Document/Exhibit Description Pages Size
1: 10-K Alliance Resource Partners, L.P. - 12/31/1999 62 341K
2: EX-3.1 Amended Agreement to Limited Partnership 82 437K
3: EX-3.2 Amended Agreement to Limited Partnership 70 276K
4: EX-10.1 Credit Agreement - August 16, 1999 116 410K
8: EX-10.11 2000 Long-Term Incentive Plan 11 42K
9: EX-10.12 Short-Term Incentive Plan 4 19K
5: EX-10.2 Note Purchase Agreement - August 16, 1999 124 477K
6: EX-10.3 Contribution & Assumption Agreement 23 51K
7: EX-10.4 Omnibus Agreement - Dated August 16, 1999 14 54K
10: EX-21.1 List of Subsidiaries 1 6K
11: EX-27.1 Financial Data Schedule 1 8K
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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, 1999
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
----------------------------
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]
The aggregate value of the Common Units held by non-affiliates of the
registrant (treating all executive officers and directors of the registrant, for
this purpose, as if they may be affiliates of the registrant) was approximately
$95,705,398 on March 23, 2000, based on $12.88 per unit, the closing price of
the Common Units as reported on the Nasdaq National Market on such date.
As of March 23, 2000, 8,982,780 Common Units and 6,422,531 Subordinated
Units are outstanding.
DOCUMENTS INCORPORATED BY REFERENCE: None
--------------------------------------------------------------------------------
TABLE OF CONTENTS
[Download Table]
Page
PART I
ITEM 1. BUSINESS ............................................................. 4
ITEM 2. PROPERTIES ........................................................... 15
ITEM 3. LEGAL PROCEEDINGS .................................................... 19
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITIES HOLDERS ................ 19
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON UNITS AND RELATED
UNITHOLDER MATTERS ................................................... 19
ITEM 6. SELECTED FINANCIAL DATA .............................................. 20
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS .................................. 22
ITEM 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK ................................................................ 28
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA .......................... 29
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE ................................................. 50
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE MANAGING GENERAL PARTNER ..... 50
ITEM 11. EXECUTIVE COMPENSATION ............................................... 52
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT ........................................................... 54
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS ....................... 56
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS
ON FORM 8-K .......................................................... 58
2
FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K contains forward-looking statements. These
statements are based on Alliance Resource Partners, L.P.'s (the "Partnership")
beliefs as well as assumptions made by and information currently available to
the Partnership. When used in this document, the words "anticipate," "believe,"
"expect," "estimate," "forecast," "project," and similar expressions identify
forward-looking statements. These statements reflect the Partnership's current
views with respect to future events and are subject to various risks,
uncertainties and assumptions including, but not limited to (a) the
Partnership's dependence on significant customer contracts and the terms of
those contracts, (b) the Partnership's productivity levels and margins that it
earns from the sale of coal, (c) the effects of any unanticipated increases in
labor costs, adverse changes in work rules, or unexpected cash payments
associated with post-mine reclamation, workers' compensation claims, and
environmental litigation or cleanup, (d) the risk of major mine-related
accidents or interruptions, (e) the effects of any adverse change in the
domestic coal industry, electric utility industry, or general economic
conditions. If one or more of these risks or uncertainties materialize, or
should underlying assumptions prove incorrect, actual results may vary
materially from those described in this Form 10-K. Except as required by
applicable securities laws, the Partnership does not intend to update these
forward-looking statements.
3
PART I
ITEM 1. BUSINESS
GENERAL
We are a diversified producer and marketer of coal to major United States
utilities and industrial users. We began mining operations in 1971 and, since
then, have grown through acquisitions and internal development to become the
eighth largest coal producer in the eastern United States. At December 31, 1999,
we had approximately 440 million tons of reserves in Illinois, Indiana,
Kentucky, Maryland and West Virginia. In 1999, we produced 14.1 million tons of
coal and sold 15.0 million tons of coal. The coal we produced in 1999 was 19.9%
low-sulfur coal, 19.9% medium-sulfur coal and 60.2% high-sulfur coal. In 1999,
approximately 85% of our medium- and high-sulfur coal was sold to utility plants
with installed pollution control devices, also known as "scrubbers," to remove
sulfur dioxide.
We currently operate six mining complexes in Illinois, Kentucky and
Maryland and have one complex under development in Indiana. Five of our active
mines are underground and one has both surface and underground mines. Our mining
activities are organized into three operating regions: (a) the Illinois Basin
operations, (b) the East Kentucky operations and (c) the Maryland operations.
We and our subsidiary, Alliance Resource Operating Partners, L.P. (the
"Intermediate Partnership"), were formed to acquire, own and operate
substantially all of the coal production and marketing assets of Alliance
Resource Holdings, Inc. ("ARH"), a Delaware corporation formerly known as
Alliance Coal Corporation. We completed our initial public offering ("IPO") on
August 20, 1999, and concurrently therewith, ARH contributed substantially all
of its operating assets and liabilities to the Intermediate Partnership.
Our managing general partner, Alliance Resource Management GP, LLC (the
"Managing GP") and our special general partner, Alliance Resource GP, LLC (the
"Special GP") (collectively, the Special GP and the Managing GP are the "General
Partners") own an aggregate 2% general partner interest in the Partnership. Our
limited partners, including the General Partners as holders of Common Units and
Subordinated Units, own an aggregate 98% limited partner interest in the
Partnership.
The coal production and marketing assets of ARH acquired by the
Partnership are referred to as the "Predecessor." All 1999 operating data
contained herein includes the results of the Partnership and the Predecessor.
RECENT DEVELOPMENTS
We are constantly evaluating strategic acquisition of coal reserve
properties that are adjacent or otherwise complementary to our existing
operations. Over the last year, we have increased our reserves from
approximately 411 million tons of proven and probable reserves at December 31,
1998, to approximately 440 million tons of proven and probable reserves at
December 31, 1999. Recent significant acquisitions and option exercises include:
Acquisition of reserves in western Kentucky. In September 1999, we
acquired approximately 21 million saleable tons of reserves in western
Kentucky that are contiguous with our Dotiki mine. This acquisition
allows for the immediate advancement of the Dotiki mine's existing
operations into the newly acquired reserve area without the cost of
additional development capital.
Exercise of options to acquire two tracts of reserves in western
Kentucky. In March 2000, the Special GP exercised two separate options to
acquire substantial tracts of reserves in western Kentucky. One tract is
contiguous with our Dotiki mine, and the other borders our Hopkins County
Coal facilities. Upon closing of the acquisition, the Special GP, in its
4
discretion, may choose to lease the tracts to us or assign the properties
to us in return for payment for all amounts it expended in connection
with the reserve acquisition, plus a market rate of interest. See "Item
13. Certain Relationships and Related Transactions." Although the Special
GP expects to close the acquisition by the end of September 2000, the
Special GP can make no assurances that it will be able to do so. The
reserves covered by these two options are not included in the 440 million
tons of proven and probable reserves noted above.
At Gibson County Coal, slope construction commenced in the fall of 1999
and construction of the preparation plant began in January 2000. We have entered
into an arrangement with the Special GP where the Special GP will construct the
preparation plant and ancillary facilities. See "Item 13. Certain Relationships
and Related Transactions." We expect the slope construction and the preparation
plant (including ancillary facilities) to be completed by this fall and the mine
to commence production by the end of this year.
MINING OPERATIONS
We produce a diverse range of steam coals with varying sulfur and heat
contents, which enables us to satisfy the broad range of specifications demanded
by our customers. The following chart illustrates our production by region for
the last five years.
[Enlarge/Download Table]
OPERATING REGION AND MINES 1999 1998 1997 1996 1995
-------------------------- --------- --------- --------- --------- ---------
(TONS IN MILLIONS)
Illinois Basin Operations:
Dotiki, Pattiki, Hopkins County Coal 8.5 7.9 5.2 4.3 4.4
East Kentucky Operations:
Pontiki/Excel, MC Mining 2.8 2.5 2.8 2.0 1.8
Maryland Operations:
Mettiki 2.8 3.0 2.9 2.7 2.6
--------- --------- --------- --------- ---------
Total 14.1 13.4 10.9 9.0 8.8
========= ========= ========= ========= =========
Illinois Basin Operations
Our Illinois Basin mining operations are currently located in western
Kentucky and southern Illinois. We have approximately 770 employees in the
Illinois Basin and currently operate three mining complexes. We also have a mine
under development in southern Indiana.
Webster County Coal, LLC. Webster County Coal operates the Dotiki mine
which is an underground mining operation located in Webster County, Kentucky.
The mine was opened in 1966, and we purchased the mine in 1971. Our Dotiki
operation utilizes continuous mining units employing room-and-pillar mining
techniques. The preparation plant has a throughput capacity of 1,000 tons of raw
coal an hour. Production from the mine is shipped via the CSX railroad, the
Paducah & Louisville railroad and by truck. Our primary customers for coal
produced at Dotiki are Seminole Electric Cooperative, Inc., Tennessee Valley
Authority and Western Kentucky Energy Corp., which purchase our coal pursuant to
long-term contracts for use in their scrubbed generating units.
White County Coal, LLC. White County Coal operates the Pattiki mine which
is an underground mining operation located in White County, Illinois. We began
construction of the mine in 1980 and have operated it since its inception. Our
Pattiki operation utilizes continuous mining units employing room-and-pillar
mining techniques. The preparation plant has a throughput capacity of 1,000 tons
of raw coal an hour. Production from the mine is shipped via the CSX railroad.
Our primary customers for coal produced at Pattiki are Seminole Electric
Cooperative, Inc. and Tennessee Valley Authority, which purchase our coal
pursuant to long-term contracts for use in their scrubbed generating units.
5
Hopkins County Coal, LLC. Hopkins County Coal is a mining complex located
in Hopkins County, Kentucky. The operation has three surface mines, one of which
is currently idle, and one underground mine. We acquired Hopkins County Coal in
January 1998. In accordance with our acquisition plan, we incurred substantial
start-up costs in early 1998, when we completed extensive rebuilds of older
equipment and purchases of new or refurbished equipment. The surface operations
utilize dragline mining, and the underground operations utilize continuous
mining units employing room-and-pillar mining techniques. The preparation plant
has a throughput capacity of 1,000 tons of raw coal an hour. Production from the
complex is shipped via the CSX and the Paducah & Louisville railroads and by
truck. Our primary customers for coal produced at the Hopkins County Coal
complex include Louisville Gas & Electric, Tennessee Valley Authority and
Western Kentucky Energy Corp.
Gibson County Coal, LLC. We control 37.8 million tons of low-sulfur coal
reserves located in Gibson County, Indiana, situated in the southwestern part
of the state. We refer to these reserves as the Gibson County Coal "north"
reserves. In 1997, we acquired an additional 104.2 million tons of reserves in
Gibson County, Indiana. We refer to these reserves as the Gibson County Coal
"south" reserves. Approximately 10.9 million tons of our Gibson County Coal
south reserves are low-sulfur coal. We recently entered into a long-term
contract with PSI Energy, Inc., a subsidiary of Cinergy Corporation, for
production from our Gibson County Coal north reserves. We began construction of
a new mining complex to supply this contract with commencement of slope
construction in the fall of 1999 and construction of the preparation plant
and ancillary facilities in January of 2000. We plan to utilize continuous
mining units with commencement of production by the end of this year. We have
contractual commitments for an aggregate of 23 million tons of production from
this mine through 2012.
East Kentucky Operations
Our East Kentucky mining operations are located in the central Appalachia
coal fields. Our East Kentucky mines are currently our principal source for
low-sulfur coal. We have approximately 245 employees and operate two mining
complexes in East Kentucky.
Pontiki Coal, LLC/Excel Mining, LLC. Pontiki/Excel is an underground
mining complex located in Martin County, Kentucky. In 1977, we constructed the
mine and operated it continuously until September 1998, when we suspended
operations and terminated substantially all of our workforce due to adverse
market conditions. While we had intended originally to idle the mine for an
indefinite period, we were able to procure a new long-term supply agreement that
justified the re-opening of the mine beginning in late 1998. As a result, this
operation was restructured with a new mine plan, operating structure, and
workforce hired by Excel, an affiliate of Pontiki. Pontiki owns the mining
complex and reserves and Excel is responsible for conducting all mining
operations. While idled, the mine incurred a net loss of approximately $5.2
million in 1998, consisting of workers' compensation accruals and severance
payments consistent with the federal Worker Adjustment and Retraining
Notification Act (the "WARN Act"), as well as the costs associated with
maintaining an idled mine. During late 1998 and early 1999, we incurred
substantial start-up costs to bring Pontiki/Excel up to its current production
level. All of the coal produced at Pontiki/Excel meets or exceeds the compliance
requirements of Phase II of the Clean Air Act Amendments. Our Pontiki/Excel
operation utilizes continuous mining units employing room-and-pillar mining
techniques. The preparation plant has a throughput capacity of 800 tons of raw
coal an hour. Production from the mine is shipped via the Norfolk Southern
railroad and by truck. Our primary customers for coal produced at Pontiki are
James River Cogeneration Company, successor to Cogentrix of Virginia, Inc., and
A.E.I. Coal Sales, Inc.
MC Mining, LLC. MC Mining is an underground mining facility located in
Pike County, Kentucky, acquired in 1989. The underground mine operations are
operated by a contract mining company. The preparation plant is operated by
employees of MC Mining. The operation utilizes continuous mining units employing
room-and-pillar mining techniques. The preparation plant was upgraded during
1999 and has a throughput capacity of 800 tons of raw coal an hour. Production
from the mine is shipped via the CSX railroad and by truck. MC Mining sells its
production primarily to industrial customers.
6
Maryland Operations
Our Maryland mining operations are located in the northern Appalachia
coal fields. We have approximately 245 employees and operate one mining complex
in Maryland.
Mettiki Coal, LLC. Mettiki is an underground longwall mining operation
located in Garrett County, Maryland. We constructed Mettiki in 1977 and have
operated it since its inception. The operation utilizes a longwall miner for the
majority of the coal extraction as well as continuous mining units used to
prepare the mine for future longwall mining operation areas. The preparation
plant has a throughput capacity of 1,350 tons of raw coal an hour. Production
from the mine is shipped via truck and the CSX railroad. Our primary customer
for coal produced at Mettiki is Virginia Electric and Power Company, which
purchases the coal pursuant to a long-term contract for use in the generating
units at its Mt. Storm, West Virginia power plant located less than 20 miles
away. We also process coal at Mettiki for Anker Energy Corporation and one of
its affiliates.
Mettiki Coal (WV), LLC. Mettiki (WV) has approximately 20.1 million tons
of undeveloped recoverable reserves in Grant and Tucker Counties, West Virginia.
We currently conduct no mining operations at Mettiki (WV).
OTHER OPERATIONS
Mt. Vernon Transfer Terminal, LLC
Mt. Vernon terminal is a rail-to-barge loading terminal on the Ohio River
in Mt. Vernon, Indiana. The terminal has a capacity of 5.5 million tons per year
with existing ground storage. Our primary customer at Mt. Vernon is Seminole
Electric Cooperative, Inc., with which we have a contract to load up to 2.7
million tons of coal annually. However, Seminole Electric Cooperative, Inc. has
filed suit in Indiana state court to terminate this contract and is seeking a
declaratory judgment as to the damages it owes us in connection with the
termination of the contract. We are currently not loading any volumes for
Seminole Electric Cooperative, Inc. We are currently exploring our options with
respect to this terminal. See "Item 3. Legal Proceedings."
Additional Services
We aggressively develop and market additional services in order to
establish ourselves as the supplier of choice for our customers. Examples of the
kind of services we have offered to date include ash and scrubber sludge
removal, coal yard maintenance and arranging alternate transportation services.
We will continue to think proactively in providing additional services for
customers and believe that this approach will give us a competitive advantage in
obtaining coal supply contracts in the future.
Coal Brokerage
We buy coal from outside producers throughout the eastern United States,
which we then resell, both directly and indirectly, to utility and industrial
customers. We purchased and sold 1.0 million tons of outside coal in 1999. We
have a policy of matching our outside coal purchases and sales to minimize
market risks associated with buying and reselling coal.
COAL MARKETING AND SALES
As is customary in the coal industry, we have entered into long-term
contracts with many of our customers. These arrangements are mutually
beneficial. Our utility customers secure a fuel supply for their power plants
for years into the future. Our long-term contracts contribute to our stability
and profitability by providing greater predictability of sales volumes and sales
prices. In 1999, approximately 75% of our sales tonnage was sold under long-term
contracts with maturities ranging from 2000 to 2010. Our total nominal
commitment under significant long-term contracts is approximately 88.4 million
tons at December 31, 1999. The total commitment of coal under contract is an
approximate number because, in some instances, our contracts contain provisions
which could cause the nominal total commitment to increase or decrease by as
much as 20%; in addition, the nominal total commitment can otherwise change
because of price reopener provisions contained in certain of these long-term
contracts. We believe our long-term contract position compares favorably to that
of our competitors.
7
By providing a diverse range of coals with varying sulfur and heat
contents, we can satisfy the demanding specifications of a broad customer base.
Our diversity of coals enables us to serve a broader market and more readily
secure long-term contracts.
The terms of long-term contracts are the results of both bidding
procedures and extensive negotiations with the customer. As a result, the terms
of these contracts vary significantly in many respects, including, among others,
price adjustment features, price and contract reopener terms, permitted sources
of supply, force majeure provisions, coal qualities, and quantity. Virtually all
of our long-term contracts are subject to price adjustment provisions which
permit an increase or decrease periodically in the contract price to reflect
changes in specified price indices or items such as taxes, royalties or actual
production costs. These provisions, however, may not assure that the contract
price will reflect every change in production or other costs. Failure of the
parties to agree on a price pursuant to an adjustment or a reopener provision
can lead to early termination of a contract. Some of the long-term contracts
also permit the contract to be reopened to renegotiate terms and conditions
other than the pricing terms, and where a mutually acceptable agreement on terms
and conditions cannot be concluded, either party may have the option to
terminate the contract. The long-term contracts typically stipulate procedures
for quality control, sampling and weighing. Most contain provisions requiring us
to deliver coal within ranges for specific coal characteristic such as heat,
sulfur, ash, moisture, grindability, volatility and other qualities. Failure to
meet these specifications can result in economic penalties or termination of the
contracts. While most of the contracts specify the approved seams and/or
approved locations from which the coal is to be mined, some contracts allow the
coal to be sourced from more than one mine or location. Although the volume to
be delivered pursuant to a long-term contract is stipulated, the buyers often
have the option to vary the volume within specified limits.
RELIANCE ON MAJOR CUSTOMERS
Our three largest customers are Seminole Electric Cooperative, Inc.,
Tennessee Valley Authority and Virginia Electric and Power Company. Sales to
these customers in the aggregate accounted for approximately 49% of our 1999
total revenues, and sales to each customer accounted for more than 10% of our
1999 total revenues. Each of these customers has purchased coal regularly from
us for more than 15 years.
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 approximately 15% of the total 1999 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, barge and truck.
Depending on the proximity of the customer to the mine and the transportation
available for delivering coal to that customer, transportation costs can range
from 10% to 60% of the delivered cost of a customer's coal. As a consequence,
the availability and cost of transportation constitute important factors in the
marketability of coal. We believe our mines are located in favorable geographic
locations that minimize transportation costs for our customers.
8
We generally pay transportation charges to deliver coal to a designated
point named in the sales contract. Customers typically pay the transportation
costs from the contractual F.O.B. point to the customer's plant. At the Mettiki
mine, a contractor operates a truck delivery system that transports the coal
from the mine to Virginia Electric and Power Company's Mt. Storm power plant.
In 1999, the largest volume transporter of our coal production was CSX
railroad, which moved approximately 50% of our tonnage over its rail system. The
practices of and rates set by the railroad serving a particular mine or customer
might affect, either adversely or favorably, our marketing efforts with respect
to coal produced from the relevant mine.
REGULATION AND LAWS
The coal mining industry is subject to regulation by federal, state and
local authorities on matters such as:
- employee health and safety;
- mine permits and other licensing requirements;
- air quality standards;
- water pollution;
- storage of petroleum products and substances which are regarded as
hazardous under applicable laws;
- plant and wildlife protection;
- reclamation and restoration of mining properties after mining is
completed;
- the discharge of materials into the environment;
- management of solid wastes generated by mining operations;
- protection of wetlands;
- management of electrical equipment containing polychlorinated
biphenyls, or PCBs;
- surface subsidence from underground mining;
- the effects that mining has on groundwater quality and availability;
and
- legislatively mandated benefits for current and retired coal miners.
In addition, the utility industry is subject to extensive regulation
regarding the environmental impact of its power generation activities which
could affect demand for our coal. The possibility exists that new legislation or
regulations, or new interpretations of exiting laws or regulations, may be
adopted which may have a significant impact on our mining operations or our
customers' ability to use coal and may require us or our customers to change our
or their operations significantly or to incur substantial costs.
We are committed to conducting mining operations in compliance with all
applicable federal, state and local laws and regulations. However, because of
extensive and comprehensive regulatory requirements, violations during mining
operations are not unusual in the industry and, notwithstanding our compliance
efforts, we do not believe these violations can be eliminated completely. None
of the violations to date or the monetary penalties assessed have been material.
9
While it is not possible to quantify the costs of compliance with all
applicable federal and state laws, those costs have been and are expected to
continue to be significant. Capital expenditures for environmental matters have
not been material in recent years. We have accrued for the estimated costs of
reclamation and mine closing, including the cost of treating mine water
discharge, when necessary. The accrual for reclamation and mine closing costs is
based upon permit requirements and the costs and timing of reclamation and mine
closing procedures. Although management believes it is making adequate
provisions for all expected reclamation and other costs associated with mine
closures, future operating results would be adversely affected if we later
determine these accruals to be insufficient. Compliance with these laws has
substantially increased the cost of coal mining for all domestic coal producers.
Mining Permits and Approvals. Numerous governmental permits or approvals
are required for mining operations. We may be required to prepare and present to
federal, state or local authorities data pertaining to the effect or impact that
any proposed production of coal may have upon the environment. All requirements
imposed by any of these authorities may be costly and time-consuming and may
delay commencement or continuation of mining operations. Future legislation and
administrative regulations may emphasize the protection of the environment and,
as a consequence, our activities may be more closely regulated. Legislation and
regulations, as well as future interpretations of existing laws, may require
substantial increases in equipment and operating costs and delays, interruptions
or a termination of operations, the extent of which cannot be predicted.
Before commencing mining on a particular property, we must obtain mining
permits and approval by state regulatory authorities of a reclamation plan for
restoring, upon the completion of mining, the mined property to its prior
condition, productive use or other permitted condition. Typically we commence
actions to obtain permits between 18 and 24 months before we plan to mine a new
area. In our experience, permits generally are approved within 12 months after a
completed application is submitted. We have already secured all of the material
permits and approvals necessary to begin mining operations for our Gibson County
Coal mine. We have not experienced difficulties in obtaining mining permits in
the areas where our reserves are currently located. However, we cannot assure
you that we will not experience difficulty in obtaining mining permits in the
future.
Under some circumstances, substantial fines and penalties, including
revocation of mining permits, may be imposed under the laws described above.
Monetary sanctions and, in severe circumstances, criminal sanctions may be
imposed for failure to comply with these laws. Regulations also provide that a
mining permit can be refused or revoked if an officer, director or a shareholder
with a 10% or greater interest in the entity is affiliated with another entity
which has outstanding permit violations. Although we have been cited for
violations in the ordinary course of our business, we have never had a permit
suspended or revoked because of any violation, and the penalties assessed for
these violations have not been material.
Mine Health and Safety Laws. Stringent safety and health standards have
been imposed by federal legislation since 1969 when the Coal Mine Health and
Safety Act of 1969 was adopted. The Mine Health and Safety Act of 1969 resulted
in increased operating costs and reduced productivity. The federal Mine Safety
and Health Act of 1977, which significantly expanded the enforcement of health
and safety standards of the Mine Health and Safety Act of 1969, imposes
comprehensive safety and health standards on all mining operations. Regulations
are comprehensive and affect numerous aspects of mining operations, including
training of mine personnel, mining procedures, blasting, the equipment used in
mining operations and other matters. The Mine Safety and Health Administration
monitors compliance with these federal laws and regulations. In addition, as
part of the Mine Health and Safety Act of 1969 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 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
pervasive system for protection of employee safety and health affecting any
segment of the industry. Even the most minute aspects of mine operations,
particularly underground mine operations, are subject to extensive regulation.
This regulation has a significant effect on our operating costs. However, our
competitors in all of the areas in which we operate are subject to the same laws
and regulations.
10
Black Lung Legislation. The Black Lung Benefits Act 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, the Black Lung Acts
provide that some claims for which coal operators had previously been
responsible will be obligations of the government trust funded by the tax. The
Revenue Act of 1987 extended the termination date of this tax from January 1,
1996, to the earlier of January 1, 2014, or the date on which the government
trust becomes solvent. For miners last employed as miners after 1969 and who are
determined to have contracted black lung, we self-insure against potential cost
using actuarially determined estimates of the cost of present and future claims.
We are also liable under state statutes for black lung claims.
In the past, legislation on black lung reform has been introduced in
Congress, but not enacted. This legislation has been recently reintroduced. If
enacted, this legislation could:
- restrict the evidence that can be offered by a mining company;
- establish a standard for evaluation of evidence that greatly favors
black lung claimants;
- allow claimants who have been denied benefits at any time since 1981
to refile their claims for consideration under the new law;
- make surviving spouse benefits significantly easier to obtain; and
- retroactively waive repayment of preliminarily awarded benefits that
are later determined to have been improperly paid.
If this or similar legislation is passed, the number of claimants who
are awarded benefits could significantly increase. We cannot assure you that
this proposed legislation or other proposed changes in black lung legislation
will not have an adverse effect on our business.
The U.S. Department of Labor has issued proposed amendments to the
regulations implementing the federal black lung laws which, among other things,
establish a presumption in favor of a claimant's treating physician, allow
previously denied claimants to challenge benefit determinations in some
circumstances, increase the time period required for self-insured operations to
pay benefits to black lung claimants and limit a coal operator's ability to
introduce medical evidence regarding the claimant's medical condition. If
adopted, the amendments could have an adverse impact on us, the extent of which
cannot be accurately predicted.
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. These changes, if enacted, could
adversely affect our financial condition and results of operation.
Retiree Health Benefits Legislation. The Coal Industry Retiree Health
Benefits Act of 1992 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 newly created 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 any payments to retired miners under the Coal Industry Retiree Health
Benefits Act of 1992, with the exception of limited payments made on behalf of
MC Mining, Inc. However, in connection with the sale of the coal assets
acquired by ARH in 1996, MAPCO Inc. agreed to retain all liabilities under the
Coal Industry Retiree Health Benefits Act of 1992.
11
Surface Mining Control and Reclamation Act. The Surface Mining Control
and Reclamation Act establishes operational, reclamation and closure standards
for all aspects of surface mining as well as many aspects of deep mining. The
act requires that comprehensive environmental protection and reclamation
standards be met during the course of and upon completion of mining activities.
In conjunction with mining the property, we reclaim and restore the mined areas
by grading, shaping and preparing the soil for seeding. Upon completion of the
mining, reclamation generally is completed by seeding with grasses or planting
trees for a variety of uses, as specified in the approved reclamation plan. We
believe that we are in compliance in all material respects with applicable
regulations relating to reclamation.
The Surface Mining Control and Reclamation Act and similar state
statutes, require, among other things, that mined property be restored in
accordance with specified standards and approved reclamation plans. The act
requires us to restore the surface to approximate the original contours as
contemporaneously as practicable with the completion of surface mining
operations. The mine operator must submit a bond or otherwise secure the
performance of these reclamation obligations. The earliest a reclamation bond
can be released is five years after reclamation has been achieved. Federal law
and some states impose on mine operators the responsibility for replacing
certain water supplies damaged by mining operations and repairing or
compensating for damage occurring on the surface as a result of mine subsidence,
a consequence of longwall mining and possibly other mining operations. In
addition, the Abandoned Mine Lands Act, which is part of the Surface Mining
Control and Reclamation Act, imposes a tax on all current mining operations, the
proceeds of which are used to restore mines closed before 1977. The maximum tax
is $0.35 per ton on surface-mined coal and $0.15 per ton on underground-mined
coal. We have accrued for the estimated costs of reclamation and mine closing,
including the cost of treating mine water discharge when necessary.
Under the Surface Mining Control and Reclamation Act, 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 contract mine operator. Sanctions against the "owner" or
"controller" are quite severe and can include being blocked from receiving new
permits and revocation of any permits that have been issued since the time of
the violations or, in the case of civil penalties and reclamation fees, since
the time their amounts became due. We are not aware of any currently pending or
asserted claims relating to the "ownership" or "control" theories discussed
above. However, we cannot assure you that such claims will not develop in the
future.
Clean Air Act. The federal Clean Air Act and similar state laws, which
regulate emissions into the air, affect coal mining and processing operations
primarily through permitting and/or emissions control requirements. The Clean
Air Act also indirectly affects coal mining operations by extensively regulating
the air emissions of coal-fired electric power generating plants. For example,
the Clean Air Act requires reduction of SO(2) emissions from electric power
generation plants in two phases. Only some facilities are subject to the Phase I
requirements. Beginning in year 2000, Phase II requires nearly all facilities to
reduce emissions. The affected utilities will be able to meet these requirements
by:
- switching to lower sulfur fuels;
- by installing pollution control devices such as scrubbers;
- by reducing electricity generating levels; or
- by purchasing or trading so-called pollution "credits."
Specific emissions sources receive these "credits" that utilities and
industrial concerns can trade or sell to allow other units to emit higher levels
of SO(2). In addition, the Clean Air Act requires a study of utility power plant
emission of some toxic substances and their eventual regulation, if warranted.
The effect of the Clean Air Act cannot be completely ascertained at this time,
although the SO(2) emissions reduction requirement is projected generally to
increase the demand for lower sulfur coal and potentially decrease demand for
higher sulfur coal.
12
The Clean Air Act also indirectly affects coal mining operations by
requiring utilities that currently are major sources of nitrogen oxides in
moderate or higher ozone nonattainment areas to install reasonably available
control technology for nitrogen oxides, which are precursors of ozone. An
October 1998 Environmental Protection Agency rulemaking that would require 22
eastern states and the District of Columbia to make substantial reductions in
nitrogen oxide emissions by the year 2003 was substantially upheld by the U.S.
Court of Appeals for the D.C. Circuit on March 3, 2000. The Environmental
Protection Agency expects these states will achieve reductions by requiring
power plants to make substantial reductions in their nitrogen oxide 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 the Environmental
Protection Agency proposal 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 Clean Air Act, the new
National Ambient Air Quality Standards or any other future regulatory provisions
will not materially adversely affect our business, financial condition or
results of operations.
In addition, the U.S. Environmental Protection Agency has already
issued and is considering further regulations relating to fugitive dust and
emissions of other coal-related pollutants such as mercury, nickel, dioxin and
fine particulates. For example, in July 1997, the Environmental Protection
Agency adopted new, more stringent National Ambient Air Quality Standards for
particulate matter which may require some states to change existing
implementation plans. These National Ambient Air Quality Standards are expected
to be implemented by 2003, although a recent decision by the U.S. Court of
Appeals for the D.C. Circuit could delay or modify the Environmental Protection
Agency's implementation of the new standards. Because coal mining operations
emit particulate matter, our mining operations and utility customers are likely
to be directly affected when the revisions to the National Ambient Air Quality
Standards are implemented by the states. These and other regulatory developments
may restrict our ability to develop new mines, or could require us or our
customers to modify existing operations, and may have a material adverse effect
on our financial condition and results of operations.
Framework Convention On Global Climate Change. The United States and
more than 160 other nations are signatories to the 1992 Framework Convention on
Global Climate Change (also known as the Kyoto Protocol) which is intended to
limit or capture emissions of greenhouse gases, such as carbon dioxide. In the
Kyoto Protocol, the signatories to the Framework Convention on Global Climate
Change established a binding set of emissions targets for developed nations. The
specific limits vary from country to country. Under the terms of the Kyoto
Protocol, the United States would be required to reduce emissions to 93% of 1990
levels over a five-year budget period from 2008 through 2012. The Clinton
Administration signed the protocol in November 1998. Although the U.S. Senate
has not ratified the Kyoto Protocol and no comprehensive regulations focusing on
greenhouse gas emissions have been enacted, efforts to control greenhouse gas
emissions could result in reduced use of coal if electric power generators
switch to lower carbon sources of fuel. These restrictions, if established
through regulation or legislation, could have a material adverse effect on our
business, financial condition and results of operations.
Clean Water Act. The federal Clean Water Act affects coal mining
operations by imposing restrictions on effluent discharge into waters. Regular
monitoring, as well as compliance with reporting requirements and performance
standards, are preconditions for the issuance and renewal of permits governing
the discharge of pollutants into water. We are also subject to Section 404 of
the Clean Water Act, which imposes permitting and mitigation requirements
associated with the dredging and filling of wetlands. The federal Clean Water
Act and equivalent state legislation, where such equivalent state
13
legislation exists, affect coal mining operations that impact wetlands. We
believe we have obtained all necessary wetlands permits required under Section
404. However, mitigation requirements under those existing, and possible future,
wetlands permits may vary considerably. For that reason, the setting of accruals
for such mitigation projects is difficult to ascertain with certainty. We
believe that we have obtained all permits required under the Clean Water Act as
traditionally interpreted by the responsible agencies and that, although more
stringent permitting requirements may be imposed in the near future, compliance
with the Clean Water Act will not materially adversely affect our business,
financial condition and results of operations.
Safe Drinking Water Act. The federal Safe Drinking Water Act and its
state equivalents affect coal mining operations by imposing requirements on the
underground injection of fine coal slurries, fly ash, and flue gas scrubber
sludge, and by requiring a permit to conduct such underground injection
activities. The inability to obtain these permits could have a material impact
on our ability to inject materials such as fine coal refuse, fly ash, or flue
gas scrubber sludge into the inactive areas of some of our old underground mine
workings.
In addition to establishing the underground injection control program,
the federal Safe Drinking Water Act also imposes regulatory requirements on
owners and operators of "public water systems." This regulatory program could
impact our reclamation operations where subsidence, or other mining-related
problems, require the provision of drinking water to affected adjacent
homeowners. However, the federal Safe Drinking Water Act defines a "public water
system" for purposes of regulatory jurisdiction as a system for the provision to
the public of water for human consumption through pipes or other constructed
conveyances, if the system has at least fifteen service connections or regularly
serves at least twenty-five individuals. It is unlikely that any of our
reclamation activities would require the provision of such a "public water
system." While we have at least one drinking water supply source for our
employees and contractors that is subject to Safe Drinking Water Act regulation,
the federal Safe Drinking Water Act is unlikely to have a material impact on our
operations.
Comprehensive Environmental Response, Compensation and Liability Act.
CERCLA and similar state laws affect coal mining operations by, among other
things, imposing cleanup requirements for threatened or actual releases of
hazardous substances that may endanger public health or welfare or the
environment. Under CERCLA, and similar state laws, joint and several liability
may be imposed on waste generators, site owners and operators and others
regardless of fault or the legality of the original disposal activity. Some
products used by coal companies in operations, such as chemicals, generate waste
containing hazardous substances which are governed by the statute. Thus, coal
mines that we currently own or have previously owned or operated, and sites to
which we sent waste materials, may be subject to liability under CERCLA and
similar state laws. We have been, on rare occasions, the subject of
administrative proceedings, litigation and investigations relating to CERCLA
matters, none of which has had a material adverse effect on our financial
condition or results of operations. However, we cannot assure you that we will
not become involved in future proceedings, litigation or investigations or that
these liabilities will not be material.
Toxic Substances Control Act. The federal Toxic Substances Control Act
regulates, among other things, electrical equipment containing polychlorinated
biphenyls (PCBs) in excess of 50 parts-per-million. Specifically, the Toxic
Substances Control Act's PCB rules require that all PCB-containing equipment be
properly labeled, stored, and disposed of, and requires the maintenance on-site
of annual records regarding the presence and use of equipment containing PCBs in
excess of 50 parts-per-million. Because the regulated PCB-containing electrical
equipment in use in our operations is owned by the utilities that serve the
operations where they are located, and because the use of PCB-containing fluids
in such equipment is in the process of being phased out, we do not believe the
Toxic Substances Control Act will have a material impact on our operations.
Resource Conservation and Recovery Act. The federal Resource
Conservation and Recovery Act affects coal mining operations by imposing
requirements for the generation, transportation, treatment, storage, disposal
and cleanup of hazardous wastes. Although many mining wastes are excluded from
the regulatory definition of
14
hazardous waste, and coal mining operations covered by the Surface Mining
Control and Reclamation Act permits are exempted from regulation under the
Resource Conservation and Recovery Act by statute, the Environmental Protection
Agency may consider the possibility of expanding regulation of mining wastes
under the Resource Conservation and Recovery Act. This expansion could have a
material adverse affect on our financial condition and results of operations.
Impact of Possible Changes to Regulatory Status of Coal Combustion
By-products. Pursuant to a consent decree entered into by the Environmental
Protection Agency and others, the agency is considering the option of imposing
hazardous waste regulatory controls on the disposal of some coal combustion
by-products, including the practice of using coal combustion by-products as
minefill. Such a regulatory classification may materially impact our reclamation
activities due to the use of fly ash from some of our customers' electricity
generation plants to neutralize acid mine drainage and as fill material for
reclamation projects. In addition, such a regulatory classification may have a
material adverse affect on our business by increasing our customers' costs and
creating disincentives to the use of coal. At this time, the Environmental
Protection Agency has noted that it currently lacks sufficient information with
which to assess adequately the risks associated with this practice. Therefore,
the Environmental Practice Agency has solicited comment on whether there are
some minefill practices that are universally poor and warrant specific
attention.
While we cannot predict the ultimate outcome of the Environmental
Protection Agency's assessment, we believe that the beneficial usages of coal
combustion by-products we employ do not constitute a universally poor practice
due to, among other things, the fact that our Clean Water Act discharge permits
for treated acid mine drainage contain parameters for pollutants of concern,
such as metals, and those permits require monitoring and reporting of effluent
quality data.
OTHER ENVIRONMENTAL, HEALTH AND SAFETY REGULATION
In addition to the laws and regulations described above, we are subject
to regulations regarding underground and above ground storage tanks where we may
store petroleum or other substances. Some monitoring equipment that we use is
subject to licensing under the federal Atomic Energy Act. Water supply wells
located on our property are subject to federal, state and local regulation. The
costs of compliance with these requirements should not adversely affect our
business, financial condition or results of operations.
EMPLOYEES
We have approximately 1,360 employees, including 100 corporate
employees and 1,260 employees involved in active mining operations. Our
work-force is entirely union-free. Relations with our employees are generally
good, and there have been no recent work stoppages or union organizing
campaigns among our employees.
ITEM 2. PROPERTIES
COAL RESERVES
As of December 31, 1999, we had approximately 440 million tons of coal
reserves. All of the estimates of reserves which are presented in this annual
report on Form 10-K are of proven and probable reserves. Proven and probable
reserves are reserves that we can economically produce using current extraction
technology from acreage we own or lease.
15
The following table sets forth production data and reserve information,
as of December 31, 1999, about each of our mining complexes.
[Enlarge/Download Table]
1999 HEAT
PRODUCTION CONTENT
(MILLION (BTUS SULFUR ASH
OPERATIONS LOCATION MINE TYPE OF TONS) PER POUND) (%) (%)
------------------- ------------------- ----------- ------------ ----------- --------- --------
Illinois Basin Operations
Dotiki Webster County, KY Underground 3.6 12,500 2.9 8.1
Pattiki White County, IL Underground 2.3 11,700 3.0 7.9
Hopkins County Hopkins County, KY Surface/ 2.6 11,300 3.2 12.4
Coal Underground
Gibson County Gibson County, IN Underground 11,600 1.0 7.0
Coal (North)
Gibson County Gibson County, IN Underground 11,600 2.1 NA
Coal (South)
----
Region Total 8.5
----
East Kentucky Operations
Pontiki/Excel Martin County, KY Underground 1.8 12,800 0.7 6.7
MC Mining Pike County, KY Underground 1.0 12,800 0.7 7.2
Other Martin County, KY Underground 12,400 0.9 9.0
----
Region Total 2.8
----
Maryland Operations
Mettiki Garrett County, MD Underground 2.8 13,000 1.6 10.0
Mettiki (WV) Grant and Tucker Underground 13,000 1.6 10.0
County, WV
----
2.8
----
----
Total 14.1
====
% of Total
PROVEN AND PROBABLE RESERVES
LOW MEDIUM HIGH
OPERATIONS LOCATION SULFUR (1) SULFUR (1) SULFUR(1) TOTAL
------------------- ------------------- ---------- ---------- --------- -------
(TONS IN MILLIONS)
Illinois Basin Operations
Dotiki Webster County, KY 73.2 73.2
Pattiki White County, IL 82.4 82.4
Hopkins County Hopkins County, KY 37.2 37.2
Coal
Gibson County Gibson County, IN 37.8 37.8
Coal (North)
Gibson County Gibson County, IN 10.9 44.1 49.2 104.2
Coal (South)
----- ----- ----- ------
Region Total 48.7 44.1 242.0 334.8
----- ----- ----- ------
East Kentucky Operations
Pontiki/Excel Martin County, KY 21.7 21.7
MC Mining Pike County, KY 23.7 23.7
Other Martin County, KY 1.3 1.3
----- ----- ----- ------
Region Total 46.7 - - 46.7
----- ----- ----- ------
Maryland Operations
Mettiki Garrett County, MD 38.6 38.6
Mettiki (WV) Grant and Tucker 20.1 20.1
County, WV
----- ----- ----- ------
- 58.7 - 58.7
----- ----- ----- ------
Total 95.4 102.8 242.0 440.2
===== ===== ===== ======
% of Total 21.7% 23.3% 55.0% 100.0%
(1) We classify low-sulfur coal as coal with a sulfur content of
less than 1%, medium-sulfur coal as coal with a sulfur content
between 1% and 2% and high-sulfur coal as coal with a sulfur
content of greater than 2%.
Our reserve estimates are prepared from geological data assembled and
analyzed by our staff of geologists and engineers. This data is obtained through
our extensive, ongoing exploration drilling and in-mine channel sampling
programs. Reserve estimates will change from time to time in reflection of
mining activities, analysis of new engineering and geological data, acquisition
or divestment of reserve holdings, modification of mining plans or mining
methods, and other factors.
We estimate that approximately 68 million tons of our reserves, or
approximately 71% of our low-sulfur reserves and 15% of our total reserves at
December 31, 1999, meet compliance standards for Phase II of the Clean Air Act
Amendments. Compliance coal consists of coal that emits less than 1.2 pounds of
SO(2) per million Btu.
We lease almost all of our reserves and generally have the right to
maintain the lease in force until the exhaustion of minable and merchantable
coal located within the leased premises or a larger coal reserve area. These
leases provide for royalties to be paid to the lessor at a fixed amount per ton
or as a percentage of the sales price. Many leases require payment of minimum
royalties, payable either at the time of the execution of the lease or in
periodic installments, even if no mining activities have begun. These minimum
royalties are normally credited against the production royalties owed to a
lessor once coal production has commenced.
In connection with our corporate reorganization and subsequent IPO, we
obtained the consents of our lessors or determined that obtaining such consents
was not required. Although we believe we have obtained all necessary consents,
in the event that we have failed to obtain a necessary consent, our operations
may be adversely impacted if we experience any disruption of our mining
operations as a consequence. As noted in our Form S-1 filed in connection with
the IPO, we previously requested that the lessor of a portion of our reserves at
the MC Mining and Pontiki/Excel mines, Big Sandy Management, Inc., confirm that
a consent to these transactions was not necessary. As of the date of this annual
report on Form 10-K, Big Sandy, specifically notified of this transaction in
September of 1999, has made no assertion that its consent was required, nor has
it confirmed in writing that a consent was not necessary. While we continue to
believe that this consent was not required, we cannot assure you what the
ultimate outcome will be with respect to this matter.
16
For economic and other operational reasons, a portion of our reserves
described above may be mined only after the construction of additional mining
facilities. The extent to which we will eventually mine our reserves will depend
on the price and demand for coal of the quality and type we control, the price
and supply of alternative fuels, and future mining practices and regulations.
RISK FACTORS
If any of the following risks were actually to occur, our business,
financial condition or results of operations could be materially adversely
affected and the trading price of our common units could decline.
Risks Inherent in Our Business
- Competition within the coal industry may adversely affect our
ability to sell coal, and excess production capacity in the industry
could put downward pressure on coal prices in the future.
- Current conditions in the coal industry may 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
affect our ability to sell coal.
- Litigation relating to disputes with our customers may result in
substantial costs, liabilities and loss of revenues.
- A loss of the benefit from state tax credits may affect adversely
our financial condition and results of operations.
- Coal mining is subject to inherent risks that are beyond our
control, and we cannot assure you that these risks will be fully
covered under our insurance policies.
- We depend on third party service providers to produce a portion of
our coal. If these providers' services were no longer available, our
ability to produce and sell coal would be adversely affected.
- Any significant increase in transportation costs or disruption of
the transportation of our coal may impair our ability to sell coal.
- We may not be able to grow successfully through future acquisitions,
and we may not be able to effectively integrate the various
businesses or properties we do acquire.
- Our business may be adversely affected if we are unable to replace
our coal reserves.
- The estimates of our reserves may prove inaccurate, and you should
not place undue reliance on these estimates.
17
- Our indebtedness may limit our ability to borrow additional funds,
make distributions to Unitholders or capitalize on business
opportunities.
- We are required to place and maintain bonds to secure our
obligations to return mined property to its original condition. The
failure to do so could result in fines and the loss of our mining
permits.
Risks Inherent in an Investment in Alliance Resource Partners
- Unitholders have limited voting rights and do not control our
Managing GP.
- We may issue additional Common Units without the approval of Common
Unitholders, which would dilute existing Unitholders' interests.
- The issuance of additional Common Units, including upon conversion
of Subordinated Units, will increase the risk that we will be unable
to pay the full minimum quarterly distribution on all Common Units.
- Cost reimbursements due to our General Partners may be substantial
and will reduce our cash available for distribution.
- Our Managing GP has a limited call right that may require
Unitholders to sell their Common Units at an undesirable time or
price.
- Unitholders may not have limited liability under some circumstances.
- Cash distributions are not guaranteed and may fluctuate with our
performance. In addition, our Managing GP's discretion in
establishing reserves may negatively impact your receipt of cash
distributions.
Regulatory Risks
- We are subject to federal, state and local regulation on numerous
matters. These regulations increase our costs of doing business and
may 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.
- The passage of legislation responsive to the Framework Convention on
Global Climate Change could result in a reduced use of coal by
electric power generators. This reduction in use could adversely
affect our revenues and results of operations.
- We are subject to the Clean Water Act, which imposes limitations and
monitoring and reporting obligations on our discharge of pollutants
into water.
- We are subject to reclamation, mine closure and real property
restoration regulations and must accrue for the estimated cost of
complying with these regulations.
- We and our customers could incur significant costs under federal and
state Superfund and waste management statutes.
Tax Risks to Common Unitholders
- The IRS could in the future choose to treat us as a corporation,
which would substantially reduce the cash available for distribution
to Unitholders.
- We have not requested an IRS ruling with respect to our tax
treatment.
18
- You may be required to pay taxes on income from us even if you
receive no cash distributions.
- Tax gain or loss on disposition of Common Units could be different
than expected.
- Common Unitholders, other than individuals who are U.S. residents,
may have adverse tax consequences from owning Units.
- We have registered with the IRS as a tax shelter. This may increase
the risk of an IRS audit of us or a Common Unitholder.
- We treat a purchaser of Common Units as having the same tax benefits
as the seller; the IRS may challenge this treatment which could
adversely affect the value of the Common Units.
- Common Unitholder will likely be subject to state and local taxes as
a result of an investment in units.
ITEM 3. LEGAL PROCEEDINGS
We are subject to various types of litigation in the ordinary course of
our business. Disputes with our customers over the provisions of long-term coal
supply contracts arise occasionally and generally relate to, among other things,
coal quality, pricing, quantity, and the existence of force majeure conditions.
Although we are not currently involved in any litigation involving our long-term
coal supply contracts, we cannot assure you that disputes will not occur in the
future or that we will be able to resolve those disputes in a satisfactory
manner. Other than the litigation with Seminole Electric Cooperative, Inc.
described in Item 8. Financial Statements and Supplementary Data. -- Note 14.
Commitments and Contingencies, we are not engaged in any litigation which we
believe is material to our operations. In addition, we are not aware of any
legal proceedings against us under the various environmental protection statutes
to which we are subject.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITIES HOLDERS
None.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED UNITHOLDER MATTERS
The Common Units representing limited partners' interest are listed on
the Nasdaq National Market under the symbol "ARLP." The Common Units began
trading on August 20, 1999, when the market price for the IPO of the Common
Units was $19.00 per unit. On March 23, 2000 the closing market price for the
Common Units was $12.88 per unit. There were approximately 6,700 record holders
and beneficial owners at December 31, 1999 (held in street name) of the
Partnership's Common Units.
The following table sets forth, the range of high and low sales price per
Common Unit and the amount of cash distribution declared with respect to the
Units, for each quarterly period since commencement of operations on August 20,
1999.
[Download Table]
HIGH LOW DISTRIBUTIONS PER UNIT
---- --- ----------------------
3rd Quarter 1999 (from $ 19.06 $ 13.50 $0.23 (paid November 12, 1999 for
August 20, 1999) the period from August 20, 1999,
through September 30, 1999)
4th Quarter 1999 $ 14.75 $ 12.00 $0.50 (paid February 14, 2000)
19
The Partnership has also issued 6,422,531 Subordinated Units, all of
which are held by the Special GP, for which there is no established public
trading market.
The Partnership will distribute to its partners (including holders of
Subordinated Units), on a quarterly basis, all of its Available Cash. Available
Cash generally means, with respect to any quarter of the Partnership, all cash
on hand at the end of each quarter less reserves in the amount of cash reserves
necessary or appropriate in the reasonable discretion of the Managing GP to (a)
provide for the proper conduct of the Partnership's business, (b) comply with
applicable law of any debt instrument or other agreement of the Partnership or
any of its affiliates, or (c) provide funds for distributions to unitholders
and the General Partners for any one or more of the next four quarters.
Available Cash is defined in the Partnership Agreement listed as an exhibit of
this annual report on Form 10-K. The Partnership Agreement defines minimum
quarterly distributions 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 minimum quarterly
distributions for each quarter during the subordination period, and to receive
any arrearages in the distribution of the minimum quarterly distributions on the
Common Units for prior quarters during the subordination period. The
subordination period will generally not end before September 30, 2004. Under
certain circumstances, up to half of the Subordinated Units may convert into
Common Units before the end of the subordination period, which will generally
not occur before September 30, 2003.
ITEM 6. SELECTED FINANCIAL DATA
On August 20, 1999, the Partnership completed its IPO whereby the
Partnership became the successor to the business of the Predecessor. Our
selected pro forma and historical financial data below was derived from the
audited consolidated financial statements of the Partnership as of December 31,
1999, and for the period from commencement of the Partnership's operations on
August 20, 1999 to December 31, 1999, the audited combined financial statements
of the Predecessor, as of August 19, 1999, and for the period from January 1,
1999, to August 19, 1999, as of and for the years ended December 31, 1998, and
1997, and as of and for the five months ended December 31, 1996. The Predecessor
purchased the coal operations of MAPCO Inc. effective August 1, 1996, in a
business combination using the purchase method of accounting and the purchase
price was allocated to the assets acquired and liabilities assumed based on
their fair values. Accordingly, the audited financial data for periods prior to
August 1, 1996, is not necessarily comparable to subsequent periods. The
unaudited historical financial data below as of and for the year ended December
1995 is derived from the financial statements of the Predecessor. In our
opinion, the unaudited financial statements include all adjustments, consisting
only of normal recurring adjustments, necessary for a fair presentation of the
results of the unaudited period. The amounts in the table, below, except for the
per unit data and the per ton information, are in millions.
20
[Enlarge/Download Table]
Partnership Predecessor
------------------------------- --------------------------------
From
Commencement For the
of Operations (on period from
Pro Forma August 20, 1999) January 1, 1999 Year Ended
Year Ended to to December 31,
December 31, December 31, August 19, --------------
1999 (1) 1999 1999 1998
-------------- -------------- -------------- --------------
STATEMENT OF OPERATIONS:
Sales and operating revenues
Coal sales $ 345.9 $ 128.8 $ 217.0 $ 357.4
Other sales and operating revenues 0.9 0.4 0.6 4.5
-------------- -------------- -------------- --------------
Total revenues 346.8 129.2 217.6 361.9
-------------- -------------- -------------- --------------
Expenses
Operating expenses 242.0 89.9 152.1 237.6
Outside purchases 24.2 6.4 17.7 51.2
General and administrative 15.1 6.2 8.9 15.3
Depreciation, depletion and amortization 39.7 15.1 24.6 39.8
Interest expense 19.4 5.9 0.1 0.2
Unusual items (2) -- -- -- 5.2
-------------- -------------- -------------- --------------
Total expenses 340.4 123.5 203.4 349.3
-------------- -------------- -------------- --------------
Income (loss) from operations 6.4 5.7 14.2 12.6
Other income (expense) 1.2 0.6 0.5 (0.1)
-------------- -------------- -------------- --------------
Income (loss) before income taxes 7.6 6.3 14.7 12.5
Income tax expense (benefit) 4.5 3.8
-------------- -------------- -------------- --------------
Net income (loss) $ 7.6 $ 6.3 $ 10.2 $ 8.7
============== ============== ============== ==============
Basic and diluted net income per
limited partner unit $ 0.48 $ 0.40
============== ==============
Weighted average number of limited
partner units outstanding 15,405,311 15,405,311
============== ==============
BALANCE SHEET DATA:
Working capital (3) -- $ 61.3 $ 11.2 $ 7.1
Total assets -- 314.8 262.8 261.1
Long-term debt -- 230.0 1.8 1.7
Total liabilities -- 330.7 110.2 108.3
Net Parent investment -- -- 151.6 152.8
Partners' equity (deficit) -- (15.9) -- --
OTHER OPERATING DATA:
Tons sold 15.0 5.6 9.4 15.1
Tons produced 14.1 5.3 8.8 13.4
Revenues per ton sold $ 23.12 $ 23.07 $ 23.15 $ 23.97
Cost per ton sold (4) $ 18.75 $ 18.30 $ 19.01 $ 20.14
OTHER FINANCIAL DATA:
EBITDA (5) $ 66.7 $ 27.3 $ 39.4 $ 52.5
Net cash provided by (used in) operating activities -- (14.7) 32.9 50.5
Net cash used in investing activities -- (43.1) (21.5) (35.6)
Net cash provided by (used in) financing activities -- 65.8 (11.4) (14.9)
Maintenance capital expenditures (6) 6.0 6.0 15.5 17.2
Predecessor
--------------------------------------------------------------------
Five Seven
Year Ended Months Months Year
December 31, Ended Ended Ended
-------------- December 31, July 31, December 31,
1997 1996 1996 1995
-------------- -------------- -------------- --------------
STATEMENT OF OPERATIONS:
Sales and operating revenues
Coal sales $ 305.3 $ 133.9 $ 184.1 $ 294.6
Other sales and operating revenues 8.5 4.4 7.5 16.4
-------------- -------------- -------------- --------------
Total revenues 313.8 138.3 191.6 311.0
-------------- -------------- -------------- --------------
Expenses
Operating expenses 197.4 79.2 110.7 173.1
Outside purchases 49.8 34.7 45.7 69.7
General and administrative 15.4 5.9 7.3 10.9
Depreciation, depletion and amortization 33.7 11.9 7.7 24.8
Interest expense -- -- -- --
Unusual items (2) -- -- -- 107.5
-------------- -------------- -------------- --------------
Total expenses 296.3 131.7 171.4 386.0
-------------- -------------- -------------- --------------
Income (loss) from operations 17.5 6.6 20.2 (75.0)
Other income (expense) 0.5 0.3 -- --
-------------- -------------- -------------- --------------
Income (loss) before income taxes 18.0 6.9 20.2 (75.0)
Income tax expense (benefit) 4.3 (0.9) 5.5 (32.2)
-------------- -------------- -------------- --------------
Net income (loss) $ 13.7 $ 7.8 $ 14.7 $ (42.8)
============== ============== ============== ==============
Basic and diluted net income per
limited partner unit
Weighted average number of limited
partner units outstanding
BALANCE SHEET DATA:
Working capital (3) $ 10.3 $ 15.9 $ 24.6 $ 32.4
Total assets 245.8 262.0 270.7 254.9
Long-term debt 1.9 -- -- --
Total liabilities 87.0 85.8 85.0 83.9
Net Parent investment 158.8 176.2 185.7 171.0
Partners' equity (deficit) -- -- -- --
OTHER OPERATING DATA:
Tons sold 12.4 5.1 6.9 10.9
Tons produced 10.9 3.9 5.3 8.8
Revenues per ton sold $ 25.31 $ 27.12 $ 27.77 $ 28.53
Cost per ton sold (4) $ 21.18 $ 23.49 $ 23.72 $ 23.28
OTHER FINANCIAL DATA:
EBITDA (5) $ 51.7 $ 18.8 $ 27.9 $ (50.2)
Net cash provided by (used in) operating activities 53.2 23.0 16.7 16.0
Net cash used in investing activities (22.4) (13.0) (16.7) (17.7)
Net cash provided by (used in) financing activities (30.8) (10.0) -- 1.7
Maintenance capital expenditures (6) 15.2 2.7 10.8 14.9
(1) The unaudited selected pro forma financial and operating data for the year
ended December 31, 1999, is based on the historical financial statements of
the Partnership from the Partnership's commencement of operations on August
20, 1999, through December 31, 1999, and the Predecessor for the period
from January 1, 1999, through August 19, 1999. The pro forma results of
operations reflect certain pro forma adjustments to the historical results
of operations as if the Partnership had been formed on January 1, 1999. The
pro forma adjustments include (a) pro forma interest on debt assumed by the
Partnership and (b) the elimination of income tax expense as income taxes
will be borne by the partners and not the Partnership. The pro forma
adjustments do not include approximately $1.0 million of general and
administrative expenses that the Partnership believes will be incurred as a
result of its being a public entity.
(2) Represents impairment of long-lived assets in 1995 and the net loss
incurred during the temporary closing of one of our mining complexes in the
second half of 1998. The impairment of long-lived assets in 1995 represents
the impairment loss recorded in accordance with Statement of Financial
Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to Be Disposed Of" to reduce the net book
value of the predecessor entity to the estimated purchase price, net of
related transaction fees, from the sale to The Beacon Group and management.
The letter of intent for the sale was entered into in December 1995, and
the related stock purchase agreement was finalized with an effective date
beginning August 1, 1996.
21
(3) Excludes accounts receivable from affiliates for the Predecessor prior to
July 31, 1996. No such receivables are present for the Partnership or the
Predecessor for all periods subsequent to July 31, 1996.
(4) Cost per ton is based on the total of operating expenses, outside purchases
and general and administrative expenses divided by tons sold.
(5) EBITDA is defined as income (loss) before interest expense, income taxes
and depreciation, depletion and amortization. EBITDA has not been adjusted
to add back unusual items. EBITDA should not be considered as an
alternative to net income, income (loss) before income taxes, cash flows
from operating activities or any other measure of financial performance
presented in accordance with generally accepted accounting principles.
EBITDA is not intended to represent cash flow and does not represent the
measure of cash available for distribution, but provides additional
information for evaluating our ability to make the minimum quarterly
distribution.
(6) Maintenance capital expenditures for the Partnership, as defined under the
terms of the partnership agreement, are defined as those capital
expenditures required to maintain, over the long term, the operating
capacity of our capital assets. Maintenance capital expenditures for the
Predecessor reflect our historical designation of maintenance capital
expenditures.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
GENERAL
The following discussion of the financial condition and results of
operations for the Partnership and its Predecessor should be read in conjunction
with the historical financial statements and notes thereto included elsewhere in
this annual report on Form 10-K. For more detailed information regarding the
basis of presentation for the following financial information, see "Item 8.
Financial Statements and Supplementary Data. -- Note 1. Organization and
Presentation."
We are a diversified producer and marketer of coal to major United
States utilities and industrial users. In 1999, our total production was 14.1
million tons and our total sales were 15.0 million tons. The coal we produced in
1999 was approximately 19.9% low-sulfur coal, 19.9% medium-sulfur coal and 60.2%
high-sulfur coal.
At December 31, 1999, we had approximately 440 million tons of proven
and probable coal reserves in Illinois, Indiana, Kentucky, Maryland and West
Virginia. We believe we control adequate reserves to implement our currently
contemplated mining plans. In addition, there are substantial unleased reserves
on adjacent properties that we intend to acquire or lease as our mining
operations approach these areas.
In 1999, approximately 77% of our sales tonnage was consumed by
electric utilities with the balance consumed by cogeneration plants and
industrial users. Our largest customers in 1999 were Seminole Electric
Cooperative, Inc., Tennessee Valley Authority, and Virginia Electric and Power
Company. We have had relationships with each of these customers for at least 15
years. In 1999, approximately 75% of our sales tonnage, including approximately
84% of our medium- and high-sulfur coal sales tonnage, was sold under long-term
contracts. The balance of our sales were made on the spot market. In June 1999,
we entered into a long-term contract to provide 23 million tons of low-sulfur
coal to PSI Energy, Inc., a subsidiary of Cinergy Corporation, through December
2012. Our long-term contracts contribute to our stability and profitability by
providing greater predictability of sales volumes and sales prices. In 1999,
approximately 85% of our medium- and high-sulfur coal was sold to utility plants
with installed pollution control devices, also known as scrubbers, to remove
sulfur dioxide.
One of our business strategies is to continue to make productivity
improvements to remain a low cost producer in each region in which we operate.
Our principal expenses related to the production of coal are labor and benefits,
22
equipment, materials and supplies, maintenance, royalties and excise taxes.
Unlike most of our competitors in the eastern United States, we employ a totally
union-free workforce. Many of the benefits of the union-free workforce are not
necessarily reflected in direct costs, but are related to higher productivity.
In addition, while we do not pay our customers' transportation costs, they may
be a 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 United States. We believe this gives us a transportation cost advantage
compared to many of our competitors.
In 1998 and 1999, our financial performance was impacted by the
following:
- In January 1998, we acquired the assets that comprise our Hopkins
County Coal operations for approximately $7.3 million in cash and
direct acquisition costs of $0.8 million. In accordance with our
acquisition plan, we spent approximately $9.4 million to rebuild
older equipment and purchase new or refurbished equipment. We began
to realize higher productivity as a result of these capital
investments beginning in the third quarter of 1998 and have
continued to realize the full impact of these efficiencies during
1999.
- In September 1998, we suspended operations at our Pontiki mine
and terminated all 267 members of our workforce due to adverse
market conditions. While we had originally intended to idle the
mine for an indefinite period, we were able to procure a new
long-term coal supply agreement with A.E.I. Coal Sales, Inc.,
justifying re-opening the mine in late 1998. Under this coal supply
agreement, we shipped 1.1 million tons during 1999. This agreement
provides for the shipment of 1.5 million tons per year during the
seven-year period of January 1, 2000, to December 31, 2006. As a
result, this operation was restructured with a new mine plan,
operating structure, and workforce hired by Excel Mining, LLC, an
affiliate of Pontiki Coal, LLC. While idled, the mine incurred a
net loss of approximately $5.2 million, consisting of workers'
compensation accruals of $1.2 million and severance payments
consistent with the WARN Act, of $1.2 million as well as the costs
associated with maintaining an idled mine of $2.8 million. The $1.2
million of wage costs associated with the WARN Act have been paid.
The $1.2 million of workers' compensation accruals is management's
estimate of amounts that may be required to be paid to certain
former Pontiki miners who may pursue worker compensation claims. Of
this estimated amount, approximately $400,000 is expected to be
paid over three years, $500,000 over eight years and $300,000 over
thirty years. The timing of these payments is governed by the level
and type of award (for example, permanent total disability,
permanent partial disability and legal and medical expenses) which
management has estimated based on past experience. Other than the
$1.2 million of workers' compensation accruals already recorded by
Pontiki, we do not believe there are any additional workers'
compensation costs to be accrued in connection with the suspension
of operations at Pontiki and the termination of its workforce.
During late 1998 and early 1999, Pontiki/Excel's cost per ton was
adversely impacted by reduced production as the new mine plan was
implemented and the mine moved toward its current higher production
level.
- We conduct a coal brokerage business, which markets both steam
and metallurgical coals. Because our coal brokerage operations
generate lower margins than our direct coal sales, changes in our
levels of brokerage activity have a greater impact on revenues than
on margins. Since 1996, we have experienced a steady decline in
brokerage sales, most of which are for export. These declining
volumes are largely attributable to competition from lower cost
foreign production. The brokerage business is not expected to be a
material part of our business in the future.
23
RESULTS OF OPERATIONS
In comparing 1999 to 1998, the Partnership and Predecessor periods for
1999 have been combined. Since the Partnership maintained the historical basis
of the Predecessor's net assets, management believes that the combined
Partnership and Predecessor results for 1999 are comparable with 1998. The
interest expense associated with the debt incurred concurrent with the closing
of the IPO is applicable only to the Partnership period. See "Item 8. Financial
Statements and Supplementary Data. -- Note 1. Organization and Presentation."
1999 Compared with 1998
Coal sales. Coal sales for 1999 declined 3.2% to $345.9 million from
$357.4 million for 1998. The decrease of $11.5 million is primarily attributable
to lower coal export brokerage volumes partially offset by improved results from
the Partnership's restructured Pontiki/Excel operation and full-year benefits
from the capital invested at the Hopkins County Coal operation. The lower
brokerage volumes are largely attributable to reduced participation in coal
export brokerage markets. The brokerage business is not expected to be material
in the future. Because the coal brokerage operations generate lower margins than
direct coal sales, changes in the levels of brokerage activity have a greater
impact on revenues and outside purchases than on margins. Tons sold decreased
less than 1.0% to 15.0 million tons for 1999 from 15.1 million tons for 1998.
Tons produced increased 5.1% to 14.1 million tons for 1999 from 13.4 million
tons for 1998.
Other sales and operating revenues. Other sales and operating revenues
declined 79.0% to $0.9 million for 1999 from $4.5 million from 1998. The
decrease of $3.6 million was primarily due to lower volumes at the Mt. Vernon
facility due to the dispute with Seminole Electric Cooperative, Inc. See "Item
8. Financial Statements and Supplementary Data. -- Note 14. Commitments and
Contingencies."
Operating expenses. Operating expenses were comparable for 1999 and 1998
at $242.0 million and $237.6 million, an increase of 1.9%.
Outside purchases. Outside purchases declined 52.8% to $24.2 million for
1999 from $51.2 million for 1998. The decrease of $27.0 million was the result
of lower coal export brokerage volumes. See coal sales above concerning the
decrease in coal export brokerage volumes.
General and administrative. General and administrative expenses were
comparable for 1999 and 1998 at $15.2 million and $15.3 million, a decrease of
less than 1.0%
Depreciation, depletion and amortization. Depreciation, depletion and
amortization expense were comparable for 1999 and 1998 at $39.7 million and
$39.8 million, a decrease of less than 1.0%
Unusual item. In response to market conditions, the Pontiki mine ceased
operations and terminated substantially all of its workforce in September 1998.
During the idle status period, which ended in November 1998, Pontiki incurred a
net loss of approximately $5.2 million consisting of estimated amounts for
increased workers' compensation claims of $1.2 million and severance payments
consistent with the WARN Act of $1.2 million as well as the costs associated
with maintaining an idled mine of $2.8 million.
Income before income taxes. Income before income taxes increased 67.3% to
$21.0 million for 1999 compared to $12.5 million for 1998. The increase of $8.5
million was primarily attributable to improved productivity, which includes the
benefits of the restructured operation at Pontiki/Excel following the idle
status period of the mine, which resulted in the $5.2 million unusual item
recorded in 1998 as discussed above, and the capital investments at the Hopkins
County Coal operation, partially offset by the losses incurred at Mt. Vernon due
to the dispute with Seminole Electric Cooperative, Inc.
Income tax expense. The Partnership is a limited partnership. As a
result, the Partnership's earnings or losses for federal income taxes purposes
will be included in the tax returns of the individual partners. Accordingly, no
recognition
24
has been given to income taxes in the accompanying financial statements of the
Partnership. The Predecessor is included in the consolidated federal income tax
return of ARH. Federal and state income taxes are calculated as if the
Predecessor had filed its return on a separate company basis utilizing an
effective income tax rate of 31%.
EBITDA. EBITDA (income from operations before net interest expense,
income taxes, depreciation, and depletion and amortization) increased 26.9% to
$66.7 million for 1999 compared with $52.5 million for 1998. The $14.2 increase
is attributable to the same factors that contributed to the increase in income
before income taxes.
1998 Compared With 1997
Coal sales. Coal sales increased 17.1% to $357.4 million for 1998 from
$305.3 million for 1997. Total tons sold increased 21.8% to 15.1 million tons
for 1998 from 12.4 million tons for 1997. The increase of $52.1 million in coal
sales is attributable primarily to:
- the acquisition of Hopkins County Coal in January 1998 which
accounted for $41.1 million of our increased sales;
- increased volumes at MC Mining which accounted for $6.8 million
of our increased sales; and
- increased shipments at Dotiki, Pattiki and Mettiki which
accounted for $16.1 million of our increased sales.
The increase in coal sales was partially offset by lower sales at
Pontiki/Excel of $16.7 million reflecting lower productivity during 1998 and the
temporary suspension of operations in September 1998. Tons produced in 1998
increased 22.9% to 13.4 million tons from 10.9 million tons in 1997.
Other sales and operating revenues. Other sales and operating revenues
decreased 47.7% to $4.5 million for 1998 compared with $8.6 million for 1997. In
1997, other sales included the sale of coke to a foreign steel producer. The
decrease of $4.1 million was primarily due to a reduction in these coke sales.
Operating expenses. Operating expenses increased 20.4% to $237.6
million for 1998 from $197.4 million in 1997. The increase of $40.2 million in
operating expenses is attributable primarily to:
- the acquisition of Hopkins County Coal in January 1998, which
accounted for $42.9 million of our increased operating expenses;
and
- increased volumes at MC Mining, which accounted for $6.8 million
of our increased operating expenses.
The increase in operating expenses was partially offset by a reduction
of operating expenses of $10.9 million at Pontiki/Excel reflecting lower
production during 1998 and the temporary suspension of operations in September
1998. Operating expense per ton sold decreased 4.9% to $20.14 in 1998 from
$21.18 in 1997, primarily due to increased productivity at our Dotiki and
Pattiki mines, offset by the higher cost per ton at our Pontiki mine.
Outside purchases. Outside purchases of coal and coke increased 2.8% to
$51.2 million in 1998 from $49.8 million in 1997. The increase of $1.4 million
was the result of higher coal brokerage volumes offset by a reduction in coke
sales.
General and administrative. General and administrative expenses were
comparable for 1998 and 1997 at $15.3 million and $15.4 million, a decrease of
less than 1.0%
Depreciation, depletion and amortization. Depreciation, depletion and
amortization increased 18.1% to $39.8 million for 1998 compared with $33.7
million for 1997. The increase of $6.1 million was primarily due to the
acquisition of the Hopkins County Coal operation.
25
Unusual item. Pontiki/Excel ceased operations from September to
November 1998. While idled, the mine incurred a net loss of approximately $5.2
million, consisting of workers' compensation accruals and severance payments
consistent with the federal WARN Act, as well as the costs associated with
maintaining an idled mine.
Income tax expense. Income tax expense was $3.9 million for 1998 and
$4.3 million for 1997. The effective rate increased to 31% in 1998 compared with
24% in 1997. The increase in the effective rate is primarily attributable to an
increase in the deferred tax asset valuation allowance partially offset by the
additional benefit of excess of tax over book depletion.
EBITDA. EBITDA (income from operations before net interest expense,
income taxes, depreciation, and depletion and amortization) was comparable for
1998 and 1997 at $52.5 million and $51.7 million, which represents an increase
of 1.6%.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
Cash provided by operating activities was $18.2 million in 1999
compared to $50.5 million in 1998. The decrease in cash flows provided by
operating activities is principally attributable to the increase in trade
receivables subsequent to the IPO and concurrent transactions that occurred on
August 20, 1999. In conjunction with these transactions, the Special GP retained
approximately $37.9 million of trade receivables.
Net cash used in investing activities increased to $64.7 million in
1999 compared to $35.6 million in 1998. The increase in net cash used in
investing activities is principally attributable to the purchase of U.S.
Treasuries and the capital expenditures described below.
Net cash provided by financing activities was $54.4 million for 1999
compared to net cash used in financing activities of $14.9 million for 1998. The
increase in cash provided by financing activities is principally attributable to
the IPO and concurrent transactions that occurred on August 20, 1999.
Capital Expenditures
Capital expenditures increased to $39.2 million in 1999 compared to
$27.7 million in 1998. The increase is primarily attributable to a major
enhancement of the Dotiki preparation plant and a coal reserve acquisition
contiguous to the Dotiki mine. The Partnership liquidated approximately $8.4
million of U.S Treasury Notes to fund various qualifying capital expenditures
with the remaining expenditures funded through cash generated from operations.
We currently expect that our average annual maintenance capital expenditures
will be approximately $21.0 million. We currently expect to fund our anticipated
capital expenditures with cash generated from operations and the utilization of
the revolving credit facility described below.
Notes Offering and Credit Facility
Concurrently with the closing of the IPO, the Special GP issued and the
Intermediate Partnership assumed the obligations under $180 million principal
amount of 8.31% senior notes due August 20, 2014. The Special GP also entered
into and the Intermediate Partnership assumed the obligations under a $100
million credit facility. The credit facility consists of three tranches,
including a $50 million term loan facility, a $25 million working capital
facility and a $25 million revolving credit facility. The Partnership has drawn
$50 million under the term loan facility but has not drawn any money under
either the working capital facility or the revolving credit facility. The
weighted average interest rate on the term loan facility at December 31, 1999,
was 7.07%. The credit facility agreement expires August 2004. The senior notes
and credit facility are secured by a pledge of the stock of all of the
subsidiaries of Alliance Coal, LLC. The senior notes and credit facility contain
various restrictions and affirmative covenants, including the amount of
distributions by the Intermediate Partnership and the incurrence of other debt.
26
Accruals of Other Liabilities
We accrue for costs we will incur in the future to satisfy obligations.
We have accrued for deferred credits and other liabilities, including current
obligations totaling $61.9 million and $64.3 million at December 31, 1999 and
1998. These accruals are chiefly comprised of workers' compensation benefits,
black lung benefits, and costs associated with reclamation and mine closing.
These obligations are self-insured and are funded at the time the expense is
incurred. The accruals of these items are based on estimates of future
liabilities, planned legislation and other developments. Thus, from time to
time, the Partnership's results of operations may be significantly affected by
changes to these deferred credits and other liabilities. See "Item 8. Financial
Statements and Supplementary Data. -- Note 11. Reclamation and Mine Closing
Costs and Note 12. Pneumoconiosis ("Black Lung") Benefits."
We are required to pay black lung benefits to eligible and former
employees under the Black Lung Benefits Act of 1969, the Black Lung Benefits
Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977. We also are
liable under various state statutes for similar claims. We provide self-insured
accruals for present and future liabilities for these benefits. We have accrued
liabilities of $22.2 million and $22.7 million for these benefits at December
31, 1999 and 1998.
We accrue for costs associated with reclamation and mine closing. We
have estimated the costs and timing of future reclamation and mine closing costs
and recorded those estimates on a present value basis. We have accrued
liabilities of $14.8 million and $13.8 million at December 31, 1999 and 1998 for
these costs.
We accrue for workers' compensation claims resulting from traumatic
injuries based on actuarial valuations and periodically adjust these estimates
based on the estimated costs of claims made. We have accrued liabilities of
$19.5 million and $18.1 million at December 31, 1999 and 1998 for these costs.
INFLATION
Inflation in the United States has been relatively low in recent years
and did not have a material impact on our results of operations for the years
ended December 31, 1999, 1998 or 1997.
IMPACT OF YEAR 2000 ISSUE
The year 2000 issue was the result of computer programs being written
using two digits rather than four to define the applicable year. Any software,
hardware and equipment and embedded chip systems that are date-sensitive may
recognize a date using "-00" as the year 1900 rather than the year 2000.
We completed our year 2000 readiness assessment to identify, remedy and
test our year 2000 systems compliance, including but not limited to, financial
systems applications, human resources and payroll systems applications, hardware
and equipment, and third-party developed software. Our project was completed on
schedule during the fourth quarter of 1999. Approximately $0.5 million was
incurred to modify, upgrade and/or replace non-compliant systems.
We have not experienced any significant impact on our systems or
operations as a result of the year 2000 issue. We do not expect any significant
problems in the future related to the year 2000 issue. However, we will continue
to monitor our systems.
RECENT ACCOUNTING PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" ("SFAS 133"). The statement establishes
accounting and reporting standards for derivative instruments and for hedging
activities. It requires that an entity recognize all derivatives as either
assets or liabilities in the statement of financial position and measure those
instruments at fair value. The Partnership has not determined the impact on its
financial statements that may
27
result from adoption of SFAS 133, which is required to be implemented by the
Partnership no later than January 1, 2001.
ITEM 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Almost all of the Predecessor's transactions were, and almost all of the
Partnership's transactions are, denominated in U.S. dollars, and as a result, it
does not have material exposure to currency exchange-rate risks.
The Predecessor did not, and the Partnership does not, engage in any
interest rate, foreign currency exchange rate or commodity price-hedging
transactions.
The Intermediate Partnership assumed obligations under a $100 million
credit facility. Borrowings under the credit facility are at variable rates and
as a result the Partnership has interest rate exposure.
The table below provides information about the Partnership's market
sensitive financial instruments and constitutes a "forward-looking statement."
The fair values of long-term debt are estimated using discounted cash flow
analyses, based upon the Partnership's current incremental borrowing rates for
similar types of borrowing arrangements as of December 31, 1999. The carrying
amounts and fair values of financial instruments are as follows (in thousands):
[Enlarge/Download Table]
FAIR VALUE
DECEMBER 31,
EXPECTED MATURITY DATES 2000 2001 2002 2003 2004 THEREAFTER TOTAL 1999
----------------------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
Senior Notes-fixed rate $ -- $ -- $ -- $ -- $ -- $ 180,000 $ 180,000 $ 165,000
Weighted Average interest rate 8.31%
Term Loan-floating rate $ -- $ 3,750 $ 15,000 $ 16,250 $ 15,000 $ -- $ 50,000 $ 50,000
Weighted Average interest rate 7.07% 7.07% 7.07% 7.07%
Since the long-term debt as of December 31, 1998 was immaterial and the
debt was retired during 1999, we did not include a table of long-term debt
maturities as of December 31, 1998.
28
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEPENDENT AUDITORS' REPORT
To the Board of Directors of the Managing General Partner and the Partners of
Alliance Resource Partners, L.P.:
We have audited the accompanying consolidated balance sheet of Alliance Resource
Partners, L.P. and subsidiaries (the "Partnership") as of December 31, 1999 and
the combined balance sheet of Alliance Resource Group (the "Predecessor") as of
December 31, 1998, the related consolidated and combined statements of income
and cash flows for the period from the Partnership's commencement of operations
(on August 20, 1999) to December 31, 1999 and the Predecessor period from
January 1, 1999 to August 19, 1999 and the years ended December 31, 1998 and
1997 and the statement of Partners' capital (deficit) for the period from the
Partnership's commencement of operations (on August 20, 1999) to December 31,
1999. These financial statements are the responsibility of the Partnership's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated and combined financial statements present
fairly, in all material respects, the financial position of the Partnership at
December 31, 1999 and the Predecessor at December 31, 1998 and the results of
their operations and their cash flows for the period from the Partnership's
commencement of operations (on August 20, 1999) to December 31, 1999 and the
Predecessor period from January 1, 1999 to August 19, 1999 and the years ended
December 31, 1998 and 1997 in conformity with accounting principles generally
accepted in the United States of America.
/s/ Deloitte & Touche LLP
Tulsa, Oklahoma
January 26, 2000, except for
Note 20 as to which the dates are
March 17, 2000 and March 23, 2000
29
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED AND COMBINED BALANCE SHEETS
DECEMBER 31, 1999 AND 1998
(IN THOUSANDS, EXCEPT UNIT DATA)
--------------------------------------------------------------------------------
[Enlarge/Download Table]
PARTNERSHIP PREDECESSOR
DECEMBER 31, DECEMBER 31,
ASSETS 1999 1998
-------------- --------------
CURRENT ASSETS:
Cash and cash equivalents $ 8,000 $ --
Trade receivables 33,056 31,268
Marketable securities (at cost, which approximates fair value) 42,339 --
Income tax receivable -- 503
Inventories 21,130 20,055
Advance royalties 1,557 2,501
Prepaid expenses and other assets 923 1,456
-------------- --------------
Total current assets 107,005 55,783
PROPERTY, PLANT AND EQUIPMENT AT COST 278,221 240,294
LESS ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION (102,709) (69,158)
-------------- --------------
175,512 171,136
OTHER ASSETS:
Advance royalties 8,306 8,880
Coal supply agreements, net 19,879 24,062
Other long-term assets 4,112 1,235
-------------- --------------
$ 314,814 $ 261,096
============== ==============
LIABILITIES AND PARTNERS' EQUITY
CURRENT LIABILITIES:
Accounts payable $ 19,377 $ 24,527
Due to affiliates 806 --
Accrued taxes other than income taxes 4,574 4,526
Accrued payroll and related expenses 8,811 9,269
Accrued interest 5,491 --
Workers' compensation and pneumoconiosis benefits 4,317 4,707
Other current liabilities 2,937 5,302
Current maturities, long-term debt -- 350
-------------- --------------
Total current liabilities 46,313 48,681
LONG-TERM LIABILITIES:
Long-term debt, excluding current maturities 230,000 1,687
Deferred income taxes -- 3,906
Accrued pneumoconiosis benefits 21,655 22,233
Workers' compensation 15,696 13,934
Reclamation and mine closing 13,407 12,824
Other liabilities 3,671 5,062
-------------- --------------
Total liabilities 330,742 108,327
COMMITMENTS AND CONTINGENCIES
NET PARENT INVESTMENT -- 152,769
PARTNERS' CAPITAL (DEFICIT):
Common Unitholders 8,982,780 units outstanding 158,705 --
Subordinated Unitholder 6,422,531 units outstanding 123,273 --
General Partners (297,906) --
-------------- --------------
Total Partners' capital (deficit) (15,928) --
-------------- --------------
$ 314,814 $ 261,096
============== ==============
See notes to consolidated and combined financial statements.
30
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED AND COMBINED STATEMENTS OF INCOME
FOR THE PERIOD FROM THE PARTNERSHIP'S COMMENCEMENT OF OPERATIONS (ON
AUGUST 20, 1999) TO DECEMBER 31, 1999 AND THE PREDECESSOR PERIOD FROM JANUARY 1,
1999 TO AUGUST 19, 1999, AND THE YEARS ENDED DECEMBER 31, 1998 AND 1997
(IN THOUSANDS, EXCEPT UNIT AND PER UNIT DATA)
--------------------------------------------------------------------------------
[Enlarge/Download Table]
PARTNERSHIP PREDECESSOR
-------------------- -----------------------------------------------
FROM
COMMENCEMENT FOR THE
OF OPERATIONS PERIOD FROM YEARS ENDED
(ON AUGUST 20, 1999) JANUARY 1, 1999 DECEMBER 31,
TO TO ------------------------
DECEMBER 31, 1999 AUGUST 19, 1999 1998 1997
-------------------- -------------------- ---------- ----------
SALES AND OPERATING REVENUES:
Coal sales $ 128,860 $ 217,033 $ 357,440 $ 305,270
Other sales and operating revenues 358 577 4,453 8,550
-------------------- -------------------- ---------- ----------
Total revenues 129,218 217,610 361,893 313,820
-------------------- -------------------- ---------- ----------
EXPENSES:
Operating expenses 89,945 152,066 237,576 197,422
Outside purchases 6,429 17,738 51,151 49,800
General and administrative 6,245 8,912 15,301 15,417
Depreciation, depletion and amortization 15,081 24,622 39,838 33,667
Interest expense (net of interest income of $999
for the partnership period) 5,887 100 169 29
Unusual item -- -- 5,211 --
-------------------- -------------------- ---------- ----------
Total operating expenses 123,587 203,438 349,246 296,335
-------------------- -------------------- ---------- ----------
INCOME FROM OPERATIONS 5,631 14,172 12,647 17,485
OTHER INCOME (EXPENSE) 641 531 (113) 520
-------------------- -------------------- ---------- ----------
INCOME BEFORE INCOME TAXES 6,272 14,703 12,534 18,005
INCOME TAX EXPENSE -- 4,498 3,866 4,288
-------------------- -------------------- ---------- ----------
NET INCOME $ 6,272 $ 10,205 $ 8,668 $ 13,717
==================== ==================== ========== ==========
GENERAL PARTNERS' INTEREST
IN NET INCOME $ 125
====================
LIMITED PARTNERS' INTEREST
IN NET INCOME $ 6,147
====================
BASIC AND DILUTED NET INCOME
PER LIMITED PARTNER UNIT $ 0.40
====================
WEIGHTED AVERAGE NUMBER
OF UNITS OUTSTANDING 15,405,311
====================
See notes to consolidated and combined financial statements.
31
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOW
FOR THE PERIOD FROM THE PARTNERSHIP'S COMMENCEMENT OF OPERATIONS (ON AUGUST 20,
1999) TO DECEMBER 31, 1999 AND THE PREDECESSOR PERIOD FROM JANUARY 1, 1999 TO
AUGUST 19, 1999, AND THE YEARS ENDED DECEMBER 31, 1998 AND 1997
(IN THOUSANDS)
--------------------------------------------------------------------------------
[Enlarge/Download Table]
PARTNERSHIP PREDECESSOR
-------------------- -----------------------------------------
FROM
COMMENCEMENT FOR THE
OF OPERATIONS PERIOD FROM YEARS ENDED
(ON AUGUST 20, 1999) JANUARY 1, 1999 DECEMBER 31,
TO TO --------------------
DECEMBER 31, 1999 AUGUST 19, 1999 1998 1997
-------------------- ----------------- -------- --------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 6,272 $ 10,205 $ 8,668 $ 13,717
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, depletion and amortization 15,081 24,622 39,838 33,667
Deferred income taxes -- 639 (1,750) (1,937)
Reclamation and mine closings 348 457 705 339
Coal inventory adjustment to market 729 -- 1,743 547
Other (605) (114) 34 134
Changes in operating assets and liabilities, net of effects
from 1998 purchase of coal business:
Trade receivables (33,048) (6,521) 229 11,955
Income tax receivable/payable -- 651 2,482 (3,539)
Inventories (1,433) (371) (6,563) (4,229)
Advance royalties 366 1,153 579 1,856
Accounts payable (7,410) (129) 2,296 (6,216)
Due to affiliates 3,252 -- -- --
Accrued taxes other than income taxes (630) 678 1,137 293
Accrued payroll and related benefits 844 (828) 491 1,666
Accrued pneumoconiosis benefits (1,122) 544 839 209
Workers' compensation 2,222 (460) 817 903
Other 452 2,370 (1,048) 3,860
-------------------- ----------------- -------- --------
Total net adjustments (20,954) 22,691 41,829 39,508
-------------------- ----------------- -------- --------
Net cash provided by (used in) operating activities (14,682) 32,896 50,497 53,225
-------------------- ----------------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Payment for purchase of business -- -- (7,310) --
Direct acquisition costs -- -- (821) --
Purchase of property, plant and equipment (17,173) (21,984) (27,669) (22,436)
Proceeds from sale of property, plant and equipment 125 447 185 49
Purchase of marketable securities (51,287) -- -- --
Proceeds from sale of marketable securities 25,225 -- -- --
-------------------- ----------------- -------- --------
Net cash used in investing activities (43,110) (21,537) (35,615) (22,387)
-------------------- ----------------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from initial public offering (Note 1) 137,872 -- -- --
Cash contribution by General Partner 5,917 -- -- --
Distributions upon formation (Note 1) (64,750) -- -- --
Payment of formation costs (4,140) -- -- --
Deferred financing cost (3,517) -- -- --
Payments on long-term debt (1,975) -- (350) --
Distribution to Partners (3,615) -- -- --
Dividend to Parent -- -- (8,642) (13,795)
Return of capital to Parent -- (11,359) (5,890) (17,043)
-------------------- ----------------- -------- --------
Net cash provided by (used in) financing activities 65,792 (11,359) (14,882) (30,838)
-------------------- ----------------- -------- --------
NET CHANGE IN CASH AND CASH EQUIVALENTS AND
BALANCE AT END OF PERIOD $ 8,000 $ -- $ -- $ --
==================== ================= ======== ========
See notes to consolidated and combined financial statements.
32
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL (DEFICIT)
FROM THE PARTNERSHIP'S COMMENCEMENT OF OPERATIONS (ON AUGUST 20, 1999) TO
DECEMBER 31, 1999
(IN THOUSANDS, EXCEPT UNIT DATA)
--------------------------------------------------------------------------------
[Enlarge/Download Table]
NUMBER OF LIMITED TOTAL
PARTNER UNITS MINIMUM PARTNERS'
------------------------ GENERAL PENSION CAPITAL
COMMON SUBORDINATED COMMON SUBORDINATED PARTNERS LIABILITY (DEFICIT)
--------- ------------ --------- ------------ --------- --------- ---------
Balance at commencement of
operations (on August 20, 1999) -- -- $ -- $ 1 $ -- $ -- $ 1
Issuance of units to public 7,750,000 -- 133,732 -- -- -- 133,732
Contribution of net assets of
Predecessor 1,232,780 6,422,531 23,455 122,186 (24,612) (459) 120,570
Managing General Partner
contribution -- -- -- -- 5,917 -- 5,917
Amount retained by Special
General Partner from
debt borrowings assumed
by the Partnership -- -- -- -- (214,514) -- (214,514)
Distribution at time of formation -- -- -- -- (64,750) -- (64,750)
Distribution to Partners -- -- (2,066) (1,477) (72) -- (3,615)
Comprehensive income:
Net income from commencement
of operations (on August 20,
1999) to December 31, 1999 -- -- 3,584 2,563 125 -- 6,272
Minimum pension liability -- -- -- -- -- 459 459
--------- ------------ --------- ------------ --------- --------- ---------
Total comprehensive income -- -- 3,584 2,563 125 459 6,731
--------- ------------ --------- ------------ --------- --------- ---------
Balance at December 31, 1999 8,982,780 6,422,531 $ 158,705 $ 123,273 $(297,906) $ -- $ (15,928)
========= ============ ========= ============ ========= ========= =========
See notes to consolidated and combined financial statements.
33
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS FOR THE PERIOD FROM THE
PARTNERSHIP'S COMMENCEMENT OF OPERATIONS (ON AUGUST 20, 1999) TO DECEMBER 31,
1999 AND THE PREDECESSOR PERIOD FROM JANUARY 1, 1999 TO AUGUST 19, 1999, AND THE
YEARS ENDED DECEMBER 31, 1998 AND 1997
--------------------------------------------------------------------------------
1. ORGANIZATION AND PRESENTATION
Alliance Resource Partners, L.P. is a Delaware limited partnership that was
formed on May 17, 1999, to acquire, own and operate certain coal production
and marketing assets of Alliance Resource Holdings, Inc., a Delaware
corporation ("ARH" or "Parent") (formerly known as Alliance Coal
Corporation) and substantially all of its operating subsidiaries
(collectively, the "Partnership").
Prior to August 20, 1999, (a) MAPCO Coal Inc., a Delaware corporation and
direct wholly-owned subsidiary of ARH merged with and into Alliance Coal,
LLC, a Delaware limited liability company ("Alliance Coal"), which prior to
August 20, 1999 was also a wholly-owned subsidiary of ARH, (b) several
other indirect corporate subsidiaries of ARH were merged with and into
corresponding limited liability companies, each of which is a wholly-owned
subsidiary of Alliance Coal and (c) two indirect limited liability
company subsidiaries of ARH became subsidiaries of Alliance Coal as a
result of the merger described in clause (a) above. Collectively, the coal
production and marketing assets and operating subsidiaries of ARH acquired
by the Partnership are referred to as the Alliance Resource Group (the
"Predecessor.") The Delaware limited partnerships and limited liability
companies that comprise the Partnership are as follows: Alliance Resource
Partners, L.P., Alliance Resource Operating Partners, L.P. (the
"Intermediate Partnership"), Alliance Coal, LLC (the holding company for
operations), Alliance Land, LLC, Alliance Properties, LLC, Backbone
Mountain, LLC, Excel Mining, LLC, Gibson County Coal, LLC, Hopkins County
Coal, LLC, MC Mining, LLC, Mettiki Coal, LLC, Mettiki Coal (WV), LLC, Mt.
Vernon Transfer Terminal, LLC, Pontiki Coal, LLC, Toptiki Coal, LLC,
Webster County Coal, LLC, and White County Coal, LLC.
The accompanying consolidated financial statements include the accounts and
operations of the limited partnerships and limited liability companies
disclosed above and present the financial position as of December 31, 1999
and the results of their operations, cash flows and changes in partners'
capital (deficit) for the period from commencement of operations on August
20, 1999 to December 31, 1999. All material intercompany transactions and
accounts have been eliminated. The accompanying combined financial
statements include the accounts and operations of the Predecessor for the
periods indicated. All significant intercompany transactions and accounts
have been eliminated.
Initial Public Offering and Concurrent Transactions
On August 20, 1999, the Partnership completed its initial public offering
(the "IPO") of 7,750,000 Common Units ("Common Units") representing limited
partner interests in the Partnership at a price of $19.00 per unit.
Concurrently with the closing of the IPO, the Partnership entered into a
contribution and assumption agreement (the "Contribution Agreement"), dated
August 20, 1999, among the Partnership and the other parties named therein,
whereby, among other things, ARH contributed its 100% member interest in
Alliance Coal, which is the sole member of fourteen subsidiary operating
limited liability companies, to the Intermediate Partnership, and the
Intermediate Partnership holds a 99.999% non-managing member interest in
Alliance Coal. The Partnership and the Intermediate Partnership are managed
by Alliance Resource Management GP, LLC, a Delaware limited liability
company (the "Managing GP"), which, as a result of the consummation of the
transactions under the Contribution Agreement, holds (a) a 0.99% and
1.0001% managing general partner interest in the Partnership and the
Intermediate Partnership, respectively, and (b) a 0.001% managing member
interest in Alliance Coal. Also, as a result of the consummation of the
transactions completed under the Contribution Agreement, Alliance Resource
GP, LLC, a Delaware limited liability company and wholly-owned subsidiary
of ARH (the "Special GP"), holds, (a) 1,232,780 Common Units, (b)
6,422,531 Subordinated Units ("Subordinated Units") convertible into Common
Units in the future upon the occurrence of certain events and (c) a 0.01%
special general partner interest in each of the Partnership and the
Intermediate Partnership.
34
Concurrently with the closing of the IPO, the Special GP issued and the
Intermediate Partnership assumed the obligations under a $180 million
principal amount of 8.31% senior notes due August 20, 2014. The Special GP
also entered into and the Intermediate Partnership assumed the obligations
under a $100 million credit facility.
Consistent with guidance provided by the Emerging Issues Task Force in
Issue No. 87-21 "Change of Accounting Basis in Master Limited Partnership
Transactions", the Partnership maintained the historical cost of the $121
million of net assets received under the Contribution Agreement.
Analysis of Pro Forma Results of Operations (Unaudited)
For the years ended December 31, 1999 and 1998, the pro forma total
revenues would have been approximately $346,828,000 and $361,893,000,
respectively. For the years ended December 31, 1999 and 1998, the pro forma
net income (loss) would have been approximately $7,567,000 and $(6,740,000)
and net income (loss) per limited partner unit would have been $0.48 and
$(0.43), respectively. The pro forma results of operations for the years
ended December 31, 1999 and 1998, are derived from the historical financial
statements of the Partnership from the commencement of operations on August
20, 1999 through December 31, 1999 and the Predecessor for the period from
January 1, 1999 through August 19, 1999, and January 1, 1998 through
December 31, 1998. The pro forma results of operations reflect certain pro
forma adjustments to the historical results of operations as if the
Partnership had been formed on January 1, 1998. The pro forma adjustments
include (i) pro forma interest on debt assumed by the Partnership and (ii)
the elimination of income tax expense as income taxes will be borne by the
partners and not the Partnership.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ESTIMATES - The preparation of consolidated and combined financial
statements in conformity with generally accepted accounting principles
requires management to make estimates and assumptions that affect the
reported amounts and disclosures in the consolidated and combined financial
statements. Actual results could differ from those estimates.
FAIR VALUE OF FINANCIAL INSTRUMENTS - The carrying amount for accounts
receivable, marketable securities and accounts payable approximates fair
value because of the short maturity of those instruments. At December 31,
1999, the fair value of long-term debt was approximately $215 million. The
fair value of long-term debt is based on interest rates that are currently
available to the Partnership for issuance of debt with similar terms and
remaining maturities.
CASH MANAGEMENT - The Partnership maintains its cash management program
independent from ARH. However, the Predecessor participated in the cash
management program of ARH prior to August 20, 1999. At the end of each
business day, the operating cash accounts for the Predecessor were swept to
the related operating cash accounts maintained by the treasury function for
ARH. The Partnership and Predecessor reclassified outstanding checks of
$3,844,000 and $6,308,000 at December 31, 1999 and 1998, respectively, to
accounts payable in the consolidated and combined balance sheets.
35
MARKETABLE SECURITIES - The Partnership has investments in six month U.S.
Treasury notes which secure the term loan facility (Note 7). These
investments are classified as available-for-sale debt securities and are
restricted for the sole purpose of funding capital expenditures. At
December 31, 1999, the cost of these investments approximates fair value
and no effect of unrealized gains (losses) is reflected in Partners'
capital (deficit).
INVENTORIES - Coal inventories are stated at the lower of cost or market on
a first-in, first-out basis. Supplies 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 is computed
principally on the straight-line method based upon the estimated useful
lives of the assets or the estimated life of each mine (9 to 15 years at
revaluation date of August 1, 1996), whichever is less and for 5 years on
certain assets related to the 1998 business acquisition. Depreciable lives
for mining equipment and processing facilities range from 1 to 15 years.
Depreciable lives for land and land improvements and depletable lives for
mineral rights range from 5 to 15 years. Depreciable lives for buildings,
office equipment and improvements range from 1 to 13 years. Gains or losses
arising from retirements are included in current operations. Depletion of
mineral rights is provided on the basis of tonnage mined in relation to
estimated recoverable tonnage.
LONG-LIVED ASSETS - The Partnership reviews the carrying value of
long-lived assets and certain identifiable intangibles whenever events or
changes in circumstances indicate that the carrying amount may not be
recoverable based upon estimated undiscounted future cash flows. The amount
of an impairment is measured by the difference between the carrying value
and the fair value of the asset, which is based on cash flows from that
asset, discounted at a rate commensurate with the risk involved.
ADVANCE ROYALTIES - Rights to coal mineral leases are often acquired
through advance royalty payments. Management assesses the recoverability of
royalty prepayments based on estimated future production and capitalizes
these amounts accordingly. Royalty prepayments expected to be recouped
within one year are classified as a current asset. As mining occurs on
those leases, the royalty prepayments are included in the cost of mined
coal. Royalty prepayments estimated to be nonrecoverable are expensed.
COAL SUPPLY AGREEMENTS - The Predecessor purchased the coal operations of
MAPCO Inc. effective August 1, 1996, in a business combination using the
purchase method of accounting. A portion of the acquisition costs was
allocated to coal supply agreements. This allocated cost is being amortized
on the basis of coal shipped in relation to total coal to be supplied
during the respective contract term. The amortization periods end on
various dates from September 2002 to December 2005. Accumulated
amortization for coal supply agreements was $18,584,000 and $14,401,000 at
December 31, 1999 and 1998, respectively.
RECLAMATION AND MINE CLOSING COSTS - Estimates of the cost of future mine
reclamation and closing procedures of currently active mines are recorded
on a present value basis. Those costs relate to sealing portals at
underground mines and to reclaiming the final pit and support acreage at
surface mines. Other costs common to both types of mining are related to
removing or covering refuse piles and settling ponds and dismantling
preparation plants and other facilities and roadway infrastructure. Ongoing
reclamation costs principally involve restoration of disturbed land and are
expensed as incurred during the mining process.
WORKERS' COMPENSATION AND PNEUMOCONIOSIS ("BLACK LUNG") BENEFITS - The
Partnership is self-insured for workers' compensation benefits, including
black lung benefits. The Partnership accrues a workers' compensation
liability for the estimated present value of current and future workers'
compensation benefits based on actuarial valuations.
36
INCOME TAXES - No provision for income taxes related to the operations of
the Partnership is included in the accompanying consolidated financial
statements because, as a Partnership, it is not subject to federal or state
income tax and the tax effect of its activities accrues to the unitholders.
Net income for financial statement purposes may differ significantly from
taxable income reportable to unitholders as a result of differences between
the tax bases and financial reporting bases of assets and liabilities and
the taxable income allocation requirements under the Partnership agreement.
The Predecessor is included in the combined U.S. income tax returns of ARH.
The Predecessor has provided for income taxes on its separate taxable
income and other tax attributes. Deferred income taxes are computed based
on recognition of future tax expense or benefits, measured by enacted tax
rates, that are attributable to taxable or deductible temporary differences
between financial statement and income tax reporting bases of assets and
liabilities.
REVENUE RECOGNITION - Revenues are recognized when coal is shipped from the
mine. Revenues not arising from coal sales, which primarily consist of
transloading fees, are included in operating revenues and are recognized as
services are performed.
NET INCOME PER UNIT - Basic and diluted net income per unit is determined
by dividing net income, after deducting the General Partners' 2% interest,
by the weighted average number of outstanding Common Units and Subordinated
Units (a total of 15,405,311 units as of December 31, 1999).
SEGMENT REPORTING - The Partnership has no reportable segments due to its
operations consisting solely of producing and marketing coal. The
Partnership has disclosed major customer sales information (Note 15) and
geographic areas of operation (Note 16).
NEW ACCOUNTING STANDARDS - In June 1998, the Financial Accounting Standards
Board issued Statement of Financial Accounting Standards No. 133,
"Accounting for Derivative Instruments and Hedging Activities" ("SFAS
133"). The statement establishes accounting and reporting standards for
derivative instruments and for hedging activities. It requires that an
entity recognize all derivatives as either assets or liabilities in the
statement of financial position and measure those instruments at fair
value. The Partnership has not determined the impact on its financial
statements that may result from adoption of SFAS 133, which is required no
later than January 1, 2001.
RECLASSIFICATIONS - Certain reclassifications have been made to the 1998
and 1997 combined financial statements to conform to the classifications
used in 1999.
3. BUSINESS ACQUISITION
Effective January 23, 1998, the Predecessor acquired substantially all of
the assets and assumed certain liabilities, excluding working capital, of
an unrelated coal company's west Kentucky coal operations, now Hopkins
County Coal, LLC, for cash of approximately $7,310,000 and direct
acquisition costs of $821,000. The acquisition was accounted for using the
purchase method of accounting. Accordingly, the purchase price was
allocated to the assets acquired and liabilities assumed based on their
estimated fair values of $25,320,000 and $17,189,000, respectively. The
results of operations are included in the Partnership's consolidated and
combined financial statements from the acquisition date and are not
considered significant.
4. UNUSUAL ITEM
In response to market conditions, one of the Predecessor's operating mines
ceased operations and terminated all of its workforce in September 1998.
Management planned to maintain the mine in an indefinite idle status
pending improvement in market conditions. Shortly after the mine closure,
the management executed a long term coal supply contract for the mine and
the mine resumed production in late 1998. During the idle status period,
the mine incurred a net loss of approximately
37
$5,211,000 consisting of estimated amounts for increased workers'
compensation claims of $1,200,000 and severance payments consistent with
the federal Worker Adjustment and Returning Notification, or "WARN" Act, of
$1,200,000 as well as the costs associated with maintaining the idled mine
of $2,811,000.
5. INVENTORIES
Inventories consist of the following at December 31, (in thousands):
[Download Table]
PARTNERSHIP PREDECESSOR
1999 1998
----------- -----------
Coal $ 15,180 $ 14,308
Supplies 5,950 5,747
---------- ----------
$ 21,130 $ 20,055
========== ==========
6. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consists of the following at December 31, (in
thousands):
[Enlarge/Download Table]
PARTNERSHIP PREDECESSOR
1999 1998
----------- -----------
Mining equipment and processing facilities $ 236,252 $ 214,016
Land and mineral rights 17,282 7,387
Buildings, office equipment and improvements 17,780 16,130
Construction in progress 6,907 2,761
---------- ----------
278,221 240,294
Less accumulated depreciation, depletion and amortization (102,709) (69,158)
---------- ----------
$ 175,512 $ 171,136
========== ==========
7. LONG-TERM DEBT
Long-term debt consists of the following at December 31, (in thousands):
[Enlarge/Download Table]
PARTNERSHIP PREDECESSOR
1999 1998
----------- -----------
Senior notes $ 180,000 $ --
Term loan 50,000 --
Promissory note, net of discount of $764 at December 31, 1998 -- 2,037
---------- ----------
230,000 2,037
Less current maturities -- (350)
---------- ----------
$ 230,000 $ 1,687
========== ==========
The Special GP issued and the Intermediate Partnership assumed obligations
under a $180 million principal amount of senior notes pursuant to a Note
Purchase Agreement with a group of institutional investors in a private
placement offering. The senior notes are payable in ten annual installments
of $18 million beginning in August 2005 and bear interest at 8.31%, payable
semi-annually.
38
The Special GP also entered into and the Intermediate Partnership assumed
obligations under a $100 million credit facility consisting of three
tranches, including a $50 million term loan facility, a $25 million working
capital facility, and a $25 million revolving credit facility. In
connection with the closing of the IPO, the Special GP borrowed $50 million
under the term loan facility and the Special GP and Intermediate
Partnership purchased $50 million of U.S. Treasury Notes, which secure the
term loan. The U.S. Treasury Notes may be liquidated for the sole purpose
of funding capital expenditures. As of December 31, 1999, the Partnership
had liquidated approximately $8.4 million of U.S. Treasury Notes to fund
various qualifying capital expenditures.
The working capital facility can be used to provide working capital and, if
necessary, to fund distributions to unitholders. The revolving credit
facility can be used for general business purposes, including capital
expenditures and acquisitions. The rate of interest charged is adjusted
quarterly based on a pricing grid which is a function of the ratio of the
Partnership's debt to cash flow. The credit facility provides the
Partnership the option of borrowing at either (1) the London Interbank
Offered Rate ("LIBOR") or (2) the "Base Rate" which is equal to the greater
of (a) the Chase Prime Rate, or (b) the Federal Funds Rate plus 1/2 of 1%,
plus, in either option, an applicable margin. The weighted average interest
rate on the term loan facility at December 31, 1999 was 7.07%. In
accordance with the pricing grid, a commitment fee ranging from 0.375% to
0.500% per annum is paid quarterly on the unused portion of the working
capital and revolving credit facilities. There were no amounts outstanding
under the Partnership's working capital facility or revolving credit
facility as of December 31, 1999. The credit facility expires August 2004.
The senior notes and credit facility are secured by a pledge of the stock
of all the subsidiaries of Alliance Coal. The senior notes and credit
facility contains various restrictive and affirmative covenants, including
the amount of distributions by the Intermediate Partnership and the
incurrence of other debt. The Partnership was in compliance with the
covenants of both the credit facility and senior notes at December 31,
1999.
The Partnership incurred debt issuance costs aggregating approximately
$3,517,000, which have been deferred and are being amortized as a component
of interest expense over the term of the notes.
Aggregate maturities of long-term debt are as follows (in thousands):
[Download Table]
YEAR ENDING
DECEMBER 31,
2000 $ --
2001 3,750
2002 15,000
2003 16,250
2004 15,000
Thereafter 180,000
-----------
$ 230,000
===========
8. DISTRIBUTIONS OF AVAILABLE CASH
The Partnership will distribute 100% of its available cash within 45 days
after the end of each quarter to unitholders of record and to the General
Partners. Available cash is generally defined as all cash and cash
equivalents of the Partnership on hand at the end of each quarter less
reserves established by the Managing GP in its reasonable discretion for
future cash requirements. These reserves are retained to provide for the
proper conduct of the Partnership's business, the payment of debt principal
and interest and to provide funds for future distributions.
39
Distributions of available cash to the holder of Subordinated Units are
subject to the prior rights of holders of Common Units to receive the
minimum quarterly distribution ("MQD") for each quarter during the
subordination period and to receive any arrearages in the distribution of
the MQD on the Common Units for the prior quarters during the subordination
period. The MQD is $0.50 per unit ($2.00 per unit on an annual basis). Upon
expiration of the subordination period, which will generally not occur
before September 30, 2004, all Subordinated Units will be converted on a
one-for-one basis into Common Units and will then participate, on a pro
rata basis with all other Common Units in future distributions of available
cash. However, under certain circumstances, up to 50% of the Subordinated
Units may convert into Common Units on or after September 30, 2003. Common
Units will not accrue arrearages with respect to distributions for any
quarter after the subordination period and Subordinated Units will not
accrue any arrearages with respect to distributions for any quarter.
If quarterly distributions of available cash exceed the MQD or the target
distributions levels, the General Partners will receive distributions based
on specified increasing percentages of the available cash that exceeds the
MQD or target distribution level. The target distribution levels are based
on the amounts of available cash from the Partnership's operating surplus
distributed for a given quarter that exceed distributions for the MQD and
common unit arrearages, if any.
For the 42-day period from the Partnership's commencement of operations (on
August 20, 1999) through September 30, 1999, the Partnership paid a
pro-rata MQD distribution of $0.23 per unit on its outstanding Common and
Subordinated Units amounting to approximately $3,543,000. On January 26,
2000, the Partnership declared a MQD, for the period from October 1, 1999
to December 31, 1999, of $0.50 per unit on its outstanding Common and
Subordinated Units totaling approximately $7,703,000.
9. INCOME TAXES
The Predecessor recognized a deferred tax asset for the future tax benefits
attributable to deductible temporary differences and other credit
carryforwards to the extent that realization of such benefits was more
likely than not. Realization of these future tax benefits was dependent on
the Predecessor's ability to generate future taxable income, which was not
assured. Management for the Predecessor believed that future taxable income
would be sufficient to recognize only a portion of the tax benefits and had
established a valuation allowance.
Due to the Predecessor's inclusion in ARH's consolidated U.S. income tax
returns, ARH allocated alternative minimum tax to the Predecessor. The
Predecessor had alternative minimum tax credit carryforwards of $2,361,000
at December 31, 1998 that were available for use in ARH's consolidated U.S.
income tax returns in future periods. A valuation allowance was established
for the total estimated future tax effects of the alternative minimum tax
credit carryforwards since utilization on future U.S. income tax returns
was not being considered more likely than not.
Concurrent with the closing of the IPO, on August 20, 1999 and in
connection with the Contribution Agreement, ARH retained the current and
deferred income taxes of the Predecessor.
40
The tax effects of significant items comprising the Predecessor's net
deferred tax liability at December 31, 1998 are as follows (in thousands):
[Download Table]
Deferred tax liabilities:
Differences between book and tax basis of property $ 18,489
Differences between book and tax basis of advance royalties 1,238
Other 2,601
----------
Deferred tax liability 22,328
----------
Deferred tax assets:
Accrued workers' compensation and pneumoconiosis benefits 14,856
Accrued reclamation and mine closing 5,520
Accrued expenses not currently deductible 4,349
Coal supply agreements 5,838
Alternative minimum tax credit carryforwards for future use
in ARH tax returns 2,361
----------
32,924
Valuation allowance (14,502)
----------
Deferred tax asset 18,422
----------
Net deferred tax liability $ 3,906
==========
Income before income taxes is derived from domestic operations.
Significant components of income taxes are as follows (in thousands):
[Download Table]
FOR THE
PERIOD FROM YEARS ENDED
JANUARY 1, 1999 DECEMBER 31,
TO --------------------
AUGUST 19, 1999 1998 1997
--------------- -------- --------
Current:
Federal $ 3,376 $ 4,815 $ 5,184
State 483 801 1,041
--------------- -------- --------
3,859 5,616 6,225
Deferred:
Federal 595 (1,531) (1,695)
State 44 (219) (242)
--------------- -------- --------
639 (1,750) (1,937)
--------------- -------- --------
Income tax expense $ 4,498 $ 3,866 $ 4,288
=============== ======== ========
41
A reconciliation of the statutory U.S. federal income tax rate and the
Predecessor's effective income tax rate is as follows:
[Download Table]
FOR THE
PERIOD FROM YEARS ENDED
JANUARY 1, 1999 DECEMBER 31,
TO ----------------------
AUGUST 19, 1999 1998 1997
--------------- --------- ---------
Statutory rate 35% 35% 35%
Increase (decrease) resulting from:
Excess of tax over book depletion (21) (29) (21)
Alternative minimum tax credit
carryforwards 3 6 7
State income taxes, net of federal
benefit 3 4 4
Valuation allowance 10 14 (3)
Other 1 1 2
--------------- --------- ---------
Effective income tax rate 31% 31% 24%
=============== ========= =========
10. EMPLOYEE BENEFIT PLANS
LONG-TERM INCENTIVE PLAN - Effective January 1, 2000, the Managing GP
adopted a Long-Term Incentive Plan (the "LTIP") for the benefit of
providing incentive compensation awards to its employees, non-employee
directors, and employees of the Partnership. Annual grant levels for
designated participants are recommended by the chief executive officer of
the Managing GP, subject to the review and approval of the Compensation
Committee. Grants are made either of restricted units, which are "phantom"
units that entitle the grantee to receive a Common Unit or an equivalent
amount of cash upon the vesting of a phantom unit, or options to purchase
Common Units. Common Units to be delivered upon the vesting of restricted
units will be acquired by the Managing GP in the open market or directly
from ARH or any other third party. The aggregate number of units reserved
for issuance under the LTIP is 600,000. Effective January 1, 2000, the
Compensation Committee approved initial grants of 142,100 restricted units,
which vest on September 30, 2002. The Partnership agreement provides that
the Managing GP be reimbursed for all compensation expenses incurred on
behalf of the Partnership.
DEFINED CONTRIBUTION PLANS - The Partnership's employees currently
participate in a defined contribution profit sharing and savings plan
sponsored by the Partnership, which is the same plan sponsored by the
Predecessor. This plan covers substantially all employees. Plan
participants may elect to make voluntary contributions to this plan up to a
specified amount of their compensation. The Partnership makes contributions
based on matching 75% of employee contributions up to 3% of their annual
compensation as well as an additional nonmatching contribution of 3/4 of 1%
of their compensation. Additionally, the Partnership contributes a defined
percentage of eligible earnings for employees not covered by the defined
benefit plan described below. The Partnership's expense for its plan was
approximately $715,000 for the period from August 20, 1999 to December 31,
1999. The Predecessor's expense for the plan was $1,226,000 for the period
from January 1, 1999 to August 19, 1999, $1,944,000 and $1,542,000 for the
years ended December 31, 1998 and 1997, respectively.
DEFINED BENEFIT PLANS - Substantially all employees at the mining
operations participate in a defined benefit plan sponsored by the
Partnership, which is the same plan sponsored by the Predecessor.
42
The benefit formula is a fixed dollar unit based on years of service.
The following sets forth changes in benefit obligations and plan assets for
the years ended December 31, 1999 and 1998 and the funded status of the
plans reconciled with amounts reported in the Partnership's consolidated
and the Predecessor's combined financial statements at December 31, 1999
and 1998, respectively. The Partnership and Predecessor periods for 1999
have been combined. Since the Partnership maintained the historical basis
of the Predecessor's net assets, management believes that the combined
Partnership and Predecessor amounts for 1999 are comparable with 1998
(dollars in thousands):
[Enlarge/Download Table]
COMBINED
PARTNERSHIP/PREDECESSOR PREDECESSOR
1999 1998
---------- ----------
CHANGE IN BENEFIT OBLIGATIONS:
Benefit obligations at beginning of year $ 6,742 $ 3,501
Service cost 2,107 2,980
Interest cost 452 240
Actuarial (gain) loss (1,435) 166
Benefits paid (92) (145)
---------- ----------
Benefit obligation at end of year $ 7,774 $ 6,742
---------- ----------
CHANGE IN PLAN ASSETS:
Fair value of plan assets at beginning of year 2,911 --
Employer contribution 4,736 2,940
Actual return on plan assets 710 116
Benefits paid (92) (145)
---------- ----------
Fair value of plan assets at end of year 8,265 2,911
---------- ----------
Funded status 491 (3,831)
Unrecognized prior service cost 332 380
Unrecognized actuarial (gain) loss (1,273) 459
---------- ----------
Net amount recognized $ (450) $ (2,992)
========== ==========
WEIGHTED-AVERAGE ASSUMPTIONS AS OF DECEMBER 31:
Discount rate 7.75% 6.75%
Expected return on plan assets 9.00% 9.00%
COMPONENTS OF NET PERIODIC BENEFIT COST:
Service cost $ 2,107 $ 2,980
Interest cost 452 240
Expected return on plan assets (413) (135)
Prior service cost 48 48
---------- ----------
Net periodic benefit cost $ 2,194 $ 3,133
========== ==========
Effect on minimum pension liability $ (459) $ 186
========== ==========
43
11. RECLAMATION AND MINE CLOSING COSTS
The majority of the Partnership's operations are governed by various state
statutes and the Federal Surface Mining Control and Reclamation Act of
1977, which establish reclamation and mine closing standards. These
regulations, among other requirements, require restoration of property in
accordance with specified standards and an approved reclamation plan. The
Partnership has estimated the costs and timing of future reclamation and
mine closing costs and recorded those estimates on a present value basis
using a 6% discount rate.
Discounting resulted in reducing the accrual for reclamation and mine
closing costs by $5,489,000 and $6,738,000 at December 31, 1999 and 1998,
respectively. Estimated payments of reclamation and mine closing costs as
of December 31, 1999 are as follows (in thousands):
[Download Table]
2000 $ 1,389
2001 699
2002 727
2003 1,141
2004 1,566
Thereafter 14,763
------------
Aggregate undiscounted reclamation and mine closing 20,285
Effect of discounting 5,489
------------
Total reclamation and mine closing costs 14,796
Less current portion 1,389
------------
Reclamation and mine closing costs $ 13,407
============
The following table presents the activity affecting the reclamation and
mine closing liability (in thousands):
[Enlarge/Download Table]
PARTNERSHIP PREDECESSOR
----------------- -----------------------------------------
FROM
COMMENCEMENT FOR THE
OF OPERATIONS PERIOD FROM YEAR ENDED
(ON AUGUST 20, 1999) JANUARY 1, 1999 DECEMBER 31,
TO TO ----------------------
DECEMBER 31, 1999 AUGUST 19, 1999 1998 1997
----------------- --------------- --------- ---------
Beginning balance $ 13,856 $ 13,800 $ 5,439 $ 5,313
Accrual 348 457 705 339
Payments (394) (401) (1,544) (213)
Allocation of liability associated
with acquisition 986 -- 9,200 --
----------------- --------------- --------- ---------
Ending balance $ 14,796 $ 13,856 $ 13,800 $ 5,439
================= =============== ========= =========
12. PNEUMOCONIOSIS ("BLACK LUNG") BENEFITS
Certain mine operating entities of the Partnership are liable under state
statutes and the Federal Coal Mine Health and Safety Act of 1969, as
amended, to pay black lung benefits to eligible employees and former
employees and their dependents. These subsidiaries provide self-insurance
accruals, determined by independent actuaries, at the present value of the
actuarially computed present and future liabilities for such benefits. The
actuarial studies utilize a 6% discount rate and various assumptions as to
the frequency of future claims, inflation, employee turnover and life
expectancies.
44
The cost or reduction of cost due to change in the estimate of black lung
benefits charged (credited) to operations for the period from the
Partnership's commencement of operations on August 20, 1999 to December 31,
1999 and for the Predecessor period from January 1, 1999 to August 19,
1999, and the years ended December 31, 1998 and 1997 was $(1,028,000),
$726,000, $1,139,000, and $1,252,000, respectively.
13. RELATED PARTY TRANSACTIONS
The Partnership Agreement provides that the Managing GP and its affiliates
be reimbursed for all direct and indirect expenses it incurs or payments it
makes on behalf of the Partnership including management's salaries and
related benefits, accounting, treasury, land administration, environmental
and permitting management, disability and workers' compensation management,
legal and information technology services. The Managing GP may determine in
its sole discretion the expenses that are allocable to the Partnership.
Total costs reimbursed to the Managing GP and its affiliates by the
Partnership were approximately $1,283,000 for the period from the
Partnership's commencement of operations on August 20, 1999 to December 31,
1999.
ARH allocated certain direct and indirect general and administrative
expenses to the Predecessor. These allocations were primarily based on the
relative size of the direct mining operating costs incurred by each of the
mine locations of the Predecessor. The allocations of general and
administrative expenses to the Predecessor were approximately $2,982,000,
$2,595,000 and $2,942,000 for the period from January 1, 1999 to August 19,
1999 and for the years ended December 31, 1998 and 1997, respectively.
Management is of the opinion that the allocations used are reasonable and
appropriate.
During November 1999, the Managing GP was authorized by its Board of
Directors to purchase up to 1.0 million Common Units of the Partnership. As
of December 31, 1999 the Managing GP had purchased 164,000 Common Units in
the open market at prevailing market prices.
14. 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. Rent expense under all operating leases was
$801,000, $496,000, $1,169,000, and $1,142,000 for the period from the
Partnership's commencement of operations on August 20, 1999 to December 31,
1999 and the Predecessor period from January 1, 1999 to August 19, 1999,
and the years ended December 31, 1998 and 1997, respectively.
Future minimum payments under operating leases are $2.9 million in total of
which $452,000 is payable each year in 2000 and 2001, $408,000 in 2002,
$274,000 in 2003, $284,000 in 2004 and $1,063,000 thereafter.
CONTRACTUAL COMMITMENTS - In connection with development of a new mining
complex, the Partnership has entered into contractual commitments for mine
construction of approximately $6.8 million at December 31, 1999.
TRANSLOADING FACILITY DISPUTE - The Partnership is currently involved in
litigation with Seminole Electric Cooperative, Inc. ("Seminole") with
respect to a long-term contract for the transloading of coal from rail to
barge through the Partnership's terminal in Indiana. Seminole has filed a
lawsuit to terminate this contract and is seeking declaratory judgment as
to the damages owed to the Partnership. The provisions of the contract
stipulate the calculation of damages to be paid in the event of breach.
Rather than pay the amount of damages stipulated, Seminole is seeking the
court's agreement that the proper damage award should be calculated based
on the Partnership's loss of net profits from the terminal for the term of
the agreement.
45
Seminole has ceased transloading any coal shipments through this terminal
and is transporting coal deliveries under the supply contract by rail. The
Partnership is currently exploring alternative uses for this terminal. The
Partnership intends to vigorously defend its contract rights and believes
that it will prevail in the determination of the amount of damages Seminole
owes under the contract and believes those damages will be in excess of the
carrying value of this terminal.
GENERAL LITIGATION - The Partnership is involved in various lawsuits,
claims and regulatory proceedings incidental to its business. In the
opinion of management, the outcome of such matters will not have a material
adverse effect on the Partnership's business, combined financial position
or results of operations.
15. SIGNIFICANT CUSTOMERS
The Partnership has significant long-term coal supply agreements some of
which contain price adjustment provisions designed to reflect changes in
market conditions, labor and other production costs and, when the coal is
sold other than FOB the mine, changes in railroad and/or barge freight
rates. Sales to major customers which exceed ten percent of total net sales
are as follows (in thousands):
[Download Table]
PARTNERSHIP PREDECESSOR
-------------------- ---------------------------------------
FROM
COMMENCEMENT FOR THE
OF OPERATIONS PERIOD FROM YEARS ENDED
(ON AUGUST 20, 1999) JANUARY 1, 1999 DECEMBER 31,
TO TO ---------------------
DECEMBER 31, 1999 AUGUST 19, 1999 1998 1997
-------------------- --------------- --------- ---------
Customer A $ 26,970 $ 40,685 $ 56,351 $ 40,297
Customer B 20,512 34,686 56,280 50,219
Customer C 16,090 31,315 69,651 57,382
The coal supply agreements with customer A expire at dates between 2000 and
2003. The coal supply agreements with customers B and C expire in 2006 and
2010, respectively.
16. GEOGRAPHIC INFORMATION
Included in the consolidated and combined financial statements are the
following revenues and long-lived assets relating to geographic locations
(in thousands):
[Enlarge/Download Table]
PARTNERSHIP PREDECESSOR
-------------------- ---------------------------------------
FROM
COMMENCEMENT FOR THE
OF OPERATIONS PERIOD FROM YEARS ENDED
(ON AUGUST 20, 1999) JANUARY 1, 1999 DECEMBER 31,
TO TO ----------------------
DECEMBER 31, 1999 AUGUST 19, 1999 1998 1997
-------------------- --------------- --------- ---------
Revenues:
United States $ 129,218 $ 211,740 $ 330,312 $ 267,096
Other foreign countries -- 5,870 31,581 46,724
-------------------- --------------- --------- ---------
$ 129,218 $ 217,610 $ 361,893 $ 313,820
==================== =============== ========= =========
Long-lived assets:
United States $ 203,697 $ 200,057 $ 204,078 $ 193,085
Other foreign countries -- -- -- --
-------------------- --------------- --------- ---------
$ 203,697 $ 200,057 $ 204,078 $ 193,085
==================== =============== ========= =========
46
17. SUPPLEMENTAL CASH FLOW INFORMATION
The Partnership's and Predecessor's supplemental disclosure of cash flow
information and other non-cash investing and financing activities were as
follows (in thousands):
[Enlarge/Download Table]
PARTNERSHIP PREDECESSOR
-------------------- ---------------------------------------
FROM
COMMENCEMENT FOR THE
OF OPERATIONS PERIOD FROM YEARS ENDED
(ON AUGUST 20, 1999) JANUARY 1, 1999 DECEMBER 31,
TO TO ---------------------
DECEMBER 31, 1999 AUGUST 19, 1999 1998 1997
-------------------- --------------- --------- ---------
Cash paid for:
Interest $ 1,173 $ -- $ -- $ --
Income taxes paid through
Parent (Note 9) -- 3,504 3,135 9,764
Non-cash investing and financing activities:
Debt transferred from Special GP 230,000 -- -- --
Marketable securities transferred -- -- --
from Special GP 15,486 -- -- --
Issuance of promissory note for --
acquisition of minerals and
other assets -- -- -- 2,186
18. NET PARENT INVESTMENT
The Net Parent Investment in the Predecessor is comprised of the following
for the period from January 1, 1999 through August 19, 1999 and the years
ended December 31, 1998 and 1997 (in thousands):
[Download Table]
Predecessor balance, January 1, 1997 $ 176,213
Net income 13,717
Dividends to Parent (13,795)
Return of capital to Parent (17,043)
Other (273)
---------
Predecessor balance, December 31, 1997 158,819
Net income 8,668
Dividends to Parent (8,642)
Return of capital to Parent (5,890)
Other (186)
---------
Predecessor balance, December 31, 1998 152,769
Net income 10,205
Return of capital to Parent (11,359)
---------
Predecessor balance, August 19, 1999 $ 151,615
=========
47
19. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
On August 20, 1999, the Partnership completed its IPO in which the
Partnership became the successor to the business of the Predecessor.
Accordingly, no recognition has been given to income taxes in the financial
statements of the Partnership as income taxes will be borne by the partners
and not the Partnership. Additionally, interest expense associated with the
debt incurred concurrent with the closing of the IPO is applicable only to
the Partnership period. Accordingly, the quarterly operating results prior
to August 20, 1999 are not necessarily comparable to subsequent periods.
A summary of the quarterly operating results for the Partnership and
Predecessor is as follows (in thousands, except unit and per unit data):
[Enlarge/Download Table]
PREDECESSOR PARTNERSHIP
-------------------------------------- -------------------------------------------
FROM
COMMENCEMENT
QUARTER ENDED JULY 1, 1999 OF OPERATIONS
------------------------ TO (ON AUGUST 20, 1999)
MARCH 31, JUNE 30, AUGUST 19, TO QUARTER ENDED
1999 1999 1999 SEPTEMBER 30, 1999 DECEMBER 31, 1999
---------- ------------ ---------- -------------------- --------------------
Revenues $ 83,062 $ 86,745 $ 47,803 $ 44,052 $ 85,166
Operating income 4,273 6,995 3,004 5,019 6,499
Net income 2,969 4,934 2,302 3,509 2,763
Basic and diluted net
income per unit -- -- -- $ 0.22 $ 0.18
Weighted average number
of units outstanding -- -- -- 15,405,311 15,405,311
[Download Table]
PREDECESSOR
QUARTER ENDED
------------------------------------------------------------
MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31,
1998 1998 1998(1) 1998(1)
---------- ------------ ------------- ------------
Revenues $ 88,322 $ 90,969 $ 98,428 $ 84,174
Operating income 4,750 929 2,484 4,653
Net income 3,324 672 1,611 3,061
(1) In response to market conditions, the Pontiki mine ceased operation
and terminated substantially all of its workforce in September 1998.
During the idle status period, which ended in late 1998, Pontiki
incurred a net loss of approximately $5.2 million, $3.8 million was
recorded in the quarter ended September 30, 1998 and $1.4 million was
recorded in the quarter ended December 31, 1998 (Note 4).
Operating income in the above table represents income from operations
before interest expense.
20. SUBSEQUENT EVENTS
On March 17, 2000, the Special GP exercised two separate options and paid
approximately $2.0 million, for the rights to acquire substantial tracts of
coal reserves in western Kentucky. Upon completion of the acquisition, the
Special GP may elect to either lease or assign the coal reserves to the
Partnership in return for payment of all amounts the Special GP expends in
connection with the coal reserve acquisition. The closing is anticipated to
occur during the third quarter of 2000, however, the Special GP can make no
assurances that it will be able to consummate the transaction.
On March 23, 2000, the Partnership entered into an arrangement with the
Special GP for construction of a coal preparation plant and ancillary
facilities (collectively the "coal preparation plant") at a new mining
complex currently under development. Under the terms of the arrangement,
the Special GP is constructing the coal preparation plant at an anticipated
cost of approximately $23.1 million and has the
48
option to sell or lease the coal preparation plant to the Partnership when
construction is completed. At December 31, 1999, the Partnership has
incurred and capitalized costs of approximately $300,000 related to site
preparation for the coal preparation plant at the mining complex.
49
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE MANAGING GENERAL PARTNER
As is commonly the case with publicly-traded limited partnerships, we are
managed and operated by our managing general partner. The following table shows
information for the directors and executive officers of the Managing GP.
Executive officers and directors are elected for one-year terms.
[Download Table]
NAME AGE POSITION WITH THE MANAGING GENERAL PARTNER
---- --- ------------------------------------------
Joseph W. Craft III 49 President, Chief Executive Officer and Director
Thomas L. Pearson 46 Senior Vice President - Law and Administration,
General Counsel and Secretary
Michael L. Greenwood 44 Senior Vice President - Chief Financial Officer and
Treasurer
Charles R. Wesley 46 Senior Vice President - Operations
Gary J. Rathburn 49 Senior Vice President - Marketing
John J. MacWilliams 44 Director
Preston R. Miller, Jr. 51 Director
John P. Neafsey 60 Director
John H. Robinson 49 Director
Paul R. Tregurtha 65 Director
Joseph W. Craft III has worked for us since 1980. Prior to the
formation of ARH, Mr. Craft was a Senior Vice President of MAPCO Inc., serving
as General Counsel and Chief Financial Officer and since 1986 as President of
MAPCO Coal Inc. Prior to working with us, Mr. Craft was an attorney at Falcon
Coal Corporation and Diamond Shamrock Coal Corporation. Mr. Craft holds a
Bachelor of Science degree in Accounting and a Doctor of Jurisprudence 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. Mr. Craft has held numerous industry leadership positions
including past Chairman of the National Coal Council, a Board and Executive
Committee member of the National Mining Association, and a Director of the
Center for Energy and Economic Development.
Thomas L. Pearson has worked for us since 1989. Prior to the formation
of ARH, he was Assistant General Counsel of MAPCO Inc. and served as General
Counsel of MAPCO Coal Inc. from 1989-1996 and has served as Secretary since
1989. Prior to working with us, Mr. Pearson was the General Counsel and
Secretary of McLouth Steel Products Corporation, one of the largest integrated
steel producers in the United States; and Corporate Counsel of Midland-Ross
Corporation, a multi-national company with numerous international joint venture
companies and projects. Previously, he was a senior associate with the Arter &
Hadden law firm in Cleveland, Ohio. In addition to his responsibilities at ARH,
Mr. Pearson is or has been active in a number of educational, charitable and
business organizations, including the following: Vice Chairman, Legal Affairs
Committee, National Mining Association; Member, Dean's Committee, The University
of Iowa College of Law; and Contributions Committee, Greater Cleveland United
Way. Mr. Pearson holds a Bachelor of Arts degree in History and Communications
from DePauw University and a Doctor of Jurisprudence from The University of
Iowa.
Michael L. Greenwood has worked for us since 1986. Prior to the
formation of ARH, Mr. Greenwood served in various financial management
capacities, including General Manager - Finance of MAPCO Coal Inc., General
Manager of Planning and Financial Analysis and Manager - Mergers and
Acquisitions of MAPCO Inc. Prior to working for us, Mr. Greenwood held financial
planning and business development management positions in the energy industry
with Davis Investments, The Williams Companies and Penn Central Corporation. Mr.
Greenwood holds a Bachelor of Science degree in Business Administration from
Oklahoma State University and a Master of Business Administration degree from
the University of Tulsa. Mr. Greenwood has also completed executive programs at
Northwestern University, Southern Methodist University and The Center for
Creative Leadership.
Charles R. Wesley has worked for us since 1974. Mr. Wesley joined the
Partnership's Webster County Coal, LLC subsidiary in 1974 as an engineering
co-op student and worked through the ranks to become General Superintendent. In
1992 he became Vice President of Operations for Mettiki Coal Corporation. He has
held his position as Senior Vice President of Operations since 1996. Mr. Wesley
has served the industry as past president of the West Kentucky Mining Institute
and National
50
Mine Rescue Association Post 11. He has also served on the board of the Kentucky
Mining Institute. Mr. Wesley holds a Bachelor of Science degree in Mining
Engineering from the University of Kentucky.
Gary J. Rathburn has worked for us since 1980 when he joined MAPCO Coal
Inc. as Manager of Brokerage Coals. Since 1980, Mr. Rathburn has managed all
phases of the marketing group involving transportation and distribution,
international sales and the brokering of coal. Prior to working for us, Mr.
Rathburn was employed by Eastern Associated Coal Corporation in its
International Sales and Brokerage groups for seven years. Mr. Rathburn has been
active in industry groups such as the Maryland Coal Association, The North
Carolina Coal Institute and the National Mining Association. Mr. Rathburn was a
Director of The National Coal Association and Chairman of the Coal Exporters
Association for several years. Mr. Rathburn holds a Bachelor of Arts degree in
Political Science from the University of Pittsburgh and has participated in
industry-related programs at the World Trade Institute, Princeton University and
the Colorado School of Mines.
John J. MacWilliams has been a General Partner of The Beacon Group, LP
(the "Beacon Group") since May 1993. Prior to the formation of The Beacon
Group, Mr. MacWilliams was an Executive Director of Goldman Sachs International
in London, where he was responsible for heading the firm's International
Structured Financing Group. Prior to moving to London, Mr. MacWilliams was a
Vice President in the Investment Banking Division of Goldman, Sachs & Co. in New
York. Prior to joining Goldman Sachs, Mr. MacWilliams was an attorney at Davis
Polk & Wardwell in New York, where he worked on international bank financings,
partnership financings, and mergers and acquisitions. Mr. MacWilliams is a
graduate of Harvard Law School (J.D.), Massachusetts Institute of Technology
(M.S.), and Stanford University (B.A.).
Preston R. Miller, Jr. has been a General Partner of The Beacon Group
since June 1993. Prior to the formation of The Beacon Group, Mr. Miller was
employed for fourteen years by Goldman, Sachs & Co. in New York City,
where he was a Vice President in the Structured Finance Group and had global
responsibility for the coverage of the independent power industry and for
asset-backed power generation and oil and gas financings. Mr. Miller also has a
background in credit analysis, and was head of the revenue bond rating group at
Standard & Poor's Corp. prior to joining Goldman Sachs. Mr. Miller is a graduate
of Harvard University (M.P.A.) and Yale University (B.A.).
John P. Neafsey has served as Chairman of ARH since September 1996 and
has served as President of JN Associates, an investment consulting firm, since
January 1994. Prior to the formation of ARH, Mr. Neafsey served as President and
CEO of Greenwich Capital Markets and served on its Board of Directors since its
founding in 1983. In addition, Mr. Neafsey held numerous other positions during
his twenty-three years at The Sun Company, including: Executive Vice President
responsible for Canadian operations, Sun Coal Company and Helios Capital
Corporation; Chief Financial Officer; and other executive management positions
with numerous subsidiary companies. In addition to his responsibilities at ARH,
Mr. Neafsey is or has been active in a number of educational, charitable and
business organizations, including the following: Member of the Board of
Directors of The West Pharmaceutical Services Company and the Provident Mutual
Life Insurance Company; Trustee of Cornell University; Board Member,
Crozer-Chester Medical Center, the Drama Guild, and The American Petroleum
Institute. Mr. Neafsey is a graduate of Cornell University (B.S./M.S.
(Engineering) and M.B.A. (Finance)).
John H. Robinson was elected a director in December 1999. In April
2000, Mr. Robinson will join Amey, PLC as Managing Director of its newly-formed
Technology Services Division. Mr. Robinson previously served as Vice Chairman
and Chief Development Officer of Black & Veatch, from January 1997 through March
2000. He was also the Chairman of Black & Veatch UK Lt. and was responsible for
guiding strategic development of the firm. He is an Executive Director of Amey,
PLC and also is a director of Commerce Bancshares Corporation, Coeur Mining
Corporation and Protection One, Inc. and serves on numerous civic and
professional boards in his community. Mr. Robinson is a graduate of the
University of Kansas (B.S. and M.S. (Engineering)). Mr. Robinson has also
completed the Owner/President Management Program at the Harvard School of
Business.
51
Paul R. Tregurtha was elected a director in December 1999. Mr.
Tregurtha serves as Chairman and Chief Executive Officer of Mormac Marine Group,
Inc., Chairman and Chief Executive Officer of Moran Towing Corporation, and
Chairman of MAC Acquisitions, Inc., the parent of Meridian Aggregates Company.
He is a director and principal officer of several companies involved in water
transportation and natural resources including Mormac, Moran, The Interlake
Steamship Company, Lakes Shipping Company, and Meridian Aggregates Company. Mr.
Tregurtha is also a director of FleetBoston Financial and FPL Group, parent of
Florida Power & Light Company. Mr. Tregurtha holds a degree in mechanical
engineering from Cornell University, where he serves as Trustee Emeritus. Before
graduating with distinction as a Baker Scholar from Harvard's Graduate School of
Business Administration, Mr. Tregurtha served as an officer in the U.S. Air
Force.
Section 16(a) Beneficial Ownership Reporting Compliance.
Section 16(a) of the Securities and Exchange Act of 1934, as amended,
requires directors, executive officers and persons who beneficially own more
than ten percent of a registered class of the Partnership's equity securities to
file with the SEC initial reports of ownership and reports or changes in
ownership of such equity securities. Such persons are also required to furnish
the Partnership with copies of all Section 16(a) forms that they file. Based
solely upon a review of the copies of the forms furnished to it, or written
representations from certain reporting persons that no Forms 5 were required,
the Partnership believes that during 1999 none of its officers and directors was
delinquent with respect to any of the filing requirements under Rule 16(a) other
than (a) Messrs. Robinson and Tregurtha, neither of whom timely filed a Form 3
upon initial appointment to the Board of Directors of the Managing GP, but for
whom Form 3s have since been filed, (b) Messrs. Rathburn and Wesley, neither of
whom timely filed a Form 4 for the month of October, but have since filed their
Form 4s, (c) Mr. Neafsey did not timely file a Form 4 for the month of November,
but has since filed this Form 4, and (d) Mr. Craft did not timely file a Form 4
for the months of August and September 1999, regarding purchases made by a
private foundation for which he serves as a trustee and disclaims beneficial
ownership, but has since filed these Form 4s.
Reimbursement of Expenses of the Managing GP and its Affiliates
The Managing GP does not receive any management fee or other compensation
in connection with its management of us. The Managing GP and its affiliates,
including ARH, are reimbursed for all expenses incurred on our behalf, including
the costs of employee, officer and director compensation and benefits properly
allocable to us, and all other expenses necessary or appropriate to the conduct
of our business of, and allocable to, us. Our Partnership Agreement provides
that the Managing GP will determine the expenses that are allocable to us in any
reasonable manner determined by the Managing GP in its sole discretion.
ITEM 11. EXECUTIVE COMPENSATION
EXECUTIVE COMPENSATION
The Partnership was formed in May 1999 but did not commence business until
August 1999. Mr. Craft, the General Partners' President and CEO, received
$109,850 for services to the Partnership in 1999. No other officer of the
General Partner received compensation for services to the Partnership in 1999 in
amounts greater than $100,000.
We made no grants of restricted units or options to acquire Common Units
in 1999 and there were no such restricted units or unit options outstanding
prior to or on December 31, 1999. See "Long-Term Incentive Plan".
COMPENSATION OF DIRECTORS
The Managing GP has adopted a Directors Compensation Program (the
"Directors Plan") and a Deferred Compensation Plan for Directors (the "Plan").
Under the Directors Plan, each non-employee Director will be paid an annual
retainer for calendar years 1999 and 2000 to be paid in advance on a quarterly
basis of $4,000 and $20,000, respectively. The annual retainer will be paid in
Common Units of the Partnership determined by dividing the pro rata annual
retainer payable on such date
52
by the closing sales price per Common Unit averaged over the immediately
preceding ten trading days. Each non-employee director may elect to defer all or
a portion of his or her compensation under the Plan.
EMPLOYMENT AGREEMENTS
The executive officers of the Managing GP and some additional members
of senior management will enter into employment agreements among the executive
officer or member of senior management, on the one hand, and the Managing GP and
ARH, on the other. We reimburse the Managing GP for the compensation and
benefits costs under these agreements. This summary of the terms of the
employment agreements does not purport to be complete, but outlines their
material provisions. A form of the agreements with each of Messrs. Craft,
Pearson, Greenwood, Wesley and Rathburn are filed as exhibits.
Each of the employment agreements has an initial term that expires on
December 31, 2001, but will automatically be extended for successive one-year
terms unless either party gives 12 months prior notice to the other party. The
employment agreements provide for a base salary, subject to review annually, of
$292,950, $177,000, $151,400, $187,000 and $152,000 for Messrs. Craft, Pearson,
Greenwood, Wesley and Rathburn, respectively. The employment agreements provide
for continued salary payments, bonus and benefits for a period of three years,
in the case of Mr. Craft, and 18 months, in the case of Messrs. Pearson,
Greenwood, Wesley and Rathburn, following termination of employment, except in
the case of a change of control of the Managing GP.
In the case of a "change of control" as defined in the agreements, in
lieu of the continuation of salary and benefits, that executive will be entitled
to a lump sum payment in an amount equal to three times base salary plus bonus,
in the case of Mr. Craft, and two times base salary plus bonus in the case of
Messrs. Pearson, Greenwood, Wesley and Rathburn. Unless the executive waives his
or her right to the continuation of base salary and bonus, the agreements
provide for a noncompetition period of 18 months. The noncompetition period does
not apply after a change in control. Amounts paid by the Managing GP pursuant to
the employment agreements will be reimbursed by the Partnership.
The executives who are subject to employment agreements also
participate in the Short- and Long-Term Incentive Plans of the Managing GP
described below along with other members of management. They also are entitled
to participate in the other employee benefit plans and programs that the
Managing GP provides for its employees.
LONG-TERM INCENTIVE PLAN
Effective January 1, 2000, the Managing GP adopted the Long-Term
Incentive Plan (the "LTIP") for employees and directors of the Managing GP and
its affiliates who perform services for us. The summary of the LTIP contained
herein does not purport to be complete but outlines its material provisions.
The LTIP is administered by the Compensation Committee of the Managing
GP's Board of Directors. Annual grant levels for designated employees and
directors will be recommended by the President and CEO of the Managing GP,
subject to the review and approval of the Compensation Committee. We will
reimburse the Managing GP for all costs incurred pursuant to the programs
described below. Grants are made either of restricted units, which are "phantom"
units that entitle the grantee to receive a Common Unit or an equivalent amount
of cash upon the vesting of a phantom unit, or options to purchase Common Units.
Common Units to be delivered upon the vesting of restricted units or to be
issued upon exercise of a unit option will be acquired by the Managing GP in the
open market at a price equal to the then-prevailing price, or directly from ARH
or any other third party, including units newly issued by us, or use units
already owned by the Managing GP, or any combination of the foregoing. The
Managing GP is entitled to reimbursement by us for the cost incurred in
acquiring these Common Units or in paying cash in lieu of Common Units upon
vesting of the restricted units. If we issue new Common Units upon payment of
the restricted units or unit options instead of purchasing them, the total
number of Common Units outstanding will increase. The aggregate number of units
reserved for issuance under the LTIP is 600,000. Effective as of January 1,
53
2000, the Compensation Committee approved initial grants of 142,100 restricted
units which vest on September 30, 2002.
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 conversion of any Subordinated
Units and will only become payable upon, and in the same proportion as, the
conversion of Subordinated Units into Common Units.
The issuance of the Common Units pursuant to the restricted unit plan
is intended to serve as a means of incentive compensation for performance and
not primarily as an opportunity to participate in the equity appreciation in
respect of the Common Units. Therefore, no consideration will be payable by the
plan participants upon receipt of the Common Units, and we receive no
remuneration for these units. Following the subordination period, the
Compensation Committee, in it discretion, may grant distribution equivalent
rights with respect to restricted units.
Unit Options. We have not made any grants of unit options. The
Compensation Committee may, in the future, determine to make unit option grants
to employees and directors containing the specific terms that they determine.
When granted, unit options will have an exercise price set by the Compensation
Committee which may be above, below or equal to the fair market value of a
Common Unit on the date of grant. Unit options, if any, granted during the
subordination period will become exercisable upon, and in the same proportions
as, the conversion of the Subordinated Units to Common Units, or at a later date
as determined by the Compensation Committee in its sole discretion.
The Managing GP's Board of Directors, in its discretion, may terminate
the LTIP at any time with respect to any Common Units for which a grant has not
theretofore been made. The Managing GP's Board of Directors will also have the
right to alter or amend the LTIP or any part of it from time to time, subject to
unitholder approval as required by the exchange upon which the Common Units may
be listed at that time; provided, however, that no change in any outstanding
grant may be made that would materially impair the rights of the participant
without the consent of the affected participant. In addition, the Managing GP
may, in its discretion, establish such additional compensation and incentive
arrangements as it deems appropriate to motivate and reward its employees. The
Managing GP is reimbursed for all compensation expenses incurred on our behalf.
SHORT-TERM INCENTIVE PLAN
Effective January 1, 1999, the Managing GP adopted a Short-Term
Incentive Plan (the "STIP") for management and other salaried employees. The
STIP is designed to enhance the financial performance by rewarding management
and salaried employees of the Managing GP and Partnership with cash awards for
achieving an annual financial performance objective. The annual performance
objective for each year is recommended by the President and CEO of the Managing
GP and approved by the Compensation Committee of its Board of Directors prior to
January 1 of that year. The STIP is administered by the Compensation Committee.
Individual participants and payments each year are determined by and in the
discretion of the Compensation Committee, and the Managing GP is able to amend
the plan at any time. The Managing GP is entitled to reimbursement by us for the
costs incurred under the STIP.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth certain information as of December 31,
1999, regarding the beneficial ownership of units held by (a) each person known
by the Managing GP to be the beneficial owner of 5% or more of the units, (b)
each director and executive officer of the Managing GP and (c) by all directors
and executive officers of the Managing GP as a group. The Managing GP is owned
by funds affiliated with The Beacon Group and members of management. The Special
GP is a wholly-owned
54
subsidiary of ARH. The address of ARH, the Managing GP and the Special GP, is
1717 South Boulder Avenue, Tulsa, Oklahoma 74119.
[Enlarge/Download Table]
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 OWNED OWNED OWNED OWNED
-------------------------- ------------ ------------ ------------ ------------ ------------
------------------------------------------------------------------------------------------------------------------------------------
Alliance Resource GP, LLC (2) 1,232,780 13.72% 6,422,531 100% 49.7%
Alliance Resource Management GP, LLC (3) 164,000 1.83% -- -- 1.1%
Joseph W. Craft III (1) (7) 73,500 * -- -- *
Thomas L. Pearson (1) 9,521 * -- -- *
Michael L. Greenwood (1) 29,950 * -- -- *
Charles R. Wesley (1) 16,600 * -- -- *
Gary J. Rathburn (1) 8,000 * -- -- *
John J. MacWilliams (4) 1,396,780 15.55% 6,422,531 100% 50.8%
Preston R. Miller, Jr. (4) 1,396,780 15.55% 6,422,531 100% 50.8%
John P. Neafsey (1) 15,000 * -- -- *
John H. Robinson (5) -- -- -- -- --
Paul R. Tregurtha (6) -- -- -- -- --
All directors and executive officers as
a group (10 persons) 1,549,351 17.25% 6,422,531 100% 51.7%
* Less than one percent.
(1) The address of Messrs. Craft, Pearson, Greenwood, Wesley, Rathburn and
Neafsey is also 1717 South Boulder Avenue, Tulsa, Oklahoma 74119.
(2) ARH may be deemed to beneficially own the Common Units and the Subordinated
Units held by the Special GP, as a result of ARH's ownership of all of the
membership interests in the Special GP. MPC Partners, LP may also be deemed
to beneficially own the Common Units and the Subordinated Units held by the
Special GP as a result of MPC Partners' ownership of 86.2% of ARH's
outstanding common stock.
(3) The Managing GP is an affiliate of the Special GP, and as a consequence,
the Special GP may be deemed to beneficially own the Common Units held by
the Managing GP.
(4) Messrs. MacWilliams and Miller may also be deemed to share beneficial
ownership of the Common Units and the Subordinated Units held by the
Special GP and the Managing GP by virtue of their status as partners of The
Beacon Group, an affiliate of MPC Partners. Messrs. MacWilliams and Miller
disclaim beneficial ownership of the Common and Subordinated Units held by
the Special GP and the Managing GP. The address of Messrs. MacWilliams and
Miller is 399 Park Avenue, New York, New York 10022.
(5) The address of Mr. Robinson is 11401 Lamar, Overland Park, Kansas 66211.
(6) The address of Mr. Tregurtha is 3 Landmark Square, Stamford, Connecticut
06901.
(7) Mr. Craft owns 60,000 Common Units and may also be deemed to share
beneficial ownership of 13,500 Common Units held by a private foundation
for which he serves as a trustee. Mr. Craft disclaims beneficial ownership
of the Common Units held by the private foundation.
55
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The Special GP owns 1,232,780 Common Units and 6,422,531 Subordinated Units
representing an aggregate 48.7% limited partner interest in Alliance Resource
Partners. In addition, the General Partners own an aggregate 2% general partner
interest in Alliance Resource Partners, the Intermediate Partnership and the
subsidiaries on a combined basis. The Managing GP's ability, as Managing GP, to
manage and operate Alliance Resource Partners and its ownership of 164,000
Common Units together with the Special GP's ownership of 1,232,780 Common Units
and 6,422,531 Subordinated Units, effectively gives the General Partners the
ability to veto some actions of Alliance Resource Partners and to control the
management of Alliance Resource Partners.
AGREEMENTS GOVERNING CERTAIN TRANSACTIONS CONCURRENT WITH THE IPO
Alliance Resource Partners, the General Partners, the Intermediate
Partnership and some other parties entered into various documents and agreements
that resulted in certain transactions, including the vesting of assets in, and
the assumption of liabilities by, the subsidiaries, and the distribution of the
IPO proceeds. These agreements were not the result of arm's-length negotiations,
and we cannot assure you that they, or that any of the transactions that they
provide for, were effected on terms at least as favorable to the parties to
these agreements as they could have been obtained from unaffiliated third
parties. All of the transaction expenses incurred in connection with these
transactions, including the expenses associated with vesting assets into our
subsidiaries, were paid from the proceeds of the IPO.
FINANCING TRANSACTIONS CONCURRENT WITH THE IPO
We have extensive ongoing relationships with ARH and its stockholders.
These relationships include ARH's wholly-owned subsidiary, Alliance Resource GP,
LLC, which serves as our Special GP, and the ownership of Alliance Resource
Management GP, LLC, which serves as our Managing GP, by the stockholders of ARH.
See "Omnibus Agreement" below.
The Special GP distributed $279.3 million in net proceeds retained or
received by it in the IPO, the private placement of senior notes and borrowings
under the term loan facility to ARH, which is owned by management and funds
managed by The Beacon Group and its affiliates. In addition, the Special GP
retained $37.9 million of working capital assets, some portion of which it
distributed to ARH.
In connection with the IPO, ARH made 20-day unsecured loans in an aggregate
amount of up to $1.3 million at an annual interest rate of 6.84% to some of the
officers and employees of our General Partners and their respective
subsidiaries, who used the funds to purchase Common Units in this IPO, which
unsecured loans were repaid within the required time period.
UNIT PURCHASE PROGRAM BY MANAGING GP
The Managing GP authorized a Common Unit purchase program in November 1999
for the purchase of up to the greater of one million Common Units or $15 million
of Common Units. Through December 31, 1999, the Managing GP purchased 164,000
Common Units. The Common Units purchased by the Managing GP retain their rights
to receive quarterly distributions of Available Cash.
TRANSACTIONS BETWEEN US AND THE SPECIAL GP
We have entered into an arrangement with the Special GP involving the
proposed acquisition of two tracts of reserves in western Kentucky. In March
2000, we assigned to the Special GP, at our cost of approximately $200,000, two
options to acquire these properties. This transaction was reviewed and approved
by the Conflicts Committee. Later in the same month, the Special GP exercised
the options by making a payment of $1.8 million to the grantor of the options.
Upon closing of the acquisition, the Special GP, in its discretion, may choose
to lease these properties back to us or assign the option properties back to us
in return for payment for all amounts it expended in connection with the
project, plus a market rate of interest. The Special GP expects to close the
acquisition of these properties by the end of September 2000; however, we can
make no assurances that we will be able to do so. See "Item 8. Financial
Statements and Supplementary Data. -- Note 20. Subsequent Events."
56
We have also entered into an arrangement with the Special GP for the
construction of the preparation plant and ancillary facilities at our Gibson
County Coal mine. This transaction was reviewed and approved by the Conflicts
Committee. Under the terms of the arrangement, the Special GP is constructing
the preparation plant and ancillary facilities at an approximate cost of $23.1
million. Upon completion, the Special GP will have the option to sell the
preparation plant and ancillary facilities to us or to assign its rights to a
third-party financing entity. In the event the Special GP elects to sell or
lease the preparation plant and ancillary facilities to us, the sale price will
amount to the Special GP's construction costs, plus a market rate of interest on
its investment. If the Special GP elects not to sell the preparation plant and
ancillary facilities to us, we will enter into an operating lease with the
Special GP or the third-party financing entity with the option to purchase the
preparation plant and ancillary facilities at the end of the lease term.
We may enter into similar arrangements in the future to support the
acquisition of additional reserve properties or to develop facilities at our
existing mining complexes.
PURCHASE OF MANAGING GENERAL PARTNER INTEREST
As a result of the IPO, management and funds managed by The Beacon
Group and its affiliates purchased 25.9% and 74.1% interests, respectively, in
the Managing GP for approximately $5.9 million. In connection with these
purchases, ARH made 20-day secured loans in an aggregate amount of $5.9 million
at an annual rate of 6.84% to those parties who used the funds to purchase their
interests in the Managing GP, which loans were repaid within the required time
period. In turn, the Managing GP purchased its general partner interest in the
Partnership for the same amount.
OMNIBUS AGREEMENT
Concurrent with the closing of the IPO, we entered into an agreement
with ARH and the General Partners, which governs potential competition among us
and the other parties to this agreement. ARH agreed, and caused its controlled
affiliates to agree, for so long as management and funds managed by The Beacon
Group and its affiliates control the Managing GP, not to engage in the business
of mining, marketing or transporting coal in the United States unless it first
offers Alliance Resource Partners the opportunity to engage in a potential
activity or acquire a potential business, and the Board of Directors of the
Managing GP, with the concurrence of its Conflicts Committee, elects to cause us
not to pursue such opportunity or acquisition. In addition, ARH has the ability
to purchase businesses, the majority value of which is not mining, marketing or
transporting coal, provided ARH offers the Partnership the opportunity to
purchase the coal assets following their acquisition. The restriction does not
apply to the assets retained and business conducted by ARH at the closing of the
IPO. Except as provided above, ARH and its controlled affiliates are prohibited
from engaging in activities in which they compete directly with the Partnership.
In addition, The Beacon Group, and the funds it manages, are prohibited from
owning or engaging in businesses which compete with the Partnership. In addition
to its non-competition provisions, this agreement contains provisions which
indemnify the Partnership against liabilities associated with certain assets and
businesses of ARH which were disposed of or liquidated prior to consummating the
IPO.
57
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a)(1) Financial Statements.
The response to this portion of Item 14 is submitted as a separate
section herein under Part II, Item 8 - Financial Statements and
Supplementary Data.
(a)(2) Financial Statement Schedules.
No schedules are required to be presented by Alliance Resource
Partners.
(a)(3) Index of Exhibits.
3.1 Amended and Restated Agreement of Limited Partnership of
Alliance Resource Partners, L.P.
3.2 Amended and Restated Agreement of Limited Partnership of
Alliance Resource Operating Partners, L.P.
*3.3 Certificate of Limited Partnership of Alliance Resource
Partners, L.P.(Incorporated by reference to Exhibit 3.6 of the
Registrant's Registration Statement on Form S-1 filed with the
Commission on May 20, 1999).
*3.4 Certificate of Limited Partnership of Alliance Resource
Operating Partners, L.P,(Incorporated by reference to Exhibit
3.8 of the Registrants Statement on Form S-1/A filed with the
Commission on July 20, 1999).
4.1 Form of Common Unit Certificate(Included as Exhibit A to the
Amended and Restated Agreement of Limited Partnership of
Alliance Resource Partners, L.P.).
10.1 Credit Agreement, dated as of August 16, 1999, among Alliance
Resource GP, LLC, The Chase Manhattan Bank (as paying agent),
Deutsche Bank AG, New York Branch (as documentation agent),
Citicorp USA, Inc. and The Chase Manhattan Bank (as
co-administrative agents) and the lenders named therein.
10.2 Note Purchase Agreement, dated as of August 16, 1999, among
Alliance Resource GP, LLC and the purchasers named therein.
10.3 Contribution and Assumption Agreement, dated August 16, 1999,
among Alliance Resource Holdings, Inc., Alliance Resource
Management GP, LLC, Alliance Resource GP, LLC, Alliance Resource
Partners, L.P., Alliance Resource Operating Partners, L.P. and
the other parties named therein.
10.4 Omnibus Agreement, dated August 16, 1999, among Alliance
Resource Holdings, Inc., Alliance Resource Management GP, LLC,
Alliance Resource GP, LLC and Alliance Resource Partners, L.P.
*10.5 Restated and Amended Coal Supply Agreement, dated February 1,
1986, among Seminole Electric Cooperative, Inc., Webster County
Coal Corporation and White County Coal Corporation.
(Incorporated by reference to Exhibit 10.9 of the Registrant's
Registration Statement on Form S-1/A filed with the Commission
on July 20, 1999).
*10.6 Contract for Purchase and Sale of Coal, dated January 31, 1995,
between Tennessee Valley Authority and Webster County Coal
Corporation. (Incorporated by reference to Exhibit 10.10 of the
Registrant's Registration Statement on Form S-1/A filed with the
Commission on July 20, 1999).
*10.7 Assignment/Transfer Agreement between Andalex Resources, Inc.,
Hopkins County Coal, LLC, Webster County Coal Corporation and
Tennessee Valley Authority, dated January 23, 1998, with Exhibit
A-Contract for Purchase and Sale of Coal between Tennessee
Valley Authority and Andalex Resources, Inc., dated January 31,
1995.(Incorporated by reference to Exhibit 10.11 of the
Registration Statement on Form S-1/A filed with the Commission
on July 20, 1999).
58
*10.8 Contract for Purchase and Sale of Coal, dated July 7, 1998,
between Tennessee Valley Authority and Webster County Coal
Corporation.(Incorporated by reference to Exhibit 10.12 of the
Registrant's Registration Statement on Form S-1/A filed with the
Commission on July 20, 1999).
*10.9 Contract for Purchase and Sale of Coal, dated July 7, 1998,
between Tennessee Valley Authority and White County Coal
Corporation.(Incorporated by reference to Exhibit 10.13 of the
Registrant's Registration Statement on Form S-1/A filed with the
Commission on July 20, 1999).
*10.10 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 Form 10-K, filed April 1,
1996, Filed No. 1-5254).
10.11 Alliance Resource Management GP, LLC 2000 Long-term Incentive
Plan (as amended).
10.12 Alliance Resource Management GP, LLC Short-term Incentive Plan.
*10.13 Form of Employment Agreement for Messrs. Craft, Pearson,
Greenwood, Wesley, and Rathburn. (Incorporated by reference to
Exhibit 10.6 of Registrant's Statement on Form S-1/A filed
with the Commission on August 9, 1999).
21.1 List of Subsidiaries.
27.1 Financial Data Schedule.
*Incorporated by reference from the Partnership's Registration
Statement on Form S-1 (Registration No. 333-78845) and from previous
filings with the Securities and Exchange Commission.
(b) Reports on Form 8-K:
None.
59
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 23, 2000.
ALLIANCE RESOURCE PARTNERS, L.P.
By: Alliance Resource Management GP, LLC
its managing general partner
/s/ Michael L. Greenwood
--------------------------------------
Michael L. Greenwood
Senior Vice President,
Chief Financial Officer
and Treasurer
(Principal Financial Officer and
Principal Accounting Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Signature Title Date
--------- ----- ----
/s/ Joseph W. Craft III President, Chief Executive March 23, 2000
-------------------------- Officer and Director
Joseph W. Craft III (Principal Executive Officer)
/s/ Michael L. Greenwood Senior Vice President, March 23, 2000
-------------------------- Chief Financial Officer
Michael L. Greenwood and Treasurer
(Principal Financial Officer and
Principal Accounting Officer)
/s/ John J. MacWilliams Director March 23, 2000
--------------------------
John J. MacWilliams
/s/ Preston R. Miller, Jr. Director March 23, 2000
--------------------------
Preston R. Miller, Jr.
/s/ John P. Neafsey Director March 23, 2000
--------------------------
John P. Neafsey
/s/ John H. Robinson Director March 23, 2000
--------------------------
John H. Robinson
/s/ Paul R. Tregurtha Director March 23, 2000
--------------------------
Paul R. Tregurtha
60
EXHIBIT INDEX
[Download Table]
EXHIBIT
NUMBER DESCRIPTION
------ -----------
3.1 Amended and Restated Agreement of Limited Partnership of
Alliance Resource Partners, L.P.
3.2 Amended and Restated Agreement of Limited Partnership of
Alliance Resource Operating Partners, L.P.
*3.3 Certificate of Limited Partnership of Alliance Resource
Partners, L.P.(Incorporated by reference to Exhibit 3.6 of the
Registrant's Registration Statement on Form S-1 filed with the
Commission on May 20, 1999).
*3.4 Certificate of Limited Partnership of Alliance Resource
Operating Partners, L.P, (Incorporated by reference to Exhibit
3.8 of the Registrants Statement on Form S-1/A filed with the
Commission on July 20, 1999).
4.1 Form of Common Unit Certificate (Included as Exhibit A to the
Amended and Restated Agreement of Limited Partnership of
Alliance Resource Partners, L.P.).
10.1 Credit Agreement, dated as of August 16, 1999, among Alliance
Resource GP, LLC, The Chase Manhattan Bank (as paying agent),
Deutsche Bank AG, New York Branch (as documentation agent),
Citicorp USA, Inc. and The Chase Manhattan Bank (as
co-administrative agents) and the lenders named therein.
10.2 Note Purchase Agreement, dated as of August 16, 1999, among
Alliance Resource GP, LLC and the purchasers named therein.
10.3 Contribution and Assumption Agreement, dated August 16, 1999,
among Alliance Resource Holdings, Inc., Alliance Resource
Management GP, LLC, Alliance Resource GP, LLC, Alliance Resource
Partners, L.P., Alliance Resource Operating Partners, L.P. and
the other parties named therein.
10.4 Omnibus Agreement, dated August 16, 1999, among Alliance
Resource Holdings, Inc., Alliance Resource Management GP, LLC,
Alliance Resource GP, LLC and Alliance Resource Partners, L.P.
*10.5 Restated and Amended Coal Supply Agreement, dated February 1,
1986, among Seminole Electric Cooperative, Inc., Webster County
Coal Corporation and White County Coal Corporation.
(Incorporated by reference to Exhibit 10.9 of the Registrant's
Registration Statement on Form S-1/A filed with the Commission
on July 20, 1999).
*10.6 Contract for Purchase and Sale of Coal, dated January 31, 1995,
between Tennessee Valley Authority and Webster County Coal
Corporation. (Incorporated by reference to Exhibit 10.10 of the
Registrant's Registration Statement on Form S-1/A filed with the
Commission on July 20, 1999).
[Download Table]
*10.7 Assignment/Transfer Agreement between Andalex Resources, Inc.,
Hopkins County Coal, LLC, Webster County Coal Corporation and
Tennessee Valley Authority, dated January 23, 1998, with Exhibit
A-Contract for Purchase and Sale of Coal between Tennessee
Valley Authority and Andalex Resources, Inc., dated January 31,
1995.(Incorporated by reference to Exhibit 10.11 of the
Registration Statement on Form S-1/A filed with the Commission
on July 20, 1999).
*10.8 Contract for Purchase and Sale of Coal, dated July 7, 1998,
between Tennessee Valley Authority and Webster County Coal
Corporation.(Incorporated by reference to Exhibit 10.12 of the
Registrant's Registration Statement on Form S-1/A filed with the
Commission on July 20, 1999).
*10.9 Contract for Purchase and Sale of Coal, dated July 7, 1998,
between Tennessee Valley Authority and White County Coal
Corporation.(Incorporated by reference to Exhibit 10.13 of the
Registrant's Registration Statement on Form S-1/A filed with the
Commission on July 20, 1999).
*10.10 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 Form 10-K, filed April 1,
1996, Filed No. 1-5254).
10.11 Alliance Resource Management GP, LLC 2000 Long-term Incentive
Plan (as amended).
10.12 Alliance Resource Management GP, LLC Short-term Incentive Plan.
10.13 Form of Employment Agreement for Messrs. Craft, Pearson,
Greenwood, Wesley, and Rathburn. (Incorporated by reference to
Exhibit 10.6 of Registrant's Statement on Form S-1/A filed with
the Commission on August 9, 1999).
21.1 List of Subsidiaries.
27.1 Financial Data Schedule.
*Incorporated by reference from the Partnership's Registration Statement on
Form S-1 (Registration No. 333-78845) and from previous filings with the
Securities and Exchange Commission.
Dates Referenced Herein and Documents Incorporated by Reference
16 Subsequent Filings that Reference this Filing
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