Alliance Resource Partners
Annual Report 2000

Plain-text annual report

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 4 mine for future longwall mining operation areas. The preparation plant has a throughput capacity of 1,350 tons of raw coal an hour. Production from the mine is shipped via truck and the CSX railroad. Our primary customer for coal produced at Mettiki is Virginia Electric and Power Company (VEPCO), which purchases the coal pursuant to a long-term contract for use in the generating units at its Mt. Storm, West Virginia power plant located less than 20 miles away. We also process coal at Mettiki for Anker Energy Corporation and one of its affiliates. Mettiki Coal (WV), LLC. Mettiki (WV) has approximately 20.1 million tons of undeveloped recoverable reserves in Grant and Tucker Counties, West Virginia adjacent to Mettiki in Garrett County, Maryland. We currently conduct no mining operations at Mettiki (WV). OTHER OPERATIONS Mt. Vernon Transfer Terminal, LLC Mt. Vernon terminal is a rail-to-barge loading terminal on the Ohio River in Mt. Vernon, Indiana. The terminal has a capacity of 5.5 million tons per year with existing ground storage. The terminal was used from 1983 through 1998 for shipments from Pattiki and Dotiki under our coal supply agreement with Seminole. Seminole now transports these shipments directly by CSX railroad. We currently use the facility as needed for spot shipments to customers other than Seminole and continue to explore our opportunities and options regarding the terminal. Coal Brokerage We buy coal from outside producers throughout the eastern United States, which we then resell, both directly and indirectly, to utility and industrial customers. We purchased and sold 200,000 tons of outside coal in 2000. We have a policy of matching our outside coal purchases and sales to minimize market risks associated with buying and reselling coal. Additional Services We develop and market additional services in order to establish ourselves as the supplier of choice for our customers. Examples of the kind of services we have offered to date include ash and scrubber sludge removal, coal yard maintenance, and arranging alternate transportation services. We will continue to think proactively in providing additional services for customers and believe that this approach will give us a competitive advantage in obtaining coal supply contracts in the future. COAL MARKETING AND SALES As is customary in the coal industry, we have entered into long-term contracts with many of our customers. These arrangements are mutually beneficial. Our utility customers secure a fuel supply for their power plants for years into the future. Our long-term contracts contribute to both our customers and our stability and profitability by providing greater predictability of sales volumes and sales prices. In 2000, approximately 85% of our sales tonnage was sold under long-term contracts with maturities ranging from 2000 to 2012. Our total nominal commitment under significant long-term contracts was approximately 74.8 million tons at December 31, 2000. The total commitment of coal under contract is an approximate number because, in some instances, our contracts contain provisions that could cause the nominal total commitment to increase or decrease by as much as 20%. In addition, the nominal total commitment can otherwise change because of price reopener provisions contained in certain of these long-term contracts. We believe our long- term contract position compares favorably to those of our competitors. The terms of long-term contracts are the results of both bidding procedures and extensive negotiations with the customer. As a result, the terms of these contracts vary significantly in many respects, including, 5 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 6 a particular mine or customer might affect, either adversely or favorably, our marketing efforts with respect to coal produced from the relevant mine. REGULATION AND LAWS The coal mining industry is subject to regulation by federal, state and local authorities on matters such as: employee health and safety; - - mine permits and other licensing requirements; - - water pollution; - 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; - - - - management of solid wastes generated by mining operations; - - management of electrical equipment containing polychlorinated biphenyls (PCBs); - - - surface subsidence from underground mining; the effects that mining has on groundwater quality and availability; and legislatively mandated benefits for current and retired coal miners. 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 7 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: 8 - - - - - - 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 9 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: - - - - 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, 10 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: - - - 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 11 - 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. 12 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) 

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