2000 Annual Report
Breaking
Breaking
New
New
Ground
Ground
M e s s a g e f r o m t h e P r e s i d e n t
a n d C h i e f E x e c u t i v e O f f i c e r
Dear Fellow Unitholders:
Alliance Resource Partners, L.P.’s completion of its first full calendar year as the coal industry’s only publicly-
traded master limited partnership (MLP) has been a challenging one. We began the year with abnormally
high coal inventories following the Y2K inventory buildup and another warmer than normal winter.
Additionally, several major utilities reduced their shipments in the first quarter of the year due to unplanned
plant outages. The overhang of coal in the marketplace resulted in a dismal pricing environment. We, along
with others, responded with reduced production. Fortunately, our long-term contracts provided pricing
stability for the Partnership.
A year ago, in our annual report, we wrote that, though utility deregulation and new regulatory and legislative
initiatives create a changing economic environment within our industry, we remain convinced that increased coal
demand will be realized over the next decade. Less than one year later our view has been confirmed.
During the last half of 2000 the fundamentals for the U.S. coal industry began to drastically change. California’s
unfortunate experience with deregulation has been a wake-up call for the rest of America. The lack of
investment in electricity generation and transmission capacity has been recognized by leaders from both political
parties as an issue to be resolved. The development of a balanced national energy policy is currently a top priority
and coal is being identified by most as the practical long-term solution to U.S. electricity shortages.
The combination of the energy crisis in the western U.S., a record cold winter in the eastern U.S., increased
electricity demand throughout the country, reduced coal production, and historically high natural gas prices have
reduced industry coal inventories to levels not seen in decades. Consequently, the coal markets experienced a
dramatic turnaround in late 2000, rising more than 50% in select markets. With the majority of the Partnership’s
production under long-term contract, we are somewhat insulated by these price hikes, however, we will reap the
benefits from the improved market as contracts expire. The renewed commitment to coal by power developers
and the political leaders of our country is most encouraging to the Partnership for years to come.
Reflecting on the Partnership’s accomplishments during 2000, we significantly increased our reserve base, began
construction on the extension of our Pattiki operation, and opened our seventh mining complex, all of which will
strengthen the Partnership for the future. Our predictable and stable cash flow continues to meet expectations,
allowing us to comfortably distribute the targeted minimum quarterly distribution of $2.00 per unit on an
annualized basis during each quarter since we
became a publicly-traded partnership.
Alliance Resource Partners, L.P. (Nasdaq: ARLP)
2000 Performance Comparison
Percentage Change
The year 2000 was equally beneficial to our
unitholders as the stock market recognized the
Partnership’s efforts to excel and the favorable
outlook for the coal industry. Year-to-year price
appreciation in our unit trading value approached
50% during 2000, far exceeding the returns on
either the Dow Jones or Nasdaq composites.
When adding in the cash distributions paid in
2000, the total return on the Partnership units
was nearly 70%, making Alliance Resource
Partners, L.P. one of the best performing equities
of the year.
60
40
20
0
(20)
(40)
(60)
Dec
99
Jan
00
Feb
00
Mar
00
Apr
00
May
00
Jun
00
Jul
00
Aug
00
Sep
00
Oct
00
Nov
00
Dec
00
ARLP
DJIA
Nasdaq
I would like to personally thank our employees and unitholders for making our first complete year as a publicly-
traded master limited partnership successful. We are optimistic about the future for our industry and our
Partnership. We are committed to continually strengthen and grow our business to reward your support
and confidence.
Joseph W. Craft III
President and Chief Executive Officer
A l l i a n c e R e s o u r c e P a r t n e r s , L . P.
O p e r a t i o n s O v e r v i e w
NAPP
Mettiki
MARYLAND
IB
INDIANA
ILLINOIS
Pattiki
Gibson
County
Coal
KENTUCKY
Pontiki
MC Mining
Dotiki
Hopkins County
Coal
CAPP
Coal is the most abundant natural resource in the U.S. with nearly 300 years of supply.
Although coal resources have been found in 38 states, four regions supply more than 75%
of U.S. coal demand. The Partnership’s mining operations produce coal from three of the
four major supply areas.
M a j o r U . S . C o a l R e g i o n s
Powder River Basin Region (PRB)
Illinois Basin Region (IB)
Northern Appalachia Region (NAPP)
Central Appalachia Region (CAPP)
n Anthracite Coal
n Bituminous Coal
n Subbituminous Coal
n Lignite Coal
T o t h e U n i t h o l d e r s o f
A l l i a n c e R e s o u r c e P a r t n e r s , L . P.
Our 2000 financial results continued to
show year over year improvements.
Although a volatile marketplace and
difficult mining conditions created
challenging operating issues, the
dedication and teamwork of our
workforce again allowed the
Partnership to have another successful
year.
Financial Highlights
For the year ended December 31,
2000, the Partnership reported net
income of $15.6 million compared to
pro forma net income of $7.6 million
for 1999. Revenues were $363.5 million
and coal sales were 15.0 million tons
for 2000, compared to $365.9 million
and 15.0 million tons for 1999. EBITDA
(income before net interest expense,
income taxes, depreciation, depletion
and amortization) for 2000 was $71.3
million compared to $66.7 million in
1999. The year 2000 financial results
included unusual items totaling $9.5
million. Excluding the unusual items,
EBITDA for 2000 was $61.8 million and
net income was $6.1 million.
The Partnership produced 13.7 million
tons in 2000, a small decrease from
the prior year. The slight reduction was
primarily attributable to one of Hopkins
County Coal’s surface mines being idled
during May 2000 in response to
reduced demand due to unplanned
outages at several major utilities. Even
with lower production from Hopkins
County Coal, the Partnership
maintained its 2000 sales tonnage
consistent with 1999. Tons sold
continued at 15 million tons as we
were able to satisfy utility demand by
reducing our coal inventory stockpiles
to normal levels. The Partnership
realized slightly higher coal sales
revenues from 1999 levels due to
stronger spot coal prices resulting from
improved market conditions during the
fourth quarter of 2000.
The year 2000 contained various
isolated non-recurring events that
negatively impacted our mining costs.
During the first quarter of 2000, we
were impacted by weather-related
problems, including localized flooding
and tornadoes that interrupted
production at several of our mines.
During the second and third quarters,
our Mettiki mine encountered adverse
mining conditions due to a sandstone
intrusion in the longwall panel.
Operating expenses were also
negatively impacted by the
development of the Partnership’s new
Gibson County Coal mining complex.
Gibson County Coal incurred start-up
operating expenses of nearly $4 million
during 2000 with little revenue offset.
The combination of these factors during
2000 offset continued productivity
improvements at our operations
resulting in increased overall mining
cost per ton by 3% versus prior year
levels. Of the increase, approximately
one-half was due to the Gibson County
Coal start-up expenses. The majority of
these higher operating expenses should
be non-recurring, leading to improved
operating expenses in the future.
EBITDA
$ Millions
71.3
66.7
51.7
52.5
46.7
80
70
60
50
40
30
20
10
0
96
97
98
99
00
Although many of our increased
operating expenses were non-recurring,
they were countered by equally unusual
revenues. During the third quarter of
2000, the Partnership resolved a
transloading facility dispute with
Seminole Electric Cooperative, Inc. The
final settlement included both cash
payments and amendments to an
existing coal supply contract. The
Partnership recorded an unusual income
item, net of legal expenses and other
contingencies, of $9.5 million. The net
effect of these revenues and expenses
resulted in the Partnership recording
EBITDA of $71.3 million for 2000
compared to $66.7 million for 1999,
a nearly 7% increase. We continue to
grow and strengthen our operations to
achieve the objective of increasing the
Partnership’s distributable cash flow.
With year-end 2000 cash and
marketable securities approaching $45
million, the Partnership has funding
available to take advantage of
incremental expansion opportunities.
Long-Term Contracts
Our long-term contracts provide the
Partnership with greater predictability of
sales volumes and sales prices. In 2000,
approximately 85% of our sales
tonnage was sold under long-term
contracts with terms extending up to
2012. Our total nominal commitment
under significant long-term contracts
was approximately 75 million tons at
December 31, 2000. The electric utility
industry, as the predominant consumer
of coal, is the primary beneficiary of
these long-term contracts. The
Partnership’s history of being a proven,
reliable supplier has allowed us to
establish long-term relationships with
major electric utilities. In 2000,
approximately 50% of our total
revenues were generated from
customers that have purchased coal
regularly from us for more than 15
years. Our long-term contracts
contribute to the stability and
profitability of both the Partnership and
our customers. Although, we will
continue to reserve a level of coal
available to pursue new customers and
take advantage of favorable spot
market conditions, the maintenance of
our long-term contracts position
provides the financial support necessary
to fund future development.
Coal Reserves
In 2000, the Partnership continued to
expand its coal reserve base to provide
the necessary assets to support long-
term production. Over the last year, we
have increased our reserves from
approximately 440 million tons of
proven and probable reserves at
December 31, 1999, to approximately
465 million tons of reserves at
December 31, 2000. Since 1998, the
Partnership has more than replaced its
production, growing its reserves by
13% by adding 55 million tons to its
reserve base during this period. The
Partnership has also entered into
discussions with its Special General
Partner to lease in excess of 150 million
tons of coal located along the common
border of Pennsylvania and West
Virginia. If an agreement can be
reached, the Partnership will gain
access to the additional reserves
through either a lease or purchase
agreement. The reserves owned by the
Special General Partner are not included
in the 465 million tons of reserves
noted above.
Cost Per Ton
$ per Ton
23.62
21.18
20.14
18.75 19.30
25
20
15
10
5
0
96
97
98
99
00
Pattiki Mine Extension
The Partnership’s Pattiki mining complex
in southern Illinois, constructed and
operated since 1980, is approaching
the boundary of its existing contiguous
reserve base. To maintain our
distributable cash flow, we approved
the extension of Pattiki into adjacent
coal reserves with groundbreaking
occurring in October 2000. The
extension will involve capital
expenditures of approximately $30
million during the 2000-2003 transition
phase for new mine shafts,
underground infrastructure, and surface
handling facilities. When completed, we
expect Pattiki to be positioned to
increase its current production level for
the next 15 years. The Pattiki mine
extension provides an excellent
opportunity to build upon the success
of the existing management and
workforce.
Distributions to Unitholders
During 2000, the Partnership made
quarterly cash distributions to its
unitholders of $0.50 per unit, an
annualized rate of $2.00 per unit.
Distributions were declared and paid on
all of the Partnership’s outstanding
common and subordinated units. The
Partnership’s distributions to unitholders
are generally not taxable to the extent
of the unitholder’s tax basis. However,
each unitholder is allocated a share of
income, gains, losses and deductions.
On average, approximately 90% of the
year 2000 distributions were not
subject to current income taxes,
resulting in a significant enhancement
of the after-tax yield on the
Partnership’s units.
Future Prospects
November 2000 marked the opening of
the Partnership’s new, low-sulfur
Gibson County Coal mining complex in
southern Indiana. The start-up of the
seventh mining complex in our portfolio
concluded 18 months of project
construction begun in June 1999. As a
greenfield development project, Gibson
County Coal will require a start-up
curve to reach its full potential of over
2 million tons per year. We currently
anticipate the operation achieving its
targeted production levels in the third
quarter of 2001. With the support of
the long-term sales contract with PSI
Energy, Inc., a subsidiary of Cinergy
Corporation, committing 23 million tons
of low-sulfur production through
December 2012, the Partnership is well
positioned to generate additional cash
flow from this new mine.
The Partnership’s Special General
Partner through its affiliates have
recently acquired the operating assets
and reserves of Roberts Bros. Coal Co.,
Warrior Coal Mining Company, Warrior
Coal Corporation and Cardinal Trust
(collectively, the Warrior Group), located
adjacent to the Partnership’s Dotiki and
Hopkins County mining complexes. Due
to its proximity to existing operations,
the Partnership and an affiliate of its
Special General Partner have entered
into a mutual option agreement that
will allow the transfer of the operating
assets of the Warrior Group to the
Partnership between 2003 and 2006.
The base option is at a predetermined
price and can be exercised subject to
certain conditions. The Warrior Group is
currently undergoing expansion efforts
through 2002 that should increase its
productive capacity to more than 2.5
million tons per year. If the option is
exercised, the acquisition should provide
us with opportunities to take advantage
of favorable operating and marketing
synergies between Dotiki, Hopkins
County Coal and the Warrior Group.
Tons Produced
Millions Tons
14.1
13.7
13.4
10.9
9.0
15
12
9
6
3
0
96
97
98
99
00
With over 50% market share in 2000,
coal maintained its historical dominance
as the largest fuel source for electricity
generation in the United States. The
rolling electricity brownouts recently
experienced in major municipalities have
increased the nation’s awareness of the
need for additional, low-cost electricity.
As the nation’s largest natural resource,
coal is positioned to supply the utility
industry’s fuel requirements for
generations to come. With skyrocketing
natural gas prices, coal has further
solidified its long-term status as the
low-cost fuel alternative. The cost
advantages of coal have not been
disregarded by electricity generators. In
the United States, there are over 40
proposed coal-fired electricity capacity
additions under consideration. These
additions are not only to existing
generating units, but more than half of
the proposals are for new construction
of coal-fired utility plants. Reliable, low-
cost energy is a requirement to
maintain and improve our standard of
living. Although the coal industry
already produces in excess of one
billion tons annually, the necessary
reserve base is there to fulfill the
nation’s energy needs. The Partnership
stands ready to participate in this
growing demand for coal.
G i b s o n C o u n t y C o a l –
B r e a k i n g N e w G r o u n d
Beneath over 9,000 acres of rural farmland in southern Indiana
lies a geologic anomaly of 38 million tons of low-sulfur coal
reserves in the predominantly high-sulfur Illinois Basin region.
Beginning in late 1999, the Partnership began to take advantage
of this phenomenon by developing a new underground mining
operation located in Gibson County, Indiana. During 2000, the
Partnership completed the initial development of this untapped
reserve base and opened its seventh mining complex, the new
Gibson County Coal.
Construction Phase
In October 1999, the Partnership announced the award of
engineering and construction contracts for the development of
dual mine slopes and a mine shaft to support mining operations.
The contractor’s workforce was mobilized and construction began
immediately. Subsequent contracts were awarded by our Special
General Partner for the construction of a coal preparation plant
and handling facilities, providing the Partnership access to these
facilities under a long-term operating lease agreement. The agreed
upon construction timeline anticipated production from Gibson
County Coal to commence in late 2000.
Coal Contract
To support the economic development of Gibson County Coal,
the Partnership entered into a new long-term contract with PSI
Energy, Inc., a subsidiary of Cinergy Corporation. The contract
provides commitments for an aggregate of 23 million tons of
production from Gibson County Coal through 2012. Production is
shipped to PSI’s Gibson Generating Station, one of the largest
coal-burning electric utility plants in the United States. The low-
sulfur production from the mine is shipped via truck as the utility
plant is less than 10 miles away.
Development Phase
Primary construction was completed and Gibson County Coal
commenced production in November 2000 – on schedule and on
budget. The operation will utilize continuous mining units
employing room-and-pillar mining techniques. The mine began
production with a single mining unit in November 2000. A
second mining unit was added during the first quarter of 2001.
The continuing development of the underground infrastructure
will allow a third mining unit to be added during the second
quarter of 2001. As a start-up operation, Gibson County Coal
requires development time to reach its full potential. We currently
anticipate the mine achieving its targeted production levels of
over 2 million tons per year in the third quarter of 2001.
Expansion Potential
The low-sulfur reserve quality of Gibson County Coal is
uncommon in the Illinois Basin where it operates. This competitive
advantage should allow the Partnership to participate in niche
markets that provide additional expansion opportunities. Gibson
County Coal has been designed to be scalable, allowing operating
capacity additions by building upon the current asset
infrastructure. As Gibson County Coal completes its start-up curve,
it should not only provide additional cash flow to the Partnership,
but also provide a platform to develop new markets in the future.
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_______________
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM _____________TO_____________
COMMISSION FILE NO.: 0-26823
_______________
ALLIANCE RESOURCE PARTNERS, L.P.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE
(STATE OR OTHER JURISDICTION OF
INCORPORATION OR ORGANIZATION)
73-1564280
(IRS EMPLOYER IDENTIFICATION NO.)
1717 SOUTH BOULDER AVENUE, SUITE 600, TULSA, OKLAHOMA 74119
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES AND ZIP CODE)
(918) 295-7600
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: Common Units representing limited partner interests
_______________
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained
herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]
The aggregate value of the Common Units held by non-affiliates of the registrant (treating all executive officers and
directors of the registrant, for this purpose, as if they may be affiliates of the registrant) was approximately $147,150,647
on March 26, 2001, based on $19.81 per unit, the closing price of the Common Units as reported on the Nasdaq National
Market on such date.
As of March 26, 2001, 8,982,780 Common Units and 6,422,531 Subordinated Units are outstanding.
DOCUMENTS INCORPORATED BY REFERENCE: None
TABLE OF CONTENTS`
PART I
Page
ITEM 1. BUSINESS.......................................................................................................................
2
ITEM 2.
PROPERTIES ..................................................................................................................
13
ITEM 3. LEGAL PROCEEDINGS ................................................................................................ 16
ITEM 4.
SUBMISSION OF MATTERS TO A VOTE OF SECURITIES
HOLDERS .......................................................................................................................
17
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON UNITS AND
RELATED UNITHOLDER MATTERS ......................................................................... 17
ITEM 6.
SELECTED FINANCIAL DATA ................................................................................... 18
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS ................................. 19
ITEM 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK................................................................................................
25
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ................................ 27
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE...............................................
49
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE
MANAGING GENERAL PARTNER.............................................................................
49
ITEM 11. EXECUTIVE COMPENSATION ...................................................................................
52
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANGEMENT ....................................................................................
55
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS ............................ 57
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND
REPORTS ON FORM 8-K.............................................................................................. 59
PART IV
1
FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K contains forward-looking statements. These statements are based on the
beliefs of Alliance Resource Partners, L.P. (Partnership) as well as assumptions made by and information
currently available to the Partnership. When used in this document, the words "anticipate," "believe,"
"expect," "estimate," "forecast," "project," and similar expressions identify forward-looking statements. These
statements reflect the Partnership's current views with respect to future events and are subject to various risks,
uncertainties and assumptions including, but not limited to (a) the Partnership's dependence on significant
customer contracts and the terms of those contracts, (b) the Partnership's productivity levels and margins that
it earns from the sale of coal, (c) the effects of any unanticipated increases in labor costs, adverse changes in
work rules, or unexpected cash payments associated with post-mine reclamation, workers' compensation
claims, and environmental litigation or cleanup, (d) the risk of major mine-related accidents or interruptions,
and (e) the effects of any adverse change in the domestic coal industry, electric utility industry, or general
economic conditions. If one or more of these risks or uncertainties materialize, or should underlying
assumptions prove incorrect, actual results may vary materially from those described in this Annual Report on
Form 10-K. Except as required by applicable securities laws, the Partnership does not intend to update these
forward-looking statements.
ITEM 1. BUSINESS
GENERAL
PART I
We are a diversified producer and marketer of coal to major United States utilities and industrial users. We
began mining operations in 1971 and, since then, have grown through acquisitions and internal development
to become the eighth largest coal producer in the eastern United States. At December 31, 2000, we had
approximately 466 million tons of reserves in Illinois, Indiana, Kentucky, Maryland and West Virginia. In
2000, we produced 13.7 million tons of coal and sold 15.0 million tons of coal. The coal we produced in 2000
was 20.4% low-sulfur coal, 19.0% medium-sulfur coal and 60.6% high-sulfur coal. In 2000, approximately
96% of our medium- and high-sulfur coal was sold to utility plants with installed pollution control devices,
also known as "scrubbers," to remove sulfur dioxide.
We currently operate seven mining complexes in Illinois, Indiana, Kentucky and Maryland. Six of our
mining complexes are underground and one has both surface and underground mines. Our mining activities
are organized into three operating regions: (a) the Illinois Basin operations, (b) the East Kentucky operations,
and (c) the Maryland operations.
We and our subsidiary, Alliance Resource Operating Partners, L.P. (Intermediate Partnership), were
formed to acquire, own and operate substantially all of the coal production and marketing assets of Alliance
Resource Holdings, Inc. (ARH), a Delaware corporation formerly known as Alliance Coal Corporation. We
completed our initial public offering (IPO) on August 20, 1999, at which time ARH contributed substantially
all of its operating assets and liabilities to the Intermediate Partnership.
Our managing general partner, Alliance Resource Management GP, LLC (Managing GP) and our special
general partner, Alliance Resource GP, LLC (Special GP) (collectively, the Special GP and the Managing GP
are the General Partners) own an aggregate 2% general partner interests in the Partnership. Our limited
partners, including the General Partners as holders of Common Units and Subordinated Units, own an
aggregate 98% of the limited partner interests in the Partnership.
2
The coal production and marketing assets of ARH acquired by the Partnership are referred to as the
"Predecessor." All 1999 operating data contained herein includes the results of the Partnership and the
Predecessor.
MINING OPERATIONS
We produce a diverse range of steam coals with varying sulfur and heat contents, which enables us to
satisfy the broad range of specifications demanded by our customers. The following chart illustrates our
production by region for the last five years.
Operating Region and Mines
2000
1999
1998 1997
1996
(tons in millions)
Illinois Basin Operations:
Dotiki, Pattiki, Hopkins County, Gibson County
8.4
8.5
2.7
2.8
7.9
2.5
5.2
2.8
4.3
2.0
2.6
13.7
2.8
14.1
3.0
13.4
2.9
10.9
2.7
9.0
East Kentucky Operations:
Pontiki, MC Mining
Maryland Operations:
Mettiki
Total
Illinois Basin Operations
Our Illinois Basin mining operations are located in western Kentucky, southern Illinois and southern
Indiana. We have approximately 835 employees in the Illinois Basin and currently operate four mining
complexes.
Webster County Coal, LLC. Webster County Coal operates the Dotiki mine, which is an underground
mining complex, located in Webster and Hopkins Counties, Kentucky. The mine was opened in 1966, and we
purchased the mine in 1971. Our Dotiki operation utilizes continuous mining units employing room-and-pillar
mining techniques. The preparation plant has a throughput capacity of 1,000 tons of raw coal an hour.
Production from the mine is shipped via the CSX railroad, the Paducah & Louisville railroad and by truck.
Our primary customers for coal produced at Dotiki are Seminole Electric Cooperative, Inc. (Seminole),
Tennessee Valley Authority (TVA) and Western Kentucky Energy Corp. (WKE), which purchase our coal
pursuant to long-term contracts for use in their scrubbed generating units. During 2000, Webster County Coal
entered into a mineral lease and sublease with an affiliate of the Special GP. See “Item 13. Certain
Relationships and Related Transactions.”
White County Coal, LLC. White County Coal operates the Pattiki mine, which is an underground mining
complex, located in White County, Illinois. We began construction of the mine in 1980 and have operated it
since its inception. Our Pattiki operation utilizes continuous mining units employing room-and-pillar mining
techniques. We are in the process of extending our Pattiki mine into adjacent coal reserves. This extension
involves capital expenditures of approximately $30 million during the 2000-2003 period and allows the
Pattiki mine to continue its existing productive capacity for the next 15 years. The preparation plant has a
throughput capacity of 1,000 tons of raw coal an hour. Production from the mine is shipped via the CSX
railroad. Our primary customers for coal produced at Pattiki are Seminole and TVA, which purchase our coal
pursuant to long-term contracts for use in their scrubbed generating units.
Hopkins County Coal, LLC. Hopkins County Coal is a mining complex located in Hopkins County,
Kentucky. The operation has three surface mines, two of which are currently idle, and one underground mine.
We acquired Hopkins County Coal in January 1998. The surface operations utilize dragline mining, and the
underground operation utilizes a continuous mining unit employing room-and-pillar mining techniques. The
preparation plant has a throughput capacity of 1,000 tons of raw coal an hour. Production from the complex is
shipped via the CSX and the Paducah & Louisville railroads and by truck. Our primary customers for coal
3
produced at Hopkins County Coal include Louisville Gas & Electric, TVA and WKE, which purchase our
coal pursuant to long-term contracts for use in their scrubbed generating units. During 2000, Hopkins County
Coal entered into an option to lease and sub-lease reserves with an affiliate of the Special GP. See “Item 13.
Certain Relationships and Related Transactions.”
Gibson County Coal, LLC. Gibson County Coal is an underground mining complex located in Gibson
County, Indiana. We began construction of the mine in 1999 and commenced production in November 2000.
The Gibson County mining complex utilizes continuous mining units employing room-and-pillar mining
techniques. The preparation plant is leased from the Special GP and has a throughput capacity of 700 tons of
raw coal an hour. Production from Gibson County Coal is a low-sulfur coal, shipped via truck to our primary
customer, PSI Energy Inc., a subsidiary of Cinergy Corporation. Gibson County Coal also has approximately
104.2 million tons of undeveloped recoverable reserves, which are not contiguous to the reserves currently
being mined.
East Kentucky Operations
Our East Kentucky mining operations are located in the Central Appalachia coal fields. Our East Kentucky
mines produce low-sulfur coal. We have approximately 360 employees and operate two mining complexes in
East Kentucky.
Pontiki Coal, LLC. Pontiki is an underground mining complex located in Martin County, Kentucky. We
constructed the mine in 1977. Pontiki owns the mining complex and reserves and Excel Mining LLC, an
affiliate of Pontiki, is responsible for conducting all mining operations. All of the coal produced at Pontiki
meets or exceeds the compliance requirements of Phase II of the Clean Air Act Amendments. Our Pontiki
operation utilizes continuous mining units employing room-and-pillar mining techniques. The preparation
plant has a throughput capacity of 800 tons of raw coal an hour. Production from the mine is shipped via the
Norfolk Southern railroad and by truck. Our primary customers for coal produced at Pontiki are James River
Cogeneration Company, the successor to Cogentrix of Virginia, Inc., and AEI Coal Sales Company, Inc.
(AEI).
MC Mining, LLC. MC Mining is an underground mining complex located in Pike County, Kentucky,
acquired in 1989. Since we began operations in late 1996, MC Mining was operated by an unaffiliated
contract mining company. However, during the fourth quarter 2000, the contract mining agreement was
terminated and MC Mining entered into an intercompany support services agreement with Excel Mining.
Selected employees of the contractor and other qualified individuals were hired by Excel Mining, which is
responsible for conducting all mining operations. The operation utilizes continuous mining units employing
room-and-pillar mining techniques. The preparation plant has a throughput capacity of 800 tons of raw coal
an hour. Production from the mine is shipped via the CSX railroad and by truck. MC Mining sells its low-
sulfur production primarily in the spot market.
Toptiki Coal, LLC. Toptiki was a surface and underground mining complex located in Martin County,
Kentucky. After conducting surface mining operations through 1982 and underground operations through
1996, we discontinued mining at the complex and have since sold our member interest in Toptiki for an
immaterial amount.
Maryland Operations
Our Maryland mining operation is located in the Northern Appalachia coal fields. We have approximately
235 employees and operate one mining complex in Maryland.
Mettiki Coal, LLC. Mettiki is an underground longwall mining complex located in Garrett County,
Maryland. We constructed Mettiki in 1977 and have operated it since its inception. The operation utilizes a
longwall miner for the majority of the coal extraction as well as continuous mining units used to prepare the
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mine for future longwall mining operation areas. The preparation plant has a throughput capacity of 1,350
tons of raw coal an hour. Production from the mine is shipped via truck and the CSX railroad. Our primary
customer for coal produced at Mettiki is Virginia Electric and Power Company (VEPCO), which purchases
the coal pursuant to a long-term contract for use in the generating units at its Mt. Storm, West Virginia power
plant located less than 20 miles away. We also process coal at Mettiki for Anker Energy Corporation and one
of its affiliates.
Mettiki Coal (WV), LLC. Mettiki (WV) has approximately 20.1 million tons of undeveloped recoverable
reserves in Grant and Tucker Counties, West Virginia adjacent to Mettiki in Garrett County, Maryland. We
currently conduct no mining operations at Mettiki (WV).
OTHER OPERATIONS
Mt. Vernon Transfer Terminal, LLC
Mt. Vernon terminal is a rail-to-barge loading terminal on the Ohio River in Mt. Vernon, Indiana. The
terminal has a capacity of 5.5 million tons per year with existing ground storage. The terminal was used from
1983 through 1998 for shipments from Pattiki and Dotiki under our coal supply agreement with Seminole.
Seminole now transports these shipments directly by CSX railroad. We currently use the facility as needed
for spot shipments to customers other than Seminole and continue to explore our opportunities and options
regarding the terminal.
Coal Brokerage
We buy coal from outside producers throughout the eastern United States, which we then resell, both
directly and indirectly, to utility and industrial customers. We purchased and sold 200,000 tons of outside
coal in 2000. We have a policy of matching our outside coal purchases and sales to minimize market risks
associated with buying and reselling coal.
Additional Services
We develop and market additional services in order to establish ourselves as the supplier of choice for our
customers. Examples of the kind of services we have offered to date include ash and scrubber sludge
removal, coal yard maintenance, and arranging alternate transportation services. We will continue to think
proactively in providing additional services for customers and believe that this approach will give us a
competitive advantage in obtaining coal supply contracts in the future.
COAL MARKETING AND SALES
As is customary in the coal industry, we have entered into long-term contracts with many of our
customers. These arrangements are mutually beneficial. Our utility customers secure a fuel supply for their
power plants for years into the future. Our long-term contracts contribute to both our customers and our
stability and profitability by providing greater predictability of sales volumes and sales prices. In 2000,
approximately 85% of our sales tonnage was sold under long-term contracts with maturities ranging from
2000 to 2012. Our total nominal commitment under significant long-term contracts was approximately 74.8
million tons at December 31, 2000. The total commitment of coal under contract is an approximate number
because, in some instances, our contracts contain provisions that could cause the nominal total commitment to
increase or decrease by as much as 20%. In addition, the nominal total commitment can otherwise change
because of price reopener provisions contained in certain of these long-term contracts. We believe our long-
term contract position compares favorably to those of our competitors.
The terms of long-term contracts are the results of both bidding procedures and extensive negotiations
with the customer. As a result, the terms of these contracts vary significantly in many respects, including,
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among others, price adjustment features, price and contract reopener terms, permitted sources of supply, force
majeure provisions, coal qualities, and quantities. Virtually all of our long-term contracts are subject to price
adjustment provisions which permit an increase or decrease periodically in the contract price to reflect
changes in specified price indices or items such as taxes, royalties or actual production costs. These
provisions, however, may not assure that the contract price will reflect every change in production or other
costs. Failure of the parties to agree on a price pursuant to an adjustment or a reopener provision can lead to
early termination of a contract. Some of the long-term contracts also permit the contract to be reopened to
renegotiate terms and conditions other than the pricing terms, and where a mutually acceptable agreement on
terms and conditions cannot be concluded, either party may have the option to terminate the contract. The
long-term contracts typically stipulate procedures for quality control, sampling and weighing. Most contain
provisions requiring us to deliver coal within ranges for specific coal characteristic such as heat, sulfur, ash,
moisture, grindability, volatility and other qualities. Failure to meet these specifications can result in
economic penalties or termination of the contracts. While most of the contracts specify the approved seams
and/or approved locations from which the coal is to be mined, some contracts allow the coal to be sourced
from more than one mine or location. Although the volume to be delivered pursuant to a long-term contract is
stipulated, the buyers often have the option to vary the volume within specified limits.
RELIANCE ON MAJOR CUSTOMERS
Our four largest customers are AEI, Seminole, TVA and VEPCO. Sales to these customers in the
aggregate accounted for approximately 62% of our 2000 total revenues, and sales to each of these customers
accounted for more than 10% of our 2000 total revenues. Three of these customers have purchased coal
regularly from us for more than 15 years. A national bond rating agency has recently reported that the parent
company of one of our significant customers is in default on a significant amount of its outstanding debt. All
of the accounts receivable under the long-term contract with our customer are current. Our management does
not anticipate that this event will have a material impact on our financial condition or results of operations.
COMPETITION
The United States coal industry is highly competitive with numerous producers in all coal producing
regions. We compete with other large producers and hundreds of small producers in the United States. The
largest coal company is estimated to have sold approximately 16% of the total 2000 tonnage sold in the
United States market. We compete with other coal producers primarily on the basis of coal price at the mine,
coal quality (including sulfur content), transportation cost from the mine to the customer, and the reliability of
supply. Continued demand for our coal and the prices that we obtain are also affected by demand for
electricity, environmental and government regulations, technological developments, and the availability and
price of alternative fuel supplies, including nuclear, natural gas, oil, and hydroelectric power.
TRANSPORTATION
Our coal is transported to our customers by rail, truck and barge. Depending on the proximity of the
customer to the mine and the transportation available for delivering coal to that customer, transportation costs
can range from 10% to 60% of the delivered cost of a customer's coal. As a consequence, the availability and
cost of transportation constitute important factors in the marketability of coal. We believe our mines are
located in favorable geographic locations that minimize transportation costs for our customers.
Customers pay the transportation costs from the contractual F.O.B. point to the customer's plant. At our
Gibson and Mettiki mines, a contractor operates a truck delivery system that transports the coal from the mine
to the primary customer’s power plant.
In 2000, the largest volume transporter of our coal production was the CSX railroad, which moved
approximately 50% of our tonnage over its rail system. The practices of, and rates set by, the railroad serving
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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;
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air quality standards;
storage of petroleum products and substances which are regarded as hazardous under
applicable laws or which, if spilled, could reach waterways or wetlands;
plant and wildlife protection;
reclamation and restoration of mining properties after mining is completed;
the discharge of materials into the environment;
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- management of solid wastes generated by mining operations;
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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.
protection of wetlands;
In addition, the utility industry is subject to extensive regulation regarding the environmental impact of its
power generation activities, which could affect demand for our coal. The possibility exists that new legislation
or regulations, or new interpretations of existing laws or regulations, may be adopted that may have a
significant impact on our mining operations or our customers' ability to use coal, and may require us or our
customers to change our or their operations significantly or to incur substantial costs.
We are committed to conducting mining operations in compliance with all applicable federal, state and
local laws and regulations. However, because of extensive and comprehensive regulatory requirements,
violations during mining operations are not unusual in the industry and, notwithstanding our compliance
efforts, we do not believe these violations can be eliminated completely. None of the violations to date or the
monetary penalties assessed at our operations have been material.
While it is not possible to quantify the costs of compliance with all applicable federal and state laws, those
costs have been and are expected to continue to be significant. Capital expenditures for environmental matters
have not been material in recent years. We have accrued for the present value estimated cost of reclamation
and mine closing, including the cost of treating mine water discharge, when necessary. The accrual for
reclamation and mine closing costs is based upon permit requirements and the costs and timing of reclamation
and mine closing procedures. Although management believes it has made adequate provisions for all expected
reclamation and other costs associated with mine closures, future operating results would be adversely
affected if we later determine these accruals to be insufficient. Compliance with these laws has substantially
increased the cost of coal mining for all domestic coal producers.
Mining Permits and Approvals. Numerous governmental permits or approvals are required for mining
operations. We may be required to prepare and present to federal, state or local authorities data pertaining to
the effect or impact that any proposed production of coal may have upon the environment. All requirements
imposed by any of these authorities may be costly and time-consuming, and may delay commencement or
continuation of mining operations. Future legislation and administrative regulations may emphasize more
heavily the protection of the environment and, as a consequence, our activities may be more closely regulated.
Legislation and regulations, as well as future interpretations of existing laws, may require substantial
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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 approvals by
state regulatory authorities of a reclamation plan for restoring, upon the completion of mining, the mined
property to its approximate prior condition, productive use or other permitted condition. Typically, we
commence actions to obtain permits between 18 and 24 months before we plan to mine a new area. In our
experience, permits generally are approved within 12 months after a completed application is submitted. We
have not experienced difficulties in obtaining mining permits in the areas where our reserves are currently
located. However, we cannot assure you that we will not experience difficulty in obtaining mining permits in
the future.
Under some circumstances, substantial fines and penalties, including revocation of mining permits, may be
imposed under the laws described above. Monetary sanctions and, in severe circumstances, criminal sanctions
may be imposed for failure to comply with these laws. Regulations also provide that a mining permit can be
refused or revoked if the permit applicant or permittee owns or controls, directly or indirectly through other
entities, mining operations which have outstanding permit violations. Although we have been cited for
violations in the ordinary course of our business, we have never had a permit suspended or revoked because
of any violation, and the penalties assessed for these violations have not been material.
Mine Health and Safety Laws. Stringent safety and health standards have been imposed by federal
legislation since 1969 when the Coal Mine Health and Safety Act of 1969 (CMHSA) was adopted. CMHSA
resulted in increased operating costs and reduced productivity. The federal Mine Safety and Health Act of
1977, which significantly expanded the enforcement of health and safety standards of CMHSA, imposes
comprehensive safety and health standards on all mining operations. Regulations are comprehensive and
affect numerous aspects of mining operations, including training of mine personnel, mining procedures,
blasting, the equipment used in mining operations and other matters. The Mine Safety and Health
Administration monitors compliance with these federal laws and regulations. In addition, as part of CMHSA
and the Mine Safety and Health Act of 1977, the Black Lung Benefits Act requires payments of benefits by
all businesses that conduct current mining operations to a coal miner with black lung disease and to some
survivors of a miner who dies from this disease. Most of the states where we operate also have state programs
for mine safety and health regulation and enforcement. In combination, federal and state safety and health
regulation in the coal mining industry is perhaps the most comprehensive and rigorous system for protection
of employee safety and health affecting any segment of any industry. Even the most minute aspects of mine
operations, particularly underground mine operations, are subject to extensive regulation. This regulation has
a significant effect on our operating costs. However, our competitors in all of the areas in which we operate
are subject to the same laws and regulations.
Black Lung Benefits Act (BLBA). The federal BLBA levies a tax on production of $1.10 per ton for
underground-mined coal and $0.55 per ton for surface-mined coal, but not to exceed 4.4% of the applicable
sales price, in order to compensate miners who are totally disabled due to black lung disease and some
survivors of miners who died from this disease, and who were last employed as miners prior to 1970 or
subsequently where no responsible coal mine operator has been identified for claims. In addition, BLBA
provides that some claims for which coal operators had previously been responsible will be obligations of the
government trust funded by the tax. The Revenue Act of 1987 extended the termination date of this tax from
January 1, 1996, to the earlier of January 1, 2014, or the date on which the government trust becomes solvent.
For miners last employed as miners after 1969 and who are determined to have contracted black lung, we self-
insure against potential cost using actuarially determined estimates of the cost of present and future claims.
We are also liable under state statutes for black lung claims.
The U.S. Department of Labor has issued revised regulations that could alter the claims process for the
federal black lung benefit recipients, which among other things:
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simplify administrative procedures for the adjudication of claims;
propose preference for the miner’s treating physician under certain circumstances;
allow previously denied claims to be refiled and litigated under a different standard;
limit the amount of evidence all parties may submit for consideration;
create a rebuttable presumption that medical treatment for any pulmonary condition is caused
or aggravated by the miner’s work; and
expand the definition of pneumoconiosis and total disability.
Because the revised regulations are expected to result in an increase in the incidence and recovery of black
lung claims, both the coal and insurance industries are currently challenging through litigation certain
provisions of the revised regulations. A federal judge has granted a limited stay of the new black lung
regulations at the request of the Bush administration. Under the preliminary injunction, claims will continue
to be processed under the new regulations, but no final decisions will be made on claims for black lung
benefits filed after the new regulations became effective. The outcome of the litigation and the impact of the
revised regulations if eventually implemented on the Partnership’s liability for black lung claims cannot be
determined at this time. In addition, Congress and state legislatures regularly consider various items of black
lung legislation, which if enacted, could adversely affect our business financial condition and results of
operations.
Workers' Compensation. We are required to compensate employees for work-related injuries. Several
states in which we operate consider changes in workers compensation laws from time to time.
Coal Industry Retiree Health Benefits Act (CIRHBA). The federal CIRHBA was enacted to provide for
the funding of health benefits for some United Mine Workers of America retirees. The act merged previously
established union benefit plans into a single fund into which "signatory operators" and "related persons" are
obligated to pay annual premiums for beneficiaries. The act also created a second benefit fund for miners who
retired between July 21, 1992, and September 30, 1994, and whose former employers are no longer in
business. Because of our union-free status, we are not required to make payments to retired miners under
CIRHBA, with the exception of limited payments made on behalf of predecessors of MC Mining, LLC.
However, in connection with the sale of the coal assets acquired by ARH in 1996, MAPCO Inc. agreed to
retain all liabilities under CIRHBA.
Surface Mining Control and Reclamation Act (SMCRA). The federal SMCRA establishes operational,
reclamation and closure standards for all aspects of surface mining as well as many aspects of deep mining.
The act requires that comprehensive environmental protection and reclamation standards be met during the
course of and upon completion of mining activities. In conjunction with mining the property, we reclaim and
restore the mined areas by grading, shaping and preparing the soil for seeding. Upon completion of the
mining, reclamation generally is completed by seeding with grasses or planting trees for a variety of uses, as
specified in the approved reclamation plan. We believe that we are in compliance in all material respects with
applicable regulations relating to reclamation.
SMCRA and similar state statutes, require, among other things, that mined property be restored in
accordance with specified standards and approved reclamation plans. The act requires us to restore the surface
to approximate the original contours as contemporaneously as practicable with the completion of surface
mining operations. The mine operator must submit a bond or otherwise secure the performance of these
reclamation obligations. The earliest a reclamation bond can be released is five years after reclamation has
been achieved. Federal law and some states impose on mine operators the responsibility for replacing certain
water supplies damaged by mining operations and repairing or compensating for damage occurring on the
surface as a result of mine subsidence, a consequence of longwall mining and possibly other mining
operations. In addition, the Abandoned Mine Lands Program, which is part of SMCRA, imposes a tax on all
current mining operations, the proceeds of which are used to restore mines closed before 1977. The maximum
tax is $0.35 per ton on surface-mined coal and $0.15 per ton on underground-mined coal. We have accrued
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for the estimated costs of reclamation and mine closing, including the cost of treating mine water discharge
when necessary.
Under SMCRA, responsibility for unabated violations, unpaid civil penalties and unpaid reclamation fees
of independent contract mine operators and other third parties can be imputed to other companies which are
deemed, according to the regulations, to have "owned" or "controlled" the third party violator. Sanctions
against the "owner" or "controller" are quite severe and can include being blocked from receiving new permits
and revocation of any permits that have been issued since the time of the violations or, in the case of civil
penalties and reclamation fees, since the time their amounts became due. We are not aware of any currently
pending or asserted claims relating to the "ownership" or "control" theories discussed above. However, we
cannot assure you that such claims will not develop in the future.
Clean Air Act (CAA). The federal CAA and similar state laws, which regulate emissions into the air,
affect coal mining and processing operations primarily through permitting and emissions control
requirements. The CAA also indirectly affects coal mining operations by extensively regulating the air
emissions of coal-fired electric power generating plants. For example, the CAA requires reduction of sulfur
dioxide (SO2) emissions from electric power generation plants in two phases. Only some facilities were
subject to the Phase I requirements. Beginning in year 2000, Phase II requires nearly all facilities to reduce
emissions. The effected utilities are able to meet these requirements by:
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switching to lower sulfur fuels;
installing pollution control devices such as scrubbers;
reducing electricity generating levels; or
purchasing or trading so-called pollution "credits."
Specific emissions sources receive these "credits" that utilities and industrial concerns can trade or sell to
allow other units to emit higher levels of SO2. In addition, the CAA requires a study of utility power plant
emissions of some toxic substances and their eventual regulation, if warranted. The effect of the CAA cannot
be completely ascertained at this time, although the SO2 emissions reduction requirement is projected
generally to increase the demand for lower sulfur coal and potentially decrease demand for higher sulfur coal.
The CAA also indirectly affects coal mining operations by requiring utilities that currently are major
sources of nitrogen oxides (NOx) in moderate or higher ozone nonattainment areas to install reasonably
available control technology for NOx, which are precursors of ozone. In October 1998, the U.S.
Environmental Protection Agency (EPA) issued a rule requiring 22 eastern states and the District of Columbia
to make substantial reductions in NOx emissions by the year 2003, which was substantially upheld by the
U.S. Court of Appeals for the D.C. Circuit on March 3, 2000. On March 5, 2001, the U.S. Supreme Court
declined to review that decision, in response to a petition by seven states and the power and coal industries.
EPA expects that effected states will achieve reductions by requiring power plants to make substantial
reductions in their NOx emissions. This in turn will require power plants to install reasonably available
control technology and additional control measures. Installation of reasonably available control technology
and additional measures required under EPA regulations will make it more costly to operate coal-fired plants
and, depending on the requirements of individual state implementation plans and the development of revised
new source performance standards, could make coal a less attractive fuel alternative in the planning and
building of utility power plants in the future. Any reduction in coal's share of the capacity for power
generation could have a material adverse effect on our business, financial condition and results of operations.
The effect these regulations, or other requirements that may be imposed in the future, could have on the coal
industry in general and on our business in particular cannot be predicted with certainty. We cannot assure you
that the implementation of the CAA, the new National Ambient Air Quality Standards (NAAQS) discussed
below, or any other current or future regulatory provision, will not materially adversely affect us.
In addition, EPA has already issued and is considering further regulations relating to fugitive dust and
emissions of other coal-related pollutants such as mercury, nickel, dioxin and fine particulates. For example,
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in July 1997 EPA adopted new, more stringent NAAQS for particulate matter, which may require some states
to change existing implementation plans. These NAAQS are expected to be implemented by 2003. These
NAAQS were effectively affirmed by the U.S. Supreme Court on February 27, 2001. That decision upheld
the constitutionality of EPA’s NAAQS statutory authority, finding that EPA acted properly in not considering
costs in setting the NAAQS, and remanded the case to the U.S. Court of Appeals for the D.C. Circuit to
dispose of any remaining challenges to the rules. Because coal mining operations and utilities emit particulate
matter, our mining operations and utility customers are likely to be directly effected when the revisions to the
NAAQS are implemented by the states.
EPA has filed suit against a number of our customers over implementation of new source performance
standards and preconstruction review requirements for new sources and major modifications under the
prevention of significant deterioration and nonattainment regulations. This issue surrounds the issue of what
constitutes regular maintenance versus new construction. Some of our customers have agreed to or proposed
settlements with EPA while others are preparing for litigation. These and other regulatory developments may
restrict our ability to develop new mines, or could require us or our customers to modify existing operations.
Framework Convention On Global Climate Change (Kyoto Protocol). The United States and more than
160 other nations are signatories to the Kyoto Protocol which is intended to limit or capture emissions of
greenhouse gases, such as carbon dioxide. The Kyoto Protocol established a binding set of emissions targets
for developed nations. The specific limits vary from country to country. Under the terms of the Kyoto
Protocol, the United States would be required to reduce emissions to 93% of 1990 levels over a five-year
budget period from 2008 through 2012. The Clinton Administration signed the Kyoto Protocol in November
1998. Although the U.S. Senate has not ratified the Kyoto Protocol and no comprehensive regulations
focusing on greenhouse gas emissions have been enacted, efforts to control greenhouse gas emissions could
result in reduced use of coal if electric power generators switch to lower carbon sources of fuel. These
restrictions, if established through regulation or legislation, could have a material adverse effect on our
business, financial condition and results of operations.
Clean Water Act (CWA). The federal CWA affects coal mining operations by imposing restrictions on
effluent discharge into waters. Regular monitoring, as well as compliance with reporting requirements and
performance standards, are preconditions for the issuance and renewal of permits governing the discharge of
pollutants into water. We are also subject to CWA §404, which imposes permitting and mitigation
requirements associated with the dredging and filling of wetlands. The CWA and equivalent state legislation,
where such equivalent state legislation exists, affect coal mining operations that impact wetlands. We believe
we have obtained all necessary wetlands permits required under Section 404. However, mitigation
requirements under those existing, and possible future, wetlands permits may vary considerably. In addition,
we are currently interpreting the effect of a January 9, 2001, U.S Supreme Court ruling concerning the
definition of isolated wetlands. This issue should not cause any increase in post-mine reclamation accruals. In
fact, this decision is expected to decrease the regulatory burden on mining operations that disturb intermittent
streams and other isolated wetlands. For that reason, the setting of post-mine reclamation accruals for such
mitigation projects is difficult to ascertain with certainty. We believe that we have obtained all permits
required under the CWA as traditionally interpreted by the responsible agencies. Although more stringent
permitting requirements may be imposed in the future, we are not able to accurately predict the impact, if any,
of any such permitting requirements.
However, each individual state is required to submit to EPA their biennial CWA §303(d) lists identifying
all waterbodies not meeting state specified water quality standards. For each listed waterbody, the state is
required to begin developing a Total Maximum Daily Load (TMDL) to:
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determine the maximum pollutant loading the waterbody can assimilate without violating
water quality standards,
identify all current pollutant sources and loadings to that waterbody,
calculate the pollutant loading reduction necessary to achieve water quality standards, and
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establish a means of allocating that burden among and between the point and non-point
sources contributing pollutants to the waterbody.
We are currently participating in stakeholders meetings and in negotiations with states and EPA to
establish reasonable TMDLs that will accommodate expansion. These and other regulatory developments may
restrict our ability to develop new mines, or could require us or our customers to modify existing operations,
the extent of which we cannot accurately or reasonably predict.
Safe Drinking Water Act (SDWA). The federal SDWA and its state equivalents affect coal mining
operations by imposing requirements on the underground injection of fine coal slurries, fly ash, and flue gas
scrubber sludge, and by requiring a permit to conduct such underground injection activities. The inability to
obtain these permits could have a material impact on our ability to inject materials such as fine coal refuse, fly
ash, or flue gas scrubber sludge into the inactive areas of some of our old underground mine workings.
In addition to establishing the underground injection control program, the federal SDWA also imposes
regulatory requirements on owners and operators of "public water systems." This regulatory program could
impact our reclamation operations where subsidence, or other mining-related problems, require the provision
of drinking water to effected adjacent homeowners. However, the federal SDWA defines a "public water
system" for purposes of regulatory jurisdiction as a system for the provision to the public of water for human
consumption through pipes or other constructed conveyances, if the system has at least fifteen service
connections or regularly serves at least twenty-five individuals. It is unlikely that any of our reclamation
activities would require the provision of such a "public water system." While we have at least one drinking
water supply source for our employees and contractors that is subject to SDWA regulation, the SDWA is
unlikely to have a material impact on our operations.
Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). The federal
CERCLA and similar state laws affect coal mining operations by, among other things, imposing cleanup
requirements for threatened or actual releases of hazardous substances that may endanger public health or
welfare or the environment. Under CERCLA, and similar state laws, joint and several liability may be
imposed on waste generators, site owners and operators and others regardless of fault or the legality of the
original disposal activity. Some products used by coal companies in operations, such as chemicals, generate
waste containing hazardous substances, which are governed by the statute. Thus, coal mines that we currently
own or have previously owned or operated, and sites to which we sent waste materials, may be subject to
liability under CERCLA and similar state laws. We have been, on rare occasions, the subject of administrative
proceedings, litigation and investigations relating to CERCLA matters, none of which has had a material
adverse effect on our financial condition or results of operations. We cannot assure you that we will not
become involved in future proceedings, litigation or investigations, or that liabilities arising out of any such
proceedings will not be material.
Toxic Substances Control Act (TSCA). The federal TSCA regulates, among other things, electrical
equipment containing PCBs in excess of 50 parts-per-million. Specifically, TSCA’s PCB rules require that all
PCB-containing equipment be properly labeled, stored, and disposed of, and require the on-site maintenance
of annual records regarding the presence and use of equipment containing PCBs in excess of 50 parts-per-
million. Because the regulated PCB-containing electrical equipment in use in our operations is owned by the
utilities that serve the operations where they are located, and because the use of PCB-containing fluids in such
equipment is in the process of being phased out, we do not believe TSCA will have a material impact on our
operations.
Resource Conservation and Recovery Act (RCRA). The federal RCRA affects coal mining operations by
imposing requirements for the generation, transportation, treatment, storage, disposal and cleanup of
hazardous wastes. Many mining wastes are excluded from the regulatory definition of hazardous wastes, and
coal mining operations covered by SMCRA permits are exempted from regulation under RCRA by statute.
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Coal Combustion By-Products. In 2000, EPA declined to impose hazardous wastes regulatory controls on
the disposal of some coal combustion by-products, including the practice of using coal combustion by-
products as minefill. However, EPA is currently evaluating the possibility of placing additional solid waste
burdens on the disposal of these types of materials, but it may be several years before these standards will be
developed.
While we cannot predict the ultimate outcome of the EPA's assessment, we believe that the beneficial uses
of coal combustion by-products we employ do not constitute poor practices due to, among other things, the
fact that our CWA discharge permits for treated acid mine drainage contain parameters for pollutants of
concern, such as metals, and those permits require monitoring and reporting of effluent quality data. Small
quantities of regulated hazardous wastes are generated at some of our facilities. However, we do not believe
that the cost of complying with applicable regulations for those wastes will have a material impact.
OTHER ENVIRONMENTAL, HEALTH AND SAFETY REGULATION
In addition to the laws and regulations described above, we are subject to regulations regarding
underground and above ground storage tanks where we may store petroleum or other substances. Some
monitoring equipment that we use is subject to licensing under the federal Atomic Energy Act. Water supply
wells located on our property are subject to federal, state and local regulation. The costs of compliance with
these requirements should not have a material adverse effect on our business, financial condition or results of
operations.
EMPLOYEES
We have approximately 1,530 employees, including some 100 corporate employees and some 1,430
employees involved in active mining operations. Our work-force is entirely union-free. Relations with our
employees are generally good, and there have been no recent work stoppages or union organizing campaigns
among our employees.
ITEM 2. PROPERTIES
COAL RESERVES
As of December 31, 2000, we had approximately 466 million tons of coal reserves. All of the estimates of
reserves which are presented in this Annual Report on Form 10-K are of proven and probable reserves.
Proven and probable reserves are reserves that we can economically produce using current extraction
technology from acreage we own or lease.
The following table sets forth production data and reserve information, as of December 31, 2000, about
each of our mining complexes.
13
Location
Mine Type
Webster and Hopkins
County, KY
White County, IL
Hopkins County, KY
Gibson County, IN
Underground
Underground
Surface/
Underground
Underground
Gibson County, IN
Underground
Martin County, KY
Pike County, KY
Underground
Underground
Garrett County, MD
Grant and Tucker
County, WV
Underground
Underground
2000
Saleable
Production
(tons in
millions)
3.9
2.3
2.1
0.1
0.0
8.4
1.9
0.8
2.7
2.6
0.0
2.6
13.7
Typical Clean Coal Quality
Heat
Content (2)
(BTU
per pound)
Sulfur (2)
(%)
Ash (2)
(%)
12,500
11,700
11,300
11,600
2.9
3.0
3.2
1.0
8.1
7.9
12.4
7.0
11,600
2.1 (3)
NA
12,800
12,800
13,000
13,000
0.7
0.7
1.6
1.6
6.7
7.2
10.0
10.0
Proven and Probable Reserves
Low
Sulfur (1)
Medium
Sulfur (1)
(tons in millions)
High
Sulfur (1)
Total
107.4
107.4
81.3
35.0
49.2
272.9
44.1
44.1
0.0
0.0
36.0
20.1
56.1
100.2
21.5%
0.0
272.9
58.5%
81.3
35.0
39.4
104.2
367.3
19.7
23.1
42.8
36.0
20.1
56.1
466.2
100.0%
39.4
10.9
50.3
19.7
23.1
42.8
0.0
93.1
20.0%
(1) We classify low-sulfur coal as coal with a sulfur content of less than 1%, medium-sulfur
coal as coal with a sulfur content between 1% and 2% and high-sulfur coal as coal with
a sulfur content of greater than 2%.
(2) Fully washed quality. Actual shipped quality varies according to the blending of washed and raw coal.
(3) Sulfur (%) represents a weighted average.
Our reserve estimates are prepared from geological data assembled and analyzed by our staff of geologists
and engineers. This data is obtained through our extensive, ongoing exploration drilling and in-mine channel
sampling programs. Reserve estimates will change from time to time in reflection of mining activities,
analysis of new engineering and geological data, acquisition or divestment of reserve holdings, modification
of mining plans or mining methods, and other factors.
We estimate that approximately 62 million tons of our reserves, or approximately 67% of our low-sulfur
reserves and 13% of our total reserves at December 31, 2000, meet compliance standards for Phase II of the
Clean Air Act Amendments. Compliance coal consists of coal that emits less than 1.2 pounds of SO2 per
million Btu.
We lease almost all of our reserves and generally have the right to maintain the lease in force until the
exhaustion of minable and merchantable coal located within the leased premises or a larger coal reserve area.
These leases provide for royalties to be paid to the lessor at a fixed amount per ton or as a percentage of the
sales price. Many leases require payment of minimum royalties, payable either at the time of the execution of
the lease or in periodic installments, even if no mining activities have begun. These minimum royalties are
normally credited against the production royalties owed to a lessor once coal production has commenced.
In connection with our corporate reorganization and subsequent IPO, we obtained the consents of our
lessors or determined that obtaining such consents was not required. Although we believe we have obtained
all necessary consents, in the event that we have failed to obtain a necessary consent, our operations may be
adversely impacted if we experience any disruption of our mining operations as a consequence.
14
For economic and other operational reasons, a portion of our reserves described above may be mined only
after the construction of additional mining facilities. The extent to which we will eventually mine our reserves
will depend on the price and demand for coal of the quality and type we control, the price and supply of
alternative fuels, and future mining practices and regulations.
RISK FACTORS
If any of the following risks were actually to occur, our business, financial condition or results of
operations could be materially adversely effected and the trading price of our Common Units could decline.
Risks Inherent in Our Business
- Competition within the coal industry may adversely affect our ability to sell coal, and excess
production capacity in the industry could put downward pressure on coal prices in the future.
- Current conditions in the coal industry may change and make it more difficult for us to extend existing
or enter into new long-term contracts. This could affect the stability and profitability of our operations.
- Some of our long-term contracts contain provisions allowing for the renegotiation of prices and, in
some instances, the termination of the contract or the suspension of purchases by customers.
- Some of our long-term contracts require us to supply all of our customers coal needs. If these
customers' coal requirements decline, our revenues under these contracts will also drop.
- A substantial portion of our coal has a high-sulfur content. This coal may become more difficult to sell
because the CAA may impact the ability of electric utilities to burn high-sulfur coal through the
regulation of emissions.
- We depend on a few customers for a significant portion of our revenues, and the loss of one or more
significant customers could have a material adverse effect on our business, financial condition or
results of operations.
- Any future litigation relating to disputes with our customers may result in substantial costs, liabilities
and loss of revenues.
- Any loss of the benefit from state tax credits may affect adversely our business financial condition or
results of operations.
- Coal mining is subject to inherent risks that are beyond our control, and we cannot assure you that
these risks will be fully covered under our insurance policies.
- We depend on third party service providers to assist us in producing a portion of our coal. If these
providers' services were no longer available, our ability to produce and sell coal may be effected
adversely.
- Any significant increase in transportation costs or disruption of the transportation of our coal may
impair our ability to sell coal.
- We may not be able to grow successfully through future acquisitions, and we may not be able to
effectively integrate the various businesses or properties we do acquire.
- Our business may be adversely effected if we are unable to replace our coal reserves.
- The estimates of our reserves may prove inaccurate, and you should not place undue reliance on these
estimates.
- Our indebtedness may limit our ability to borrow additional funds, make distributions to Unitholders or
capitalize on business opportunities.
- We are required to obtain and maintain bonds to secure our obligations to return mined property to its
approximate original condition. The failure to do so may result in fines and the loss of mining permits.
Risks Inherent in an Investment in the Partnership
- Unitholders have limited voting rights and do not control our Managing GP.
- We may issue additional Common Units without the approval of Common Unitholders, which would
dilute existing Unitholders' interests.
15
- The issuance of additional Common Units, including upon conversion of Subordinated Units, will
increase the risk that we will be unable to pay the full minimum quarterly distribution on all Common
Units.
- Cost reimbursements to our General Partners may be substantial and will reduce our cash available for
distribution.
- Our Managing GP has a limited call right that may require Unitholders to sell their Common Units at
an undesirable time or price.
- Unitholders may not have limited liability under some circumstances.
- Cash distributions are not guaranteed and may fluctuate with our performance. In addition, our
Managing GP's discretion in establishing reserves may negatively impact your receipt of cash
distributions.
Regulatory Risks
- We are subject to federal, state and local regulations on numerous matters. These regulations increase
our costs of doing business and may discourage customers from buying our coal.
- We are subject to black lung benefits and workers' compensation obligations, which could increase if
new legislation is enacted.
- The CAA affects our customers and could significantly influence their purchasing decisions.
- The passage of legislation responsive to the Kyoto Protocol could result in a reduced use of coal by
electric power generators. This reduction in use could adversely affect our revenues and results of
operations.
- The CWA imposes limitations and monitoring and reporting obligations on our discharge of pollutants
into water.
- We are subject to reclamation, mine closure and real property restoration regulation obligations, which
could increase if new legislation is enacted.
- We and our customers could incur significant costs under federal and state Superfund and waste
management statutes.
Tax Risks to Common Unitholders
- The Internal Revenue Service (IRS) could in the future choose to treat us as a corporation, which would
substantially reduce the cash available for distribution to Unitholders.
- We have not requested an IRS ruling with respect to our tax treatment.
- You may be required to pay taxes on income from us even if you receive no cash distributions.
- Tax gain or loss on disposition of Common Units could be different than expected.
- Common Unitholders, other than individuals who are U.S. residents, may have adverse tax
consequences from owning Common Units.
- We have registered with the IRS as a tax shelter. This may increase the risk of an IRS audit of us or a
Common Unitholder.
- We treat a purchaser of Common Units as having the same tax benefits as the seller; the IRS may
challenge this treatment, which could adversely affect the value of the Common Units.
- Common Unitholders will likely be subject to state and local taxes as a result of an investment in units.
ITEM 3. LEGAL PROCEEDINGS
We are subject to various types of litigation in the ordinary course of our business. Disputes with our
customers over the provisions of long-term coal supply contracts arise occasionally and generally relate to,
among other things, coal quality, pricing, quantity, and the existence of force majeure conditions. Although
we are not currently involved in any litigation involving our long-term coal supply contracts, we cannot
assure you that disputes will not occur in the future or that we will be able to resolve those disputes in a
satisfactory manner. We are not engaged in any litigation which we believe is material to our operations,
including under the various environmental protection statutes to which we are subject. The information
16
under “General Litigation” under “Item 8. Financial Statements and Supplementary Data. – Note 15.
Commitments and Contingencies” is hereby incorporated by reference.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITIES HOLDERS
None.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON UNITS AND RELATED
UNITHOLDER MATTERS
The Common Units representing limited partner interests are listed on the Nasdaq National Market under
the symbol "ARLP." The Common Units began trading on August 20, 1999, when the market price for the
IPO of the Common Units was $19.00 per unit. On March 26, 2001 the closing market price for the Common
Units was $19.81 per unit. There were approximately 6,100 record holders and beneficial owners at
December 31, 2000 (held in street name) of the Partnership's Common Units.
The following table sets forth, the range of high and low sales price per Common Unit and the amount of
cash distribution declared with respect to the Units, for each quarterly period since commencement of
operations on August 20, 1999.
High Low
Distributions Per Unit
3rd Quarter 1999 (from
$
19.06
$
13.50
August 20, 1999)
$0.23 (paid November 12, 1999 for the period from
August 20, 1999, through September 30, 1999)
4th Quarter 1999
1st Quarter 2000
2nd Quarter 2000
3rd Quarter 2000
4th Quarter 2000
$
$
$
$
$
14.75
14.50
15.13
17.75
18.25
$
$
$
$
$
12.00
12.13
12.63
14.25
15.00
$0.50 (paid February 14, 2000)
$0.50 (paid May 15, 2000)
$0.50 (paid August 14, 2000)
$0.50 (paid November 14, 2000)
$0.50 (paid February 14, 2001)
The Partnership has also issued 6,422,531 Subordinated Units, all of which are held by the Special GP, for
which there is no established public trading market.
The Partnership will distribute to its partners (including holders of Subordinated Units), on a quarterly
basis, all of its Available Cash. Available Cash generally means, with respect to any quarter of the
Partnership, all cash on hand at the end of each quarter less cash reserves in an amount necessary or
appropriate in the reasonable discretion of the Managing GP to (a) provide for the proper conduct of the
Partnership's business, (b) comply with applicable law of any debt instrument or other agreement of the
Partnership or any of its affiliates, or (c) provide funds for distributions to unitholders and the General
Partners for any one or more of the next four quarters. Available Cash is defined in the Partnership Agreement
listed as an exhibit to this Annual Report on Form 10-K. The Partnership Agreement defines minimum
quarterly distributions (MQDs) as $0.50 for each full fiscal quarter. Distributions of Available Cash to the
holder of the Subordinated Units are subject to the prior rights of the holders of the Common Units to receive
MQDs for each quarter during the subordination period, and to receive any arrearages in the distribution of
the MQDs on the Common Units for prior quarters during the subordination period. The subordination period
will generally not end before September 30, 2004. Under certain circumstances, up to half of the Subordinated
17
Units may convert into Common Units before the end of the subordination period, which will generally not
occur before September 30, 2003.
ITEM 6. SELECTED FINANCIAL DATA
On August 20, 1999, the Partnership completed its IPO whereby the Partnership became the successor to
the business of the Predecessor. Our selected pro forma and historical financial data below was derived from
the audited consolidated financial statements of the Partnership as of December 31, 2000 and 1999, for the
year ended December 31, 2000 and the period from the Partnership's commencement of operations (on
August 20, 1999) to December 31, 1999, the audited combined financial statements of the Predecessor, as of
August 19, 1999, and for the period from January 1, 1999 to August 19, 1999, as of and for the years ended
December 31, 1998, and 1997, and as of and for the five months ended December 31, 1996. The Predecessor
purchased the coal operations of MAPCO Inc. effective August 1, 1996, in a business combination using the
purchase method of accounting and the purchase price was allocated to the assets acquired and liabilities
assumed based on their fair values. Accordingly, the audited financial data for periods prior to August 1,
1996, is not necessarily comparable to subsequent periods. The amounts in the table below, except for the per
unit data and the per ton information, are in millions.
Partnership
Predecessor
Year Ended
December 31,
2000
Pro Forma
Year Ended
December 31,
1999 (1)
From
Commencement
of Operations (on
August 20, 1999)
to
December 31,
1999
For the
period from
January 1, 1999
to
August 19,
1999
Year Ended
December 31,
1998
1997
Five
Months
Ended
December 31,
1996
Seven
Months
Ended
July 31,
1996
$
347.2
13.5
2.8
363.5
$
345.9
19.1
0.9
365.9
$
128.8
4.9
0.4
134.1
$
217.0
14.2
0.6
231.8
$
357.4
41.4
4.5
403.3
$
305.3
42.7
8.5
356.5
$
133.9
20.4
4.4
158.7
$
184.1
29.0
7.5
220.6
257.4
13.5
16.9
15.2
39.1
16.6
(9.5)
349.2
14.3
1.3
15.6
-
15.6
$
242.0
19.1
24.2
15.1
39.7
19.4
-
359.5
6.4
1.2
7.6
-
7.6
$
89.9
4.9
6.4
6.2
15.1
5.9
-
128.4
5.7
0.6
6.3
-
6.3
$
152.1
14.2
17.7
8.9
24.6
0.1
-
217.6
14.2
0.5
14.7
4.5
10.2
$
237.6
41.4
51.2
15.3
39.8
0.2
5.2
390.7
12.6
(0.1)
12.5
3.8
8.7
$
197.4
42.7
49.8
15.4
33.7
-
-
339.0
17.5
0.5
18.0
4.3
13.7
$
79.2
20.4
34.7
5.9
11.9
-
-
152.1
6.6
0.3
6.9
(0.9)
7.8
$
110.7
29.0
45.7
7.3
7.7
-
-
200.4
20.2
-
20.2
5.5
14.7
$
$
0.99
$
0.48
$
0.40
$
0.98
$
0.48
$
0.40
15,405,311
15,405,311
15,405,311
15,551,062
15,405,311
15,405,311
$
38.6
309.2
226.3
341.0
-
(31.8)
-
$
-
-
-
-
-
$
61.2
314.8
230.0
330.7
-
(15.9)
$
11.2
262.8
1.8
110.2
151.6
-
15.0
13.7
23.33
19.30
$
$
15.0
14.1
23.12
18.75
$
$
5.6
5.3
23.07
18.30
$
$
9.4
8.8
23.15
19.01
$
$
$
71.3
71.4
(41.0)
(31.4)
21.2
$
66.7
-
-
-
6.0
$
27.3
(13.9)
(43.9)
65.8
6.0
$
39.4
32.9
(21.5)
(11.4)
15.5
$
7.1
261.1
1.7
108.3
152.8
-
15.1
13.4
23.97
20.14
$
$
$
52.5
50.5
(35.6)
(14.9)
17.2
$
10.3
245.8
1.9
87.0
158.8
-
$
15.9
262.0
-
85.8
176.2
-
$
24.6
270.7
-
85.0
185.7
-
12.4
10.9
25.31
21.18
$
$
5.1
3.9
27.12
23.49
$
$
6.9
5.3
27.77
23.72
$
$
$
51.7
53.2
(22.4)
(30.8)
15.2
$
18.8
23.0
(13.0)
(10.0)
2.7
$
27.9
16.7
(16.7)
-
10.8
Statements of Income:
Sales and operating revenues
Coal sales
Transportation revenues (2)
Other sales and operating revenues
Total revenues
Expenses
Operating expenses
Transportation expenses (2)
Outside purchases
General and administrative
Depreciation, depletion and amortization
Interest expense
Unusual items (3)
Total expenses
Income from operations
Other income (expense)
Income before income taxes
Income tax expense (benefit)
Net income
Basic net income per limited
partner unit
Diluted net income per limited
partner unit
Weighted average number of units
outstanding-basic
Weighted average number of units
outstanding-diluted
Balance Sheet Data:
Working capital (4)
Total assets
Long-term debt
Total liabilities
Net Parent investment
Partners' capital (deficit)
Other Operating Data:
Tons sold
Tons produced
Revenues per ton sold (5)
Cost per ton sold (6)
Other Financial Data:
EBITDA (7)
Net cash provided by (used in) operating activities
Net cash used in investing activities
Net cash provided by (used in) financing activities
Maintenance capital expenditures (8)
18
(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 believed would have been incurred as a result of its being a
public entity.
(2) During the fourth quarter 2000, the Partnership adopted the Financial Accounting Standards Board Emerging Issues
Task Force Issue No. 00-10 “Accounting for Shipping and Handling Fees and Costs” (EITF No. 00-10). The
Partnership records the cost of transporting coal to customers through third party carriers and the corresponding
Partnership’s direct reimbursement of these costs through customer billings. This activity is separately presented as
transportation revenue and expense rather than offsetting these amounts in the consolidated and combined
statements of income. There was no cumulative effect of the accounting change on net income and prior periods
presented have been reclassified to comply with EITF No. 00-10.
(3) Represents income from the final resolution of an arbitrated dispute with respect to the termination of a long-term
contract, net of impairment charges relating to certain transloading facility assets, partially offset by expenses
associated with other litigation matters in 2000 and the net loss incurred during the temporary closing of one of our
mining complexes in the second half of 1998.
(4) Excludes accounts receivable from affiliates for the Predecessor prior to July 31, 1996.
(5) Revenues per ton sold is based on the total of coal sales and other sales and operating revenues divided by tons sold.
(6) Cost per ton sold is based on the total of operating expenses, outside purchases and general and administrative
expenses divided by tons sold.
(7) EBITDA is defined as income from operations before interest expense, income taxes and depreciation, depletion and
amortization. EBITDA should not be considered as an alternative to net income, income before income taxes, cash
flows from operating activities or any other measure of financial performance presented in accordance with
generally accepted accounting principles. EBITDA has not been adjusted for unusual items. EBITDA is not
intended to represent cash flow and does not represent the measure of cash available for distribution, but provides
additional information for evaluating our ability to make the MQDs. The Partnership’s method of computing
EBITDA also may not be the same method used to compute similar measures reported by other companies, or
EBITDA may be computed differently by the Partnership in different contexts (i.e., public reporting versus
computation under financing arrangements).
(8) Maintenance capital expenditures for the Partnership, as defined under the terms of the Partnership Agreement, are
defined as those capital expenditures required to maintain, over the long term, the operating capacity of our capital
assets. Maintenance capital expenditures for the Predecessor reflect our historical designation of maintenance capital
expenditures.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
GENERAL
The following discussion of the financial condition and results of operations for the Partnership and its
Predecessor should be read in conjunction with the historical financial statements and notes thereto included
elsewhere in this Annual Report on Form 10-K. For more detailed information regarding the basis of
presentation for the following financial information, see "Item 8. Financial Statements and Supplementary
Data. -- Note 1. Organization and Presentation."
19
We are a diversified producer and marketer of coal to major U.S. utilities and industrial users. In 2000, our
total production was 13.7 million tons and our total sales were 15.0 million tons. The coal we produced in
2000 was approximately 20.4% low-sulfur coal, 19.0% medium-sulfur coal and 60.6% high-sulfur coal.
At December 31, 2000, we had approximately 466 million tons of proven and probable coal reserves in
Illinois, Indiana, Kentucky, Maryland and West Virginia. We believe we control adequate reserves to
implement our currently contemplated mining plans. In addition, there are substantial unleased reserves on
adjacent properties that we intend to acquire or lease as our mining operations approach these areas.
In 2000, approximately 73% of our sales tonnage was consumed by electric utilities with the balance
consumed by cogeneration plants and industrial users. Our largest customers in 2000 were AEI, Seminole,
TVA, and VEPCO. We have had relationships with three of these customers for at least 15 years. In 2000,
approximately 85% of our sales tonnage, including approximately 86% of our medium- and high-sulfur coal
sales tonnage, was sold under long-term contracts. The balance of our sales were made on the spot market.
Our long-term contracts contribute to our stability and profitability by providing greater predictability of sales
volumes and sales prices. In 2000, approximately 96% of our medium- and high-sulfur coal was sold to utility
plants with installed pollution control devices, also known as scrubbers, to remove sulfur dioxide.
One of our business strategies is to continue to make productivity improvements to remain a low cost
producer in each region in which we operate. Our principal expenses related to the production of coal are
labor and benefits, equipment, materials and supplies, maintenance, royalties and excise taxes. Unlike most of
our competitors in the eastern U.S., we employ a totally union-free workforce. Many of the benefits of the
union-free workforce are not necessarily reflected in direct costs, but we believe are related to higher
productivity. In addition, while we do not pay our customers' transportation costs, they may be substantial
and often the determining factor in a coal consumer's contracting decision. Our mining operations are located
near many of the major eastern utility generating plants and on major coal hauling railroads in the eastern
U.S. We believe this gives us a transportation cost advantage compared to many of our competitors.
RESULTS OF OPERATIONS
In comparing 2000 to 1999 and 1999 to 1998, the Partnership and Predecessor periods for 1999 have been
combined. Since the Partnership maintained the historical basis of the Predecessor's net assets, management
believes that the combined Partnership and Predecessor results for 1999 are comparable with 1998. The
interest expense associated with the debt incurred concurrent with the closing of the IPO is applicable only to
the Partnership period. See "Item 8. Financial Statements and Supplementary Data. -- Note 1. Organization
and Presentation."
2000 Compared with 1999
Coal sales. Coal sales for 2000 increased 0.4% to $347.2 million from $345.9 million for 1999. The
increase of $1.3 million was primarily attributable to higher sales volumes in the Illinois Basin operations and
at the restructured Pontiki operation, which were directly offset by planned reduced participation in low
margin, coal export brokerage markets. The brokerage business is not expected to be material in the future.
Tons sold remained consistent at 15.0 million for 2000 and 1999. Tons produced decreased 2.9% to 13.7
million for 2000 from 14.1 million for 1999.
Transportation revenues. Transportation revenues for 2000 decreased 29.4% to $13.5 million from $19.1
million for 1999. The decrease of $5.6 million was primarily attributable to planned reduced participation in
coal export brokerage markets, which generally have higher transportation costs. No margin is realized on
transportation revenues.
Other sales and operating revenues. Other sales and operating revenues increased to $2.8 million for 2000
from $0.9 million for 1999. The increase of $1.9 million resulted from the introduction of a third party coal
20
synfuel production facility at the Hopkins County Coal mining complex. Hopkins County Coal provided the
coal feedstock and received various fees for operating the third party’s coal synfuel facility and providing
other services. We assisted the third party with marketing the coal synfuel and received a fee for such
services. Synfuel shipments continue in 2001 on a month to month basis, currently contemplated through
mid-2001, with customer interest through 2003. However, future shipments are dependent upon, among other
things, receiving a new favorable private letter ruling from the IRS. In late October 2000, the IRS issued Rev.
Proc. 2000-47, suspending issuance of private letter rulings for most coal synfuel plants while a review is
conducted concerning whether current tax rules adequately address the evolving synfuel industry. The IRS
requested public comment on Rev. Proc. 2000-47 by November 27, 2000. The IRS indicated it will provide
substantial guidance in the form of a general revenue ruling or a tax regulation to address tax credits granted
under Section 29 of the Internal Revenue Code. Until such guidance is received from the IRS, we cannot give
any assurance that future benefits will be received from the coal synfuel production facility.
Operating expenses. Operating expenses increased 6.3% to $257.4 million for 2000 from $242.0 million
for 1999. The increase of $15.4 million was a result of: (a) start-up expenses related to the opening of the
newly developed Gibson County Coal mining complex during the fourth quarter of 2000, (b) higher sales
volumes in the Illinois Basin operations, (c) increased production volumes at the restructured Pontiki
operation, and (d) prolonged adverse mining conditions at the Mettiki longwall mine.
Transportation expenses. See “Transportation Revenues” above concerning the decrease in transportation
expenses.
Outside purchases. Outside purchases declined 30.2% to $16.9 million for 2000 from $24.2 million for
1999. The decrease of $7.3 million was the result of lower coal export brokerage volumes. See “Coal sales”
above concerning the decrease in coal export brokerage volumes.
General and administrative. General and administrative expenses were comparable for 2000 and 1999 at
$15.2 million.
Depreciation, depletion and amortization. Depreciation, depletion and amortization expense were
comparable for 2000 and 1999 at $39.1 million and $39.7 million, respectively.
Interest expense. Interest expense was $16.6 million for 2000 compared to $6.0 million for 1999. The
increase reflected the full year impact of interest on the $180 million principal amount of 8.31% senior notes
and $50 million of borrowings on the term loan facility in connection with the IPO and concurrent
transactions occurring on August 20, 1999. See “Item 8. Financial Statements and Supplementary Data. --
Note 1. Organization and Presentation.”
Unusual items. The Partnership was involved in litigation with Seminole with respect to Seminole’s
termination of a long-term contract for the transloading of coal from rail to barge through the Mt. Vernon
terminal in Indiana. The final resolution between the parties, reached in conjunction with an arbitrator’s
decision rendered during the third quarter, included both cash payments and amendments to an existing coal
supply contract. The Partnership recorded income of $12.2 million, which is net of litigation expenses and
impairment charges relating to certain Mt. Vernon transloading facility assets. Additionally, the Partnership
recorded an expense of $2.7 million related to other litigation matters. The net effect of these unusual items
was $9.5 million. See “Item 8. Financial Statements. -- Note 4. Unusual Items.”
Income before income taxes. Income before income taxes was $15.6 million for 2000 compared to $21.0
million for 1999. The decrease of $5.4 million was primarily attributable to: (a) start-up expenses related to
the opening of the new Gibson County coal mining complex during the fourth quarter of 2000, (b) increased
operating expenses as a result of prolonged adverse mining conditions encountered at the Mettiki longwall
mining complex and (c) additional interest expense associated with the debt incurred concurrent with the
21
closing of the IPO, partially offset by unusual items recorded during 2000. See “Unusual items” described
above.
Income tax expense. The Partnership’s earnings or loss for federal income taxes purposes will be included
in the tax returns of the individual partners. Accordingly, no recognition is given to income taxes in the
accompanying financial statements of the Partnership. The Predecessor was included in the consolidated
federal income tax return of ARH. Federal and state income taxes were calculated as if the Predecessor had
filed its return on a separate company basis utilizing an effective income tax rate of 31%.
EBITDA (income from operations before net interest expense, income taxes, depreciation and depletion
and amortization) increased 6.9% to $71.3 million for 2000 compared with $66.7 million for 1999. The $4.6
million increase was primarily attributable to the unusual items recorded during 2000, see “Unusual items”
described above, and the increased production and sales volumes at the restructured Pontiki mine, which was
partially offset by increased operating expenses as a result of adverse mining conditions at the Mettiki
longwall mining complex.
EBITDA should not be considered as an alternative to net income, income before income taxes, cash flows
from operating activities or any other measure of financial performance presented in accordance with
generally accepted accounting principles. EBITDA has not been adjusted for unusual items. EBITDA is not
intended to represent cash flow and does not represent the measure of cash available for distribution, but
provides additional information for evaluating the Partnership’s ability to make MQDs. The Partnership’s
method of computing EBITDA also may not be the same method used to compute similar measures reported
by other companies, or EBITDA may be computed differently by the Partnership in different contexts (i.e.,
public reporting versus computation under financing agreements).
1999 Compared with 1998
Coal sales. Coal sales for 1999 declined 3.2% to $345.9 million from $357.4 million for 1998. The
decrease of $11.5 million was primarily attributable to lower coal export brokerage volumes partially offset
by improved results from the restructured Pontiki mining complex and full-year benefits from the capital
invested at Hopkins County Coal. The lower brokerage volumes were largely attributable to reduced
participation in coal export brokerage markets. The brokerage business is not expected to be material in the
future. Because coal brokerage operations generate lower margins than direct coal sales, changes in the levels
of brokerage activity have a greater impact on revenues and outside purchases than on margins. Tons sold
decreased less than 1.0% to 15.0 million tons for 1999 from 15.1 million tons for 1998. Tons produced
increased 5.1% to 14.1 million tons for 1999 from 13.4 million tons for 1998.
Transportation revenues. Transportation revenues for 1999 decreased 53.9% to $19.1 million from $41.4
million for 1998. The decrease of $22.3 million was primarily attributable to planned reduced participation in
coal export brokerage markets, which generally have higher transportation costs. No margin is realized on
transportation revenues.
Other sales and operating revenues. Other sales and operating revenues declined 79.0% to $0.9 million for
1999 from $4.5 million from 1998. The decrease of $3.6 million was primarily due to lower volumes at the
Mt. Vernon facility due to the dispute with Seminole. See "Item 8. Financial Statements and Supplementary
Data. -- Note 4. Unusual Items."
Transportation expenses. See “Transportation Revenues” above concerning the decrease in transportation
expenses.
Operating expenses. Operating expenses were comparable for 1999 and 1998 at $242.0 million and $237.6
million, an increase of 1.9%.
22
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%.
Interest expense. Interest expense was $6.0 million for 1999 compared to $0.2 million for 1998. The
increase reflected the interest on the $180 million principal amount of 8.31% senior notes and $50 million of
borrowings on the term loan facility in connection with the IPO and concurrent transactions occurring on
August 20, 1999. See “Item 8. Financial Statements and Supplementary Data. -- Note 1. Organization and
Presentation.”
Unusual items. In response to market conditions, the Pontiki mining complex ceased operations and
terminated substantially all of its workforce in September 1998. During the idle status period, which ended in
November 1998, Pontiki incurred a net loss of approximately $5.2 million consisting of estimated amounts
for increased workers' compensation claims of $1.2 million and severance payments consistent with the
Worker Adjustment and Retraining Notification Act of $1.2 million, as well as the costs associated with
maintaining an idled mine of $2.8 million.
Income before income taxes. Income before income taxes increased 67.3% to $21.0 million for 1999
compared to $12.5 million for 1998. The increase of $8.5 million was primarily attributable to improved
productivity, which included the benefits of the restructured operation at Pontiki following the idle status
period of the mine, which resulted in the $5.2 million unusual item recorded in 1998 as discussed above, and
the capital investments at the Hopkins County operation, partially offset by the losses incurred at Mt. Vernon
due to the dispute with Seminole.
Income tax expense. The Partnership's earnings or loss for federal income taxes purposes are included in
the tax returns of the individual partners. Accordingly, no recognition is given to income taxes in the
accompanying financial statements of the Partnership. The Predecessor is included in the consolidated federal
income tax return of ARH. Federal and state income taxes are calculated as if the Predecessor had filed its
return on a separate company basis utilizing an effective income tax rate of 31%.
EBITDA. (income from operations before net interest expense, income taxes, depreciation, and depletion
and amortization) increased 26.9% to $66.7 million for 1999 compared with $52.5 million for 1998. The
$14.2 million increase was attributable to the same factors that contributed to the increase in income before
income taxes.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
Cash provided by operating activities was $71.4 million in 2000 compared to $19.0 million in 1999. The
increase in cash provided by operating activities was principally attributable to the decrease in coal inventory
of approximately $10.0 million and the Special GP retaining approximately $37.9 million of trade receivables
in conjunction with the IPO and concurrent transactions that occurred on August 20, 1999.
Net cash used in investing activities of $41.0 million in 2000 was principally attributable to capital
expenditures. Net cash used in investing activities of $65.4 million for 1999 was principally attributable to
23
capital expenditures and the purchase of U.S. Treasuries in conjuction with the IPO and concurrent
transactions that occurred on August 20, 1999.
Net cash used in financing activities was $31.4 million for 2000 compared to net cash provided by
financing activities of $54.4 million for 1999. Cash used in financing activities during 2000 was a direct
result of four MQDs paid in 2000 of $0.50 per unit on Common and Subordinated Units outstanding. The net
cash provided by financing activities in 1999 was principally attributable to net cash provided by the IPO and
concurrent transactions that occurred on August 20, 1999.
Capital Expenditures
Capital expenditures increased to $46.2 million in 2000 compared to $39.2 million in 1999. The increase
was primarily attributable to the development of the new Gibson County Coal mining complex, which
commenced production in November 2000. During 2000, the Partnership liquidated approximately $7.1
million of U.S. Treasury Notes to fund various qualifying capital expenditures with the remaining
expenditures funded through cash generated from operations. The Partnership approved an extension of its
existing Pattiki mine into adjacent coal reserves. The extension involves capital expenditures of
approximately $30.0 million during the 2000-2003 period and is expected to allow the Pattiki mine to
continue its existing production level for the next 15 years.
We currently expect that our average annual maintenance capital expenditures will be approximately $23.5
million. We currently expect to fund our anticipated capital expenditures with cash generated from operations
and the utilization of the revolving credit facility described below.
Notes Offering and Credit Facility
Concurrently with the closing of the IPO, the Special GP issued and the Intermediate Partnership assumed
the obligations with respect to $180 million principal amount of 8.31% senior notes due August 20, 2014
(Senior Notes). The Special GP also entered into, and the Intermediate Partnership assumed the obligations
under a $100 million credit facility (Credit Facility). The Credit Facility consists of three tranches, including a
$50 million term loan facility, a $25 million working capital facility and a $25 million revolving credit
facility. The Partnership has borrowings outstanding of $50 million under the term loan facility, but no
borrowings outstanding under either the working capital facility or the revolving credit facility at December
31, 2000, and 1999. The weighted average interest rates on the term loan facility at December 31, 2000, and
1999, was 7.77% and 7.07%, respectively. The Credit Facility expires August 2004. The Senior Notes and
Credit Facility are guaranteed by Alliance Coal, LLC and all of its subsidiaries. In addition, the Credit
Facility is further secured by a pledge of treasury securities, which, upon written notice, are released for
purposes of financing qualified capital expenditures of the Intermediate Partnership or its subsidiaries. The
Senior Notes and Credit Facility contain various restrictive and affirmative covenants, including the amount
of distributions by the Intermediate Partnership and the incurrence of other debt.
Accruals of Other Liabilities
We had accruals for deferred credits and other liabilities, including current obligations, totaling $67.1
million and $61.9 million at December 31, 2000 and 1999. These accruals were chiefly comprised of workers'
compensation benefits, black lung benefits, and costs associated with reclamation and mine closing. These
obligations are self-insured and were funded at the time the expense was incurred. The accruals of these items
were based on estimates of future expenditures based on current legislation and related regulations and other
developments. Thus, from time to time, the Partnership's results of operations may be significantly effected by
changes to these deferred credits and other liabilities. See "Item 8. Financial Statements and Supplementary
Data. -- Note 12. Reclamation and Mine Closing Costs and Note 13. Pneumoconiosis ("Black Lung")
Benefits."
24
We are required to pay black lung benefits to eligible and former employees under the BLBA. We also
are liable under various state statutes for similar claims. We provide self-insured accruals for these benefits.
We had accrued liabilities of $22.2 million for these benefits at December 31, 2000, and 1999.
We accrue for reclamation and mine closing costs. We estimate the costs and timing of future reclamation
and mine closing costs and record those estimates on a present value basis. We had accrued liabilities of $16.0
million and $14.8 million at December 31, 2000 and 1999 for these costs.
We accrue for workers' compensation claims resulting from traumatic injuries based on actuarial
valuations and periodically adjust these estimates based on the estimated costs of claims made. We had
accrued liabilities of $20.6 million and $19.5 million at December 31, 2000 and 1999 for these costs.
INFLATION
Inflation in the U.S. has been relatively low in recent years and did not have a material impact on our
results of operations for the years ended December 31, 2000, 1999 or 1998.
RECENT ACCOUNTING PRONOUNCEMENTS
Effective January 1, 2001, the Partnership adopted Statement of Financial Accounting Standards No. 133,
“Accounting for Derivative Instruments and Hedging Activities,” which establishes accounting and reporting
standards for derivative instruments and for hedging activities. It requires that all derivatives be recognized as
either assets or liabilities in the statement of financial position and be measured at fair value. The Partnership
currently has no identified derivative instruments or hedging activities. Accordingly, this standard had no
material effect on the Partnership’s consolidated financial statements upon adoption.
During the fourth quarter 2000, the Partnership adopted Financial Accounting Standards Board Emerging
Issues Task Force Issue No. 00-10 “Accounting for Shipping and Handling Fees and Costs.” Accordingly,
the Partnership reflects the cost of transporting coal to customers through third party carriers as transportation
expenses and the corresponding reimbursement of these costs through customer billings as transportation
revenues in the consolidated and combined statements of income. These amounts were previously offset.
There was no cumulative effect on net income and the prior periods’ consolidated and combined statements of
income have been reclassified to comply with this presentation.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Almost all of the Predecessor's transactions were, and almost all of the Partnership's transactions are,
denominated in U.S. dollars, and as a result, the Partnership does not have material exposure to currency
exchange-rate risks.
The Partnership does not, engage in any interest rate, foreign currency exchange rate or commodity price-
hedging transactions.
The Intermediate Partnership assumed obligations under the Credit Facility. Borrowings under the Credit
Facility are at variable rates and as a result the Partnership has interest rate exposure.
The table below provides information about the Partnership's market sensitive financial instruments and
constitutes a "forward-looking statement." The fair values of long-term debt are estimated using discounted
cash flow analyses, based upon the Partnership's current incremental borrowing rates for similar types of
borrowing arrangements as of December 31, 2000 and 1999. The carrying amounts and fair values of
financial instruments are as follows (in thousands):
25
Expected Maturity Dates
as of December 31, 2000
Senior Notes-fixed rate
Weighted Average interest rate
2001
2002
2003
2004
2005
Thereafter
Total
Fair Value
December 31,
2000
$
-
$
-
$
-
$
-
$
18,000
8.31%
$
162,000
8.31%
$
180,000
$
180,000
Term Loan-floating rate
Weighted Average interest rate
$
3,750
7.77%
$
15,000
7.77%
$
16,250
7.77%
$
15,000
7.77%
$
-
$
-
$
50,000
$
50,000
Expected Maturity Dates
as of December 31, 1999
Senior Notes-fixed rate
Weighted Average interest rate
2000
2001
2002
2003
2004
Thereafter
Total
Fair Value
December 31,
1999
$
-
$
-
$
-
$
-
$
-
$
180,000
8.31%
$
180,000
$
165,000
Term Loan-floating rate
Weighted Average interest rate
$
-
$
3,750
7.07%
$
15,000
7.07%
$
16,250
7.07%
$
15,000
7.07%
$
-
$
50,000
$
50,000
26
INDEPENDENT AUDITORS’ REPORT
To the Board of Directors of the Managing
General Partner and the Partners of
Alliance Resource Partners, L.P.:
We have audited the accompanying consolidated balance sheets of Alliance Resource Partners, L.P.
and subsidiaries (the “Partnership”) as of December 31, 2000 and 1999, the related consolidated and
combined statements of income and cash flows for the year ended December 31, 2000 and the period
from the Partnership’s commencement of operations (on August 20, 1999) to December 31, 1999 and
the Predecessor period from January 1, 1999 to August 19, 1999 and the year ended December 31,
1998 and the statement of Partners’ capital (deficit) for the year ended December 31, 2000 and the
period from the Partnership’s commencement of operations (on August 20, 1999) to December 31,
1999. These financial statements are the responsibility of the Partnership’s management. Our
responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States
of America. Those standards require that we plan and perform the audit to obtain reasonable assurance
about whether the financial statements are free of material misstatement. An audit includes examining,
on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates made by management,
as well as evaluating the overall financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated and combined financial statements present fairly, in all material
respects, the financial position of the Partnership at December 31, 2000 and 1999 and the results of
their operations and their cash flows for the year ended December 31, 2000 and the period from the
Partnership’s commencement of operations (on August 20, 1999) to December 31, 1999 and the
Predecessor period from January 1, 1999 to August 19, 1999 and the year ended December 31, 1998 in
conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Tulsa, Oklahoma
January 24, 2001
27
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2000 AND 1999
(In thousands, except unit data)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents
Trade receivables
Due from affiliates
Marketable securities (at cost, which approximates fair value)
Inventories
Advance royalties
Prepaid expenses and other assets
Total current assets
PROPERTY, PLANT AND EQUIPMENT AT COST
LESS ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
OTHER ASSETS:
Advance royalties
Coal supply agreements, net
Other long-term assets
LIABILITIES AND PARTNERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable
Due to affiliates
Accrued taxes other than income taxes
Accrued payroll and related expenses
Accrued interest
Workers’ compensation and pneumoconiosis benefits
Other current liabilities
Current maturities, long-term debt
Total current liabilities
LONG-TERM LIABILITIES:
Long-term debt, excluding current maturities
Accrued pneumoconiosis benefits
Workers’ compensation
Reclamation and mine closing
Due to affiliates
Other liabilities
Total liabilities
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL (DEFICIT):
Common Unitholders 8,982,780 units outstanding
Subordinated Unitholder 6,422,531 units outstanding
General Partners
Total Partners’ capital (deficit)
See notes to consolidated and combined financial statements.
28
December 31,
2000
1999
$
6,933
35,898
208
37,398
10,842
2,865
1,168
95,312
320,445
(135,782)
184,663
10,009
16,324
2,858
309,166
$
$
25,558
-
4,863
6,975
5,439
4,415
5,710
3,750
$
8,000
33,056
-
42,339
21,130
1,557
923
107,005
278,221
(102,709)
175,512
8,306
19,879
4,112
314,814
$
$
19,377
334
4,574
8,811
5,491
4,317
2,937
-
56,710
45,841
226,250
21,651
16,748
14,940
1,278
3,376
340,953
230,000
21,655
15,696
13,407
472
3,671
330,742
149,642
116,794
(298,223)
(31,787)
309,166
$
158,705
123,273
(297,906)
(15,928)
314,814
$
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED AND COMBINED STATEMENTS OF INCOME
FOR THE YEAR ENDED DECEMBER 31, 2000 AND THE PERIOD FROM THE PARTNERSHIP’S COMMENCEMENT OF
OPERATIONS (ON AUGUST 20, 1999) TO DECEMBER 31, 1999 AND THE PREDECESSOR PERIOD FROM
JANUARY 1, 1999 TO AUGUST 19, 1999 AND THE YEAR ENDED DECEMBER 31, 1998
(In thousands, except unit and per unit data)
SALES AND OPERATING REVENUES:
Coal sales
Transportation revenues
Other sales and operating revenues
Total revenues
EXPENSES:
Operating expenses
Transportation expenses
Outside purchases
General and administrative
Depreciation, depletion and amortization
Interest expense (net of interest income and interest
capitalized of $3,015 and $999 for the year ended
December 31, 2000 and 1999 partnership period)
Unusual items
Total operating expenses
INCOME FROM OPERATIONS
OTHER INCOME (EXPENSE)
INCOME BEFORE INCOME TAXES
INCOME TAX EXPENSE
NET INCOME
GENERAL PARTNERS’ INTEREST
IN NET INCOME
LIMITED PARTNERS’ INTEREST
IN NET INCOME
BASIC NET INCOME PER LIMITED
PARTNER UNIT
DILUTED NET INCOME PER LIMITED
PARTNER UNIT
WEIGHTED AVERAGE NUMBER
OF UNITS OUTSTANDING - BASIC
WEIGHTED AVERAGE NUMBER
OF UNITS OUTSTANDING - DILUTED
See notes to consolidated and combined financial statements.
Partnership
Predecessor
From
Commencement
of Operations
(on August 20, 1999)
to
December 31, 1999
For the
period from
January 1, 1999
to
August 19, 1999
Year Ended
December 31,
2000
Year Ended
December 31,
1998
$
347,209
13,511
2,749
363,469
$
128,860
4,907
358
134,125
$
217,033
14,223
577
231,833
$
357,440
41,408
4,453
403,301
257,365
13,511
16,874
15,176
39,141
16,563
(9,466)
349,164
14,305
1,276
15,581
-
89,945
4,907
6,429
6,245
15,081
5,887
-
128,494
5,631
641
6,272
-
152,066
14,223
17,738
8,912
24,622
100
-
217,661
14,172
531
14,703
4,498
237,576
41,408
51,151
15,301
39,838
169
5,211
390,654
12,647
(113)
12,534
3,866
$
15,581
$
6,272
$
10,205
$
8,668
$
312
$
125
$
15,269
$
6,147
$
0.99
$
0.40
$
0.98
$
0.40
15,405,311
15,405,311
15,551,062
15,405,311
29
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOW
FOR THE YEAR ENDED DECEMBER 31, 2000 AND THE PERIOD FROM THE PARTNERSHIP’S COMMENCEMENT OF
OPERATIONS (ON AUGUST 20, 1999) TO DECEMBER 31, 1999 AND THE PREDECESSOR PERIOD FROM
JANUARY 1, 1999 TO AUGUST 19, 1999 AND THE YEAR ENDED DECEMBER 31, 1998
(In thousands)
Partnership
Predecessor
From
Commencement
of Operations
(on August 20, 1999)
to
December 31, 1999
Year Ended
December 31,
2000
For the
period from
January 1, 1999 Year Ended
December 31,
1998
to
August 19, 1999
$
15,581
$
6,272
$
10,205
$
8,668
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization
Impairment of transloading facility
Deferred income taxes
Reclamation and mine closings
Coal inventory adjustment to market
Other
Changes in operating assets and liabilities, net of effects
from 1998 purchase of coal business:
Trade receivables
Income tax receivable/payable
Inventories
Advance royalties
Accounts payable
Due to affiliates
Accrued taxes other than income taxes
Accrued payroll and related benefits
Accrued pneumoconiosis benefits
Workers’ compensation
Other
Total net adjustments
Net cash provided by (used in) operating activities
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of property, plant and equipment
Proceeds from sale of property, plant and equipment
Purchase of marketable securities
Proceeds from the maturity of marketable securities
Payment for purchase of business
Direct acquisition costs
Net cash used in investing activities
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from initial public offering (Note 1)
Cash contribution by General Partner
Distributions upon formation (Note 1)
Payment of formation costs
Deferred financing cost
Borrowings under revolving credit facility
Payments under revolving credit facility
Payments on long-term debt
Distributions to Partners
Dividend to Parent
Return of capital to Parent
Net cash provided by (used in) financing activities
39,141
2,439
-
1,074
579
391
(2,842)
-
9,709
(3,011)
6,181
264
289
(1,836)
(4)
1,052
2,366
55,792
71,373
(46,151)
210
(72,523)
77,464
-
-
(41,000)
-
-
-
-
-
29,500
(29,500)
-
(31,440)
-
-
(31,440)
NET CHANGE IN CASH AND CASH EQUIVALENTS
(1,067)
CASH AND CASH EQUIVALENTS AT
BEGINNING OF PERIOD
8,000
15,081
-
-
348
729
186
(33,048)
-
(1,433)
366
(7,410)
3,252
(630)
844
(1,122)
2,222
452
(20,163)
(13,891)
(17,173)
125
(51,287)
24,434
-
-
(43,901)
137,872
5,917
(64,750)
(4,140)
(3,517)
-
-
(1,975)
(3,615)
-
-
65,792
8,000
-
24,622
-
639
457
-
(114)
(6,521)
651
(371)
1,153
(129)
-
678
(828)
544
(460)
2,370
22,691
32,896
(21,984)
447
-
-
-
-
(21,537)
-
-
-
-
-
-
-
-
-
-
(11,359)
(11,359)
-
-
39,838
-
(1,750)
705
1,743
34
229
2,482
(6,563)
579
2,296
-
1,137
491
839
817
(1,048)
41,829
50,497
(27,669)
185
-
-
(7,310)
(821)
(35,615)
-
-
-
-
-
-
-
(350)
-
(8,642)
(5,890)
(14,882)
-
-
CASH AND CASH EQUIVALENTS AT END OF PERIOD
$
6,933
$
8,000
$
-
$
-
See notes to consolidated and combined financial statements.
30
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL (DEFICIT)
FOR THE YEAR ENDED DECEMBER 31, 2000 AND THE PERIOD FROM THE PARTNERSHIP’S
COMMENCEMENT OF OPERATIONS (ON AUGUST 20, 1999) TO DECEMBER 31, 1999
(In thousands, except unit data)
Number of Limited
Partner Units
Common
Subordinated
Common
Subordinated
General
Partners
Minimum
Pension
Liability
Total
Partners’
Capital
(Deficit)
Balance at commencement of
operations (on August 20, 1999)
-
Issuance of units to public
7,750,000
-
-
$
-
$
1
$
-
$
-
$
1
133,732
-
-
-
133,732
1,232,780
6,422,531
23,455
122,186
(24,612)
(459)
120,570
-
-
-
-
5,917
-
5,917
Contribution of net assets of
Predecessor
Managing General Partner
contribution
Amount retained by Special
General Partner from
debt borrowings assumed
by the Partnership
Distribution at time of formation
Distribution to Partners
Comprehensive income:
Net income from
commencement of
operations (on August 20,
1999) to December 31, 1999
Minimum pension liability
Total comprehensive income
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
(214,514)
(64,750)
(2,066)
(1,477)
(72)
3,584
-
3,584
2,563
-
2,563
125
-
125
-
-
-
-
459
459
-
-
-
(214,514)
(64,750)
(3,615)
6,272
459
6,731
(15,928)
15,581
(31,440)
Balance at December 31, 1999
8,982,780
6,422,531
158,705
123,273
(297,906)
Net income
Distribution to Partners
-
-
-
-
8,903
6,366
(17,966)
(12,845)
312
(629)
Balance at December 31, 2000
8,982,780
6,422,531
$
149,642
$
116,794
$
(298,223)
$
-
$
(31,787)
See notes to consolidated and combined financial statements.
31
ALLIANCE RESOURCE PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
FOR THE YEAR ENDED DECEMBER 31, 2000 AND THE PERIOD FROM THE
PARTNERSHIP’S COMMENCEMENT OF OPERATIONS (ON AUGUST 20, 1999) TO
DECEMBER 31, 1999 AND THE PREDECESSOR PERIOD FROM JANUARY 1, 1999 TO
AUGUST 19, 1999 AND THE YEAR ENDED DECEMBER 31, 1998
1. ORGANIZATION AND PRESENTATION
Alliance Resource Partners, L.P., a Delaware limited partnership (the “Partnership”) was formed on
May 17, 1999, to acquire, own and operate certain coal production and marketing assets of Alliance
Resource Holdings, Inc., a Delaware corporation (“ARH”) (formerly known as Alliance Coal
Corporation), consisting of substantially all of ARH’s operating subsidiaries, but excluding ARH.
Prior to August 20, 1999, (a) MAPCO Coal Inc., a Delaware corporation and direct wholly-owned
subsidiary of ARH merged with and into Alliance Coal, LLC, a Delaware limited liability company
(“Alliance Coal”), which prior to August 20, 1999 was also a wholly-owned subsidiary of ARH,
(b) several other indirect corporate subsidiaries of ARH were merged with and into corresponding
limited liability companies, each of which is a wholly-owned subsidiary of Alliance Coal, and (c) two
indirect limited liability company subsidiaries of ARH became subsidiaries of Alliance Coal as a result
of the merger described in clause (a) above. Collectively, the coal production and marketing assets and
operating subsidiaries of ARH acquired by the Partnership, but excluding ARH, are referred to as the
Alliance Resource Group (the “Predecessor”). The Delaware limited partnerships and limited liability
companies that comprise the Partnership are as follows: Alliance Resource Partners, L.P., Alliance
Resource Operating Partners, L.P. (the “Intermediate Partnership”), Alliance Coal, LLC (the holding
company for operations), Alliance Land, LLC, Alliance Properties, LLC, Backbone Mountain, LLC,
Excel Mining, LLC, Gibson County Coal, LLC, Hopkins County Coal, LLC, MC Mining, LLC, Mettiki
Coal, LLC, Mettiki Coal (WV), LLC, Mt. Vernon Transfer Terminal, LLC, Pontiki Coal, LLC, Webster
County Coal, LLC, and White County Coal, LLC.
The accompanying consolidated financial statements include the accounts and operations of the limited
partnerships and limited liability companies disclosed above and present the financial position as of
December 31, 2000 and 1999 and the results of their operations, cash flows and changes in partners’
capital (deficit) for the year ended December 31, 2000 and the period from commencement of operations
on August 20, 1999 to December 31, 1999. The accompanying combined financial statements include
the accounts and operations of the Predecessor for the periods indicated. All material intercompany
transactions and accounts of the Partnership and Predecessor have been eliminated.
Initial Public Offering and Concurrent Transactions
On August 20, 1999, the Partnership completed its initial public offering (the “IPO”) of 7,750,000
Common Units (“Common Units”) representing limited partner interests in the Partnership at a price of
$19.00 per unit.
Concurrently with the closing of the IPO, the Partnership entered into a contribution and assumption
agreement (the “Contribution Agreement”) dated August 20, 1999 among the Partnership and the other
parties named therein, whereby, among other things, ARH contributed its 100% member interest in
Alliance Coal, which is the sole member of thirteen subsidiary operating limited liability companies, to
the Intermediate Partnership, and the Intermediate Partnership holds a 99.999% non-managing member
interest in Alliance Coal. The Partnership and the Intermediate Partnership are managed by Alliance
Resource Management GP, LLC, a Delaware limited liability company (the “Managing GP”), which as
32
a result of the consummation of the transactions under the Contribution Agreement, holds (a) a 0.99%
and 1.0001% managing general partner interest in the Partnership and the Intermediate Partnership,
respectively, and (b) a 0.001% managing member interest in Alliance Coal. Also, as a result of the
consummation of the transactions completed under the Contribution Agreement, Alliance Resource GP,
LLC, a Delaware limited liability company and wholly-owned subsidiary of ARH (the “Special GP”),
holds (a) 1,232,780 Common Units, (b) 6,422,531 Subordinated Units convertible into Common Units
in the future upon the occurrence of certain events and (c) a 0.01% special general partner interest in
each of the Partnership and the Intermediate Partnership.
Concurrently with the closing of the IPO, the Special GP issued and the Intermediate Partnership
assumed the obligations under a $180 million principal amount of 8.31% senior notes due August 20,
2014. The Special GP also entered into and the Intermediate Partnership assumed the obligations under
a $100 million credit facility.
Consistent with guidance provided by the Emerging Issues Task Force in Issue No. 87-21 “Change of
Accounting Basis in Master Limited Partnership Transactions,” the Partnership maintained the historical
cost of the $121 million of net assets received under the Contribution Agreement.
Pro Forma Results of Operations (Unaudited)
For the years ended December 31, 1999 and 1998, the pro forma total revenues would have been
approximately $346,828,000 and $361,893,000, respectively. For the years ended December 31, 1999
and 1998, the pro forma net income (loss) would have been approximately $7,567,000 and $(6,740,000)
and net income (loss) per limited partner unit would have been $0.48 and $(0.43), respectively. The pro
forma results of operations for the years ended December 31, 1999 and 1998, are derived from the
historical financial statements of the Partnership from the commencement of operations on August 20,
1999 through December 31, 1999 and the Predecessor for the period from January 1, 1999 through
August 19, 1999, and January 1, 1998 through December 31, 1998. The pro forma results of operations
reflect certain pro forma adjustments to the historical results of operations as if the Partnership had been
formed on January 1, 1998. The pro forma adjustments include (i) pro forma interest on debt assumed
by the Partnership and (ii) the elimination of income tax expense as income taxes will be borne by the
partners and not the Partnership.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Estimates – The preparation of consolidated and combined financial statements in conformity with
generally accepted accounting principles requires management to make estimates and assumptions that
affect the reported amounts and disclosures in the consolidated and combined financial statements.
Actual results could differ from those estimates.
Fair Value of Financial Instruments – The carrying amounts for accounts receivable, marketable
securities and accounts payable approximate fair value because of the short maturity of those
instruments. At December 31, 2000 and 1999, the estimated fair value of long-term debt was
approximately $230 million and $215 million, respectively. The fair value of long-term debt is based on
interest rates that are currently available to the Partnership for issuance of debt with similar terms and
remaining maturities.
Cash Management – The Partnership reclassified outstanding checks of $4,698,000 and $3,844,000 at
December 31, 2000 and 1999, respectively, to accounts payable in the consolidated balance sheets.
Marketable Securities – The Partnership has investments in six month U.S. Treasury Notes that are
classified as available-for-sale debt securities. These investments are subject to certain provisions of the
credit facility (Note 7), which could restrict the use of these investments for financing a required level of
33
capital expenditures within the second anniversary of the credit facility’s effective date. At
December 31, 2000, the Partnership has satisfied the capital expenditure requirements and consequently,
the Partnership’s use of the investments is not restricted. At December 31, 2000 and 1999, the cost of
these investments approximates fair value and no effect of unrealized gains (losses) is reflected in
Partners’ capital (deficit).
Inventories – Coal inventories are stated at the lower of cost or market on a first-in, first-out basis.
Supply inventories are stated at the lower of cost or market on an average cost basis.
Property, Plant and Equipment – Additions and replacements constituting improvements are
capitalized. Maintenance, repairs, and minor replacements are expensed as incurred. Depreciation and
amortization are computed principally on the straight-line method based upon the estimated useful lives
of the assets or the estimated life of each mine (9 to 15 years at the revaluation date of August 1, 1996),
whichever is less and for 5 years on certain assets related to the 1998 business acquisition. Depreciable
lives for mining equipment and processing facilities range from 1 to 15 years. Depreciable lives for land
and land improvements and depletable lives for mineral rights range from 5 to 15 years. Depreciable
lives for buildings, office equipment and improvements range from 1 to 13 years. Gains or losses
arising from retirements are included in current operations. Depletion of mineral rights is provided on
the basis of tonnage mined in relation to estimated recoverable tonnage.
Long-Lived Assets – The Partnership reviews the carrying value of long-lived assets and certain
identifiable intangibles whenever events or changes in circumstances indicate that the carrying amount
may not be recoverable based upon estimated undiscounted future cash flows. The amount of an
impairment is measured by the difference between the carrying value and the fair value of the asset,
which is based on cash flows from that asset, discounted at a rate commensurate with the risk involved.
During 2000, the Partnership recorded an impairment loss of approximately $2,439,000 relating to
certain transloading facility assets, which is included as an unusual item in the accompanying
consolidated and combined statements of operations.
Advance Royalties – Rights to coal mineral leases are often acquired through advance royalty payments.
Management assesses the recoverability of royalty prepayments based on estimated future production
and capitalizes these amounts accordingly. Royalty prepayments expected to be recouped within one
year are classified as a current asset. As mining occurs on those leases, the royalty prepayments are
included in the cost of mined coal. Royalty prepayments estimated to be nonrecoverable are expensed.
Coal Supply Agreements – The Predecessor purchased the coal operations of MAPCO Inc. effective
August 1, 1996, in a business combination using the purchase method of accounting. A portion of the
acquisition costs was allocated to coal supply agreements. This allocated cost is being amortized on the
basis of coal shipped in relation to total coal to be supplied during the respective contract term. The
amortization periods end on various dates from September 2002 to December 2005. Accumulated
amortization for coal supply agreements was $22,139,000 and $18,584,000 at December 31, 2000 and
1999, respectively.
Reclamation and Mine Closing Costs – Estimates of the cost of future mine reclamation and closing
procedures of currently active mines are recorded on a present value basis. Those costs relate to sealing
portals at underground mines and to reclaiming the final pit and support acreage at surface mines. Other
costs common to both types of mining are related to removing or covering refuse piles and settling
ponds and dismantling preparation plants and other facilities and roadway infrastructure. Ongoing
reclamation costs principally involve restoration of disturbed land and are expensed as incurred during
the mining process.
Workers’ Compensation and Pneumoconiosis (“Black Lung”) Benefits – The Partnership is
self-insured for workers’ compensation benefits, including black lung benefits. The Partnership accrues
34
a workers’ compensation liability for the estimated present value of current and, in the case of black
lung benefits, future workers’ compensation benefits based on actuarial valuations.
Income Taxes – No provision for income taxes related to the operations of the Partnership is included in
the accompanying consolidated financial statements because, as a Partnership, it is not subject to federal
or state income tax and the tax effect of its activities accrues to the unitholders. Net income for financial
statement purposes may differ significantly from taxable income reportable to unitholders as a result of
differences between the tax bases and financial reporting bases of assets and liabilities and the taxable
income allocation requirements under the Partnership agreement.
The Predecessor is included in the combined U.S. income tax returns of ARH. The Predecessor has
provided for income taxes on its separate taxable income and other tax attributes. Deferred income taxes
are computed based on recognition of future tax expense or benefits, measured by enacted tax rates, that
are attributable to taxable or deductible temporary differences between financial statement and income
tax reporting bases of assets and liabilities.
Revenue Recognition – Revenues are recognized when coal is shipped from the mine. Revenues not
arising from coal sales, which primarily consist of transloading fees, are included in operating revenues
and are recognized as services are performed.
Net Income Per Unit – Basic net income per limited partner unit is determined by dividing net income,
after deducting the General Partners’ 2% interest, by the weighted average number of outstanding
Common Units and Subordinated Units (a total of 15,405,311 units as of December 31, 2000 and 1999).
Diluted net income per unit is based on the combined weighted average number of Common Units,
Subordinated Units and common unit equivalents outstanding which primarily include restricted units
granted under the Long-Term Incentive Plan (Note 11).
Segment Reporting – The Partnership has no reportable segments due to its operations consisting solely
of producing and marketing coal. The Partnership has disclosed major customer sales information
(Note 16) and geographic areas of operation (Note 17).
New Accounting Standards – Effective January 1, 2001, the Partnership adopted Statement of Financial
Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities,” which
establishes accounting and reporting standards for derivative instruments and for hedging activities. It
requires that all derivatives be recognized as either assets or liabilities in the statement of financial
position and be measured at fair value. The Partnership currently has no identified derivative
instruments or hedging activities. Accordingly, this standard had no material effect on the Partnership’s
consolidated financial statements upon adoption.
During the fourth quarter 2000, the Partnership adopted Financial Accounting Standards Board
Emerging Issues Task Force Issue No. 00-10 “Accounting for Shipping and Handling Fees and Costs.”
Accordingly, the Partnership reflects the cost of transporting coal to customers through third party
carriers as transportation expenses and the corresponding reimbursement of these costs through
customer billings as transportation revenues in the consolidated and combined statements of income.
These amounts were previously offset. There was no cumulative effect on net income and the prior
periods’ consolidated and combined statements of income have been reclassified to comply with this
presentation.
Reclassifications – Certain reclassifications have been made to the 1999 and 1998 combined and
consolidated financial statements to conform to the classifications used in 2000.
35
3. BUSINESS ACQUISITION
Effective January 23, 1998, the Predecessor acquired substantially all of the assets and assumed certain
liabilities, excluding working capital, of an unrelated coal company’s west Kentucky coal operations,
now Hopkins County Coal, LLC, for cash of approximately $7,310,000 and direct acquisition costs of
$821,000. The acquisition was accounted for using the purchase method of accounting. Accordingly,
the purchase price was allocated to the assets acquired and liabilities assumed based on their estimated
fair values of $25,320,000 and $17,189,000, respectively. The results of operations are included in the
Partnership’s consolidated and combined financial statements from the acquisition date and are not
considered significant.
4. UNUSUAL ITEMS
The Unusual items for the years ended December 31, 2000 and 1998 are as follows (in thousands):
Gain on settlement of transloading facility dispute
Litigation matters
Temporary mine closings
Year Ended
December 31,
2000
1998
$
(12,141)
2,675
-
$
-
-
5,211
$
(9,466)
$
5,211
The Partnership was involved in litigation with Seminole Electric Cooperative, Inc. (“Seminole”) with
respect to Seminole’s termination of a long-term contract for the transloading of coal from rail to barge
through the Partnership’s terminal in Indiana. The final resolution between the parties, reached in
conjunction with an arbitrator’s decision rendered during the third quarter of 2000, included both cash
payments and amendments to an existing coal supply contract. The Partnership recorded income of
$12,141,000, which is net of litigation expenses and impairment charges relating to certain transloading
facility assets.
The Partnership recorded an expense of $2,675,000 related to litigation matters settled and contingencies
associated with other litigation matters.
In response to market conditions, one of the Predecessor’s operating mines ceased operations and
terminated all of its workforce in September 1998. Management planned to maintain the mine in an
indefinite idle status pending improvement in market conditions. Shortly after the mine closure,
management executed a long-term coal supply contract for the mine and the mine resumed production in
late 1998. During the idle status period, the mine incurred a net loss of approximately $5,211,000
consisting of estimated amounts for increased workers’ compensation claims of $1,200,000 and
severance payments consistent with the federal Worker Adjustment and Retraining Notification, or
“WARN” Act, of $1,200,000 as well as the costs associated with maintaining the idled mine of
$2,811,000.
36
5.
INVENTORIES
Inventories consist of the following at December 31, (in thousands):
Coal
Supplies
2000
1999
$
5,140
5,702
$
15,180
5,950
$
10,842
$
21,130
6. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment consists of the following at December 31, (in thousands):
Mining equipment and processing facilities
Land and mineral rights
Buildings, office equipment and improvements
Construction in progress
Less accumulated depreciation, depletion and amortization
2000
1999
$
267,287
17,686
24,224
11,248
320,445
(135,782)
$
236,252
17,282
17,780
6,907
278,221
(102,709)
$
184,663
$
175,512
7. LONG-TERM DEBT
Long-term debt consists of the following at December 31, (in thousands):
Senior notes
Term loan
Less current maturities
2000
1999
$
180,000
50,000
230,000
(3,750)
$
180,000
50,000
230,000
-
$
226,250
$
230,000
The Special GP issued and the Intermediate Partnership assumed obligations with respect to a
$180 million principal amount of senior notes pursuant to a Note Purchase Agreement with a group of
institutional investors in a private placement offering. The senior notes are payable in ten annual
installments of $18 million beginning in August 2005 and bear interest at 8.31%, payable semiannually.
The Special GP also entered into and the Intermediate Partnership assumed obligations, under a
$100 million credit facility consisting of three tranches, including a $50 million term loan facility, a
$25 million working capital facility and a $25 million revolving credit facility. In connection with the
closing of the IPO, the Special GP borrowed $50 million under the term loan facility and the Special GP
and Intermediate Partnership purchased $50 million of U.S. Treasury Notes, which secure the term loan.
The U.S. Treasury Notes may be liquidated for the sole purpose of funding capital expenditures.
Through December 31, 2000, the Partnership had liquidated approximately $15.5 million of U.S.
Treasury Notes to fund various qualifying capital expenditures.
37
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 ½ of 1%, plus, in either option, an applicable margin. The weighted average
interest rates on the term loan facility at December 31, 2000 and 1999 were 7.77% and 7.07%,
respectively. In accordance with the pricing grid, a commitment fee ranging from 0.375% to 0.500%
per annum is paid quarterly on the unused portion of the working capital and revolving credit facilities.
There were no amounts outstanding under the Partnership’s working capital facility or revolving credit
facility as of December 31, 2000 and 1999. The credit facility expires in August 2004.
The senior notes and credit facility are guaranteed by Alliance Coal, LLC and all of its subsidiaries. In
addition, the credit facility is further secured by a pledge of treasury securities, which upon written
notice, are released for purposes of financing qualifying capital expenditures of the Intermediate
Partnership or its subsidiaries. The senior notes and credit facility contain various restrictive and
affirmative covenants, including the amount of distributions by the Intermediate Partnership and the
incurrence of other debt. The Partnership was in compliance with the covenants of both the credit
facility and senior notes at December 31, 2000.
The Partnership incurred debt issuance costs aggregating approximately $3,517,000, which have been
deferred and are being amortized as a component of interest expense over the term of the notes.
Aggregate maturities of long-term debt are as follows (in thousands):
Year Ending
December 31,
2001
2002
2003
2004
2005
Thereafter
$
3,750
15,000
16,250
15,000
18,000
162,000
$
230,000
8. DISTRIBUTIONS OF AVAILABLE CASH
The Partnership will distribute 100% of its available cash within 45 days after the end of each quarter to
unitholders of record and to the General Partners. Available cash is generally defined as all cash and
cash equivalents of the Partnership on hand at the end of each quarter less reserves established by the
Managing GP in its reasonable discretion for future cash requirements. These reserves are retained to
provide for the conduct of the Partnership’s business, the payment of debt principal and interest and to
provide funds for future distributions.
Distributions of available cash to the holder of Subordinated Units are subject to the prior rights of
holders of Common Units to receive the minimum quarterly distribution (“MQD”) for each quarter
during the subordination period and to receive any arrearages in the distribution of the MQD on the
Common Units for the prior quarters during the subordination period. The MQD is $0.50 per unit
($2.00 per unit on an annual basis). Upon expiration of the subordination period, which will generally
not occur before September 30, 2004, all Subordinated Units will be converted on a one-for-one basis
into Common Units and will then participate, on a pro rata basis with all other Common Units in future
38
distributions of available cash. However, under certain circumstances, up to 50% of the Subordinated
Units may convert into Common Units on or after September 30, 2003. Common Units will not accrue
arrearages with respect to distributions for any quarter after the subordination period and Subordinated
Units will not accrue any arrearages with respect to distributions for any quarter.
If quarterly distributions of available cash exceed the MQD or the target distributions levels, the General
Partners will receive distributions based on specified increasing percentages of the available cash that
exceeds the MQD or target distribution levels. The target distribution levels are based on the amounts of
available cash from the Partnership’s operating surplus distributed for a given quarter that exceed
distributions for the MQD and common unit arrearages, if any.
For the 42-day period from the Partnership’s commencement of operations (on August 20, 1999)
through September 30, 1999, the Partnership paid a pro-rata MQD distribution of $0.23 per unit on its
outstanding Common and Subordinated Units. For each of the quarters ended December 31, 1999
through September 30, 2000, quarterly distributions of $0.50 per unit were paid to the common and
subordinated unitholders. On January 24, 2001, the Partnership declared a MQD, for the period from
October 1, 2000 to December 31, 2000, of $0.50 per unit, totaling approximately $7,703,000 on its
outstanding Common and Subordinated Units, payable on February 14, 2001 to all unitholders of record
on January 31, 2001.
9.
INCOME TAXES
The Predecessor recognized a deferred tax asset for the future tax benefits attributable to deductible
temporary differences and other credit carryforwards, including alternative minimum tax credit
carryforwards. Realization of these future tax benefits was dependent on the Predecessor’s ability to
generate future taxable income, which was not assured. Management of the Predecessor believed that
future taxable income would be sufficient to recognize only a portion of the tax benefits and had
established a valuation allowance.
Concurrent with the closing of the IPO on August 20, 1999, and in connection with the Contribution
Agreement, ARH retained the current and deferred income taxes of the Predecessor.
Income before income taxes is derived from domestic operations. Significant components of income
taxes are as follows (in thousands):
Current:
Federal
State
Deferred:
Federal
State
For the
period from
January 1, 1999
to
August 19, 1999
Year Ended
December 31,
1998
$
3,376
483
3,859
595
44
639
$
4,815
801
5,616
(1,531)
(219)
(1,750)
Income tax expense
$
4,498
$
3,866
39
A reconciliation of the statutory U.S. federal income tax rate and the Predecessor’s effective income tax
rate is as follows:
Statutory rate
Increase (decrease) resulting from:
Excess of tax over book depletion
Alternative minimum tax credit
carryforwards
State income taxes, net of federal
benefit
Valuation allowance
Other
Effective income tax rate
For the
period from
January 1, 1999
to
August 19, 1999
Year Ended
December 31,
1998
35 %
(21)
3
3
10
1
35 %
(29)
6
4
14
1
31 %
31 %
10. NET INCOME PER LIMITED PARTNER UNIT
A reconciliation of net income and weighted average units used in computing basic and diluted earnings
per unit is as follows (in thousands, except per unit data):
Net income per limited partner unit
Weighted average limited partner units - basic
Basic net income per limited partner unit
Weighted average limited partner units - basic
Units contingently issuable:
Restricted units for Long-Term Incentive Plan
Directors’ compensation units deferred
Year
Ended
December 31,
2000
From
Commencement
of Operations
(on August 20, 1999)
to
December 31, 1999
$
15,269
15,405
$
0.99
15,405
142
4
$
6,147
15,405
$
0.40
15,405
-
-
Weighted average limited partner units,
assuming dilutive effect of restricted units
15,551
15,405
Diluted net income per limited partner unit
$
0.98
$
0.40
40
11. EMPLOYEE BENEFIT PLANS
Long-Term Incentive Plan – Effective January 1, 2000, the Managing GP adopted the Long-Term
Incentive Plan (the “LTIP”) for certain employees and directors of the Managing GP and its affiliates
who perform services for the Partnership. Annual grant levels and vesting provisions for designated
participants are recommended by the President and Chief Executive Officer of the Managing GP, subject
to the review and approval of the Compensation Committee. Grants are made either of restricted units,
which are “phantom” units that entitle the grantee to receive a Common Unit or an equivalent amount of
cash upon the vesting of a phantom unit, or options to purchase Common Units. Common Units to be
delivered upon the vesting of restricted units will be acquired by the Managing GP in the open market at
a price equal to the then prevailing price, or directly from ARH or any other third party. The Partnership
agreement provides that the Managing GP be reimbursed for all costs incurred in acquiring these
Common Units or in paying cash in lieu of Common Units upon vesting of the restricted units. The
aggregate number of units reserved for issuance under the LTIP is 600,000. Effective January 1, 2000,
the Compensation Committee approved initial grants of 142,100 restricted units, which vest at the end of
the subordination period, which will generally not end before September 30, 2004. During 2000, the
Managing GP billed the Partnership approximately $538,000 attributable to the LTIP. The Partnership
has recorded this amount as compensation expense. Effective January 1, 2001, the Compensation
Committee approved additional grants of 131,490 restricted units, which also vest at the end of the
subordination period.
Defined Contribution Plans – The Partnership’s employees currently participate in a defined
contribution profit sharing and savings plan sponsored by the Partnership, which is the same plan
sponsored by the Predecessor. This plan covers substantially all full-time employees. Plan participants
may elect to make voluntary contributions to this plan up to a specified amount of their compensation.
The Partnership makes contributions based on matching 75% of employee contributions up to 3% of
their annual compensation as well as an additional nonmatching contribution of ¾ of 1% of their
compensation. Additionally, the Partnership contributes a defined percentage of eligible earnings for
certain employees not covered by the defined benefit plan described below. The Partnership’s expense
for its plan was approximately $1,590,000 for the year ended December 31, 2000 and $715,000 for the
period from August 20, 1999 to December 31, 1999. The Predecessor’s expense for the plan was
$1,226,000 for the period from January 1, 1999 to August 19, 1999, and $1,944,000 for the year ended
December 31, 1998.
Defined Benefit Plans – Certain employees at the mining operations participate in a defined benefit plan
sponsored by the Partnership, which is the same plan sponsored by the Predecessor. The benefit formula
is a fixed dollar unit based on years of service.
41
The following sets forth changes in benefit obligations and plan assets for the years ended December 31,
2000 and 1999 and the funded status of the plans reconciled with amounts reported in the Partnership’s
consolidated and the Predecessor’s combined financial statements at December 31, 2000 and 1999,
respectively. The Partnership and Predecessor periods for 1999 have been combined. Since the
Partnership maintained the historical basis of the Predecessor’s net assets, management believes that the
combined Partnership and Predecessor amounts for 1999 are comparable with 2000 (dollars in
thousands):
2000
1999
Change in benefit obligations:
Benefit obligations at beginning of year
Service cost
Interest cost
Actuarial (gain) loss
Benefits paid
Benefit obligation at end of year
Change in plan assets:
Fair value of plan assets at beginning of year
Employer contribution
Actual return on plan assets
Benefits paid
Fair value of plan assets at end of year
Funded status
Unrecognized prior service cost
Unrecognized actuarial (gain) loss
$
7,774
1,971
596
(136)
(70)
10,135
8,265
1,100
205
(70)
9,500
(635)
284
(828)
$
6,742
2,107
452
(1,435)
(92)
7,774
2,911
4,736
710
(92)
8,265
491
332
(1,273)
Net amount recognized
$
(1,179)
$
(450)
Weighted-average assumptions as of December 31:
Discount rate
Expected return on plan assets
7.50 %
9.00 %
7.75 %
9.00 %
Components of net periodic benefit cost:
Service cost
Interest cost
Expected return on plan assets
Prior service cost
Net gain
Net periodic benefit cost
$
$
1,971
596
(737)
48
(49)
1,829
$
2,107
452
(413)
48
-
2,194
$
Effect on minimum pension liability
$
-
$
(459)
12. RECLAMATION AND MINE CLOSING COSTS
The majority of the Partnership’s operations are governed by various state statutes and the federal
Surface Mining Control and Reclamation Act of 1977, which establish reclamation and mine closing
standards. These regulations, among other requirements, require restoration of property in accordance
with specified standards and an approved reclamation plan. The Partnership has estimated the costs and
42
timing of future reclamation and mine closing costs and recorded those estimates on a present value
basis using a 6% discount rate.
Discounting resulted in reducing the accrual for reclamation and mine closing costs by $10,420,000 and
$5,489,000 at December 31, 2000 and 1999, respectively. Estimated payments of reclamation and mine
closing costs as of December 31, 2000 are as follows (in thousands):
2001
2002
2003
2004
2005
Thereafter
Aggregate undiscounted reclamation and mine closing
Effect of discounting
Total reclamation and mine closing costs
Less current portion
Reclamation and mine closing costs
$
1,078
1,191
1,594
2,147
2,511
17,917
26,438
10,420
16,018
1,078
$
14,940
The following table presents the activity affecting the reclamation and mine closing liability (in
thousands):
Partnership
Predecessor
Year
Ended
December 31,
2000
$
14,796
1,074
(764)
From
Commencement
of Operations
(on August 20, 1999)
to
December 31, 1999
For the
period from
January 1, 1999
to
August 19, 1999
Year
Ended
December 31,
1998
$
13,856
348
(394)
$
13,800
457
(401)
$
5,439
705
(1,544)
912
986
-
9,200
Beginning balance
Accrual
Payments
Allocation of liability associated
with acquisition and mine
development
Ending balance
$
16,018
$
14,796
$
13,856
$
13,800
13. PNEUMOCONIOSIS (“BLACK LUNG”) BENEFITS
Certain mine operating entities of the Partnership are liable under state statutes and the federal Coal
Mine Health and Safety Act of 1969, as amended, to pay black lung benefits to eligible employees and
former employees and their dependents. These subsidiaries provide self-insurance accruals, determined
by independent actuaries, at the present value of the actuarially computed present and future liabilities
for such benefits. The actuarial studies utilize a 6% discount rate and various assumptions as to the
frequency of future claims, inflation, employee turnover and life expectancies.
The cost or reduction of cost due to change in the estimate of black lung benefits charged (credited) to
operations for the year ended December 31, 2000, the period from the Partnership’s commencement of
operations on August 20, 1999 to December 31, 1999 and for the Predecessor period from January 1,
43
1999 to August 19, 1999, and the year ended December 31, 1998 was $123,000, $(1,028,000), $726,000,
and $1,139,000, respectively.
The U.S. Department of Labor has issued revised regulations that could alter the claims process for the
federal black lung benefit recipients. The revised regulations are expected to result in an increase in the
incidence and recovery of black lung claims. Both the coal and insurance industries are currently
challenging through litigation certain provisions of the revised regulations. The impact of the revised
regulations on the Partnership’s liability for future black lung claims cannot be determined at this time.
14. RELATED PARTY TRANSACTIONS
The Partnership Agreement provides that the Managing GP and its affiliates be reimbursed for all direct
and indirect expenses it incurs or payments it makes on behalf of the Partnership, including
management’s salaries and related benefits, accounting, budget and planning, treasury, public relations,
land administration, environmental and permitting management, payroll and benefits management,
disability and workers’ compensation management, legal and information technology services. The
Managing GP may determine in its sole discretion the expenses that are allocable to the Partnership.
Total costs reimbursed to the Managing GP and its affiliates by the Partnership were approximately
$3,899,000 and $1,283,000 for the year ended December 31, 2000 and the period from the Partnership’s
commencement of operations on August 20, 1999 to December 31, 1999, respectively.
ARH allocated certain direct and indirect general and administrative expenses to the Predecessor. These
allocations were primarily based on the relative size of the direct mining operating costs incurred by
each of the mine locations of the Predecessor. The allocations of general and administrative expenses to
the Predecessor were approximately $2,982,000 and $2,595,000 for the period from January 1, 1999 to
August 19, 1999 and for the year ended December 31, 1998, respectively. Management is of the opinion
that the allocations used are reasonable and appropriate.
During November 1999, the Managing GP was authorized by its Board of Directors to purchase up to
1.0 million Common Units of the Partnership. As of December 31, 2000 and 1999 the Managing GP
had purchased 164,000 Common Units in the open market at prevailing market prices.
In September 2000, the Special GP acquired coal reserves and the right to acquire additional coal
reserves that are (a) contiguous to the Webster County Coal, LLC (“WCC”) mining complex
(“Providence No. 3 Reserves”) and (b) contiguous to the Hopkins County Coal, LLC (“HCC”) mining
complex (“Elk Creek Reserves”). Such coal reserves and the rights to acquire additional coal reserves
were transferred to SGP Land, LLC (“SGP Land”), a newly formed wholly-owned subsidiary of the
Special GP.
Concurrent with such coal reserve acquisitions, the Special GP, through affiliates, was negotiating for
the purchase of (a) the capital stock of Roberts Bros. Coal Co., Inc., Warrior Coal Mining Company, and
Warrior Coal Corporation, and (b) the related coal reserves (“Warrior Reserves”) owned by Cardinal
Trust, LLC (collectively the “Warrior Group”). The Warrior Group’s operating assets are located
adjacent to the Providence No. 3 Reserves and were purchased by a newly formed affiliate of the Special
GP, Warrior Coal, LLC (“Warrior Coal”). SGP Land acquired the Warrior Reserves, which are located
between the Providence No. 3 Reserves and HCC. The acquisition of the Warrior Group closed in
January 2001.
SGP Land entered into a mineral lease and sublease with WCC for a portion of each of the Providence
No. 3 Reserves and the Warrior Reserves, and granted an option to HCC to lease and/or sublease the Elk
Creek Reserves. Under the terms of the WCC lease and sublease, WCC has an annual minimum royalty
obligation of $2.7 million, payable in advance, from 2000 to 2013 or until $37.8 million of cumulative
annual minimum and/or earned royalty payments have been paid. WCC paid the first annual minimum
44
royalty of $2.7 million in 2000. Under the terms of the HCC option to lease and sublease, HCC paid an
option fee of $645,000 in 2000. The anticipated annual minimum royalty obligation is
$684,000 payable in advance, from 2001 to 2009.
The Partnership and ARH Warrior Holdings, Inc. (“ARH Warrior Holdings”), the parent company of
Warrior Coal, have entered into an Amended and Restated Put and Call Option Agreement (“Put/Call
Agreement”) with the Partnership. Under the terms of the Put/Call Agreement, ARH Warrior Holdings
can require the Partnership to purchase Warrior Coal from ARH Warrior Holdings during the period
from January 2, 2003 to January 11, 2003, with a put option price of the sum of $10 million and interest
on the $10 million at 12 percent, compounded annually. The Partnership can also require ARH Warrior
Holdings to sell Warrior Coal to the Partnership during the period from April 12, 2003 to December 31,
2006, with a call option price of the sum of (a) $10 million, (b) interest on the $10 million at 12 percent,
compounded annually and (c) 25 percent of the interest determined in (b).
Separately, on December 29, 2000, the Partnership entered into a noncancelable operating lease
arrangement with the Special GP for a “build-to-suit” coal preparation plant and ancillary facilities at the
Gibson County Coal, LLC mining complex that was constructed and is currently owned by the Special
GP. This lease arrangement qualified for sale-leaseback accounting treatment, and consequently, the
Partnership has removed the corresponding asset and liability associated with the coal preparation plant
from its consolidated balance sheet. Based on the terms of the lease, the Partnership will make monthly
payments of approximately $216,000 for 121 months. Lease expense incurred for the year ended
December 31, 2000 was approximately $14,000.
15. COMMITMENTS AND CONTINGENCIES
Commitments – The Partnership leases buildings and equipment under operating lease agreements
which provide for the payment of both minimum and contingent rentals. The Partnership also has a
noncancelable lease with the Special GP (Note 14). Future minimum lease payments under operating
leases are as follows (in thousands):
Year ending December 31,
2001
2002
2003
2004
2005
Thereafter
Affiliate
Others
Total
$
2,595
2,595
2,595
2,595
2,595
13,190
$
452
408
274
284
284
780
$
3,047
3,003
2,869
2,879
2,879
13,970
$
26,165
$
2,482
$
28,647
Lease expense under all operating leases was $1,409,000, $801,000, $496,000, and $1,169,000 for the
year ended December 31, 2000, the period from the Partnership’s commencement of operations on
August 20, 1999 to December 31, 1999 and the Predecessor period from January 1, 1999 to August 19,
1999, and the year ended December 31, 1998, respectively.
Contractual Commitments – In connection with the expansion of an existing mine into adjacent coal
reserves, the Partnership has entered into contractual commitments for mine development of
approximately $22.5 million at December 31, 2000.
General Litigation – The Partnership is involved in various lawsuits, claims and regulatory proceedings,
including those conducted by the Mine Safety and Health Administration, incidental to its business. The
Partnership provides for costs related to litigation and regulatory proceedings, including civil fines
45
issued as part of the outcome of such proceedings, when a loss is probable and the amount is reasonably
determinable. The Partnership also recorded an expense of $2,675,000 related to litigation matters
settled and contingencies associated with other litigation matters, which is reflected in “Unusual items”
in the accompanying consolidated and combined statements of income. In the opinion of management,
the outcome of such matters to the extent not previously provided for or covered under insurance, will
not have a material adverse effect on the Partnership’s business, financial position or results of
operations, although management cannot give any assurance to that effect.
16. CONCENTRATION OF CREDIT RISK AND MAJOR CUSTOMERS
The Partnership has significant long-term coal supply agreements, some of which contain price
adjustment provisions designed to reflect changes in market conditions, labor and other production costs
and, when the coal is sold other than FOB the mine, changes in railroad and/or barge freight rates. Total
revenues to major customers, including transportation revenues (Note 2), which exceed ten percent of
total revenues are as follows (in thousands):
Partnership
Predecessor
Year
Ended
December 31,
2000
$
67,234
61,007
58,498
38,713
From
Commencement
of Operations
(on August 20, 1999)
to
December 31, 1999
$
23,104
26,993
16,090
11,926
For the
period from
January 1, 1999
to
August 19, 1999
$
38,875
40,752
31,328
19,582
Year
Ended
December 31,
1998
$
62,642
57,233
74,076
-
Customer A
Customer B
Customer C
Customer D
Trade accounts receivable from these customers totaled approximately $18.1 million at December 31,
2000. The Partnership’s bad debt experience has historically been insignificant. Based on current
evaluations, Partnership management believes that no allowance is required to absorb potential
uncollectible balances. However, changes in the financial conditions of its customers could result in a
material change to this estimate in future periods. The coal supply agreements with customers A, B, C
and D expire in 2006, 2001, 2010 and 2006, respectively.
46
17. GEOGRAPHIC INFORMATION
Included in the consolidated and combined financial statements are the following revenues and long-
lived assets relating to geographic locations (in thousands):
Partnership
Predecessor
Year
Ended
December 31,
2000
From
Commencement
of Operations
(on August 20, 1999)
to
December 31, 1999
For the
period from
January 1, 1999
to
August 19, 1999
Year
Ended
December 31,
1998
Revenues:
United States
Other foreign countries
Long-lived assets:
United States
Other foreign countries
$
363,469
-
363,469
$
$
210,996
-
210,996
$
$
$
134,125
-
134,125
$
$
203,697
-
203,697
$
221,339
10,494
231,833
$
$
200,057
-
200,057
$
$
348,055
55,246
403,301
$
$
204,078
-
204,078
$
18. SUPPLEMENTAL CASH FLOW INFORMATION
The Partnership’s and Predecessor’s supplemental disclosure of cash flow information and other
non-cash investing and financing activities were as follows (in thousands):
Partnership
Predecessor
Year
Ended
December 31,
2000
From
Commencement
of Operations
(on August 20, 1999)
to
December 31, 1999
For the
period from
January 1, 1999
to
August 19, 1999
Year
Ended
December 31,
1998
$
19,043
$
1,173
$
-
$
-
-
-
-
-
3,504
3,135
230,000
15,486
-
-
-
-
-
-
Cash paid for:
Interest
Income taxes paid through
Parent (Note 9)
Non-cash investing and financing
activities:
Debt transferred from Special GP
Marketable securities transferred
from Special GP
19. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
On August 20, 1999, the Partnership completed its IPO in which the Partnership became the successor to
the business of the Predecessor. Accordingly, no recognition has been given to income taxes in the
financial statements of the Partnership as income taxes will be borne by the partners and not the
Partnership. Additionally, interest expense associated with the debt incurred concurrent with the closing
of the IPO is applicable only to the Partnership period. Accordingly, the quarterly operating results prior
to August 20, 1999 are not necessarily comparable to subsequent periods.
47
A summary of the quarterly operating results for the Partnership and Predecessor is as follows (in
thousands, except unit and per unit data):
Revenues
Operating income
Net income (loss)
Basic net income (loss) per limited Partner unit
Diluted net income (loss) per limited
Partner unit
Weighted average number of units
outstanding - basic
Weighted average number of units
outstanding - diluted
Partnership
Quarter Ended
March 31,
2000
June 30,
2000
September 30,
December 31,
2000 (1)
2000
$
89,420
6,191
2,366
$
86,652
5,912
2,098
$
96,459
15,669
11,560
$
90,938
3,096
(443)
$
0.15
$
0.13
$
0.74
$
(0.03)
$
0.15
$
0.13
$
0.73
$
(0.03)
15,405,311
15,405,311
15,405,311
15,405,311
15,550,489
15,550,845
15,552,017
15,553,372
Predecessor
Partnership
From
Commencement
Quarter Ended
to
(on August 20, 1999)
July 1, 1999
of Operations
March 31,
June 30,
August 19,
to
Quarter Ended
1999
1999
1999
September 30, 1999
December 31, 1999
Revenues
Operating income
Net income
$
87,876
4,273
2,969
$
93,395
6,995
4,934
$
50,562
3,004
2,302
$
45,758
5,019
3,509
$
88,367
6,499
2,763
Basic and diluted net
income per unit
Weighted average number
of units outstanding - basic
and diluted
-
-
-
-
-
$
0.22
$
0.18
-
15,405,311
15,405,311
(1) The Partnership recorded income of $12.2 million, which is net of litigation expenses and costs relating to
the impairment of certain transloading facility assets. Additionally, the Partnership recorded an expense of
$2.7 million related to litigation matters settled and contingencies associated with other litigation matters.
The net effect of these unusual items for the quarter was $9.5 million (Note 4).
Operating income in the above table represents income from operations before interest expense.
* * * * * *
48
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE MANAGING GENERAL
PARTNER
As is commonly the case with publicly-traded limited partnerships, we are managed and operated by our
Managing GP. The following table shows information for the directors and executive officers of the
Managing GP. Executive officers and directors are elected for one-year terms.
Name
Joseph W. Craft III
Robert G. Sachse
Thomas L. Pearson
Michael L. Greenwood
Charles R. Wesley
Gary J. Rathburn
John J. MacWilliams
Preston R. Miller, Jr.
John P. Neafsey
John H. Robinson
Paul R. Tregurtha
Age
50
Position With our Managing General Partner
President, Chief Executive Officer and Director
52
47
45
46
50
45
52
61
50
65
Executive Vice President and Director
Senior Vice President - Law and Administration,
General Counsel and Secretary
Senior Vice President - Chief Financial Officer
and Treasurer
Senior Vice President - Operations
Senior Vice President - Marketing
Director
Director
Director
Director
Director
Joseph W. Craft III has worked for us since 1980. Prior to the formation of ARH, Mr. Craft was a Senior
Vice President of MAPCO Inc., serving as General Counsel and Chief Financial Officer, and since 1986 as
President of MAPCO Coal Inc. Mr. Craft has held his current positions since August 1996. Prior to working
with us, Mr. Craft was an attorney at Falcon Coal Corporation and Diamond Shamrock Coal Corporation.
Mr. Craft has held numerous industry leadership positions, including past Chairman of the National Coal
Council, a Board and Executive Committee member of the National Mining Association, and a Director of the
Center for Energy and Economic Development. Mr. Craft holds a Bachelor of Science degree in Accounting
and a Juris Doctor degree from the University of Kentucky. Mr. Craft also is a graduate of the Senior
Executive Program of the Alfred P. Sloan School of Management at Massachusetts Institute of Technology.
Robert G. Sachse joined us as Executive Vice President and Vice Chairman in August 2000. Prior to
working with us, Mr. Sachse was Executive Vice President and Chief Operating Officer of MAPCO Inc. from
1996 to 1998 until MAPCO Inc. merged with The Williams Companies, Inc. Mr. Sachse held various
positions with MAPCO Coal Inc. from 1982 to 1991, and was promoted to President of MAPCO Natural Gas
49
Liquids in 1992. Mr. Sachse holds a Bachelor of Science degree from Trinity University and a Juris Doctor
degree from the University of Tulsa.
Thomas L. Pearson has worked for us since 1989. Prior to the formation of ARH, Mr. Pearson was
Assistant General Counsel of MAPCO Inc. and served as General Counsel and Secretary of MAPCO Coal
Inc. from 1989-1996. Mr. Pearson has held his current positions since September 1996. Prior to working
with us, Mr. Pearson was General Counsel and Secretary of McLouth Steel Products Corporation, one of the
largest integrated steel producers in the United States; and Corporate Counsel of Midland-Ross Corporation, a
multi-national company with numerous international joint venture companies and projects. Previously, he was
an attorney with the Arter & Hadden law firm in Cleveland, Ohio. Mr. Pearson is or has been active in a
number of educational, charitable and business organizations, including the following: Vice Chairman, Legal
Affairs Committee, National Mining Association; Member, Dean's Committee, The University of Iowa
College of Law; and Contributions Committee, Greater Cleveland United Way. Mr. Pearson holds a Bachelor
of Arts degree in History and Communications from DePauw University and a Juris Doctor degree from The
University of Iowa.
Michael L. Greenwood has worked for us since 1986. Prior to the formation of ARH, Mr. Greenwood
served in various financial management capacities, including General Manager - Finance of MAPCO Coal
Inc., General Manager of Planning and Financial Analysis, and Manager - Mergers and Acquisitions of
MAPCO Inc. Mr. Greenwood has held his current positions since September 1996. Prior to working for us,
Mr. Greenwood held financial planning and business development management positions in the energy
industry with Davis Investments, The Williams Companies, Inc. and Penn Central Corporation. Mr.
Greenwood holds a Bachelor of Science degree in Business Administration from Oklahoma State University
and a Master of Business Administration degree from the University of Tulsa. Mr. Greenwood has also
completed executive programs at Northwestern University, Southern Methodist University and The Center for
Creative Leadership.
Charles R. Wesley has worked for us since 1974. Mr. Wesley joined Webster County Coal Corporation in
1974 as an engineering co-op student and worked through the ranks to become General Superintendent. In
1992 he became Vice President of Operations for Mettiki Coal Corporation. He has held his current position
since September 1996. Mr. Wesley has served the industry as past President of the West Kentucky Mining
Institute and National Mine Rescue Association Post 11. He also served on the board of the Kentucky Mining
Institute. Mr. Wesley holds a Bachelor of Science degree in Mining Engineering from the University of
Kentucky.
Gary J. Rathburn has worked for us since 1980 when he joined MAPCO Coal Inc. as Manager of
Brokerage Coals. Since 1980, Mr. Rathburn has managed all phases of the marketing group involving
transportation and distribution, international sales and the brokering of coal. He has held his current position
since September 1996. Prior to working for us, Mr. Rathburn was employed by Eastern Associated Coal
Corporation in its International Sales and Brokerage groups. Mr. Rathburn has been active in industry groups
such as the Maryland Coal Association, The North Carolina Coal Institute and the National Mining
Association. Mr. Rathburn was a Director of The National Coal Association and Chairman of the Coal
Exporters Association for several years. Mr. Rathburn holds a Bachelor of Arts degree in Political Science
from the University of Pittsburgh and has participated in industry-related programs at the World Trade
Institute, Princeton University and the Colorado School of Mines.
John J. MacWilliams has served as a Director since June 1996. Mr. MacWilliams has been a General
Partner of The Beacon Group, LP (The Beacon Group) since May 1993. Prior to the formation of The Beacon
Group, Mr. MacWilliams was an Executive Director of Goldman Sachs International in London, where he
was responsible for heading the firm's International Structured Financing Group. Prior to moving to London,
Mr. MacWilliams was a Vice President in the Investment Banking Division of Goldman, Sachs & Co. in New
York. Prior to joining Goldman Sachs, Mr. MacWilliams was an attorney at Davis Polk & Wardwell in New
York, where he worked on international bank financings, partnership financings, and mergers and
50
acquisitions. Mr. MacWilliams is also a director of Campagnie Generale Geophysique. Mr. MacWilliams
holds a Bachelor of Arts degree from Stanford University, Master of Science degree from Massachusetts
Institute of Technology, and a Juris Doctor degree from Harvard Law School.
Preston R. Miller, Jr. has served as a Director since June 1996. Mr. Miller has been a General Partner of
The Beacon Group since June 1993. Prior to the formation of The Beacon Group, Mr. Miller was employed
for fourteen years by Goldman, Sachs & Co. in New York City, where he was a Vice President in the
Structured Finance Group and had global responsibility for the coverage of the independent power industry,
asset-backed power generation, and oil and gas financings. Mr. Miller also has a background in credit
analysis, and was head of the revenue bond rating group at Standard & Poor's Corp. prior to joining Goldman
Sachs. Mr. Miller holds a Bachelor of Arts degree from Yale University and a Master of Public
Administration degree from Harvard University.
John P. Neafsey has served as Chairman since June 1996. Mr. Neafsey has served as President of JN
Associates, an investment consulting firm, since January 1994. Mr. Neafsey served as President and CEO of
Greenwich Capital Markets from 1990 to 1993 and Director since its founding in 1983. In addition, Mr.
Neafsey held numerous other positions during his twenty-three years at The Sun Company, including:
Executive Vice President responsible for Canadian operations, Sun Coal Company and Helios Capital
Corporation; Chief Financial Officer; and other executive management positions with numerous subsidiary
companies. Mr. Neafsey is or has been active in a number of educational, charitable and business
organizations, including the following: Director, The West Pharmaceutical Services Company, Longhorn
Partners Pipeline Inc. and the Provident Mutual Life Insurance Company; Trustee, Cornell University; and
Overseer of Cornell-Weill Medical Center. Mr. Neafsey holds Bachelor and Master of Science degrees in
Engineering and a Master of Business Administration degree from Cornell University.
John H. Robinson has served as a Director since December 1999. In April 2000, Mr. Robinson joined
Amey, plc, a British support services business, as Executive Director of its newly-formed Technology
Services Division. Mr. Robinson previously served as Vice Chairman of Black & Veatch, a global engineer-
constructor firm, from January 1997 through March 2000. He was also the Chairman of Black & Veatch UK
Ltd. and was responsible for guiding strategic development of the firm, having begun his career there in 1973.
He is a Director of Coeur Precious Metals, Protection One and Commerce Bancshares. Mr. Robinson holds
Bachelor and Master of Science degrees in Engineering from the University of Kansas and has completed the
Owner/President Management Program at the Harvard School of Business.
Paul R. Tregurtha has served as a Director since December 1999. Mr. Tregurtha serves as Chairman and
Chief Executive Officer of Mormac Marine Group, Inc. and Moran Transportation Company, and Chairman
of MAC Acquisitions, Inc. He is a director and principal officer of several companies involved in water
transportation and natural resources, including The Interlake Steamship Company and Lakes Shipping
Company. Mr. Tregurtha is also a director of FleetBoston Financial and FPL Group, Inc., the parent of
Florida Power & Light Company. Mr. Tregurtha holds a Bachelor of Science degree in Mechanical
Engineering from Cornell University, where he serves as Trustee Emeritus, and a Master of Business
Administration degree from the Harvard School of Business.
Section 16(a) Beneficial Ownership Reporting Compliance.
Section 16(a) of the Securities and Exchange Act of 1934, as amended, requires directors, executive
officers and persons who beneficially own more than ten percent of a registered class of the Partnership's
equity securities to file with the SEC initial reports of ownership and reports or changes in ownership of such
equity securities. Such persons are also required to furnish the Partnership with copies of all Section 16(a)
forms that they file. Based solely upon a review of the copies of the forms furnished to it, or written
representations from certain reporting persons, the Partnership believes that during 2000 none of its officers
and directors was delinquent with respect to any of the filing requirements under Rule 16(a) other than (a) Mr.
Craft did not file a Form 4 for the months of August and September 1999, regarding purchases made by a
51
private foundation for which he serves as a trustee and disclaims beneficial ownership, and (b) Mr. Neafsey
did not timely file a Form 4 for the month of August 2000, but has since filed this Form 4.
Reimbursement of Expenses of the Managing GP and its Affiliates
The Managing GP does not receive any management fee or other compensation in connection with its
management of us. However, our Managing GP and its affiliates, including ARH, perform services for us and
are reimbursed by us for all expenses incurred on our behalf, including the costs of employee, officer and
director compensation and benefits properly allocable to us, as well as all other expenses necessary or
appropriate to the conduct of our business, and properly allocable to us. Our Partnership Agreement provides
that the Managing GP will determine the expenses that are allocable to us in any reasonable manner
determined by the Managing GP in its sole discretion.
ITEM 11. EXECUTIVE COMPENSATION
EXECUTIVE COMPENSATION
The following table sets forth certain compensation information for all executive officers of our Managing
GP who received salary and bonus compensation in excess of $100,000 in 2000. The Partnership was formed
in May 1999 but did not commence business until August 1999. Therefore 1999 compensation information is
for the Partnership period from commencement of operations (on August 20, 1999) to December 31, 1999.
SUMMARY COMPENSATION TABLE
Name and Principal Position
Year
Salary
Bonus
(1)
Other Annual
Compensation
(2)
Annual Compensation
Long Term
Compensation
Restricted
Stock Awards
(3)
All Other
Compensation
(4)
2000
1999
$292,950 $94,200
70,040
106,313
$ -
700
$678,150
-
$63,695
21,495
2000
1999
177,000
64,234
45,000
28,306
1,550
-
122,067
-
43,856
12,385
Joseph W. Craft III,
President, Chief Executive Officer
and Director
Thomas L. Pearson,
Senior Vice President-Law and
Administration, General Counsel
and Secretary
Michael L. Greenwood,
Senior Vice President-Chief
Financial Officer and Treasurer
2000
1999
151,400
54,944
45,000
28,306
-
-
Charles R. Wesley,
Senior Vice President-Operations
2000
1999
187,000
67,863
47,600
35,565
Gary J. Rathburn,
Senior Vice President-Marketing
2000
1999
152,000
55,161
45,000
28,306
1,500
-
1,500
-
122,067
-
135,630
-
122,067
-
26,009
7,972
32,802
12,383
28,008
9,407
(1) Amount awarded under the Short-Term Incentive Plan. See “Short-Term Incentive Plan” below.
(2) Amount reimbursed for income tax preparation.
(3) Awards under the Long-Term Incentive Plan. The amount represents the value of restricted units at the date of
issuance. The total number of restricted units and their market value as of December 31, 2000, were: Mr. Craft,
50,000 units valued at $900,000; Mr. Pearson, 9,000 units valued at $162,000; Mr. Greenwood, 9,000 units valued
at $162,000; Mr. Wesley, 10,000 units valued at $180,000; Mr. Rathburn, 9,000 units valued at $162,000. Units
52
granted under the Long-Term Incentive Plan do not vest until the end of the subordination period, which will
generally not end before September 30, 2004. See “Long-Term Incentive Plan” below.
(4) Amount represents (a) the Managing General Partner’s matching contributions to its 401(k) Plan and (b) the
Managing General Partner’s contribution to a Supplemental Executive Retirement Plan.
COMPENSATION OF DIRECTORS
Under the Managing GP’s Directors Compensation Program (Directors Plan) each non-employee Director
is paid an annual retainer of $20,000. The annual retainer is payable in Common Units of the Partnership to
be paid on a quarterly basis in advance determined by dividing the pro rata annual retainer payable on such
date by the closing sales price per Common Unit averaged over the immediately preceding ten trading days.
Each non-employee director may elect to defer all or a portion of his or her compensation under the Deferred
Compensation Plan for Directors.
In addition each non-employee director participates in the Long-Term Incentive Plan. The directors
restricted units vest in accordance with the same procedure as is described below. Messrs. MacWilliams and
Miller have declined compensation under the Directors and Long-Term Incentive Plans.
Mr. Sachse has a consulting agreement with the Managing GP, for a term of three years, effective August
14, 2000. The consulting agreement provides that Mr. Sachse will serve as Executive Vice President of the
Managing GP and devote his services on a part-time basis. In addition to compensation received under the
Directors Plan and Long-Term Incentive Plan described above, Mr. Sachse is entitled to receive an annual fee
of $150,000 payable in arrears monthly. Mr. Sachse also is entitled to receive quarterly payments in arrears
of $7,500 less the market value of 250 Common Units of the Partnership calculated by the closing sales price
per Common Unit averaged over the immediately preceding ten trading days. A copy of the consulting
agreement with Mr. Sachse is filed as an exhibit hereto.
EMPLOYMENT AGREEMENTS
The executive officers of the Managing GP and some additional members of senior management will enter
into employment agreements among the executive officer or member of senior management, on the one hand,
and the Managing GP and ARH, on the other. We reimburse the Managing GP for the compensation and
benefits costs under these agreements. This summary of the terms of the employment agreements does not
purport to be complete, but outlines their material provisions. A form of the agreements with each of Messrs.
Craft, Pearson, Greenwood, Wesley and Rathburn are filed as exhibits.
Each of the employment agreements has an initial term that expires on December 31, 2001, but will
automatically be extended for successive one-year terms unless either party gives 12 months prior notice to
the other party. The employment agreements provide for a base salary, subject to review annually, of
$292,950, $177,000, $151,400, $187,000 and $152,000 for Messrs. Craft, Pearson, Greenwood, Wesley and
Rathburn, respectively. The employment agreements provide for continued salary payments, bonus and
benefits for a period of three years, in the case of Mr. Craft, and 18 months, in the case of Messrs. Pearson,
Greenwood, Wesley and Rathburn, following termination of employment, except in the case of a change of
control of the Managing GP.
In the case of a "change of control" as defined in the agreements, in lieu of the continuation of salary and
benefits, that executive will be entitled to a lump sum payment in an amount equal to three times base salary
plus bonus, in the case of Mr. Craft, and two times base salary plus bonus in the case of Messrs. Pearson,
Greenwood, Wesley and Rathburn. Unless the executive waives his or her right to the continuation of base
salary and bonus, the agreements provide for a noncompetition period of 18 months. The noncompetition
period does not apply after a change in control. Amounts paid by the Managing GP pursuant to the
employment agreements will be reimbursed by the Partnership.
53
The executives who are subject to employment agreements also participate in the Short- and Long-Term
Incentive Plans of the Managing GP described below along with other members of management. They also
are entitled to participate in the other employee benefit plans and programs that the Managing GP provides for
its employees.
LONG-TERM INCENTIVE PLAN
Effective January 1, 2000, the Managing GP adopted the Long-Term Incentive Plan (LTIP) for certain
employees and directors of the Managing GP and its affiliates who perform services for us. The summary of
the LTIP contained herein does not purport to be complete, but outlines its material provisions.
The LTIP is administered by the Compensation Committee of the Managing GP's Board of Directors.
Annual grant levels for designated participants are recommended by the President and CEO of the Managing
GP, subject to the review and approval of the Compensation Committee. We will reimburse the Managing GP
for all costs incurred pursuant to the programs described below. Grants are made either of restricted units,
which are "phantom" units that entitle the grantee to receive a Common Unit or an equivalent amount of cash
upon the vesting of a phantom unit, or options to purchase Common Units. Common Units to be delivered
upon the vesting of restricted units or to be issued upon exercise of a unit option will be acquired by the
Managing GP in the open market at a price equal to the then prevailing price, or directly from ARH or any
other third party, including units newly issued by us, or use units already owned by the Managing GP, or any
combination of the foregoing. The Managing GP is entitled to reimbursement by us for the cost incurred in
acquiring these Common Units or in paying cash in lieu of Common Units upon vesting of the restricted
units. If we issue new Common Units upon payment of the restricted units or unit options instead of
purchasing them, the total number of Common Units outstanding will increase. The aggregate number of
units reserved for issuance under the LTIP is 600,000. Effective January 1, 2000, the Compensation
Committee approved initial grants of 142,100 restricted units, which vest at the end of the subordination
period, which will generally not end before September 30, 2004. Effective as of January 1, 2001, the
Compensation Committee approved additional grants of 131,490 restricted units, which also vest at the end of
the subordination period.
Restricted Units. Restricted units will vest over a period of time as determined by the Compensation
Committee. However, if a grantee's employment is terminated for any reason prior to the vesting of any
restricted units, those restricted units will be automatically forfeited, unless the Compensation Committee, in
its sole discretion, provides otherwise. In addition, vested restricted units will not be payable before the end of
the subordination period, which will generally not end before September 30, 2004.
The issuance of the Common Units pursuant to the restricted unit plan is intended to serve as a means of
incentive compensation for performance and not primarily as an opportunity to participate in the equity
appreciation in respect of the Common Units. Therefore, no consideration will be payable by the plan
participants upon receipt of the Common Units, and we receive no remuneration for these units. Following the
subordination period, the Compensation Committee, in it discretion, may grant distribution equivalent rights
with respect to restricted units.
Unit Options. We have not made any grants of unit options. The Compensation Committee may, in the
future, determine to make unit option grants to employees and directors containing the specific terms that they
determine. When granted, unit options will have an exercise price set by the Compensation Committee which
may be above, below or equal to the fair market value of a Common Unit on the date of grant. Unit options, if
any, granted during the subordination period will become exercisable upon, and in the same proportions as,
the conversion of the Subordinated Units to Common Units, or at a later date as determined by the
Compensation Committee in its sole discretion.
54
The Managing GP's Board of Directors, in its discretion, may terminate the LTIP at any time with respect
to any Common Units for which a grant has not previously been made. The Managing GP's Board of
Directors will also have the right to alter or amend the LTIP or any part of it from time to time, subject to
unitholder approval as required by the exchange upon which the Common Units may be listed at that time;
provided, however, that no change in any outstanding grant may be made that would materially impair the
rights of the participant without the consent of the affected participant. In addition, the Managing GP may, in
its discretion, establish such additional compensation and incentive arrangements as it deems appropriate to
motivate and reward its employees. The Managing GP is reimbursed for all compensation expenses incurred
on our behalf.
SHORT-TERM INCENTIVE PLAN
Effective January 1, 1999, the Managing GP adopted a Short-Term Incentive Plan (STIP) for management
and other salaried employees. The STIP is designed to enhance the financial performance by rewarding
management and salaried employees of the Managing GP and Partnership with cash awards for the
Partnership achieving an annual financial performance objective. The annual performance objective for each
year is recommended by the President and CEO of the Managing GP and approved by the Compensation
Committee of its Board of Directors prior to January 1 of that year. The STIP is administered by the
Compensation Committee. Individual participants and payments each year are determined by and in the
discretion of the Compensation Committee, and the Managing GP is able to amend the plan at any time. The
Managing GP is entitled to reimbursement by us for the costs incurred under the STIP.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth certain information as of March 1, 2001, regarding the beneficial ownership
of Common and Subordinated Units held by (a) each person known by the Managing GP to be the beneficial
owner of 5% or more of the Common and Subordinated Units, (b) each director and executive officer of the
Managing GP and (c) all directors and executive officers of the Managing GP as a group. The Managing GP
is owned by funds affiliated with The Beacon Group and members of management. The Special GP is a
wholly-owned subsidiary of ARH. The address of ARH, the Managing GP and the Special GP, is 1717 South
Boulder Avenue, Tulsa, Oklahoma 74119.
Name of Beneficial Owner
Alliance Resource GP, LLC (2)
Alliance Resource Management GP, LLC (3)
Joseph W. Craft III (1) (7)
Robert G. Sachse (1)
Thomas L. Pearson (1)
Michael L. Greenwood (1)
Charles R. Wesley (1)
Gary J. Rathburn (1)
John J. MacWilliams (4)
Preston R. Miller, Jr. (4)
John P. Neafsey (1)
John H. Robinson (5)
Paul R. Tregurtha (6)
All directors and executive officers as
Common
Units
Beneficially
Owned (8)
1,232,780
164,000
73,500
646
9,971
29,950
20,000
8,000
1,396,780
1,396,780
12,257
2,257
2,257
Percentage of
Common
Units
Beneficially
Owned
13.72%
1.83%
*
*
*
*
*
*
15.55%
15.55%
*
*
*
Subordinated
Units
Beneficially
Owned
6,422,531
-
-
-
-
-
-
-
6,422,531
6,422,531
-
-
-
Percentage of
Subordinated
Units
Beneficially
Owned
100%
-
-
-
-
-
-
-
100%
100%
-
-
-
Percentage
of Total
Units
Beneficially
Owned
49.7%
1.1%
*
*
*
*
*
*
50.8%
50.8%
*
*
*
a group (11 persons)
1,555,618
17.32%
6,422,531
100%
51.8%
* Less than one percent.
(1) The address of Messrs. Craft, Sachse, Pearson, Greenwood, Wesley, Rathburn and Neafsey is 1717 South Boulder
Avenue, Tulsa, Oklahoma 74119.
55
(2) ARH may be deemed to beneficially own the Common Units and the Subordinated Units held by the Special GP,
as a result of ARH's ownership of all of the membership interests in the Special GP. MPC Partners, LP (MPC
Partners) may also be deemed to beneficially own the Common Units and the Subordinated Units held by the
Special GP as a result of MPC Partners' ownership of 86.2% of ARH's outstanding common stock.
(3) The Managing GP is an affiliate of the Special GP, and as a consequence, the Special GP may be deemed to
beneficially own the Common Units held by the Managing GP.
(4) Messrs. MacWilliams and Miller may also be deemed to share beneficial ownership of the Common Units and the
Subordinated Units held by the Special GP and the Managing GP by virtue of their status as partners of The
Beacon Group, an affiliate of MPC Partners. Messrs. MacWilliams and Miller disclaim beneficial ownership of the
Common and Subordinated Units held by the Special GP and the Managing GP. The address of Messrs.
MacWilliams and Miller is Beacon Group Energy Funds, an affiliate of JP Morgan Partners, 1221 Avenue of the
Americas, 4th floor, New York, New York 10020.
(5) The address of Mr. Robinson is 24 Hanover Square, London, England W1S1JD.
(6) The address of Mr. Tregurtha is 3 Landmark Square, Stamford, Connecticut 06901.
(7) Mr. Craft owns 60,000 Common Units and may also be deemed to share beneficial ownership of 13,500 Common
Units held by a private foundation for which he serves as a trustee. Mr. Craft disclaims beneficial ownership of the
Common Units held by the private foundation.
(8) The amounts set forth do not include any restricted units granted under the LTIP.
56
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The Special GP owns 1,232,780 Common Units and 6,422,531 Subordinated Units representing an
aggregate 48.7% limited partner interest in the Partnership. In addition, the General Partners own, on a
combined basis, an aggregate 2% general partner interest in the Partnership, the Intermediate Partnership and
the subsidiaries. The Managing GP's ability, as managing general partner, to manage and operate the
Partnership and its ownership of 164,000 Common Units together with the Special GP's ownership of
1,232,780 Common Units and 6,422,531 Subordinated Units, effectively gives the General Partners the ability
to veto some actions of the Partnership and to control the management of the Partnership.
UNIT PURCHASE PROGRAM BY THE MANAGING GP
The Managing GP authorized a Common Unit purchase program in November 1999 for the purchase of up
to the greater of one million Common Units or $15 million of Common Units. As of December 31, 2000, the
Managing GP has purchased 164,000 Common Units. The Common Units purchased by the Managing GP
retain their rights to receive quarterly distributions of Available Cash.
TRANSACTIONS BETWEEN THE PARTNERSHIP, SPECIAL GP AND ARH
In September 2000, the Special GP acquired coal reserves and the right to acquire additional coal reserves
(a) contiguous to our Dotiki mine (Providence No. 3 Reserves) and (b) contiguous to Hopkins County Coal
(Elk Creek Reserves). Such coal reserves and the rights to acquire additional coal reserves were transferred to
SGP Land, LLC (SGP Land), a newly formed wholly-owned subsidiary of the Special GP.
Concurrent with such coal reserve acquisitions, the Special GP, through affiliates, was negotiating for the
purchase of (a) the capital stock of Roberts Bros. Coal Co., Inc., Warrior Coal Mining Company, and Warrior
Coal Corporation, and (b) the related coal reserves (Warrior Reserves) owned by Cardinal Trust, LLC
(collectively, the Warrior Group). The Warrior Group’s operating assets are located adjacent to the
Providence No. 3 Reserves and were purchased by a newly formed affiliate of the Special GP, Warrior Coal,
LLC (Warrior Coal). SGP Land acquired the Warrior Reserves, which are immediately between the
Providence No. 3 Reserves and Hopkins County Coal. The acquisition of the Warrior Group closed in
January 2001.
SGP Land entered into a mineral lease and sublease with Webster County Coal for a portion of each of the
Providence No. 3 Reserves and the Warrior Reserves, and granted an option to Hopkins County Coal to lease
and/or sublease the Elk Creek Reserves. Under the terms of the Webster County Coal lease and sublease,
Webster County Coal has an annual minimum royalty obligation of $2.7 million, payable in advance, from
2000 to 2013, or until $37.8 million of cumulative annual minimum and/or earned royalty payments have
been paid. Webster County Coal paid the first annual minimum royalty of $2.7 million in 2000. Under the
terms of the Hopkins County Coal option to lease and sub-lease, Hopkins County Coal paid an option fee of
$645,000 in 2000. The anticipated annual minimum royalty obligation is $684,000 payable in advance, from
2001 to 2009.
Consistent with the terms of the Omnibus Agreement discussed below, the above transactions were
initially offered to the Partnership. However, the Board of Directors of the Managing GP, with the
concurrence of its Conflicts Committee, elected not to pursue these transactions. However, the Partnership
and ARH Warrior Holdings, Inc. (ARH Warrior Holdings), the parent company of Warrior Coal, entered into
an Amended and Restated Put and Call Option Agreement (Put/Call Agreement), filed as an exhibit hereto,
which provides as follows:
57
(a) ARH Warrior Holdings can require the Partnership to purchase Warrior Coal from ARH Warrior
Holdings during the period from January 2, 2003 to January 11, 2003, with a put option price of the
sum of (i) $10 million, and (ii) interest on the $10 million at 12 percent, compounded annually; and
(b) the Partnership can require ARH Warrior Holdings to sell Warrior Coal to the Partnership during
the period from April 12, 2003 to December 31, 2006, with a call option price of the sum of (i) $10
million, (ii) interest on the $10 million at 12 percent, compounded annually, and (iii) 25 percent of the
interest determined in (ii).
Separately, we entered into a noncancelable operating lease arrangement with the Special GP for a coal
preparation plant and ancillary facilities at Gibson County Coal. This transaction was reviewed and approved
by the Conflicts Committee. Under the terms of the lease, the Partnership began making monthly payments
commencing January 1, 2001, of approximately $216,000 for 121 months.
We may enter into similar arrangements in the future to support the acquisition of additional reserve
properties or to develop facilities at our existing mining complexes.
OTHER RELATED PARTY TRANSACTIONS
J.P. Morgan Chase & Co. (Chase) is paying agent, co-administrative agent and a lender under our Credit
Facility. In 2000, we made interest payments to Chase on outstanding borrowings and paid Chase customary
fees for their other services. We expect that these relationships will continue in 2001. The Beacon Group is
an affiliate of Chase. Messrs. MacWilliams and Miller are General Partners of the Beacon Group and
Directors of the Managing GP.
OMNIBUS AGREEMENT
Concurrent with the closing of the IPO, we entered into an Omnibus Agreement with ARH and the
General Partners, which governs potential competition among us and the other parties to this agreement. ARH
agreed, and caused its controlled affiliates to agree, for so long as management and funds managed by The
Beacon Group and its affiliates control the Managing GP, not to engage in the business of mining, marketing
or transporting coal in the U.S. unless it first offers the Partnership the opportunity to engage in a potential
activity or acquire a potential business, and the Board of Directors of the Managing GP, with the concurrence
of its Conflicts Committee, elects to cause us not to pursue such opportunity or acquisition. In addition, ARH
has the ability to purchase businesses, the majority value of which is not mining, marketing or transporting
coal, provided ARH offers the Partnership the opportunity to purchase the coal assets following their
acquisition. The restriction does not apply to the assets retained and business conducted by ARH at the
closing of the IPO. Except as provided above, ARH and its controlled affiliates are prohibited from engaging
in activities in which they compete directly with the Partnership. In addition, The Beacon Group, and the
funds it manages, are prohibited from owning or engaging in businesses which compete with the Partnership.
In addition to its non-competition provisions, this agreement contains provisions which indemnify the
Partnership against liabilities associated with certain assets and businesses of ARH which were disposed of or
liquidated prior to consummating the IPO.
58
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
PART IV
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
3.2
3.3
3.4
4.1
10.1
10.2
10.3
Amended and Restated Agreement of Limited Partnership of Alliance Resource
Partners, L.P. (Incorporated by reference to Exhibit 3.1 of the Registrant’s
Annual Report on Form 10-K for the year ended December 31, 1999).
Amended and Restated Agreement of Limited Partnership of Alliance Resource
Operating Partners, L.P. (Incorporated by reference to Exhibit 3.2 of the
Registrant’s Annual Report on Form 10-K for the year ended December 31,
1999).
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).
Certificate of Limited Partnership of Alliance Resource Operating Partners, L.P.
(Incorporated by reference to Exhibit 3.8 of the Registrant’s Statement on Form
S-1/A filed with the Commission on July 20, 1999).
Form of Common Unit Certificate (Included as Exhibit A to the Amended and
Restated Agreement of Limited Partnership of Alliance Resource Partners, L.P.)
Credit Agreement, dated as of August 16, 1999, among Alliance Resource GP,
LLC, The Chase Manhattan Bank (as paying agent), Deutsche Bank AG, New
York Branch (as documentation agent), Citicorp USA, Inc. and The Chase
Manhattan Bank (as co-administrative agents) and the lenders named therein.
(Incorporated by reference to Exhibit 10.1 of the Registrant’s Annual Report 10-
K for the year ended December 31, 1999).
Note Purchase Agreement, dated as of August 16, 1999, among Alliance
Resource GP, LLC and the purchasers named therein. (Incorporated by reference
to Exhibit 10.2 of the Registrant’s Annual Report on Form 10-K for the year
ended December 31, 1999).
Contribution and Assumption Agreement, dated August 16, 1999, among
Alliance Resource Holdings, Inc., Alliance Resource Management GP, LLC,
Alliance Resource GP, LLC, Alliance Resource Partners, L.P., Alliance Resource
Operating Partners, L.P. and the other parties named therein. (Incorporated by
59
10.4
10.5
10.6
10.7
10.8
10.9
10.10
10.11
reference to Exhibit 10.3 of the Registrant’s Annual Report on Form 10-K for the
year ended December 31, 1999).
Omnibus Agreement, dated August 16, 1999, among Alliance Resource
Holdings, Inc., Alliance Resource Management GP, LLC, Alliance Resource GP,
LLC and Alliance Resource Partners, L.P. (Incorporated by reference to Exhibit
10.4 of the Registrant’s Annual Report on Form 10-K for the year ended
December 31, 1999).
Alliance Resource Management GP, LLC 2000 Long-Term Incentive Plan (as
amended). (Incorporated by reference to Exhibit 10.11 of the Registrant’s
Annual Report on Form 10-K for the year ended December 31, 1999).
Incentive Plan.
Alliance Resource Management GP, LLC Short-Term
(Incorporated by reference to Exhibit 10.12 of the Registrant’s Annual Report on
Form 10-K for the year ended December 31, 1999).
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).
Amendment No. 1 to the Restated and Amended Coal Supply Agreement
effective April 1, 1996, between MAPCO Coal Inc., Webster County Coal
Corporation, White County Coal Corporation, and Seminole Electric
Cooperative, Inc. (Incorporated by reference to Exhibit 10.14 of the Registrant’s
Quarterly Report on Form 10-Q for the quarter ended June 30, 2000).
Interim Coal Supply Agreement effective May 1, 2000, between Alliance Coal,
LLC and Seminole Electric Cooperative, Inc. (Incorporated by reference to
Exhibit 10.15 of the Registrant’s Quarterly Report on Form 10-Q for the quarter
ended June 30, 2000).
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).
Assignment/Transfer Agreement between Andalex Resources, Inc., Hopkins
County Coal LLC, Webster County Coal Corporation and Tennessee Valley
Authority, dated January 23, 1998, with Exhibit A – Contract for Purchase and
Sale of Coal between Tennessee Valley Authority and Andalex Resources, Inc.,
dated January 31, 1995. (Incorporated by reference to Exhibit 10.11 of the
Registrant’s Registration Statement on Form S-1/A filed with the Commission on
July 20, 1999).
10.12
Contract for Purchase and Sale of Coal, dated July 7, 1998, between Tennessee
Valley Authority and Webster County Coal Corporation. (Incorporated by
reference to Exhibit 10.12 of the Registrant’s Registration Statement on Form S-
1/A filed with the Commission on July 20, 1999).
60
10.13
10.14
*10.15
*10.16
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).
Agreement for Supply of Coal to the Mt. Storm Power Station, dated January 15,
1996, between Virginia Electric and Power Company and Mettiki Coal
Corporation. (Incorporated by reference to Exhibit 10. (t) to MAPCO Inc.’s
Annual Report on Form 10-K, filed April 1, 1996, File No. 1-5254).
Coal Sales Agreement, dated October 3, 1998, between Pontiki Coal Corporation
and A.E.I. Coal Sales, Inc. (Portions of this agreement have been omitted based
on a request for confidential treatment. Those omitted portions have been filed
with the Securities and Exchange Commission).
Amendment No. 1 to Coal Sales Agreement dated February 28, 2001, between
Pontiki Coal, LLC and AEI Coal Sales Company, Inc. (Portions of this
agreement have been omitted based upon a request for confidential treatment.
Those omitted portions have been field with the Securities and Exchange
Commission).
*10.17
Amended and Restated Put and Call Option Agreement dated February 12, 2001
between ARH Warrior Holdings, Inc. and Alliance Resource Partners, L.P.
*10.18
Consulting Agreement for Mr. Sachse dated January 1, 2001.
10.19
Form of Employee Agreement for Messrs. Craft, Pearson, Greenwood, Wesley
and Rathburn. (Incorporated by reference to Exhibit 10.6 of the Registrant’s
Registration Statement on Form S-1/A filed with the Commission on August 9,
1999).
* 21.1
List of Subsidiaries
* Filed here within
(b)
Reports on Form 8-K:
None.
61
Signatures
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned thereunto duly authorized, in Tulsa, Oklahoma, on March
14, 2001.
ALLIANCE RESOURCE PARTNERS, L.P.
By: Alliance Resource Management GP, LLC
its managing general partner
/s/ Michael L. Greenwood
Michael L. Greenwood
Senior Vice President,
Chief Financial Officer
and Treasurer
(Principal Financial Officer and
Principal Accounting Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by
the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature
Title
/s/ Joseph W. Craft III
Joseph W. Craft III
/s/ Michael L. Greenwood
Michael L. Greenwood
/s/ John J. MacWilliams
John J. MacWilliams
/s/ Preston R. Miller, Jr.
Preston R. Miller, Jr.
/s/ John P. Neafsey
John P. Neafsey
/s/ John H. Robinson
John H. Robinson
/s/ Robert G. Sachse
Robert G. Sachse
/s/ Paul R. Tregurtha
Paul R. Tregurtha
President, Chief Executive
Officer and Director
(Principal Executive Officer)
Senior Vice President,
Chief Financial Officer
and Treasurer
(Principal Financial Officer and
Principal Accounting Officer)
Director
Director
Director
Director
Date
March 14, 2001
March 14, 2001
March 14, 2001
March 14, 2001
March 14, 2001
March 14, 2001
Executive Vice President and Director March 14, 2001
Director
March 14, 2001
62
Exhibit
Number
Description
EXHIBIT INDEX
3.1
3.2
3.3
3.4
4.1
10.1
10.2
10.3
10.4
10.5
10.6
Amended and Restated Agreement of Limited Partnership of Alliance Resource
Partners, L.P. (Incorporated by reference to Exhibit 3.1 of the Registrant’s Annual
Report on Form 10-K for the year ended December 31, 1999).
Amended and Restated Agreement of Limited Partnership of Alliance Resource
Operating Partners, L.P. (Incorporated by reference to Exhibit 3.2 of the
Registrant’s Annual Report on Form 10-K for the year ended December 31, 1999).
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).
Certificate of Limited Partnership of Alliance Resource Operating Partners, L.P.
(Incorporated by reference to Exhibit 3.8 of the Registrant’s Statement on Form S-
1/A filed with the Commission on July 20, 1999).
Form of Common Unit Certificate (Included as Exhibit A to the Amended and
Restated Agreement of Limited Partnership of Alliance Resource Partners, L.P.).
Credit Agreement, dated as of August 16, 1999, among Alliance Resource GP,
LLC, The Chase Manhattan Bank (as paying agent), Deutsche Bank AG, New
York Branch (as documentation agent), Citicorp USA, Inc. and The Chase
Manhattan Bank (as co-administrative agents) and the lenders named therein.
(Incorporated by reference to Exhibit 10.1 of the Registrant’s Annual Report on
Form 10-K for the year ended December 31, 1999).
Note Purchase Agreement, dated as of August 16, 1999, among Alliance Resource
GP, LLC and the purchasers named therein. (Incorporated by reference to Exhibit
10.2 of the Registrant’s Annual Report on Form 10-K for the year ended December
31, 1999).
Contribution and Assumption Agreement, dated August 16, 1999, among Alliance
Resource Holdings, Inc., Alliance Resource Management GP, LLC, Alliance
Resource GP, LLC, Alliance Resource Partners, L.P., Alliance Resource Operating
Partners, L.P. and the other parties named therein. (Incorporated by reference to
Exhibit 10.3 of the Registrant’s Annual Report on Form 10-K for the year ended
December 31, 1999).
Omnibus Agreement, dated August 16, 1999, among Alliance Resource Holdings,
Inc., Alliance Resource Management GP, LLC, Alliance Resource GP, LLC and
Alliance Resource Partners, L.P. (Incorporated by reference to Exhibit 10.4 of the
Registrant’s Annual Report on Form 10-K for the year ended December 31, 1999).
Alliance Resource Management GP, LLC 2000 Long-Term Incentive Plan (as
amended). (Incorporated by reference to Exhibit 10.11 of the Registrant’s Annual
Report on Form 10-K for the year ended December 31, 1999).
Incentive Plan.
Alliance Resource Management GP, LLC Short-Term
(Incorporated by reference to Exhibit 10.12 of the Registrant’s Annual Report on
Form 10-K for the year ended December 31, 1999).
63
10.7
10.8
10.9
10.10
10.11
10.12
10.13
10.14
*10.15
*10.16
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).
Amendment No. 1 to the Restated and Amended Coal Supply Agreement effective
April 1, 1996 between MAPCO Coal Inc., Webster County Coal Corporation,
White County Coal Corporation, and Seminole Electric Cooperative, Inc.
(Incorporated by reference to Exhibit 10.14 of the Registrant’s Quarterly Report on
Form 10-Q for the quarter ended June 30, 2000).
Interim Coal Supply Agreement effective May 1, 2000 between Alliance Coal,
LLC and Seminole Electric Cooperative, Inc. (Incorporated by reference to Exhibit
10.15 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended
June 30, 2000).
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).
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).
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).
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).
Agreement for Supply of Coal to the Mt. Storm Power Station, dated January 15,
1996, between Virginia Electric and Power Company and Mettiki Coal
Corporation. (Incorporated by reference to Exhibit 10. (t) to MAPCO Inc.’s Annual
Report on Form 10-K, filed April 1, 1996, File No. 1-5254).
Coal Sales Agreement, dated October 3, 1998, between Pontiki Coal Corporation
and A.E.I. Coal Sales, Inc. (Portions of this agreement have been omitted based on
a request for confidential treatment. Those omitted portions have been filed with
the Securities and Exchange Commission).
Amendment No. 1 to Coal Sales Agreement dated February 28, 2001, between
Pontiki Coal, LLC and AEI Coal Sales Company, Inc. (Portions of this agreement
have been omitted based on a request for confidential treatment. Those omitted
portions have been filed with the Securities and Exchange Commission).
* 10.17
Amended and Restated Put and Call Option Agreement dated February 12, 2001
between ARH Warrior Holdings, Inc. and Alliance Resource Partners, L.P.
64
*10.18
Consulting Agreement for Mr. Sachse dated January 1, 2001.
10.19
Form of Employment Agreement for Messrs. Craft, Pearson, Greenwood, Wesley
and Rathburn. (Incorporated by reference to Exhibit 10.6 of the Registrant’s
Registration Statement on Form S-1/A filed with the Commission on August 9,
1999).
* 21.1
List of Subsidiaries.
*Filed here within
65
U n i t h o l d e r I n f o r m a t i o n
Publicly-Traded Units
Alliance Resource Partners, L.P. is a
publicly-traded master limited
partnership.
Alliance Resource Partners, L.P.
common units began trading on the
Nasdaq National Market under the
symbol “ARLP” in August of 1999. As
of December 31, 2000, there were
15,405,311 common and subordinated
units outstanding.
Cash Distributions
Alliance Resource Partners, L.P. expects
to make Minimum Quarterly
Distributions of $0.50 per common
unit within 45 days after the end of
each March, June, September and
December to unitholders of record on
the applicable record dates.
Partnership Tax Details
n Unitholders are partners in the
Partnership and receive cash
distributions. The cash distributions
are generally not taxable as long as
the unitholder’s tax basis remains
above zero.
n A partnership is generally not subject
to federal or state income tax. The
annual income, gains, losses,
deductions, or credits of the
Partnership flow through to the
unitholders, who are required to
report their allocated share of these
amounts on their individual tax
returns, as though the unitholder had
incurred these items directly.
n Unitholders of record will receive
Schedule K-1 packages that
summarize their allocated share of
the Partnership’s reportable tax items
for the fiscal year. It is important to
note that cash distributions received
should not be reported as taxable
income. Only the amounts provided
on the Schedule K-1 should be
entered on each unitholder’s 2000
tax return.
n Should you have questions
regarding the Schedule K-1 contact:
Alliance Resource Partners, L.P.
K-1 Support
P.O. Box 480927
Denver, CO 80248
(800) 485-6875
Fax: (720) 931-7937
Transfer Agent and Registrar
Unitholder requests regarding transfer of units, lost certificates, lost distribution
checks or changes of address should be directed to:
American Stock Transfer and Trust Company
Attn: Shareholder Services
40 Wall Street
New York, NY 10005
(800) 937-5449
Additional Investor Information
Additional information about Alliance Resource Partners, L.P. can be obtained by
contacting Investor Relations by e-mail at fredric@arlp.com, telephone at (918)
295-7642, or writing to the Partnership’s Mailing Address provided below.
Partnership Offices
Alliance Resource Partners, L.P.
1717 South Boulder Avenue
Tulsa, OK 74119
(918) 295-7600
Partnership Mailing Address
P.O. Box 22027
Tulsa, OK 74121-2027
Independent Auditors
Deloitte & Touche LLP
Two Warren Place
6120 South Yale, Suite 1700
Tulsa, OK 74136
Officers and Directors
Joseph W. Craft III
President, Chief Executive Officer and
Director
Robert G. Sachse
Executive Vice President and Director
Thomas L. Pearson
Senior Vice President – Law and
Administration, General Counsel and
Secretary
Michael L. Greenwood
Senior Vice President – Chief Financial
Officer and Treasurer
Charles R. Wesley
Senior Vice President – Operations
Gary J. Rathburn
Senior Vice President – Marketing
John J. MacWilliams
Director
Preston R. Miller, Jr.
Director
John P. Neafsey
Director
John H. Robinson
Director
Paul R. Tregurtha
Director
1717 South Boulder Avenue
P.O. Box 22027
Tulsa, Oklahoma 74121-2027
Contact:
Carolyn Fredrich
Director – Investor Relations
918-295-7642
fredric@arlp.com
Alliance Resource Partners, L.P.
common units
are traded on the Nasdaq National Market
Ticker Symbol: ARLP
ARLP
(cid:13)