounting
Standards ("SFAS") No. 142 "Goodwill and Intangible Assets." This standard
discontinues the practice of amortizing goodwill and indefinite lived intangible
assets and initiates an annual review for impairment. This standard had no
material effect on our consolidated financial statements upon adoption.
In August 2001, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 143, "Accounting for Asset Retirement Obligations," which requires the
fair value of a liability for an asset retirement obligation to be recognized in
the period in which it is incurred. When the liability is initially recorded, a
cost is capitalized by increasing the carrying amount of the related long-lived
asset. Over time, the liability is accreted to its present value for each
period, and the capitalized cost is depreciated over the useful life of the
related asset. To settle the liability, the obligation for its recorded amount
is paid or a gain or loss upon settlement is incurred. Since we historically
adhered to accounting principles similar to SFAS No. 143 in accounting for
reclamation and mine closing costs, we do not believe that adoption of SFAS No.
143, effective January 1, 2003, will have a material impact on our financial
statements.
Effective January 1, 2002, the Partnership adopted SFAS No. 144,
"Accounting for the Impairment or Disposal of Long-Lived Assets." This standard
had no material effect on our consolidated financial statements upon adoption.
In November 2002, the FASB issued Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others." This interpretation elaborates on the
disclosures to be made by a guarantor in its financial statements about its
obligations under certain guarantees that it has issued. It also requires a
guarantor to recognize, at the inception of a guarantee, a liability for the
fair value of the obligations it has undertaken in issuing the guarantee. The
initial recognition and initial measurement provisions of the interpretation are
applicable on a prospective basis to guarantees issued or modified after
December 31, 2002. The disclosure requirements are effective for financial
statements of interim or annual periods ending after December 15, 2002. We do
not believe this interpretation will have a material effect on our financial
statements upon adoption.
RISK FACTORS
If any of the following risks were actually to occur, our business,
financial condition or results of operations could be materially adversely
affected and the trading price of our common units could decline.
RISKS INHERENT IN OUR BUSINESS
- A substantial or extended decline in coal prices could negatively
impact our results of operations.
- Several of our customers have had their credit rating down-graded, and
one customer recently filed for bankruptcy. While we have not received
notice of, and otherwise are not aware of, the intent of any of these
customers to default on their contractual obligations to us, the
lowered credit ratings and the bankruptcy filing of these customers
indicate that this is a possibility.
- Several coal companies that compete with us have recently filed for
bankruptcy protection. If they emerge from bankruptcy with their debt
burden reduced or eliminated, those companies may possess a
significant competitive advantage over us.
- A material portion of our net income and cash flow is dependent on the
continued ability by us or others to realize benefits from state and
federal tax credits. If the benefit to us from any of these tax
credits is
37
materially reduced, it could have a material adverse effect on our
operations and might impair our ability to pay the distributions on
our units.
- 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.
- Most newly constructed power plants may be fueled by natural gas. Any
change in consumption patterns by utilities away from the use of coal
could affect our ability to sell the coal we produce.
- From time to time conditions in the coal industry may make it more
difficult for us to extend existing or enter into new long-term
contracts. This could affect the stability and profitability of our
operations.
- Some of our long-term contracts contain provisions allowing for the
renegotiation of prices and, in some instances, the termination of the
contract or the suspension of purchases by customers.
- Some of our long-term contracts require us to supply all of our
customers coal needs. If these customers' coal requirements decline,
our revenues under these contracts will also drop.
- A substantial portion of our coal has a high-sulfur content. This coal
may become more difficult to sell because the Clean Air Act may impact
the ability of electric utilities to burn high-sulfur coal through the
regulation of emissions.
- We depend on a few customers for a significant portion of our
revenues, and the loss of one or more significant customers could
impact our ability to sell the coal we produce.
- Litigation relating to disputes with our customers may result in
substantial costs, liabilities and loss of revenues.
- The term of each of the agreements associated with the coal synfuel
facility at Hopkins is subject to early cancellation provisions
customary for transactions of these types, including the
unavailability of synfuel tax credits, the termination of associated
coal synfuel sales contracts, and the occurrence of certain force
majeure events. Therefore, the continuation of the operating revenues
associated with the coal synfuel production facility cannot be
assured.
- Any loss of the benefit from state tax credits may affect adversely
our ability to pay distributions.
- Coal mining is subject to inherent risks that are beyond our control
and these risks may not be fully covered under our insurance policies.
- Although none of our employees are members of unions, our work force
may not remain union-free in the future.
- Any significant increase in transportation costs or disruption of the
transportation of our coal may impair our ability to sell coal.
- We may not be able to grow successfully through future acquisitions,
and we may not be able to effectively integrate the various businesses
or properties we do acquire.
- Our business may be adversely affected if we are unable to replace our
coal reserves.
38
- The estimates of our reserves may prove inaccurate, and unitholders
should not place undue reliance on these estimates.
- Cash distributions are not guaranteed and may fluctuate with our
performance. In addition, our managing general partner's discretion in
establishing reserves may negatively impact a unitholder's receipt of
cash distributions.
- Our indebtedness may limit our ability to borrow additional funds,
make distributions to unitholders or capitalize on business
opportunities.
RISKS INHERENT IN AN INVESTMENT IN THE PARTNERSHIP
- Under our management's buy-out agreement with The Beacon Group, under
some circumstances The Beacon Group may assume control of the business
and affairs of our general partner.
- The president and chief executive officer of our managing general
partner effectively controls us through his ownership of a majority of
the equity interests in our managing general partner and an affiliate.
- Unitholders have limited voting rights and do not control our managing
general partner.
- We may issue additional common units without the approval of common
unitholders, which would dilute existing unitholders' interests.
- The issuance of additional common units, including upon conversion of
subordinated units, will increase the risk that we will be unable to
pay the full minimum quarterly distribution on all common units.
- Cost reimbursements to our general partners may be substantial and
will reduce our cash available for distribution.
- Our managing general partner has a limited call right that may require
unitholders to sell their common units at an undesirable time or
price.
- Unitholders may not have limited liability under some circumstances.
- Our general partners and their affiliates, which are controlled by our
management, may in some instances engage in activities that compete
directly with us.
REGULATORY RISKS
- A recent federal district court decision, currently on appeal, extends
prohibitions previously applicable only to surface mines to
underground mines, which could limit our ability to conduct
underground mining operations.
- Federal and state laws require bonds to secure our obligations related
to (a) the statutory requirement that we return mined property to its
approximate original condition and (b) workers compensation. Due to
problems in the surety industry, like other mine operators we may have
difficulty maintaining our surety bonds for mine reclamation as well
as workers' compensation and black lung benefits. At December 31,
2002, we had $58.8 million of surety bonds in place. Our failure to
maintain, or inability
39
to acquire, surety bonds that are required by state and federal law
would have a material adverse effect on us.
- We are subject to federal, state and local regulations on health,
safety, environmental and numerous other matters. These regulations
increase our costs of doing business, or discourage customers from
buying our coal.
- We have black lung benefits and workers' compensation obligations that
could increase if new legislation is enacted.
- The Clean Air Act affects our customers and could significantly
influence their purchasing decisions. New regulations under the Clean
Air Act could also reduce demand for our coal.
- The passage of state and federal legislation responsive to concerns
over emissions of greenhouse gases such as carbon dioxide could result
in a reduced use of coal by electric power generators. Any such
reduction in use could adversely affect our revenues and results of
operations.
- We are subject to the Clean Water Act which imposes limitations, and
monitoring and reporting obligations, on our discharge of pollutants
into water. Those limitations and obligations may become more
stringent and result in restricted operations and increased costs.
- We are subject to the Safe Drinking Water Act, which imposes various
requirements on us.
- We are subject to reclamation, mine closure and real property
restoration regulatory obligations and must accrue for the estimated
cost of complying with these regulations.
- We could incur significant costs under federal and state Superfund and
waste management statutes.
TAX RISKS TO COMMON UNITHOLDERS
- Our tax treatment depends on our status as a partnership for federal
income tax purposes, as well as our not being subject to entity-level
taxation by states. If the IRS treats us as a corporation or we become
subject to entity-level taxation for state tax purposes, it would
substantially reduce distributions to our unitholders and our ability
to make payments on our debt securities.
- We have not requested an IRS ruling with respect to our tax treatment.
- You may be required to pay taxes on income from us even if you receive
no cash distributions.
- Tax gain or loss on disposition of common units could be different
than expected.
- Common unitholders, other than individuals who are U.S. residents, may
experience adverse tax consequences from owning common units.
- We have registered with the IRS as a tax shelter. This may increase
the risk of an IRS audit of us or a common unitholder.
- We treat a purchaser of common units as having the same tax benefits
as the seller. The IRS may challenge this treatment, which could
adversely affect the value of common units.
40
- Common unitholders will likely be subject to state and local taxes as
a result of an investment in common units.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We have significant long-term coal supply agreements. Virtually all of the
long-term coal supply agreements are subject to price adjustment provisions,
which permit an increase or decrease periodically in the contract price to
principally reflect changes in specified price indices or items such as taxes,
royalties or actual production costs. For additional discussion of coal supply
agreements, see "Item 1. Business. - Coal Marketing and Sales" and "Item 8.
Financial Statements and Supplementary Data. - Note 16. Concentration of Credit
Risk and Major Customers."
Almost all of our Predecessor's transactions were, and all of our
transactions are, denominated in U.S. dollars, and as a result, we do not have
material exposure to currency exchange-rate risks.
We do not engage in any interest rate, foreign currency exchange rate or
commodity price-hedging transactions.
The intermediate partnership assumed obligations under the Credit Facility.
Borrowings under the Credit Facility are at variable rates and, as a result, we
have interest rate exposure.
The table below provides information about our market sensitive financial
instruments and constitutes a "forward-looking statement." The fair values of
long-term debt are estimated using discounted cash flow analyses, based upon our
current incremental borrowing rates for similar types of borrowing arrangements
as of December 31, 2002, and 2001. The carrying amounts and fair values of
financial instruments are as follows (in thousands):
FAIR VALUE
EXPECTED MATURITY DATES DECEMBER 31,
AS OF DECEMBER 31, 2002 2003 2004 2005 2006 2007 THEREAFTER TOTAL 2002
- ----------------------------------------------------------------------------------------------------------------------------
Senior Notes-fixed rate $ - $ - $ 18,000 $ 18,000 $ 18,000 $ 126,000 $ 180,000 $ 197,247
Weighted Average interest rate 8.31% 8.31% 8.31% 8.31%
Term Loan-floating rate $ 16,250 $ 15,000 $ - $ - $ 31,250 $ 31,250
Weighted Average interest rate 4.31% 4.31%
FAIR VALUE
EXPECTED MATURITY DATES DECEMBER 31,
AS OF DECEMBER 31, 2001 2002 2003 2004 2005 2006 THEREAFTER TOTAL 2001
- ----------------------------------------------------------------------------------------------------------------------------
Senior Notes-fixed rate $ - $ - $ - $ 18,000 $ 18,000 $ 144,000 $ 180,000 $ 180,000
Weighted Average interest rate 8.31% 8.31% 8.31%
Term Loan-floating rate $ 15,000 $ 16,250 $ 15,000 $ - $ - $ 46,250 $ 46,250
Weighted Average interest rate 3.40% 3.40% 3.40%
41
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,
2002 and 2001, the related consolidated statements of income, cash flows and
Partners' capital (deficit) for each of the three years in the period ended
December 31, 2002. Our audits also included the financial statement schedule
listed in the Index at Item 15. These financial statements and financial
statement schedule are the responsibility of the Partnership's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of the Partnership at December 31,
2002 and 2001, and the results of their operations and their cash flows for each
of the three years in the period ended December 31, 2002, in conformity with
accounting principles generally accepted in the United States of America. Also,
in our opinion, such financial statement schedule, when considered in relation
to the basic consolidated financial statements taken as a whole, presents fairly
in all material respects the information set forth therein.
As discussed in Note 3 to the consolidated financial statements, the Partnership
changed its method of estimating coal workers' pneumoconiosis benefits liability
effective January 1, 2001.
/s/ Deloitte & Touche LLP
Tulsa, Oklahoma
March 7, 2003, except for Note 19,
as to which the date is March 14, 2003
42
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2002 AND 2001
(IN THOUSANDS, EXCEPT UNIT DATA)
DECEMBER 31,
----------------------------
ASSETS 2002 2001
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents $ 9,000 $ 9,176
Trade receivables, less allowance of $763 at December 31, 2002 and 2001 30,793 31,124
Due from affiliates 1,369 -
Marketable securities (at cost, which approximates fair value) - 10,085
Inventories 12,023 11,600
Advance royalties 5,231 5,353
Prepaid expenses and other assets 2,680 2,020
---------- ----------
Total current assets 61,096 69,358
PROPERTY, PLANT AND EQUIPMENT, AT COST 413,889 367,050
LESS ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION (206,471) 169,960
---------- ----------
207,418 197,090
OTHER ASSETS:
Advance royalties 9,486 9,756
Coal supply agreements, net 8,167 12,031
Other long-term assets 2,240 2,670
---------- ----------
$ 288,407 $ 290,905
========== ==========
LIABILITIES AND PARTNERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 19,770 $ 25,237
Due to affiliates 4,706 2,595
Accrued taxes other than income taxes 7,615 5,660
Accrued payroll and related expenses 9,319 8,284
Accrued interest 5,361 5,402
Workers' compensation and pneumoconiosis benefits 5,254 4,194
Other current liabilities 8,899 5,324
Current maturities, long-term debt 16,250 15,000
---------- ----------
Total current liabilities 77,174 71,696
LONG-TERM LIABILITIES:
Long-term debt, excluding current maturities 195,000 211,250
Pneumoconiosis benefits 16,067 14,615
Workers' compensation 19,710 18,409
Reclamation and mine closing 18,139 15,387
Due to affiliates 6,152 3,624
Other liabilities 2,718 2,865
---------- ----------
Total liabilities 334,960 337,846
COMMITMENTS AND CONTINGENCIES
PARTNERS' CAPITAL (DEFICIT):
Common Unitholders 8,982,780 units outstanding 144,219 141,448
Subordinated Unitholder 6,422,531 units outstanding 112,916 110,935
General Partners (298,413) (298,510)
Minimum pension liability (5,275) (814)
---------- ----------
Total Partners' capital (deficit) (46,553) (46,941)
---------- ----------
$ 288,407 $ 290,905
========== ==========
See notes to consolidated financial statements.
43
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 2002, 2001, AND 2000
(IN THOUSANDS, EXCEPT UNIT AND PER UNIT DATA)
YEAR ENDED DECEMBER 31,
--------------------------------------------
2002 2001 2000
------------ ------------ ------------
SALES AND OPERATING REVENUES:
Coal sales $ 478,383 $ 421,996 $ 347,209
Transportation revenues 18,992 18,090 13,511
Other sales and operating revenues 20,367 6,214 2,749
------------ ------------ ------------
Total revenues 517,742 446,300 363,469
------------ ------------ ------------
EXPENSES:
Operating expenses 333,112 307,977 257,365
Transportation expenses 18,992 18,090 13,511
Outside purchases 46,738 31,840 16,874
General and administrative 19,408 17,728 15,176
Depreciation, depletion and amortization 47,218 45,451 39,141
Interest expense (net of interest income and interest
capitalized of $1,139, $1,928, and $3,015 for the
Partnership's respective periods) 16,338 16,805 16,563
Unusual items - - (9,466)
------------ ------------ ------------
Total operating expenses 481,806 437,891 349,164
------------ ------------ ------------
INCOME FROM OPERATIONS 35,936 8,409 14,305
OTHER INCOME 528 752 1,276
------------ ------------ ------------
INCOME BEFORE INCOME TAXES AND
CUMULATIVE EFFECT OF ACCOUNTING CHANGE 36,464 9,161 15,581
INCOME TAX EXPENSE 175 - -
------------ ------------ ------------
INCOME BEFORE CUMULATIVE EFFECT OF
ACCOUNTING CHANGE 36,289 9,161 15,581
CUMULATIVE EFFECT OF ACCOUNTING CHANGE - 7,939 -
------------ ------------ ------------
NET INCOME $ 36,289 $ 17,100 $ 15,581
============ ============ ============
GENERAL PARTNERS' INTEREST IN NET INCOME $ 726 $ 342 $ 312
============ ============ ============
LIMITED PARTNERS' INTEREST IN NET INCOME $ 35,563 $ 16,758 $ 15,269
============ ============ ============
BASIC NET INCOME PER LIMITED PARTNER UNIT $ 2.31 $ 1.09 $ 0.99
============ ============ ============
BASIC NET INCOME PER LIMITED PARTNER UNIT
BEFORE ACCOUNTING CHANGE $ 2.31 $ 0.58 $ 0.99
============ ============ ============
DILUTED NET INCOME PER LIMITED
PARTNER UNIT $ 2.24 $ 1.07 $ 0.98
============ ============ ============
DILUTED NET INCOME PER LIMITED PARTNER
UNIT BEFORE ACCOUNTING CHANGE $ 2.24 $ 0.57 $ 0.98
============ ============ ============
PRO FORMA NET INCOME ASSUMING ACCOUNTING
CHANGE IS APPLIED RETROACTIVELY $ 36,289 $ 9,161 $ 14,907
============ ============ ============
WEIGHTED AVERAGE NUMBER
OF UNITS OUTSTANDING - BASIC 15,405,311 15,405,311 15,405,311
============ ============ ============
WEIGHTED AVERAGE NUMBER
OF UNITS OUTSTANDING - DILUTED 15,842,708 15,684,550 15,551,062
============ ============ ============
See notes to consolidated financial statements.
44
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2002, 2001, AND 2000
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
--------------------------------------------
2002 2001 2000
------------ ------------ ------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 36,289 $ 17,100 $ 15,581
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 47,218 45,451 39,141
Cumulative effect of accounting change - (7,939) -
Impairment of transloading facility - - 2,439
Reclamation and mine closings 1,328 943 1,074
Coal inventory adjustment to market 21 212 579
Other 445 (257) 391
Changes in operating assets and liabilities:
Trade receivables 331 4,774 (2,842)
Inventories (444) (970) 9,709
Advance royalties 392 (2,235) (3,011)
Accounts payable (5,467) (321) 6,181
Due to affiliates 3,270 5,149 264
Accrued taxes other than income taxes 1,955 797 289
Accrued payroll and related benefits 1,035 1,309 (1,836)
Accrued pneumoconiosis benefits 1,452 903 (4)
Workers' compensation 2,361 1,661 1,052
Other (2,607) (2,926) 2,366
------------ ------------ ------------
Total net adjustments 51,290 46,551 55,792
------------ ------------ ------------
Net cash provided by operating activities 87,579 63,651 71,373
------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of property, plant and equipment (51,524) (53,714) (46,151)
Proceeds from sale of property, plant and equipment 124 183 210
Purchase of marketable securities - (33,527) (72,523)
Proceeds from the sale of marketable securities 10,085 60,840 77,464
------------ ------------ ------------
Net cash used in investing activities (41,315) (26,218) (41,000)
------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under revolving credit and working capital facilities 66,400 1,100 29,500
Payments under revolving credit and working capital facilities (66,400) (1,100) (29,500)
Payments on long-term debt (15,000) (3,750) -
Distributions to Partners (31,440) (31,440) (31,440)
------------ ------------ ------------
Net cash used in financing activities (46,440) (35,190) (31,440)
------------ ------------ ------------
NET CHANGE IN CASH AND CASH EQUIVALENTS (176) 2,243 (1,067)
CASH AND CASH EQUIVALENTS AT
BEGINNING OF PERIOD 9,176 6,933 8,000
------------ ------------ ------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 9,000 $ 9,176 $ 6,933
============ ============ ============
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest $ 17,059 $ 18,070 $ 19,043
============ ============ ============
See notes to consolidated financial statements.
45
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL (DEFICIT)
FOR THE YEARS ENDED DECEMBER 31, 2002, 2001, AND 2000
(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 January 1, 2000 8,982,780 6,422,531 $ 158,705 $ 123,273 $ (297,906) $ - $ (15,928)
Net income - - 8,903 6,366 312 - 15,581
Distribution to Partners - - (17,966) (12,845) (629) - (31,440)
--------- ----------- --------- ---------- ---------- -------- ---------
Balance at December 31, 2000 8,982,780 6,422,531 149,642 116,794 (298,223) - (31,787)
Comprehensive income:
Net income - - 9,772 6,986 342 - 17,100
Minimum pension liability - - - - - (814) (814)
--------- ----------- --------- ---------- ---------- -------- ---------
Total comprehensive income - - 9,772 6,986 342 (814) 16,286
Distribution to Partners - - (17,966) (12,845) (629) - (31,440)
--------- ----------- --------- ---------- ---------- -------- ---------
Balance at December 31, 2001 8,982,780 6,422,531 141,448 110,935 (298,510) (814) (46,941)
Comprehensive income:
Net income - - 20,737 14,826 726 - 36,289
Minimum pension liability - - - - - (4,461) (4,461)
--------- ----------- --------- ---------- ---------- -------- ---------
Total comprehensive income - - 20,737 14,826 726 (4,461) 31,828
Distribution to Partners - - (17,966) (12,845) (629) - (31,440)
--------- ----------- --------- ---------- ---------- -------- ---------
Balance at December 31, 2002 8,982,780 6,422,531 $ 144,219 $ 112,916 $ (298,413) $ (5,275) $ (46,553)
========= =========== ========= ========== ========== ======== =========
See notes to consolidated financial statements.
46
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2002, 2001, AND 2000
1. ORGANIZATION AND PRESENTATION
Alliance Resource Partners, L.P., a Delaware limited partnership (the
"Partnership") was formed in May 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), which assets consisted of substantially all
of ARH's operating subsidiaries. Collectively, the coal production and
marketing assets and the operating subsidiaries of ARH acquired by the
Partnership, but excluding ARH and certain excluded assets and
subsidiaries, are referred to as the "Predecessor."
The Delaware limited partnerships and limited liability companies and
corporation that comprise the Partnership's subsidiaries are as
follows: Alliance Resource Partners, L.P., Alliance Resource Operating
Partners, L.P. (the "Intermediate Partnership"), Alliance Coal, LLC
(the holding company for operations), Alliance Land, LLC, Alliance
Properties, LLC, Alliance Service, Inc., Backbone Mountain, LLC, Excel
Mining, LLC, Gibson County Coal, LLC, Hopkins County Coal, LLC, MC
Mining, LLC, Mettiki Coal, LLC, Mettiki Coal (WV), LLC, Mt. Vernon
Transfer Terminal, LLC, Pontiki Coal, LLC, Webster County Coal, LLC,
and White County Coal, LLC.
The Partnership completed its initial public offering (the "IPO") in
August 1999, issuing 7,750,000 Common Units ("Common Units") at $19.00
per unit and received net proceeds of $133.7 million. Concurrently with
the offering ARH contributed certain assets to the Partnership in
exchange for cash, 0.01% general partner interest in each of the
Partnership and the Intermediate Partnership, the right to receive
incentive distributions as defined in the partnership agreement and the
assumption of related indebtedness and 1,232,780 common and 6,422,531
subordinated units that are held by Alliance Resource GP, LLC, a
Delaware limited liability company and wholly-owned subsidiary of ARH
(the "Special GP"). On February 14, 2003 and March 14, 2003, the
Partnership issued 2,250,000 and 288,000 additional Common Units at a
public offering price of $22.51 per unit and received net proceeds of
$48.5 million and $6.2 million, respectively, before expenses other
than underwriters fees (Note 19).
Consistent with guidance provided by the Emerging Issues Task Force in
Issue No. 87-21, "Change of Accounting Basis in Master Limited
Partnership Transactions," the Partnership maintained the historical
cost basis of the $121 million of net assets contributed by ARH to the
Partnership.
The Partnership is managed by Alliance Resource Management GP, LLC, a
Delaware limited liability company (the "Managing GP"), which holds a
0.99% and 1.0001% managing general partner interest in the Partnership
and the Intermediate Partnership, respectively.
The accompanying consolidated financial statements include the accounts
and operations of the limited partnerships, limited liability companies
and corporation disclosed above and present the financial position as
of December 31, 2002 and 2001 and the results of their operations, cash
flows and changes in partners' capital (deficit) for each of the three
years in the period ended December 31, 2002. All material intercompany
transactions and accounts of the Partnership have been eliminated.
47
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ESTIMATES - The preparation of consolidated 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 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, 2002 and 2001, the estimated fair value of long-term debt
was approximately $228.5 million and $226.3 million, respectively. The
fair value of long-term debt is based on interest rates that are
currently available to the Partnership for issuance of debt with
similar terms and remaining maturities.
CASH AND CASH EQUIVALENTS - Cash and cash equivalents include cash on
hand and on deposit, including highly liquid investments with
maturities of three months or less.
CASH MANAGEMENT - The Partnership reclassified outstanding checks of
$3,352,000 at December 31, 2001, to accounts payable in the
consolidated balance sheets.
MARKETABLE SECURITIES - At December 31, 2001, the Partnership had an
investment in a Federal Agency Note, which matured February 1, 2002 and
was classified as an available-for-sale security. At December 31, 2001,
the cost of marketable securities approximated fair value and no effect
of unrealized gains (losses) is reflected in Partners' capital
(deficit).
INVENTORIES - Coal inventories are stated at the lower of cost or
market on a first-in, first-out basis. Supply inventories are stated at
the lower of cost or market on an average cost basis.
PROPERTY, PLANT AND EQUIPMENT - Additions and replacements constituting
improvements are capitalized. Maintenance, repairs, and minor
replacements are expensed as incurred. Depreciation and amortization
are computed principally on the straight-line method based upon the
estimated useful lives of the assets or the estimated life of each
mine, whichever is less ranging from 2 to 20 years. Depreciable lives
for mining equipment and processing facilities range from 2 to 20
years. Depreciable lives for land and land improvements and depletable
lives for mineral rights range from 5 to 20 years. Depreciable lives
for buildings, office equipment and improvements range from 2 to 20
years. Gains or losses arising from retirements are included in current
operations. Depletion of mineral rights is provided on the basis of
tonnage mined in relation to estimated recoverable tonnage. At December
31, 2002 and 2001, land and mineral rights include $2,178,000
representing the carrying value of coal reserves attributable to
properties where the Partnership is not currently engaged in mining
operations or leasing to third parties, and therefore, the coal
reserves are not currently being depleted. Management believes that the
carrying value of these reserves will be recovered.
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. During 2000, the
Partnership recorded an impairment loss of approximately $2,439,000
relating to certain transloading facility assets, associated with
Seminole Electric Cooperative, Inc.'s ("Seminole") termination of a
long-term contract for transloading of coal from rail to barge. Because
this facility's
48
revenues were primarily attributable to the Seminole long-term
contract, the carrying value of the transloading facility and
associated equipment, net of salvage value, was recorded as an
impairment and is included as an unusual item in 2000 in the
accompanying consolidated statements of income.
ADVANCE ROYALTIES - Rights to coal mineral leases are often acquired
through advance royalty payments. Management assesses the
recoverability of royalty prepayments based on estimated future
production and capitalizes these amounts accordingly. Royalty
prepayments expected to be recouped within one year are classified as a
current asset. As mining occurs on those leases, the royalty
prepayments are included in the cost of mined coal. Royalty prepayments
estimated to be nonrecoverable are expensed.
COAL SUPPLY AGREEMENTS - The Predecessor purchased the coal operations
of MAPCO Inc. effective August 1, 1996, in a business combination using
the purchase method of accounting. A portion of the acquisition costs
was allocated to coal supply agreements. This allocated cost is being
amortized on the basis of coal shipped in relation to total coal to be
supplied during the respective contract terms. The amortization periods
end on various dates from September 2002 to December 2005. Accumulated
amortization for coal supply agreements was $30,296,000 and $26,432,000
at December 31, 2002 and 2001, respectively. The aggregate amortization
expense recognized for coal supply agreements was $3,864,000,
$4,293,000 and $3,555,000 for the years ended December 31, 2002, 2001
and 2000, respectively. The estimated aggregate amortization expense
for years 2003 through 2005 is approximately $2,722,000 per year.
RECLAMATION AND MINE CLOSING COSTS - The liability for the estimated
cost of future mine reclamation and closing procedures is recorded on a
present value basis when incurred and the associated cost is
capitalized by increasing the carrying amount of the related long-lived
asset. Those costs relate to sealing portals at underground mines and
to reclaiming the final pits and support acreage at surface mines.
Other costs common to both types of mining are related to removing or
covering refuse piles and settling ponds, and dismantling preparation
plants, other facilities and roadway infrastructure. Ongoing
reclamation costs principally involve restoration of disturbed land and
are expensed as incurred during the mining process.
WORKERS' COMPENSATION AND PNEUMOCONIOSIS ("BLACK LUNG") BENEFITS - The
Partnership is self-insured for workers' compensation benefits,
including black lung benefits. The Partnership accrues a workers'
compensation liability for the estimated present value of workers'
compensation and black lung benefits based on actuarial valuations.
Effective January 1, 2001, the Partnership changed its method of
estimating the black lung benefits liability (Note 3).
INCOME TAXES - The Partnership is not a taxable entity for federal or
state income tax purposes; 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 Partnership's subsidiary, Alliance
Service, Inc. ("Alliance Service"), is subject to federal and state
income taxes.
REVENUE RECOGNITION - Revenues from coal sales are recognized when
title passes to the customer as the coal is shipped. Non-coal sales
revenues primarily consist of rental and service fees associated with
agreements to host and operate a third-party coal synfuel facility and
to assist with the coal synfuel marketing and other related services.
These non-coal sales revenues are recognized as the services are
performed. Transportation revenues are recognized in connection with
the Partnership incurring the corresponding costs of transporting the
coal to customers through third-party carriers since the Partnership is
directly reimbursed for these costs through customer billings.
49
COMMON UNIT-BASED COMPENSATION - The Partnership accounts for the
compensation expense of the restricted common units granted under the
Long-Term Incentive Plan (Note 11) using the intrinsic value method
prescribed in Accounting Principles Board Opinion No. 25, "Accounting
for Stock Issued to Employees" and the related FASB Interpretation No.
28, "Accounting for Stock Appreciation Rights and Other Variable Stock
Option or Award Plans." Compensation cost for the restricted common
units is recorded on a pro-rata basis, as appropriate given the "cliff
vesting" nature of the grants, based upon the current market value of
the Partnership's common units at the end of each period.
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, 2002 and 2001). 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 and
providing rental and service fees associated with producing and
marketing coal synfuel. The Partnership has disclosed major customer
sales information (Note 16). The Partnership's geographic areas of
operation are concentrated in the United States.
NEW ACCOUNTING STANDARDS - On January 1, 2002, the Partnership adopted
Statement of Financial Accounting Standards ("SFAS") No. 142 "Goodwill
and Intangible Assets." This standard discontinues the practice of
amortizing goodwill and indefinite lived intangible assets and
initiates an annual review for impairment. This standard had no
material effect on the Partnership's consolidated financial statements
upon adoption.
In August 2001, the Financial Accounting Standards Board ("FASB")
issued SFAS No. 143, "Accounting for Asset Retirement Obligations,"
which requires the fair value of a liability for an asset retirement
obligation to be recognized in the period in which it is incurred. When
the liability is initially recorded, a cost is capitalized by
increasing the carrying amount of the related long-lived asset. Over
time, the liability is accreted to its present value for each period,
and the capitalized cost is depreciated over the useful life of the
related asset. To settle the liability, the obligation for its recorded
amount is paid or a gain or loss upon settlement is incurred. Since the
Partnership has historically adhered to accounting principles similar
to SFAS No. 143 in accounting for its reclamation and mine closing
costs, the Partnership does not believe that adoption of SFAS No. 143,
effective January 1, 2003, will have a material impact on its
consolidated financial statements.
On January 1, 2002, the Partnership adopted SFAS No. 144, "Accounting
for the Impairment or Disposal of Long-Lived Assets. This standard had
no material effect on the Partnership's consolidated financial
statements upon adoption.
In November 2002, the FASB issued Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others." This interpretation
elaborates on the disclosures to be made by a guarantor in its
financial statements about its obligations under certain guarantees
that it has issued. It also requires a guarantor to recognize, at the
inception of a guarantee, a liability for the fair value of the
obligations it has undertaken in issuing the guarantee. The initial
recognition and initial measurement provisions of the interpretation
are applicable on a prospective basis to guarantees issued or modified
after December 31, 2002. The disclosure requirements are effective for
financial statements of interim or annual periods ending after December
15, 2002. The Partnership does not believe this interpretation will
have a material effect on the Partnership's consolidated financial
statements upon adoption.
50
3. ACCOUNTING CHANGE
Effective January 1, 2001, the Partnership changed its method of
estimating coal workers' pneumoconiosis ("black lung") benefits
liability to the service cost method described in SFAS No. 106,
"Employers' Accounting for Postretirement Benefits Other Than
Pensions," which method is permitted under SFAS No. 112 "Employers'
Accounting for Postemployment Benefits." The Partnership previously
accrued the black lung benefits liability at the present value of the
actuarially determined current and future estimated black lung benefit
payments utilizing the methodology prescribed under SFAS No. 5
"Accounting for Contingencies," which was also permitted by SFAS No.
112. In January 2001, governmental regulations regarding the black lung
benefits claims approval process were enacted. These new regulations
specifically define the black lung disability as progressive and also
expand the definition of pneumoconiosis to mandate consideration of
diseases that are caused by factors other than exposure to coal dust.
The Partnership believes the change to the SFAS No. 106 measurement
methodology better matches black lung costs over the service lives of
the miners who ultimately receive the black lung benefits and is more
reflective of the recently enacted regulations, which place significant
emphasis on coal miners' future years of employment in the coal
industry.
The adjustment of $7,939,000 to apply retroactively the new method of
estimating the black lung liability is included in net income for the
year ended December 31, 2001. The effect of the change for the year
ended December 31, 2001 was to decrease income before cumulative effect
of a change in accounting principle $435,000 ($(0.03) per basic and
diluted limited partner unit) and increase net income $7,504,000 ($0.48
and $0.47 per basic and diluted partner unit, respectively). Assuming
the retroactive application of the service cost method of estimating
the black lung liability, the pro forma net income for the year ended
December 31, 2000, would have been approximately $14,907,000 or $0.95
per basic limited partner unit and $0.94 per diluted limited partner
unit, respectively, as compared to reported net income of $15,581,000
or $0.99 per basic limited partner unit and $0.98 per diluted limited
partner unit.
4. UNUSUAL ITEMS
The Partnership was involved in litigation with Seminole with respect
to Seminole's termination of a long-term contract for the transloading
of coal from rail to barge through the Mt. Vernon terminal in Indiana.
The final resolution between the parties, reached in conjunction with
an arbitrator's decision rendered during the third quarter of 2000,
included both cash payments and amendments to an existing coal supply
contract. The Partnership recorded income of $12,141,000, which was net
of litigation expenses of approximately $881,000 and an impairment
charge of $2,439,000 relating to the facility's assets. Additionally,
during the third quarter of 2000, the Partnership recorded an expense
of $2,675,000, consisting of $675,000 relating to a settlement and
$2,000,000 attributable to contingencies associated with third-party
claims arising out of the Partnership's mining operations. The net
effect of these unusual items was $9,466,000 recorded in the year ended
December 31, 2000.
5. INVENTORIES
Inventories consist of the following at December 31, (in thousands):
2002 2001
-------- --------
Coal $ 4,190 $ 4,184
Supplies 7,833 7,416
-------- --------
$ 12,023 $ 11,600
======== ========
51
6. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consists of the following at December 31,
(in thousands):
2002 2001
--------- ---------
Mining equipment and processing facilities $ 344,062 $ 299,480
Land and mineral rights 17,720 17,691
Buildings, office equipment and improvements 33,414 29,359
Construction in progress 18,693 20,520
--------- ---------
413,889 367,050
Less accumulated depreciation, depletion and amortization (206,471) (169,960)
--------- ---------
$ 207,418 $ 197,090
========= =========
7. LONG-TERM DEBT
Long-term debt consists of the following at December 31, (in
thousands):
2002 2001
--------- ---------
Senior notes $ 180,000 $ 180,000
Term loan through credit facility 31,250 46,250
--------- ---------
211,250 226,250
Less current maturities (16,250) (15,000)
--------- ---------
$ 195,000 $ 211,250
========= =========
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 Intermediate Partnership has a $100 million credit facility that
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 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 interest rates on the term
loan facility at December 31, 2002 and 2001 were 4.31% and 3.40%,
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, 2002 and 2001.
The credit facility expires in August 2004.
The senior notes and credit facility are guaranteed by all subsidiaries
of the Intermediate Partnership. The senior notes and credit facility
contain various restrictive and affirmative covenants, including
limitations on the amount of distributions by the Intermediate
Partnership and the incurrence of other debt. The Partnership was in
compliance with the covenants of both the credit facility and senior
notes at December 31, 2002 and 2001.
52
The Partnership entered into agreements with three banks to provide
letters of credit in an aggregate amount of $35.0 million. At December
31, 2002, the Partnership had $21.6 million in letters of credit
outstanding. The Special GP guarantees the letters of credit (Note 14).
Aggregate maturities of long-term debt are payable as follows (in
thousands):
YEAR ENDING
DECEMBER 31,
2003 $ 16,250
2004 15,000
2005 18,000
2006 18,000
2007 18,000
Thereafter 126,000
---------
$ 211,250
=========
8. DISTRIBUTIONS OF AVAILABLE CASH
The Partnership will distribute 100% of its available cash within 45
days after the end of each quarter to unitholders of record and to the
General Partners. Available cash is generally defined as all cash and
cash equivalents of the Partnership on hand at the end of each quarter
less reserves established by the Managing GP in its reasonable
discretion for future cash requirements. These reserves are retained to
provide for the conduct of the Partnership's business, the payment of
debt principal and interest and to provide funds for future
distributions.
Distributions of available cash to the holder of Subordinated Units are
subject to the prior rights of holders of Common Units to receive the
minimum quarterly distribution ("MQD") for each quarter during the
subordination period and to receive any arrearages in the distribution
of the MQD on the Common Units for the prior quarters during the
subordination period. The MQD is $0.50 per unit ($2.00 per unit on an
annual basis). Upon expiration of the subordination period, which will
generally not occur before September 30, 2004, all Subordinated Units
will be converted on a one-for-one basis into Common Units and will
then participate, on a pro rata basis with all other Common Units in
future distributions of available cash. However, under certain
circumstances, up to 50% of the Subordinated Units may convert into
Common Units on or after September 30, 2003. Common Units will accrue
arrearages with respect to distributions for any quarter during the
subordination period, but Subordinated Units will not accrue any
arrearages with respect to distributions for any quarter.
If quarterly distributions of available cash exceed the MQD or the
target distributions levels, the General Partners will receive
distributions based on specified increasing percentages of the
available cash that exceed 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 each of the quarters ended December 31, 1999 through September 30,
2002, quarterly distributions of $0.50 per unit were paid to the common
and subordinated unitholders. On January 28, 2003, the Partnership
declared a quarterly distribution, for the period from October 1, 2002
to December 31, 2002, of $0.525 per unit, totaling approximately
$8,088,000 on its outstanding Common and Subordinated Units, payable on
February 14, 2003 to all unitholders of record on February 3, 2003.
53
9. INCOME TAXES
The Partnership's subsidiary, Alliance Service, is subject to federal
and state income taxes. In conjunction with a decision to relocate the
coal synfuel facility from Hopkins County Coal to Warrior Coal (Note
14), agreements for a portion of the services provided to the coal
synfuel producer were assigned to Alliance Service in December 2002.
Alliance Service has no temporary differences between the financial
reporting basis and the tax basis of its assets and liabilities.
Components of income tax expense are as follows (in thousands):
YEAR ENDED
DECEMBER 31,
2002
------------
Current:
Federal $ 153
State 22
-----
$ 175
=====
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):
YEAR ENDED DECEMBER 31,
--------------------------------------------
2002 2001 2000
-------- -------- --------
Net income per limited partner unit $ 35,563 $ 16,758 $ 15,269
Weighted average limited partner units - basic 15,405 15,405 15,405
Basic net income per limited partner unit $ 2.31 $ 1.09 $ 0.99
======== ======== ========
Basic net income per limited partner unit
before accounting change $ 2.31 $ 0.58 $ 0.99
======== ======== ========
Weighted average limited partner units - basic 15,405 15,405 15,405
Units contingently issuable:
Restricted units for Long-Term Incentive Plan 390 263 142
Directors' compensation units deferred 13 9 4
Supplemental Executive Retirement Plan 35 8 -
-------- -------- --------
Weighted average limited partner units, assuming
dilutive effect of restricted units 15,843 15,685 15,551
-------- -------- --------
Diluted net income per limited partner unit $ 2.24 $ 1.07 $ 0.98
======== ======== ========
Diluted net income per limited partner unit before
accounting change $ 2.24 $ 0.57 $ 0.98
======== ======== ========
54
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 the phantom unit, or options to purchase Common Units. Common Units
to be delivered upon the vesting of restricted units or to be issued
upon exercise of a unit option will be acquired by the Managing GP in
the open market at a price equal to the then prevailing price, or
directly from ARH or any other third party, including units newly
issued by the Partnership, units already owned by the Managing GP, or
any combination of the foregoing. The Partnership agreement provides
that the Managing GP be reimbursed for all costs incurred in acquiring
these Common Units or in paying cash in lieu of Common Units upon
vesting of the restricted units. The aggregate number of units reserved
for issuance under the LTIP is 600,000. Effective January 1, 2002, 2001
and 2000 the Compensation Committee approved grants of 133,885, 129,200
and 142,100 restricted units, respectively, which vest at the end of
the subordination period, which will generally not end before September
30, 2004. As of December 31, 2002, 15,050 units have been forfeited.
During 2002, 2001 and 2000, the Managing GP billed the Partnership
approximately $2,338,000, $1,929,000 and $538,000, respectively,
attributable to the LTIP. The Partnership has recorded this amount as
compensation expense in accordance with variable plan accounting.
Effective January 1, 2003, the Compensation Committee approved
additional grants of 139,705 restricted units, which will vest
September 30, 2005, subject to certain financial tests.
DEFINED CONTRIBUTION PLANS - The Partnership's employees currently
participate in a defined contribution profit sharing and savings plan
sponsored by the Partnership. 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 $2,565,000, $2,430,000 and $2,050,000 for
the years ended December 31, 2002, 2001 and 2000, respectively.
DEFINED BENEFIT PLANS - Certain employees at the mining operations
participate in a defined benefit plan sponsored by the Partnership. The
benefit formula is a fixed dollar unit based on years of service.
55
The following sets forth changes in benefit obligations and plan assets
for the years ended December 31, 2002 and 2001 and the funded status of
the plans reconciled with amounts reported in the Partnership's
consolidated financial statements at December 31, 2002 and 2001,
respectively (dollars in thousands):
2002 2001
-------- --------
CHANGE IN BENEFIT OBLIGATIONS:
Benefit obligations at beginning of year $ 13,202 $ 10,135
Service cost 2,249 2,050
Interest cost 952 755
Actuarial loss 1,817 384
Benefits paid (143) (122)
-------- --------
Benefit obligation at end of year 18,077 13,202
-------- --------
CHANGE IN PLAN ASSETS:
Fair value of plan assets at beginning of year 10,508 9,500
Employer contribution 3,661 1,500
Actual loss on plan assets (1,594) (370)
Benefits paid (143) (122)
-------- --------
Fair value of plan assets at end of year 12,432 10,508
-------- --------
Funded status (5,645) (2,694)
Unrecognized prior service cost 187 235
Unrecognized actuarial loss 5,275 814
-------- --------
Net amount recognized $ (183) $ (1,645)
======== ========
AMOUNTS RECOGNIZED IN STATEMENT OF FINANCIAL POSITION:
Accrued benefit liability $ (5,645) $ (2,694)
Intangible asset 187 235
Accumulated other comprehensive income 5,275 814
-------- --------
Net amount recognized $ (183) $ (1,645)
======== ========
WEIGHTED-AVERAGE ASSUMPTIONS AS OF DECEMBER 31:
Discount rate 6.75% 7.25%
Expected return on plan assets 9.00% 9.00%
2002 2001 2000
-------- -------- -------
COMPONENTS OF NET PERIODIC BENEFIT COST:
Service cost $ 2,249 $ 2,050 $ 1,971
Interest cost 952 755 596
Expected return on plan assets (1,050) (888) (737)
Prior service cost 48 48 48
Net gain - - (49)
-------- -------- -------
Net periodic benefit cost $ 2,199 $ 1,965 $ 1,829
======== ======== =======
Effect on minimum pension liability $ 4,461 $ 814 $ -
======== ======== =======
56
12. RECLAMATION AND MINE CLOSING COSTS
The majority of the Partnership's operations are governed by various
state statutes and the Federal Surface Mining Control and Reclamation
Act of 1977, which establish reclamation and mine closing standards.
These regulations, among other requirements, require restoration of
property in accordance with specified standards and an approved
reclamation plan. The Partnership has estimated the costs and timing of
future reclamation and mine closing costs and recorded those estimates
on a present value basis using a 6% discount rate.
Discounting resulted in reducing the accrual for reclamation and mine
closing costs by $12,429,000 and $12,184,000 at December 31, 2002 and
2001, respectively. Estimated payments of reclamation and mine closing
costs as of December 31, 2002 are as follows (in thousands):
YEAR ENDING
DECEMBER 31,
2003 $ 1,186
2004 2,702
2005 3,726
2006 2,430
2007 -
Thereafter 21,710
--------
Aggregate undiscounted reclamation and mine closing 31,754
Effect of discounting 12,429
--------
Total reclamation and mine closing costs 19,325
Less current portion 1,186
--------
Reclamation and mine closing costs $ 18,139
========
The following table presents the activity affecting the reclamation and
mine closing liability (in thousands):
YEAR ENDED DECEMBER 31,
----------------------------------
2002 2001 2000
-------- -------- --------
Beginning balance $ 16,465 $ 16,018 $ 14,796
Accrual 1,131 943 1,074
Payments (709) (454) (764)
Allocation of liability associated with
acquisition and mine development 2,438 (42) 912
-------- -------- --------
Ending balance $ 19,325 $ 16,465 $ 16,018
======== ======== ========
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.
57
The Partnership changed its method of estimating black lung benefits
liability effective January 1, 2001 to the service cost method (Note
3). Under the service cost method the calculation of the actuarial
present value of the estimated black lung obligation is based on an
actuarial study performed by an independent actuary. Actuarial gains or
losses are amortized over the remaining service period of active
miners. The discount rate used to calculate the estimated present value
of future obligations was 5.5% at December 31, 2002 and 2001,
respectively.
The reconciliation of changes in benefit obligations at December 31,
2002 and 2001 is as follows (in thousands):
2002 2001
-------- --------
Benefit obligations at beginning of year, including cumulative
effect of accounting change of $7,939 effective
January 1, 2001 (Note 3) $ 14,615 $ 13,712
Service cost 783 464
Interest cost 811 705
Actuarial loss 45 -
Benefits paid (187) (266)
-------- --------
Benefit obligations at end of year $ 16,067 $ 14,615
======== ========
The Partnership previously accrued the black lung benefits liability
based upon the actuarially computed present and future claims. The cost
due to change in the estimate of black lung benefits charged to
operations for the year ended December 31, 2000 was $123,000.
The U.S. Department of Labor has issued revised regulations that will
alter the claims process for the federal black lung benefit recipients.
Both the coal and insurance industries have challenged certain
provisions of the revised regulations through litigation, but the
regulations were upheld, with some exceptions as to the retroactive
application of the regulations. The revised regulations are expected to
result in an increase in the incidence and recovery of black lung
claims.
14. RELATED PARTY TRANSACTIONS
ADMINISTRATIVE SERVICES - 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, but not limited to, management's salaries and
related benefits, and accounting, budget, planning, treasury, public
relations, land administration, environmental, permitting, payroll,
benefits, disability, workers' compensation management, legal and
information technology services. The Managing GP may determine in its
sole discretion the expenses that are allocable to the Partnership.
Total costs billed by the Managing GP and its affiliates to the
Partnership were approximately $6,559,000, $6,503,000, and $3,899,000
for the years ended December 31, 2002, 2001 and 2000, respectively.
WARRIOR COAL ACQUISITION - On February 14, 2003, the Partnership
acquired Warrior Coal, LLC ("Warrior Coal") from an affiliate, ARH
Warrior Holdings, Inc. ("ARH Warrior Holdings") a subsidiary of ARH,
pursuant to an Amended and Restated Put and Call Option Agreement
("Put/Call Agreement"). Warrior Coal purchased the capital stock of
Roberts Bros. Coal Co., Inc., Warrior Coal Mining Company, Warrior Coal
Corporation and certain assets of Christian Coal Corp. and Richland
Mining Co., Inc. in January 2001. The Managing GP had previously
declined the opportunity to purchase these assets as the Partnership
had previously committed to major capital expenditures at two existing
operations. As a condition to not exercising its right of first
refusal, the Partnership requested that ARH Warrior Holdings enter into
a put and call arrangement for Warrior Coal. ARH Warrior Holdings and
the Partnership, with the approval of the Conflicts Committee of the
Managing GP, entered into the Put/Call Agreement in January 2001.
Concurrently, ARH Warrior Holdings acquired Warrior Coal in January
2001 for $10.0 million.
58
The Put/Call Agreement preserved the opportunity for the Partnership to
acquire Warrior Coal during a specified time period at a price
significantly greater than the price paid by ARH Warrior Holdings.
Under the terms of the Put/Call Agreement, ARH Warrior Holdings
exercised its put option requiring the Partnership to purchase Warrior
Coal at a put option price of approximately $12.7 million.
The option provisions of the Put/Call Agreement were subject to certain
conditions (unless otherwise waived), including, among others, (a) the
non-occurrence of a material adverse change in the business and
financial condition of Warrior Coal, (b) the prohibition of any
dividends or other distributions to Warrior Coal's shareholders, (c)
the maintenance of Warrior Coal's assets in good working condition, (d)
the prohibition on the sale of any equity interest in Warrior Coal
except for the options contained in the Put/Call Agreement, and (e) the
prohibition on the sale or transfer of Warrior Coal's assets except
those made in the ordinary course of its business.
The Put/Call Agreement option prices reflected negotiated sale and
purchase amounts that both parties determined would allow each party to
satisfy acceptable minimum investment returns in the event either the
put or call options were exercised. In January 2001 and in December
2002, the Partnership developed financial projections for Warrior Coal
based on due diligence procedures it customarily performs when
considering the acquisition of a coal mine. The assumptions underlying
the financial projections made by the Partnership for Warrior Coal
included, among others, (a) annual production levels ranging from 1.5
million to 1.8 million tons, (b) coal prices at or below the then
current coal prices and (c) a discount rate of 12 percent. Based on
these financial projections, as of December 31, 2002 and 2001, the
Partnership believed that the fair value of Warrior Coal was equal to
or greater than the put option exercise price.
The put option price of $12.7 million was paid to ARH Warrior Holdings
in accordance with the terms of the Put/Call Agreement, as amended to
extend the put option period through February 28, 2003. In addition,
the Partnership repaid Warrior Coal's borrowings of $17.0 million under
the revolving credit agreement between the Special GP and Warrior Coal.
The primary borrowings under the revolving credit agreement financed
new infrastructure capital projects at Warrior Coal that are expected
to improve productivity and significantly increase capacity. The
Partnership funded the Warrior Coal acquisition through a portion of
the proceeds received from the issuance of 2,250,000 common units (Note
19). Based on the Partnership's current financial projections, the
Partnership continues to believe that the fair value of Warrior Coal is
equal to or greater than the put option exercise price. Because the
Warrior Coal acquisition was between entities under common control, it
will be accounted for at historical cost in a manner similar to that
used in a pooling of interests.
Under the terms of the Put/Call Agreement, the Partnership assumed
certain other obligations, including a mineral lease and sublease with
SGP Land, LLC ("SGP Land"), a subsidiary of the Special GP, covering
coal reserves that have been and will continue to be mined by Warrior
Coal. The terms and conditions of the mineral lease and sub-lease
remained unchanged.
59
During 2002 and 2001, the Partnership provided management and
administrative services to Warrior Coal under an administrative service
agreement. Under this agreement, the Partnership recognized approximately
$929,000 and $1,019,000 as a reduction of general and administrative
expenses during the years ended December 31, 2002 and 2001, respectively.
During 2001, the Partnership entered into an agreement with Warrior Coal to
perform certain reclamation procedures for the Partnership. The total
estimated cost of the reclamation procedures covered by this agreement is
$475,000 of which approximately $97,000 and $160,000 was paid to Warrior
Coal for the years ended December 31, 2002 and 2001, respectively.
During 2002 and 2001, the Partnership made coal purchases of approximately
$36,700,000 and $3,135,000, respectively, from Warrior Coal. Accounts
payable to Warrior Coal of $3,400,000 and $1,876,000 is included in the
amount due to affiliates at December 31, 2002 and 2001, respectively.
During 2002, the Partnership made coal sales of approximately $3.5 million
to Warrior Coal. Accounts receivable from Warrior Coal of $1.4 million
offset a portion of the amount due to affiliates at December 31, 2002.
SGP LAND - The Partnership has a mineral lease and sublease with SGP Land
requiring annual minimum royalty payments of $2.7 million, payable in
advance through 2013 or until $37.8 million of cumulative annual minimum
and/or earned royalty payments have been paid. The Partnership paid annual
minimum royalties of $2.7 million during each of the three years in the
period ended December 31, 2002.
The Partnership also has an option to lease and/or sublease certain
reserves from SGP Land, which reserves are contiguous to the Partnership's
Hopkins County Coal LLC mining complex. Under the terms of the option to
lease and sublease, the Partnership paid option fees of $684,000 during the
years ended December 31, 2002 and 2001. The anticipated annual minimum
royalty obligation is $684,000, payable in advance, from 2003 through 2009.
In 2001, SGP Land, as successor in interest to an unaffiliated third party,
entered into an amended mineral lease with MC Mining, LLC ("MC Mining").
Under the terms of the lease, MC Mining has paid and will continue to pay
an annual minimum royalty obligation of $300,000 until $6.0 million of
cumulative annual minimum and/or earned royalty payments have been paid. MC
Mining paid royalties of $568,000 and $705,000 for the years ended December
31, 2002 and 2001, respectively.
SPECIAL GP - The Partnership has a noncancelable operating lease
arrangement with the Special GP for the coal preparation plant and
ancillary facilities at the Gibson County Coal, LLC mining complex. Based
on the terms of the lease, the Partnership will make monthly payments of
approximately $216,000 through January 2011. Lease expense incurred for
each of the three years in the period ended December 31, 2002 was
$2,595,000.
The Partnership entered into agreements with three banks to provide letters
of credit in an aggregate amount of $35.0 million to maintain surety bonds
to secure its obligations for reclamation liabilities and workers'
compensation benefits. At December 31, 2002, the Partnership had $21.6
million in outstanding letters of credit. The Special GP guarantees these
letters of credit, and as a result the Partnership has agreed to compensate
the Special GP for a guarantee fee equal to 0.30% per annum of the face
amount of the letters of credit outstanding. The Partnership paid
approximately $48,200 and $8,800 in guarantee fees to the Special GP for
the years ended December 31, 2002 and 2001, respectively.
60
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,
2003 $ 2,595 $ 780 $ 3,375
2004 2,595 792 3,387
2005 2,595 795 3,390
2006 2,595 627 3,222
2007 2,595 451 3,046
Thereafter 8,000 213 8,213
--------- -------- --------
$ 20,975 $ 3,658 $ 24,633
========= ======== ========
Lease expense under all operating leases was $4,235,000, $4,224,000,
$1,409,000, for the years ended December 31, 2002, 2001 and 2000,
respectively.
In October 2002, the Partnership entered into a master equipment lease. The
Partnership's credit facilities limit the amount of total operating lease
obligations to $10 million payable in any period of 12 consecutive months.
This master equipment lease is subject to this limitation on lease
obligations. There was no equipment leased under the master equipment lease
at December 31, 2002.
CONTRACTUAL COMMITMENTS - In connection with the expansion of an existing
mine into adjacent coal reserves and construction of a new mine shaft at
another existing mine, the Partnership has remaining contractual
commitments of approximately $6.0 million at December 31, 2002.
GENERAL LITIGATION - The Partnership is involved in various lawsuits,
claims and regulatory proceedings, incidental to its business. The
Partnership provides for costs related to litigation and regulatory
proceedings, including civil fines issued as part of the outcome of such
proceedings, when a loss is probable and the amount is reasonably
determinable. The Partnership also recorded an expense of $2,675,000
consisting of $675,000 relating to a settlement and $2,000,000 attributable
to contingencies associated with third-party claims arising out of its
mining operations, which is reflected in "Unusual items" in the
accompanying consolidated statements of income for the year ended December
31, 2000. In the opinion of management, the outcome of such matters to the
extent not previously provided for or covered under insurance, will not
have a material adverse effect on the Partnership's business, financial
position or results of operations, although management cannot give any
assurance to that effect.
OTHER - During September 2002, the Partnership completed its annual
property insurance and casualty renewal. In general, recent insurance
carrier losses worldwide have created a tightening market reducing
available capacity for underwriting property insurance. As a result, the
Partnership and its affiliates increased the deductible for commercial
property insurance from $1.0 million to $3.5 million and, in addition,
retained a participating interest along with its insurance carriers in the
commercial property program at various levels up to 15.48%. The aggregate
maximum limit in the commercial property program is $50.0 million per
occurrence of which the Partnership would be responsible for a maximum
limit of $7.7 million for each occurrence. While the Partnership does not
have a significant history of material insurance claims, the ultimate
amount of occurrences incurred and claims made, if
61
any, are dependent on future developments. The Partnership cannot assure
that it will not experience significant insurance claims in the future,
which as a result of the Partnership's participation in the commercial
property program, could have a material adverse effect on its business,
financial condition and results of operations.
The Partnership is involved in a dispute with PSI Energy Inc. ("PSI")
concerning the procedures for and testing of a certain coal quality
specification relating to the minimum Hardgrove Grindability Index (i.e.,
physical hardness of coal) of coal supplied by its Gibson County Coal
mining complex. Gibson County Coal and PSI have had on-going discussions
since March 2001 concerning the procedures for and testing of coal supplied
by the Gibson County Coal mining complex, and have been unable to resolve
their differences to-date. During March and April 2002, PSI withheld
approximately $234,000 in payments due to Gibson County Coal. PSI has not
withheld any additional payments and has verbally advised that it does not
intend to withhold any future payments until this dispute is resolved. PSI
claimed damages of $2,220,000 at December 31, 2002.
During April 2002, Gibson County Coal and PSI agreed to proceed with
mediation in an effort to resolve this contractual dispute. The mediation
of the dispute occurred in August 2002 during which the parties concluded
an outline of a tentative settlement, subject to the negotiation of a
definitive settlement agreement. The parties are in the process of
negotiating such settlement agreement, but no assurance can be provided
that a final settlement can be reached. In the event the final settlement
agreement and certain other agreements cannot be concluded, the parties
will proceed with either additional mediation efforts or resort to
arbitration. Gibson County Coal continues to strongly disagree with PSI's
position.
16. CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS
The Partnership has significant long-term coal supply agreements, some of
which contain prospective 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 transportation rates.
Total revenues to major customers, including transportation revenues (Note
2), which exceed ten percent of total revenues (Customers D and E comprise
less than one percent and seven percent of total revenues in 2002,
respectively) are as follows (in thousands):
YEAR ENDED DECEMBER 31,
-------------------------------
2002 2001 2000
--------- ------- -------
Customer A $ 113,094 $ 540 $ -
Customer B 69,933 74,091 58,498
Customer C 72,224 63,241 67,234
Customer D 1,047 47,492 61,007
Customer E 32,491 32,614 38,713
Trade accounts receivable from these customers totaled approximately $17.2
million at December 31, 2002. The Partnership's bad debt experience has
historically been insignificant, however the Partnership established an
allowance of $763,000 during 2001, due to the Partnership's total credit
exposure to Enron Corp., which filed for bankruptcy protection during
December 2001. Financial conditions of its customers could result in a
material change to this estimate in future periods. The coal supply
agreements with Customers A, C, D and E expire in 2006 and Customer B in
2010.
62
17. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
A summary of the quarterly operating results for the Partnership is as
follows (in thousands, except unit and per unit data):
QUARTER ENDED
-----------------------------------------------------------
MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31,
2002 2002 2002 2002
----------- ----------- ------------- ------------
Revenues $ 125,051 $ 126,829 $ 132,171 $ 133,691
Operating income 14,738 18,019 9,268 10,249
Income before income taxes 11,220 14,220 4,801 6,223
Net income 11,220 14,220 4,801 6,048
Basic net income per limited partner unit $ 0.71 $ 0.90 $ 0.31 $ 0.38
Diluted net income per limited
partner unit $ 0.69 $ 0.88 $ 0.30 $ 0.37
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 15,841,062 15,842,657 15,844,316 15,842,783
QUARTER ENDED
--------------------------------------------------------------
MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31,
2001 (1) 2001 2001 2001
------------ ------------- ------------- -------------
Revenues $ 106,752 $ 110,722 $ 117,894 $ 110,932
Operating income 8,456 4,012 11,943 803
Net income (loss) 12,375 (46) 7,816 (3,045)
Basic net income (loss) per limited partner unit $ 0.79 $ (0.01) $ 0.50 $ (0.19)
Basic net income (loss) per limited partner unit
before accounting change $ 0.28 $ (0.01) $ 0.50 $ (0.19)
Diluted net income (loss) per limited
partner unit $ 0.77 $ (0.01) $ 0.49 $ (0.19)
Diluted net income (loss) per limited
partner unit before accounting change $ 0.28 $ (0.01) $ 0.49 $ (0.19)
Weighted average number of units
outstanding - basic 15,405,311 15,405,311 15,405,311 15,405,311
Weighted average number of units
outstanding - diluted 15,680,594 15,681,411 15,678,013 15,708,968
(1) The Partnership changed its method of estimating black lung benefits
liability effective January 1, 2001. The cumulative effect of this
change resulted in the reduction of this liability and a corresponding
increase in net income of $7,939,000 for the quarter (Note 3).
Operating income in the above table represents income from operations
before interest expense.
18. REGISTRATION STATEMENT
The Partnership filed a shelf registration statement on April 1, 2002 to
register common units representing limited partner interests and debt
securities, including guarantees. The Partnership, exclusive of its
investment in all of its wholly-owned operating subsidiaries, has no
independent assets or operations. If a series of debt securities is
guaranteed, such series will be guaranteed by all of the Partnership's
operating subsidiaries on a full and unconditional and joint and several
basis.
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19. SUBSEQUENT EVENTS
On February 14, 2003, the Partnership completed a public offering of
2,250,000 common units and received net proceeds of approximately $48.5
million, before expenses, other than underwriters fees and on March 14,
2003, received net proceeds of approximately $6.2 million, before expenses,
from the exercise of the underwriters option to purchase an additional
288,000 common units. The Partnership used the net proceeds to fund the
purchase of Warrior Coal and for working capital and general partnership
purposes.
The Partnership acquired Warrior Coal on February 14, 2003 pursuant to the
terms of an Amended and Restated Put/Call Agreement with ARH Warrior
Holdings, a subsidiary of ARH. The Partnership paid the put option price of
$12.7 million and repaid Warrior Coal's borrowings of $17.0 million under
the revolving credit agreement between the Special GP and Warrior Coal.
Because the Warrior Coal acquisition is between entities under common
control, it will be accounted for at historical cost in a manner similar
to that used in a pooling of interests.
* * * * * *
64
SCHEDULE II
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 2002 AND 2001
BALANCE AT ADDITIONS BALANCE AT
BEGINNING CHARGED TO END OF
OF YEAR INCOME DEDUCTIONS YEAR
(In Thousands)
2002
Allowance for doubtful accounts $ 763 $ - $ - $ 763
====== ====== ==== ======
2001
Allowance for doubtful accounts $ - $ 763 $ - $ 763
====== ====== ==== ======
A table for fiscal year ended December 31, 2000 has been omitted because there
was no allowance for doubtful accounts.
65
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. IRECTORS AND EXECUTIVE OFFICERS OF THE MANAGING GENERAL PARTNER
As is commonly the case with publicly-traded limited partnerships, we
are managed and operated by our managing general partner. The following table
shows information for the directors and executive officers of the managing
general partner. Executive officers and directors are elected until death,
resignation, retirement, disqualification, or removal.
NAME AGE POSITION WITH OUR MANAGING GENERAL PARTNER
- -------------------- --- ------------------------------------------
Joseph W. Craft III 52 President, Chief Executive Officer and Director
Robert G. Sachse 54 Executive Vice President and Vice Chairman of the Board
Thomas L. Pearson 49 Senior Vice President - Law and Administration,
General Counsel and Secretary
Charles R. Wesley 48 Senior Vice President - Operations
Gary J. Rathburn 52 Senior Vice President - Marketing
Michael J. Hall 58 Director and Member of the Audit* and Conflicts
Committees
John J. MacWilliams 47 Director
Preston R. Miller, Jr. 54 Director and Member of the Compensation* Committee
John P. Neafsey 63 Chairman of the Board and Member of Audit, Compensation
and Conflicts Committees
John H. Robinson 52 Director and Member of Audit, Compensation and
Conflicts Committees
*Indicates Chairman of Committee
Joseph W. Craft III has been President, Chief Executive Officer and a
Director since August 1996 and has indirect majority ownership of our managing
general partner. Previously Mr. Craft served as President of MAPCO Coal Inc.
since 1986. During that period, he also was Senior Vice President of MAPCO Inc.
and had been previously that company's General Counsel and Chief Financial
Officer. Before joining MAPCO, Mr. Craft was an attorney at Falcon Coal
Corporation and Diamond Shamrock Coal Corporation. He is past Chairman of the
National Coal Council, a Board and Executive Committee Member of the National
Mining
66
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 has been Executive Vice President and Vice Chairman since
August 2000. Prior to his current position, Mr. Sachse was Executive Vice
President and Chief Operating Officer of MAPCO Inc. from 1996 to 1998 when MAPCO
merged with The Williams Companies. He held various positions with MAPCO Coal
Inc. from 1982 to 1991, and was promoted to President of MAPCO Natural Gas
Liquids in 1992. Mr. Sachse holds a Bachelor of Science degree from Trinity
University and a Juris Doctor degree from the University of Tulsa.
Thomas L. Pearson has been Senior Vice President -- Law and Administration,
General Counsel and Secretary since August 1996. Mr. Pearson previously was
Assistant General Counsel of MAPCO Inc., and served as General Counsel and
Secretary of MAPCO Coal Inc. from 1989 to 1996. Before joining the company, he
was General Counsel and Secretary of McLouth Steel Products Corporation,
Corporate Counsel for Midland-Ross Corporation, and an attorney for Arter &
Hadden, a law firm in Cleveland, Ohio. Mr. Pearson's current and past business,
charitable and education involvement includes Trustee of the Energy and Mineral
Law Foundation, Vice Chairman, Legal Affairs Committee, National Mining
Association, and Member, Dean's Committee, The University of Iowa College of
Law. 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.
Charles R. Wesley has been Senior Vice President -- Operations since August
1996. He joined the company in 1974 when he began working for Webster County
Coal Corporation as an engineering co-op student. In 1992, Mr. Wesley was named
Vice President -- Operations for Mettiki Coal Corporation. He has served the
industry as past President of the West Kentucky Mining Institute and National
Mine Rescue Association Post 11, and he has 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 been Senior Vice President -- Marketing since August
1996. He joined MAPCO Coal Inc. as Manager of Brokerage Coals in 1980. Since
that time, he has managed all phases of the marketing group involving
transportation and distribution, international sales and the brokering of coal.
Prior to joining the company, Mr. Rathburn was employed by Eastern Associated
Coal Corporation in its International Sales and Brokerage groups. Active in many
industry-related groups, he 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.
Michael J. Hall became a Director in March 2003. Mr. Hall is Vice President
- - Finance and Chief Financial Officer of Matrix Service Company and serves on
its Board of Directors. Prior to working for Matrix, Mr. Hall was Vice President
and Chief Financial Officer of Pexco Holdings, Inc., Vice President - Finance
and Chief Financial Officer for Worldwide Sports & Recreation, Inc. an
affiliated company of Pexco and worked for T.D. Williamson, Inc., as Senior Vice
President, Chief Financial and Administrative Officer, and Director of
Operations -- Europe, Africa and Middle East Region. Mr. Hall holds a Bachelor
of Science degree in Accounting from Boston College and a Master of Business
Administration from Stanford University. Mr. Hall is Chairman of the Audit
Committee and a Member of the Conflicts Committee. .
John J. MacWilliams, a General Partner of The Beacon Group, LP, has served
as a Director since June 1996. Mr. MacWilliams' previous positions include
serving as a General Partner of JP Morgan Partners, Executive Director of
Goldman Sachs International in London, Vice President for Goldman Sachs & Co.'s
67
Investment Banking Division in New York, and as an attorney at Davis Polk &
Wardwell in New York. He also is a Director of Compagnie Generale de
Geophysique. Mr. MacWilliams holds a Bachelor of Arts degree from Stanford
University, Master of Science degree from Massachusetts Institute of Technology,
and a Juris Doctor degree from Harvard Law School.
Preston R. Miller, Jr., a General Partner of The Beacon Group, LP, has
served as a Director since June 1996. Mr. Miller's previous positions include
serving as a General Partner of JP Morgan Partners and as Vice President for
Goldman Sachs & Co.'s Structured Finance Group in New York City where he had
global responsibility for coverage of the independent power industry,
asset-backed power generation, and oil and gas financing. He also has a
background in credit analysis, and was head of the revenue bond rating group at
Standard & Poor's Corp. Mr. Miller holds a Bachelor of Arts degree from Yale
University and a Master of Public Administration degree from Harvard University.
Mr. Miller is the Chairman of our Compensation Committee.
John P. Neafsey has served as Chairman since June 1996. Mr. Neafsey is
President of JN Associates, an investment consulting firm. Mr. Neafsey served as
President and CEO of Greenwich Capital Markets from 1990 to 1993 and a Director
since its founding in 1983. Positions that Mr. Neafsey held during a 23-year
career at The Sun Company include Executive Vice President responsible for
Canadian operations, Sun Coal Company and Helios Capital Corporation; Chief
Financial Officer; and other executive positions with numerous subsidiary
companies. He is or has been active in a number of organizations, including the
following: Director for The West Pharmaceutical Services Company and Longhorn
Partners Pipeline, Inc. Trustee Emeritus and Presidential Counselor, Cornell
University, and Overseer of Cornell-Weill Medical Center. Mr. Neafsey holds
Bachelor and Master of Science degrees in Engineering and a Master of Business
Administration degree from Cornell University. Mr. Neafsey is a Member of the
Audit, Conflicts and Compensation Committees.
John H. Robinson became a Director in December 1999. Mr. Robinson is
Executive Director of Metilinx Inc, a systems optimization software company.
From 2000 to 2002, he was Executive Director of the Technology Services Division
of Amey plc, a British support services business. Mr. Robinson served as Vice
Chairman of Black & Veatch from 1997 to 2000. He began his career at Black &
Veatch in 1973 and was a General Partner and Managing Partner prior to becoming
Vice Chairman when the firm incorporated. Mr. Robinson is a Director of Coeur
d'Alene Mining Corporation. Mr. Robinson holds Bachelor and Master of Science
degrees in Engineering from the University of Kansas and is a graduate of the
Owner-President-Management Program at the Harvard Business School. He is a
Member of our Audit, Compensation, and Conflicts Committees.
The position of Chairman of the Conflicts Committee of our managing general
partner is currently open because of the retirement of Mr. Paul Tregurtha from
the Board of Directors in December 2002. We expect that one of the current
committee members will be elected as Chairman of the Conflicts Committee.
The Chief Financial Officer position of our managing general partner is
currently open and an executive search is underway to find an individual to fill
this position. Until this position is filled, the responsibilities of the
Principle Financial Officer is jointly shared by Messrs. Joseph W. Craft and
Cary P. Marshall, Vice President - Corporate Finance and Treasurer. The
responsibilities of the Principle Accounting Officer are performed by Dale G.
Wilkerson, Vice President and Controller.
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Securities and Exchange Act of 1934, as amended,
requires directors, executive officers and persons who beneficially own more
than ten percent of a registered class of our equity securities to file with the
SEC initial reports of ownership and reports or changes in ownership of such
equity securities.
68
Such persons are also required to furnish us with copies of all Section 16(a)
forms they file. Based solely upon a review of the copies of the forms furnished
to it, or written representations from certain reporting persons, we believe
that during 2002 none of our officers and directors was delinquent with respect
to any of the filing requirements under Rule 16(a) other than Mr. Sachse who did
not timely file a Form 4 for a purchase on October 2, 2002, but has since filed
a Form 4 with respect to this transaction.
REIMBURSEMENT OF EXPENSES OF THE MANAGING GENERAL PARTNER AND ITS AFFILIATES
The managing general partner does not receive any management fee or other
compensation in connection with its management of us. However, our managing
general partner and its affiliates, including Alliance Resource Holdings,
perform services for us and are reimbursed by us for all expenses incurred on
our behalf, including the costs of employee, officer and director compensation
and benefits properly allocable to us, as well as all other expenses necessary
or appropriate to the conduct of our business, and properly allocable to us. Our
partnership agreement provides that the managing general partner will determine
the expenses that are allocable to us in any reasonable manner determined by the
managing general partner in its sole discretion.
ITEM 11. EXECUTIVE COMPENSATION
EXECUTIVE COMPENSATION
The following table sets forth certain compensation information for the
Chief Executive Officer, the former Chief Financial Officer, and each of the
four other most highly compensated executive officers of our managing general
partner in excess of $100,000 in 2002, 2001 and 2000. We reimburse our managing
general partner and its affiliates for expenses incurred on our behalf,
including the cost of officer compensation allocable to us.
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION LONG TERM
---------------------------------------- COMPENSATION
OTHER ANNUAL RESTRICTED ALL OTHER
BONUS COMPENSATION STOCK AWARDS COMPENSATION
NAME AND PRINCIPAL POSITIO YEAR SALARY (1) (2) (3) (4)
- -------------------------------------------------------------------------------------------------------------------------------
Joseph W. Craft III, 2002 $ 328,955 $ 227,000 $ 1,075 $1,237,500 $ 52,171
President, Chief Executive Officer 2001 314,700 130,000 5,250 781,875 50,562
and Director 2000 292,950 94,200 - 678,150 63,695
Thomas L. Pearson, 2002 196,178 83,000 1,750 222,750 32,631
Senior Vice President-Law and 2001 192,000 63,000 1,167 140,738 31,914
Administration, General Counsel and Secretary 2000 177,000 45,000 1,550 122,067 43,856
Michael L. Greenwood (5) 2002 180,267 - - 222,750 93,250
Senior Vice President-Chief 2001 162,650 50,000 - 140,738 24,531
Financial Officer and Treasurer 2000 151,400 45,000 - 122,067 26,009
Charles R. Wesley, 2002 211,504 130,000 - 247,500 33,001
Senior Vice President-Operations 2001 202,000 65,000 925 156,375 33,286
2000 187,000 47,600 1,500 135,630 32,802
Gary J. Rathburn, 2002 170,634 90,000 2,285 233,750 29,884
Senior Vice President-Marketing 2001 167,000 70,000 3,000 140,738 26,702
2000 152,000 45,000 1,500 122,067 28,008
69
Robert G. Sachse (6) 2002 180,392 - - 61,875 25,470
Executive Vice President, 2001 180,265 - - 39,096 21,976
Vice Chairman and Director 2000 62,981 - - - 5,149
(1) Amounts awarded under the Short-Term Incentive Plan. See "Short-Term
Incentive Plan" below.
(2) Amounts reimbursed for income tax preparation and financial planning
services.
(3) Awards under the Long-Term Incentive Plan. The amount represents the
value of restricted units at the effective date of grant. The total
number of restricted units and their aggregate market value as of
December 31, 2002, were: Mr. Craft, 140,000 units valued at $3,390,800;
Mr. Pearson, 25,200 units valued at $610,344; Mr. Greenwood, 25,200
units valued at $610,344; Mr. Wesley, 28,000 units valued at $678,160;
Mr. Rathburn, 25,600 units valued at $620,032; Mr. Sachse 4,500 units
valued at $108,990. Units granted under the Long-Term Incentive Plan do
not vest until the end of the subordination period, which will
generally not end before September 30, 2004. See "Long-Term Incentive
Plan" below.
(4) Amounts represent (a) the managing general partner's matching
contributions to its 401(k) Plan, (b) the managing general partner's
contribution to its Supplemental Executive Retirement Plan (SERP), (c)
in regard to Mr. Greenwood only, a payment of $85,050 in accordance
with the terms of the SERP and (d) in regard to Mr. Sachse only, the
managing general partner's contribution to its Directors Compensation
Program.
(5) Mr. Greenwood separated from service effective May 17, 2002, Under the
terms of his severance agreement he continued to receive compensation
during 2002.
(6) Mr. Sachse was hired effective August 14, 2000; therefore his 2000
compensation information is for the period from August 14, 2000 to
December 31, 2000.
COMPENSATION OF DIRECTORS
Under the managing general partner's Directors Compensation Program
(Directors Plan) each non-employee Director is paid an annual retainer of
$21,500. The annual retainer is payable in common units to be paid on a
quarterly basis in advance determined by dividing the pro rata annual retainer
payable on such date by the closing sales price per common unit averaged over
the immediately preceding ten trading days. Each non-employee director may elect
to defer all or a portion of his or her compensation under the Deferred
Compensation Plan for Directors.
In addition, each non-employee director participates in the Long-Term
Incentive Plan. The directors restricted units vest in accordance with the
procedures 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 general partner for
a term of three years, commencing August 14, 2000. The consulting agreement
provides that Mr. Sachse will serve as Executive Vice President of the managing
general partner and devote his services on a part-time basis. In addition to
compensation received under the Directors and Long-Term Incentive Plans
described above, Mr. Sachse is entitled to receive an annual fee of $150,000,
payable in arrears monthly. Mr. Sachse also is entitled to receive quarterly
payments in arrears of $7,500, less the market value of 250 common units
calculated by the closing sales price per common unit averaged over the
immediately preceding ten trading days. A copy of the consulting agreement with
Mr. Sachse is an exhibit hereto.
EMPLOYMENT AGREEMENTS
The executive officers of the managing general partner and some additional
members of senior management will enter into employment agreements among the
executive officer or member of senior
70
management, on the one hand, and the managing general partner on the other. We
reimburse the managing general partner for the compensation and benefits costs
under these agreements. This summary of the terms of the employment agreements
does not purport to be complete, but outlines their material provisions. A form
of the agreements with each of Messrs. Craft, Pearson, Wesley and Rathburn is an
exhibit hereto.
Each of the form of employment agreements had an initial term that expired
on December 31, 2002, but automatically extend for successive one-year terms
unless either party gives 12 months prior notice to the other party. The form of
employment agreements provide for a base salary, subject to review annually, of
$334,828, $199,680, $215,280 and $173,680 for Messrs. Craft, Pearson, 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, Wesley and Rathburn,
following termination of employment, except in the case of a change of control
of the managing general partner.
In the case of a "change of control" as defined in the agreements, in lieu
of the continuation of salary and benefits, that executive will be entitled to a
lump sum payment in an amount equal to three times base salary plus bonus, in
the case of Mr. Craft, and two times base salary plus bonus in the case of
Messrs. Pearson, Wesley and Rathburn. Unless the executive waives his or her
right to the continuation of base salary and bonus, the agreements provide for a
noncompetition period of 18 months. The noncompetition period does not apply
after a change in control. Amounts paid by the managing general partner pursuant
to the employment agreements will be reimbursed by us.
The executives who are subject to employment agreements also participate in
the Short- and Long-Term Incentive Plans of the managing general partner
described below along with other members of management. They also are entitled
to participate in the other employee benefit plans and programs that the
managing general partner provides for its employees.
LONG-TERM INCENTIVE PLAN
Effective January 1, 2000, the managing general partner adopted the
Long-Term Incentive Plan (LTIP) for certain employees and directors of the
managing general partner and its affiliates who perform services for us. The
summary of the LTIP contained herein does not purport to be complete, but
outlines its material provisions.
The LTIP is administered by the Compensation Committee of the managing
general partner's Board of Directors. Annual grant levels for designated
participants are recommended by the President and CEO of the managing general
partner, subject to the review and approval of the Compensation Committee. We
will reimburse the managing general partner for all costs incurred pursuant to
the programs described below. Grants are made of either restricted units, which
are "phantom" units that entitle the grantee to receive a common unit or an
equivalent amount of cash upon the vesting of a phantom unit, or options to
purchase common units. Common units to be delivered upon the vesting of
restricted units or to be issued upon exercise of a unit option will be acquired
by the managing general partner in the open market at a price equal to the then
prevailing price, or directly from Alliance Resource Holdings or any other third
party, including units newly issued by us, or use units already owned by the
managing general partner, or any combination of the foregoing. The managing
general partner is entitled to reimbursement by us for the cost incurred in
acquiring these common units or in paying cash in lieu of common units upon
vesting of the restricted units. If we issue new common units upon payment of
the restricted units or unit options instead of purchasing them, the total
number of common units outstanding will increase. The aggregate number of units
reserved for issuance under the LTIP is 600,000. Effective January 1, 2002, 2001
and 2000, the Compensation Committee approved initial grants of 133,885, 129,200
and 142,100 restricted units, vesting at the end of the subordination period,
which generally will not end before September 30, 2004. As of December 31, 2002,
71
15,050 units have been forfeited. Effective as of January 1, 2003, the
Compensation Committee approved additional grants of 139,705 restricted units,
which vest September 30, 2005, subject to certain financial tests.
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, in the future, may decide to make unit option grants to employees and
directors containing the specific terms as the Committee determines. When
granted, unit options will have an exercise price set by the Compensation
Committee which may be above, below or equal to the fair market value of a
common unit on the date of grant. Unit options, if any, granted during the
subordination period will become exercisable upon, and in the same proportions
as, the conversion of the subordinated units to common units, or at a later date
as determined by the Compensation Committee in its sole discretion.
The managing general partner's Board of Directors, in its discretion, may
terminate the LTIP at any time with respect to any common units for which a
grant has not previously been made. The managing general partner's Board of
Directors will also have the right to alter or amend the LTIP or any part of it
from time to time, subject to unitholder approval as required by the exchange
upon which the common units may be listed at that time; provided, however, that
no change in any outstanding grant may be made that would materially impair the
rights of the participant without the consent of the affected participant. In
addition, the managing general partner may, in its discretion, establish such
additional compensation and incentive arrangements as it deems appropriate to
motivate and reward its employees. The managing general partner is reimbursed
for all compensation expenses incurred on our behalf.
Long-Term Incentive Plan - Awards in Last Fiscal Year
PERFORMANCE OR
OTHER PERIOD UNTIL
NUMBER OF MATURATION OR
UNITS (1) PAYOUT (2)
--------- ------------------
Joseph W. Craft III 45,000 33 Months
Thomas L. Pearson 8,100 33 Months
Michael L. Greenwood 8,100 33 Months
Charles R. Wesley 9,000 33 Months
Gary J. Rathburn 8,500 33 Months
Robert G. Sachse 2,250 33 Months
(1) Units granted under the LTIP will vest at the end of the subordination
period. The subordination period will end if certain financial tests
contained in the partnership agreement are met for three consecutive
four-quarter periods, but not sooner than September 30, 2004.
72
(2) The number of units granted is not subject to minimum
thresholds, targets or maximum payout conditions.
SHORT-TERM INCENTIVE PLAN
Effective January 1, 1999, the managing general partner adopted a
Short-Term Incentive Plan (STIP) for management and other salaried employees.
The STIP is designed to enhance the financial performance by rewarding
management and our salaried employees and those of the managing general partner
with cash awards for our achieving an annual financial performance objective.
The annual performance objective for each year is recommended by the President
and CEO of the managing general partner and approved by the Compensation
Committee of its Board of Directors prior to or during January of that year. The
STIP is administered by the Compensation Committee. Individual participants and
payments each year are determined by and in the discretion of the Compensation
Committee, and the managing general partner is able to amend the plan at any
time. The managing general partner is entitled to reimbursement by us for the
costs incurred under the STIP.
SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN
Effective January 1, 1997, the managing general partner adopted a
supplemental executive retirement plan (SERP) for certain officers and key
employees. The purpose of the SERP is to enhance our ability to retain specific
officers and key employees, by providing them with the deferred compensation
benefits contained in the SERP. The intent of the SERP is to provide each
participant with retirement benefits that are comparable in value to those of
similar retirement programs administered by other companies, as well as to align
each participant's supplemental benefits under the SERP with the interests of
the our unitholders. All allocations made to participants under the SERP are
made in the form of "phantom" units. The SERP is administered by the
Compensation Committee. The managing general partner is able to amend or
terminate the plan at any time. The managing general partner is entitled to
reimbursement by us for its costs incurred under the SERP.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth certain information as of March 1, 2003,
regarding the beneficial ownership of common and subordinated units held by (a)
each person known by the managing general partner to be the beneficial owner of
5% or more of the common and subordinated units, (b) each director and executive
officer of the managing general partner and (c) all directors and executive
officers of the managing general partner as a group. The managing general
partner is owned by members of management. The special general partner is a
wholly-owned subsidiary of Alliance Resource Holdings. The address of Alliance
Resource Holdings, the managing general partner and the special general partner
is 1717 South Boulder Avenue, Tulsa, Oklahoma 74119.
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PERCENTAGE OF
COMMON COMMON SUBORDINATED SUBORDINATED OF TOTAL
UNITS UNITS UNITS UNITS UNITS
BENEFICIALLY BENEFICIALLY BENEFICIALLY BENEFICIALLY BENEFICIALLY
NAME OF BENEFICIAL OWNER OWNED (5) OWNED OWNED OWNED OWNED
- --------------------------------------- ------------ ------------- ------------ ------------ ------------
Alliance Resource gp, llc (1) 1,232,780 11.01% 6,422,531 100% 43.4%
Joseph W. Craft iii (1) (4) 1,449,223 12.94% 6,422,531 100% 44.7%
Robert G. Sachse (1) 6,302 * - - *
Thomas L. Pearson (1) 17,151 * - - *
Charles R. Wesley (1) 53,392 * - - *
Gary J. Rathburn (1) 14,793 * - - *
John J. MacWilliams (2) - * - - *
Preston R. Miller, jr. (2) - * - - *
John P. Neafsey (1) 13,729 * - - *
John H. Robinson (3) 4,685 * - - *
All directors and executive officers as
a group (9 persons) 1,559,275 13.93% 6,422,531 100% 45.3%
* Less than one percent.
(1) The address of Alliance Resource GP, LLC and Messrs. Craft, Sachse,
Pearson, Wesley, Rathburn and Neafsey is 1717 South Boulder Avenue,
Tulsa, Oklahoma 74119.
(2) The address of Messrs. MacWilliams and Miller is The Beacon Group, LP,
275 Grove St., Suite 2-400, Newton, Massachusetts 02466.
(3) The address of Mr. Robinson is 11 Grosvenor Crescent, London, England
SW1X 7EE.
(4) Mr. Craft may be deemed to share beneficial ownership of 1,232,780
common units and 6,422,531 subordinated units held by Alliance Resource
GP, LLC through Alliance Resource Holdings II, Inc., of which he is the
sole director and majority shareholder. Alliance Resource Holdings II
holds all of the outstanding shares of Alliance Resource Holdings,
Inc., which holds all of the outstanding shares of Alliance Resource
GP. Mr. Craft may be deemed to share beneficial ownership of 115,695
common units held be AMH II, LLC, of which he is the sole director and
majority member. Mr. Craft may be deemed to share beneficial ownership
of 11,667 common units held by Alliance Management Holdings, LLC, of
which he is the sole director and majority member. Mr. Craft may also
be deemed to share beneficial ownership of an additional 13,500 common
units held by a private foundation for which he serves as a Trustee.
Mr. Craft disclaims beneficial ownership of the common units held by
the private foundation.
(5) The amounts set forth do not include any restricted units granted under
the LTIP.
EQUITY COMPENSATION PLAN INFORMATION
NUMBER OF UNITS TO BE ISSUED UPON NUMBER OF UNITS REMAINING
EXERCISE/VESTING OF OUTSTANDING WEIGHTED-AVERAGE EXERCISE PRICE AVAILABLE FOR FUTURE ISSUANCE UNDER
OPTIONS, WARRANTS AND RIGHTS OF OUTSTANDING OPTIONS, WARRANTS EQUITY COMPENSATION PLANS
PLAN CATEGORY AS OF MARCH 1, 2003 AND RIGHTS AS OF MARCH 1, 2003
EQUITY COMPENSATION PLANS
APPROVED BY UNITHOLDERS:
Long-Term Incentive Plan 514,790 N/A 85,210
EQUITY COMPENSATION PLANS
NOT APPROVED BY
UNITHOLDERS:
Supplemental Executive
Retirement Plan 38,405 N/A 41,595
Deferred Compensation Plan
for Directors 15,498 N/A 34,502
Please read "Supplemental Executive Retirement Plan" and "Compensation of
Directors" under "Item 11. Executive Compensation."
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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The special general partner owns 1,232,780 common units and 6,422,531
subordinated units representing an aggregate 42.6% limited partner interest in
us. In addition, the general partners own, on a combined basis, an aggregate 2%
general partner interest in us, the intermediate partnership and the
subsidiaries. The managing general partner's ability, as managing general
partner, together with the special general partner's ownership of 1,232,780
common units and 6,422,531 subordinated units, effectively gives the general
partners the ability to veto some of our actions and to control our management.
TRANSACTIONS BETWEEN THE PARTNERSHIP, SPECIAL GENERAL PARTNER AND ALLIANCE
RESOURCE HOLDINGS
We purchase coal from affiliates, lease a coal preparation plant and
handling facilities at Gibson, lease coal reserves from our special general
partner and its affiliates, provide general and administrative services to an
affiliate, and receive reclamation services at Dotiki from an affiliate. Our
special general partner guarantees our letters of credit. In accordance with the
provisions of a put/call option agreement, we purchased Warrior from ARH Warrior
in February 2003. See "Item 8. Financial Statements and Supplementary Data. -
Note 14. Related Party Transactions" and "Liquidity and Capital Resources -
Related Party Transactions" under "Item 7. Management's Discussion and Analysis
of Financial Condition and Results of Operations."
OTHER RELATED PARTY TRANSACTIONS
J.P. Morgan Chase & Co. (Chase) is paying agent, co-administrative agent
and a lender under our Credit Facility. In 2002 and 2001, we made interest and
principle payments to Chase on outstanding borrowings and paid Chase customary
fees for their other services. We expect that these relationships will continue
in 2003. The Beacon Group is an affiliate of Chase. Messrs. MacWilliams and
Miller are General Partners of the Beacon Group and Directors of the managing
general partner.
OMNIBUS AGREEMENT
Concurrent with the closing of our initial public offering, we entered into
an omnibus agreement with Alliance Resource Holdings and the general partners,
which governs potential competition among us and the other parties to this
agreement. The omnibus agreement was amended in May 2002. Pursuant to the terms
of the amended omnibus agreement, Alliance Resource Holdings agreed, and caused
its controlled affiliates to agree, for so long as management controls the
managing general partner, not to engage in the business of mining, marketing or
transporting coal in the U.S. unless it first offers us the opportunity to
engage in a potential activity or acquire a potential business, and the Board of
Directors of the managing general partner, with the concurrence of its Conflicts
Committee, elects to cause us not to pursue such opportunity or acquisition. In
addition, Alliance Resource Holdings has the ability to purchase businesses, the
majority value of which is not mining, marketing or transporting coal, provided
Alliance Resource Holdings offers us the opportunity to purchase the coal assets
following their acquisition. The restriction does not apply to the assets
retained and business conducted by Alliance Resource Holdings at the closing of
our initial public offering. Except as provided above, Alliance Resource
Holdings and its controlled affiliates are prohibited from engaging in
activities in which they compete directly with us. In addition to its
non-competition provisions, this agreement contains provisions which indemnify
us against liabilities associated with certain assets and businesses of Alliance
Resource Holdings which were disposed of or liquidated prior to consummating our
initial public offering.
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ITEM 14. CONTROLS AND PROCEDURES
Within the 90-day period prior to filing of this report, an evaluation was
carried out by management, including our chief executive officer and principal
accounting officer, of the effectiveness of the design and operation of our
disclosure controls and procedures (as defined in Rule 13a-14(c) under the
Securities Exchange Act of 1934). Based upon this evaluation, the chief
executive officer and the principal accounting officer concluded that the design
and operation of these disclosure controls and procedures were effective.
Subsequent to this evaluation on March 14, 2003 through the date of this
filing on Form 10-K for the year ended December 31, 2002, there have been no
significant changes in the Partnership's internal controls or in other factors
that could significantly affect these controls, including any significant
deficiencies or material weaknesses of internal controls that would require
corrective action.
Each of the chief executive officer and the principal accounting officer of
our managing general partner has furnished a certificate to the Securities and
Exchange Commission as required by Section 906 of the Sarbanes-Oxley Act of
2002.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) (1) Financial Statements.
The response to this portion of Item 15 is submitted as a
separate section herein under Part II, Item 8. - Financial
Statements and Supplementary Data.
(a)(2) Financial Statement Schedules.
Schedule II - Valuation and Qualifying Accounts - Years ended
December 31, 2002 and 2001, is set forth under Part II Item 8. -
Financial Statements and Supplementary Data. All other schedules
are omitted because they are not applicable or the information is
shown in the financial statements or notes thereto.
(a)(3) and (c) The exhibits listed below are filed as part of this annual
report.
3.1 Amended and Restated Agreement of Limited Partnership of
Alliance Resource Partners, L.P. (Incorporated by reference to
Exhibit 3.1 of the Registrant's Annual Report on Form 10-K for
the year ended December 31, 1999, File No. 000-26823).
3.2 Amended and Restated Agreement of Limited Partnership of
Alliance Resource Operating Partners, L.P. (Incorporated by
reference to Exhibit 3.2 of the Registrant's Annual Report on
Form 10-K for the year ended December 31, 1999, File No.
000-26823).
3.3 Certificate of Limited Partnership of Alliance Resource
Partners, L.P. (Incorporated by reference to Exhibit 3.6 of
the Registrant's Registration Statement on Form S-1 filed with
the Commission on May 20, 1999 (Reg. No. 333-78845)).
3.4 Certificate of Limited Partnership of Alliance Resource
Operating Partners, L.P. (Incorporated by reference to Exhibit
3.8 of the Registrant's Registration Statement on Form S-1/A
filed with the Commission on July 20, 1999 (Reg. No.
333-78845)).
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3.5 Certificate of Formation of Alliance Resource Management GP,
LLC (Incorporated by reference to Exhibit 3.7 of the
Registrant's Registration Statement on Form S-1/A filed with
the Commission on July 23, 1999 (Reg. No. 333-78845)).
3.6 Amended and Restated Operating Agreement of Alliance Resource
Management GP, LLC (Incorporated by reference to Exhibit 3.4
of the Registrant's Registration Statement on Form S-3 filed
with the Commission on April 1, 2002 (Reg. No. 333-85282)).
3.7 Amendment No. 1 to Amended and Restated Operating Agreement of
Alliance Resource Management GP, LLC (Incorporated by
reference to Exhibit 3.5 of the Registrant's Registration
Statement on Form S-3 filed with the Commission on April 1,
2002 (Reg. No. 333-85282)).
3.8 Amendment No. 2 to Amended and Restated Operating Agreement of
Alliance Resource Management GP, LLC (Incorporated by
reference to Exhibit 3.6 of the Registrant's Registration
Statement on Form S-3 filed with the Commission on April 1,
2002 (Reg. No. 333-85282)).
4.1 Form of Common Unit Certificate (Included as Exhibit A to the
Amended and Restated Agreement of Limited Partnership of
Alliance Resource Partners, L.P.)
10.1 Credit Agreement, dated as of August 16, 1999, among Alliance
Resource GP, LLC, JP Morgan Chase Bank (formerly The Chase
Manhattan Bank) (as paying agent), Deutsche Bank AG, New York
Branch (as documentation agent), Citicorp USA, Inc. and JP
Morgan Chase Bank (as co-administrative agents) and the
lenders named therein. (Incorporated by reference to Exhibit
10.1 of the Registrant's Annual Report on Form 10-K for the
year ended December 31, 1999, File No. 000-26823).
10.2 Amendment No. 1 dated December 7, 2001, to the Credit
Agreement, dated as of August 16, 1999, among Alliance
Resource GP, LLC, JP Morgan Chase Bank (formerly The Chase
Manhattan Bank) (as paying agent), Deutsche Bank AG, New York
Branch (as documentation agent), Citicorp USA, Inc. and JP
Morgan Chase Bank (as co-administrative agents) and the
lenders named therein. (Incorporated by reference to Exhibit
10.2 of the Registrant's Annual Report on Form 10-K for the
year ended December 31, 2001, File No. 000-26823).
10.3 Note Purchase Agreement, dated as of August 16, 1999, among
Alliance Resource GP, LLC and the purchasers named therein.
(Incorporated by reference to Exhibit 10.20 of the
Registrant's Annual Report on Form 10-K for the year ended
December 31, 1999, File No. 000-26823).
10.4 Letter of Credit Facility Agreement dated as of June 29, 2001,
between Alliance Resource Partners, L.P. and Bank of Oklahoma,
National Association. (Incorporated by reference to Exhibit
10.20 of the Registrant's Quarterly Report on Form 10-Q for
the quarter ended September 30, 2001, File No. 000-26823).
10.5 Amendment One to Letter of Credit Facility Agreement between
Alliance Resource Partners, L.P. and Bank of Oklahoma,
National Association.
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(Incorporated by reference to Exhibit
10.32 of the Registrant's Quarterly Report on Form 10-Q for
the quarter ended September 30, 2002, File No. 000-26823).
10.6 Promissory Note Agreement dated as of July 31, 2001, between
Alliance Resource Partners, L.P. and Bank of Oklahoma, N. A.
(Incorporated by reference to Exhibit 10.21 of the
Registrant's Quarterly Report on Form 10-Q for the quarter
ended September 30, 2001, File No. 000-26823).
10.7 Guarantee Agreement, dated as of July 31, 2001, between
Alliance Resource GP, LLC and Bank of Oklahoma, N.A.
(Incorporated by reference to Exhibit 10.22 of the
Registrant's Quarterly Report on Form 10-Q for the quarter
ended September 30, 2001, File No. 000-26823).
10.8 Letter of Credit Facility Agreement dated as of August 30,
2001, between Alliance Resource Partners, L.P. and Fifth Third
Bank. (Incorporated by reference to Exhibit 10.23 of the
Registrant's Quarterly Report on Form 10-Q for the quarter
ended September 30, 2001, File No. 000-26823).
*10.9 Amendment No. 1 to Letter of Credit Facility Agreement between
Alliance Resource Partners, L.P. and Fifth Third Bank.
10.10 Guarantee Agreement, dated as of August 30, 2001, between
Alliance Resource GP, LLC and Fifth Third Bank. (Incorporated
by reference to Exhibit 10.24 of the Registrant's Quarterly
Report on Form 10-Q for the quarter ended September 30, 2001,
File No. 000-26823).
10.11 Letter of Credit Facility Agreement dated as of October 2,
2001, between Alliance Resource Partners, L.P. and Bank of the
Lakes, National Association. (Incorporated by reference to
Exhibit 10.25 of the Registrant's Quarterly Report on Form
10-Q for the quarter ended September 30, 2001, File No.
000-26823).
10.12 First Amendment to the Letter of Credit Facility Agreement
between Alliance Resource Partners, L.P. and Bank of the
Lakes, National Association. (Incorporated by reference to
Exhibit 10.33 of the Registrant's Quarterly Report on Form
10-Q for the quarter ended September 30, 2002, File No.
000-26823).
10.13 Promissory Note Agreement dated as of October 2, 2001, between
Alliance Resource Partners, L.P. and Bank of the Lakes, N.A.
(Incorporated by reference to Exhibit 10.26 of the
Registrant's Quarterly Report on Form 10-Q for the quarter
ended September 30, 2001, File No. 000-26823).
10.14 Guarantee Agreement, dated as of October 2, 2001, between
Alliance Resource GP, LLC and Bank of the Lakes, N.A.
(Incorporated by reference to Exhibit 10.27 of the
Registrant's Quarterly Report on Form 10-Q for the quarter
ended September 30, 2001, File No. 000-26823).
10.15 Guaranty Fee Agreement dated as of July 31, 2001, between
Alliance Resource Partners, L.P. and Alliance Resource GP,
LLC. (Incorporated by reference to Exhibit 10.28 of the
Registrant's Quarterly Report on Form 10-Q for the quarter
ended September 30, 2001, File No. 000-26823).
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10.16 Contribution and Assumption Agreement, dated August 16, 1999,
among Alliance Resource Holdings, Inc., Alliance Resource
Management GP, LLC, Alliance Resource GP, LLC, Alliance
Resource Partners, L.P., Alliance Resource Operating Partners,
L.P. and the other parties named therein. (Incorporated by
reference to Exhibit 10.3 of the Registrant's Annual Report on
Form 10-K for the year ended December 31, 1999, File No.
000-26823).
10.17 Omnibus Agreement, dated August 16, 1999, among Alliance
Resource Holdings, Inc., Alliance Resource Management GP, LLC,
Alliance Resource GP, LLC and Alliance Resource Partners, L.P.
(Incorporated by reference to Exhibit 10.4 of the Registrant's
Annual Report on Form 10-K for the year ended December 31,
1999, File No. 000-26823).
10.18 Alliance Resource Management GP, LLC 2000 Long-Term Incentive
Plan (as amended). (Incorporated by reference to Exhibit 10.11
of the Registrant's Annual Report on Form 10-K for the year
ended December 31, 1999, File No. 000-26823).
10.19 Alliance Resource Management GP, LLC Short-Term Incentive
Plan. (Incorporated by reference to Exhibit 10.12 of the
Registrant's Annual Report on Form 10-K for the year ended
December 31, 1999, File No. 000-26823).
10.20 Alliance Resource Management GP, LLC Supplemental Executive
Retirement Plan. (Incorporated by reference to Exhibit 99.2 of
the Registrant's Registration Statement on Form S-8 filed with
the Commission on April 1, 2002 (Reg. No. 333-85258)).
10.21 Alliance Resource Management GP, LLC Deferred Compensation
Plan for Directors. (Incorporated by reference to Exhibit 99.3
of the Registrant's Registration Statement on Form S-8 filed
with the Commission on April 1, 2002 (Reg. No. 333-85258)).
10.22 Restated and Amended Coal Supply Agreement, dated February 1,
1986, among Seminole Electric Cooperative, Inc., Webster
County Coal Corporation and White County Coal Corporation.
(Incorporated by reference to Exhibit 10.9 of the Registrant's
Registration Statement on Form S-1/A filed with the Commission
on July 20, 1999 (Reg. No. 333-78845)).
10.23 Amendment No. 1 to the Restated and Amended Coal Supply
Agreement effective April 1, 1996, between MAPCO Coal Inc.,
Webster County Coal Corporation, White County Coal
Corporation, and Seminole Electric Cooperative, Inc.
(Incorporated by reference to Exhibit 10.14 of the
Registrant's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2000, File No. 000-26823).
10.24 Amendment No. 2 to the Restated and Amended Coal Supply
Agreement effective February 28, 2002 between Webster County
Coal, LLC, White County Coal, LLC, and Seminole Electric
Cooperative, Inc. (Incorporated by reference to Exhibit 10.32
of the Registrant's Quarterly Report on Form 10-Q for the
quarter ended June 30, 2002, File No. 000-26823).
10.25 Interim Coal Supply Agreement effective May 1, 2000, between
Alliance Coal, LLC and Seminole Electric Cooperative, Inc.
(Incorporated by reference to Exhibit 10.15 of the
Registrant's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2000, File No. 000-26823).
79
10.26 Contract for Purchase and Sale of Coal, dated January 31,
1995, between Tennessee Valley Authority and Webster County
Coal Corporation. (Incorporated by reference to Exhibit 10.10
of the Registrant's Registration Statement on Form S-1/A filed
with the Commission on July 20, 1999 (Reg. No. 333-78845)).
10.27 Assignment/Transfer Agreement between Andalex Resources, Inc.,
Hopkins County Coal LLC, Webster County Coal Corporation and
Tennessee Valley Authority, dated January 23, 1998, with
Exhibit A - Contract for Purchase and Sale of Coal between
Tennessee Valley Authority and Andalex Resources, Inc., dated
January 31, 1995. (Incorporated by reference to Exhibit 10.11
of the Registrant's Registration Statement on Form S-1/A filed
with the Commission on July 20, 1999 (Reg. No. 333-78845)).
10.28 Contract for Purchase and Sale of Coal, dated July 7, 1998,
between Tennessee Valley Authority and Webster County Coal
Corporation. (Incorporated by reference to Exhibit 10.12 of
the Registrant's Registration Statement on Form S-1/A filed
with the Commission on July 20, 1999 (Reg. No. 333-78845)).
10.29 Contract for Purchase and Sale of Coal, dated July 7, 1998,
between Tennessee Valley Authority and White County Coal
Corporation. (Incorporated by reference to Exhibit 10.13 of
the Registrant's Registration Statement on Form S-1/A filed
with the Commission on July 20, 1999 (Reg. No. 333-78845)).
10.30 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).
10.31 Coal Feedstock Supply Agreement dated October 26, 2001,
between Synfuel Solutions Operating LLC and Hopkins County
Coal, LLC (Incorporated by reference to Exhibit 10.27 of the
Registrant's Annual Report on Form 10-K for the year ended
December 31, 2001, File No. 000-26823).
10.32 Amendment No. 1 to Coal Feedstock Supply Agreement dated
February 28, 2002, between Synfuel Solutions Operating LLC and
Hopkins County Coal, LLC (Incorporated by reference to Exhibit
10.28 of the Registrant's Annual Report on Form 10-K for the
year ended December 31, 2001, File No. 000-26823).
10.33 Amended and Restated Put and Call Option Agreement dated
February 12, 2001 between ARH Warrior Holdings, Inc. and
Alliance Resource Partners, L.P. (Incorporated by reference to
Exhibit 10.17 of the Registrant's Annual Report on Form 10-K
for the year ended December 31, 2000, File No. 000-26823).
*10.34 Letter Agreement dated January 31, 2003 between ARH Warrior
Holdings, Inc. and Alliance Resource Partners, L.P.
10.35 Consulting Agreement for Mr. Sachse dated January 1, 2001.
(Incorporated by reference to Exhibit 10.18 of the
Registrant's Annual Report on Form 10-K for the year ended
December 31, 2000, File No. 000-26823).
80
10.36 Form of Employee Agreements for Messrs. Craft, Pearson, Wesley
and Rathburn. (Incorporated by reference to Exhibit 10.6 of
the Registrant's Registration Statement on Form S-1/A filed
with the Commission on August 9, 1999 (Reg. No. 333-78845)).
10.37 Security and Pledge Agreement dated as of May 8, 2002 by and
among Alliance Resource Holdings II, Inc., AMH II, LLC,
Alliance Resource Holdings, Inc., Alliance Resource GP, LLC,
the Management Investors as identified therein, The Beacon
Group Energy Investment Fund, L.P., MPC Partners, LP and three
individuals as "Sellers" identified therein, and JPMorgan
Chase Bank as collateral agent. (Incorporated by reference to
Exhibit 99.2 of the Registrant's Form 8-K filed with the
Commission on May 9, 2002, File No. 000-26823).
10.38 Form of Promissory Note made by Alliance Resource Holdings,
Inc. dated as of May 8, 2002. (Incorporated by reference to
Exhibit 99.3 of the Registrant's Form 8-K filed with the
Commission on May 9, 2002, File No. 000-26823).
18.1 Preferability Letter on Accounting Change. (Incorporated by
reference to Exhibit 18.1 of the Registrant's Amended
Quarterly Report on Form 10-Q/A for the quarter ended March
31, 2001, File No. 000-26823).
*21.1 List of Subsidiaries
*23.1 Consent of Deloitte & Touche LLP regarding Form S-3 and
Form S-8, Registration No. 333-85282 and No. 333-85258,
respectively.
* Filed herewith
(b) Reports on Form 8-K:
A Form 8-K was filed on November 14, 2002 to submit to the
Securities and Exchange Commission the certifications of the
Partnership's Chief Executive Officer and Principal Accounting Officer
pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
A Form 8-K/A was also filed on December 23, 2002 to correct a
typographical error in the Principal Accounting Officer certification
filed on November 14, 2002.
81
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 19, 2003.
ALLIANCE RESOURCE PARTNERS, L.P.
By: Alliance Resource Management GP, LLC
its managing general partner
/s/ Joseph W. Craft III
-----------------------
Joseph W. Craft III
President, Chief Executive
Officer and Director
/s/ Dale G. Wilkerson
---------------------
Dale G. Wilkerson
Vice President and Controller
(Principal Accounting Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
SIGNATURE TITLE DATE
--------- ----- ----
/s/ Joseph W. Craft III President, Chief Executive March 19, 2003
- ----------------------- Officer and Director
Joseph W. Craft III (Principal Executive Officer)
/s/ Dale G. Wilkerson Vice President and Controller March 19, 2003
- ---------------------
Dale G. Wilkerson (Principal Accounting Officer)
/s/ Michael J. Hall Director March 19, 2003
- -------------------
Michael J. Hall
/s/ John J. MacWilliams Director March 19, 2003
- -----------------------
John J. MacWilliams
/s/ Preston R. Miller, Jr. Director March 19, 2003
- --------------------------
Preston R. Miller, Jr.
/s/ John P. Neafsey Director March 19, 2003
- -------------------
John P. Neafsey
/s/ John H. Robinson Director March 19, 2003
- --------------------
John H. Robinson
/s/ Robert G. Sachse Executive Vice President and March 19, 2003
- -------------------- Director
Robert G. Sachse
82
CERTIFICATION
I, Joseph W. Craft III certify that:
1. I have reviewed this Annual Report on Form 10-K of Alliance
Resource Partners, L.P.;
2. Based on my knowledge, this annual report does not contain any
untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not
misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other
financial information included in this annual report, fairly
present in all material respects the financial condition, results
of operations and cash flows of the registrant as of, and for, the
periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible
for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-14 and 15d-14)
for the registrant and we have:
a. designed such disclosure controls and procedures to
ensure that material information relating to the
registrant, including its consolidated subsidiaries, is
made known to us by others within those entities,
particularly during the period in which this annual
report is being prepared;
b. evaluated the effectiveness of the registrant's
disclosure controls and procedures as of a date within 90
days prior to the filing date of this annual report (the
"Evaluation Date"); and
c. presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures
based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed,
based on our most recent evaluation, to the registrant's auditors
and the audit committee of the registrant's board of directors (or
persons performing the equivalent functions):
a. all significant deficiencies in the design or operation
of internal controls which could adversely affect the
registrant's ability to record, process, summarize and
report financial data and have identified for the
registrant's auditors any material weaknesses in internal
controls; and
b. any fraud, whether or not material, that involves
management or other employees who have a significant role
in the registrant's internal controls; and
6. The registrant's other certifying officer and I have indicated in
this annual report whether or not there were significant changes
in internal controls or in other factors that could significantly
affect internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.
Date: March 19, 2003
/s/ Joseph W. Craft III
- -----------------------
Joseph W. Craft III
President, Chief Executive
Officer and Director
83
CERTIFICATION
I, Dale G. Wilkerson certify that:
1. I have reviewed this Annual Report on Form 10-K of Alliance
Resource Partners, L.P.;
2. Based on my knowledge, this annual report does not contain any
untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not
misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other
financial information included in this annual report, fairly
present in all material respects the financial condition, results
of operations and cash flows of the registrant as of, and for, the
periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible
for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-14 and 15d-14)
for the registrant and we have:
a. designed such disclosure controls and procedures to
ensure that material information relating to the
registrant, including its consolidated subsidiaries, is
made known to us by others within those entities,
particularly during the period in which this annual
report is being prepared;
b. evaluated the effectiveness of the registrant's
disclosure controls and procedures as of a date within 90
days prior to the filing date of this annual report (the
"Evaluation Date"); and
c. presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures
based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed,
based on our most recent evaluation, to the registrant's auditors
and the audit committee of the registrant's board of directors (or
persons performing the equivalent functions):
a. all significant deficiencies in the design or operation
of internal controls which could adversely affect the
registrant's ability to record, process, summarize and
report financial data and have identified for the
registrant's auditors any material weaknesses in internal
controls; and
b. any fraud, whether or not material, that involves
management or other employees who have a significant role
in the registrant's internal controls; and
6. The registrant's other certifying officer and I have indicated in
this annual report whether or not there were significant changes
in internal controls or in other factors that could significantly
affect internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.
Date: March 19, 2003
/s/ Dale G. Wilkerson
- ---------------------
Dale G. Wilkerson
Vice President and Controller
(Principal Accounting
Officer)
84
EXHIBIT INDEX
3.1 Amended and Restated Agreement of Limited Partnership of
Alliance Resource Partners, L.P. (Incorporated by reference to
Exhibit 3.1 of the Registrant's Annual Report on Form 10-K for
the year ended December 31, 1999, File No. 000-26823).
3.2 Amended and Restated Agreement of Limited Partnership of
Alliance Resource Operating Partners, L.P. (Incorporated by
reference to Exhibit 3.2 of the Registrant's Annual Report on
Form 10-K for the year ended December 31, 1999, File No.
000-26823).
3.3 Certificate of Limited Partnership of Alliance Resource
Partners, L.P. (Incorporated by reference to Exhibit 3.6 of
the Registrant's Registration Statement on Form S-1 filed with
the Commission on May 20, 1999 (Reg. No. 333-78845)).
3.4 Certificate of Limited Partnership of Alliance Resource
Operating Partners, L.P. (Incorporated by reference to Exhibit
3.8 of the Registrant's Registration Statement on Form S-1/A
filed with the Commission on July 20, 1999 (Reg. No.
333-78845)).
3.5 Certificate of Formation of Alliance Resource Management GP,
LLC (Incorporated by reference to Exhibit 3.7 of the
Registrant's Registration Statement on Form S-1/A filed with
the Commission on July 23, 1999 (Reg. No. 333-78845)).
3.6 Amended and Restated Operating Agreement of Alliance Resource
Management GP, LLC (Incorporated by reference to Exhibit 3.4
of the Registrant's Registration Statement on Form S-3 filed
with the Commission on April 1, 2002 (Reg. No. 333-85282)).
3.7 Amendment No. 1 to Amended and Restated Operating Agreement of
Alliance Resource Management GP, LLC (Incorporated by
reference to Exhibit 3.5 of the Registrant's Registration
Statement on Form S-3 filed with the Commission on April 1,
2002 (Reg. No. 333-85282)).
3.8 Amendment No. 2 to Amended and Restated Operating Agreement of
Alliance Resource Management GP, LLC (Incorporated by
reference to Exhibit 3.6 of the Registrant's Registration
Statement on Form S-3 filed with the Commission on April 1,
2002 (Reg. No. 333-85282)).
4.1 Form of Common Unit Certificate (Included as Exhibit A to the
Amended and Restated Agreement of Limited Partnership of
Alliance Resource Partners, L.P.)
10.1 Credit Agreement, dated as of August 16, 1999, among Alliance
Resource GP, LLC, JP Morgan Chase Bank (formerly The Chase
Manhattan Bank) (as paying agent), Deutsche Bank AG, New York
Branch (as documentation agent), Citicorp USA, Inc. and JP
Morgan Chase Bank (as co-administrative agents) and the
lenders named therein. (Incorporated by reference to Exhibit
10.1 of the Registrant's Annual Report on Form 10-K for the
year ended December 31, 1999, File No. 000-26823).
10.2 Amendment No. 1 dated December 7, 2001, to the Credit
Agreement, dated as of August 16, 1999, among Alliance
Resource GP, LLC, JP Morgan Chase Bank (formerly The Chase
Manhattan Bank) (as paying agent), Deutsche Bank AG, New York
Branch (as documentation agent), Citicorp USA, Inc. and JP
Morgan Chase Bank (as co-administrative agents) and the
lenders named therein. (Incorporated by reference to Exhibit
10.2 of the Registrant's Annual Report on Form 10-K for the
year ended December 31, 2001, File No. 000-26823).
10.3 Note Purchase Agreement, dated as of August 16, 1999, among
Alliance Resource GP, LLC and the purchasers named therein.
(Incorporated by reference to Exhibit 10.20 of the
Registrant's Annual Report on Form 10-K for the year ended
December 31, 1999, File No. 000-26823).
10.4 Letter of Credit Facility Agreement dated as of June 29, 2001,
between Alliance Resource Partners, L.P. and Bank of Oklahoma,
National Association. (Incorporated by reference to Exhibit
10.20 of the Registrant's Quarterly Report on Form 10-Q for
the quarter ended September 30, 2001, File No. 000-26823).
10.5 Amendment One to Letter of Credit Facility Agreement between
Alliance Resource Partners, L.P. and Bank of Oklahoma,
National Association.
(Incorporated by reference to Exhibit 10.32 of the
Registrant's Quarterly Report on Form 10-Q for the quarter
ended September 30, 2002, File No. 000-26823).
10.6 Promissory Note Agreement dated as of July 31, 2001, between
Alliance Resource Partners, L.P. and Bank of Oklahoma, N. A.
(Incorporated by reference to Exhibit 10.21 of the
Registrant's Quarterly Report on Form 10-Q for the quarter
ended September 30, 2001, File No. 000-26823).
10.7 Guarantee Agreement, dated as of July 31, 2001, between
Alliance Resource GP, LLC and Bank of Oklahoma, N.A.
(Incorporated by reference to Exhibit 10.22 of the
Registrant's Quarterly Report on Form 10-Q for the quarter
ended September 30, 2001, File No. 000-26823).
10.8 Letter of Credit Facility Agreement dated as of August 30,
2001, between Alliance Resource Partners, L.P. and Fifth Third
Bank. (Incorporated by reference to Exhibit 10.23 of the
Registrant's Quarterly Report on Form 10-Q for the quarter
ended September 30, 2001, File No. 000-26823).
*10.9 Amendment No. 1 to Letter of Credit Facility Agreement between
Alliance Resource Partners, L.P. and Fifth Third Bank.
10.10 Guarantee Agreement, dated as of August 30, 2001, between
Alliance Resource GP, LLC and Fifth Third Bank. (Incorporated
by reference to Exhibit 10.24 of the Registrant's Quarterly
Report on Form 10-Q for the quarter ended September 30, 2001,
File No. 000-26823).
10.11 Letter of Credit Facility Agreement dated as of October 2,
2001, between Alliance Resource Partners, L.P. and Bank of the
Lakes, National Association. (Incorporated by reference to
Exhibit 10.25 of the Registrant's Quarterly Report on Form
10-Q for the quarter ended September 30, 2001, File No.
000-26823).
10.12 First Amendment to the Letter of Credit Facility Agreement
between Alliance Resource Partners, L.P. and Bank of the
Lakes, National Association. (Incorporated by reference to
Exhibit 10.33 of the Registrant's Quarterly Report on Form
10-Q for the quarter ended September 30, 2002, File No.
000-26823).
10.13 Promissory Note Agreement dated as of October 2, 2001, between
Alliance Resource Partners, L.P. and Bank of the Lakes, N.A.
(Incorporated by reference to Exhibit 10.26 of the
Registrant's Quarterly Report on Form 10-Q for the quarter
ended September 30, 2001, File No. 000-26823).
10.14 Guarantee Agreement, dated as of October 2, 2001, between
Alliance Resource GP, LLC and Bank of the Lakes, N.A.
(Incorporated by reference to Exhibit 10.27 of the
Registrant's Quarterly Report on Form 10-Q for the quarter
ended September 30, 2001, File No. 000-26823).
10.15 Guaranty Fee Agreement dated as of July 31, 2001, between
Alliance Resource Partners, L.P. and Alliance Resource GP,
LLC. (Incorporated by reference to Exhibit 10.28 of the
Registrant's Quarterly Report on Form 10-Q for the quarter
ended September 30, 2001, File No. 000-26823).
10.16 Contribution and Assumption Agreement, dated August 16, 1999,
among Alliance Resource Holdings, Inc., Alliance Resource
Management GP, LLC, Alliance Resource GP, LLC, Alliance
Resource Partners, L.P., Alliance Resource Operating Partners,
L.P. and the other parties named therein. (Incorporated by
reference to Exhibit 10.3 of the Registrant's Annual Report on
Form 10-K for the year ended December 31, 1999, File No.
000-26823).
10.17 Omnibus Agreement, dated August 16, 1999, among Alliance
Resource Holdings, Inc., Alliance Resource Management GP, LLC,
Alliance Resource GP, LLC and Alliance Resource Partners, L.P.
(Incorporated by reference to Exhibit 10.4 of the Registrant's
Annual Report on Form 10-K for the year ended December 31,
1999, File No. 000-26823).
10.18 Alliance Resource Management GP, LLC 2000 Long-Term Incentive
Plan (as amended). (Incorporated by reference to Exhibit 10.11
of the Registrant's Annual Report on Form 10-K for the year
ended December 31, 1999, File No. 000-26823).
10.19 Alliance Resource Management GP, LLC Short-Term Incentive
Plan. (Incorporated by reference to Exhibit 10.12 of the
Registrant's Annual Report on Form 10-K for the year ended
December 31, 1999, File No. 000-26823).
10.20 Alliance Resource Management GP, LLC Supplemental Executive
Retirement Plan. (Incorporated by reference to Exhibit 99.2 of
the Registrant's Registration Statement on Form S-8 filed with
the Commission on April 1, 2002 (Reg. No. 333-85258)).
10.21 Alliance Resource Management GP, LLC Deferred Compensation
Plan for Directors. (Incorporated by reference to Exhibit 99.3
of the Registrant's Registration Statement on Form S-8 filed
with the Commission on April 1, 2002 (Reg. No. 333-85258)).
10.22 Restated and Amended Coal Supply Agreement, dated February 1,
1986, among Seminole Electric Cooperative, Inc., Webster
County Coal Corporation and White County Coal Corporation.
(Incorporated by reference to Exhibit 10.9 of the Registrant's
Registration Statement on Form S-1/A filed with the Commission
on July 20, 1999 (Reg. No. 333-78845)).
10.23 Amendment No. 1 to the Restated and Amended Coal Supply
Agreement effective April 1, 1996, between MAPCO Coal Inc.,
Webster County Coal Corporation, White County Coal
Corporation, and Seminole Electric Cooperative, Inc.
(Incorporated by reference to Exhibit 10.14 of the
Registrant's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2000, File No. 000-26823).
10.24 Amendment No. 2 to the Restated and Amended Coal Supply
Agreement effective February 28, 2002 between Webster County
Coal, LLC, White County Coal, LLC, and Seminole Electric
Cooperative, Inc. (Incorporated by reference to Exhibit 10.32
of the Registrant's Quarterly Report on Form 10-Q for the
quarter ended June 30, 2002, File No. 000-26823).
10.25 Interim Coal Supply Agreement effective May 1, 2000, between
Alliance Coal, LLC and Seminole Electric Cooperative, Inc.
(Incorporated by reference to Exhibit 10.15 of the
Registrant's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2000, File No. 000-26823).
10.26 Contract for Purchase and Sale of Coal, dated January 31,
1995, between Tennessee Valley Authority and Webster County
Coal Corporation. (Incorporated by reference to Exhibit 10.10
of the Registrant's Registration Statement on Form S-1/A filed
with the Commission on July 20, 1999 (Reg. No. 333-78845)).
10.27 Assignment/Transfer Agreement between Andalex Resources, Inc.,
Hopkins County Coal LLC, Webster County Coal Corporation and
Tennessee Valley Authority, dated January 23, 1998, with
Exhibit A - Contract for Purchase and Sale of Coal between
Tennessee Valley Authority and Andalex Resources, Inc., dated
January 31, 1995. (Incorporated by reference to Exhibit 10.11
of the Registrant's Registration Statement on Form S-1/A filed
with the Commission on July 20, 1999 (Reg. No. 333-78845)).
10.28 Contract for Purchase and Sale of Coal, dated July 7, 1998,
between Tennessee Valley Authority and Webster County Coal
Corporation. (Incorporated by reference to Exhibit 10.12 of
the Registrant's Registration Statement on Form S-1/A filed
with the Commission on July 20, 1999 (Reg. No. 333-78845)).
10.29 Contract for Purchase and Sale of Coal, dated July 7, 1998,
between Tennessee Valley Authority and White County Coal
Corporation. (Incorporated by reference to Exhibit 10.13 of
the Registrant's Registration Statement on Form S-1/A filed
with the Commission on July 20, 1999 (Reg. No. 333-78845)).
10.30 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).
10.31 Coal Feedstock Supply Agreement dated October 26, 2001,
between Synfuel Solutions Operating LLC and Hopkins County
Coal, LLC (Incorporated by reference to Exhibit 10.27 of the
Registrant's Annual Report on Form 10-K for the year ended
December 31, 2001, File No. 000-26823).
10.32 Amendment No. 1 to Coal Feedstock Supply Agreement dated
February 28, 2002, between Synfuel Solutions Operating LLC and
Hopkins County Coal, LLC (Incorporated by reference to Exhibit
10.28 of the Registrant's Annual Report on Form 10-K for the
year ended December 31, 2001, File No. 000-26823).
10.33 Amended and Restated Put and Call Option Agreement dated
February 12, 2001 between ARH Warrior Holdings, Inc. and
Alliance Resource Partners, L.P. (Incorporated by reference to
Exhibit 10.17 of the Registrant's Annual Report on Form 10-K
for the year ended December 31, 2000, File No. 000-26823).
*10.34 Letter Agreement dated January 31, 2003 between ARH Warrior
Holdings, Inc. and Alliance Resource Partners, L.P.
10.35 Consulting Agreement for Mr. Sachse dated January 1, 2001.
(Incorporated by reference to Exhibit 10.18 of the
Registrant's Annual Report on Form 10-K for the year ended
December 31, 2000, File No. 000-26823).
10.36 Form of Employee Agreements for Messrs. Craft, Pearson, Wesley
and Rathburn. (Incorporated by reference to Exhibit 10.6 of
the Registrant's Registration Statement on Form S-1/A filed
with the Commission on August 9, 1999 (Reg. No. 333-78845)).
10.37 Security and Pledge Agreement dated as of May 8, 2002 by and
among Alliance Resource Holdings II, Inc., AMH II, LLC,
Alliance Resource Holdings, Inc., Alliance Resource GP, LLC,
the Management Investors as identified therein, The Beacon
Group Energy Investment Fund, L.P., MPC Partners, LP and three
individuals as "Sellers" identified therein, and JPMorgan
Chase Bank as collateral agent. (Incorporated by reference to
Exhibit 99.2 of the Registrant's Form 8-K filed with the
Commission on May 9, 2002, File No. 000-26823).
10.38 Form of Promissory Note made by Alliance Resource Holdings,
Inc. dated as of May 8, 2002. (Incorporated by reference to
Exhibit 99.3 of the Registrant's Form 8-K filed with the
Commission on May 9, 2002, File No. 000-26823).
18.1 Preferability Letter on Accounting Change. (Incorporated by
reference to Exhibit 18.1 of the Registrant's Amended
Quarterly Report on Form 10-Q/A for the quarter ended March
31, 2001, File No. 000-26823).
*21.1 List of Subsidiaries
*23.1 Consent of Deloitte & Touche LLP regarding Form S-3 and
Form S-8, Registration No. 333-85282 and No. 333-85258,
respectively.
* Filed herewith