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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, 2003
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM _____________TO_____________
COMMISSION FILE NO.: 0-26823
________________
ALLIANCE RESOURCE PARTNERS, L.P.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 73-1564280
(STATE OR OTHER JURISDICTION OF (IRS EMPLOYER IDENTIFICATION NO.)
INCORPORATION OR ORGANIZATION)
1717 SOUTH BOULDER AVENUE, SUITE 600, TULSA, OKLAHOMA 74119
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES AND ZIP CODE)
(918) 295-7600
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: common units
representing limited partner interests
_______________
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
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
$272,396,559 as of June 30, 2003, the last business day of the registrant's most
recently completed second fiscal quarter, based on $27.25 per unit, the closing
price of the common units as reported on the Nasdaq National Market on such
date.
As of March 12, 2004, 14,692,527 common units and 3,211,266 subordinated
units were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE: None
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TABLE OF CONTENTS
PAGE
PART I
ITEM 1. BUSINESS..................................................................................... 3
ITEM 2. PROPERTIES ................................................................................. 20
ITEM 3. LEGAL PROCEEDINGS............................................................................ 23
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITIES HOLDERS ....................................... 23
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON UNITS AND RELATED UNITHOLDER MATTERS.......................... 24
ITEM 6. SELECTED FINANCIAL DATA...................................................................... 25
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS........ 27
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK................................... 44
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.................................................. 46
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANT ON ACCOUNTING AND FINANCIAL DISCLOSURE.......... 74
ITEM 9A. CONTROLS AND PROCEDURES...................................................................... 74
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND
CONTROL PERSONS OF THE MANAGING GENERAL PARTNER.............................................. 74
ITEM 11. EXECUTIVE COMPENSATION....................................................................... 79
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT............................... 87
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS............................................... 88
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES ...................................................... 89
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K............................. 90
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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;
- fluctuation 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 10.0% participation (excluding any applicable
deductible) in our commercial insurance property program.
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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.
2
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 what we
believe to be the eighth largest coal producer in the eastern United States. At
December 31, 2003, we had approximately 418.4 million tons of reserves in
Illinois, Indiana, Kentucky, Maryland and West Virginia. In 2003, we produced
19.2 million tons of coal and sold 19.5 million tons of coal. The coal we
produced in 2003 was 31.2% low-sulfur coal, 17.2% medium-sulfur coal and 51.6%
high-sulfur coal. In 2003, 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, 2003, we operated seven underground mining complexes in
Illinois, Indiana, Kentucky and Maryland. We have one surface operation that is
currently idle. 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 also host and operate a coal synfuel
facility, supply the facility with coal feedstock, assist with the marketing of
coal synfuel, and provide other services to the owner of the synfuel facility.
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.
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% limited partner interest 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.
Our internet address is www.arlp.com, and we make available on our internet
website our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, our
Current Reports on Form 8-K, and Form 4's for our Section 16 filers (and
amendments and exhibits, such as press releases, to such filings) as soon as
reasonably practicable after we electronically file with or furnish such
material to the Securities and Exchange Commission. Our "Code of Ethics" for our
chief executive officer and our senior financial officers is also posted on our
website.
3
RECENT DEVELOPMENTS
Dotiki Mine Fire
On February 11, 2004 the Dotiki mine was temporarily idled following the
occurrence of a mine fire. The fire originated from a diesel supply tractor
located in an area near two of the mine's active mining areas. All employees
were evacuated without injury. Working closely and cooperatively with federal
and state mine safety agencies, which continuously had representatives on site,
Dotiki personnel began implementing a plan to isolate and extinguish the fire.
Fire fighting techniques initially focused on rendering the mine atmosphere
inert by cutting off oxygen to the fire through a combination of temporarily
sealing two main underground passageways and one of four mine portals, creating
an initial set of temporary seals from the surface through boreholes and
injecting nitrogen and carbon dioxide gases into the mine.
Once the mine atmosphere was rendered inert, recovery personnel re-entered
the mine and created a second set of temporary seals to further contain the area
of the mine impacted by the fire. Mine personnel then constructed permanent
seals. With the injection of inert gases complete, the mine fire was effectively
extinguished, and the affected area of the mine was totally isolated behind the
permanent seals on or about March 4, 2004. Once the permanent seals were
installed and the mine safely ventilated, Dotiki crews performed a thorough
examination of the entire mine. Information obtained during these examinations
indicated minimal impact to the mine outside of the permanently sealed fire
area. All six mining units returned to production on March 8, 2004. We are
unable to predict at this time when the mine will return to normal production
levels.
The temporary idling of Dotiki will reduce earnings for the first quarter
of 2004. At this time, we are unable to quantify the financial impact of the
fire. We have commercial property insurance (including business interruption
coverage) that we currently believe should cover a substantial portion of the
financial loss. Assuming that is correct, Dotiki's losses recognized in the
first quarter of 2004 should be substantially offset by an insurance settlement
that would be recognized later in the year. There can be no assurance of the
amount or timing of recovery, however, until the claim is resolved with the
insurance underwriter. Our insurance program provides for a deductible of $3.5
million and a ten percent coinsurance. In addition to the losses associated with
business interruption, we have currently identified approximately $6.0 million
of out-of-pocket expenses that generally fall into the category of extra
expenses, expedited expenses and other areas of coverage under the commercial
property insurance policy. We expect that additional out-of-pocket costs will be
identified in the future.
TRANSACTIONS IN 2003
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.
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
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revolving credit agreement between an affiliate of ARH Warrior Holdings and
Warrior. Please see "Item 8. Financial Statements and Supplementary Data - Note
3, Warrior Coal Acquisition."
Conversion of Subordinated Units
Our partnership agreement provides for the early conversion of one-half of
the subordinated units if certain financial tests were satisfied before
September 30, 2003. We satisfied the required financial tests for converting
one-half of the subordinated units into common units as provided for under
applicable provisions in our partnership agreement. Accordingly, in October 2003
the board of directors (and its conflicts committee) of our managing general
partner approved management's determination that such conversion financial tests
were satisfied. As a result, one-half of the outstanding subordinated units
(i.e., 3,211,265 subordinated units) held by our special general partner
converted into common units on November 15, 2003. The remaining 3,211,266
subordinated units are expected to convert on a one-for-one basis into common
units in the fourth quarter of 2004, assuming we continue to meet the financial
test requirements of our partnership agreement.
Management Buy-Out of Beacon Group Funds' Interests
Prior to May 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. In May 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 4,444,045 common units and 3,211,266
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. In May 2003 management refinanced the
remaining balance due on the promissory notes of $23.4 million with a commercial
banking facility, secured by certain assets owned by subsidiaries of Alliance
Resource Holdings. Some of the secured assets are leased to us by subsidiaries
of Alliance Resource Holdings. A security and pledge agreement with The Beacon
Group associated with the original promissory notes was cancelled in conjunction
with the refinancing. The intermediate partnership and our subsidiary, Alliance
Coal, LLC (Alliance Coal), have issued a parent guarantee on the reserve leases
between SGP Land, LLC (SGP Land), a subsidiary of our special general partner,
and us. Please see "Item 8. Financial Statements and Supplementary Data. - Note
16, Related Party Transactions."
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 coal production by region
for the last five years.
5
OPERATING REGIONS AND COMPLEXES 2003 2002 2001 2000 1999
- ------------------------------- ---- ---- ---- ---- ----
(TONS IN MILLIONS)
Illinois Basin Operations:
Dotiki, Gibson, Hopkins, Pattiki, Warrior Complexes 12.3 12.1 11.9 8.4 8.5
East Kentucky Operations:
MC Mining, Pontiki Complexes 3.6 3.0 2.8 2.7 2.8
Maryland Operations:
Mettiki Complex 3.3 2.9 2.7 2.6 2.8
---- ---- ---- ---- ----
Total 19.2 18.0 17.4 13.7 14.1
==== ==== ==== ==== ====
ILLINOIS BASIN OPERATIONS
Our Illinois Basin mining operations are located in western Kentucky,
southern Illinois and southern Indiana. We have approximately 1,075 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. In 2004, Dotiki plans to increase the number
of mining sections that operate with two continuous miners. The preparation
plant currently has a throughput capacity of 1,000 tons of raw coal an hour
which capacity will be expanded by approximately 30% in 2004, principally to
accommodate a change in customer requirements for washed coal rather than raw
coal. On February 11, 2004, the Dotiki mine was temporarily idled following the
occurrence of a mine fire. We have successfully extinguished the fire and have
totally isolated the affected area of the mine behind permanent seals.
Production resumed on March 8, 2004. However, we are unable to predict at this
time when Dotiki will return to normal production. For information on the fire
at our Dotiki mine, please see "Recent Developments - Dotiki Mine Fire" above.
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 Louisville Gas & Electric (LG&E), Seminole Electric
Cooperative, Inc. (Seminole) and Tennessee Valley Authority (TVA), all of which
purchase our coal pursuant to long-term contracts for use in their scrubbed
generating units. In April 2003, Dotiki completed construction of a new mine
shaft and ancillary facilities which provides new access to the coal reserves
for miners and supplies.
Warrior Complex. Warrior Coal, LLC operates Warrior, 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 in 1985. Warrior utilizes continuous mining units employing
room-and-pillar mining techniques producing high-sulfur coal. In September 2002,
Warrior completed construction of a new shaft that provides new access to the
coal reserves for miners and supplies. In April 2003, a continuous mining unit
was added and a new slope was completed. The new slope provides improved
ventilation and more efficient transportation of the coal from underground to
the preparation plant. Warrior's preparation plant has a throughput capacity of
600 tons of raw coal an hour.
Production from Warrior in 2002 and into 2003 was shipped via truck on U.S.
and state highways primarily to our Hopkins County Coal, LLC (Hopkins) complex
for resale to our customer Synfuel Solutions Operating LLC (SSO). At our Hopkins
complex, this coal was used as feedstock in the production of coal synfuel, as
discussed under "Coal Synfuel" below. SSO's coal synfuel production facility was
moved from Hopkins to Warrior in April 2003, and Warrior now sells substantially
all of its production to SSO. Warrior's
6
production can be shipped via the CSX and PAL railroads and by truck on U.S. and
state highways. Additionally, Warrior now purchases supplemental production from
Dotiki for resale to SSO. SSO continues 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.
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 the construction of two new shafts
and ancillary facilities. 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 Ameren Energy
Fuels & Services Company, Northern Indiana Public Service Company (NIPSCO), and
Seminole for use in their generating units. NIPSCO and Seminole have scrubbed
generating units.
Hopkins Complex. Hopkins County Coal, LLC owns Hopkins, a mining complex
that is currently idle and located near the city of Madisonville in Hopkins
County, Kentucky. We acquired the complex in January 1998. The complex has two
inactive surface mines which utilize dragline mining. The preparation plant has
a throughput capacity of 1,000 tons of raw coal an hour.
The Hopkins complex was idled in June 2003 because we were unable to secure
sufficient sales commitments in the Illinois Basin region. The Hopkins complex
will remain idle until sufficient sales commitments for the Illinois Basin
region are secured. In April 2003, Hopkins depleted the coal reserves of its
active underground mine.
During 2002 and into 2003, the majority of Hopkins high-sulfur production
was sold to SSO, whose coal synfuel production facility was located at Hopkins.
SSO's coal synfuel production facility was moved from Hopkins to Warrior in
April 2003. Historically, Hopkins' production was shipped via the CSX and PAL
railroads and by truck on U.S. and state highways.
Gibson Complex. Gibson County Coal, LLC operates Gibson, 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. In February 2003,
Gibson added a continuous mining unit. 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, primarily shipped via truck
approximately 10 miles on U.S. and state highways to Gibson's principal
customer, PSI Energy Inc. (PSI), a subsidiary of Cinergy Corporation. Gibson's
production can also be trucked to our Mt. Vernon transloading facility for sale
to utilities capable of receiving barge deliveries.
Coal Synfuel. We entered into long-term agreements with SSO to host and
operate its coal synfuel facility currently located at Warrior, 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
7
discussed above, we sell most of the coal produced at Warrior to SSO, while
Alliance Coal Sales, a division of Alliance Coal, assists SSO with the sale of
its coal synfuel to our customers pursuant to a sales agency agreement. The term
of each of these agreements is subject to early cancellation provisions
customary for transactions of these types, including the unavailability of
synfuel tax credits, the termination of associated coal synfuel sales contracts,
and the occurrence of certain force majeure events. Therefore, the continuation
of the 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. 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.
For 2003, the incremental annual net income benefit from the combination of
the various coal synfuel-related agreements was approximately $15.5 million,
assuming that coal pricing would not have increased without the availability of
synfuel. The continuation of the incremental net income benefit associated with
SSO's coal synfuel facility cannot be assured. We earn income by supplying SSO's
synfuel facility with coal feedstock, assisting SSO with the marketing of coal
synfuel, and providing rental and other services. Pursuant to our agreement with
SSO, we are not obligated to make retroactive adjustments or reimbursements if
SSO's tax credits are disallowed.
In June 2003 the Internal Revenue Service (IRS) suspended the issuance of
private letter rulings on the significant chemical change requirement to qualify
for synfuel tax credits and announced that it was reviewing the test procedures
and results used by taxpayers to establish that a significant chemical change
had occurred. In October 2003, the IRS completed its review and concluded that
the test procedures and results were scientifically valid if applied in a
consistent and unbiased manner. The IRS has resumed issuing private letter
rulings under its existing guidelines. SSO has advised us that its private
letter ruling could be reviewed by the IRS as part of a tax audit, similar to
the IRS reviews of other synfuel procedures. SSO has also advised us that the
Permanent Subcommittee on Investigations of the Senate Committee on Governmental
Affairs (Subcommittee) is reviewing the synfuel industry, that the Subcommittee
has indicated that they hope to interview almost all taxpayers that are involved
in the synfuel business and that SSO has been requested to meet informally with
the Subcommittee to help enhance the Subcommittee's knowledge of the synfuel
industry.
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 480 employees and operate two mining complexes in East Kentucky.
Pontiki Complex. Pontiki Coal, LLC owns Pontiki, 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.
Our primary customer for the low-sulfur coal produced at Pontiki is AEI
Coal Sales Company, Inc. Production from the mine is shipped primarily to
electric utilities located in the southeastern United States via the Norfolk
Southern railroad or by truck via U.S. and state highways to various docks on
the Big Sandy River in Kentucky.
8
MC Mining Complex. MC Mining, LLC owns MC Mining, an underground mining
complex located near the city of Pikeville in Pike County, Kentucky. We acquired
the mine in 1989. MC Mining owns the mining complex and leases the reserves, and
Excel, an affiliate of MC Mining, is responsible for conducting all mining
operations. The complex utilizes continuous mining units employing
room-and-pillar mining techniques. In August 2003, MC Mining completed
construction of a new shaft and added a continuous mining unit. The new mine
shaft provides new access to the coal reserves for miners and supplies. 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 220 employees and operate one mining complex in
Maryland.
Mettiki Complex. Mettiki Coal, LLC operates Mettiki, 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 scrubbed 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.
Mettiki Coal (WV). Mettiki Coal (WV), LLC has approximately 23.3 million
tons of undeveloped reserves in Grant and Tucker Counties, West Virginia close
to Mettiki in Garrett County, Maryland. We currently do not conduct mining
operations at Mettiki Coal (WV).
OTHER OPERATIONS
MT. VERNON TRANSFER TERMINAL, LLC
The Mt. Vernon transfer terminal is a rail-to-barge loading terminal on the
Ohio River at Mt. Vernon, Indiana. The terminal has a capacity of 8 million tons
per year with existing ground storage. During 2003, the terminal loaded
approximately 1.3 million tons for Pattiki and Dotiki customers and for
third-party shippers.
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 191,000 tons of
outside coal from non-affiliates in 2003. We have a policy of matching our
outside coal purchases and sales to minimize market risks associated with buying
and reselling coal.
9
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 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
by contributing to both our customers' and our stability and profitability by
providing greater predictability of sales volumes and sales prices. In 2003,
approximately 84% 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 2003 to 2023. Our total nominal commitment
under significant long-term contracts was approximately 97.6 million tons at
December 31, 2003, and is expected to be delivered as follows: 17.5 million tons
in 2004, 16.4 million tons in 2005, 15.8 million tons in 2006, 8.3 million tons
in 2007, 6.0 million tons in 2008, and 33.6 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 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 2003 were Seminole, SSO, and VEPCO. Sales to
these customers in the aggregate accounted for approximately 46% of our 2003
total revenues, and sales to each of these customers accounted for 10% or more
of our 2003 total revenues.
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In February 2002, a major customer of Pontiki, 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, 2003 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, some action by Horizon is possible.
In May 2003, a significant customer of MC Mining voluntarily filed for
Chapter 11 bankruptcy protection. We did not incur any losses associated with
this bankruptcy filing. We believe that our payment terms with the customer
protect us from any significant bad debt exposure and at December 31, 2003, we
did not have any accounts receivable from this customer.
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 2003 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 5% to 45% of the delivered cost of a customer's coal. As a consequence, the
availability and cost of transportation constitute important factors in the
marketability of coal. We believe our mines are located in favorable geographic
locations that minimize transportation costs for our customers.
Our 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 2003, the largest
volume transporter of our coal shipments, including coal synfuel shipped by SSO,
was the CSX railroad, which moved approximately 57% 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 Gibson and
Mettiki, 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:
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- 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 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 or prevent
commencement or continuation of mining operations in certain locations. 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.
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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.
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 (WVDEP) requesting approval for the
mining of approximately 3.1 million tons of coal deposits controlled by Mettiki
Coal (WV), one of our subsidiaries, but contiguous with our Mettiki coal
reserves in Maryland. In January 2002, the WVDEP denied the permit. We appealed
the permit denial to the West Virginia Surface Mine Board (Surface Mine Board)
and, in July 2002, the Surface Mine Board approved a permit that allowed 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 approximately 600,000 additional tons of this coal.
In February 2004, we completed mining in this coal reserve area.
On October 15, 2003, the WVDEP issued a letter denying Mettiki Coal (WV)'s
application for an underground mining permit for its proposed E-Mine. The E-Mine
is a proposed longwall underground mine to be located primarily in Tucker
County, West Virginia. The stated basis of WVDEP's denial was its belief that
Mettiki Coal (WV)'s proposed E-Mine would result in the movement of acid mine
drainage (AMD) outside the permit area from the post-mining mine pool, which
would require long-term chemical treatment without a defined "end-point." WVDEP
takes the position that the applicable surface mining laws require reclamation
of land and water resources, and that treatment for a period without a defined
end-point is not an acceptable reclamation alternative. However, WVDEP
previously issued a permit to Island Creek Coal Company to mine the same general
reserve area without expressing such concerns. On November 14, 2003, Mettiki
Coal (WV) appealed that decision to the Surface Mine Board. The appeal of the
denial of this permit application is scheduled currently to be heard by the
Surface Mine Board on April 6, 2004.
In order to expedite the WVDEP's consideration of additional information
that we believe addresses WVDEP's basis for denial of the original permit
application, Mettiki Coal (WV) prepared and submitted a new permit application
on January 15, 2004. The new permit application addresses, among other issues,
the stated concern for long-term material damage to the hydrologic balance
outside the permit area by adding an alkaline recharge component to the
hydrologic reclamation plan.
On January 22, 2004, the WVDEP notified Mettiki Coal (WV) that the new
permit application was determined to be administratively complete. On February
6, 2004, the WVDEP notified Mettiki Coal (WV) of certain technical corrections
that must be responded to before the new permit application review can be
completed. Mettiki Coal (WV) submitted technical corrections to the WVDEP on
February 17, 2004.
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WVDEP's determination on the new permit application is expected within 30 days
of an informal public conference to be held by the WVDEP on March 23, 2004.
In the event that WVDEP denies the new permit application, Mettiki Coal
(WV) anticipates that it will vigorously pursue the appeal of the denial of the
new mining permit application to the Surface Mine Board. The Surface Mine Board,
a seven-member board, typically hears cases within several months after appeals
are filed and rarely waits more than several weeks after hearing a case to
render a final decision. Mettiki Coal (WV) has approximately $1.5 million of
advance minimum royalties associated with the E-Mine reserves, which management
believes are fully recoverable.
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 (MSHA) monitors compliance
with these federal laws and regulations. In addition, as part of CMHSA and the
Mine Safety and Health Act of 1977, the Black Lung Benefits Act requires
payments of benefits by all businesses that conduct current mining operations to
a coal miner with black lung disease and to some survivors of a miner who dies
from this disease. Most of the states where we operate also have state programs
for mine safety and health regulation and enforcement. In combination, federal
and state safety and health regulation in the coal mining industry is perhaps
the most comprehensive and rigorous system for protection of employee safety and
health affecting any segment of any industry. Even the most minute aspects of
mine operations, particularly underground mine operations, are subject to
extensive regulation. This regulation has a significant effect on our operating
costs. For example, new regulations governing exposures to diesel particulate
matter in underground mines have recently increased our compliance costs, and
new regulations that would effectively further limit coal dust and silica
exposures are under consideration by MSHA. 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;
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- limit the amount of evidence all parties may submit for consideration;
- create a rebuttable presumption that when a miner who is eligible for
black lung benefits receives medical treatment for any pulmonary
condition, the disorder 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. 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 (SMCRA)". In addition, Congress and state legislatures regularly
consider various items of black lung legislation, which, if enacted, could
adversely affect our business, financial condition and results of operations.
WORKERS' COMPENSATION
We are required to compensate employees for work-related injuries. Several
states in which we operate consider changes in workers' compensation laws from
time to time. 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 (SMCRA)."
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., now a wholly-owned subsidiary of The Williams
Companies, 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 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
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water supplies damaged by mining operations and repairing or compensating for
damage to certain structures 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 AMD 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 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.
In 2002, a U.S. District Court reached a decision interpreting SMCRA to
prohibit subsidence from underground mining on certain federal lands, near
occupied dwelling, public or community building, public road, schools, churches,
and cemeteries, or adversely affecting public parks or certain historic
properties. The U.S. Court of Appeals, District of Columbia Circuit, reversed
the district court decision as erroneous and in February 2004, the U.S. Supreme
Court refused to hear an appeal of the Court of Appeals decision.
Federal and state laws require bonds to secure our obligations to reclaim
lands used for mining, to pay federal and state workers' compensation, to pay
certain black lung claims, and to satisfy other miscellaneous obligations. These
bonds are typically renewable on a yearly basis. It has become increasingly
difficult for us and for our competitors generally 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 (SO2) 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."
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Specific emissions sources receive these "credits" that utilities and
industrial concerns can trade or sell to allow other units to emit higher levels
of SO2. In addition, the CAA required a study of utility power plant emissions
of some toxic substances and their eventual regulation, if warranted. As a
result of that study, EPA has proposed, but not yet finalized, alternative
regulatory approaches to controlling mercury emissions from power plants. We
cannot accurately predict the effect of such CAA controls 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 non-attainment 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 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
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. Non-attainment designations for these NAAQS are expected
to be made in 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.
In conjunction with the mercury proposal noted above, EPA has also proposed an
Interstate Air Quality Rule which would require coal-burning power plants in 29
eastern states and the District of Columbia to achieve greater reductions in NOx
and SO2 emissions by means of a "cap and trade" program. Congress may consider
other controls on other air pollutants emitted by electric utilities. 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 non-attainment regulations. The issue raised in this
litigation is 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 or are engaged in
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
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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, 2003, countries representing
44.2% of 1990 carbon dioxide emissions had ratified the Kyoto Protocol.
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 on our business, financial condition and results of operations.
CLEAN WATER ACT (CWA)
The Federal CWA affects coal mining operations by imposing restrictions on
effluent discharge into waters. Regular monitoring, as well as compliance with
reporting requirements and performance standards, are preconditions for the
issuance and renewal of permits governing the discharge of pollutants into
water. 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. Although
permitting requirements have been tightened in recent years, 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.
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We are currently participating in stakeholders meetings and in negotiations
with states and EPA to establish reasonable TMDLs that will accommodate
expansion of our operations. 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 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." While we have several drinking water supply sources
for our employees and contractors that are subject to SDWA regulation, the SDWA
is unlikely to have a material impact on our operations.
COMPREHENSIVE ENVIRONMENTAL RESPONSE, COMPENSATION AND LIABILITY ACT
(CERCLA)
The Federal CERCLA, 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 and corresponding state laws regulating hazardous waste
affect 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 by statute
exempted from RCRA permitting. 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 waste regulatory controls on the
disposal of some coal combustion by-products, including the practice of using
coal combustion by-products (CCB) as mine fill. However, under pressure from
environmental groups, EPA has continued evaluating the possibility of placing
additional solid waste burdens on the disposal of these types of materials, and
Congress has commissioned a
19
National Academy of Sciences study of CCB mine filling to be concluded in 2005.
EPA's current semi-annual regulatory agent states that a rule on CCB mine
filling is planned for proposal in July 2005.
While we cannot predict the ultimate outcome of the National Academy's
study or 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 AMD 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.
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 became 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 1,875 employees, including approximately 100 corporate
employees and approximately 1,775 employees involved in active mining
operations. Our work-force is entirely union-free. Relations with our employees
are generally good.
ITEM 2. PROPERTIES
COAL RESERVES
We must obtain permits from applicable state regulatory authorities before
beginning to mine particular reserves. Applications for permits require
extensive engineering and data analysis and presentation, and must address a
variety of environmental, health, and safety matters associated with a proposed
mining operation. These matters include the manner and sequencing of coal
extraction, the storage, use and disposal of waste and other substances and
other impacts on the environment, the construction of 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, except for the E-mine permit discussed above in
"Item 1. Business; Regulations and Laws; Mining Permits and Approvals", we are
not currently
20
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 and are in accordance with guidance from SEC Industry Guide No. 7. 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, 2003, we had approximately 418.4 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, 2003,
about each of our mining complexes:
Heat
Content Proven and Probable Reserves
(Btus --------------------------- Reserve Assignment
Mine per Pounds S02 per MMbtu ----------------------
Operations Type pound) <1.2 1.2-2.5 >2.5 Total Assigned Unassigned
---------- ---- ------ -------- -------- ---- ----- -------- ----------
(tons in millions)
Illinois Basin Operations
Dotiki Underground 12,500 - - 100.4 100.4 100.4 -
Warrior Underground 12,500 - - 23.8 23.8 23.8 -
Pattiki Underground 11,700 - - 47.3 47.3 47.3 -
Hopkins Underground 11,300 - - 20.0 20.0 - 20.0
/ Surface - - 9.7 9.7 9.7 -
Gibson (North) Underground 11,600 - 26.5 7.2 33.7 33.7 -
Gibson (South) Underground 11,600 - 46.5 36.2 82.7 - 82.7
---- ----- ----- ----- ----- -----
Region Total 0.0 73.0 244.6 317.6 214.9 102.7
---- ----- ----- ----- ----- -----
East Kentucky Operations
Pontiki Underground 12,800 12.1 12.2 - 24.3 24.3 -
MC Mining Underground 12,800 24.2 - - 24.2 24.2 -
---- ----- ----- ----- ----- -----
Region Total 36.3 12.2 0.0 48.5 48.5 0.0
---- ----- ----- ----- ----- -----
Maryland Operations
Mettiki Underground 12,200 - 15.8 13.2 29.0 13.2 15.8
Mettiki Coal (WV) Underground 12,200 - - 23.3 23.3 23.3 -
---- ----- ----- ----- ----- -----
Region Total 0.0 15.8 36.5 52.3 36.5 15.8
---- ---- ----- ----- ----- -----
Total 36.3 101.0 281.1 418.4 299.9 118.5
==== ===== ===== ===== ===== =====
% of Total 8.7% 24.1% 67.2% 100.0% 71.7% 28.3%
==== ===== ===== ===== ===== =====
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.
21
Reserve estimates will change from time to time to reflect evolving market
conditions, mining activities, additional analyses, 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 36.3
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 23.3 million tons of reserves controlled
by Mettiki Coal (WV) has been submitted to the WVDEP. Please see "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 - 13.3 million
tons, Pattiki - 3.2 million tons, Gibson (South) - 7.5 million tons, and Warrior
- - 2.2 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:
22
TONS PRODUCED
----------------------
OPERATIONS 2003 2002 2001 TRANSPORTATION EQUIPMENT
---------- ---- ---- ---- -------------- ---------
(tons in millions)
ILLINOIS BASIN OPERATIONS
Dotiki 4.9 4.5 4.6 CSX, PAL; truck; CM
barge
Warrior 2.4 1.6 1.7 CSX, PAL; truck CM
Hopkins 0.8 2.2 2.0 CSX, PAL; truck DL; CM
Pattiki 1.8 1.9 1.9 CSX; truck; barge CM
Gibson (North) 2.4 1.9 1.7 Truck CM
---- ---- ----
Region Total 12.3 12.1 11.9
==== ==== ====
EAST KENTUCKY OPERATIONS
Pontiki 2.0 1.7 1.7 NS; truck CM
MC Mining 1.6 1.3 1.1 NS; truck CM
---- ---- ----
Region Total 3.6 3.0 2.8
==== ==== ====
MARYLAND OPERATIONS
Mettiki 3.3 2.9 2.7 Truck; CSX LW; CM
---- ---- ----
Region Total 3.3 2.9 2.7
==== ==== ====
TOTAL 19.2 18.0 17.4
==== ==== ====
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.
We are not currently involved in any litigation involving any of our long-term
coal supply contracts. In August 2003, we settled a contract dispute with PSI as
described under "Other" in "Item 8. Financial Statements and Supplementary Data.
- - Note 17. Commitments and Contingencies." However, we cannot assure you that
disputes will not occur or that we will be able to resolve those disputes in a
satisfactory manner. We are not engaged in any litigation 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" and
"Other" under "Item 8. Financial Statements and Supplementary Data. - Note 17.
Commitments and Contingencies" is incorporated herein by this reference.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITIES HOLDERS
None.
23
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 11, 2004, the closing market price for the common
units was $37.55 per unit. There were approximately 14,275 record holders and
beneficial owners (held in street name) of common units at December 31, 2003.
The following table sets forth the range of high and low sales prices per
common unit and the amount of cash distributions declared and paid with respect
to the units, for the two most recent fiscal years:
HIGH LOW DISTRIBUTIONS PER UNIT
---- --- ----------------------
1st Quarter 2002 $28.250 $21.710 $0.5000 (paid May 15, 2002)
2nd Quarter 2002 $24.700 $21.850 $0.5000 (paid August 14, 2002)
3rd Quarter 2002 $25.000 $17.000 $0.5000 (paid November 14, 2002)
4th Quarter 2002 $25.200 $20.000 $0.5250 (paid February 14, 2003)
1st Quarter 2003 $25.500 $21.490 $0.5250 (paid May 15, 2003)
2nd Quarter 2003 $27.999 $21.980 $0.5250 (paid August 14, 2003)
3rd Quarter 2003 $29.920 $25.480 $0.5250 (paid November 14, 2003)
4th Quarter 2003 $35.240 $28.000 $0.5625 (paid February 13, 2004)
We have also outstanding 3,211,266 subordinated units, all of which are
held by our special general partner and for which there is no established public
trading market. Originally we issued 6,422,531 subordinated units to our special
general partner. In November 2003, 3,211,265 outstanding subordinated units
converted to common units in accordance with our partnership agreement as
explained below.
We will distribute to our partners (including holders of subordinated
units), on a quarterly basis, all of our available cash. "Available cash", as
defined in our partnership agreement, generally means, with respect to any
quarter, all cash on hand at the end of each quarter, plus working capital
borrowings after the end of the quarter, less cash reserves in the amount
necessary or appropriate in the reasonable discretion of our 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. If quarterly
distributions of available cash exceed the minimum quarterly distribution (MQD)
and certain target distribution levels as established in our partnership
agreement, our managing general partner will receive distributions based on
specified increasing percentages of the available cash that exceed the MQD and
the target distribution levels. Our partnership agreement defines the 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 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 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. Our partnership agreement provides for the early conversion of one-half
of the subordinated units if certain
24
financial tests were satisfied before September 30, 2003. We satisfied the
required financial tests for converting one-half of the subordinated units into
common units as provided for under applicable provisions in the partnership
agreement. Accordingly, in October 2003, the board of directors (and its
conflicts committee) of our managing general partner approved management's
determination that such conversion financial tests were satisfied. As a result,
one-half of the outstanding subordinated units (i.e., 3,211,265 subordinated
units) held by our special general partner converted into common units on
November 15, 2003. The remaining 3,211,266 subordinated units are expected to
convert on a one-for-one basis into common units in the fourth quarter of 2004,
assuming we continue to meet the financial test requirements of the partnership
agreement.
EQUITY COMPENSATION PLANS
The information relating to our equity compensation plans required by Item
5 is incorporated by reference to such information as set forth in "Item 12.
Security Ownership of Certain Beneficial Owners and Management" contained
herein.
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, 2003, 2002, 2001, 2000 and 1999, for the years ended December 31,
2003, 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. We acquired Warrior from ARH Warrior Holdings, a
subsidiary of Alliance Resource Holdings, in February 2003. Because the Warrior
acquisition was between entities under common control, it is accounted for at
historical cost in a manner similar to that used in a pooling of interests.
Accordingly, the financial statements as of December 31, 2002 and 2001, and for
each of the two years in the period ended December 31, 2002, have been restated
to reflect the combined historical results of operations, financial position,
and cash flows of the Partnership and Warrior. ARH Warrior Holdings acquired the
assets that comprise Warrior on January 26, 2001.
25
(in millions, except per unit and per ton data) Partnership
-------------------------------------------------------------------------------------
From
Commencement
of Operations
(on
Pro Forma August 20, 1999)
Year Ended December 31, Year Ended to
-------------------------------------------------- December 31, December 31
2003 2002 2001 2000 1999 (1) 1999
---- ---- ---- ---- -------- ----
STATEMENTS OF INCOME:
Sales and operating revenues
Coal sales $ 501.6 $ 479.5 $ 453.1 $ 347.2 $ 345.9 $ 128.8
Transportation revenues (2) 19.5 19.0 18.2 13.5 19.1 4.9
Other sales and operating revenues 21.6 20.4 6.2 2.8 0.9 0.4
---------- ----------- ------------ ----------- ------------ ---------------
Total revenues 542.7 518.9 477.5 363.5 365.9 134.1
---------- ----------- ------------ ----------- ------------ ---------------
EXPENSES:
Operating expenses 368.8 367.5 337.2 257.4 242.0 89.9
Transportation expenses (2) 19.5 19.0 18.2 13.5 19.1 4.9
Outside purchases 8.5 10.1 28.9 16.9 24.2 6.4
General and administrative 28.3 20.3 18.7 15.2 15.1 6.2
Depreciation, depletion and
amortization 52.5 52.4 50.7 39.1 39.7 15.1
Interest expense 16.0 16.4 16.8 16.6 19.4 5.9
Unusual items (3) - - - (9.5) - -
---------- ----------- ------------ ----------- ------------ ---------------
Total expenses 493.6 485.7 470.5 349.2 359.5 128.4
---------- ----------- ------------ ----------- ------------ ---------------
Income from operations 49.1 33.2 7.0 14.3 6.4 5.7
Other income (expense) 1.4 0.5 0.8 1.3 1.2 0.6
---------- ----------- ------------ ----------- ------------ ---------------
Income before income taxes and cumulative
effect of accounting change 50.5 33.7 7.8 15.6 7.6 6.3
Income tax expense (benefit) 2.6 (1.1) (0.8) - - -
---------- ----------- ------------ ----------- ------------ ---------------
Income before cumulative effect of
accounting change 47.9 34.8 8.6 15.6 7.6 6.3
Cumulative effect of accounting change(4) - - 7.9 - - -
---------- ----------- ------------ ----------- ------------ ---------------
Net income $ 47.9 $ 34.8 $ 16.5 $ 15.6 $ 7.6 $ 6.3
========== =========== ============ =========== ============ ===============
General Partners' interest in net income
(loss) $ 0.3 $ (0.8) $ (0.2) $ 0.3 $ 0.2 $ 0.1
========== =========== ============ =========== ============ ===============
Limited Partners' interest in net income $ 47.6 $ 35.6 $ 16.7 $ 15.3 $ 7.4 $ 6.2
========== =========== ============ =========== ============ ===============
Basic net income per limited partner unit $ 2.71 $ 2.31 $ 1.09 $ 0.99 $ 0.48 $ 0.40
========== =========== ============ =========== ============ ===============
Basic net income per limited partner unit
before accounting change $ 2.71 $ 2.31 $ 0.58 $ 0.99 $ 0.48 $ 0.40
========== =========== ============ =========== ============ ===============
Diluted net income per limited partner
unit $ 2.62 $ 2.24 $ 1.07 $ 0.98 $ 0.48 $ 0.40
========== =========== ============ =========== ============ ===============
Diluted net income per limited partner
unit before accounting change $ 2.62 $ 2.24 $ 0.57 $ 0.98 $ 0.48 $ 0.40
========== =========== ============ =========== ============ ===============
Weighted average number of units
outstanding- basic 17,580,734 15,405,311 15,405,311 15,405,311 15,405,311 15,405,311
========== =========== ============ =========== ============ ===============
Weighted average number of units
outstanding- diluted 18,162,839 15,842,708 15,684,550 15,551,062 15,405,311 15,405,311
========== =========== ============ =========== ============ ===============
BALANCE SHEET DATA:
Working capital (deficit) $ 16.4 $ (15.8) $ 0.9 $ 38.6 $ - $ 61.2
Total assets 336.5 316.9 310.3 309.2 - 314.8
Long-term debt 180.0 195.0 211.3 226.3 - 230.0
Total liabilities 323.9 355.7 347.8 341.0 - 330.7
Net Parent investment - - - - - -
Partners' capital (deficit) 12.6 (38.8) (37.6) (31.8) - (15.9)
OTHER OPERATING DATA:
Tons sold 19.5 18.4 18.6 15.0 15.0 5.6
Tons produced 19.2 18.0 17.4 13.7 14.1 5.3
Revenues per ton sold (5) $ 26.83 $ 27.17 $ 24.69 $ 23.33 $ 23.12 $ 23.07
Cost per ton sold (6) $ 20.80 $ 21.63 $ 20.69 $ 19.30 $ 18.75 $ 18.30
OTHER FINANCIAL DATA:
Net cash provided by (used in) operating
activities $ 110.3 $ 101.3 $ 70.5 $ 71.4 $ - $ (13.9)
Net cash used in investing activities (77.8) (56.9) (31.1) (41.0) - (43.9)
Net cash provided by (used in) financing (31.3) (46.4) (35.2) (31.4) - 65.8
activities
Maintenance capital expenditures (7) 30.0 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
to
August 19,
1999
----
STATEMENTS OF INCOME:
Sales and operating revenues
Coal sales $ 217.0
Transportation revenues (2) 14.2
Other sales and operating revenues 0.6
--------------
Total revenues 231.8
--------------
EXPENSES:
Operating expenses 152.1
Transportation expenses (2) 14.2
Outside purchases 17.7
General and administrative 8.9
Depreciation, depletion and amortization 24.6
Interest expense 0.1
Unusual items (3) -
--------------
Total expenses 217.6
--------------
Income from operations 14.2
Other income (expense) 0.5
--------------
Income before income taxes and cumulative
effect of accounting change 14.7
Income tax expense (benefit) 4.5
--------------
Income before cumulative effect of
accounting change 10.2
Cumulative effect of accounting change(4) -
--------------
Net income $ 10.2
==============
General Partners' interest in net income
(loss)
Limited Partners' interest in net income
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
Total assets 262.8
Long-term debt 1.8
Total liabilities 110.2
Net Parent investment 151.6
Partners' capital (deficit) -
OTHER OPERATING DA TA:
Tons sold 9.4
Tons produced 8.8
Revenues per ton sold (5) $ 23.15
Cost per ton sold (6) $ 19.01
OTHER FINANCIAL DATA:
Net cash provided by (used in) operating $ 32.9
activities
Net cash used in investing activities (21.5)
Net cash provided by (used in) financing (11.4)
activities
Maintenance capital expenditures (7) 15.5
(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
26
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 of 2000, we adopted the Financial Accounting
Standards Board Emerging Issues Task Force Issue No. 00-10 "Accounting for
Shipping and Handling Fees and Costs" (EITF No. 00-10). We record the cost
of transporting coal to customers through third party carriers and our
corresponding direct reimbursement of these costs through customer
billings. This activity is separately presented as transportation revenue
and expense rather than offsetting these amounts in the consolidated and
combined statements of income. There was no cumulative effect of the
accounting change on net income and prior periods presented have been
reclassified to comply with EITF No. 00-10.
(3) Represents income from the final resolution of an arbitrated dispute with
respect to the termination of a long-term contract, net of impairment
charges relating to certain transloading facility assets, partially offset
by expenses associated with other litigation matters in 2000.
(4) Represents the cumulative effect of the change in the method of estimating
coal workers' pneumoconiosis ("black lung") benefits liability effective
January 1, 2001. Please 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
4. 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) Our maintenance capital expenditures, as defined under the terms of our
partnership agreement, are 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. Maintenance capital
expenditures for the years ended December 31, 2002 and 2001 have not been
restated to include Warrior.
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
operation should be read in conjunction with the historical financial statements
and notes thereto included elsewhere in this Annual Report on Form 10-K. We
acquired Warrior from ARH Warrior Holdings, a subsidiary of Alliance Resource
Holdings, in February 2003. Because the Warrior acquisition was between entities
under common control, it is accounted for at historical cost in a manner similar
to that used in a pooling of interests. Accordingly, the financial statements as
of December 31, 2002 and 2001, and for each of the two years in the period ended
December 31, 2002, have been restated to reflect the combined historical results
of operations, financial position and cash flows of the Partnership and Warrior.
ARH Warrior Holdings acquired Warrior on January 26, 2001. For more detailed
information regarding the basis of presentation for the following financial
information, please see "Item 8. Financial Statements and Supplementary Data. -
Note 1. Organization and Presentation and Note 2. Summary of Significant
Accounting Policies."
27
BUSINESS
We are a diversified producer and marketer of coal to major U.S. utilities
and industrial users. In 2003, our total production was 19.2 million tons and
our total sales were 19.5 million tons. The coal we produced in 2003 was
approximately 31.2% low-sulfur coal, 17.2% medium-sulfur coal and 51.6%
high-sulfur coal.
At December 31, 2003, we had approximately 418.4 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 properties adjacent to some of our Illinois Basin region operations that we
currently intend to acquire or lease as our mining operations approach these
areas.
In 2003, approximately 79% of our sales tonnage was consumed by electric
utilities with the balance consumed by cogeneration plants and industrial users.
Our largest customers in 2003 were Seminole, SSO, and VEPCO. In 2003,
approximately 84% of our sales tonnage, including approximately 88% 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 2003, 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 Warrior, 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. 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. In conjunction with a decision to
relocate the coal synfuel production facility from Hopkins 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.
For 2003, the incremental annual net income benefit from the combination of
the various coal synfuel-related agreements was approximately $15.5 million,
assuming that coal pricing would not have increased without the availability of
synfuel. The continuation of the incremental net income benefit associated with
SSO's coal synfuel facility cannot be assured. We earn income by supplying SSO's
synfuel facility with coal feedstock, assisting SSO with the marketing of coal
synfuel, and providing rental and other services. Pursuant to our agreement with
SSO, we are not obligated to make retroactive adjustments or reimbursements if
SSO's tax credits are disallowed.
In June 2003 the IRS suspended the issuance of private letter rulings on
the significant chemical change requirement to qualify for synfuel tax credits
and announced that it was reviewing the test procedures and results used by
taxpayers to establish that a significant chemical change had occurred. In
October 2003, the IRS completed its review and concluded that the test
procedures and results were scientifically valid if applied in a consistent and
unbiased manner. The IRS has resumed issuing private letter rulings under its
existing guidelines. SSO has advised us that its private letter ruling could be
reviewed by the IRS as part of a tax audit, similar to the IRS reviews of other
synfuel procedures. SSO has also advised us that the Permanent Subcommittee on
Investigations of the Senate Committee on Governmental Affairs (Subcommittee) is
28
reviewing the synfuel industry, that the Subcommittee has indicated that they
hope to interview almost all taxpayers that are involved in the synfuel
business, and that SSO has been requested to meet informally with the
Subcommittee to help enhance the Subcommittee's knowledge of the synfuel
industry.
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.
SUMMARY
In 2003, we reported record net income of $47.9 million, an increase of
38.0% over 2002 net income of $34.8 million. We grew through a combination of
internal expansion and an acquisition. We added continuous miner units at
Gibson, Warrior and MC Mining and completed infrastructure investments such as
new mine shafts at Dotiki and MC Mining and a new slope at Warrior. We acquired
Warrior in February 2003. Tons produced increased 7.1% to 19.2 million tons.
Tons sold increased 6.0% to 19.5 million tons.
The combination of adding mining units, realizing benefits from completed
infrastructure projects and the absence of adverse geologic conditions
encountered at Mettiki in the third quarter of 2002 contributed to lower
operating expenses per ton sold. The lower operating expenses per ton sold was
the primary factor in achieving record net income, offsetting the impact of
lower sales prices.
For 2004, we have commitments for substantially all of our 2004 production.
For our estimated 2005 production, approximately 84% is committed under existing
coal sales agreements and approximately 49% is subject to market price
negotiations.
In 2004, we will continue our efforts to maximize the cost reduction
opportunities created by our increased production capacity. Dotiki plans to
increase the number of operating sections that operate with two continuous
miners and expand the throughput capacity of its preparation plant approximately
30%. With the infrastructure created by the capital investments we have made
over the past three years, we could, with some additional capital investments,
increase production approximately two million tons to respond to increases in
market place demand.
On February 11, 2004, the Dotiki mine was temporarily idled following the
occurrence of a mine fire. We have successfully extinguished the fire and have
totally isolated the affected area of the mine behind permanent seals.
Production resumed on March 8, 2004. At this time, we are unable to quantify the
financial impact of the fire or to predict when Dotiki will return to normal
production. The temporary idling of Dotiki will reduce earnings for the first
quarter of 2004. We have commercial property insurance (including business
interruption coverage) that we currently believe should cover a substantial
portion of the financial loss. Assuming that is correct, Dotiki's losses
recognized in the first quarter of 2004 should be substantially offset by an
insurance settlement that would be recognized later in the year. There can be no
assurance of the amount or timing of recovery, however, until the claim is
resolved with the insurance underwriter. Our insurance program provides for a
deductible of $3.5 million and a ten percent coinsurance. In addition to the
losses associated with business interruption, we have currently identified
approximately $6.0 million of out-of-pocket expenses that generally fall into
the category of extra expenses, expedited expenses and other areas of coverage
under the commercial property insurance policy. We expect that additional
out-of-pocket costs will be identified in the future. Please see "Item 1.
Business; Recent Developments; Dotiki Mine Fire."
29
RESULTS OF OPERATIONS
2003 COMPARED WITH 2002
PER TON SOLD
------------
2003 2002 2003 2002
---- ---- ---- ----
(in thousands)
Tons sold 19,467 18,370 N/A N/A
Tons produced 19,238 17,970 N/A N/A
Coal Sales $501,596 $479,515 $ 25.77 $ 26.10
Operating Expenses and Outside Purchases $377,343 $377,644 $ 19.38 $ 20.56
Operating expenses. Operating expenses were comparable for 2003 and 2002 at
$368.8 million and $367.6 million, respectively. Increased operating expenses
associated with higher production and sales levels at our active mines were
offset by a decrease associated with idling the Hopkins complex on June 2, 2003.
Operating expenses declined on a cost-per-ton sold basis as production increased
at all of our active operations except Pattiki. Pattiki's production was
essentially the same in 2003 and 2002.
Increased production reflects the absence of the adverse geologic
conditions encountered at Mettiki in the third quarter of 2002 and the emerging
benefit of several strategic capital investments made during the past two years.
We have added continuous miner units at Gibson, Warrior and MC Mining and have
made infrastructure investments, such as new mine shafts, at Dotiki, Warrior and
MC Mining. Additionally, operating expenses decreased due to the reversal of an
expense accrual of $1.2 million established in 1998. The expense accrual was
established in conjunction with the idling of Pontiki in 1998 that created an
expectation of a probable increase in workers' compensation costs associated
with the terminated workforce. The anticipated increase in workers' compensation
claims did not emerge and, with limited exceptions, the statute of limitations
expired in December 2003 for the filing or reopening of workers' compensation
claims associated with the employee terminations.
Coal sales. Coal sales for 2003 increased 4.6% to $501.6 million from
$479.5 million for 2002. The increase of $22.1 million was attributable to
increased tons sold partially offset by lower sales prices. Sales prices in 2002
benefited from coal sales agreements entered into during the second half of 2001
when sales prices for deliveries in 2002 increased in response to a combination
of factors including low coal stockpiles and supply shortages. Tons sold
increased 6.0% to 19.5 million for 2003 from 18.4 million in 2002, reflecting an
increase in tons produced. Tons produced increased 7.1% to 19.2 million for 2003
from 18.0 million in 2002. Please see "Operating Expenses" above concerning the
increase in tons produced.
Other sales and operating revenues. Other sales and operating revenues,
which is primarily comprised of services to the coal synfuel production
facility, increased 6.0% to $21.6 million from $20.4 million in 2002. However,
the $1.2 million increase was primarily attributable to providing additional
services for treating, handling and transporting coal unrelated to the coal
synfuel services.
General and administrative. General and administrative expenses for 2003
increased 39.0% to $28.3 million compared to $20.3 million for 2002. The $8.0
million increase was primarily attributable to higher expense accruals of $6.9
million associated with incentive compensation programs, and the remaining
increase in expense reflects various other increases in administrative
compliance costs.
30
Depreciation, depletion and amortization. Depreciation, depletion and
amortization were comparable for 2003 and 2002 at $52.5 million and $52.4
million, respectively. Additional depreciation associated with the capital
additions described in "Operating Expenses" above was offset by lower
depreciation of $3.0 million at the idled Hopkins complex. Please see "Item 1.
Business, Mining Operations, Illinois Basin Operations."
Interest expense. Interest expense for 2003 declined 2.3% to $16.0 million
from $16.4 million in 2002 primarily attributable to decreased borrowings under
the revolving credit facility.
Outside purchases. Outside purchases for 2003 decreased 15.6% to $8.5
million from $10.1 million in 2002. The decrease was primarily attributable to a
decrease in coal purchases from a third-party producer that ceased production in
the fourth quarter of 2002.
Transportation revenues and expenses. Transportation revenues and expenses
for 2003 increased 3.0% to 19.6 million from $19.0 million for 2002. The
increase of $0.6 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.
Income before income tax expense (benefit) and cumulative effect of
accounting change. Income before income tax expense (benefit) and cumulative
effect of accounting change increased 49.8% to $50.5 million for 2003 compared
to $33.7 million for 2002. The increase was primarily attributable to lower cost
per-ton-sold operating costs and higher sales volumes, partially offset by lower
sales prices and increased general and administrative expenses.
Income tax expense (benefit). Income tax expense for 2003 was $2.6 million
compared to an income tax benefit of $1.1 million in 2002. 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. Approximately $2.1 million of the increase in income
tax expense was associated with coal synfuel-related services performed by
Alliance Service. The balance of the income tax expense increase was
attributable to Warrior, which had a net income tax benefit for the year 2002 of
approximately $1.3 million. Since our acquisition of Warrior on February 14,
2003, the financial results of Warrior are no longer subject to federal or state
income taxes.
2002 COMPARED WITH 2001
We acquired Warrior from ARH Warrior Holdings, a subsidiary of Alliance
Resource Holdings, in February 2003. Because the Warrior acquisition was between
entities under common control, it is accounted for at historical cost in a
manner similar to that used in a pooling of interests. Accordingly, the
financial statements as of December 31, 2002 and 2001, and for each of the two
years in the period ended December 31, 2002, have been restated to reflect the
combined historical results of operations, financial position, and cash flows of
the Partnership and Warrior. ARH Warrior Holdings acquired Warrior on January
26, 2001.
31
PER TON SOLD
------------
2002 2001 2002 2001
---- ---- ---- ----
(in thousands)
Tons sold 18,370 18,569 NA NA
Tons produced 17,970 17,354 NA NA
Coal Sales $ 479,515 $453,054 $ 26.10 $ 24.40
Other Sales and Operating Revenues $ 20,385 $ 6,233 NA NA
Operating Expenses and Outside Purchases $ 377,644 $366,073 $ 20.56 $ 19.71
Coal sales. Coal sales for 2002 increased 5.8% to $479.5 million from
$453.1 million for 2001. The increase of $26.4 million was primarily
attributable to higher price sales contracts secured during the second half of
2001 for deliveries in 2002 and higher productivity and coal sales from Gibson.
The higher priced sales contracts reflected a combination of factors including
low coal stockpiles and supply shortages. These increases were partially offset
by a decrease in the domestic coal brokerage market. Tons sold were comparable
for 2002 and 2001 at 18.4 million tons and 18.6 million tons, respectively. Tons
produced increased 3.5% to 18.0 million for 2002 compared to 17.4 million in
2001, primarily reflecting increased production at Gibson.
Other sales and operating revenues. Other sales and operating revenues
increased to $20.4 million for 2002 from $6.2 million for 2001. The increase of
$14.2 million was attributable to additional rental and service fees associated
with increased volumes at a third-party coal synfuel production facility at
Hopkins. Please see "Item 1. Business, Mining Operations, Illinois Basin
Operations."
Operating expenses. Operating expenses increased 9.0% to $367.6 million in
2002 from $337.2 million in 2001. The increase of $30.4 million was primarily
the result of increased operating expenses associated with increased tons sold
from production, increased coal synfuel production and a period of higher costs
at Dotiki and Warrior during the construction of infrastructure investments.
Operating expenses increased on a cost-per-ton basis, reflecting the higher cost
production periods at Dotiki and Warrior, the transition into higher
cost-per-ton mining areas at Hopkins and production losses at Mettiki
attributable to adverse geologic conditions.
Outside purchases. Outside purchases decreased to $10.1 million in 2002
from $28.9 million in 2001. The decrease of $18.8 million was primarily
attributable to a decrease in the domestic coal brokerage market.
General and administrative. General and administrative expenses increased
8.5% to $20.3 million in 2002 compared to $18.7 million in 2001. The increase of
$1.6 million was primarily attributable to higher expense accruals of $0.8
million associated with incentive compensation programs and various other
increases in administrative compliance costs.
Depreciation, depletion and amortization. Depreciation, depletion and
amortization expenses increased 3.4% to $52.4 million for 2002 compared to $50.7
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 2.5% to $16.4 million for 2002
from $16.8 million for 2001 primarily reflecting debt reduction due to scheduled
debt payments.
Transportation revenues and expenses. Transportation revenues and expenses
for 2002 increased 4.6% to $19.0 million from $18.2 million in 2001. The
increase reflects increased shipments to a customer with
32
above-average transportation costs. 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.
Income before income tax expense (benefit) and cumulative effect of
accounting change. Income before income tax expense (benefit) and cumulative
effect of accounting change increased $25.9 million to $33.7 million for 2002
from $7.8 million for 2001. The increase was primarily attributable to higher
price sales contracts, increased volumes associated with the coal synfuel
related agreements, and higher sales volume at Gibson partially offset by
increased operating expense per ton sold, reflecting the higher cost production
periods at Dotiki and Warrior during the construction of infrastructure
investments, the transition into higher cost-per-ton mining areas at Hopkins and
production losses at Mettiki attributable to adverse geologic conditions.
Income tax expense (benefit). Income tax benefit for 2002 was $1.1 million
compared to an income tax benefit of $0.8 million in 2001. Although we are not a
taxable entity for federal or state income tax purposes, Warrior was subject to
federal and state income taxes prior to February 2003 when we purchased Warrior.
Warrior had a net income tax benefit of $1.3 million in 2002 compared to $0.8
million in 2001. Additionally, 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,
resulting in income tax expense of $0.2 million.
Cumulative effect of accounting change. Please see discussion above under
"Workers' Compensation and Pneumoconiosis ("Black Lung") Benefits."
ONGOING ACQUISITION ACTIVITIES
Consistent with our business strategy, from time-to-time we engage in
discussions with potential sellers regarding possible acquisitions by us.
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
distribution 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. During 2003, we had rental expense of
$1.0 million under the master lease agreement. We had no equipment leased under
the master equipment lease at December 31, 2002. Our credit facility limits the
amount of total operating lease obligations to $15.0 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.
33
Cash Flows
Cash provided by operating activities was $110.3 million in 2003, compared
to $101.3 million in 2002. The increase in cash provided by operating activities
was principally attributable to increased operating income.
Net cash used in investing activities was $77.8 million in 2003, compared
to net cash used in investing activities of $56.9 million in 2002. The increased
use of cash is principally attributable to purchasing of marketable securities
of $23.1 million in 2003 compared to the receipt of proceeds from the maturity
of marketable securities in 2002.
Net cash used in financing activities was $31.3 million for 2003, compared
to net cash used in financing activities of $46.4 million for 2002. The decrease
is primarily attributable to the proceeds received from our common unit offering
during 2003 of $53.9 million partially offset by an increase of $5.6 million in
distributions to our partners due to an increase in the quarterly distribution
rate of $0.025 per unit to $0.525 per unit and the additional common units
outstanding from the common unit offering, payment of Warrior's borrowings of
$17.0 million under a revolving credit agreement and an increase in payments of
$16.3 million on long-term debt. The quarterly distribution rate was increased
to $0.5625 per unit for the quarter ended December 31, 2003. We expect to
maintain this level of quarterly cash distribution during 2004.
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, 2003 (in thousands):
LESS
CONTRACTUAL THAN 1 2-3 4-5 AFTER 5
OBLIGATIONS TOTAL YEAR YEARS YEARS YEARS
----------- ----- ---- ----- ----- -----
Long-term debt $180,000 $ - $ 36,000 $ 36,000 $108,000
Operating leases 25,265 4,663 8,911 6,273 5,418
Other long-term obligations
(excluding discount effect of $10.3
million for reclamation liability) 33,798 1,749 5,599 8,247 18,203
Capital projects 7,659 7,659 - - -
-------- --------- -------- -------- --------
$246,722 $ 14,071 $ 50,510 $ 50,520 $131,621
======== ========= ======== ======== ========
We expect to contribute $3.3 million to the defined benefit pension plan
(Pension Plan) during 2004. We estimate that our combined interest and income
tax cash requirements will be approximately $15.5 million and $2.4 million,
respectively in 2004.
Capital Expenditures
Capital expenditures decreased to $55.7 million in 2003, compared to $67.3
million in 2002. The capital expenditures in 2003 of $55.7 million included
$12.7 million for the Warrior acquisition. Excluding the Warrior acquisition,
capital expenditures for 2003 decreased $24.3 million compared to capital
expenditures for the 2002 period. The decrease is primarily attributable to the
substantial completion of the extension into an adjacent reserve area at Pattiki
in late 2002, new infrastructure projects at Warrior in 2002, and the new
service shaft at Dotiki completed in April 2003. The majority of the capital
expenditures associated with the Pattiki, Warrior and Dotiki projects were
incurred during 2002.
34
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. 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 our special general partner
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.
We currently project that our average annual maintenance capital
expenditures will be approximately $34.0 million. We also currently expect to
fund our anticipated total capital expenditures for 2004 of $46.5 million, with
cash generated from operations and borrowings under our revolving credit
facility described below.
Notes Offering and Credit Facility
Concurrently with the closing of our initial public offering, our special
general partner issued, and our intermediate partnership assumed the obligations
with respect to, $180 million principal amount of 8.31% senior notes due August
20, 2014 (Senior Notes). On August 22, 2003, our intermediate partnership
completed a new $85 million revolving credit facility (Credit Facility), which
expires September 30, 2006. The Credit Facility replaced a $100 million credit
facility that would have expired August 2004. We paid in full all amounts
outstanding under the original credit facility with borrowings of $20 million
under the Credit Facility. The interest rate on the Credit Facility is based on
either the (i) London Interbank Offered Rate or (ii) the "Base Rate", which is
equal to the greater of the JPMorgan Chase Prime Rate or the Federal Funds Rate
plus 1/2 of 1%, plus, in either case, an applicable margin. We incurred certain
costs aggregating $1.2 million associated with the Credit Facility. These costs
have been deferred and are being amortized as a component of interest expense
over the term of the Credit Facility. We had no borrowings outstanding under the
Credit Facility at December 31, 2003. Letters of credit can be issued under the
Credit Facility not to exceed $30 million. Outstanding letters of credit reduce
amounts available under the Credit Facility. At December 31, 2003, we had
letters of credit of $9.0 million outstanding under the Credit Facility.
The Senior Notes and Credit Facility are guaranteed by all of the
subsidiaries of our intermediate partnership. The Senior Notes and Credit
Facility contain various restrictive and affirmative covenants, including the
amount of distributions by our 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, 2003.
We have previously entered into and have maintained agreements with two
banks to provide additional letters of credit in an aggregate amount of $25.0
million to maintain surety bonds to secure our obligations for reclamation
liabilities and workers' compensation benefits. At December 31, 2003, we had
$15.6 million in letters of credit outstanding under these agreements. Our
special general partner guarantees the letters of credit.
35
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. Please 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 us 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 our 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 $23.5 million for these
costs at December 31, 2003 and 2002, 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 independent actuarial study. 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 $28.2 million and $24.7 million for these costs at
December 31, 2003 and 2002, respectively. A one-percentage-point reduction in
the discount rate would have increased the liability at December 31, 2003
approximately $1.2 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, mortality, death benefits, dependents and interest rates. We had
accrued liabilities of $18.1 million and $16.6 million for these benefits at
December 31, 2003 and 2002, respectively. A one-percentage-point reduction in
the discount rate would have increased the expense recognized for the year ended
December 31, 2003 by approximately $0.3 million. Under the service cost method
used to estimate our black lung benefits liability,
36
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 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.
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 $200 million of debt or equity securities. At March 1, 2004,
we had approximately $142.9 million available under this registration statement.
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 they incur or
payments they make on our behalf including, but not limited to, management's
salaries and related benefits (including incentive compensation), 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 $12,471,000, $6,559,000, and $6,503,000 for the years ended
December 31, 2003, 2002, and 2001 respectively. The increase from 2002 to 2003
was primarily attributable to higher accruals related to common unit based
incentive programs, which were impacted by the increased market value of our
common units, and the Short Term Incentive Plan (STIP).
Warrior 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. 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.
37
The Put/Call Agreement preserved the opportunity for us to acquire Warrior
during a specified time period. 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
the date of the acquisition and at 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. In addition, we repaid
Warrior's borrowings of $17.0 million under the revolving credit agreement
between our special general partner and Warrior. The primary borrowings under
the revolving credit agreement financed new infrastructure capital projects at
Warrior that have contributed to improved productivity and significantly
increased capacity. We funded the Warrior acquisition through a portion of the
proceeds received from the issuance of 2,250,000 common units. Because the
Warrior acquisition was between entities under common control, it has been
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, 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.
SGP Land
Dotiki 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. Dotiki paid royalties of $3,460,000 for 2003 and $2.7 million in
2002 and 2001. Dotiki has recouped as earned royalties all advance minimum
royalty payments made under these lease terms as of December 31, 2003.
Warrior has a mineral lease and sublease with SGP Land. Under the terms of
the lease, Warrior has paid and will continue to pay in arrears an annual
minimum royalty obligation of $2,270,000 until $15,890,000 of cumulative annual
minimum and/or earned royalty payments have been paid. The annual minimum
royalty periods are from October 1st through the end of the following September,
expiring September 30, 2007. Warrior paid royalties of $2,453,000, $2,127,000
and $2,838,000 for the years ended December 31, 2003, 2002, and 2001,
respectively. Warrior has recouped as earned royalties all advance minimum
royalty payments made in accordance with these lease terms except for $1,230,000
as of December 31, 2003.
38
Under the terms of the mineral lease and sublease agreements described
above, Dotiki and Warrior also reimbursed SGP Land for SGP Land's base lease
obligations. We reimbursed SGP Land $4,395,000, $3,922,000, and $2,347,000 for
the years ended December 31, 2003, 2002 and 2001 respectively, for the base
lease obligations. Dotiki and Warrior have recouped as earned royalties all
advance minimum royalty payments made in accordance with these terms except for
$320,000 as of December 31, 2003.
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 $479,000,
$568,000, and $705,000 for the years ended December 31, 2003, 2002, and 2001,
respectively. MC Mining has recouped as earned royalties all advance minimum
royalty payments made under these lease terms as of December 31, 2003.
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 2003 option fee of $684,000 was paid in January
2004 and is included in the due to affiliates balance as of December 31, 2003.
The anticipated annual minimum royalty obligation is $684,000, payable in
advance through 2009.
Special General Partner
Effective January 2001, Gibson entered into a noncancelable operating lease
arrangement with our special general partner 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 was $2,595,000 for 2003, 2002 and 2001.
We have previously entered into and have maintained agreements with two
banks to provide letters of credit in an aggregate amount of $25.0 million to
maintain surety bonds to secure our obligations for reclamation liabilities and
workers' compensation benefits. At December 31, 2003, we had $15.6 million in
outstanding letters of credit. Our special general partner guarantees these
letters of credit. Historically, we have compensated our special general partner
a guarantee fee equal to 0.30% per annum of the face amount of the letters of
credit outstanding. Our special general partner agreed to waive the guarantee
fee in exchange for a parent guarantee from our intermediate partnership and
Alliance Coal on the mineral lease and sublease with Dotiki and Warrior. We paid
approximately $31,300, $48,200, and $8,800 in guarantee fees to our special
general partner for the years ended December 31, 2003, 2002, and 2001,
respectively.
ACCRUALS OF OTHER LIABILITIES
We had accruals for other liabilities, including current obligations,
totaling $77.8 million and $75.8 million at December 31, 2003 and 2002. 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 be significantly affected by changes to these liabilities. Please
see "Item 8. Financial Statements and Supplementary Data. - Note 14. Reclamation
and Mine Closing Costs and Note 15. Pneumoconiosis ("Black Lung") Benefits."
PENSION PLAN
We maintain a Pension Plan, which covers certain employees at the mining
operations.
39
Our pension expense was approximately $3,049,000 and $2,199,000 for the
years ended December 31, 2003 and 2002, respectively. The pension expense is
based upon a number of actuarial assumptions, including an expected long-term
rate of returns on our Pension Plan assets of 8.0% and 9.0% and a discount rates
of 6.75% and 7.25% for the years ended December 31, 2003 and 2002, 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. At January 1, 2004,
our expected long-term return assumption is 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 10.2%,
and 20.0% with fixed income managers, with an expected long-term rate of return
of 5.4%. The pension plan trustee regularly reviews our actual asset allocation
in accordance with our investment guidelines and periodically rebalanced our
investments to our targeted allocation when considered appropriate. The
investment committee reviews our asset allocation with the compensation
committee annually.
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 6.75% at December 31, 2002 to 6.25% at
December 31, 2003.
We estimate that our Pension Plan expense and cash contributions will be
approximately $2,640,000 and $3,300,000, respectively in 2004. 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
8.0% to 7.0%) at December 31, 2002 would have increased our pension expense for
the year ended December 31, 2003 by approximately $140,000. Lowering the
discount rate assumption by 0.5% (from 6.75% to 6.25%) at December 31, 2002
would have increased our pension expense for the year ended December 31, 2003 by
approximately $357,000.
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, 2003.
RECENT ACCOUNTING PRONOUNCEMENTS
On January 1, 2003, we adopted Statement of Financial Accounting Standards
("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 obligations for
its recorded amount is paid or a gain
40
or loss upon settlement is incurred. Since we have historically adhered to
accounting principles similar to SFAS No. 143, this standard had no material
effect on our consolidated financial statements upon adoption.
On January 1, 2003, we adopted Financial Accounting Standards Board
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. This interpretation had no material effect on our
consolidated financial statements upon adoption.
RECENT ACCOUNTING ISSUE
Extractive industry companies have historically classified leased coal
interests and advance royalties as tangible assets, which is consistent with the
classification of owned coal due to the similar rights of the leaseholder. SFAS
No. 141, "Business Combinations," identifies mineral rights as an example of a
contract-based intangible asset that should be considered for separate
classification as the result of a business combination. Due to the potential for
inconsistencies in applying the provisions of SFAS No. 141 (and SFAS No. 142,
"Goodwill and Other Intangible Assets") in the extractive industries as they
relate to mineral interests controlled by other than fee ownership, the Emerging
Issues Task Force (EITF) has established a Mining Industry Working Group that is
currently addressing this issue. Depending on the conclusions reached by the
Mining Industry Working Group and the EITF, the classification of our leased
coal interests and advance royalties in our consolidated balance sheets may be
revised.
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
two customers have 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 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 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.
41
- 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 Warrior 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.
- Coal mining is subject to inherent risks that are beyond our control
and these risks may not be fully covered under our insurance policies.
These risks include fires and explosions from methane, natural
disasters like floods, mining and processing equipment failures,
changes or variations in geologic conditions, inability to acquire
mining rights or permits, employee injuries or fatalities, and
labor-related interruptions.
- 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 will be adversely affected if we are unable to replace
our coal reserves.
- The estimates of our reserves may prove inaccurate, and unitholders
should not place undue reliance on these estimates.
42
- Cash distributions are not guaranteed and may fluctuate with our
performance. In addition, our managing general partner's discretion in
establishing cash 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
- 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 affiliates.
- 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
- 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.
43
- 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 through coal refuse disposal under the underground
injection control program or regulation of our public drinking water
systems.
- 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.
- 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, please see "Item 1. Business. - Coal Marketing and Sales" and "Item
8. Financial Statements and Supplementary Data. - Note 18. 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.
44
At the current time, we do not have any interest rate, foreign currency
exchange rate or commodity price-hedging transactions outstanding.
On August 22, 2003, our intermediate partnership completed a $85 million
revolving credit facility which replaces a $100 million credit facility.
Borrowings under the new revolving credit facility and the previous credit
facility are and were at variable rates and, as a result, we have interest rate
exposure. Our earnings are not materially affected by changes in interest rates.
If interest rates would have increased by 100 basis points, interest expense for
the year ended December 31, 2003 would have increased by approximately $250,000.
We had no borrowings outstanding under the Credit Facility at December 31, 2003.
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, 2003, and 2002. 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, 2003 2004 2005 2006 2007 2008 THEREAFTER TOTAL 2003
- ----------------------- ---- ---- ---- ---- ---- ---------- ----- ----
Senior Notes fixed rate $ - $18,000 $18,000 $18,000 $18,000 $ 108,000 $ 180,000 $ 204,604
Weighted Average interest rate 8.31% 8.31% 8.31% 8.31% 8.31%
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%
45
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,
2003 and 2002, the related consolidated statements of income, cash flows and
Partners' capital (deficit) for each of the three years in the period ended
December 31, 2003. 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,
2003 and 2002, and the results of their operations and their cash flows for each
of the three years in the period ended December 31, 2003, 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 4 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 12, 2004
46
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2003 AND 2002
(IN THOUSANDS, EXCEPT UNIT DATA)
DECEMBER 31,
-----------------------
2003 2002
--------- ---------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 10,156 $ 9,028
Trade receivables, less allowance of $763 at December 31, 2003 and 2002 38,305 33,018
Marketable securities 23,615 470
Inventories 14,527 13,165
Advance royalties 1,108 5,232
Prepaid expenses and other assets 3,432 2,784
--------- ---------
Total current assets 91,143 63,697
PROPERTY, PLANT AND EQUIPMENT, AT COST 474,357 446,629
LESS ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION (251,567) (216,777)
--------- ---------
222,790 229,852
OTHER ASSETS:
Advance royalties 12,439 10,542
Coal supply agreements, net 5,445 8,167
Other long-term assets 4,637 4,674
--------- ---------
$ 336,454 $ 316,932
========= =========
LIABILITIES AND PARTNERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 22,651 $ 23,330
Due to affiliates 13,546 1,286
Accrued taxes other than income taxes 10,375 8,105
Accrued payroll and related expenses 11,095 10,004
Accrued interest 5,402 5,361
Workers' compensation and pneumoconiosis benefits 5,905 5,275
Other current liabilities 5,739 9,877
Current maturities, long-term debt -- 16,250
--------- ---------
Total current liabilities 74,713 79,488
LONG-TERM LIABILITIES:
Long-term debt, excluding current maturities 180,000 195,000
Pneumoconiosis benefits 17,633 16,067
Workers' compensation 22,819 19,949
Reclamation and mine closing 21,717 21,821
Due to affiliates 3,735 20,652
Other liabilities 3,280 2,717
--------- ---------
Total liabilities 323,897 355,694
COMMITMENTS AND CONTINGENCIES
PARTNERS' CAPITAL (DEFICIT):
Common Unitholders 14,692,527 and 8,982,780 units outstanding, respectively 263,071 144,219
Subordinated Unitholder 3,211,266 and 6,422,531 units outstanding, respectively 58,411 112,916
General Partners (305,034) (290,472)
Unrealized loss on marketable securities (102) (150)
Minimum pension liability (3,789) (5,275)
--------- ---------
Total Partners' capital (deficit) 12,557 (38,762)
--------- ---------
$ 336,454 $ 316,932
========= =========
See notes to consolidated financial statements.
47
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002, AND 2001
(IN THOUSANDS, EXCEPT UNIT AND PER UNIT DATA)
YEAR ENDED DECEMBER 31,
----------------------------------------------
2003 2002 2001
------------ ------------ ------------
SALES AND OPERATING REVENUES:
Coal sales $ 501,596 $ 479,515 $ 453,054
Transportation revenues 19,553 18,992 18,163
Other sales and operating revenues 21,598 20,385 6,233
------------ ------------ ------------
Total revenues 542,747 518,892 477,450
------------ ------------ ------------
EXPENSES:
Operating expenses 368,835 367,567 337,223
Transportation expenses 19,553 18,992 18,163
Outside purchases 8,508 10,077 28,850
General and administrative 28,270 20,337 18,747
Depreciation, depletion and amortization 52,495 52,408 50,696
Interest expense (net of interest income and interest
capitalized of $545, $1,353 and $2,056 for the
Partnership's respective periods) 15,981 16,360 16,772
------------ ------------ ------------
Total operating expenses 493,642 485,741 470,451
------------ ------------ ------------
INCOME FROM OPERATIONS 49,105 33,151 6,999
OTHER INCOME 1,374 540 771
------------ ------------ ------------
INCOME BEFORE INCOME TAXES AND
CUMULATIVE EFFECT OF ACCOUNTING CHANGE 50,479 33,691 7,770
INCOME TAX EXPENSE (BENEFIT) 2,577 (1,094) (836)
------------ ------------ ------------
INCOME BEFORE CUMULATIVE EFFECT OF
ACCOUNTING CHANGE 47,902 34,785 8,606
CUMULATIVE EFFECT OF ACCOUNTING CHANGE - - 7,939
------------ ------------ ------------
NET INCOME $ 47,902 $ 34,785 $ 16,545
============ ============ ============
ALLOCATION OF NET INCOME:
PORTION APPLICABLE TO WARRIOR COAL EARNINGS (LOSS)
PRIOR TO ITS ACQUISITION ON FEBRUARY 14, 2003 $ (666) $ (1,504) $ (555)
PORTION APPLICABLE TO PARTNERS' INTEREST 48,568 36,289 17,100
------------ ------------ ------------
NET INCOME $ 47,902 $ 34,785 $ 16,545
============ ============ ============
GENERAL PARTNERS' INTEREST IN NET INCOME (LOSS) $ 306 $ (778) $ (213)
============ ============ ============
LIMITED PARTNERS' INTEREST IN NET INCOME $ 47,596 $ 35,563 $ 16,758
============ ============ ============
BASIC NET INCOME PER LIMITED PARTNER UNIT $ 2.71 $ 2.31 $ 1.09
============ ============ ============
BASIC NET INCOME PER LIMITED PARTNER UNIT
BEFORE ACCOUNTING CHANGE $ 2.71 $ 2.31 $ 0.58
============ ============ ============
DILUTED NET INCOME PER LIMITED PARTNER UNIT $ 2.62 $ 2.24 $ 1.07
============ ============ ============
DILUTED NET INCOME PER LIMITED PARTNER UNIT BEFORE
ACCOUNTING CHANGE $ 2.62 $ 2.24 $ 0.57
============ ============ ============
PRO FORMA NET INCOME ASSUMING ACCOUNTING CHANGE IS
APPLIED RETROACTIVELY $ 47,902 $ 34,785 $ 8,606
============ ============ ============
WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING - BASIC 17,580,734 15,405,311 15,405,311
============ ============ ============
WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING - DILUTED 18,162,839 15,842,708 15,684,550
============ ============ ============
See notes to consolidated financial statements.
48
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002, AND 2001
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
-----------------------------------
2003 2002 2001
--------- --------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 47,902 $ 34,785 $ 16,545
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 52,495 52,408 50,696
Cumulative effect of accounting change - - (7,939)
Reclamation and mine closings 1,341 1,365 1,175
Coal inventory adjustment to market 687 48 233
Other (353) (1,014) (890)
Changes in operating assets and liabilities:
Trade receivables (5,287) (464) 6,395
Inventories (2,049) (104) (584)
Advance royalties 2,227 (311) (2,589)
Accounts payable (679) (4,144) (37)
Due to affiliates 9,978 14,080 6,447
Accrued taxes other than income taxes 2,270 1,936 1,011
Accrued payroll and related benefits 1,091 1,348 1,322
Accrued pneumoconiosis benefits 1,566 1,452 903
Workers' compensation 3,500 2,568 1,493
Other (4,377) (2,647) (3,716)
--------- --------- ---------
Total net adjustments 62,410 66,521 53,920
--------- --------- ---------
Net cash provided by operating activities 110,312 101,306 70,465
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of property, plant and equipment (43,004) (67,339) (58,661)
Purchase of Warrior Coal (12,661) - -
Proceeds from sale of property, plant and equipment 913 323 233
Purchase of marketable securities (23,091) - (33,527)
Proceeds from the sale of marketable securities - 10,085 60,840
--------- --------- ---------
Net cash used in investing activities (77,843) (56,931) (31,115)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from common unit offering to public 53,927 - -
Cash contribution by General Partners 9 - -
Payments on Warrior Coal revolver (17,000) - -
Borrowings under revolving credit and working capital facilities 31,600 66,400 1,100
Payments under revolving credit and working capital facilities (31,600) (66,400) (1,100)
Payments on long-term debt (31,250) (15,000) (3,750)
Distributions to Partners (37,027) (31,440) (31,440)
--------- --------- ---------
Net cash used in financing activities (31,341) (46,440) (35,190)
--------- --------- ---------
NET CHANGE IN CASH AND CASH EQUIVALENTS 1,128 (2,065) 4,160
CASH AND CASH EQUIVALENTS AT
BEGINNING OF PERIOD 9,028 11,093 6,933
--------- --------- ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 10,156 $ 9,028 $ 11,093
========= ========= =========
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest $ 15,960 $ 17,294 $ 18,162
========= ========= =========
Cash paid to taxing authorities $ 2,681 $ - $ -
========= ========= =========
See notes to consolidated financial statements.
49
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL (DEFICIT)
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002, AND 2001
(IN THOUSANDS, EXCEPT UNIT DATA)
NUMBER OF LIMITED TOTAL
PARTNER UNITS UNREALIZED MINIMUM PARTNERS'
------------------------ GENERAL GAIN PENSION CAPITAL
COMMON SUBORDINATED COMMON SUBORDINATED PARTNERS (LOSS) LIABILITY (DEFICIT)
---------- ------------ --------- ------------ ---------- --------- ---------- ---------
Balance at January 1, 2001 8,982,780 6,422,531 $ 149,642 $ 116,794 $ (298,223) $ - $ - $ (31,787)
Comprehensive income:
Net income (loss) - - 9,772 6,986 (213) - - 16,545
Unrealized loss - - - - - (74) - (74)
Minimum pension liability - - - - - - (814) (814)
---------- ------------ --------- ------------ ---------- --------- ---------- ---------
Total comprehensive income - - 9,772 6,986 (213) (74) (814) 15,657
Capital contribution by
affiliate (Note 3) - - - - 10,000 - - 10,000
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 (289,065) (74) (814) (37,570)
Comprehensive income:
Net income (loss) - - 20,737 14,826 (778) - - 34,785
Unrealized loss - - - - - (76) - (76)
Minimum pension liability - - - - - - (4,461) (4,461)
---------- ------------ --------- ------------ ---------- --------- ---------- ---------
Total comprehensive income - - 20,737 14,826 (778) (76) (4,461) 30,248
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 (290,472) (150) (5,275) (38,762)
Comprehensive income:
Net income - - 31,346 16,250 306 - - 47,902
Unrealized gain - - - - - 48 - 48
Minimum pension liability - - - - - - 1,486 1,486
---------- ------------ --------- ------------ ---------- --------- ---------- ---------
Total comprehensive income - - 31,346 16,250 306 48 1,486 49,436
Issuance of units to public 2,538,000 - 53,927 - - - - 53,927
General Partners contribution - - - - 9 - - 9
Retirement of common units
contributed by Managing
General Partner (39,518) - (890) - 890 - - -
Subordinated units conversion
to common units 3,211,265 (3,211,265) 57,268 (57,268) - - - -
Warrior Coal purchase - - - - (15,026) - - (15,026)
Distribution to Partners - - (22,799) (13,487) (741) - - (37,027)
---------- ------------ --------- ------------ ---------- --------- ---------- ---------
Balance at December 31, 2003 14,692,527 3,211,266 $ 263,071 $ 58,411 $ (305,034) $ (102) $ (3,789) $ 12,557
========== ============ ========= ============ ========== ========= ========= =========
See notes to consolidated financial statements.
50
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002, AND 2001
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), consisting of substantially all of ARH's operating
subsidiaries, but excluding ARH.
The Delaware limited partnerships, 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, Warrior 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 Units 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 of approximately $0.8 million, excluding underwriters
fees. In November 2003, 3,211,265 outstanding Subordinated Units were
converted to Common Units in accordance with the partnership agreement.
On February 14, 2003, the Partnership acquired Warrior Coal, LLC ("Warrior
Coal") (Note 3). Because the Warrior Coal acquisition was between entities
under common control, the acquisition was recorded at historical cost in a
manner similar to that used in a pooling of interests. Accordingly, the
consolidated financial statements and accompanying notes of the
Partnership as of December 31, 2002 and 2001 and for each of the two years
in the period ended December 31, 2002 have been restated to reflect the
combined historical results of operations, financial position and cash
flows of the Partnership and Warrior Coal. ARH Warrior Holdings, Inc.
("ARH Warrior Holdings"), a subsidiary of ARH, acquired Warrior Coal on
January 26, 2001.
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.
51
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, 2003 and 2002 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, 2003. All material intercompany transactions
and accounts of the Partnership have been eliminated.
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,
2003 and 2002, the estimated fair value of long-term debt was
approximately $204.6 million and $228.5 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
$1,257,000 at December 31, 2003, to accounts payable in the consolidated
balance sheets.
MARKETABLE SECURITIES--The Partnership currently classifies all marketable
securities as available-for-sale securities. At December 31, 2003 and
2002, the cost of marketable securities are reported at fair value with
unrealized gains and losses reported as a component of Partners' capital
(deficit) until realized. The Partnership has restricted investments which
are included in other assets in the consolidated balance sheets. The
restricted marketable securities are held in escrow and secure reclamation
bonds (Note 5).
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, 2003 and 2002, 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.
52
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.
On June 2, 2003, the Partnership idled its Hopkins County Coal mining
complex. Hopkins County Coal's two surface mines produced 1.6 million tons
of coal in 2002 and were idled in response to soft market demand. The
Partnership continues to evaluate the recoverability of the appropriate
asset group and has concluded that there is no impairment loss.
ADVANCE ROYALTIES--Rights to coal mineral leases are often acquired and/or
maintained 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.
Extractive industry companies have historically classified leased coal
interests and advance royalties as tangible assets, which is consistent
with the classification of owned coal due to the similar rights of the
leaseholder. Statement of Financial Accounting Standards ("SFAS") No. 141,
Business Combinations, identifies mineral rights as an example of a
contract-based intangible asset that should be considered for separate
classification as the result of a business combination. Due to the
potential for inconsistencies in applying the provisions of SFAS No. 141
(and SFAS No. 142, Goodwill and Other Intangible Assets) in the extractive
industries as they relate to mineral interests controlled by other than
fee ownership, the Emerging Issues Task Force ("EITF") has established a
Mining Industry Working Group that is currently addressing this issue.
Depending on the conclusions reached by the Mining Industry Working Group
and the EITF, the classification of our leased coal interests and advance
royalties in our consolidated balance sheets may be revised.
COAL SUPPLY AGREEMENTS--A portion of the acquisition costs from a business
combination in 1996 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 $33,018,000
and $30,296,000 at December 31, 2003 and 2002, respectively. The aggregate
amortization expense recognized for coal supply agreements was $2,722,000,
$3,864,000 and $4,293,000 for the years ended December 31, 2003, 2002 and
2001, respectively. The estimated aggregate amortization expense for years
2004 and 2005 is approximately $2,723,000 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.
53
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 4).
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.
Prior to the Partnership's acquisition of Warrior Coal, the financial
results of Warrior Coal were subject to federal and state income taxes.
The federal and state income taxes associated with Warrior Coal's
financial results from January 26, 2001, the date of ARH Warrior Holdings'
acquisition of Warrior Coal, to February 14, 2003, the date of the
Partnership's acquisition of Warrior Coal, are included in 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.
COMMON UNIT-BASED COMPENSATION--The Partnership accounts for the
compensation expense of the non-vested restricted common units granted
under the Long-Term Incentive Plan (Note 13) using the intrinsic value
method prescribed in Accounting Principles Board Opinion No. 25,
Accounting for Stock Issued to Employees and the related Financial
Accounting Standards Board 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.
54
Consistent with the disclosure requirements of SFAS No. 148, Accounting
for Stock-Based Compensation Transition and Disclosure, and amendment of
SFAS No. 123, Accounting for Stock-Based Compensation, the following table
provides pro forma results as if the fair value-based method had been
applied to all outstanding and non-vested awards, including Long-Term
Incentive Plan units, in each period presented (in thousands, except per
unit data):
YEAR ENDED DECEMBER 31,
---------------------------------
2003 2002 2001
--------- --------- ---------
Net income, as reported $ 47,902 $ 34,785 $ 16,545
Add: compensation expenses related to
Long-Term Incentive Plan units included in
reported net income 7,687 2,338 1,929
Deduct: compensation expense related to
Long-Term Incentive Plan units determined
under fair value method for all awards (3,632) (2,257) (958)
--------- --------- ---------
Net income, pro forma $ 51,957 $ 34,866 $ 17,516
General partners' interest in net income (loss),
pro forma 386 (777) (194)
--------- --------- ---------
Limited partners' interest in net income, pro forma $ 51,571 $ 35,643 $ 17,710
========= ========= =========
Earnings per limited partner unit:
Basic, as reported $ 2.71 $ 2.31 $ 1.09
Basic, pro forma $ 2.93 $ 2.38 $ 1.16
Diluted, as reported $ 2.62 $ 2.24 $ 1.07
Diluted, pro forma $ 2.84 $ 2.32 $ 1.14
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. Warrior Coal's earnings (loss) prior to the
Partnership's acquisition on February 14, 2003 was allocated entirely to
the general partners. Diluted net income per unit is based on the combined
weighted average number of Common Units, Subordinated Units and common
unit equivalents outstanding (Note 11), which primarily include restricted
units granted under the Long-Term Incentive Plan (Note 13).
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, which meets the aggregation criteria of SFAS No. 131, Disclosures
About Segments of an Enterprise and Related Information. The Partnership
has disclosed major customer sales information (Note 18). The
Partnership's geographic areas of operation are concentrated in the United
States.
NEW ACCOUNTING STANDARDS--On January 1, 2003, the Partnership adopted
Financial Accounting Standards Board Interpretation No. 45, Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others ("FIN No. 45"). This interpretation
elaborates on the disclosures to be made by a guarantor in its financial
statements about its
55
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. This interpretation had no material effect on the Partnership's
consolidated financial statements upon adoption.
3. WARRIOR COAL ACQUISITION
On February 14, 2003, Warrior Coal was acquired from an affiliate, 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.
The Put/Call Agreement preserved the opportunity for the Partnership to
acquire Warrior Coal during a specified time period. 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 the date of the acquisition and at 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. 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 have contributed to
improved productivity and significantly increased capacity. The
Partnership funded the Warrior Coal acquisition through a portion of the
proceeds received from the
56
issuance of 2,250,000 Common Units (Note 1). Because the Warrior Coal
acquisition was between entities under common control, it has been
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 (Note
16).
4. 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 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).
5. MARKETABLE SECURITIES
At December 31, 2003 and 2002, the cost of the certificates of deposit and
U.S. Treasury securities approximated fair value and no effect of
unrealized gains (losses) is reflected in Partners' capital (deficit). The
equity securities had a cumulative unrealized loss reflected in Partners'
capital (deficit) of $102,000 and $150,000 at December 31, 2003 and 2002,
respectively.
Marketable securities consist of the following at December 31, (in
thousands):
2003 2002
--------- ---------
Certificates of deposit (maturing April 4, 2004) $ 23,091 $ -
Equity securities 524 470
--------- ---------
Total unrestricted marketable securities $ 23,615 $ 470
========= =========
Cash and cash equivalents $ 1,809 $ 821
U.S. Treasury securities - 963
--------- ---------
Total restricted marketable securities $ 1,809 $ 1,784
========= =========
57
6. INVENTORIES
Inventories consist of the following at December 31, (in thousands):
2003 2002
--------- ---------
Coal $ 6,186 $ 4,436
Supplies 8,341 8,729
--------- ---------
$ 14,527 $ 13,165
========= =========
7. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consists of the following at December 31,
(in thousands):
2003 2002
--------- ---------
Mining equipment and processing facilities $ 411,070 $ 367,396
Land and mineral rights 20,705 18,453
Buildings, office equipment and improvements 36,786 35,428
Construction in progress 5,796 25,352
--------- ---------
474,357 446,629
Less accumulated depreciation, depletion and amortization (251,567) (216,777)
--------- ---------
$ 222,790 $ 229,852
========= =========
8. LONG-TERM DEBT
Long-term debt consists of the following at December 31, (in thousands):
2003 2002
--------- ---------
Senior notes $ 180,000 $ 180,000
Term loan through credit facility - 31,250
--------- ---------
180,000 211,250
Less current maturities - (16,250)
--------- ---------
$ 180,000 $ 195,000
========= =========
The Intermediate Partnership has $180 million principal amount of 8.31%
senior notes due August 20, 2014, payable in ten equal annual installments
of $18 million beginning in August 2005 with interest payable
semiannually. On August 22, 2003, the Intermediate Partnership completed a
new $85 million revolving credit facility which expires September 30,
2006. The new revolving credit facility replaced a $100 million credit
facility that would have expired August 2004. The Partnership paid in full
all amounts outstanding under the original credit facility with borrowings
of $20 million under the new revolving credit agreement. The interest rate
on the new revolving credit facility is based on either the (i) London
Interbank Offered Rate or (ii) the "Base Rate," which is equal to the
greater of the JPMorgan Chase Prime Rate or the Federal Funds Rate plus
1/2 of 1%, plus, in either case, an applicable margin. The Partnership
incurred certain costs aggregating $1.2 million associated with the new
revolving credit facility. These costs have been deferred and are being
amortized as a component of interest expense over the term of the
revolving credit facility. The Partnership had no borrowings outstanding
under the
58
revolving credit facility at December 31, 2003. Letters of credit can be
issued under the revolving credit facility not to exceed $30 million;
outstanding letters of credit reduce amounts available under the revolving
credit facility. At December 31, 2003, the Partnership had letters of
credit of $9.0 million outstanding under the revolving credit facility to
secure the Partnership's obligations for reclamation liabilities and
workers' compensation benefits.
The senior notes and revolving credit facility are guaranteed by all of
the subsidiaries of the Intermediate Partnership. The senior notes and
revolving credit facility contain various restrictive and affirmative
covenants, including the amount of distributions by the Intermediate
Partnership and the incurrence of other debt. The Partnership was in
compliance with the covenants of both the revolving credit facility and
senior notes at December 31, 2003.
The Partnership previously entered into and has maintained agreements with
two banks to provide additional letters of credit in an aggregate amount
of $25.0 million to maintain surety bonds to secure its obligations for
reclamation liabilities and workers' compensation benefits. At December
31, 2003, the Partnership had $15.6 million in letters of credit
outstanding under these agreements. The Special GP guarantees the letters
of credit (Note 16).
Aggregate maturities of long-term debt are payable as follows (in
thousands):
YEAR ENDING
December 31,
- ------------
2004 $ -
2005 18,000
2006 18,000
2007 18,000
2008 18,000
Thereafter 108,000
----------
$ 180,000
==========
9. DISTRIBUTIONS OF AVAILABLE CASH AND CONVERSION OF SUBORDINATED UNITS
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).
The Partnership satisfied the early conversion financial test for
converting one-half of the Subordinated Units into Common Units as
provided for under applicable provisions in the Partnership Agreement. On
October 24, 2003, the Board of Directors (and its Conflicts Committee) of
the Managing GP approved management's determination that such early
conversion financial test was satisfied. As a result, one-half
59
of the outstanding Subordinated Units (i.e., 3,211,265 Subordinated Units)
held by the Special GP converted into Common Units on November 15, 2003.
The remaining 3,211,266 Subordinated Units are expected to convert on a
one-for-one basis into Common Units in the fourth quarter of 2004,
assuming the Partnership continues to meet the financial test requirements
of the Partnership Agreement.
If quarterly distributions of available cash exceed the MQD and target
distributions levels as established in the Partnership Agreement, the
Managing GP will receive distributions based on specified increasing
percentages of the available cash that exceed the MQD and the 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 the MQD and common unit
arrearages, if any. No incentive distributions to the Managing GP have
been made through December 31, 2003.
For each of the quarters ended December 31, 2000 through September 30,
2002, quarterly distributions of $0.50 per unit were paid to the common
and subordinated unitholders. For each of the quarters ended December 31,
2002 through September 30, 2003, quarterly distributions of $0.525 per
unit were paid to the common and subordinated unitholders. On January 26,
2004, the Partnership declared a quarterly distribution, for the period
from October 1, 2003 to December 31, 2003, of $0.5625 per unit, totaling
approximately $10,311,000, payable on February 13, 2004 to all unitholders
of record on February 5, 2004.
10. 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, 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. Prior to the Partnership's
acquisition of Warrior Coal, the financial results of Warrior Coal were
subject to federal and state income taxes. The federal and state income
taxes associated with Warrior Coal's financial results from January 26,
2001, the date ARH Warrior Holdings acquired the assets that comprise
Warrior Coal, to February 14, 2003, the date the Partnership acquired
Warrior Coal, are included in income taxes. Components of income tax
expense (benefit) are as follows (in thousands):
YEAR ENDED DECEMBER 31,
-----------------------------------
2003 2002 2001
--------- --------- ---------
Current:
Federal $ 1,516 $ 310 $ 528
State 431 45 75
--------- --------- ---------
1,947 355 603
Deferred:
Federal 550 (1,269) (1,256)
State 80 (180) (183)
--------- --------- ---------
630 (1,449) (1,439)
--------- --------- ---------
Income tax expense (benefit) $ 2,577 $ (1,094) $ (836)
========= ========= =========
60
Reconciliations from the provision for income taxes at the U.S. federal
statutory rate to the effective tax rate for the provision for income taxes are
as follows (in thousands):
YEAR ENDED DECEMBER 31,
-----------------------------------
2003 2002 2001
--------- --------- ---------
Income taxes at statutory rate $ 17,668 $ 11,792 $ 2,719
Less: Income taxes at statutory rate on
Partnership income not subject to income taxes (15,855) (12,606) (3,206)
Increase/(decrease) resulting from:
Depletion - (114) (232)
State taxes, net of federal income tax benefit 313 (136) (107)
Deferred tax assets retained by
ARH Warrior Holdings 413 - -
Other 38 (30) (10)
--------- --------- ---------
Income tax expense (benefit) $ 2,577 $ (1,094) $ (836)
========= ========= =========
The tax effects of significant items comprising Warrior Coal's net deferred tax
asset included in other long-term assets on the consolidated balance sheet at
December 31, 2002 is as follows (in thousands):
Deferred tax assets:
Accrued reclamation and mine closing $ 1,259
Accrued expenses not currently deductible 308
Other 275
--------
Deferred tax asset 1,842
Deferred tax liabilities:
Differences between book and tax basis of property 1,055
Other 157
-------
Deferred tax liability 1,212
--------
Net deferred tax asset $ 630
========
61
11. 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,
-----------------------------------
2003 2002 2001
--------- --------- ---------
Net income per limited partner unit $ 47,596 $ 35,563 $ 16,758
Weighted average limited partner units - basic 17,581 15,405 15,405
Basic net income per limited partner unit $ 2.71 $ 2.31 $ 1.09
========= ========= =========
Basic net income per limited partner unit
before accounting change $ 2.71 $ 2.31 $ 0.58
========= ========= =========
Weighted average limited partner units - basic 17,581 15,405 15,405
Units contingently issuable:
Restricted units for Long-Term Incentive Plan 527 390 263
Directors' compensation units deferred 16 13 9
Supplemental Executive Retirement Plan 39 35 8
--------- --------- ---------
Weighted average limited partner units, assuming
dilutive effect of restricted units 18,163 15,843 15,685
--------- --------- ---------
Diluted net income per limited partner unit $ 2.62 $ 2.24 $ 1.07
========= ========= =========
Diluted net income per limited partner unit before
accounting change $ 2.62 $ 2.24 $ 0.57
========= ========= =========
12. EMPLOYEE BENEFIT PLANS
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 matching contributions based on a percent of an employee's eligible
compensation and for certain subsidiaries makes an additional nonmatching
contribution also based on an employee's eligible 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
$2,975,000, $2,959,000 and $2,795,000 for the years ended December 31,
2003, 2002 and 2001, respectively.
DEFINED BENEFIT PLANS--Certain employees at the mining operations
participate in a defined benefit plan (the "Pension Plan") sponsored by
the Partnership. The benefit formula is a fixed dollar unit based on years
of service.
62
The following sets forth changes in benefit obligations and plan assets
for the years ended December 31, 2003 and 2002 and the funded status of
the Pension Plan reconciled with amounts reported in the Partnership's
consolidated financial statements at December 31, 2003 and 2002,
respectively (dollars in thousands):
2003 2002
--------- ---------
CHANGE IN BENEFIT OBLIGATIONS:
Benefit obligations at beginning of year $ 18,077 $ 13,202
Service cost 2,502 2,249
Interest cost 1,215 952
Actuarial loss 1,367 1,817
Benefits paid (213) (143)
--------- ---------
Benefit obligation at end of year 22,948 18,077
--------- ---------
CHANGE IN PLAN ASSETS:
Fair value of plan assets at beginning of year 12,432 10,508
Employer contribution 5,397 3,661
Actual return (loss) on plan assets 3,569 (1,594)
Benefits paid (213) (143)
--------- ---------
Fair value of plan assets at end of year 21,185 12,432
--------- ---------
Funded status (1,763) (5,645)
Unrecognized prior service cost 139 187
Unrecognized actuarial loss 3,789 5,275
--------- ---------
Net amount recognized $ 2,165 $ (183)
========= =========
AMOUNTS RECOGNIZED IN STATEMENT OF FINANCIAL POSITION:
Accrued benefit liability $ (1,763) $ (5,645)
Intangible asset 139 187
Accumulated other comprehensive income 3,789 5,275
--------- ---------
Net amount recognized $ 2,165 $ (183)
========= =========
WEIGHTED-AVERAGE ASSUMPTIONS AS OF DECEMBER 31:
Discount rate 6.25% 6.75%
WEIGHTED-AVERAGE ASSUMPTIONS USED TO DETERMINE NET
PERIODIC BENEFIT COST FOR THE YEAR ENDED DECEMBER 31:
Discount rate 6.75% 7.25%
Expected return on plan assets 8.00% 9.00%
WEIGHTED-AVERAGE ASSET ALLOCATIONS AS OF DECEMBER 31:
Equity securities 86% 85%
Fixed income securities 13% 13%
Cash and cash equivalents 1% 2%
--------- ---------
100% 100%
========= =========
(Continued)
63
2003 2002 2001
--------- --------- ---------
COMPONENTS OF NET PERIODIC BENEFIT COST:
Service cost $ 2,502 $ 2,249 $ 2,050
Interest cost 1,215 952 755
Expected return on plan assets (1,115) (1,050) (888)
Prior service cost 48 48 48
Net loss 399 - -
--------- --------- ---------
Net periodic benefit cost $ 3,049 $ 2,199 $ 1,965
========= ========= =========
Effect on minimum pension liability $ (1,486) $ 4,461 $ 814
========= ========= =========
Concluded
The Partnership expects to contribute $3,300,000 to the Pension Plan in
2004.
The Compensation Committee ("Compensation Committee") of the Board of
Directors of the Managing GP maintains a Funding and Investment Policy
Statement ("Policy Statement") for the Pension Plan. The Policy Statement
provides that the assets of the Pension Plan be invested in a diversified
mix of domestic equity securities and international equity securities,
domestic fixed income securities and cash equivalents with the goal of
ensuring that the Pension Plan assets provide sufficient resources to meet
or exceed benefit obligations. Investment options, which may be through
mutual funds, collective funds, or direct investment in individual stock,
bonds or cash equivalent investments, include (a) money market accounts,
(b) U.S. Government bonds, (c) corporate bonds, (d) large, mid, and small
capitalization stocks, and (e) international stocks. The Policy Statement
imposes the following limitations, subject to exceptions authorized by the
Compensation Committee under unusual market conditions: (a) the maximum
investment in any one stock should not exceed 10% of the total stock
portfolio, the maximum investment in any one industry should not exceed
30% of the total stock portfolio, the average credit quality of the bond
portfolio should be at least AA with a maximum amount of non-investment
grade debt of 10%. The Policy Statement's current asset allocation
guidelines are as follows:
PERCENTAGE OF TOTAL PORTFOLIO
-----------------------------
MINIMUM TARGET MAXIMUM
------- ------ -------
Domestic stocks 50% 70% 90%
Foreign stocks 0% 10% 20%
Fixed income/cash 5% 20% 40%
The expected long-term rate of return assumption is developed based on
input from an independent investment manager, including their review of
asset class return, expectations by economists, and an independent
actuary. The Partnership's advisors base the projected returns on broad
equity and bond indices. The Pension Plan's expected long-term rate of
return is based on an asset allocation assumption of 80.0% with equity
manager, with an expected long-term rate of return of 10.2%, and 20.0%
with fixed income managers, with an expected long-term rate of return of
5.4%. The Pension Plan was established effective January 1, 1997 and the
Partnership's initial contribution to the Pension Plan was in 1998.
64
13. RESTRICTED UNIT-BASED COMPENSATION
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, 2004, the Compensation Committee approved an
amendment to the LTIP clarifying that if an award is paid or settled in
cash rather than through the delivery of units, then the units granted by
such award shall be "reloaded" with respect to which options and
restricted units may be granted under the LTIP in the future. The
Compensation Committee additionally authorized the cash settlement of at
least 40% of all awards under the LTIP that will vest at the end of the
subordination period which will be no earlier than November 2004. During
2003 the Compensation Committee approved grants of 141,205 restricted
units, which will vest September 30, 2005, subject to certain financial
tests. During 2002 and 2001, the Compensation Committee approved grants of
133,885 and 129,200 restricted units, respectively, which vest at the end
of the subordination period (Note 9). As of December 31, 2003, 18,125
restricted units have been forfeited. During 2003, 2002 and 2001, the
Managing GP billed the Partnership approximately $7,687,000, $2,338,000
and $1,929,000, respectively, attributable to the LTIP. Effective January
1, 2004, the Compensation Committee approved additional grants of 103,425
restricted units, which will vest December 31, 2006, subject to certain
financial tests.
14. 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 discount rates ranging from 4.25% to 6.0%.
On January 1, 2003, the Partnership adopted 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. Since the Partnership has historically adhered to
accounting principles similar to SFAS No. 143, this standard had no
material effect on the Partnership's consolidated financial statements
upon adoption.
65
Discounting resulted in reducing the accrual for reclamation and mine
closing costs by $10,332,000 and $10,510,000 at December 31, 2003 and
2002, respectively. Estimated payments of reclamation and mine closing
costs as of December 31, 2003 are as follows (in thousands):
YEAR ENDING
DECEMBER 31,
- ------------
2004 $ 1,749
2005 2,410
2006 3,189
2007 3,288
2008 4,959
Thereafter 18,203
---------
Aggregate undiscounted reclamation and mine closing 33,798
Effect of discounting 10,332
---------
Total reclamation and mine closing costs 23,466
Less current portion (1,749)
---------
Reclamation and mine closing costs $ 21,717
=========
The following table presents the activity affecting the reclamation and mine
closing liability (in thousands):
YEAR ENDED DECEMBER 31,
-----------------------------------
2003 2002 2001
--------- --------- ---------
Beginning balance $ 23,456 $ 20,518 $ 16,018
Accretion expense 1,341 1,365 1,175
Payments (1,054) (865) (571)
Allocation of liability associated with
acquisition, mine development and
change in assumptions (277) 2,438 3,896
--------- --------- ---------
Ending balance $ 23,466 $ 23,456 $ 20,518
========= ========= =========
15. PNEUMOCONIOSIS ("BLACK LUNG") BENEFITS
Certain mine operating entities of the Partnership are liable under state
statutes and the Federal Coal Mine Health and Safety Act of 1969, as
amended, to pay black lung benefits to eligible employees and former
employees and their dependents.
The Partnership changed its method of estimating black lung benefits
liability effective January 1, 2001 to the service cost method (Note 4).
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 4.7% and 5.5% at December 31, 2003 and 2002, respectively.
66
The reconciliation of changes in benefit obligations at December 31, 2003
and 2002 is as follows (in thousands):
2003 2002
--------- ---------
Benefit obligations at beginning of year $ 16,067 $ 14,615
Service cost 947 783
Interest cost 978 811
Actuarial loss 65 45
Benefits and expenses paid (424) (187)
--------- ---------
Benefit obligations at end of year $ 17,633 $ 16,067
========= =========
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.
16. 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
(including the LTIP), 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 $12,471,000, $6,559,000 and $6,503,000 for the years ended
December 31, 2003, 2002 and 2001, respectively. The increase from 2002 to
2003 was primarily attributable to higher accruals related to Common
Unit-based incentive programs, which were impacted by the increased market
value of the Partnership's Common Units, and a Short-Term Incentive Plan.
SGP LAND--Webster County Coal, LLC ("Webster County Coal") 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.
Webster County Coal paid royalties of $3,460,000 for the year ended
December 31, 2003 and $2.7 million during each of the two years in the
period ended December 31, 2002. Webster County Coal has recouped as earned
royalties all advance minimum royalty payments made under these lease
terms as of December 31, 2003.
Warrior Coal has a mineral lease and sublease with SGP Land. Under the
terms of the lease, Warrior Coal has paid and will continue to pay in
arrears an annual minimum royalty obligation of $2,270,000 until
$15,890,000 of cumulative annual minimum and/or earned royalty payments
have been paid. The annual minimum royalty periods are from October 1
through the end of the following September 30, expiring September 30,
2007. Warrior Coal paid royalties of $2,453,000, $2,127,000 and $2,838,000
for the years ended December 31, 2003, 2002 and 2001, respectively.
Warrior Coal has recouped as earned royalties all advance minimum royalty
payments made in accordance with these lease terms except for $1,230,000
as of December 31, 2003.
67
Under the terms of the mineral lease and sublease agreements described
above, Webster County Coal and Warrior Coal also reimburse SGP Land for
SGP Land's base lease obligations. The Partnership reimbursed SGP Land
$4,395,000, $3,922,000 and $2,347,000 for the years ended December 31,
2003, 2002 and 2001, respectively, for the base lease obligations. Webster
County Coal and Warrior Coal have recouped as earned royalties all advance
minimum royalty payments made in accordance with these terms except for
$320,000 as of December 31, 2003.
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 $479,000, $568,000 and
$705,000 for the years ended December 31, 2003, 2002 and 2001,
respectively. MC Mining has recouped as earned royalties all advance
minimum royalty payments made under these lease terms as of December 31,
2003.
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 2003 option fee of
$684,000 was paid in January 2004 and is included in the due to affiliates
balance as of December 31, 2003. The anticipated annual minimum royalty
obligation is $684,000, payable in advance through 2009.
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, 2003 was
$2,595,000.
The Partnership previously entered into and has maintained agreements with
two banks to provide letters of credit in an aggregate amount of $25.0
million (Note 8). At December 31, 2003, the Partnership had $15.6 million
in outstanding letters of credit. The Special GP guarantees these letters
of credit. Historically, the Partnership has compensated the Special GP
for a guarantee fee equal to 0.30% per annum of the face amount of the
letters of credit outstanding. The Special GP agreed to waive the
guarantee fee in exchange for a parent guarantee from the Intermediate
Partnership and Alliance Coal, LLC on the mineral lease and sublease with
Webster County Coal and Warrior Coal described above. Since the guarantee
is made on behalf of entities within the consolidated partnership, the
guarantee has no fair value under FIN No. 45 and does not impact the
consolidated financial statements. The Partnership paid approximately
$31,300, $48,200 and $8,800 in guarantee fees to the Special GP for the
years ended December 31, 2003, 2002 and 2001, respectively.
68
17. 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 16). Future minimum lease payments under
operating leases are as follows (in thousands):
YEAR ENDING
DECEMBER 31, AFFILIATE OTHERS TOTAL
- ------------ --------- --------- ---------
2004 $ 2,595 $ 2,068 $ 4,663
2005 2,595 2,071 4,666
2006 2,595 1,650 4,245
2007 2,595 819 3,414
2008 2,595 264 2,859
Thereafter 5,405 13 5,418
--------- --------- ---------
$ 18,380 $ 6,885 $ 25,265
========= ========= =========
Lease expense under all operating leases was $5,490,000, $4,707,000 and
$4,740,000 for the years ended December 31, 2003, 2002 and 2001,
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. The Partnership entered into nine operating leases during
2003 under the master equipment lease with lease terms ranging from three
to six years.
CONTRACTUAL COMMITMENTS--The Partnership had contractual commitments of
approximately $7.7 million at December 31, 2003.
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. Although the ultimate outcome of these matters cannot be
predicted with certainty, in the opinion of management, the outcome of
these matters, to the extent not previously provided for or covered under
insurance, are not expected to have a material adverse effect on the
Partnership's business, financial position or results of operations.
Nonetheless, these matters or estimates that are based on current facts
and circumstances, if resolved in a manner different from the basis on
which management has formed its opinion, could have a material adverse
effect on the Partnership's financial position or results of operations.
OTHER--During September 2003, the Partnership completed its annual
property and casualty insurance renewal. Recent insurance carrier losses
worldwide have created a tightening market reducing available capacity for
underwriting property insurance. As a result, the Partnership and its
affiliates retained a 10.0% participating interest along with its
insurance carriers in the commercial property program. The aggregate
maximum limit in the commercial property program is $75 million per
occurrence of which the Partnership would be responsible for a maximum
limit of $7.5 million for each occurrence, excluding a $3.5 million
deductible.
69
On October 15, 2003, the West Virginia Department of Environmental
Protection ("WVDEP") issued a letter denying Mettiki Coal (WV), LLC's, one
of the Partnership's subsidiaries, application for an underground mining
permit for its proposed E-Mine. The E-Mine is a proposed longwall
underground mine to be located primarily in Tucker County, West Virginia.
The stated basis of WVDEP's denial was its belief that Mettiki Coal (WV)'s
proposed E-Mine would result in the movement of acid mine drainage outside
the permit area from the post-mining mine pool, which would require
long-term chemical treatment without a defined "end-point." WVDEP takes
the position that the applicable surface mining laws require reclamation
of land and water resources, and that treatment for a period without a
defined end-point is not an acceptable reclamation alternative. However,
WVDEP previously issued a permit to Island Creek Coal Company to mine the
same general reserve area without expressing such concerns. On November
14, 2003, Mettiki Coal (WV) appealed that decision to the West Virginia
Surface Mine Board ("Surface Mine Board"). The appeal of the denial of
this permit application is scheduled currently to be heard by the Surface
Mine Board on April 6, 2004.
In order to expedite the WVDEP's consideration of additional information
that we believe addresses WVDEP's basis for denial of the original permit
application, Mettiki Coal (WV) prepared and submitted a new permit
application on January 15, 2004. The new permit application addresses,
among other issues, the stated concern for long-term material damage to
the hydrologic balance outside the permit area by adding an alkaline
recharge component to the hydrologic reclamation plan.
On January 22, 2004, the WVDEP notified Mettiki Coal (WV) that the new
permit application was determined to be administratively complete. On
February 6, 2004, the WVDEP notified Mettiki Coal (WV) of certain
technical corrections that must be responded to before the new permit
application review can be completed. Mettiki Coal (WV) submitted technical
corrections to the WVDEP on February 17, 2004. WVDEP's determination on
the new permit application is expected within 30 days of an informal
public conference to be held by the WVDEP on March 23, 2004.
In the event that WVDEP denies the new permit application, Mettiki Coal
(WV) anticipates that it will vigorously pursue the appeal of the denial
of the new mining permit application to the Surface Mine Board. The
Surface Mine Board, a seven-member board, typically hears cases within
several months after appeals are filed and rarely waits more than several
weeks after hearing a case to render a final decision. Mettiki Coal (WV)
has approximately $1.5 million of advance minimum royalties associated
with the E-Mine reserves, which management believes are fully recoverable.
In August 2003, the Partnership resolved 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 the Gibson County
Coal mining complex. At that time, Gibson County Coal and PSI concluded a
definitive settlement agreement that was consistent with a tentative
settlement reached during mediation procedures that occurred in August
2002. As part of the settlement, the Partnership agreed with PSI to
exchange mutual releases of any and all claims related to the contract
dispute. The Partnership's previously recorded accruals of approximately
$800,000 relating to the dispute were consistent with the terms of the
executed settlement agreement and certain other agreements.
70
18. 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 (Customer D comprised less
than four and two percent of total revenues in 2003 and 2002,
respectively) are as follows (in thousands):
YEAR ENDED DECEMBER 31,
-----------------------------------
2003 2002 2001
--------- --------- ---------
Customer A $ 116,750 $ 113,094 $ 540
Customer B 78,724 72,224 63,241
Customer C 52,561 69,933 74,091
Customer D 21,382 5,415 59,279
Trade accounts receivable from these customers totaled approximately $17.2
million at December 31, 2003. The Partnership's bad debt experience has
historically been insignificant, however the Partnership established an
allowance of $763,000 during 2001, due to the Partnership's total credit
exposure to Enron Corp., which filed for bankruptcy protection during
December 2001. Financial conditions of its customers could result in a
material change to this estimate in future periods. The coal supply
agreements with Customers A, B, C and D expire in 2007, 2006, 2010 and
2023, respectively.
19. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
A summary of the quarterly operating results for the Partnership is as
follows (in thousands, except unit and per unit data):
QUARTER ENDED
-----------------------------------------------------------
MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31,
2003 2003 2003 2003 (1)
----------- ----------- ------------- ------------
Revenues $ 124,925 $ 133,471 $ 141,799 $ 142,552
Operating income 18,057 12,781 15,210 19,038
Income before income taxes 14,083 9,248 11,466 15,682
Net income 13,128 8,528 10,803 15,443
Basic net income per limited partner unit $ 0.81 $ 0.47 $ 0.59 $ 0.85
Diluted net income per limited
partner unit $ 0.79 $ 0.45 $ 0.57 $ 0.82
Weighted average number of units
outstanding - basic 16,593,609 17,903,793 17,903,793 17,903,793
Weighted average number of units
outstanding - diluted 17,176,824 18,485,741 18,487,787 18,486,098
71
QUARTER ENDED
-----------------------------------------------------------
MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31,
2002 2002 2002 2002
----------- ----------- ------------- ------------
Revenues $ 125,388 $ 126,828 $ 132,780 $ 133,896
Operating income 15,038 17,660 7,976 8,837
Income before income taxes 11,553 13,836 3,556 4,746
Net income 11,400 14,012 4,126 5,247
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
Operating income in the above table represents income from operations
before interest expense.
(1) The Partnership's quarterly revenue was impacted by a contractual
modification that resulted in a $2.0 million favorable pricing
adjustment associated with coal feedstock sales to Synfuel Solutions
Operating LLC for shipments made primarily in 2003 but prior to the
fourth quarter of 2003. Additionally, operating expenses decreased
due to the reversal of an expense accrual of $1.2 million established
in 1998. The expense accrual was established in conjunction with the
idling of Pontiki in 1998 that created an expectation of a probable
increase in workers' compensation costs associated with the
terminated workforce. The expected anticipated increase in workers'
compensation claims did not emerge and, with limited exceptions, the
statute of limitations expired in December 2003 for the filing or
reopening of workers' compensation claims associated with the
employee terminations.
20. SUBSEQUENT EVENT
On February 11, 2004, Webster County Coal's Dotiki mine was temporarily
idled following the occurrence of a mine fire. Dotiki has successfully
extinguished the fire and has totally isolated the affected area of the
mine behind permanent seals. Production resumed on March 8, 2004. At this
time, the Partnership is unable to quantify the financial impact of the
fire or to predict when Dotiki will return to normal production. The
temporary idling of Dotiki will reduce earnings for the first quarter of
2004. The Partnership does have commercial property insurance (including
business interruption coverage) that the Partnership currently believes
will cover a substantial portion of the financial loss. Assuming that is
correct, Dotiki's recognized losses in the first quarter of 2004 should be
substantially offset by an insurance settlement that would be recognized
later in the year. There can be no assurance of the amount or timing of
recovery, however, until the claim is resolved with the insurance
underwriter. The Partnership's insurance program provides for a deductible
of $3.5 million and a ten percent coinsurance. In addition to the losses
associated with business interruption, the Partnership has currently
identified approximately $6.0 million of out-of-pocket expenses that
generally fall into the category of extra expenses, expedited expenses and
other areas of coverage under the commercial property insurance policy.
The Partnership expects that additional out-of-pocket costs will be
identified in the future.
******
72
SCHEDULE II
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 2003, 2002, AND 2001
BALANCE AT ADDITIONS
BEGINNING CHARGED TO BALANCE AT
OF YEAR INCOME DEDUCTIONS END OF YEAR
------- ------ ---------- -----------
(in thousands)
2003
Allowance for doubtful accounts $ 763 $ - $ - $ 763
========== ========= ========== ==========
2002
Allowance for doubtful accounts $ 763 $ - $ - $ 763
========== ========= ========== ==========
2001
Allowance for doubtful accounts $ - $ 763 $ - $ 763
========== ========= ========== ==========
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.
73
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
An evaluation was carried out by management, including our chief executive
officer and chief financial officer, of the effectiveness of the design and
operation of our disclosure controls and procedures (as defined in Rule
13a-15(e) and Rule 15d-15(e) under the Securities Exchange Act of 1934). Based
upon this evaluation, the chief executive officer and the chief financial
officer concluded that the design and operation of these disclosure controls and
procedures were effective as of the end of the period covered by this report.
During the quarterly period ended December 31, 2003, there have not been any
changes in our internal control over financial reporting (as defined in Rule
13a-15(f) under the Securities Exchange Act of 1934) identified in connection
with this evaluation that have materially affected, or are reasonably likely to
materially affect, our internal control over financial reporting.
Each of the chief executive officer and the chief financial officer of our
managing general partner has furnished as Exhibit 32.1 and Exhibit 32.2,
respectively, a certificate to the Securities and Exchange Commission as
required by Section 906 of the Sarbanes-Oxley Act of 2002.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS 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 our 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 53 President, Chief Executive Officer and Director
Robert G. Sachse 55 Executive Vice President and Vice Chairman of the Board
Thomas L. Pearson 50 Senior Vice President - Law and Administration,
General Counsel and Secretary
Charles R. Wesley 49 Senior Vice President - Operations
Brian L. Cantrell 44 Senior Vice President - Chief Financial Officer
Gary J. Rathburn 53 Senior Vice President - Marketing
Michael J. Hall 59 Director and Member of the Audit* and Conflicts
Committees
John J. MacWilliams 48 Director
74
Preston R. Miller, Jr. 55 Director and Member of the Compensation* Committee
John P. Neafsey 64 Chairman of the Board and Member of Audit, Compensation
and Conflicts
Committees
John H. Robinson 53 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 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. Following the merger, Mr. Sachse had a two
year non-compete consulting agreement with The Williams Companies. Mr. Sachse
held various positions while 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 in Business Administration 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.
Brian L. Cantrell was named Senior Vice President and Chief Financial
Officer in October 2003. Prior to his current position, Mr. Cantrell was
President of AFN Communications, LLC from November 2001 to October 2003 where he
had previously served as Executive Vice President and Chief Financial Officer
after joining AFN in September 2000. Mr. Cantrell's previous positions include
Chief Financial Officer, Treasurer
75
and Director with Brighton Energy, LLC from August 1997 to September 2000; Vice
President - Finance of KCS Medallion Resources, Inc.; and Vice President -
Finance, Secretary and Treasurer of Intercoast Oil and Gas Company. Mr. Cantrell
is a Certified Public Accountant and holds a Master of Accountancy and Bachelor
of Accountancy from the University of Oklahoma.
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, Secretary and Treasurer of Matrix Service
Company (Matrix) and serves on its Board of Directors. He assumed these
positions when he joined Matrix in September 1998. Matrix is a company which
provides general industrial construction and repair and maintenance services
principally to the petroleum, petrochemical, power, bulk storage terminal,
pipeline and industrial gas industries. Mr. Hall is responsible for all
financial and administrative functions including accounting, financial
reporting, auditing, finance, budgeting, tax, risk management, investor
relations, human resources and information technology. Effective May 31, 2004,
Mr. Hall will retire from his position of Vice President - Finance and Chief
Financial Officer and will continue to serve on the Board of Directors of Matrix
Service Company. 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, is a Partner of The Tremont Group, LLC, a private
equity investment firm founded in January 2003, located in Newton, MA., which
has specialized expertise in the energy industry. Mr. MacWilliams is also a
General Partner of The Beacon Group, LP, that he joined in 1993, and has served
as a Director since June 1996. As part of the Beacon Group, he co-manages two
private equity funds focusing on the energy industry. 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 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., is a Partner of The Tremont Group, LLC, a private
equity investment firm founded in January 2003, located in Newton, MA., which
has a specialized expertise in the energy industry. Mr. Miller is a General
Partner of The Beacon Group, LP that he joined in 1993 and has served as a
Director since June 1996. As a part of The Beacon Group, he co-manages two
private equity funds focusing on the energy industry. Mr. Miller's previous
positions include serving as a General Partner of JP Morgan Partners from June
2000 through December 2002, and was with Goldman Sachs & Co.'s from January 1979
through January 1993, most recently as Vice President in the Structured Finance
Group in New York City where he had global responsibility for coverage of the
independent power industry, asset-backed power generation, and
76
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 the
compensation committee.
John P. Neafsey has served as Chairman since June 1996. Mr. Neafsey is
President of JN Associates, an investment consulting firm formed in 1993. 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 Constar, 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
President and Chief Operating Officer 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
chairman of the conflicts committee and a member of the audit and compensation
committees.
AUDIT COMMITTEE
The audit committee is comprised of three non-employee members of the board
of directors (currently, Mr. Hall, Mr. Neafsey and Mr. Robinson). After
reviewing the qualifications of the current members of the audit committee, and
any relationships they may have with us that might affect their independence,
the board of directors has determined that all current audit committee members
are "independent" as that concept is defined in Section 10A of the Exchange Act,
all current audit committee members are "independent" as that concept is defined
in the applicable rules of the NASDAQ, all current audit committee members are
financially literate, and Mr. Hall and Mr. Neafsey qualify as audit committee
financial experts under the applicable rules promulgated pursuant to the
Exchange Act.
Report of the Audit Committee
The audit committee of Alliance Resource Management GP, LLC, oversees our
Partnership's financial reporting process on behalf of the board of directors.
Management has the primary responsibility for the financial statements and the
reporting process including the systems of internal controls. The audit
committee has the responsibility for the appointment, compensation and oversight
of the work of our independent accountants and will assist the board of
directors by conducting its own review of our:
- filings with the Securities and Exchange Commission (the "SEC") and
the Securities Act of 1933 and the Securities Exchange Act of 1934
(the "Exchange Act") (i.e., Forms 10-K and 10-Q);
- press releases and other communications by the Partnership to the
public concerning earnings, financial condition and results of
operations, including changes in distribution policies or practices
affecting the holders of Partnership units;
77
- systems of internal controls regarding finance and accounting that
management and the board of directors have established; and
- auditing, accounting and financial reporting processes generally.
In fulfilling its oversight responsibilities, the audit committee reviewed
and discussed with management the audited financial statements contained in this
Annual Report on Form 10-K.
The Partnership's independent public accountants, Deloitte & Touche, LLP,
are responsible for expressing an opinion on the conformity of the audited
financial statements with generally accepted accounting principles. The audit
committee reviewed with Deloitte & Touche, LLP their judgment as to the quality,
not just the acceptability, of the Partnership's accounting principles and such
other matters as are required to be discussed with the audit committee under
generally accepted auditing standards.
The audit committee discussed with Deloitte & Touche, LLP the matters
required to be discussed by SAS 61 (Codification of Statement on Auditing
Standards, AU ss. 380), as may be modified or supplemented. The committee
received written disclosures and the letter from Deloitte & Touche, LLP required
by Independence Standards Board No. 1., Independence Discussions with Audit
Committees, as may be modified or supplemented, and has discussed with Deloitte
& Touche, LLP its independence from management and the Partnership.
Based on the reviews and discussions referred to above, the audit committee
recommended to the board of directors that the audited financial statements be
included in the Annual Report on Form 10-K for the year ended December 31, 2003
for filing with the SEC.
Members of the Audit Committee:
Michael J. Hall, Chairman
John P. Neafsey
John H. Robinson
CODE OF ETHICS
We have adopted a Code of Ethics with which our chief executive officer and
our senior financial officers (including our principal financial officer, and
our principal accounting officer or controller), are expected to comply. The
Code of Ethics is publicly available on our website under Investors Relations at
www.arlp.com and is available in print to any unitholder who requests it. If any
substantive amendments are made to the Code of Ethics or if there is a grant of
a waiver, including any implicit waiver, from a provision of the code to our
chief executive officer, chief financial officer or chief accounting officer or
controller, we will disclose the nature of such amendment or waiver on our
website or in a report on Form 8-K.
78
COMMUNICATIONS WITH THE BOARD
Unitholders or other interested parties can contact any director or
committee of the board by writing to them c/o Senior Vice President - Law and
Administration, General Counsel and Secretary, P. O. Box 22027, Tulsa, Oklahoma
74121-2027. Comments or complaints relating to our accounting, internal
accounting controls or auditing matters will also be referred to members of the
audit committee. The audit committee has procedures for receipt, retention and
treatment of complaints received by us regarding accounting, internal accounting
controls, or auditing matters; and for the confidential, anonymous submission by
our employees of concerns regarding questionable accounting or auditing matters.
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Securities and Exchange Act of 1934, as amended,
requires directors, executive officers and persons who beneficially own more
than ten percent of a registered class of our equity securities to file with the
SEC initial reports of ownership and reports or changes in ownership of such
equity securities. Such persons are also required to furnish us with copies of
all Section 16(a) forms they file. Based solely upon a review of the copies of
the forms furnished to us, or written representations from certain reporting
persons, we believe that during 2003 none of our officers and directors were
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 related to his purchase of 250
units on July 14, 2003, but has since filed a Form 4 with respect to this
transaction.
REIMBURSEMENT OF EXPENSES OF OUR MANAGING GENERAL PARTNER AND ITS AFFILIATES
Our 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 our managing general partner will determine
the expenses that are allocable to us in any reasonable manner determined by our
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 and each of the four other most highly compensated
executive officers of our managing general partner in excess of $100,000 in
2003, 2002 and 2001. We reimburse our managing general partner and its
affiliates for expenses incurred on our behalf, including the cost of officer
compensation allocable to us.
79
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION
----------------------------------------------- LONG-TERM
OTHER ANNUAL COMPENSATION ALL OTHER
COMPENSATION RESTRICTED STOCK COMPENSATION
NAME AND PRINCIPAL POSITION YEAR SALARY BONUS (1) (2) AWARDS (3) (4)
--------------------------- ---- ------ --------- --- ---------- ---
Joseph W. Craft III, 2003 $334,828 $387,000 $3,400 $1,105,605 $62,694
President, Chief Executive Officer 2002 328,955 227,000 1,075 1,237,500 52,171
and Director 2001 314,700 130,000 5,250 781,875 50,562
Thomas L. Pearson, 2003 199,680 166,000 - 221,121 31,481
Senior Vice President-Law and 2002 196,178 83,000 1,750 222,750 32,631
Administration, General Counsel and 2001 192,000 63,000 1,167 140,738 31,914
Secretary
Charles R. Wesley, 2003 215,665 234,500 - 343,966 37,115
Senior Vice President-Operations 2002 211,504 130,000 - 247,500 33,001
2001 202,000 65,000 925 156,375 33,286
Gary J. Rathburn, 2003 173,680 171,000 - 227,263 30,602
Senior Vice President-Marketing 2002 170,634 90,000 2,285 233,750 29,884
2001 167,000 70,000 3,000 140,738 26,702
Thomas M. Wynne 2003 153,600 150,000 - 159,699 17,448
Vice President-Operations 2002 144,462 60,000 - 178,750 16,102
2001 135,308 40,000 - 112,938 10,194
(1) Amounts awarded under the Short-Term Incentive Plan. Please 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, 2003,
were: Mr. Craft, 185,000 units valued at $6,360,300; Mr. Pearson, 34,200
units valued at $1,175,796; Mr. Wesley, 42,000 units valued at $1,443,960;
Mr. Rathburn, 34,850 units valued at $1,198,143; Mr. Wynne 26,000 units
valued at $893,880. Please see "Long-Term Incentive Plan" below.
(4) Amounts represent (a) our managing general partner's matching contributions
to its 401(k) Plan, (b) our managing general partner's contribution to its
Supplemental Executive Retirement Plan (SERP), and (c) in regard to Mr.
Sachse only, our managing general partner's contribution to its Directors'
Compensation Program.
COMPENSATION OF DIRECTORS
Under our managing general partner's Directors' Compensation Program
(Directors' Plan) each non-employee director was paid an annual retainer of
$21,500 during 2003, except Mr. MacWilliams and Mr. Miller who each received
$10,750 in 2003. 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 is
eligible to participate in a deferred compensation plan that is administered by
the compensation committee. Prior to the beginning of each plan year, each
non-employee director may elect to defer all or a portion of his compensation
until he ceases to be a member of the board of directors. A new election must be
made for each plan year. For compensation deferred by a director, a notional
account is established and credited with "phantom" units equal to the number of
common units deferred. In addition, when distributions are made with respect to
common units, the notional account is credited with "phantom"
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distributions with respect to phantom units that are equal in amount to the
distributions made with respect to common units. The board of directors may
change or terminate the deferred compensation plan at any time; provided,
however, that accrued benefits under the deferred benefit plan cannot be
impaired. Effective January 1, 2004, the annual retainer was increased to
$22,500.
In addition, each non-employee director is entitled to participate in the
Long-Term Incentive Plan. Under the Long-Term Incentive Plan such directors
receive annual grants of restricted units, which vest in accordance with the
procedures described below. Please see "Long-Term Incentive Plan" below. Prior
to the refinancing of the promissory notes in May 2003 between Alliance
Resources Holdings and The Beacon Group, Mr. MacWilliams and Mr. Miller had
declined compensation under the Directors' Plan and Long-Term Incentive Plans.
Please see "Item 1. Business - Transactions in 2003."
Mr. Sachse has a consulting agreement with our managing general partner
with an indefinite term, subject to termination by either party upon receipt of
ninety-days advance written notice of termination. The consulting agreement
provides that Mr. Sachse will serve as Executive Vice President of our 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. Copies of Mr. Sachse's original
consulting agreement and the letter agreement extending the term of the original
agreement are exhibits hereto.
EMPLOYMENT AGREEMENTS
The executive officers of our managing general partner and some additional
members of senior management will enter into employment agreements among the
executive officer or member of senior management, on the one hand, and our
managing general partner on the other. We reimburse our 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, $225,280 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 our 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 our 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 our managing general partner
described below along with other members of management.
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They also are entitled to participate in the other employee benefit plans and
programs that our managing general partner provides for its employees.
LONG-TERM INCENTIVE PLAN
Effective January 1, 2000, our managing general partner adopted the
Long-Term Incentive Plan (LTIP) for certain employees and directors of our
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 our managing
general partner's board of directors. Annual grant levels for designated
participants are recommended by the president and chief executive officer of our
managing general partner, subject to the review and approval of the compensation
committee. We will reimburse our 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 our 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 our managing general partner, or any combination of the foregoing. Our
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, 2004, the compensation committee approved an
amendment to the LTIP clarifying that if an award is paid or settled in cash
rather than through the delivery of units, then the units granted by such award
shall be available with respect to which options and restricted units may be
granted under the LTIP in the future. A copy of the amendment is an exhibit
hereto. The compensation committee additionally authorized the cash settlement
of at least 40% of all awards under the LTIP that will vest at the end of the
subordination period, which will be no earlier than November 2004. During 2003
the compensation committee approved grants of 141,205 restricted units, which
will vest September 30, 2005, subject to certain financial tests. During 2002
and 2001, the compensation committee approved grants of 133,885 and 129,200
restricted units, which vest at the end of the subordination period, which
generally will not end before September 30, 2004. As of December 31, 2003,
18,125 units have been forfeited. Effective as of January 1, 2004, the
compensation committee approved additional grants of 103,425 restricted units,
which vest on December 31, 2006 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.
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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.
Our 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. Our 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, our managing general partner may, in its discretion, establish such
additional compensation and incentive arrangements as it deems appropriate to
motivate and reward its employees. Our 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 9,000 33 Months
Charles R. Wesley 14,000 33 Months
Gary J. Rathburn 9,250 33 Months
Thomas M. Wynne 6,500 33 Months
(1) Units granted under the LTIP will vest September 30, 2005, subject to
certain financial tests.
(2) The number of units granted is not subject to minimum thresholds,
targets or maximum payout conditions.
SHORT-TERM INCENTIVE PLAN
Our managing general partner maintains a STIP for management and other
salaried employees. The STIP is designed to enhance the financial performance by
rewarding management and selected salaried employees and those of our 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 chief executive officer of our 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 our
managing general partner is able to amend the plan at any time. Our managing
general partner is entitled to reimbursement by us for the costs incurred under
the STIP.
SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN
Our managing general partner maintains 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
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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.
Our managing general partner is able to amend or terminate the plan at any time.
Our managing general partner is entitled to reimbursement by us for its costs
incurred under the SERP.
COMPENSATION COMMITTEE'S REPORT ON EXECUTIVE COMPENSATION
The compensation committee administers the executive compensation programs
of our managing general partner and was established to fulfill two purposes: (a)
to discharge the board of directors' responsibilities relating to compensation
of our managing general partner's directors and executives, and (b) to produce
an annual report on executive compensation for inclusion in our annual report on
Form 10-K. All three members of the compensation committee of the board of
directors (currently Mr. Miller, Mr. Neafsey and Mr. Robinson) are "non-employee
directors" as defined under the Securities Exchange Act of 1934 and the Internal
Revenue Code. The board of directors has assigned to the compensation committee
the following functions:
- To review and approve corporate goals and objectives relative to our
managing general partner's president and chief executive officer's
(CEO) compensation, and evaluate the CEO's performance in light of
those goals and objectives and to set the CEO's compensation level
based on this evaluation.
- To review and approve corporate goals and objectives relative to our
senior executive officers, including our named executive officers'
compensation, evaluate our senior executive officers' performance in
light of those goals and objectives, and to set the senior executive
compensation levels based on this evaluation.
- To make recommendations to the board of directors with respect to
incentive compensation plans and equity-based plans, including,
without limitation, our managing general partner's short-term
incentive plan (STIP), long-term incentive plan (LTIP), and
supplemental executive retirement plan (SERP).
- To administer our managing general partner's LTIP and grant restricted
units or other awards pursuant to such plan.
- To evaluate its own performance at least annually and report on such
performance to the board of directors.
For the fiscal year ended December 31, 2003, the compensation committee's
activities focused on the primary elements of the total direct compensation
program for executive officers; the merits of continuing the LTIP; the
guidelines for the STIP pertaining to eligibility, minimum thresholds, target
objectives, target results, target payout groups, the respective percentage
targets and the payout formula .
OVERALL EXECUTIVE COMPENSATION PROGRAM
The goals of our managing general partner's executive compensation program
are to align compensation with our managing general partner's business
objectives and performance and enable our managing general partner to attract,
retain and motivate qualified executive officers that contribute to the
long-term success of our managing general partner and its affiliates. The
primary components of our managing general partner's executive compensation
programs are:
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- base salary;
- annual incentive bonus awards; and
- equity participation in the form of restricted units.
Executive officers are also entitled to customary benefits available to all
of our managing general partner's employees, including group medical, dental,
and life insurance and participation in our managing general partner's Profit
Sharing and Savings Plan.
Base Salary
The compensation committee reviews and recommends the base salary of our
managing general partner's named executive officers, as well as our other
officers and key employees. When reviewing base salaries, the compensation
committee considers the individual's performance, past performance of our
managing general partner and the individual's contribution to that performance,
the individual's level of responsibility and competitive pay practices. In
general, base salaries are generally targeted at the middle of the competitive
market place. This assessment considers relevant industry salary practices, the
position's complexity and level of responsibility, its importance to our
managing general partner in relation to other executive positions, and the
competitiveness of an executive's total compensation. Subject to the committee's
approval, the level of executive officer's base pay is determined on the basis
of relative comparative compensation data and the CEO's assessment of the
executive's performance, experience, demonstrated leadership, job knowledge and
management skills.
Annual Incentive Bonus Awards
To provide annual incentive bonus awards, our managing general partner
maintains the STIP. The purpose of the STIP is to enhance unitholder value by
providing eligible employees, including executive officers of our managing
general partner, with added incentive to achieve specific annual targets. The
STIP also assists our managing general partner in attracting, retaining and
motivating qualified personnel in order to allow our managing general partner to
remain competitive with its industry peers. The targets are intended to be
aligned with our managing general partner's mission so that bonus payments are
made only if unitholder interests are advanced. These targets are established
prior to the beginning of each fiscal year. Under the STIP and its related
guidelines, our managing general partner's executive officers and other
employees selected by the compensation committee are eligible for cash bonuses
based upon the comparison of our actual performance results to an annual EBITDA
target. EBITDA is defined as income before net interest expense, income taxes
and depreciation, depletion and amortization.
Each executive officer of our managing general partner participating in the
STIP was eligible to earn a cash bonus expressed as a percentage of such
officer's base salary. The incentive bonus opportunities varied by each
executive officer's level of responsibility. The maximum percentage of base
salary payable as an incentive bonus was (i) up to 160 percent for our managing
general partner's CEO, (ii) up to 120 percent for our managing general partner's
senior vice presidents, (iii) up to 80 percent for our managing general
partner's vice presidents, and (iv) up to specified percentages for other
participants. For fiscal year 2003, we achieved our respective annual targets by
varying amounts so that all of the 2003 STIP participants were eligible to
receive a percentage of their salary as bonus awards at the discretion of the
compensation committee and/or our CEO. Bonuses are payable in the first quarter
of the following calendar year.
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Equity Participation
Equity compensation in the form of restricted units is a key component of
our managing general partner's executive compensation program. Under the LTIP
administered by the compensation committee, annual grant levels for designated
employees are recommended by the CEO. The grants are made either of (a)
restricted units, which are "phantom units" that entitle a grantee to receive a
common unit or an equivalent amount of cash upon the vesting of a phantom unit
or (b) options to purchase common units. Restricted units are vested over a
stated period from the grant date. The issuance of the common units pursuant to
the LTIP is intended to serve as a means of incentive compensation performance
and not primarily as an opportunity to participate in the equity participation
with respect to our common units. Therefore, no consideration will be payable by
the plan participants upon receipt of the common units. To date, the
compensation committee has not granted any unit options under the LTIP.
CEO Executive Compensation
In determining Mr. Craft's compensation, the compensation committee
considered our financial performance and peer group compensation data as well as
Mr. Craft's leadership, decision-making skills, experience, knowledge,
communication with the board of directors and strategic recommendations. The
compensation committee did not place any particular relative weight on any one
of these factors, but our financial performance is generally given the most
weight. The committee's decisions regarding Mr. Craft's compensation are
reported to and discussed with the board of directors meeting in executive
session without Mr. Craft's participation. For fiscal year 2003, Mr. Craft
served as CEO of our managing general partner. Effective June 1, 2002, Mr.
Craft's annual salary was increased to $334,828 from $321,950, which adjustment
was determined in the manner described above. The compensation committee honored
Mr. Craft's request that his salary not be increased in 2003 even though a
salary increase would have been warranted under the compensation adjustment
procedure described above. Based on our record performance for 2003, Mr. Craft
received a cash bonus (paid in fiscal year 2004) equal to approximately 116% of
his base salary. Mr. Craft was awarded 28,000 restricted units under the LTIP,
subject to certain vesting requirements. The number of restricted units granted
to Mr. Craft was determined in the same manner as restricted units granted for
our managing general partner's other executive officers as described above.
Conclusion
Based upon its review of our managing general partner's overall executive
compensation program, the compensation committee has concluded that the
program's structure is appropriate, competitive and effective to serve the
purposes for which it was established. Moreover, the compensation committee
believes that the total compensation opportunities provided to our managing
general partner's executive officers creates a commonality of interest and
alignment with the long-term interests of both our managing general partner and
its unitholders.
Members of the Compensation Committee:
Preston R. (Jeff) Miller, Chairman
John H. Robinson
John P. Neafsey
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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth certain information as of March 1, 2004,
regarding the beneficial ownership of common and subordinated units held by (a)
each person known by our 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 our managing general partner and (c) all directors and executive
officers of our managing general partner as a group. Our managing general
partner is owned by members of management. Our special general partner is a
wholly-owned subsidiary of Alliance Resource Holdings. The address of Alliance
Resource Holdings, our managing general partner and our special general partner
is 1717 South Boulder Avenue, Tulsa, Oklahoma 74119.
PERCENTAGE OF PERCENTAGE OF PERCENTAGE
COMMON COMMON SUBORDINATED SUBORDINATED OF TOTAL
UNITS UNITS UNITS UNITS UNITS
BENEFICIALLY BENEFICIALLY BENEFICIALLY BENEFICIALLY BENEFICIALLY
NAME OF BENEFICIAL OWNER OWNED (5) OWNED OWNED OWNED OWNED
- ------------------------ ------------ -------------- ------------ ------------- -------------
Alliance Resource GP, LLC (1) 4,444,045 30.25% 3,211,266 100% 42.8%
Joseph W. Craft III (1)(4) 4,660,133 31.72% 3,211,266 100% 44.0%
Robert G. Sachse (1) 8,319 * - - *
Thomas L. Pearson (1) 18,168 * - - *
Charles R. Wesley (1) 27,845 * - - *
Brian L. Cantrell (1) - * - - *
Gary J. Rathburn (1) 15,703 * - - *
Michael J. Hall (1) 169 * - - *
John J. MacWilliams (2) 172 * - - *
Preston R. Miller, Jr. (2) 172 * - - *
John P. Neafsey (1) 14,847 * - - *
John H. Robinson (3) 5,875 * - - *
All directors and executive officers
as a group (9 persons) 4,779,248 32.53% 3,211,266 100% 44.6%
* Less than one percent
(1) The address of Alliance Resource GP, LLC and Messrs. Craft, Sachse,
Pearson, Wesley, Cantrell, Rathburn, Hall, and Neafsey is 1717 South
Boulder Avenue, Tulsa, Oklahoma 74119.
(2) The address of Mr. MacWilliams and Mr. Miller is The Tremont Group, LLC.,
275 Grove St., Suite 2-400, Newton, Massachusetts 02466.
(3) The address of Mr. Robinson is 121 West 48th Street, Suite 1006, Kansas
City, Missouri 64112.
(4) Mr. Craft may be deemed to share beneficial ownership of 4,444,045 common
units and 3,211,266 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 113,561 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 10,921 common units held by
Alliance Management Holdings, LLC, of which he is the sole director. 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 which vest at various dates ranging from the end of the subordination
period, which generally will not end before September 30, 2004 through
December 31, 2006, subject to certain financial tests.
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EQUITY COMPENSATION PLAN INFORMATION
NUMBER OF UNITS TO BE ISSUED UPON NUMBER OF UNITS REMAINING
EXERCISE/VESTING OF OUTSTANDING WEIGHTED-AVERAGE EXERCISE AVAILABLE FOR FUTURE ISSUANCE
OPTIONS, WARRANTS AND RIGHTS PRICE OF OUTSTANDING UNDER EQUITY COMPENSATION
PLAN CATEGORY AS OF MARCH 1, 2004 OPTIONS, WARRANTS AND RIGHTS PLANS AS OF MARCH 1, 2004
- ------------- ------------------- ---------------------------- -------------------------
EQUITY COMPENSATION PLANS APPROVED
BY UNITHOLDERS:
Long-Term Incentive Plan 476,566 N/A 123,434
EQUITY COMPENSATION PLANS NOT
APPROVED BY UNITHOLDERS:
Supplemental Executive 44,986 N/A 35,014
Retirement Plan
Deferred Compensation Plan 14,835 N/A 35,165
for Directors
For a description of our Supplemental Executive Retirement Plan and our
Deferred Compensation Plan for Directors, please read "Supplemental Executive
Retirement Plan" and "Compensation of Directors" under "Item 11.
Executive Compensation."
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Our special general partner owns 4,444,045 common units and 3,211,266
subordinated units representing an aggregate 42.6% limited partner interest in
us. In addition, our general partners own, on a combined basis, an aggregate 2%
general partner interest in us, the intermediate partnership and the
subsidiaries. Our managing general partner's ability, as managing general
partner, to control us together with our special general partner's ownership of
4,444,045 common units and 3,211,266 subordinated units, effectively gives our
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 lease a coal preparation plant and handling facilities at Gibson and
lease coal reserves from our special general partner and its affiliates. 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
Holdings in February 2003. Please see "Item 8. Financial Statements and
Supplementary Data. - Note 16. 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
JPMorgan Chase Bank (Chase) is paying agent, co-administrative agent and a
lender under our Credit Facility. In 2003, 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 2004. The Beacon Group is an affiliate of Chase. Mr. MacWilliams and Mr.
Miller are directors of both the Beacon Group and our managing general partner.
OMNIBUS AGREEMENT
Concurrently with the closing of our initial public offering, we entered
into an omnibus agreement with Alliance Resource Holdings and our 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
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the amended omnibus agreement, Alliance Resource Holdings agreed, and caused its
controlled affiliates to agree, for so long as management controls our 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 our 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.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The firm of Deloitte & Touche LLP is our independent auditors. Fees
paid to Deloitte & Touche LLP during the last two fiscal years were as follows:
Audit Services. Fees for audit services provided during the
years ended December 31, 2003 and 2002, were $240,000 and $377,000,
respectively. Audit services consist primarily of the audit and
quarterly reviews of the consolidated financial statements, but can
also be related to statutory audits of subsidiaries required by
governmental or regulatory bodies, attestation services required by
statute or regulation, comfort letters, consents, assistance with and
review of documents filed with the SEC, work performed by tax
professionals in connection with the audit and quarterly reviews, and
accounting and financial reporting consultations and research work
necessary to comply with generally accepted accounting principles.
Audit-Related Services. Fees for audit-related services
provided during the years ended December 31, 2003 and 2002, were
$36,000 and $21,000, respectively. Audit-related services consist
primarily of audits of employee benefit plans, consultations concerning
financial accounting and reporting standards, and attestation services
associated with third-party compliance.
Tax Services. Fees for tax services provided during the years
ended December 31, 2003 and 2002, were $231,000 and $147,000,
respectively. Tax services relate primarily to the preparation of
federal and state tax returns but can also be related to tax advise,
exclusive of tax services rendered in conjunction with the audit.
All Other Fees. There were no other fees during the years
ended December 31, 2003 and 2002.
The charter of the audit committee provides that the committee is
responsible for the pre-approval of all auditing services and permitted
non-audit services to be performed for us by our independent auditors, subject
to the requirements of applicable law. In accordance with such law, the audit
committee has delegated the authority to grant such pre-approvals to the audit
committee chairman, which approvals are then reviewed by the full audit
committee at is next regular meeting. Typically, however, the audit committee
itself reviews the matters to be approved. The audit committee periodically
monitors the services rendered by and actual fees
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paid to the independent auditors to ensure that such services are within the
parameters approved by the audit committee.
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, 2003, 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)).
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
90
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 22, 2003, among
Alliance Resource Operating Partners, L.P., JPMorgan
Chase Bank (as paying agent), Citicorp USA, Inc. and
JPMorgan Chase Bank (as co-administrative agents) and
lenders named therein. (Incorporated by reference to
Exhibit 10.2 of the Registrant's Quarterly Report on
Form 10-Q for the quarter ended September 30, 2003,
File No. 000-26823).
10.2 Note Purchase Agreement, dated as of August 16, 1999,
among Alliance Resource GP, LLC and the purchasers
named therein. (Incorporated by reference to Exhibit
10.20 of the Registrant's Annual Report on Form 10-K
for the year ended December 31, 1999, File No.
000-26823).
10.3 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).
10.4 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 10.33 of the Registrant's
Quarterly Report on Form 10-Q for the quarter ended
September 30, 2002, File No. 000-26823).
10.5 Promissory Note Agreement dated as of July 31, 2001,
between Alliance Resource Partners, L.P. and Bank of
Oklahoma, N. A. (Incorporated by reference to Exhibit
10.21 of the Registrant's Quarterly Report on Form
10-Q for the quarter ended September 30, 2001, File
No. 000-26823).
10.6 Guarantee Agreement, dated as of July 31, 2001,
between Alliance Resource GP, LLC and Bank of
Oklahoma, N.A. (Incorporated by reference to Exhibit
10.22 of the Registrant's Quarterly Report on Form
10-Q for the quarter ended September 30, 2001, File
No. 000-26823).
10.7 Letter of Credit Facility Agreement dated as of
August 30, 2001, between Alliance Resource Partners,
L.P. and Fifth Third Bank. (Incorporated by reference
to Exhibit 10.23 of the Registrant's Quarterly Report
on Form 10-Q for the quarter ended September 30,
2001, File No. 000-26823).
10.8 Amendment No. 1 to Letter of Credit Facility
Agreement between Alliance Resource Partners, L.P.
and Fifth Third Bank. (Incorporated by reference to
Exhibit 10.9 of the Registrant's Annual Report on
Form 10-K for the year ended December 31, 2002, File
No. 000-26823).
91
10.9 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).
10.10 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).
10.11 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 10.32 of the
Registrant's Quarterly Report on Form 10-Q for the
quarter ended September 30, 2002, File No.
000-26823).
10.12 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).
10.13 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).
10.14 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).
10.15 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).
10.16 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).
*10.17 Amended and Restated Alliance Resource Management GP,
LLC 2000 Long-Term Incentive Plan.
*10.18 First Amendment to the Alliance Resource Management
GP, LLC 2000 Long-Term Incentive Plan.
92
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 Amendment No. 3 to the Restated and Amended Coal
Supply Agreement effective January 1, 2003 between
Webster County Coal, LLC, White County Coal, LLC,
Alliance Coal, LLC, and Seminole Electric
Cooperative, Inc. (Incorporated by reference to
Exhibit 10.39 of the Registrant's Quarterly Report on
Form 10-Q for the quarter ended March 31, 2003, File
No. 000-26823).
10.26 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).
10.27 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).
10.28 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).
93
10.29 First Amendment 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).
10.30 Second Amendment to Coal Feedstock Supply Agreement
dated April 1, 2003, between Synfuel Solutions
Operating LLC and Warrior Coal, LLC. (Incorporated by
reference to Exhibit 10.40 of the Registrant's
Quarterly Report on Form 10-Q for the quarter ended
June 30, 2003, File No. 000-26823).
*10.31 Assignment and Assumption Agreement dated April 1,
2003 between Synfuel Solutions Operating LLC, Hopkins
County Coal, LLC, and Warrior Coal, LLC.
10.32 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).
10.33 Letter Agreement dated January 31, 2003 between ARH
Warrior Holdings, Inc. and Alliance Resource
Partners, L.P. (Incorporated by reference to Exhibit
10.34 of the Registrant's Annual Report on Form 10-K
for the year ended December 31, 20002 File No.
000-26823).
10.34 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).
10.35 Extension of Consulting Agreement with Mr. Sachse,
dated September 30, 2003. (Incorporated by reference
to Exhibit 10.42 of the Registrant's Quarterly Report
on Form 10-Q for the quarter ended September 30,
2003, 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).
94
*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.
*31.1 Certification of Joseph W. Craft III, President
and Chief Executive Officer of Alliance Resource
Management GP, LLC, the managing general partner of
Alliance Resource Partners, L.P., dated March 12,
2004, pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002 furnished herewith.
*31.2 Certification of Brian L. Cantrell, Senior Vice
President and Chief Financial Officer of Alliance
Resource Management GP, LLC, the managing general
partner of Alliance Resource Partners, L.P., dated
March 12, 2004, pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002 furnished herewith.
*32.1 Certification of Joseph W. Craft III, President
and Chief Executive Officer of Alliance Resource
Management GP, LLC, the managing general partner of
Alliance Resource Partners, L.P., dated March 12,
2004, pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002 furnished herewith.
*32.2 Certification of Brian L. Cantrell, Senior Vice
President and Chief Financial Officer of Alliance
Resource Management GP, LLC, the managing general
partner of Alliance Resource Partners, L.P., dated
March 12, 2004, pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002 furnished herewith.
*Filed herewith.
(b) Reports on Form 8-K:
A Form 8-K was filed on October 27, 2003 to submit to the
Securities and Exchange Commission a press release announcing earnings
and operating results for the third quarter of 2003. The press release
contains the following financial statements: (i) consolidated statement
of income and operating data for the three-months and nine-months ended
September 30, 2003 and 2002; (ii) consolidated balance sheets at
September 30, 2003 and December 31, 2002; and (iii) consolidated
condensed statements of cash flows for the nine-months ended September
30, 2003 and 2002.
95
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 12, 2004.
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/ Brian L. Cantrell
---------------------------------------
Brian L. Cantrell
Senior Vice President and
Chief Financial 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 Officer, March 12, 2004
- ------------------------- and Director (Principal Executive Officer)
Joseph W. Craft III
/s/ Brian L. Cantrell Senior Vice President and March 12, 2004
- -------------------------- Chief Financial Officer
Brian L. Cantrell
/s/ Michael J. Hall Director March 12, 2004
- --------------------------
Michael J. Hall
/s/ John J. MacWilliams Director March 12, 2004
- --------------------------
John J. MacWilliams
/s/ Preston R. Miller, Jr. Director March 12, 2004
- --------------------------
Preston R. Miller, Jr.
/s/ John P. Neafsey Director March 12, 2004
- --------------------------
John P. Neafsey
/s/ John H. Robinson Director March 12, 2004
- --------------------------
John H. Robinson
/s/ Robert G. Sachse Executive Vice President and Director March 12, 2004
- --------------------------
Robert G. Sachse
96
INDEX TO EXHIBITS
EXHIBITS DESCRIPTION
- -------- -----------
3.1 Amended and Restated Agreement of Limited Partnership of Alliance
Resource Partners, L.P. (Incorporated by reference to Exhibit 3.1 of
the Registrant's Annual Report on Form 10-K for the year ended December
31, 1999, File No. 000-26823).
3.2 Amended and Restated Agreement of Limited Partnership of Alliance
Resource Operating Partners, L.P. (Incorporated by reference to Exhibit
3.2 of the Registrant's Annual Report on Form 10-K for the year ended
December 31, 1999, File No. 000-26823).
3.3 Certificate of Limited Partnership of Alliance Resource Partners, L.P.
(Incorporated by reference to Exhibit 3.6 of the Registrant's
Registration Statement on Form S-1 filed with the Commission on May 20,
1999 (Reg. No. 333-78845)).
3.4 Certificate of Limited Partnership of Alliance Resource Operating
Partners, L.P. (Incorporated by reference to Exhibit 3.8 of the
Registrant's Registration Statement on Form S-1/A filed with the
Commission on July 20, 1999 (Reg. No. 333-78845)).
3.5 Certificate of Formation of Alliance Resource Management GP, LLC
(Incorporated by reference to Exhibit 3.7 of the Registrant's
Registration Statement on Form S-1/A filed with the Commission on July
23, 1999 (Reg. No. 333-78845)).
3.6 Amended and Restated Operating Agreement of Alliance Resource
Management GP, LLC (Incorporated by reference to Exhibit 3.4 of the
Registrant's Registration Statement on Form S-3 filed with the
Commission on April 1, 2002 (Reg. No. 333-85282)).
3.7 Amendment No. 1 to Amended and Restated Operating Agreement of Alliance
Resource Management GP, LLC (Incorporated by reference to Exhibit 3.5
of the
Registrant's Registration Statement on Form S-3 filed with the
Commission on April 1, 2002 (Reg. No. 333-85282)).
3.8 Amendment No. 2 to Amended and Restated Operating Agreement of Alliance
Resource Management GP, LLC (Incorporated by reference to Exhibit 3.6
of the Registrant's Registration Statement on Form S-3 filed with the
Commission on April 1, 2002 (Reg. No. 333-85282)).
4.1 Form of Common Unit Certificate (Included as Exhibit A to the Amended
and Restated Agreement of Limited Partnership of Alliance Resource
Partners, L.P.)
10.1 Credit Agreement, dated as of August 22, 2003, among Alliance Resource
Operating Partners, L.P., JPMorgan Chase Bank (as paying agent),
Citicorp USA, Inc. and JPMorgan Chase Bank (as co-administrative
agents) and lenders named therein. (Incorporated by reference to
Exhibit 10.2 of the Registrant's Quarterly Report on Form 10-Q for the
quarter ended September 30, 2003, File No. 000-26823).
10.2 Note Purchase Agreement, dated as of August 16, 1999, among Alliance
Resource GP, LLC and the purchasers named therein. (Incorporated by
reference to Exhibit 10.20 of the Registrant's Annual Report on Form
10-K for the year ended December 31, 1999, File No. 000-26823).
10.3 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).
10.4 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 10.33 of the Registrant's
Quarterly Report on Form 10-Q for the quarter ended September 30, 2002,
File No. 000-26823).
10.5 Promissory Note Agreement dated as of July 31, 2001, between Alliance
Resource Partners, L.P. and Bank of Oklahoma, N. A. (Incorporated by
reference to Exhibit 10.21 of the Registrant's Quarterly Report on Form
10-Q for the quarter ended September 30, 2001, File No. 000-26823).
10.6 Guarantee Agreement, dated as of July 31, 2001, between Alliance
Resource GP, LLC and Bank of Oklahoma, N.A. (Incorporated by reference
to Exhibit 10.22 of the Registrant's Quarterly Report on Form 10-Q for
the quarter ended September 30, 2001, File No. 000-26823).
10.7 Letter of Credit Facility Agreement dated as of August 30, 2001,
between Alliance Resource Partners, L.P. and Fifth Third Bank.
(Incorporated by reference to Exhibit 10.23 of the Registrant's
Quarterly Report on Form 10-Q for the quarter ended September 30, 2001,
File No. 000-26823).
10.8 Amendment No. 1 to Letter of Credit Facility Agreement between Alliance
Resource Partners, L.P. and Fifth Third Bank. (Incorporated by
reference to Exhibit 10.9 of the Registrant's Annual Report on Form
10-K for the year ended December 31, 2002, File No. 000-26823).
10.9 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).
10.10 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).
10.11 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 10.32 of the
Registrant's Quarterly Report on Form 10-Q for the quarter ended
September 30, 2002, File No. 000-26823).
10.12 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).
10.13 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).
10.14 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).
10.15 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).
10.16 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).
* 10.17 Amended and Restated Alliance Resource Management GP, LLC 2000
Long-Term Incentive Plan.
* 10.18 First Amendment to the Alliance Resource Management GP, LLC 2000
Long-Term Incentive Plan.
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 Amendment No. 3 to the Restated and Amended Coal Supply Agreement
effective January 1, 2003 between Webster County Coal, LLC, White
County Coal, LLC, Alliance Coal, LLC, and Seminole Electric
Cooperative, Inc. (Incorporated by reference to Exhibit 10.39 of the
Registrant's Quarterly Report on Form 10-Q for the quarter ended March
31, 2003, File No. 000-26823).
10.26 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).
10.27 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).
10.28 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).
10.29 First Amendment 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).
10.30 Second Amendment to Coal Feedstock Supply Agreement dated April 1,
2003, between Synfuel Solutions Operating LLC and Warrior Coal, LLC.
(Incorporated by reference to Exhibit 10.40 of the Registrant's
Quarterly Report on Form 10-Q for the quarter ended June 30, 2003, File
No. 000-26823).
*10.31 Assignment and Assumption Agreement dated April 1, 2003 between Synfuel
Solutions Operating LLC, Hopkins County Coal, LLC, and Warrior Coal,
LLC.
10.32 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).
10.33 Letter Agreement dated January 31, 2003 between ARH Warrior Holdings,
Inc. and Alliance Resource Partners, L.P. (Incorporated by reference to
Exhibit 10.34 of the Registrant's Annual Report on Form 10-K for the
year ended December 31, 20002 File No. 000-26823).
10.34 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).
10.35 Extension of Consulting Agreement with Mr. Sachse, dated September 30,
2003. (Incorporated by reference to Exhibit 10.42 of the Registrant's
Quarterly Report on Form 10-Q for the quarter ended September 30, 2003,
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.
* 31.1 Certification of Joseph W. Craft III, President and Chief Executive
Officer of Alliance Resource Management GP, LLC, the managing general
partner of Alliance Resource Partners, L.P., dated March 12, 2004,
pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 furnished
herewith.
* 31.2 Certification of Brian L. Cantrell, Senior Vice President and Chief
Financial Officer of Alliance Resource Management GP, LLC, the managing
general partner of Alliance Resource Partners, L.P., dated March 12,
2004, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
furnished herewith.
* 32.1 Certification of Joseph W. Craft III, President and Chief Executive
Officer of Alliance Resource Management GP, LLC, the managing general
partner of Alliance Resource Partners, L.P., dated March 12, 2004,
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 furnished
herewith.
* 32.2 Certification of Brian L. Cantrell, Senior Vice President and Chief
Financial Officer of Alliance Resource Management GP, LLC, the managing
general partner of Alliance Resource Partners, L.P., dated March 12,
2004, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
furnished herewith.
* Filed herewith.