Item 1. Business.
Kentucky River Properties LLC (the Successor Company), a Delaware limited liability company, was formed on February 14, 2002 in connection with the proposed restructuring of Kentucky River Coal Corporation (the Predecessor Company) to convert to S corporation status for federal income tax purposes. The shareholders of the Predecessor Company approved the restructuring at a special meeting on July 29, 2002. As part of the restructuring, a wholly-owned subsidiary of the Predecessor Company merged into the Predecessor Company on July 31, 2002 and
o each common share held by the majority shareholders (40,414 shares) remained outstanding (the majority shareholders are the 70 shareholders that (i) held the highest percentage of the Predecessor Company's common shares as of the close of business on July 22, 2002, (ii) were eligible to be S corporation shareholders and (iii) who returned the required documentation) and
o each common share of the Predecessor Company held by other shareholders (21,491 shares) was converted into the right to receive $4,000 in cash and a subscription right to subscribe for one Kentucky River Properties LLC membership unit at an exercise price of $4,000 per membership unit.
On November 30, 2002, the Predecessor Company transferred to Kentucky River Properties LLC substantially all of its assets and liabilities, except for membership units in Kentucky River Properties LLC, and Kentucky River Properties LLC became the operating company for the business of the Predecessor Company.
On December 1, 2002, the subscription rights for Kentucky River Properties LLC membership units became exercisable and remained exercisable for a 30-day period. The subscription rights expired at 5:00 p.m., Eastern Time, on December 30, 2002. As of December 31, 2002, 6,007 membership units had been exercised and were outstanding in addition to the 40,414 membership units held by the Predecessor Company resulting in a total of 46,421 Kentucky River Properties LLC membership units outstanding.
Kentucky River Properties LLC, and the Predecessor Company prior to the restructuring, is principally engaged in the business of managing coal-bearing properties in Southeastern Kentucky. We enter into long-term leases with experienced, third-party mine operators for the right to mine our coal reserves in exchange for royalty payments. We currently lease our reserves to 17 different operators who mine coal at 41 mines. Our lessees are generally required to make payments to us based on the amount of coal they produce from our properties and the price at which they sell the coal, subject to fixed minimum base royalty rates per ton. We do not operate any mines now, nor have we ever in the past. In managing our properties, we monitor the operations of our lessees to ensure they are obtaining acceptable recovery of reserves from our properties under the given mining conditions, and that they are reporting the tonnage and royalty computations accurately. Some of our lessees use preparation and transportation facilities situated on our property, for which we receive a utilization fee based on the tonnage and sales price of the coal processed. For the Successor Company's period December 1 through December 31, 2002 and for the Predecessor Company's period January 1 through November 30, 2002, in excess of 90% of our revenue was derived from coal-bearing properties. Accordingly, the Successor Company and the Predecessor Company are considered to operate in a single, dominant industry segment.
As of December 31, 2002, our coal properties contained an estimated 569 million tons of proven and probable recoverable reserves located on approximately 214,000 acres in Southeastern Kentucky. Our coal reserves consist of bituminous coal and are predominantly high in energy content and low to medium sulfur content. As of December 31, 2002, approximately 18% of our reserve base was compliance coal and 25% of our reserve base exhibits an average clean sulfur content of less than 1.00%, including compliance coal. Compliance coal refers to coal that, when burned, emits less than 1.2 pounds of sulfur dioxide per million Btu (British thermal units).
In addition to our coal business, we generate revenues from royalties and sales of oil and gas and from the sale of timber harvested from our properties. Our oil and gas revenue is generated primarily from royalties from wells for which we retain the underlying property.
Our timber generates only a modest amount of revenue. Recent studies of our timber by forestry consultants have concluded that there is little potential for materially increasing timber revenues in the short run because our stands are of poor quality. This is mainly the result of the most valuable species having been repeatedly harvested leaving only inferior species to dominate the stands. We are taking steps to improve the quality of our timber as prescribed by the consultants, but due to the slow growing nature of timber, the results will not be evident for decades.
Besides our natural resource operations, we also invest in fixed income and equity securities, and we own undeveloped real estate in Kentucky, Florida and Maryland. During 2002, our portfolio of securities was liquidated to finance our restructuring. As a result of the exercise of the membership units in December 2002, and the resultant influx of cash, some of which was invested in U.S Treasury bills, our portfolio of securities at December 31, 2002 was valued at approximately $19 million. As a result of the restructuring, we anticipate that we will no longer engage in investing activities except as a means of enhancing returns from liquid assets on a near term basis.
Our undeveloped real estate has an estimated market value of about $20 million, based on pending sales and option contracts and internal valuation estimates. The real estate was acquired more than ten years ago during a period when we were buying undeveloped parcels a short distance from more intense land uses, with the intent of selling when they became suitable for higher-value land uses. This strategy has become less viable in recent years as holding costs increased and owners have declining autonomy in determining uses for their land as result of stricter zoning regulations. We have not purchased any non-coal real estate for several years, and have never participated in real estate development.
Business Strategy
Our principal business strategies are to:
o Maintain stable coal production from our properties. Despite the peaks and valleys inherent to the coal industry, our lessees as a group have provided a remarkably steady level of coal production over the years. We support our lessees by providing large boundaries of reserves under common control and significant reserve data relating to the areas they are mining and propose to mine. We own substantial unleased reserves with which we may provide our lessees additional reserves as their areas of current mining become exhausted.
o Expand our reserve base. We have pursued reserve acquisitions throughout our history, but have added only two significant boundaries over the past 20 years, one comprising 13,000 acres and the other 9,000 acres. We believe as a result of the restructuring we will become more competitive with respect to reserve acquisitions, as our strongest competitors in the past have typically had a tax advantage that allowed them to pay more for reserves. As a result of the restructuring, we will be on equal footing with those competitors with respect to our tax structure. We expect to continue to focus on acquisitions in southeastern Kentucky where we now operate, but we will consider the acquisition of reserves in other areas if the reserves satisfy our acquisition criteria, including the expectation of a satisfactory return on investment. Without an investment portfolio to complement our natural resource assets, it will become more important for us to be able to replace our reserves in order to remain a going concern.
o Diversify our lessee base. We currently lease our coal reserves to 17 different operators who are mining at 41 mines. We depend on a limited number of primary operators, however, for a significant portion of our coal royalty revenues. The James River Group (27% in 2000, 28% in 2001, and 21% in 2002), Horizon Natural Resources Company, formerly AEI Resource Holding, Inc. (25%, 23% and 26%, respectively), and Diamond May Coal Co. (14%, 12% and 10%, respectively), each with multiple leases, account for more than 55% of our coal royalty revenues. We intend to diversify our lessee base to enhance the stability of our cash flow. Diversification of our lessee base is critical because the trend in the industry and among our own lessees has been toward consolidation, resulting in our royalties coming from fewer lessees. With consolidation, the risks associated with our royalty income are spread over fewer lessees, such that if a single lessee falters the adverse impact on our earnings could be magnified.
o Utilize our properties productively. Though most of our revenue comes from coal, we will work to develop other sources of income including oil and gas as well as timber. On a modest scale, we will participate in the drilling of oil and gas wells with operators on our property to the extent that financial returns justify doing so. By participating in the drilling, we encourage the drilling to take place, as it allows the drilling operators to spread their capital over a larger number of wells, thereby reducing their risk. For us, we have the added benefit of having more production from our property, such that in addition to the sale of oil and gas we also earn royalties.
Competitive Strengths
We have several competitive strengths that we believe will allow us to successfully execute our business strategies:
o Our royalty structure generates relatively stable and predictable cash flows and limits our exposure to low commodity prices, compared to mining companies. Our leases provide for royalty rates generally equal to the higher of a fixed minimum rate or a percentage of the gross sales price received by our lessees for the coal they produce from our reserves. This structure causes our earnings and cash flow to be stable and predictable in periods of low commodity prices, while enabling us to benefit during periods of high commodity prices. Also, since we do not operate any mines, we do not directly bear any operational risks or production costs.
o We lease to experienced lessees that have long-term relationships with major customers. We lease our reserves principally to lessees that have substantial experience as coal mine operators, established reputations in the industry and strong relationships with major electric utilities, independent power producers and other commercial and industrial customers. Our lessees' major customers include AEP, Duke Energy and Southern Company. Many of our lessees' customers have purchased coal regularly from our lessees for more than ten years. We believe that our lessees sold approximately 80% of the coal they mined from our reserves in 2002 under supply contracts with terms of more than one year.
o We will be well-positioned to pursue reserve acquisitions. While we have not made many acquisitions in recent years, our restructuring will position us to make more acquisitions in the future. Our knowledge of engineering and geology provide us with the ability to evaluate opportunities that are presented to us. In addition, we have conducted an extensive study of our own reserves, through which we also learned much about nearby reserves owned by others. This information could help us identify reserves that would be suitable for acquisition.
o Much of our reserves are low sulfur coal. With Phase II of the Clean Air Act Amendments in effect, compliance and low sulfur coal have captured a growing share of U.S. coal demand, commanding higher prices than higher sulfur coal in the market place. As of December 31, 2002, approximately 18% of our reserve base was compliance coal and approximately 25% of our reserve base exhibits an average clean sulfur content of less than 1.00%, including compliance coal. We believe we are well-positioned to capitalize on the continuing growth in demand for low sulfur coal to produce electricity.
o Our reserves are well positioned geographically. Our reserves are located on or near some of the major coal hauling railroads that serve Central Appalachia. We believe that the geographic location of our reserves gives our lessees a transportation cost advantage, particularly with respect to coal produced in the western states, which improves their competitive position and our corresponding coal royalty revenues.
o We have a strong management team with a successful record of managing and leasing coal properties. We have a highly capable and experienced management team that is familiar with the areas in which our lessees mine coal, the mining environment and trends in the industry. Our active land management style is a fundamental basis for our business. Our management team also reviews numerous acquisition opportunities on an ongoing basis.
Coal Leases
We earn our coal royalty revenues under long-term leases that generally require our lessees to make payments to us based on the higher of a percentage of the gross sales price or a fixed price per ton of coal they sell, with pre-established minimum annual tonnage requirements. Currently, we lease approximately 334 million tons of reserves to 17 different lessees that operate 41 mines. A typical lease has a 5 to 10 year base term, or until all the mineable and merchantable coal has been removed, whichever last occurs.
Substantially all of our leases require the lessee to pay minimum royalties in annual installments, even if no mining activities take place. These minimum royalties are recoupable, usually over a period of five years from the time of payment, against the production royalties owed to us once coal production exceeds minimum production requirements in the year of the recoupment. Substantially all our leases impose on the lessee the following obligations:
o to diligently mine the greatest amount of coal using current mining techniques from the leased property;
o to employ a competent registered professional mining engineer to plan mining development and to plot the development on maps for our review;
o to indemnify us for any damages we incur in connection with the lessee's mining operations;
o to conduct mining and reclamation operations in compliance with all applicable federal, state and local laws and regulations;
o to obtain our written consent prior to subleasing or assigning the lease; and
o to maintain general liability and property damage insurance in amounts we deem reasonable.
Substantially all of the leases grant us the following rights:
o to terminate the lease and take possession of the leased premises in the event of a default by the lessee;
o to review all lessee mining plans and maps;
o to enter the leased premises to examine mining operations and to conduct both engineering and financial audits to confirm the amount of coal mined from our properties and the sale price received for the coal by our lessees; and
o to retain all rights to the leased premises other than the right to mine the leased coal, including the right to use the surface of the leased property and to retain all rights to oil, gas, timber and other coal seams and minerals existing on the leased premises.
In addition, each lease provides that we expressly deny any warranty as to the quality or quantity of coal on our property. Each lease also provides that we make no warranty as to title and that we lease only those rights we own and have the right to lease. Our leases typically do not include any provisions permitting the lessee to terminate the lease before the end of its term.
We have three leases that each accounted for more than 10% of our coal royalties in 2002. The first of these leases is with a division of James River Coal Company, the second lease is with Diamond May Coal Company and the third lease is with a division of Horizon Natural Resources Company. The lease with the James River division covers mining rights in Perry and Leslie Counties. The lease with Diamond May Coal Company covers mining rights in Knott and Letcher Counties. The lease with Horizon Natural Resources covers mining rights in Leslie County. The lease with the James River division provides for arbitration of disputes arising under the lease. The lease with Diamond May permits the lessee, if it is not in default under the lease, to terminate a portion of the lease with 12 months notice by paying us a fee of $1 million plus lease minimums with respect to the terminated portion of the lease through the entire calendar year during which termination occurs. Otherwise, these leases do not contain provisions that differ materially from the general provisions described above.
Lessees
We have leases with 17 different coal companies. In 2002, we had 25 active underground mines, eight inactive underground mines and 15 active surface mines on our properties. Our three major leaseholders are Horizon Natural Resources Company (formerly, AEI Resource Holding, Inc.), James River Coal Corporation and Diamond May Coal Company. Some of our lessees engage contractors to operate their mines which, under the terms of our leases, requires our consent.
Approximately one-half of the coal mined from our property is shipped by rail through the CSX Transportation, Inc. The remainder is either trucked directly to ultimate consumer or trucked to barge loading facilities located on the Ohio River near Ashland, Kentucky. The following is a summary of our primary lessees' operations on our properties.
Except for one facility located on property leased to Diamond May Coal Company, we do not own any coal processing or handling facilities. Many of our lessees have built or refurbished existing coal handling facilities which are located on our properties. We receive a haulage fee for coal that is brought from other property onto our property and processed for shipment.
Horizon Natural Resources Company
Horizon Natural Resources Company (formerly, AEI Resource Holding, Inc.) is the owner of four operating divisions which hold 11 leases covering surface and underground mining rights in Perry, Leslie, Knott and Harlan Counties. Horizon operates eight surface mines and one underground mine. Horizon ships most of its coal through its unit train loadout facility; however, some coal is shipped directly to local power plants or to barge loading facilities by truck. Horizon has four train loadout facilities, two of which are presently idle, and four coal preparation plants, two of which are presently idle. The two active preparation plants are located near our property and are capable of processing approximately 850 tons of coal per hour. Horizon's primary customers for coal from our property include Georgia Power Company, the Tennessee Valley Authority and Kentucky Utilities. Horizon began operation in 1972 as Addington Brothers Mining, and through expansion and acquisition, has become one of the country's largest mining companies with operations in several states. On February 28, 2002, Horizon, then known as AEI Resources Holding, Inc. announced a proposed debt restructuring to be completed through a pre-packaged reorganization under Chapter 11 of the U.S. Bankruptcy Code. On April 12, 2002, AEI announced that the U.S. Bankruptcy Court for the Eastern District of Kentucky had approved the company's plan of reorganization, and on May 10, 2002, the company announced that it had emerged from the bankruptcy restructuring as Horizon Natural Resources Company. On November 13, 2002, Horizon re-entered bankruptcy by filing for Chapter 11 protection in the Eastern District of Kentucky. Although presently in bankruptcy proceedings, Horizon continues to operate mines on our property.
James River Coal Company
James River Coal Company is the owner of four operating divisions which hold 13 leases covering surface and underground mining rights in Perry, Leslie, Knott, Letcher and Harlan Counties. James River operates two surface mines and 11 underground mines. The majority of the underground mines use continuous haulage systems, with the exception of some of James River's contract mines and longwall operating in one mine. James River ships primarily through its unit train loadout facilities. Some coal is shipped by truck directly to local utilities. James River operates four preparation plants, which are capable of processing 650 tons, 1,250 tons, 800 tons and 1,500 tons of coal per hour, respectively. Two of these plants are located on our property and the other two are located near our property. James River's primary customers for coal from our property include Georgia Power Company, the Santee Cooper Plant of South Carolina Public Services, City of Lakeland Florida, Jacksonville Electric and Dayton Power & Light. James River is a major mining company and one of its divisions has had leases with us since our founding in 1915.
Diamond May Coal Company
Diamond May has one lease covering surface and underground mining rights in Knott and Letcher Counties and covering underground mining rights along the Knott and Letcher County line. Diamond May operates three surface mines and three underground mines. A new underground mine in the Amburgy seam opened in 2002 and replaced a mine in the Hazard 5-A seam which had mined to exhaustion. Diamond May processes most of its coal through a preparation plant which we own and which is capable of processing approximately 500 tons of coal per hour. Diamond May ships most of its coal from a unit train loadout which we own. Diamond May ships some coal by truck to barge loading facilities on the Ohio River or to an affiliated unit train loadout facility located near our property. Diamond May's primary customers for coal from our property include Florida Power's Crystal River Plant, Co-Gentrix, American Electric Power and Weyerhaeuser. Diamond May Coal Company is a subsidiary of Progress Fuels, which is owned by Progressive Energy, a diversified holding company whose portfolio includes Florida Power and CP&L. Progress Fuel's mining subsidiaries own or control property in the Central Appalachian region.
TECO Coal Corporation
TECO Coal Corporation is the owner of two operating divisions which hold four leases covering surface and underground mining rights in Perry and Knott Counties. TECO operates one surface mine and three underground mines. One of TECO's divisions, Bear Branch Coal Company, has one lease covering surface and underground mining rights in Perry and Knott Counties. This division recently opened a new underground mining complex in the Amburgy seam and began production in late 2002. Teco plans to begin production in the Elkhorn No. 3 seam from this same complex in late 2003. The other division, Perry County Coal Corporation, has three leases covering surface and underground mining rights in Perry and Leslie counties and operates two underground mines. Coal mined from our property is trucked to and processed at a preparation plant and unit train loadout facility located near our property. The preparation plant is currently being upgraded to process approximately 1,500 tons per hour. The primary customers for coal from our property are Duke Power Company, Detroit Edison and South Carolina Gas & Electric Company. TECO, an affiliate of Tampa Electric Company of Florida, mines and ships coal from several mining operations in southeastern Kentucky and southwest Virginia.
Alpha Natural Resources (formerly Coastal Coal Company, LLC.)
Alpha Natural Resources has three leases covering surface and underground mining rights in Perry and Letcher Counties. Alpha was formed by First Reserve and its owner is American Metals and Coal International (AMCI). These leases were formerly held by Coastal Coal Company, LLC, successor to Enterprise Coal Company. Coastal's parent company is El Paso Energy, which sold its coal operating divisions in 2002. Alpha now operates three underground mines and is reevaluating the area for future mining. Alpha operates a preparation facility that is capable of processing approximately 500 tons of coal per hour. Alpha ships nearly all of its coal from a train loadout facility located near our property. Alpha's primary customers for coal from our property include Co-Gentrix, Ontario Power and Georgia Power. Alpha and its predecessor, Coastal, have had leases with us since 1989.
Cheyenne Resources, Inc.
Cheyenne Resources, Inc. has one lease covering surface mining rights in Knott County. Cheyenne started operations on our property using a highwall mine in August 2001. Cheyenne ships most of its coal to Virginia Electric Company by rail from a unit train loadout facility located near our property. Cheyenne ships some coal on specialty orders by truck. Cheyenne has been mining and processing coal since the mid 1980's in southeastern Kentucky, southwest Virginia and West Virginia.
Ernest Cook & Sons Mining, Inc.
Ernest Cook & Sons Mining, Inc. acquired operations of Golden Oak Mining Company, LLC in late 2000 and has three leases covering surface and underground mining rights in Letcher County. Cook & Sons operates three underground mines, one of which began operation in late 2001, and one surface mine. Most of Cook & Sons coal is processed and loaded at a preparation plant located on our property, which is capable of processing 1,000 tons of coal per hour. Cook & Sons ship the coal from a unit train loadout facility located on our property. Cook & Sons' primary customers for coal from our property include Detroit Edison, Virginia Power and South Carolina Power.
Miller Leasing, Inc.
Miller Leasing, Inc. has one lease covering surface mining rights in Knott County. Miller Leasing started surface mining on this property in November 2001. Miller Leasing ships all coal from this mine by truck to various customers. Miller Leasing has been mining coal in eastern Kentucky since the 1980's, and has held leases from us in the past.
Nally & Hamilton Enterprises, Inc.
Nally & Hamilton Enterprises, Inc. has four leases covering surface mining rights in Perry, Leslie, Letcher and Harlan Counties. The company added a large boundary of Hazard No. 4 and Hazard No. 5-A seam coal to one of Nally & Hamilton leases, and currently Nally & Hamilton has begun its permitting process for this boundary. Nally & Hamilton also works as a contract miner for Blue Diamond Coal Company on its leasehold. Nally & Hamilton ships all of its coal by truck to either the ultimate consumer or other coal companies which in turn ship through their unit train loadout facilities. Nally & Hamilton began its surface mining business in the late 1960's.
Phoenix Mining, Inc.
Phoenix Mining, Inc. has one lease covering surface and underground mining rights in Letcher and Knott counties. Phoenix subleases its surface mining rights to Nally & Hamilton and its underground mining rights to Cook & Sons. Currently one surface mine and one underground mine are operating on this property. Phoenix ships all of its coal by truck. Phoenix's owners have over 50 years experience in the mining industry.
Pine Branch Coal Sales, Inc.
Pine Branch Coal Sales, Inc. has one lease covering surface and underground mining rights in Perry County and operates two surface mines. Pine Branch ships most of its coal by rail through its unit train facility located near our property. Pine Branch ships coal directly to Georgia Power Company and Kentucky Utilities, the primary customers for coal from our property. Pine Branch also ships some coal to East Kentucky Power by truck. Pine Branch is owned by a family that has been mining in Perry and surrounding counties for nearly 40 years.
Other Businesses
In addition to our coal business, we generate revenue from royalties in sale of oil and gas and from the sale of timber harvested from our properties. We also own non-coal real estate.
In November 2001, we sold our portion of the oil and gas wells in which we owned an interest, but retained all of the underlying property we owned, thereby preserving oil and gas royalties on the existing wells. These royalties relate to oil and gas located on the fee acreage and mineral acreage listed under Item 2.
Item 2. Properties.
Our properties are primarily located in the six counties of Breathitt, Harlan, Knott, Leslie, Letcher and Perry in southeastern Kentucky and contain approximately 214,000 acres. Approximately 94,000 acres of the acreage is fee acreage, where we own the surface rights overlying the mineral we own. Mineral acreage refers to the property where we own the mineral rights but do not own the overlying surface rights. Surface acreage refers to property where we own the surface rights only, but do not own the mineral rights. We have not had a title company confirm title to our properties, however, our attorneys have abstracted title for almost all of our properties and we have maintained control over, and paid property tax on, our properties since we acquired them. We acquired most of our properties around the time of our incorporation in 1915.
The following table shows the acreage owned in each county.
Kentucky River Properties LLC Acreage Owned By County
Fee Mineral Surface County County Acreage Acreage Acreage Total - ------ ------- ------- ------- ------- Breathitt... -0- 225 -0- 225 Harlan...... 10,396 1,336 -0- 11,732 Knott....... 11,882 24,918 20 36,820 Leslie...... 18,486 17,204 205 35,895 Letcher..... 20,699 29,974 1,018 51,691 Perry....... 32,737 45,439 45 78,221 ------ ------- ----- ------- Total.... 94,200 119,096 1,288 214,584 ====== ======= ===== =======
The six-county area is serviced by the Daniel Boone Parkway and Highway 80 running east/west and Highway 15 running north/south. Highway 80 connects with U.S. Route 23 and extends north to the Ohio River which offers barge loading facilities that many lessees use. Rivers in this area are not navigable. The Daniel Boone Parkway connects with Interstate 75, which is a major north/south United States artery. Highway 15 connects with Interstate 64, which is a major east/west United States artery. Also, the properties are serviced by CSX Rail System, which services many of the lessees and offers rail delivery to most major utilities in the southeastern part of the United States.
Production
There were approximately 13.3 million tons mined from our properties in the calendar year 2002. Approximately 53% of the production was from underground mines and 47% was from surface mines. The following table shows our production and income for the last three years.
* Haulage is rental we collect from operators using our properties to facilitate their coal operations on property belonging to third parties. For example, we charge haulage for the transportation of third party coal across our properties and the loading of third party coal into trains using a unit train loadout facility located on our property. We usually base haulage on a rate per ton or a percentage of the gross sales price received by the operator, whichever is greater.
The following table sets forth our production royalty income by county for the last three years.
Production Royalty Income by County
County 2000 2001 2002 - ------ ----------- ----------- ----------- Harlan.............. $ 895,100 $ 1,352,744 $ 1,234,173 Knott............... 4,963,248 6,528,389 4,738,934 Leslie.............. 4,297,199 4,424,372 6,860,711 Letcher............. 4,498,576 4,868,079 4,137,305 Perry............... 9,840,623 10,875,120 7,110,671 ----------- ----------- ----------- Total............ $24,494,746 $28,048,704 $24,081,794
We project that the percentage of our total production from underground mining will increase from 65% to 79% in the next five years.
We project that approximately 60 million tons will be mined from our properties from 2003 through 2007.
Coal Reserves
As of December 31, 2002, we had 569 million recoverable tons of proven and probable coal reserves located on approximately 214,000 acres in five adjoining counties in southeastern Kentucky.
These counties are: Breathitt, Harlan, Knott, Leslie, Letcher, and Perry counties. All of our coal reserves are considered to be steam grade reserves.
A reserve is defined as that part of a mineral (coal) deposit which could be economically and legally extracted or produced at the time of the reserve determination. All estimates of our reserves presented are recoverable, proven and probable reserves. Proven and probable reserves are defined as follows:
o Proven Reserves. Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established.
o Probable Reserves. Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but the sites for inspection, sampling, and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven reserves, is high enough to assume continuity between points of observation.
Tons (000's) --------------- Seam Name(1) Leased Unleased - ------------ ------- -------- Upper Skyline (No. 12).................. 158 0 Skyline (No. 11)........................ 577 0 Tiptop (No. 10)......................... 1,296 142 Hazard No. 9............................ 14,254 311 Peach Orchard........................... 0 3,567 Hazard No. 8............................ 27,605 212 Hazard No. 7 Rider...................... 6,272 0 Hazard No. 7............................ 10,591 124 Hazard No. 5A........................... 32,624 6,055 Haddix.................................. 1,954 1,599 Copland................................. 1,047 101 Hamlin & Upper Hamlin................... 2,330 1,667 Hazard No. 4 Rider...................... 17,911 257 Hazard No. 4............................ 59,167 1,363 Upper Whitesburg........................ 196 0 Amburgy................................. 61,089 60,940(5) Upper Elkhorn No. 3..................... 49,405 79,531(5) Upper Elkhorn No. 2..................... 29,560 63,063(5) Upper Elkhorn No. 1..................... 17,978 16,252(5) ------- ------- Totals............................... 334,014 235,184(5) ======= =======
(1) Reserve quantity is presented as recoverable short tons (1 ton = 2000 pounds) which takes into account expected mining and washing losses. (2) Average mining recovery and wash plant recovery, where applicable, are reflected in the estimated reserve quantity. (3) Coal quality values are derived from washability analyses at a 1.50 specific gravity. The clean-coal values are adjusted to an 'as received' basis by applying a moisture content of 6 percent to compensate for quality variation upon delivery. (4) 18% of the total reserves are compliance; 82% are non-compliance. (5) 93% of the unleased coal reserves are made up of these seams.
Our reserve estimates are prepared from geological data assembled and analyzed by our geologists and engineers. These estimates are compiled using geological data taken from approximately 3,600 drill holes, adjacent mine workings, outcrop prospect openings and other sources. These estimates take into account legal, technical and economic limitations that may keep coal from being mined. In addition, these estimates take into account any detriments to mining, including roads, buildings, power lines, or other physical barriers that may prevent mining. We also do not consider any of our unleased coal included in our reserves to be unmarketable because of quality. Reserve estimates will change from time to time due to mining activities, acquiring new data, acquisitions or divestment of reserve holdings, modification of mining plans or mining methods and other factors.
As of December 31, 2002, approximately 90% of our total reserves are recoverable through underground mining methods. The remaining 10% is recoverable through surface mining methods.
We classify our coal reserves with respect to sulfur content as coal containing less than 1.00% sulfur by weight, coal containing a sulfur greater than 1.00% by weight, and as undefined coal reserves. That portion of the low sulfur coal, less than 1.00%, that meets the compliance standards for Phase II of the Clean Air Act Amendments of 1.2 pounds of sulfur dioxide per million Btus (1.2 lbs. SO\\2\\/mmBtu) is considered compliance coal. As of December 31, 2002, approximately 18% of our total estimated reserves met compliance standards for Phase II of the Clean Air Act Amendments.
Exploration Program
In 1995 we initiated a coal exploration program, which we refer to as The Exploration Program, to evaluate our coal reserves and to more actively lease our coal properties. In the Exploration Program, subsurface geological data is collected by core drilling methods that provide samples of the deeper coal seams and associated rocks. These samples are subjected to detailed descriptions, testing, and analyses in order to assess the quality and mineability characteristics of the coal seams.
In addition to assisting in the leasing of coal properties, we use data from The Exploration Program to revise our reserve estimates. We have established a computer database of the pertinent geological data using Coal Master (C-Master) for initial entry and editing of the geological data, and Coal Geology Bank (CGB) for inclusion of the quality data. There are approximately 3,600 geological data points in the database. We use Surfer to generate grids and isopach or isopleth lines are imported into AutoCAD to plot on the maps. We are evaluating the coal reserves on a seam-by-seam basis for each of the USGS topographic quadrangle maps covering our coal holdings. We have prepared seam maps that shows the data points available for the each coal seam, its thickness, elevation, mined out areas and our tract boundaries.
Office Properties
We own our office building in Hazard, Kentucky consisting of approximately 14,000 square feet and lease our corporate offices in Lexington, Kentucky consisting of 4,400 square feet.
Item 3.
Item 3. Legal Proceedings.
Although we are, from time to time, involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any legal proceedings against us under the various environmental protection statutes to which we are subject.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders.
Not applicable.
PART II
Item 5.
Item 5. Market for Registrant's Common Equity and Related Unitholder Matters.
There is currently no public trading market for Kentucky River Properties LLC membership units and we do not currently anticipate that a trading market will develop. The membership units are subject to transfer restrictions under Kentucky River Properties LLC's operating agreement and are not freely transferable. As of March 24, 2003, there were 46,421 membership units issued and outstanding to 144 membership unit holders of record.
The operating agreement requires that Kentucky River Properties LLC distribute its net cash flow, if any, not later than 30 days after the end of each fiscal quarter, to the members in proportion to the number of membership units owned. The term "net cash flow" is defined in the operating agreement as the gross cash proceeds of Kentucky River Properties LLC minus the portion thereof used to pay
or establish reserves for expenses, debt payments, capital improvements, replacements, and contingencies, as determined by the management committee. The definition further provides that net cash flow will not be reduced by depreciation, amortization, cost recovery deductions or similar allocations, but will be increased by any reduction in reserves previously established. The term "gross cash proceeds" is not defined in the operating agreement but is intended to include all cash received by Kentucky River Properties LLC from any source for any reason. Thus, gross cash proceeds include all cash received by Kentucky River Properties LLC in the ordinary course of business as the result of operating, investing or financing activities as well as all cash received from dispositions or other extraordinary events.
While the operating agreement requires that Kentucky River Properties LLC distribute 100% of its net cash flow, whether there is any net cash flow to distribute will depend upon both the level of gross cash proceeds and upon the portion of gross cash proceeds used to pay or establish reserves for expenses, debt payments, capital improvements, replacements, and contingencies. To the maximum extent consistent with its fiduciary duties, the management committee of Kentucky River Properties LLC, will endeavor to limit discretionary payments so as to distribute net cash flow on a quarterly basis to each member in proportion to such member's percentage interest in Kentucky River Properties LLC in an amount at least sufficient to enable members to pay federal and state income taxes attributable to ownership of membership units based on the highest applicable individual combined federal and state income tax rates. The management committee anticipates limiting discretionary payments so as to distribute a greater amount: at least 90% of Kentucky River Properties LLC's taxable income during the first five years after the restructuring and thereafter at least 50% of Kentucky River Properties LLC's taxable income.
Members may not receive a distribution from Kentucky River Properties LLC to the extent that, after giving effect to the distribution, all liabilities of Kentucky River Properties LLC, other than liability to members on account of their capital contributions, would exceed the fair value of its assets.
In January 2003, Kentucky River Properties LLC declared and paid a $2.3 million distribution of December 2002 net cash flow. The quarterly dividends declared by the Predecessor Company for the two most recent fiscal years are listed in the table below.
Kentucky River Coal Corporation (The Predecessor Company)
2001 Dividend - ---- -------- First Quarter..................................... $115.00 Second Quarter.................................... 40.00 Third Quarter..................................... 40.00 Fourth Quarter.................................... 40.00
2002 Dividend - ---- -------- First Quarter..................................... $115.00 Second Quarter.................................... 40.00 Third Quarter..................................... 40.00 Fourth Quarter (through November 30, 2002)........ 76.00
Item 6.
Item 6. Selected Financial Data.
SELECTED CONSOLIDATED FINANCIAL INFORMATION (in thousands, except share data)
The annual selected historical consolidated financial data presented below has been derived from our audited consolidated financial statements. As this information is only a summary, it should be read in conjunction with our historical consolidated financial statements and related notes contained elsewhere in this Form 10-K report.
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation.
Introduction
Our primary assets are coal-bearing properties in Southeastern Kentucky. Our business consists of leasing those properties to coal mine operators in exchange for royalty payments. As of December 31, 2002, our properties contained an estimated 569 million tons of proven and probable coal reserves. We currently lease coal under various leases to 17 lessees who mine coal at 41 mines. We also generate coal-related revenues through fees charged for use of coal preparation and loading facilities situated on our property. For the years ended December 31, 2000, 2001 and 2002, in excess of 90% of our total revenue, excluding the sale of substantially all of our oil and gas properties, was derived from coal-bearing properties.
In addition to coal, we receive revenues from oil and gas sales and royalties and own undeveloped non-coal real estate and a portfolio of equity and fixed income securities. Oil and gas sales accounted for less than 10% of total revenue, excluding the sale of substantially all of our oil and gas properties, for the years ended December 31, 2000, 2001 and 2002. After application of the quantitative thresholds for aggregation of reportable business segments, which in our situation was determined based primarily upon the nature of the products and services provided, the financial reporting throughout this document has been made on a fully aggregated basis as is appropriate for a company operating in a single, dominant industry segment.
We do not operate any mines. Instead, we enter into long-term leases with experienced, third-party coal mine operators for the right to mine coal reserves on our properties in exchange for royalty payments. Our leases pay royalties based on the higher of a percentage of the gross sales price or a fixed price per ton of coal sold, with pre-established minimum annual tonnage requirements. Because we do not mine the coal, we have relatively small operating expenses and capital expenditure requirements as compared to mining companies. Therefore, our coal royalty business has relatively high margins. We also contractually limit our exposure to liabilities associated with the operation of coal mines, including site or environmental remediation costs.
Our coal reserves are located on numerous individual tracts in the Kentucky counties of Perry, Letcher, Knott, Leslie, Breathitt, and Harlan. We own a total of 214,584 acres, of which 94,200 acres are both mineral and surface properties, 119,096 acres are mineral only and 1,288 acres are surface only.
Our revenues and profitability are largely dependent on the production of coal from our reserves by our lessees. Our coal royalty revenues vary depending on the coal prices realized by our lessees, subject to specified minimum fixed rates per ton. We estimate that our lessees sell more than 80% of the coal they produce to customers pursuant to contracts with negotiated prices and terms of a year or more. They sell the remaining portion of the coal they produce on the spot market. Therefore, our coal royalty revenues are affected by changes in coal prices and our lessees' long-term supply contracts and, to a lesser extent, by fluctuations in the spot market prices for coal. A number of factors affect the prevailing price for coal, including demand, the price and availability of alternative fuels, overall economic conditions and governmental regulations.
Following a spike in demand and prices for coal in the second half of 2000 and the first half of 2001, the coal industry experienced a decline in demand and prices throughout most of 2002. Coal market conditions for coal stabilized during the last months of 2002. During the period of decline in 2002, most utilities were reducing their excess stockpiles they had accumulated to avoid coal repeating shortages they experienced in the winter 2001-2000. However, due to a mild winter 2001-2002, the utilities carried excess stockpiles into late 2002. As a result of the weak market, many coal producers shut down mines or reduced production in existing mines. More recently, a very cold winter 2002-2003 and unstable natural gas prices caused spot coal prices to reach their highest level since early 2002. The Energy Information Administration (EIA) forecasts the trend in coal prices to be downward despite an upward trend in coal demand over the next 20 years. However, in the short-term, we expect coal prices and demand in 2003 to remain higher than experienced during most of 2002.
In addition to coal royalty revenues, we also generate revenues from fees charged to lessees for the use of coal preparation and transportation facilities situated on our property. These fees are generally calculated based on a percentage of the sales price of the coal, however, some are fixed at a dollar amount per ton.
We also receive revenues from oil and gas sales and royalties from production in Southeastern Kentucky. Sales are derived from oil and gas wells that we own in whole or in part. Royalties are revenues from oil and gas produced from our property. Most of the royalties relate to oil, as we sold most of our interests in the natural gas underlying our property in 1926.
In November 2001, we sold most of our working interests in oil and gas wells for $6.6 million, but retained all of our royalty interests. We traditionally participate in the drilling of a few wells each year, and despite having sold most of our wells in 2001, we expect to continue doing so.
Our non-coal real estate consists of six undeveloped parcels located near Lexington, Kentucky, Jacksonville, Florida, and Owings Mill, Maryland. Typically, we have bought undeveloped land a short distance from areas of more intense development, and profited when the tracts became suitable for a higher-value land use. In recent years, this approach has become less viable as a result of increasing carrying costs and less autonomy in determining land uses. We have not purchased any non-coal real estate for several years, and have never participated in real estate development.
Our investment portfolio consists of equity securities in publicly held companies and fixed income securities. These portfolios are managed by the management of Kentucky River Properties LLC. Our fixed income portfolio consists of investment-grade government securities with maturities no longer than one year.
Our investment portfolio is categorized into three types:
o trading securities;
o available-for-sale securities; and
o held-to-maturity securities.
We held no trading securities at December 31, 2002. Available-for-sale securities consist solely of equity securities at December 31, 2002. During 2002 the trading securities portfolio and substantially all of the available-for-sale portfolio was liquidated to finance the restructuring. The unrealized gains and losses in available-for-sale and held-to-maturity securities are only reported in earnings when securities are sold.
Operating, general and administrative costs and expenses related to our coal properties consist primarily of:
o salaries, benefits and other personnel costs;
o reserve exploration expenses;
o property taxes;
o office expenses;
o insurance; and
o accounting and legal fees.
As part of the restructuring, the Predecessor Company, transferred substantially all of its assets and liabilities, excluding the membership units it held in Kentucky River Properties LLC to Kentucky River Properties LLC.
Critical Accounting Policies
Our critical accounting policies are as follows:
Investment Mix
Investments comprised 54% of our total assets as of December 31, 2002 and comprised 65% and 82% of our total assets as of December 31, 2001 and December 31, 2000, respectively. As of December 31, 2002 our investment portfolio consists of U.S. treasury bills and equity securities of a publicly held company. As of December 31, 2001 and 2000 our investment portfolio consisted of fixed income securities and equity securities, primarily in publicly held companies, which have readily determinable market values. As funds become available, we assess the current market and our objectives and invest funds in light of other cash flow requirements.
Estimation of Mineral Reserves
Upon an initial purchase of property, our engineers estimate mineral reserves on the property and continue to monitor the amounts mined by our lessees. We compare estimates made by our engineers and our internal, on-site audits to the amounts reported by our lessees to ensure proper reporting of tonnage mined and payment of royalties. The mineral reserve estimates are utilized to compute cost depletion by the units of production method.
Results of Operations
Fiscal Year Ended December 31, 2002 Compared With Fiscal Year Ended December 31,
As is more fully discussed in this report on form 10-K, Part I, Item 1, Business, the Predecessor Company transferred substantially all of its assets and liabilities to the Successor Company on November 30, 2002. The Successor Company's results of operations subsequent to the transfer, the period from December 1, 2002 through December 31, 2002, are not comparable to the Predecessor's results of operations for the year ended December 31, 2001. For purposes of this Management's Discussion and Analysis, we have combined the actual results of operations for the Successor Company from December 1, 2002 through December 31, 2002 and the Predecessor Company from January 1, 2002 through November 30, 2002 operating results in order to present a meaningful comparative analysis of current and prior fiscal years operating results. The Successor Company from December 1, 2002 through December 31, 2002 and the Predecessor Company from January 1, 2002 through November 30, 2002 financial information are derived from the Consolidated Financial Statements.
The following table sets forth our revenues, operating expenses and operating statistics for the fiscal year ended December 31, 2002 compared with the fiscal year ended December 31, 2001.
Net Income. Net income was $20.3 million for the year ended December 31, 2002, as compared to $22.1 million for the year ended December 31, 2001, a decrease of $1.7 million, or 8%. The decrease is attributable to the gain on sale of revenue-producing properties in 2001 for which there was no comparable sale in 2002 offset by the related decrease in income taxes.
Revenues. Total revenues for the year ended December 31, 2002, were $32.4 million compared to $37.6 million for the year ended December 31, 2001, a decrease of $5.2 million, or 14%. The decrease is primarily attributable to the gain on sale of revenue-producing properties in 2001 for which there was no comparable sale in 2002 as well as the related decline, in 2002, in oil and gas revenues resulting from that sale late in 2001.
Coal royalty revenues for the year ended December 31, 2002, were $28.6 million for 13.3 million tons compared to $28.2 million for 13.0 million tons for the year ended December 31, 2001, an increase of $363,000, or 1%, and 259,000 tons, or 2%. During 2002, minimum royalties of $3.5 million for 2.0 million tons were received from a lessee for the previous four production years. These minimum royalties were not recognized as revenue in prior periods as collectability was not reasonably assured. Excluding this minimum royalty, royalty revenue and production were $25.1 million for 11.3 million tons, down 11% and 13%, respectively, for the year ended December 31, 2002 compared to the same 2001 period. Excluding this minimum royalty, realization increased to $2.23 per ton for the year ended December 31, 2002, up from $2.17 for the year ago period, an increase of 3%. Demand for coal, and as a result prices, stabilized during the last months of 2002 after falling throughout the year. Demand for coal was soft early in 2002 as a result of the mild winter of 2001-2002, and the utilities were working off stockpiles they had built up to avoid the shortages that occurred in the winter of 2001. As a result, many coal operators shut down mines or reduced production from existing mines. More recently, the unusually warm summer of 2002 and the very cold winter of 2002 caused the utilities' stockpiles to shrink, which resulted in a slightly higher demand for coal in the fourth quarter of 2002. The slightly higher realization per ton occurred despite sharply lower spot coal prices in early first half of 2002 relative to the same period in 2001, indicating that our lessees were able to increase some of the prices in their sales contracts during the period of higher prices in 2000 and 2001. Also realization increased toward the end of 2002 as a result of spot coal prices reaching their highest level since early 2002. We expect coal prices and demand for coal will continue to increase in 2003.
Rents and haulage were $2.3 million for the year ended December 31, 2002, compared to $1.8 million for the year ended December 31, 2001, an increase of $449,000, or 25%. The increase was due to an increase in haulage tonnage to 5.4 million tons for the year ended December 31, 2002, from 3.8 million tons for the year-ago period offset by a decrease in the realization to $.41 per ton in the same 2002 period from $.46 per ton for the year-ago period. The increase in haulage revenue and tonnage, as well as the decrease in haulage realization, is due primarily to minimum haulage of $269,000 for 1.3 million tons recognized in 2002 from a lessee for the past four years minimum haulage requirements. This revenue was not recognized in prior periods as collectability was not reasonably assured. Excluding this minimum haulage, haulage tonnage was 4.2 million tons with a realization of $.47 per ton, an increase of 365,000 tons, or 10%, and $.01 per ton, or 2%. Since haulage revenues are generated by the processing by our lessees of coal belonging to others, the tonnage fluctuates depending on the extent to which our lessees are mining inside or outside our property boundaries. Haulage is based in part on a percentage of the sales price, so like royalties, the realization is a function of price.
Oil and gas sales and royalties were $1.5 million for the year ended December 31, 2002, compared to $3.1 million for the year ended December 31, 2001, a decrease of $1.6 million, or 51%. The decrease is mainly attributable to the sale of substantially all of our oil and gas working interests during the fourth quarter of 2001 which was effective as of June 30, 2001. A decrease in prices early in 2002, especially for natural gas, also had an effect in the decline. During 2002, nine gross, or four net, new working interest gas wells came on-line and contributed 7% of the oil and gas revenue. We anticipate continuing to participate in gas drilling efforts during 2003 at a modest rate.
Expenses. Aggregate operating costs and expenses remained relatively flat at $6.5 million for the year ended December 31, 2002 and 2001, respectively. The increase in operating, general and administrative expenses was offset by the decrease in oil and gas operating expenses.
Operating, general and administrative expenses were $6.3 million for the year ended December 31, 2002 compared to $5.8 million for the year ended December 31, 2001, an increase of $502,000, or 9%. The increase is primarily attributable to the expenses associated with our restructuring transaction.
Oil and gas expenses were $183,000 for the year ended December 31, 2002, compared to $686,000 for the year ended December 31, 2001, a decrease of $503,000, or 73%. This decrease resulted from the sale of substantially all of our oil and gas working interests during the fourth quarter of 2001which was effective as of June 30, 2001. Our royalty interests bear no operating expenses other than severance taxes, so following the sale of the working interests, oil and gas expenses declined disproportionately more than oil and gas revenues for the year 2002. We expect oil and gas expenses to increase slightly in 2003 due to operating expenses related to new gas wells expected to be drilled.
Income from operations was $25.9 million for the year ended December 31, 2002, compared to $31.1 million for the year ended December 31, 2001, a decrease of $5.2 million, or 17%. The decrease is due primarily to the gain on sale of substantially all of our working interest oil and gas wells in 2001 for which there was no comparable sale in 2002. Further, the sale of those wells resulted in a decrease in oil and gas revenue offset by the slight increase in coal royalties and rents and haulage.
Other Income. Other income was $3.9 million for the year ended December 31, 2002, compared to $2.9 million for the year ended December 31, 2001, an increase of $1.0 million, or 33%. The difference is primarily the result of the change in unrealized security gains and losses offset by a reduction in realized gain on sale of securities.
Unrealized loss on investment in limited partnerships was $1,125 for the year ended December 31, 2002. There were no such losses recorded in 2001. This loss was a result of a decline in market value of the investment portfolio held by a limited partnership in which we are a partner.
There was no net unrealized gain or loss on trading securities for the year ended December 31, 2002, because the trading securities portfolio was liquidated during the first quarter 2002. By comparison, the net unrealized loss for the year ended December 31, 2001, was $5.0 million. During the year ended December 31, 2002, our trading securities portfolio was entirely liquidated and our available-for-sale securities portfolio was mostly liquidated, in order to reduce the Company's exposure to near-term market volatility in light of the need for liquid assets to finance the restructuring.
Interest and dividend income was relatively flat at $1.8 million for the year ended December 31, 2002, compared to the year ended December 31, 2001. Interest and divided income from portfolio investments decreased in 2002 due to the liquidation of our trading securities portfolio from which the proceeds were invested in short-term U.S. treasury bills. As those short-term U.S. treasury bills matured or were sold the proceeds were retained as cash and used to finance the restructuring. During December 2002 cash from the sale of membership units of the Successor Company was received and a portion of those proceeds was invested in U.S. treasury bills at year end. The decrease in investment portfolio interest and dividends was offset by interest received in 2002 from a lessee for four prior years' minimum royalty and haulage and related interest.
Gain on sale of assets was $2.4 million for the year ended December 31, 2002, compared to $2.3 million for the year ended December 31, 2001, an increase of $152,000, or 7%. Variations in gains on sale of land and improvements result from the irregular nature, in both size and timing, of such sales.
Other income, consisting mostly of sales of standing timber, was $563,000 for the year ended December 31, 2002, compared to $408,000 for the year ended December 31, 2001, an increase of $155,000, or 38%. Timber revenues fluctuate significantly from year to year, depending on a number of factors, including marketing conditions, weather, species mix and the level of harvesting in advance of surface mining operations.
Income Taxes. Income tax expense was $9.4 million (effective tax rate of 32%) for the year ended December 31, 2002, based on pretax income of $29.8 million as compared with $11.9 million (effective tax rate of 35%) for the year ended December 31, 2001, based on pretax income of $34.0 million for the year earlier period. The $2.5 million, or 21%, decrease was primarily due to the election of the S Corporation status for the Predecessor Company in the third quarter effective January 1, 2003 and the corresponding tax effect of oil and gas drilling costs as well as the tax effect of unrealized losses on trading securities from the December 31, 2001 reporting period. Additionally, as a result of the restructuring, the month of December 2002 net income is not taxed at the partnership level, therefore, no tax accrual was made for that month.
Fiscal Year Ended December 31, 2001 Compared With Fiscal Year Ended December 31,
The following table sets forth the Predecessor Company's revenues, operating expenses and operating statistics for the fiscal year ended December 31, 2001 compared with the fiscal year ended December 31, 2000.
Predecessor Company Year Ended December 31, ---------------------- 2000 2001 ------- ------- (in thousands, except average gross royalty data) Financial Highlights: Revenues: Coal royalties................................... $25,324 $28,233 Rents and haulage................................ 2,021 1,816 Oil and gas sales and royalties.................. 2,735 3,051 Gain on the sale of revenue-producing properties. -- 4,458 ------- ------- Total revenues............................... $30,080 $37,558 Expenses: Operating, general and administrative expenses... $ 5,301 $ 5,809 Oil and gas expenses............................. 943 686 ------- ------- Total expenses............................... $ 6,244 $ 6,495 ------- ------- Income from operations.............................. $23,836 $31,063
Other Income and Expense: Interest and dividend income..................... $ 2,287 $ 1,801 Gain on sale of securities....................... 7,772 3,441 Unrealized loss on trading securities............ (2,743) (4,983) Gain on sale of assets........................... 1,640 2,270 Interest expense................................. (14) -- Other income..................................... 587 408 ------- ------- Total other income........................... $ 9,529 $ 2,937 ------- ------- Income Before Income Taxes.......................... $33,365 $34,000 Income Taxes........................................ 11,634 11,931 ------- ------- Net Income.......................................... $21,731 $22,069 ======= ======= Operating Statistics: Coal: Royalty coal tons produced by lessees............ 12,690 12,665 Average gross royalties ($ per ton).............. $ 1.93 $ 2.21
Revenues. Total revenues for the year ended December 31, 2001 were $37.6 million compared to $30.1 million for the year ended December 31, 2000, an increase of $7.5 million, or 25%. The increase is primarily attributable to a $4.5 million gain on the sale of oil and gas properties. Coal royalty revenues for the year ended December 31, 2001 were $28.2 million compared to $25.3 million for year ended December 31, 2000, an increase of $2.9 million, or 11%. Over these same periods, production was flat at 12.7 million tons. Realization per ton increased to $2.21 per ton for the year ended December 31, 2001 compared to $1.93 for the year ended December 31, 2000. The higher realization reflects higher coal prices in 2001 compared to 2000.
Rents and haulage decreased to $1.8 million for the year ended December 31, 2001 from $2.0 million for the year earlier period. The decline was primarily due to a drop in haulage tonnage to 3.8 million tons from 5.0 million tons, partially offset by an increase in realization to $.46 per ton from $.39 per ton.
Oil and gas sales and royalties were $3.1 million for the year ended December 31, 2001 compared to $2.8 million for the year ended December 31, 2000. The increase is attributable to an increase in prices for natural gas and oil in 2001, partially offset by the sale of most of our working interests during the year. That sale closed on November 30, 2001, for $6.6 million, but included in the sale was all the related production from the wells after June 30, 2001. Our gain on the sale was $4.5 million ($2.7 million after-tax). We retained all of our royalty interests, but still expect our future oil and gas revenues to decline by more than 50% in 2002 as a result of the sale.
Expenses. Aggregate operating costs and expenses for the year ended December 31, 2001 were $6.5 million compared with $6.2 million for the year ended December 31, 2000, an increase of $251,000, or 4%. The increase in operating expenses primarily relates to an increase in operating, general and administrative expenses.
Operating general and administrative expenses increased to $5.8 million for the year ended December 31, 2001 compared to $5.3 million for the year ended December 31, 2000, an increase of $508,000 or 10%. The increase is partly attributable to increased personnel costs, and partly due to the expenses associated with the proposed restructuring transaction.
Oil and gas expenses decreased to $686,000 for the year ended December 31, 2001 from $943,000 for the year ended December 31, 2000, a decrease of $257,000 or 27%. This decrease resulted from the sale of the majority of our working interest production effective as of June 30, 2001.
Other Income. Other income decreased to $2.9 million for the year ended December 31, 2001 compared to $9.5 million for the year ended December 31, 2000, a difference of $6.6 million, or 69%. The difference is mainly the result of a decrease in gains on sales of securities and unrealized gains on securities.
Net unrealized loss on trading securities for the year ended December 31, 2001 was $5.0 million compared to a net unrealized loss for the previous year of $2.7 million, a difference of $2.2 million. The difference reflects the decline in overall portfolio performance for the year ended December 31, 2001 compared to the earlier year.
Gain on sale of securities decreased to $3.4 million for the year ended December 31, 2001 compared to $7.8 million for the year ended December 31, 2000, a decrease of $4.4 million.
The aggregate return for our equity portfolios of publicly traded securities for 2001 was a loss of 5.3%, compared to a loss of 11.9% for the S&P 500 index. The outperformance of our portfolios relative to the S&P is due to outperformance by one portfolio managed by a large cap, value oriented investment manager and by our internally managed portfolio, with returns of 6.1% and 3.1%, respectively. This was partially offset by a loss of 47.9% by a portfolio managed by a small cap, technology oriented manager.
During the fourth quarter we cancelled the investment management agreement with the small cap, technology oriented manager and liquidated approximately half of the portfolio, based on an assessment of the portfolio's performance, the outlook for the technology market and the expected future internal need for funds. Also during the fourth quarter we sold securities in the internally managed portfolio, generating $10.8 million in proceeds to reduce the exposure to market volatility in light of the expected future need for funds to finance our restructuring. We added no funds to the portfolios under outside management during the year, while adding $333,000 to the internally managed portfolio in the first quarter.
Our overall portfolio strategy is to buy stocks based on analysis of individual companies, either directly or through outside investment managers, for a long term holding period. We mitigate non-systematic risk by holding a large number of positions. Much of our portfolio turnover is driven by our liquidity needs.
Subsequent to year end, most of the equity portfolios were liquidated to reduce exposure to near-term market volatility in light of the projected need for liquid assets to finance the proposed restructuring.
Interest and dividend income decreased to $1.8 million for the year ended December 31, 2001 compared to $2.3 million for the year ended December 31, 2000. The reduction was primarily due to a decline in interest rates.
Gain on sale of assets increased to $2.3 million for the year ended December 31, 2001 compared to $1.6 million for the year ended December 31, 2000, an increase of $630,000. The increase reflects higher activity in the sales of non-coal real estate.
Other income, consisting mostly of sales of standing timber, decreased to $408,000 for the year ended December 31, 2001, compared to $587,000 for the year ended December 31, 2000, a decrease of $179,000 or 30%. Timber revenues fluctuate significantly from year to year, depending on a number of factors, including, market conditions, weather, species mix and the level of harvesting in advance of surface mining operations.
Income Taxes. Income tax expense was $11.9 million (effective tax rate of 35%) for the year ended December 31, 2001 based on pretax income of $34.0 million as compared with $11.6 million (effective tax rate of 34%) for the year ended December 31, 2000 based on pretax income of $33.4 million for that earlier period. The $300,000 increase was primarily due to the tax due on the gain from the sale of oil and gas interests and operating income, partially offset by decreases in other income.
Net Income. Net income was $22.1 million, for the year ended December 31, 2001 as compared to $21.7 million for the year ended December 31, 2000, an increase of $338,000, or 2%.
Liquidity and Capital Resources
Historically, we have generally satisfied our working capital requirements and funded our capital expenditures with cash generated from operations. We believe that cash generated from operations for at least the next several years will be sufficient to meet our working capital requirements and anticipated capital expenditures. Our ability to fund planned capital expenditures, to make acquisitions and to pay distributions to our investors will depend upon our future operating performance, which will be affected by prevailing economic conditions in the coal industry, and financial, business and other factors, some of which are beyond our control.
Cash Flows
Net cash provided by operating activities was $36.3 million in 2002, $16.2 million in 2001 and $27.0 million in 2000. The changes in cash provided by operating activities were largely due to changes in purchases and sales of securities. Securities transactions included in the net cash provided by operating activities totaled $20.3 million in 2002, $5.9 million in 2001 and $5.6 million in 2000. Cash provided by operating activities increased $20.1 million for the year ended December 31, 2002 as compared to the year ended December 31, 2001. The increase in cash provided by operating activities resulted from the $20.3 million effect of securities transactions offset by a decrease in net income, decrease in gain on sale of equipment, a decrease in income tax receivable, an increase in trade accounts receivable and an increase in other receivables and prepaid expenses. The decrease in gain on sale equipment was due to the 2001 sale of oil and gas working interest for which there was no comparable sale in 2002. The decrease in income tax receivable is due to an overpayment of federal income tax in 2001 that was applied toward 2002 tax liability. The increase in trade accounts receivable is due to an increase in average days outstanding of receivables due from a few lessees. We believe ultimate collectability is reasonably assured due to our preferred legal status with our lessees. The increase in other receivables and prepaid expenses is due to a receivable from the Predecessor resulting from the transfer of assets and liabilities from the Predecessor Company to the Successor Company. This receivable was collected in February 2003.
Cash provided by operating activities decreased $10.9 million for the year ended December 31, 2001 as compared to the year ended December 31, 2000. This decrease is a result of the gain on the sale of assets related to the sale of working interests in oil and gas wells of $4.5 million and a reduction in income tax receivable of $3.0 million included in cash provided by operating activities for the year ended December 31, 2001. For the year ended December 31, 2000, there was no comparable sale of asset and income tax receivable increased $2.2 million.
Net cash provided by investing activities was $23.5 in 2002, $19.6 million in 2001 and $19.0 million in 2000. The variation in cash provided or used in investing activities is mainly due to the variation in securities transactions and the 2001 sale of working interests in oil and gas wells. Securities transactions included in net cash provided by investing activities totaled $20.5 million in 2002, $10.9 million in 2001 and $15.4 million in 2000. Net cash provided by investing activities increased $3.9 million for the year ended December 31, 2002, as compared to the year ended December 31, 2001. The increase is the result of the net effect of the increase in securities transactions for 2002 as compared to 2001 offset by the proceeds from the sale of working interests in oil & gas wells included in 2001 for which there was no comparable sale of property and equipment in 2002. Additionally, proceeds from the sale of land and improvements and purchases of property and equipment increased in 2002 as compared to 2001.
Net cash provided by investing activities increased $651,000 for the year ended December 31, 2001as compared to the year ended December 31, 2000. The increase is due to the net effect of the proceeds from the sale of working interests in oil & gas wells included in 2001 for which there was no comparable sale of property and equipment in 2000 offset by the decrease in securities transactions for 2001 as compared to 2000. Additionally, the increase is offset by a decrease in proceeds from the sale of land and improvements for 2001 as compared to 2000.
Net cash used in financing activities was $74.8 million in 2002, $20.2 million in 2001 and $46.6 million in 2000. Financing activities primarily represent dividends, common stock repurchases by the Predecessor Company and, in 2002, the issuance of membership units of the Successor Company. Dividends paid were $14.3 in 2002, $14.6 million in 2001 and $12.8 million in 2000. Common stock repurchases were $86.0 million in 2002, $5.7 million in 2001 and $33.9 million in 2000. The current year repurchase of common stock of the Predecessor Company and the issuance of membership units of the Successor Company are due to the restructuring. In prior years, we repurchased common shares because we considered these repurchases a use of cash superior to holding short term, fixed rate equivalents and the repurchase provided additional liquidity for shareholders, especially for shareholders with larger blocks that otherwise might have been difficult to sell.
Net cash used in financing activities for the year ended December 31, 2002, was $74.8 million compared to $20.2 million for the comparable period for 2001. The increase of $54.6 million is primarily attributable to the purchase of all outstanding shares, 21,491, of the Predecessor Company's common stock owned by minority shareholders offset by the issuance of 6,007 the Successor Company's membership units. The Predecessor Company borrowed $3 million to finance payments for the Predecessor Company's common stock in the restructuring. This debt was repaid by the Successor Company using a portion of the proceeds received from the issuance of the membership units in December 2002. Additionally, $1.8 million was received in 2002 from the sale of common shares under the employee stock plan. Dividends paid were relatively flat at $14.3 million for the year ended December 31, 2002 compared to $14.6 million for the comparable period for 2001. Dividends were paid by the Predecessor Company to its shareholders. The Successor Company expects to pay distributions, rather than dividends, of its net income, as available, to its membership unit holders.
Net cash used in financing activities for the year ended December 31, 2001, was $20.2 million compared to $46.6 million for the comparable period for 2000, a decrease of $26.4 million. The decrease is due primarily to the reduction in treasury stock purchased in 2001 as compared to 2000. The decrease is offset by an increase in dividends paid for 2001of $14.6 million up from $12.8 million for 2000.
Capital Expenditures
Capital expenditures were $1.1 million in 2002, $581,000 in 2001 and $572,000 in 2000. The increase in capital expenditures for 2002 as compared to 2001 and 2000 was due primarily to the cost of new gas wells drilled. In 2002 eleven gross wells were drilled, five net wells, of which nine gross wells, four net wells, were producing at December 31, 2002. For each of these periods, we used cash generated from operations to fund capital expenditures. Our capital expenditures in each year were primarily made to acquire land and support equipment and facilities.
We anticipate that our average annual maintenance capital expenditures will be less than $1.0 million. Total capital expenditures, though, may increase, as we seek acquisitions of coal reserves and other strategic assets. We currently expect capital expenditures to be funded by cash generated by operations.
FORWARD-LOOKING STATEMENTS
In this report we present "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Act of 1934, as amended. The statements include those identified by such words as "may," "will," "expect," "anticipate," "believe," "plan," "project," "should," and other similar terminology. These forward-looking statements reflect our current expectations regarding future events and operating and financial performance and are based upon data available at the time of the statements. Although the Successor Company believes the assumptions underlying the forward-looking statements contained herein are reasonable, any of the assumptions could be inaccurate, and therefore, there can be no assurance the forward-looking statements included herein will prove to be accurate. Actual results involve risks and uncertainties, including both those specific to the Successor Company and those specific to the industry, and could differ materially from expectations. Factors that could cause actual results to differ from the results discussed in the forward-looking statements include, but are not limited to:
o the ability of our lessees to produce sufficient quantities of coal on an economic basis from our reserves, o the volatility of commodity prices for coal, o the financial condition of our primary lessees, o changes in fuel consumption patterns by electric power generators away from the use of coal, o competition among producers in the coal industry,
o ability of our lessees to enter into long-term supply contracts, o fluctuations in transportation costs and the availability or reliability of transportation of coal mined from our properties, o labor relations and costs, o the extent to which the amount and quality of coal our lessees are able to economically recover differs from estimated recoverable coal reserves, o the ability to replace or increase our reserves on satisfactory terms, o availability of cash from lessees to enable payment of distributions comparable to historic levels, o changes in governmental regulation or enforcement practices, especially with respect to mining environmental, health and safety matters, such as emissions levels applicable to electric power generators and steel manufacturers, and o economic and political conditions (including inflation and interest rates).
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk.
Market risk is the risk of loss arising from adverse changes in market rates and prices. We are primarily exposed to equity price, interest rate and coal price risks. The following is a discussion of our primary market risk exposures and how those exposures are managed.
Equity Price and Interest Rate Risk
Our market risk sensitive instruments are primarily corporate equity securities and U.S. Treasury securities. In addition to our investment portfolio, a limited partnership of which we are a partner owns an investment portfolio consisting primarily of privately traded equity securities. Our directly held corporate equity securities, classified as available-for-sale securities, and investment in limited partnerships are subject to price risk. U.S. Treasury securities are classified as held-to-maturity due to our intention and ability to hold the securities until maturity and are subject to interest rate risk.
In 2002, we began an orderly liquidation of our investment portfolio, excluding land and improvements, to finance the restructuring. As a result of the liquidation our investment portfolio, excluding land and improvements, decreased 68% compared to the value at December 31, 2001. We held no trading securities at December 31, 2002. Available-for-sale and held-to-maturity securities at December 31, 2002 consisted of $1.4 million in corporate equity securities and $17.9 million in short-term fixed maturity U.S. Treasury securities, respectively. Corporate equity securities that are managed internally are classified as available-for-sale. They are purchased because they represent a better risk/reward opportunity than cash equivalents or other short-term fixed-income securities for capital that we do not expect to use in our primary business for the intermediate term, roughly three to five years. A hypothetical 10% decline in the value of our corporate equity securities classified as available-for-sale would have resulted in a $137,400 decline in their value. We employ a buy-and-hold strategy and, consequently, do not monitor day-to-day market conditions. We periodically assess the performance of this portfolio and make adjustments to the holdings in this portfolio as needed. Our exposure to equity price risk for corporate equity securities classified as available-for-sale is currently limited to $1.4 million.
In 2002 we recognized an unrealized loss of $1.1 million on our investment in limited partnerships to more accurately reflect the market value of a partnership's investment portfolio. A hypothetical 10% decline in the value of our corporate equity securities held by a partnership in which we are a partner would have resulted in a $115,600 decline in their value. Our exposure to equity price risk for corporate equity securities of the investment in partnerships is currently limited to $1.2 million.
At December 31, 2002 the market risk to our portfolio of fixed maturity securities was primarily interest rate risk. We are subject to interest rate risk to the degree that our fixed maturity securities re-price with changes in interest rates. We manage interest rate risk by investing in fixed maturity securities with a short duration, usually less than one year. Our pricing model makes various estimates at each level of interest rate change regarding cash flows from interest collections and principal repayments. At December 31, 2002 a one percent increase in interest rates would have decreased the value of our fixed maturity securities by $45,700. Our current exposure to interest rate risk on our fixed maturity securities is minimal.
Coal Price Risk
Coal prices are influenced by a number of factors and vary dramatically by region. The two principal components of the delivered price of coal are the price of coal at the mine, which is influenced by mine operating costs and coal quality, and the cost of transporting coal from the mine to the point of use. Electricity generators purchase coal on the basis of its delivered cost per million Btu (British thermal unit).
In their December 2001 "Short Term Outlook" report, Energy Information Administration (EIA) noted that, "In the first half of this year, an unusual phenomenon occurred: for the first time in years, the monthly average price of coal to electric utilities increased notably. Due to pressures for coal substitution for expensive gas and also because of the very tight storage situation for coal at power generating stations, the price of coal jumped. However, by mid-summer the price began receding as coal stocks rebounded and as gas prices withered. Next year, coal prices should continue to recede as coal stocks gain and natural gas prices remain relatively low." As predicted, coal prices continued to recede throughout most of 2002. Toward the end of 2002 spot coal prices increased to their highest level since early 2002. We expect coal prices and demand to be higher in 2003 than that of 2002. Our expectation for 2003 is due to utilities' lower stockpiles of coal, continued unstable natural gas prices and increased oil prices as a result of perceived supply-side issues as a result of the Venezuelan (an OPEC member) general strike and continued oil sector strike and the war with Iraq. Per the EIA March 2003 "Short Term Outlook", "If the oil strike is prolonged and tensions in the Middle East
continue the chance of a [oil] price spike will remain high." We expect increased oil prices, along with the aforementioned factors, to have a direct correlation on coal prices and demand in the short-term.
In March 2003, prices for Central Appalachian coal futures for April 2003 delivery on the New York Mercantile Exchange ranged from $31.75 to $32.75 per ton. These prices reflect an increase from $4.30 to $4.75 per ton when compared to a similar, but not exact, period in 2002. In January 2002, prices for Central Appalachian coal futures for March 2002 delivery on the New York Mercantile Exchange ranged from $27.00 to $28.45 per ton, after peaking at $43.00 in August 2001. These coal futures contracts are representative of 12,500 Btu Central Appalachian coal.
The price of coal at the mine is influenced by geological characteristics such as seam thickness, overburden ratios and depth of underground reserves. It is generally cheaper to mine coal seams that are thick and located close to the surface than to mine thin underground seams. Typically, coal mining operations will begin at the part of the coal seam that is easiest and most economical to mine. In the coal industry, this surface mining characteristic is referred to as low ratio. As the seam is mined, it becomes more difficult and expensive to mine because the seam either becomes thinner or extends more deeply into the earth, requiring removal of more overburden. Underground mining is generally more expensive than surface mining as a result of high capital costs including costs for modern mining equipment and construction of extensive ventilation systems and higher labor costs, including costs for labor benefits and health care.
In addition to the cost of mine operations, the price of coal at the mine is also a function of quality characteristics such as heat value and sulfur, ash and moisture content. Metallurgical coal has higher carbon and lower ash content and is usually priced $4 to $10 per ton higher than steam coal produced in the same regions.
Coal used for domestic consumption is generally sold free on board at a loading point, and the purchaser normally pays the transportation costs. Export coal is usually sold at an export terminal, and the seller is responsible for shipment to the export coal loading facility while the purchaser pays the ocean freight.
Most electric power generators arrange long-term shipping contracts with rail or barge companies to assure stable delivery costs. Transportation cost can be a large component of the purchaser's cost. Although the customer pays the freight, transportation cost is still important to coal mining companies because the customer may choose a supplier largely based on the cost of transportation. Trucks and overland conveyors haul coal over shorter distances, while lake carriers and ocean vessels move coal to export markets. Some domestic coal is shipped over the Great Lakes. Railroads move more coal than any other product, and in 1999, coal accounted for 22% of total U.S. rail freight revenue and more than 44% of total freight tonnage. Railroads typically handle approximately 60% of U.S. coal production, with CSX and Norfolk Southern the dominant carriers in the eastern United States and Burlington Northern Santa Fe and Union Pacific the dominant carriers in the western United States.
Item 8.
Item 8. Financial Statements and Supplementary Data.
Page ----
Independent Auditors' Report 27
Consolidated Balance Sheets - Predecessor Company at December 31, 2001 and Successor Company at December 31, 2002 28
Consolidated Statements of Income - Predecessor Company for the years ended December 31, 2000 and 2001 and for the period from January 1, 2002 through November 30, 2002 and Successor Company for the period from December 1, 2002 through December 31, 2002 29
Consolidated Statements of Unitholders'/Stockholders' Equity and Comprehensive Income - Predecessor Company for the years ended December 31, 2000 and 2001 and for the period from January 1, 2002 through November 30, 2002 and Successor Company for the period from December 1, 2002 through December 31, 2002 30
Consolidated Statements of Cash Flows - Predecessor Company for the years ended December 31, 2000 and 2001 and for the period from January 1, 2002 through November 30, 2002 and Successor Company for the period from December 1, 2002 through December 31, 2002 31
Notes to Consolidated Financial Statements 32
Independent Auditors' Report
The Board of Directors and Unitholders Kentucky River Properties LLC:
We have audited the accompanying consolidated balance sheet of Kentucky River Properties LLC and subsidiaries (the Company) as of December 31, 2002, and the related consolidated statements of income, unitholders' equity and comprehensive income, and cash flows for the period from December 1, 2002 through December 31, 2002 (Successor Period), and the consolidated statements of income, stockholders' equity and comprehensive income, and cash flows for the period from January 1, 2002 through November 30, 2002 (Predecessor Period) of Kentucky River Coal Corporation and subsidiaries (the Predecessor). Further, we have audited the accompanying consolidated balance sheet of Kentucky River Coal Corporation and subsidiaries as of December 31, 2001, and the related consolidated statements of income, stockholders' equity and comprehensive income, and cash flows for the years ended December 31, 2001 and 2000. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated 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, the aforementioned Company consolidated financial statements referred to above present fairly, in all material respects, the financial position of Kentucky River Properties LLC and subsidiaries as of December 31, 2002 and the results of their operations and their cash flows for the Successor Period, in conformity with accounting principles generally accepted in the United States of America. Further, in our opinion, the aforementioned Predecessor consolidated financial statements present fairly, in all material respects, the financial position of Kentucky River Coal Corporation and subsidiaries as of December 31, 2001, and the results of their operations and their cash flows for the Predecessor Period and for the years ended December 31, 2001 and 2000, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 1 to the consolidated financial statements, on November 30, 2002, the Predecessor Company transferred to Kentucky River Properties LLC substantially all of its assets and liabilities, except for membership units in Kentucky River Properties LLC, and Kentucky River Properties LLC became the operating company.
/s/ KPMG LLP
Louisville, Kentucky March 7, 2003
See accompanying notes to consolidated financial statements.
See accompanying notes to consolidated financial statements.
See accompanying notes to consolidated financial statements.
See accompanying notes to consolidated financial statements.
KENTUCKY RIVER Properties llc AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2001 and 2002
(In thousands, except share data)
(1) Description of the Business and Summary of Significant Accounting Policies
(a) Business
Kentucky River Properties LLC (the Successor Company), and Kentucky River Coal Corporation (the Predecessor Company) prior to the restructuring, and its subsidiaries are primarily engaged in leasing mineral reserves and, to a lesser degree, participating in partnerships and joint ventures which explore for and develop oil and gas properties. The majority of the Successor Company's revenue-producing properties are located in Eastern Kentucky.
On February 14, 2002, Kentucky River Properties LLC was formed. On March 1, 2002, the Predecessor Company filed a registration statement with the Securities and Exchange Commission relating to the proposed corporate restructuring of the Predecessor Company to convert to S Corporation status. On June 10, 2002, the registration statement, initially filed on March 1, 2002, became effective.
On July 29, 2002, at a special shareholders' meeting, the shareholders of the Predecessor Company approved the restructuring. Pursuant to the restructuring, on July 31, 2002, each minority share of the Predecessor Company was converted into the right to receive $4 in cash and a subscription right to subscribe for one Kentucky River Properties, LLC membership unit at an exercise price of $4 per membership unit. A minority share of the Predecessor Company is a share held by a shareholder who did not qualify to become a shareholder of the S Corporation. On July 31, 2002, 21,491 minority shares were converted resulting in an obligation to minority shareholders of $85,964. As of December 31, 2002, the obligation to minority shareholders was $311 for 46 minority shares not surrendered for payment.
On November 30, 2002, the Predecessor Company transferred (the Transfer) to Kentucky River Properties LLC substantially all of its assets and liabilities, except for membership units in Kentucky River Properties LLC, and Kentucky River Properties LLC became the operating company for the business of the Predecessor Company. In return the Predecessor Company received 40,414 membership units of Kentucky River Properties LLC. The number of membership units received by the Predecessor Company is the number of Predecessor Company shares held by the Predecessor Company majority shareholders prior to the restructuring. The assets and liabilities transferred at historical cost by the Predecessor Company to Kentucky River Properties LLC and the Predecessor Company's Investment in Kentucky River Properties LLC immediately after the transfer, which totaled $21,895 at November 30, 2002, are detailed as follows:
Investments: Available-for-sale securities...................................... $ 7,186 Land and improvements.............................................. 3,005 -------- Total investments................................................ 10,191 -------- Cash and cash equivalents........................................... 4 -------- Other assets: Accounts receivable--trade......................................... 5,475 Investment in limited partnerships................................. 2,323 Other receivables and prepaid expenses............................. 1,981 -------- Total other assets............................................... 9,779 -------- Properties and equipment: Land and revenue-producing properties.............................. 11,932 Buildings and equipment............................................ 2,753 Less accumulated depletion and depreciation........................ (9,788) -------- Properties and equipment, net.................................... 4,897 -------- Current liabilities: Accounts payable and accrued expenses.............................. (198) Note payable....................................................... (3,000) -------- Total current liabilities........................................ (3,198) --------
Net transferred to Kentucky River Properties LLC from Predecessor Company on November 30, 2002....................................... 21,673 Predecessor Company initial investment in Kentucky River Properties LLC..................................................... 250 Predecessor Company equity in earnings of Kentucky River Properties LLC for the period January 1, 2002 through November 30, 2002.................................................. (28) -------- Predecessor Company investment in Kentucky River Properties LLC at November 30, 2002............................................... $21,895 ========
On December 1, 2002, the subscription rights for Kentucky River Properties LLC membership units became exercisable and remained exercisable for a 30-day period. The subscription rights expired on December 30, 2002. As of December 31, 2002, 6,007 membership units had been exercised and were outstanding in addition to the 40,414 membership units held by the Predecessor Company resulting in a total of 46,421 Kentucky River Properties LLC membership units outstanding.
As a result of the Successor Company assuming operations of the Predecessor Company as of the date of the Transfer, the financial statements presented herein reflect the financial statements of the Successor Company as of December 31, 2002, and for the period December 1 through December 31, 2002 (the Successor Period). Also the financial statements reflect the financial statements of the Predecessor Company as of December 31, 2001, and for the period January 1 through November 30, 2002 (the Predecessor Period) and for the years ended December 31, 2001 and 2000, respectively.
(b) Consolidation Practice
The accompanying Successor Company's consolidated financial statements include the accounts of Kentucky River Properties LLC, KRCC Oil & Gas LLC (KRCC Oil and Gas), and Timberlands LLC. The accompanying Predecessor Company's consolidated financial statements include the accounts of those companies as well as Kentucky River Coal Corporation. On November 30, 2002, KRCC Oil & Gas LLC and Timberlands LLC were transferred to Kentucky River Properties LLC as a result of the Transfer. The following companies were merged into Kentucky River Coal Corporation in 2002 prior to the Transfer: Florida Kentucky Timberlands, Inc., The Kent-Mar Corporation, and Tennis Capital, Inc. All significant intercompany accounts and transactions have been eliminated.
(c) Investment Securities
Investment securities consist of U.S. Treasury and equity securities. The Predecessor and Successor Companies classify their debt and equity securities in one of three categories: trading, available-for-sale, or held-to-maturity. Trading securities are bought and held principally for the purpose of selling them in the near term. Held-to-maturity securities are those securities in which the Predecessor and Successor Companies have the ability and intent to hold the security until maturity. All securities not included in trading or held-to-maturity are classified as available-for-sale.
Trading and available-for-sale securities are recorded at fair value. Held-to-maturity securities are recorded at amortized cost, adjusted for the amortization or accretion of premiums or discounts. Unrealized holding gains and losses on trading securities are included in earnings. Unrealized holding gains and losses, net of the related tax effect prior to the Transfer, on available-for-sale securities are reported as a separate component of comprehensive income. Realized gains and losses from the sale of available-for-sale securities are determined on a specific identification basis.
A decline in the market value of any available-for-sale or held-to-maturity security below cost that is deemed to be other than temporary results in a reduction in carrying amount to fair value. The impairment is charged to earnings and a new cost basis for the security is established. Premiums and discounts are amortized or accreted over the life of the related held-to-maturity or available-for-sale security as an adjustment to yield using the effective interest method. Dividend and interest income are recognized when earned.
(d) Investment in Land and Improvements
Land and improvements are stated at cost.
(e) Land and Revenue-Producing Properties, Buildings, and Equipment
The investment in land and revenue-producing properties is stated at the lower of cost or estimated realizable value. Buildings and equipment are stated at cost. Depreciation is computed principally on the straight-line method over the estimated useful lives of depreciable assets. Cost depletion is computed on the units-of-production method based on mineral reserves as determined by the Successor Company's engineers.
(f) Oil and Gas Operations
KRCC Oil and Gas participates in partnerships and joint ventures which explore for and develop oil and gas properties. The successful efforts method of accounting is followed for costs incurred in oil and gas exploration and development operations. Capitalized costs are amortized by the units-of-production method based on estimated proven reserves.
(g) Royalties
Royalties, rents and haulage and oil and gas sales are recorded in the month coal is mined or oil and gas is produced. Certain of the Successor Company's leases may require lessees to pay a minimum royalty if minimum tonnage is not mined during the year. These royalties are based upon a specified minimum tonnage and the greater of a fixed dollar per ton or a percentage of the sales price and can generally be recouped by the lessee over the succeeding five years against future royalties that exceed the minimum. Minimum royalties are recognized when received and are offset by recoupments as such recoupments occur. For the period December 1, 2002 through December 31, 2002 (Successor Period) minimum royalties included in income of the Successor Company were $1,205. For the period January 1, 2002 through November 30, 2002 (Predecessor Period) and for the years ended December 31, 2001, and 2000, minimum royalties included in income were $3,494, $603, and $455, respectively. Minimum royalties potentially recoupable amount to $5,636. Such amount will expire within the next five years in the amounts of $1,466, $1,064, $594, $1,304, and $1,208, respectively.
(h) Common Stock
The excess of the purchase price over the par value of the Predecessor Company's common stock which has been purchased for constructive retirement is charged to retained earnings.
(i) Cash Equivalents
Cash equivalents consist of overnight repurchase agreements and certificates of deposit with an initial term of less than three months. For purposes of the consolidated statements of cash flows, the Company considers all highly liquid debt instruments with original maturities of three months or less to be cash equivalents. The Company has cash accounts insured by the Federal Deposit Insurance Corporation up to $100. At December 31, 2001 the Predecessor Company's uninsured cash balances total approximately $2,500. At December 31, 2002 the Company's uninsured cash balances total approximately $4,700.
(j) Income Taxes
The Successor Company is considered a partnership for tax purposes. Accordingly, no income taxes, deferred or current, are recognized for the partnership.
The Predecessor Company's income taxes were accounted for under the asset and liability method. Deferred tax assets and liabilities were recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities were measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
(k) Net Income Per Share
Kentucky River Properties LLC's basic net income per membership unit is based upon the weighted average number of membership units outstanding during the Successor Period. Dilutive earnings per membership unit takes into account the dilutive effect of membership unit equivalents, such as membership unit options. There were no dilutive items outstanding during the Successor Period, therefore, basic and dilutive membership units are 43,765 for the Successor Period.
The Predecessor Company's basic net income per share is based on the weighted average number of common shares outstanding of 66,937 and 61,790 shares for the years ended December 31, 2000 and 2001, respectively, and 53,893 shares for the Predecessor Period. Dilutive earnings per share takes into account the dilutive effect of common stock equivalents, such as stock options.
(l) Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
(m) Stock Option Plan
Prior to January 1, 1996, the Predecessor Company accounted for its stock option plan in accordance with the provisions of Accounting Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. As such, compensation expense would be recorded on the date of grant only
if the current market price of the underlying stock exceeded the exercise price. On January 1, 1996, the Predecessor Company adopted Statement of Financial Accounting Standards (SFAS) No. 123, Accounting for Stock-Based Compensation, which permits entities to recognize as expense over the vesting period the fair value of all stock-based awards on the date of grant. Alternatively, SFAS No. 123 also allows entities to continue to apply the provisions of APB Opinion No. 25 and provide pro forma net income and pro forma earnings per share disclosures for employee stock option grants made in 1995 and future years as if the fair-value-based method defined in SFAS No. 123 had been applied. The Predecessor Company has elected to continue to apply the provisions of APB Opinion No. 25 and provide the pro forma disclosure provisions of SFAS No. 123. All options were exercised in the current year prior to the S-corp restructuring. The stock option plan of the Predecessor Company terminated as a result of the restructuring.
(n) Comprehensive Income
Statement of Financial Accounting Standards No. 130, Reporting Comprehensive Income establishes standards for reporting and presentation of comprehensive income and its components in a full set of financial statements. Comprehensive income consists of net income and net unrealized gains (losses) on securities and is presented in the consolidated statements of unitholders'/stockholders' equity and comprehensive income. The Statement requires only additional disclosures in the consolidated financial statements; it does not affect the Successor or Predecessor Company's financial position or results of operations.
(o) Recently Issued Accounting Standards
In November 2002, the Financial Accounting Standards Board (FASB) issued Interpretation No. 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others, an interpretation of FASB Statements No. 5, 57 and 107 and a rescission of FASB Interpretation No. 34. This Interpretation elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees issued. The Interpretation also clarifies that a guarantor is required to recognize, at inception of a guarantee, a liability for the fair value of the obligation undertaken. The initial recognition and measurement provisions of the Interpretation are applicable to guarantees issued or modified after December 31, 2002 and are not expected to have a material effect on the Company's consolidated financial statements. The disclosure requirements are effective for financial statements of interim or annual periods ending after December 15, 2002.
(2) Concentration of Credit Risk
The Predecessor Company received approximately 52% and 51% for the years ended December 31, 2000 and 2001, respectively, and 49% for the Predecessor Period of its coal royalties from two lessees. The Successor Company received approximately 22% of its coal royalties for the Successor Period from two lessees.
Successor Predecessor Company Company ------------------- --------- For the For the Period Period January December For the 1, 2002 1, 2002 Year Ended through through December 31, November December 2000 2001 30, 2002 31, 2002 ---- ---- -------- -------- Lessee A.......................... 25% 23% 27% 11% Lessee B.......................... 27% 28% 22% 11% -- -- -- -- Total.......................... 52% 51% 49% 22% == == == ==
Lessee A filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code on February 28, 2002 and November 13, 2002, respectively. In the opinion of management, the coal royalties under this lease may decrease.
(3) Securities
The change in net unrealized holding losses on trading securities that has been included in net income is $2,743 and $4,983 in 2000 and 2001, respectively, $0 for the Predecessor Period, and $0 for the Successor Period.
The amortized cost and approximate fair value of securities and the gross unrealized gains and losses at December 31, 2001 and 2002 follow:
Predecessor Company -------------------------------------- Unrealized ------------ Amortized cost Gains Losses Fair value -------------- ----- ------ ---------- Available-for-sale securities-- Corporate equity securities... $10,947 2,223 199 12,971 Corporate bonds............... 5,503 130 4 5,629 U.S. Treasury securities...... 754 -- -- 754 ------- ----- --- ------ $17,204 2,353 203 19,354 ======= ===== === ====== Held-to-maturity securities-- U.S. Treasury securities...... $20,552 163 3 20,712 ======= ===== === ======
Successor Company -------------------------------------- Unrealized ------------ Amortized cost Gains Losses Fair value -------------- ----- ------ ---------- Available-for-sale securities-- Corporate equity securities... $ 873 501 -- 1,374 ======= ===== === ====== Held-to-maturity securities-- U.S. Treasury................. $17,948 -- 3 17,945 ======= ===== === ======
A summary of the Successor Company's debt securities as of December 31, 2002 based on contractual maturities follows. Expected maturities may differ from contractual maturities because the issuers may have the right to call or prepay obligations with or without call or prepayment penalties.
Amortized cost Fair value -------------- ---------- Due within one year U.S. Treasury securities.................. $17,948 17,945
Due after one year through five years U.S. Treasury securities.................. -- -- ------- ------ $17,948 17,945 ======= ======
All held-to-maturity securities as of December 31, 2002 will mature on April 3, 2002.
Proceeds from the sale of available-for-sale securities were $20,192 and $20,966 in 2000 and 2001, respectively, $36,390 for the Predecessor Period, and $0 for the Successor Period.
Gross realized gains on sales of available-for-sale securities were $0 and $2,629 in 2000 and 2001, respectively, $1,952 for the Predecessor Period and $0 for the Successor Period. Gross realized losses on sales of available-for-sale securities were $235 and $25 in 2000 and 2001, respectively, $441 for the Predecessor Period and $0 for the Successor Period.
(4) Income Taxes
Total income taxes were allocated as follows:
Successor Predecessor Company Company ---------------------------- -------- For the For the Period Period January December For the 1, 2002 1, 2002 Year Ended through through December 31, November December 2000 2001 30, 2002 31, 2002 -------- -------- -------- -------- Income from continuing operations... $ 11,634 $ 11,931 $ 9,409 $ -- Stockholders' equity, for unrealized holding gain (loss) on debt and equity securities recognized for financial reporting purposes............................ 1,219 (626) (536) -- -------- -------- -------- -------- $ 12,853 $ 11,305 $ 8,873 $ -- ======== ======== ======== ========
Income tax expense (benefit) attributable to pretax income consists of:
Current Deferred Total ------- -------- ------ Predecessor Company:
Year ended December 31, 2000: U.S. Federal......................................... $11,895 (1,442) 10,453 State and local...................................... 1,177 4 1,181 ------- ------ ------ $13,072 (1,438) 11,634 ======= ====== ====== Year ended December 31, 2001: U.S. Federal......................................... $12,353 (2,085) 10,268 State and local...................................... 1,721 (58) 1,663 ------- ------ ------ $14,074 (2,143) 11,931 ======= ====== ====== Period January 1 through November 30, 2002: U.S. Federal......................................... $ 9,325 (1,056) 8,269 State and local...................................... 1,233 (93) 1,140 ------- ------ ------ $10,558 (1,149) 9,409 ======= ====== ====== Successor Company:
Period December 1 through December 31, 2002: U.S. Federal......................................... $ -- -- -- State and local...................................... -- -- -- ------- ------ ------ $ -- -- -- ======= ====== ======
Income tax expense differed from the expected amounts computed by applying the U.S. Federal income tax rate of 35% to pretax income as a result of the following:
Successor Predecessor Company Company ---------------------------- -------- For the For the Period Period January December For the 1, 2002 1, 2002 Year Ended through through December 31, November December 2000 2001 30, 2002 31, 2002 -------- -------- -------- -------- Computed "expected" tax expense......... $ 11,678 11,900 9,907 -- Increase (reduction) in income taxes resulting from: Excess percentage depletion over cost depletion............................ (827) (905) (798) -- State and local income taxes, net of Federal income tax benefit........... 765 1,119 801 -- Other, net.............................. 18 (183) (501) -- -------- -------- -------- -------- $ 11,634 11,931 9,409 -- ======== ======== ======== ========
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2001 and 2002 are presented below:
Predecessor Successor Company Company 2001 2002 ----------- --------- Deferred tax assets: Geological and geophysical, net of amortization...... $ 3 -- Proven properties, net of depletion.................. 18 -- ----------- --------- Total gross deferred tax assets 21 -- ----------- --------- Deferred tax liabilities: Intangible drilling costs, net of impairment reserves and depletion.............................. (199) -- Tangible drillings costs, net of impairment reserves and depreciation........................... (5) -- Trading securities market value...................... (966) -- Available-for-sale securities market value........... (764) -- ----------- --------- Total gross deferred tax liabilities (1,934) -- ----------- --------- $ (1,913) -- =========== =========
(5) Earnings Per Share/Unit
The following data details the amounts used in computing earnings per membership unit and share and the effect on income and the weighted average number of units/shares of dilutive potential membership units/common stock.
Successor Predecessor Company Company ---------------------------- -------- For the For the Period Period January December For the 1, 2002 1, 2002 Year Ended through through December 31, November December 2000 2001 30, 2002 31, 2002 -------- -------- -------- -------- Net income attributable to unitholders/ shareholders for basic and diluted earnings per unit/share................$ 21,731 22,069 18,897 1,445 ======== ======== ======== ======== Weighted average number of membership units/common shares used in basic earnings per unit/share................ 66,937 61,790 53,893 43,767 Effect of dilutive securities: Stock options.......................... 45 77 25 -- -------- -------- -------- -------- Weighted number of membership units/ common shares and dilutive potential membership units/common shares used in diluted earnings per unit/share..... 66,982 61,867 53,918 43,767 ======== ======== ======== ========
(6) Benefit Plans
The Successor Company has a defined benefit pension plan (the Plan) which covers substantially all employees who have met certain requirements as to age and length of service. The Plan's benefit formula generally bases payments to retired employees upon 2% of the final average compensation multiplied by the number of years of service. The Successor Company makes annual contributions to the Plan equal to the maximum amount that can be deducted for income tax purposes.
The following table sets forth the Plan's fair value of plan assets, benefit obligations and funded status at December 31, 2000, 2001, and 2002:
Predecessor Predecessor Successor Company Company Company 2000 2001 2002 ----------- ----------- --------- Fair value of plan assets at December 31..$ 7,645 7,909 7,486 Benefit obligation at December 31......... (3,669) (3,752) (5,374) ----------- ----------- --------- Funded status $ 3,976 4,157 2,112 =========== =========== =========
Prepaid benefit cost..................... $ 798 1,087 1,326
Weighted average assumptions as of December 31: Discount rate........................ 7.50% 7.50% 6.75% Expected return on plan assets....... 7.50 7.50 7.50 Rate of compensation increase........ 6.00 6.00 6.00
Benefit cost............................. $ (203) (289) (239) Employer contribution.................... -- -- -- Plan participants' contribution.......... -- -- -- Benefits paid............................ 475 237 50
The following table sets forth the Plan's change in benefit obligations and plan assets for the years ended December 31, 2000, 2001, and, 2002:
Predecessor Predecessor Successor Company Company Company 2000 2001 2002 ----------- ----------- --------- Change in benefit obligation: Benefit obligation at beginning of year $ 3,133 3,669 3,752 Service cost......................... 291 171 256 Interest cost........................ 232 271 250 Benefits paid........................ (475) (237) (50) Actuarial loss (gain)................ 488 (122) 1,166 ----------- ----------- --------- Benefit obligation at end of year...... $ 3,669 3,752 5,374 ----------- ----------- --------- Change in plan assets: Fair value of plan assets at beginning of year.............................. 7,245 7,645 7,909 Actual return on plan assets....... 875 501 (373) Benefits paid...................... (475) (237) (50) ----------- ----------- --------- Fair value of plan assets at end of year................................. $ 7,645 7,909 7,486 =========== =========== =========
In addition, the Successor Company sponsors a deferred profit sharing plan. Contributions by the Predecessor Company were $125 and $129 in 2000 and 2001, respectively, and $101 for the Predecessor Period. Contributions by the Successor Company to this plan were $12 for the Successor Period.
In 1980, the Predecessor Company adopted a stock option plan (the Plan) for eligible employees. The Plan provided for granting of stock options to purchase shares of common stock at an exercise price equal to the fair value of the stock on the day the option is granted. Options were exercisable for a two-year period beginning on the date of grant. All options were exercised in the current year prior to the restructuring. The Successor Company does not have a stock option plan.
The fair value of each option was estimated on the date of grant using the minimum value method (excluding a volatility assumption) with the following weighted average assumptions: 2000 - expected dividend yield 6.6%, risk-free interest rate of 5.12%, and an expected life of 2 years; 2001 - expected dividend yield 7.31%, risk-free interest rate of 3.21%, and an expected life of 2 years.
The Predecessor Company applies APB Opinion No. 25 in accounting for the Plan and, accordingly, no compensation cost has been recognized for its stock options in the financial statements. Had the Predecessor Company determined compensation cost based on the fair value at the grant date for its stock options under SFAS No. 123, the Predecessor Company's net income would have been reduced to the pro forma amounts indicated below:
2000 2001 2002 ----------- ----------- --------- Net income: As reported............................ $ 21,731 22,069 18,897 Pro forma.............................. 21,146 21,875 --
Stock option activity during the periods indicated is as follows:
Weighted average Number exercise shares price -------- -------- Predecessor Company: Balance at December 31, 1999........... 646 $ 2,915 Granted.............................. 352 2,850 Expired.............................. (320) 2,900 Exercised............................ (16) 2,850 -------- -------- Balance at December 31, 2000........... 662 2,890 Granted.............................. 339 2,850 Expired.............................. (336) 2,925 Exercised............................ (33) 2,890 -------- -------- Balance at December 31, 2001........... 632 2,850 Granted.............................. -- -- Expired.............................. (3) 2,930 Exercised............................ (629) 2,850 -------- -------- Balance at November 30, 2002........... -- $ -- ======== ======== Successor Company: Balance at December 1, 2002............ -- $ -- Granted.............................. -- -- Expired.............................. -- -- Exercised............................ -- -- -------- -------- Balance at December 31, 2002........... -- $ -- ======== ========
At December 31, 2000 and 2001, respectively, the number of options exercisable was 662 and 632. At November 30, 2002, the end of the Predecessor Period, and at December 31, 2002, the end of the Successor Period, there were no options exercisable. The weighted average exercise price of these options was $2,890 and $2,850, for 2000 and 2001, respectively.
(7) Fair Value of Financial Instruments
The following table presents the carrying amounts and estimated fair values of the Successor Company's and the Predecessor Company's financial instruments at December 31, 2001 and 2002, respectively. The fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties.
The carrying amounts shown in the table are included in the balance sheets under the indicated captions.
The following methods and assumptions were used to estimate the fair value of each class of financial instruments:
Cash and cash equivalents, Other assets, and Accounts payable, Accrued expenses, and Income taxes payable - The carrying amounts approximate fair value due to the short maturity of those instruments.
Investment Securities - The fair values of debt securities (trading, available-for-sale and held-to-maturity securities) and equity investments are based on quoted market prices at the reporting date for those or similar investments.
Investment in limited partnerships - The fair values of equity securities owned by the limited partnerships are based on fair values reported to us by the partnership as of September 30, 2002. These securities are privately traded.
(8) Sale of Revenue - Producing Properties
In 2001, the Predecessor Company sold oil wells, with a cost basis of $2,953, resulting in a gain of $4,458.
(9) Related Party Transactions
At December 31, 2002, a $2.2 million affiliated receivable is reported on the face of the Successor Company's December 31, 2002 balance sheet. The receivable balance includes $1.9 million due from the Predecessor Company related to the November 30, 2002 transfer of assets and liabilities from the Predecessor Company to Successor Company as a result of the restructuring. Also included in that affiliated receivable balance are amounts for various expense items paid by the Successor Company on behalf of the Predecessor Company offset by amounts paid by the Predecessor Company on behalf of the Successor Company. Specifically, during the month of December 2002 the Successor Company paid, on behalf of the Predecessor Company, $442,000 of expenses incurred before the transfer date in the normal course of business. This amount is properly excluded from the expenses reported in the income statement of the Successor Company. Also, included in the affiliated receivable total is an offset of $176,000 for December 2002 employee compensation paid by the Predecessor Company, on behalf of the Successor Company. The $176,000 is properly included in Operating, General and Administrative expense of the Successor Company.
(10) Commitments and Contingencies
In 1996, the Predecessor Company committed to fund $3,000 in capital contributions to a limited partnership formed for the purpose of investing in various companies. The commitment period has a term of five years and, as of December 31, 2002, $2,911 had been advanced to the limited partnership. The commitment and the investment were transferred to the Successor Company on November 30, 2002 as a result of the Transfer. The balance at December 31, 2002 of $1,138 is included in other assets - investment in limited partnerships in the consolidated financial statements.
In 2001, the Predecessor Company committed to fund $2,000 in capital contributions to another limited partnership formed for the purpose of investing in various companies. The commitment and the investment were transferred to the Successor Company on November 30, 2002 as a result of the Transfer. In January 2003, the Successor Company elected to reduce its commitment to $1,500 effective March 15, 2003. The commitment period
has a term of five years and, as of December 31, 2002, $20 had been advanced to the limited partnership. The balance at December 31, 2002 was $18 and is included in other assets - investment in limited partnerships in the consolidated financial statements.
The Successor Company is involved in various claims and legal actions arising in the ordinary course of business. In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the Successor Company's consolidated financial position, results of operations or cash flows.
On August 2, 2002, the Predecessor Company entered into a financing arrangement, pursuant to a March 2002 commitment letter that permitted the Predecessor Company, or the Successor Company subsequent to the Transfer, to borrow up to $20,000 at one month LIBOR plus 2.25%. The Predecessor Company, or the Successor Company subsequent to the Transfer, must retain $1,000 in an account with its lender as a compensating balance. No amounts are outstanding on this line as of December 31, 2002. In January 2003 the Successor Company terminated the financing agreement.
Item 9.
Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure.
Not applicable.
PART III
Item 10.
Item 10. Managers and Executive Officers of the Registrant.
Our managers and executive officers as of March 24, 2003 are listed below. Our board of managers is classified into three classes with terms expiring in 2005, 2006 and 2007, respectively. Our executive officers are elected annually.
RUTHEFORD B. CAMPBELL, JR. was appointed to our board on October 16, 2002 and was a member of Kentucky River Coal Corporation's (Predecessor Company) board from 1990 until he resigned October 16, 2002. His current term expires in 2006. He is the Chairman of our Audit Committee and a member of our Compensation Committee. Mr. Campbell has been a professor at the University of Kentucky College of Law for more than five years and served as Dean from 1988 until 1993. He is also Of Counsel at Stoll, Keenon & Park LLP, one of the law firms that serve as our outside counsel.
CATESBY W. CLAY was appointed to our board on February 14, 2002 and his current term expires in 2005. He is also a member of Kentucky River Coal Corporation's (Predecessor Company) board and has been since 1949. He is also a member of our Executive Committee. Mr. Clay served as our President and Chief Executive Officer of Kentucky River Coal Corporation until May 1989 and has since been retired. He is a Director Emeritus of Churchill Downs, Inc. Mr. Clay is the uncle of James G. Kenan III.
GARY I. CONLEY has served as Executive Vice President and General Counsel since he was appointed to our board on February 14, 2002. His current term expires in 2006. He was a member of Kentucky River Coal Corporation's (Predecessor Company) board from February 1996 until he resigned October 16, 2002. At Kentucky River Coal Corporation he has served as Executive Vice President and General Counsel since May 1999. From May 1989 until May 1999 he served as Vice President and General Counsel. From January 1987 until May 1989 he was General Counsel. Prior to joining Kentucky River Coal Corporation in 1980, Mr. Conley worked as an attorney in private practice.
CARROLL R. CROUCH has served as Treasurer since February 14, 2002. He has served as Treasurer for Kentucky River Coal Corporation (Predecessor Company) since May 1999 and as Secretary since May 1996. Prior to joining Kentucky River Coal Corporation in 1985, Mr. Crouch worked as a certified public accountant from 1977 to 1985.
ROBERT L. FRANTZ was appointed to our board on October 16, 2002 and was a member of Kentucky River Coal Corporation's (Predecessor Company) board from 1992 until he resigned October 16, 2002. His current term expires in 2006. He is a member of both our Audit and Compensation Committees. Mr. Frantz was professor of mining engineering at Pennsylvania State University from 1974 until 1993, serving as head of the Department of Mineral Engineering from 1974 until 1986 and Associate Dean for Continuing Education and Industry Programs from 1986 to 1993. Mr. Frantz was with John T. Boyd Company, a mining engineering consulting firm, from 1964 until 1974 serving as President from 1973 to 1974.
JAMES G. KENAN III was appointed to our board on February 14, 2002 and his current term expires in 2007. He is also a member of Kentucky River Coal Corporation's (Predecessor Company) board and has been since May 1984, where he has served as Chairman of the board since May 1999. From May 1989 until May 1999, Mr. Kenan served as Chief Executive Officer and President. He also served as Vice President from May 1980 until May 1989. Mr. Kenan worked at J.P. Morgan for six years prior to joining Kentucky River in 1975. Mr. Kenan is the nephew of Catesby W. Clay.
PETER KIRILL, JR. was appointed to our board on October 16, 2002 and was a member of Kentucky River Coal Corporation's (Predecessor Company) board from 2000 until he resigned October 16, 2002. His current term expires in 2007. He is a member of our Audit Committee. Mr. Kirill has served as president of four automobile dealerships for more than five years.
CHISWELL D. LANGHORNE, JR. was appointed to our board on February 14, 2002 and his current term expires in 2005. He is also a member of Kentucky River Coal Corporation's (Predecessor Company) board and has been since 1965, where he has served as Vice Chairman of the board since 1983. He is Chairman of our Compensation Committee and a member of our Executive Committee. Mr. Langhorne has served as President of C.D. Langhorne, Jr., Inc., an exploration entity, since 1982 and is a partner in Blackstone Minerals Company L.P.
DANNY S. MAGGARD has served as Chief Engineer since February 14, 2002 and has served as Chief Engineer for Kentucky River Coal Corporation (Predecessor Company) since January 1991. Prior to joining Kentucky River Corporation in 1979, Mr. Maggard held various engineering positions for coal mining companies.
FRED N. PARKER was appointed to our board on February 14, 2002 and his current term expires in 2005. He was a member of Kentucky River Coal Corporation's (Predecessor Company) board from February 1996 until he resigned October 16, 2002. Mr. Parker has served as President and Chief Executive Officer since February 14, 2002. He has served as Chief Executive Officer and President of Kentucky River Coal Corporation since May 1999. He also served as Vice President and Treasurer from May 1989 until May 1999, and Secretary and Treasurer from January 1986 until May 1989. Prior to joining Kentucky River Coal Corporation in 1981, Mr. Parker worked as a certified public accountant for five years.
WILLIAM T. YOUNG, JR. was appointed to our board on October 16, 2002 and was a member of Kentucky River Coal Corporation's (Predecessor Company) board from 2000 until he resigned October 16, 2002. His current term expires in 2007. He is a member of our Audit Committee. Mr. Young has served as President of W.T. Young LLC, a warehousing and thoroughbred horse business, since 1985.
Item 11.
Item 11. Executive Compensation.
Summary Compensation Table
The following table sets forth the compensation paid by the Predecessor Company during each of the years 2002, 2001 and 2000 for services rendered by our five most highly compensated executive officers. The executive officers of the Successor Company were appointed to the same office of the Successor Company as the officer previously held with the Predecessor Company. The Predecessor Company paid all compensation through December 31, 2002. Compensation for the month of December 2002 was paid by the Predecessor Company on behalf of the Successor Company. The Successor Company recorded an affiliated liability to the Predecessor Company and an affiliated expense for the December 2002 compensation paid on behalf of the Successor Company. The Successor Company began paying compensation January 1, 2003.
(1) No named executive officer received perquisites or other personal benefits, securities or other property that, in the aggregate, exceeded ten percent of such executive's total annual salary and bonus. (2) We traditionally pay a semi-annual bonus equivalent to 30% of base salary. (3) Consists of our contributions to the profit sharing plan and director fees. (4) Option grants shown represent options to purchase shares of the Predecessor Company.
Aggregated Option Exercises and Fiscal Year-End Values
The following table sets forth certain information with respect to our executive officers named in the Summary Compensation Table concerning the exercise of options during 2002. As a result of the restructuring there are no unexercised options held by those individuals as of the end of 2002.
Shares Aggregate Acquired on Value Exercise Realized Name (#) ($)(1) - ---- ----------- --------- James G. Kenan III 57 $65,550 Fred N. Parker.... 84 $96,600 Gary I. Conley.... 80 $92,000 Danny S. Maggard.. 48 $55,200 Carroll R. Crouch. 40 $46,000
(1) Based on the market value of the common shares on the date of exercise less the exercise price paid for those shares.
Director Compensation
Members of the board who are not also employees are paid an annual retainer of $4,000 for services as director paid in quarterly installments and prorated when a director does not serve for a full year. In addition, all directors receive a fee of $1,000 for each director meeting attended and non-employee directors receive a fee of $500 for each committee meeting attended. The Successor Company's board held a total of two meetings during 2002. The Predecessor Company's board held a total of six meetings during 2002. Directors are reimbursed for travel costs incurred for attendance at board and committee meetings.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.
The following tables set forth the number and percentage of Kentucky River Properties LLC membership units and Kentucky River Coal Corporation common shares owned by each of our directors, certain executive officers, owners of more than five percent of Kentucky River Properties LLC membership units or Kentucky River Coal Corporation common shares, respectively, and all directors and officers as a group, on March 24, 2003.
(a) Kentucky River Coal Corporation, Predecessor Company, holds 40,414 membership units of Kentucky River Properties LLC, Successor Company. See the table above titled Kentucky River Coal Corporation for details of Predecessor Company shares owned by each of our directors, certain executive officers, owners of more than five percent of the Predecessor Company's common shares, and all directors and officers as a group. (b) Includes 100 Predecessor Company shares held by Mr. Langhorne's wife, and 400 Predecessor Company shares held as trustee in trust for the benefit of Mr. Langhorne's children, for which he holds shared voting and dispositive power. (c) Includes 4,238 Predecessor Company shares held as trustee in various trusts for Mr. Clay's benefit, and for the benefit of his children, nieces and nephews, for which Mr. Clay shares voting and dispositive power with Mr. Kenan; 2,295 Predecessor Company shares held as trustee in various trusts for the benefit of Mr. Clay's daughter, nieces and brother-in-law, for which Mr. Clay holds shared voting and dispositive power; and 577 Predecessor Company shares held as trustee in various trusts for the benefit of Mr. Clay's children for which he holds sole voting and dispositive power. (d) Includes 4,238 shares Predecessor Company held as trustee in various trusts for Mr. Clay's benefit, and for the benefit of Mr. Clay's children, nieces and nephews, for which Mr. Kenan shares voting and dispositive power with Mr. Clay; 800 Predecessor Company shares held as trustee in a trust for the benefit of Mr. Kenan and his siblings, for which he holds shared voting and dispositive power; and 463 Predecessor Company shares held in a family foundation for which Mr. Kenan is a director and may be deemed to hold shared voting and dispositive power. (e) Includes 400 Predecessor Company shares held in a family owned limited liability company, for which Mr. Young is a director and may be deemed to hold shared voting and dispositive power. (f) Includes 10 Predecessor Company shares held by Mr. Kirill's wife. (g) Includes 160 Predecessor Company shares held jointly with Mr. Parker's wife, for which he holds shared voting and dispositive power. (h) Includes 28 Successor Company membership units held jointly with Mr. Conley's wife, for which he holds shared voting and dispositive power. (i) Includes 27 Successor Company membership units held jointly with Mr. Maggard's wife, for which he holds shared voting and dispositive power. (j) Includes 57 Successor Company membership units held jointly with Mr. Crouch's wife, for which he holds shared voting and dispositive power. (k) Represents less than one percent of the membership units/shares outstanding. (l) The business address of each of the individuals listed in this table is the address of Kentucky River Properties LLC, 200 West Vine Street, Suite 8-K, Lexington, Kentucky 40507. (m) The business address of each of the individuals listed in this table is the address of Kentucky River Coal Corporation, 200 West Vine Street, Suite 8-K, Lexington, Kentucky 40507. (n) As of March 24, 2003 there were no outstanding membership unit options exercisable for Kentucky River Properties LLC membership units and there were no outstanding stock options exercisable for Kentucky River Corporation common stock.
There were no equity compensation plans previously approved by unit holders or equity compensation plans not previously approved by unit holders at December 31, 2002.
Item 13.
Item 13. Certain Relationships and Related Transactions.
At December 31, 2002, a $2.2 million affiliated receivable is reported on the face of the Successor Company's December 31, 2002, balance sheet. The receivable balance includes $1.9 million due from the Predecessor Company related to the November 30, 2002, transfer of assets and liabilities from the Predecessor Company to Successor Company as a result of the restructuring. Also included in that affiliated receivable balance are amounts for various expense items paid by the Successor Company on behalf of the Predecessor Company offset by amounts paid by the Predecessor Company on behalf of the Successor Company. Specifically, during the month of December 2002 the Successor Company paid, on behalf of the Predecessor Company, $442,000 of expenses incurred before the transfer date in the normal course of business. This amount is properly excluded from the expenses reported in the income statement of the Successor Company. Also, included in the affiliated receivable total is an offset of $176,000 for December 2002 employee compensation paid by the Predecessor Company, on behalf of the Successor Company. The $176,000 is properly included in Operating, General and Administrative expense of the Successor Company. As of March 24, 2003 no affiliated receivable or payable amounts were outstanding.
Item 14.
Item 14. Controls and Procedures.
The Successor Company's Chief Executive Officer and Chief Financial Officer have reviewed and evaluated the Successor Company's disclosure controls and procedures within 90 days of the filing of this report, and have concluded that the Successor Company's disclosure controls and procedures were adequate and effective to ensure that information required to be disclosed is recorded, processed, summarized, and reported in a timely manner.
There were no significant changes in the Successor Company's internal controls or in other factors that could significantly affect these controls subsequent to the date of the Chief Executive Officer and Chief Financial Officer's evaluation, nor were there any significant deficiencies or material weaknesses in the controls which required corrective action.
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) Exhibits
Exhibit No. Description - ----------- -----------
3.1 Certificate of Formation of Kentucky River Properties LLC dated February 14, 2002 (incorporated by reference to Exhibit 3.1 to Form S-4 (SEC File #: 333-83634) filed by the Registrant with the SEC on March 1, 2002).
3.2 Kentucky River Properties LLC Operating Agreement dated February 14, 2002 (incorporated by reference to Exhibit 3.2 to Form S-4 (SEC File #: 333-83634) filed by the Registrant with the SEC on March 1, 2002).
21 Subsidiaries of the Registrant.
99.1 Certification of Fred N. Parker, Chief Executive Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.2 Certification of Carroll R. Crouch, Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(b) Reports on Form 8-K. No reports on Form 8-K were filed during the three months ended December 31, 2002.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
Kentucky River Properties LLC
By: /s/ Fred N. Parker ---------------------- Fred N. Parker President & Chief Executive Officer
Pursuant to the requirement of the Securities 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.
CERTIFICATION
I, Fred N. Parker, certify that:
1. I have reviewed this annual report on Form 10-K of Kentucky River Properties LLC;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 24, 2003 /s/ Fred N. Parker Fred N. Parker Chief Executive Officer
CERTIFICATION
I, Carroll R. Crouch, certify that:
1. I have reviewed this annual report on Form 10-K of Kentucky River Properties LLC;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 24, 2003 /s/ Carroll R. Crouch Carroll R. Crouch Chief Financial Officer