Back to GetFilings.com
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
FOR ANNUAL AND TRANSITION REPORTS PURSUANT TO SECTIONS 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 For the fiscal year ended December 31, 2002
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _______ to ________
Commission file number 333-83634
KENTUCKY RIVER PROPERTIES LLC
(Exact name of registrant as specified in its charter)
Delaware 37-1450003
(State or Other Jurisdiction (I.R.S. Employer
Of Incorporation or Organization) Identification Number)
200 West Vine Street Suite 8-K
Lexington, Kentucky 40507
(Address of Principal Executive Offices) (Zip Code)
Registrant's Telephone Number, Including Area Code: (859) 254-8498
Securities registered pursuant to
Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
Not applicable. Not applicable.
- --------------------------------- -------------------------------
Securities registered pursuant to Section 12(g) of the Act:
Not applicable.
---------------------------------------------------
(Title of class)
- ------------------------------------------------------------------
(Title of class)
Indicate by check mark whether the registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K (229.405 of this chapter) is not contained herein, and will
not be contained to the best of the registrant's knowledge, in definitive proxy
or information statements incorporated by reference in Part III of this Form
10-K or any amendment to this Form 10-K. [X]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act).
Yes [ ] No [X]
The aggregate market value of the voting and non-voting common equity held by
non-affiliates computed by reference to the price at which the common equity was
last sold, or the average bid and asked price of such common equity, as June 28,
2002 was $0.
The number of the Registrant's membership units outstanding as of March
24, 2003 was 46,421 units.
TABLE OF CONTENTS
Page
----
PART I..................................................................... 1
Item 1. Business........................................................ 1
Item 2. Properties...................................................... 11
Item 3. Legal Proceedings............................................... 14
Item 4. Submission of Matters to a Vote of Security Holders............. 14
PART II.................................................................... 14
Item 5. Market for Registrant's Common Equity and Related
Unitholder Matters.............................................. 14
Item 6. Selected Financial Data......................................... 16
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operation........................................ 17
Item 7A. Quantitative and Qualitative Disclosures About Market Risk..... 17
Item 8. Financial Statements and Supplementary Data..................... 26
Item 9. Changes in and Disagreements With Accountants on Accounting
and Financial Disclosure........................................ 43
PART III................................................................... 43
Item 10. Managers and Executive Officers of the Registrant.............. 43
Item 11. Executive Compensation......................................... 44
Item 12. Security Ownership of Certain Beneficial Owners and
Management and Related Unitholder Matters...................... 46
Item 13. Certain Relationships and Related Transactions................. 47
Item 14. Controls and Procedures........................................ 47
PART IV.................................................................... 48
Item 15. Exhibits, Financial Statement Schedules, and Reports on
Form 8-K....................................................... 48
Signatures................................................................. 49
Certifications............................................................. 50
PART I
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.
1
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.
2
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.
3
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.
4
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. Properties of this Form 10-K.
5
We also sell timber harvested from our fee acreage and surface acreage listed
under listed under Item 2. Properties of this Form 10-K.
We also own non-coal real estate consisting of six undeveloped parcels near
Lexington, Kentucky (1,270 acres), Jacksonville, Florida (22 acres), and Owings
Mill, Maryland (79 acres). We have not purchased any non-coal real estate for
several years and have never participated in real estate development.
Regulation
The coal mining industry is subject to regulation by federal, state and local
authorities on matters such as:
o blasting;
o the discharge of materials into the environment;
o fly ash disposal;
o employee health and safety;
o taxes;
o mine permits and other licensing requirements;
o reclamation and restoration of mining properties after mining is completed;
o re-mining to restore pre-law sites which were not subject to the Surface
Mining Control and Reclamation Act;
o management of materials generated by mining operations;
o surface subsidence from underground mining;
o water pollution;
o legislatively mandated benefits for current and retired coal miners;
o air quality standards;
o protection of wetlands;
o endangered species protection;
o protection of historic, archeological and culturally important sites;
o plant and wildlife protection;
o limitations on land use;
o storage of petroleum products and substances which are regarded as
hazardous under applicable laws; and
o management of electrical equipment containing polychlorinated biphenyls, or
PCBs.
In addition, the utility industry, which is the most significant end-user of
coal, is subject to extensive regulation regarding the environmental impact of
its power generation activities. This could affect demand for our lessees' coal.
Further, new legislation or regulations may be adopted which may have a
significant impact on the mining operations of our lessees or their customers'
ability to use coal, and may require us, our lessees or their customers to
change operations significantly or incur substantial costs.
Our lessees are obligated to conduct mining operations in compliance with all
applicable federal, state and local laws and regulations. In the event that we
provide notice to any of our lessees that they have failed to comply with all
applicable federal, state and local laws and regulations and such failure
continues beyond a specified period, typically 10 to 30 days, an event of
default is deemed to occur under the lease giving us the right to terminate the
lease and to seek other legal and equitable remedies against the lessee. In
addition, each of our lessees is contractually obligated under our leases to
post a reclamation bond. However, because of extensive and comprehensive
regulatory requirements, violations during mining operations are not unusual in
the industry and, notwithstanding compliance efforts, we do not believe
violations by our lessees can be eliminated completely. Most of the violations
to date have been minor or technical violations that have or can be remedied. As
a result, none of the violations to date, or the monetary penalties assessed,
have been material to us or, to our knowledge, our lessees. We do not currently
expect that future compliance will have a material adverse effect on us.
6
While it is not possible to quantify the costs of compliance by our lessees with
all applicable federal and state laws, those costs have been and are expected to
continue to be significant. Capital expenditures for environmental matters have
not been material to us or our lessees in recent years. Our lessees post
performance bonds for the estimated costs of reclamation and mine closing,
including the cost of treating mine water discharge when necessary. Although we
do not accrue for such costs because our lessees are contractually liable for
all costs relating to their mining operations, including the costs of
reclamation and mine closure, we have, with respect to some of our smaller
lessees, required a letter of credit from a banking institution as security that
the lessee perform its obligations under its lease. Although our lessees
typically accrue adequate amounts for these costs, their future operating
results would be adversely affected if they later determined these accruals to
be insufficient. Compliance with these laws has substantially increased the cost
of coal mining for all domestic coal producers.
During 2002, to facilitate the restructuring, two of our operating subsidiaries
were converted into new limited liability companies. Additionally, three of our
operating subsidiaries were merged into the Kentucky River Coal Corporation
prior to the restructuring. As a matter of law, the new limited liability
companies have assumed the liabilities of our operating subsidiaries. These
liabilities include liabilities for any past or present environmental regulatory
infractions and for environmental cleanup costs. The regulatory infractions
giving rise to these liabilities could relate to property or mining operations
that have been owned or operated by other corporations which have been
previously acquired by or merged into the predecessor or converting corporation.
Clean Air Act. The Federal Clean Air Act and similar state and local laws, that
regulate emissions into the air, affect coal mining and processing operations
primarily through permitting and/or emissions control requirements. The Clean
Air Act also indirectly affects coal mining operations by extensively regulating
the emissions from coal-fired industrial boilers and power plants, which are the
largest end-users of our coal. These regulations can take a variety of forms, as
explained below.
The Clean Air Act imposes obligations on the Environmental Protection Agency
(EPA) and the states to implement regulatory programs that will lead to the
attainment and maintenance of EPA-promulgated ambient air quality standards,
including standards for sulfur dioxide, particulate matter and nitrogen oxides.
Coal-fired power plants and industrial boilers have been required to expend
considerable resources in an effort to comply with these ambient air standards.
Significant additional emissions control expenditures, including expenditures to
reduce current emissions of nitrogen oxides from power plants, will be needed in
order to meet the current national ambient air standard for ozone. Emissions
control requirements for new and expanded coal mines or coal-fired power plants
and industrial boilers are expected to become more demanding in the years ahead.
For example, in July 1997 the EPA adopted more stringent ambient air quality
standards for particulate matter and ozone. In a February 2001 decision, the
U.S. Supreme Court largely upheld the EPA's position, although it remanded the
EPA's ozone implementation policy for further consideration. Further, details
regarding the new particulate standard itself are still subject to judicial
challenge. These ozone restrictions could require electric utilities to reduce
the amount of nitrogen oxide emitted from their power plants. Increasing
controls on the amount of particulate matter electric utilities may emit during
the combustion process could also result. These ozone and particulate matter
regulations and future regulations regarding these and other ambient air
standards could restrict the market for coal, the development of new mines and
lessees of our coal reserves. This in turn may have a material adverse effect on
our royalty revenues.
Further, the EPA recently announced a proposal that would require 19 states in
the eastern U.S. that have ambient air quality problems to make substantial
reductions in nitrogen oxide emissions by the year 2004. To achieve such
reductions, many power plants would be required to install additional control
measures. The installation of these measures would make it more costly to
operate coal-fired power plants and, depending on the requirements of individual
state implementation plans, could make coal a less attractive fuel. Any
reduction in coal's share of the capacity for power generation could have a
material adverse effect on our business, financial condition and results of
operations and the business, financial condition and results of operations of
our lessees.
Additionally, the U.S. Department of Justice, on behalf of the EPA, has filed
lawsuits against several investor-owned electric utilities and brought an
administrative action against one government-owned electric utility for alleged
violations of the Clean Air Act. The EPA claims that these utilities' power
plants have failed to obtain permits required under the Clean Air Act for
alleged facility modifications. Our lessees supply coal to some of the currently
affected utilities, and it is possible that other of our lessees' customers will
be sued. These lawsuits could require the utilities to pay penalties and install
pollution control equipment, which could adversely impact their demand for high
sulfur coal, and coal in general. Any outcome that adversely affects our
lessees' customers and their demand for coal could adversely impact our
financial condition or results of operations.
Other Clean Air Act programs are also applicable to power plants that use our
coal. For example, Title IV of the Clean Air Act requires reduction of sulfur
dioxide emissions from power plants in two phases. Because sulfur is a natural
component of coal, required sulfur dioxide reductions can affect coal mining
operations. Phase I, which became effective in 1995, regulated the sulfur
dioxide emissions levels from 261 generating units at 110 power plants and
targeted the highest sulfur dioxide emitters. Phase II, implemented January 1,
2000, made the regulations more stringent and extended them to additional power
plants, including all power plants of greater than 25 megawatt capacity.
Affected electric utilities can comply with these requirements by:
o burning lower sulfur coal, either exclusively or mixed with higher sulfur
coal;
o installing pollution control devices such as scrubbers, which reduce the
emissions from high sulfur coal;
7
o reducing electricity generating levels; or
o purchasing or trading pollution credits.
Specific emissions sources receive pollution credits, which electric utilities
and industrial concerns can trade or sell to allow other units to emit higher
levels of sulfur dioxide. Each credit allows its holder to emit one ton of
sulfur dioxide.
In addition to emissions control requirements designed to control acid rain and
to attain the national ambient air quality standards, the Clean Air Act also
imposes standards on sources of hazardous air pollutants. Although these
standards have not yet been extended to coal mining operations or the
by-products of coal combustion, consideration is now being given to regulating
certain hazardous air pollutant components that are found in coal combustion
exhaust. The most prominently targeted pollutant is mercury, although other
by-products of coal combustion could also be covered by future hazardous air
pollutant standards for coal combustion sources. Some states are now proposing
mercury control regulations and the EPA expects to have a regulation concerning
mercury implemented by 2007.
In summary, the effect that a variety of Clean Air Act regulations could have on
the coal industry and thus our business cannot be predicted with certainty.
Future regulatory provisions may materially adversely affect our business,
financial condition or results of operations. Additionally, we have no ability
to control, or specific knowledge regarding, the environmental and other
regulatory compliance of purchasers of coal mined from our properties.
Mountaintop Mining/Valley Fill Litigation.
The Kentuckians for the Commonwealth filed a lawsuit on August 21, 2001 in a
federal district court in Charleston, West Virginia, related to valley fills in
streams of Martin County, Kentucky. Plaintiffs alleged that the Corps of
Engineers violated the Clean Water Act and the National Environmental Policy
Act. Specifically, the lawsuit claims that the Corps of Engineers has no
authority under the Clean Water Act to issue permits allowing valley fills in
streams. In the alternative, plaintiffs claim that:
o the Corps of Engineers violated the Clean Water Act by issuing nationwide
Clean Water Act Section 404 dredge and fill permits for valley fills rather
than site specific permits;
o the Corps of Engineers violated the National Environmental Policy Act by
approving these permits without preparing an environmental impact
statement;
o the Corps of Engineers may not issue these permits without analyzing
measures required by the Clean Water Act to avoid and minimize impact on
streams; and
o the Corps of Engineers cannot authorize disposal without waiting for the
U.S. EPA to complete proceedings under the Clean Water Act to veto the
proposed permit.
The plaintiffs sought an injunction prohibiting the Corps of Engineers from
issuing any new permits allowing valley fills in streams or, in the alternative,
requiring revocation of the specific permits subject to this litigation. On May
8, 2002, the court granted the injunction requested by the plaintiffs.
On January 29, 2003 the Fourth Circuit reversed this injunction which prohibited
the Army Corp of Engineers from issuing new Section 404 permits for the deposit
of mountaintop debris in valley fills, indicating that issuance of permits did
not violate the Clean Water Act.
Mine Health and Safety Laws. Stringent safety and health standards have been
imposed by federal legislation since the adoption of the Mine Health and Safety
Act of 1969. The Mine Health and Safety Act of 1969 resulted in increased
operating costs and reduced productivity. The Mine Safety and Health Act of
1977, which significantly expanded the enforcement of health and safety
standards of the Mine Health and Safety Act of 1969, imposes comprehensive
safety and health standards on all mining operations. In addition, as part of
the Mine Health and Safety Acts of 1969 and 1977, the Black Lung Acts require
payments of benefits by all businesses conducting current mining operations to
coal miners with black lung and to some survivors of a miner who dies from this
disease. To our knowledge, our lessees have made all the payments required under
the Black Lung Act, and are in compliance with all applicable mine health and
safety laws.
Surface Mining Control and Reclamation Act (SMCRA). SMCRA establishes
operational, reclamation and closure standards for all aspects of surface mining
as well as many aspects of deep mining. SMCRA requires that comprehensive
environmental protection and reclamation standards be met during the course of
and upon completion of mining activities. In conjunction with mining the
property, our lessees are contractually obligated under the terms of their
leases to comply with all laws, including SMCRA and equivalent state and local
laws, which obligations include reclaiming and restoring the mined areas by
grading, shaping and preparing the soil for seeding. Upon completion of the
mining, reclamation generally is completed by seeding with grasses or planting
trees for use as pasture or timberland, as specified in the approved reclamation
plan. To our knowledge, all of our lessees are in compliance in all material
respects with applicable regulations relating to reclamation.
SMCRA also requires our lessees to submit a bond or otherwise secure the
performance of their reclamation obligations. The earliest a reclamation bond
can be completely released is five years after reclamation has been achieved.
Federal law and some state laws impose on mine operators the responsibility for
repairing the property or compensating the property owners for damage occurring
8
on the surface of the property as a result of mine subsidence, a consequence of
longwall mining and possibly other mining operations. In addition, the Abandoned
Mine Lands Act, which is part of SMCRA, imposes a tax on all current mining
operations, the proceeds of which are used to restore mines closed before 1977.
The maximum tax is $0.35 per ton of coal produced from surface mines and $0.15
per ton of coal produced from underground mines. Since our lessees are
responsible for these obligations and any related liabilities, we do not accrue
for the estimated costs of reclamation and mine closing.
Under SMCRA, responsibility for unabated violations, unpaid civil penalties and
unpaid reclamation fees of independent contract mine lessees and other third
parties could potentially be imputed to other companies that are deemed,
according to the regulations, to have owned or controlled the contract mine
operator. A recent decision by the Interior Board of Land Appeals held that a
lease giving the lessor the right to approve or disapprove a mining plan
constitutes the authority to "control" the conduct of a mining operation. Our
leases contain that provision, however, they allow the lessee to override any
objection we may have to the mine plan. This language is generally the type used
by a lessor to insure that the lessee mines all the mineable and merchantable
coal rather than controlling day-to-day operations. However, sanctions against
the owner or controller are quite severe and can include civil penalties,
reclamation fees and reclamation costs. We are not aware of any currently
pending or asserted claims against us asserting that we own or control our
lessees, and believe our lessees are in substantial compliance with all
reclamation requirements under their SMCRA permits. Nevertheless, as many
factors affect the financial stability of our lessees, especially downswings in
the market, situations could arise in which a government agency would seek to
hold us responsible for reclamation deficiencies.
On March 29, 2002, the U.S. District Court for the District of Columbia issued a
ruling that could restrict underground mining activities conducted:
o in the vicinity of public roads;
o within a variety of federally protected lands;
o within national forests; and
o within a certain proximity of occupied dwellings.
The lawsuit, Citizens Coal Council v. Norton, was filed in February 2000 to
challenge regulations issued by the Department of Interior providing, among
other things, that subsidence and underground activities that may lead to
subsidence are not surface mining activities within the meaning of SMCRA. SMCRA
generally contains restrictions and certain prohibitions on the locations where
surface mining activities can be conducted. The District Court entered summary
judgment upon the plaintiff's claims that the Secretary of the Interior's
determination violated SMCRA. By order dated April 9, 2002, the court remanded
the regulations to the Secretary of the Interior for reconsideration.
None of the deep mining activities undertaken on our properties are within
federally protected lands or national forests where SMCRA restricts surface
mining, even though several are within proximity to occupied dwellings. However,
this case poses a potential restriction on underground mining within 100 feet of
a public road.
The significance of this decision for the coal mining industry remains unclear
because this ruling is subject to appellate review, and the Department of
Interior and the National Mining Association, a trade group that intervened in
this action, have announced their intention to seek a stay of the order pending
appeal to the U.S. Court of Appeals for the District of Columbia. If the stay is
not granted, the District Court's decision is not overturned, or if some
legislative solution is not enacted, this ruling could have a material adverse
effect on all coal mine operations that utilize underground mining techniques,
including those of our lessees. While it still may be possible to obtain permits
for underground mining operations in these areas, the time and expense of that
permitting process are likely to increase significantly.
Framework Convention on Global Climate Change. The U.S. and more than 160 other
nations are signatories to the 1992 Framework Convention on Global Climate
Change, commonly known as the Kyoto Protocol, that is intended to limit or
capture emissions of greenhouse gases, such as carbon dioxide. The U.S. Senate
has neither ratified the treaty commitments, which would mandate a reduction in
U.S. greenhouse gas emissions, nor enacted any law specifically controlling
greenhouse gas emissions, and the Bush administration has not supported this
treaty. Nonetheless, future regulation of greenhouse gases could occur. Efforts
to control greenhouse gas emissions could result in reduced demand for coal if
electric power generators are required to switch to lower carbon sources of
fuel. These restrictions could have a material adverse effect on our business.
Clean Water Act. The Clean Water Act affects coal mining operations by imposing
restrictions on effluent discharge into waters. Regular monitoring, as well as
compliance with reporting requirements and performance standards, are
preconditions for the issuance and renewal of permits governing the discharge of
pollutants into water. Our lessees are also subject to Section 404 of the Clean
Water Act, which imposes permitting and mitigation requirements associated with
the dredging and filling of wetlands. Our lessees are contractually obligated
under the terms of our leases to obtain all necessary wetlands permits required
under Section 404 of the Clean Water Act. However, mitigation requirements under
those existing, and possible future, wetlands permits may vary considerably. To
our knowledge, our lessees have obtained all permits required under the Clean
Water Act and equivalent state laws.
9
As a result of the mountain top mining/valley fill litigation in West Virginia,
the U.S. Army Corp. of Engineers is re-evaluating its role in issuing nationwide
permits authorizing discharges and fills into waters of the United States.
Comprehensive Environmental Response, Compensation and Liability Act (CERCLA).
CERCLA and similar state laws affect coal mining operations by, among other
things, imposing cleanup requirements for threatened or actual releases of
hazardous substances that may endanger public health or welfare or the
environment. Under CERCLA and similar state laws, joint and several liability
may be imposed on waste generators, site owners and lessees and others
regardless of fault or the legality of the original disposal activity. While the
EPA deems waste substances generated by coal mining and processing operations to
constitute high volume, but low risk wastes, it generally does not deem those
wastes to constitute hazardous substances for the purposes of CERCLA. However,
the statute governs some products used by coal companies in operations, such as
chemicals. Thus, coal mines on our property that our lessees currently operate
or have previously operated, and sites to which our lessees sent waste
materials, may be subject to liability under CERCLA and similar state laws. Our
lessees may become involved in future proceedings, litigation or investigations
and these liabilities may be material. In addition an agency may attempt to
impute such liability to us as a site owner.
Mining Permits and Approvals. Numerous governmental permits or approvals are
required for mining operations. In connection with obtaining these permits and
approvals, our lessees may be required to prepare and present to federal, state
or local authorities data pertaining to the effect or impact that any proposed
production of coal may have upon the environment. The requirements imposed by
any of these authorities may be costly and time consuming and may delay
commencement or continuation of mining operations. To our knowledge, our lessees
hold all required mining permits and approvals.
In order to obtain mining permits and approvals from state regulatory
authorities, mine operators, including our lessees, must submit a reclamation
plan for restoring, upon the completion of mining operations, the mined property
to its prior condition, productive use or other permitted condition. Typically
our lessees submit the necessary permit applications between 12 and 18 months
before they plan to begin mining a new area. In our experience, permits
generally are approved within 12 months after a completed application is
submitted. In the past, our lessees have generally obtained their mining permits
without significant delay. However, they may experience difficulty in obtaining
mining permits in the future.
Future legislation and administrative regulations may emphasize more protection
of the environment and, as a consequence, the activities of mine operators,
including our lessees, may be more closely regulated. Legislation and
regulations, as well as future interpretations of existing laws, may also
require substantial increases in equipment expenditures and operating costs, as
well as delays, interruptions or the termination of operations. The possible
effect of such regulatory changes cannot be predicted.
Under some circumstances, substantial fines and penalties, including revocation
or suspension of mining permits, may be imposed under the laws described above.
Monetary sanctions and, in severe circumstances, criminal sanctions may be
imposed for failure to comply with these laws. Regulations also provide that a
mining permit can be refused or revoked if an officer, director or a shareholder
with a 10% or greater interest in the entity is affiliated with another entity
which has outstanding permit violations.
Endangered Species. The federal Endangered Species Act and counterpart state
legislation protect species threatened with possible extinction. Protection of
endangered species may have the effect of prohibiting or delaying our lessees
from obtaining mining permits and may include restrictions on timber harvesting,
road building and other mining or forestry activities in areas containing the
affected species. A number of species indigenous to Central Appalachia are
protected under the Endangered Species Act, and some of these species have been
identified on our property in the vicinity of Pine Mountain in the counties of
Harlan, Leslie, Letcher and Perry. However, based on the species which have been
identified to date and the current application of applicable laws and
regulations, we do not believe there are any species protected under the
Endangered Species Act that would materially and adversely affect our lessees'
ability to mine coal from our properties in accordance with current mining plans
or our ability to sell timber growing on our properties for harvest. Additional
species on our properties may receive protected status under the Endangered
Species Act and additional currently protected species may be discovered within
our properties.
Executive Order by the Governor of Kentucky. By Executive Order dated September
21, 2001, Kentucky's Governor established a moratorium on permits for non-coal
mining operations (limestone) and the review of permits and laws regarding oil
and gas wells in the Pine Mountain area. The stated purpose of the order is to
protect the environment and scenic landscape along the Pine Mountain Trail. The
governor has proposed a state park along the trail. The park would extend from
Elkhorn City, Pike County Kentucky to Cumberland Gap at Middlesboro, Kentucky,
approximately 120 miles. Viewscape or viewshed is now being recognized as a
factor to be considered in Lands Unsuitable Petitions. However, legislation
adopted in March 2002 establishing the Pine Mountain Trail as a park includes
specific findings that the park boundaries are adequate to protect the trail and
that use of lands outside the boundary of the park will not be restricted
because those lands may be viewed from the park. If this legislation was
challenged and a lands unsuitable for mining petition seeking denial of mining
permits where mining would be within the view from the park were successful, it
could have a material impact on our business, financial condition or results of
operations, as the view from the top of Pine Mountain extends through the
counties of Harlan, Leslie, Letcher and Perry.
Unmined Mineral Taxes. In addition to regular property taxes, Kentucky's Revenue
Cabinet assesses our coal property each year. We are often in disagreement as to
the value they place on our reserves. If informal discussions do not settle the
disagreement, we must file a formal protest, which is a more formal process
seeking a compromise. Failure to compromise results in an appeal to the Kentucky
Board of Tax Appeals. The decision of the board can be appealed to the Franklin
Circuit Court and on through the appellate process. Complying with existing
regulations for filing unmined coal returns is very expensive and time
consuming. The coal owner is required to map and list all mineable coal on his
tax return. If the owner believes a boundary of coal is not mineable, but the
Revenue Cabinet believes it is, the Revenue Cabinet will take the position that
the coal was "omitted", and assess a penalty along with interest. The Revenue
Cabinet may also consider a boundary as "omitted" if the owner lists it but at
nominal value. We have ongoing negotiations and litigation with the Revenue
Cabinet over our assessments and returns. However, our coal leases require that
the lessee reimburse us for all unmined mineral taxes paid on coal they have
leased.
10
Other Environmental Laws Affecting Our Lessees. Our lessees are required to
comply with numerous other federal, state and local environmental laws in
addition to those previously discussed. These additional laws include, for
example, the Resource Conservation and Recovery Act, the Safe Drinking Water
Act, the Toxic Substance Control Act, and the Emergency Planning and Community
Right-to-Know Act. We believe that our lessees are in substantial compliance
with all applicable environmental laws.
The federal government and several states have developed or are developing
proposals to bundle emission standards for utilities. These proposals could
significantly reduce coal's use for generation of electricity. The EPA has also
implemented a regional haze rule, the purpose of which is to improve visibility
in national parks. If the EPA focuses application of this rule on the utility
industry, it could have a negative impact on the use of coal in electricity
generation. Litigation is pending that challenges the application of this rule
because it focuses on stationary sources and is not based upon reasonable
attribution. The lawsuit also alleges that the EPA has relied upon faulty
cost/benefit analysis.
Employees and Labor Relations
We have approximately 25 employees, none of whom is subject to a collective
bargaining agreement.
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.
11
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.
Minimum Minimum Total
Production Production Royalty Royalty Total Royalty Haulage Total Haulage
Year Tonnage Royalty Received Recouped Received Received* & Royalty
- ---- ---------- ----------- ---------- --------- ------------ ---------- -----------
2000..... 12,689,951 $24,494,745 $ 454,550 $(253,007) $24,696,288 $1,961,612 $26,657,900
2001..... 12,664,708 $28,048,704 $ 603,000 $(427,720) $28,223,984 $1,759,052 $29,983,036
2002..... 13,271,124 $24,081,794 $4,699,472 $(203,368) $28,577,898 $2,211,082 $30,788,980
* 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.
12
The following table sets forth our estimates of proven and probable recoverable
coal reserves, and average quality, by seam as of December 31, 2002.
Average Quality at 1.50 Specific Gravity
--------------------------------------
Recovery(2) ( As Received Basis )(3)
----------- -------------------------
Recoverable Reserves -
Tons (000's) (1) Mining Method % % % % Lbs/Mbtu
------------------------ ------------------- ---- ------ ----- ------ ------------
SO\\2\\
Seam Name Total Proven Probable Underground Surface Mine Washer Ash Sulfur Btu/Lb (4)
--------- ------- ------- -------- ----------- ------- ---- ------ ----- ------ ------ -----
Upper Skyline (No. 12) 158 158 0 158 85 100 -- -- -- --
Skyline (No. 11)...... 577 83 494 0 577 85 100 -- -- -- --
Tiptop (No. 10)....... 1,438 722 716 0 1,438 85 100 -- -- -- --
Hazard No. 9.......... 14,565 8,162 6,403 1,018 13,547 83 99 11.62 2.52 11,480 4.4
Peach Orchard......... 3,567 3,567 0 3,567 0 50 80 11.59 0.84 11,468 1.5
Hazard No. 8.......... 27,817 17,566 10,251 9,032 18,785 74 94 11.59 0.84 11,468 1.5
Hazard No. 7 Rider.... 6,272 2,729 3,543 0 6,272 85 100 11.91 1.41 11,562 2.4
Hazard No. 7.......... 10,715 8,687 2,028 947 9,768 82 99 9.50 0.77 11,956 1.3
Hazard No. 5A......... 38,679 25,346 13,333 35,574 3,105 54 91 6.93 0.77 12,784 1.2
Haddix................ 3,553 2,289 1,264 3,553 0 50 90 6.52 0.82 12,989 1.3
Copland............... 1,148 782 366 1,148 0 50 90 7.05 1.18 12,690 1.9
Hamlin & Upper Hamlin. 3,997 1,765 2,232 3,997 0 50 90 8.46 1.22 12,455 2.0
Hazard No. 4 Rider.... 18,168 6,435 11,733 18,117 51 50 90 9.40 2.12 12,220 3.5
Hazard No. 4.......... 60,530 36,889 23,641 60,105 425 50 90 6.66 0.75 12,896 1.2
Upper Whitesburg...... 196 196 185 11 64 94 5.97 1.11 13,105 1.7
Amburgy............... 122,029 39,376 82,653 122,029 0 50 90 5.57 1.05 13,343 1.6
Upper Elkhorn No. 3... 128,936 49,036 79,900 128,936 0 50 90 4.16 1.51 13,597 2.2
Upper Elkhorn No. 2... 92,623 30,569 62,054 92,623 0 50 90 4.94 1.49 13,513 2.2
Upper Elkhorn No. 1... 34,230 9,481 24,749 34,230 0 50 90 3.60 1.07 13,656 1.6
------- ------- ------- ------- ------
Totals............. 569,198 243,680 325,518 515,061 54,137
======= ======= ======= ======= ======
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)
======= =======
13
(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. 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. Submission of Matters to a Vote of Security Holders.
Not applicable.
PART II
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
14
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
15
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.
Successor
Predecessor Company Company
-------------------------------------------- --------
For the For the
Period Period
from from
January December
1, 2002 1, 2002
through through
November December
For the Year Ended December 31, 30, ,31
----------------------------------- -------- --------
1998 1999 2000 2001 2002 2002
-------- -------- -------- -------- -------- --------
Income Statement Data:
Revenues:
Coal royalties..................... $ 23,655 $ 23,887 $ 25,324 $ 28,233 $ 25,891 $ 2,705
Rents and haulage.................. 2,625 2,286 2,021 1,816 2,212 53
Oil and gas........................ 2,365 2,665 2,735 3,051 1,251 245
Gain on the sale of revenue-
producing properties.............. -- -- -- 4,458 -- --
-------- -------- -------- -------- -------- --------
Total revenues.................. $ 28,645 $ 28,838 $ 30,080 $ 37,558 $ 29,354 $ 3,003
Expenses:
Operating, general, and
administrative expenses........... $ 5,867 $ 5,344 $ 5,301 $ 5,809 $ 5,819 492
Oil and gas expenses............... 1,141 1,330 943 686 122 61
-------- -------- -------- -------- -------- --------
Total expenses.................. $ 7,008 $ 6,674 $ 6,244 $ 6,495 $ 5,941 $ 553
-------- -------- -------- -------- -------- --------
Income from operations................. $ 21,637 $ 22,164 $ 23,836 $ 31,063 $ 23,413 $ 2,450
Other income:
Interest and dividend income....... 3,084 3,337 2,287 1,801 1,736 35
Gain (loss) on sale of securities.. 14,414 718 7,772 3,441 309 (24)
Unrealized loss on investment in
limited partnerships.............. -- -- -- -- -- (1,125)
Unrealized gain (loss) on trading
securities........................ 1,429 6,406 (2,743) (4,983) -- --
Gain on sale of assets............. 87 1,042 1,640 2,270 2,420 2
Interest expense................... -- -- (14) -- (27) (1)
Other income....................... 841 424 587 408 455 108
-------- -------- -------- -------- -------- --------
Income before income taxes............. $ 41,492 $ 34,091 $ 33,365 $ 34,000 $ 28,306 $ 1,445
Income tax expense..................... 14,482 12,020 11,634 11,931 9,409 --
-------- -------- -------- -------- -------- --------
Net income............................. $ 27,010 $ 22,071 $ 21,731 $ 22,069 18,897 1,445
======== ======== ======== ======== ======== ========
Basic earnings per share/unit.......... $ 357.00 $ 293.43 $ 324.65 $ 357.16 $ 350.65 $ 33.02
======== ======== ======== ======== ======== ========
Diluted earnings per share/unit........ $ 356.73 $ 293.43 $ 324.43 $ 356.71 $ 350.49 $ 33.02
======== ======== ======== ======== ======== ========
Basic shares/units..................... 75,657 75,216 66,937 61,790 53,893 43,767
======== ======== ======== ======== ======== ========
Diluted shares/units................... 75,714 75,216 66,982 61,867 53,918 43,767
======== ======== ======== ======== ======== ========
Dividends declared per common
share/unit........................... $ 170.00 $ 180.00 $ 190.00 $ 235.00 $ 271.00 $ --
======== ======== ======== ======== ======== ========
Balance Sheet Data (at period end):
Total assets........................... $122,386 $130,381 $107,131 $105,243 $ 26,681 $ 48,139
Long-term liabilities.................. -- -- -- -- -- --
Total liabilities...................... $ 3,300 $ 5,837 $ 5,203 $ 2,627 $ 4,670 $ 269
Stockholders'/unitholders' equity...... $119,086 $124,544 $101,928 $102,616 $ 22,011 $ 47,870
16
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.
17
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.
18
Results of Operations
Fiscal Year Ended December 31, 2002 Compared With Fiscal Year Ended December 31,
2001
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.
Successor
Predecessor Company Company
------------------- --------
For the For the
Period Period
from from
For the January December For the
Year 1, 2002 1, 2002 Year
Ended through through Ended
December November December December
31, 2001 30, 2002 31, 2002 31, 2002
-------- -------- -------- --------
(in thousands, except average gross
royalty data)
Financial Highlights:
Revenues:
Coal royalties...................................$ 28,233 $ 25,891 $ 2,705 $ 28,596
Rents and haulage................................ 1,816 2,212 53 2,265
Oil and gas sales and royalties.................. 3,051 1,251 245 1,496
Gain on the sale of revenue-producing properties. 4,458 -- -- --
-------- -------- -------- --------
Total revenues...............................$ 37,558 $ 29,354 $ 3,003 $ 32,357
Expenses:
Operating, general and administrative expenses...$ 5,809 $ 5,819 $ 492 $ 6,311
Oil and gas expenses............................. 686 122 61 183
-------- -------- -------- --------
Total expenses...............................$ 6,495 $ 5,941 $ 553 $ 6,494
-------- -------- -------- --------
Income from operations..............................$ 31,063 $ 23,413 $ 2,450 $ 25,863
Other Income and Expense:
Interest and dividend income.....................$ 1,801 $ 1,736 $ 35 $ 1,771
Gain (loss) on sale of securities................ 3,441 309 (24) 285
Unrealized loss on investment in limited
partnerships................................... -- -- (1,125) (1,125)
Unrealized loss on trading securities............ (4,983) -- -- --
Gain on sale of assets........................... 2,270 2,420 2 2,422
Interest expense................................. -- (27) (1) (28)
Other income..................................... 408 455 108 563
-------- -------- -------- --------
Total other income (expense).................$ 2,937 $ 4,893 $ (1,005) $ 3,888
-------- -------- -------- --------
Income Before Income Taxes..........................$ 34,000 $ 28,306 $ 1,445 $ 29,751
Income Taxes........................................ 11,931 9,409 -- 9,409
-------- -------- -------- --------
Net Income..........................................$ 22,069 $ 18,897 $ 1,445 $ 20,342
======== ======== ======== ========
Operating Statistics:
Coal:
Royalty coal tons produced by lessees............ 12,665 11,952 1,319 13,271
Average gross royalties ($ per ton)..............$ 2.21 $ 2.16 $ 2.05 $ 2.15
19
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.
20
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,
2000
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
21
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.
22
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.
23
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,
24
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. 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
25
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. Financial Statements and Supplementary Data.
Table of Contents
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
26
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
27
KENTUCKY RIVER PROPERTIES LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31, 2001 and 2002
(In thousands, except share and per share data)
Predecessor Successor
Company Company
-------- --------
December 31,
-------------------
2001 2002
-------- --------
ASSETS
Investments:
Trading securities................................................. $ 20,322 --
Available-for-sale securities...................................... 19,354 1,374
Held-to-maturity securities........................................ 20,552 17,948
Land and improvements.............................................. 8,466 6,897
-------- --------
Total investments................................................ 68,694 26,219
-------- --------
Cash and cash equivalents........................................... 20,109 5,080
-------- --------
Other assets:
Accounts receivable--trade......................................... 4,334 6,512
Accrued interest receivable........................................ 98 3
Income tax receivable.............................................. 3,388 172
Investment in limited partnerships................................. 2,574 1,156
Receivable from affiliate.......................................... -- 2,213
Other receivables and prepaid expenses............................. 10 31
-------- --------
Total other assets............................................... 10,404 10,087
-------- --------
Properties and equipment:
Land and revenue-producing properties.............................. 11,932 11,932
Oil and gas properties............................................. 2,731 2,819
Buildings and equipment............................................ 2,616 2,766
Less accumulated depletion and depreciation........................ (11,243) (10,764)
-------- --------
Properties and equipment, net.................................... 6,036 6,753
-------- --------
$105,243 48,139
======== ========
LIABILITIES AND STOCKHOLDERS'/UNITHOLDERS' EQUITY
Accounts payable and accrued expenses............................... $ 713 269
Income taxes payable................................................ 1 --
Deferred income taxes............................................... 1,913 --
-------- --------
Total liabilities................................................ 2,627 269
-------- --------
Stockholders'/ Unitholders' equity:
Unitholders' equity; outstanding 46,421 and 0 units in 2002 and
2001, respectively................................................ -- 47,368
Common stock, par value of $25 a share. Authorized 100,000 shares;
issued and outstanding 0 and 61,276 shares in 2002 and 2001,
respectively..................................................... 1,532 --
Additional paid-in capital......................................... 1,782 --
Accumulated other comprehensive income............................. 1,386 502
Retained earnings.................................................. 97,916 --
-------- --------
Total stockholders'/unitholders' equity.......................... 102,616 47,870
Commitments and contingencies....................................... -- --
-------- --------
$105,243 48,139
======== ========
See accompanying notes to consolidated financial statements.
28
KENTUCKY RIVER PROPERTIES LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In thousands, except share and per share data)
Successor
Predecessor Company Company
------------------------------ --------
For the For the
Period Period
From From
For the Year Ended January December
1, 2002 1, 2002
December 31, through through
------------------ November December
2000 2001 30, 2002 31, 2002
-------- -------- -------- --------
Operating income:
Income from revenue-producing properties:
Coal:
Royalties........................................... $ 25,324 28,233 25,891 2,705
Rents and haulage................................... 2,021 1,816 2,212 53
Oil and gas:
Sales............................................... 1,771 1,801 242 126
Royalties........................................... 964 1,250 1,009 119
-------- -------- -------- --------
Total income from revenue-producing properties.... 30,080 33,100 29,354 3,003
Gain on the sale of revenue-producing properties........ -- 4,458 -- --
-------- -------- -------- --------
Total operating income............................ 30,080 37,558 29,354 3,003
Expenses:
Operating, general, and administrative.................. 5,301 5,809 5,819 492
Oil and gas expenses:
Operating............................................. 922 611 116 61
Exploration and development........................... 21 75 6 --
-------- -------- -------- --------
Total expenses.................................... 6,244 6,495 5,941 553
-------- -------- -------- --------
Income from operations............................ 23,836 31,063 23,413 2,450
-------- -------- -------- --------
Other income and expense:
Interest and dividend income............................ 2,287 1,801 1,736 35
Gain (loss) on sale of securities....................... 7,772 3,441 309 (24)
Gain on sale of assets.................................. 1,640 2,270 2,420 2
Unrealized loss on investment in limited partnership.... -- -- -- (1,125)
Unrealized losses on trading securities................. (2,743) (4,983) -- --
Interest expense........................................ (14) -- (27) (1)
Other................................................... 587 408 455 108
-------- -------- -------- --------
Total other income (expense)...................... 9,529 2,937 4,893 (1,005)
-------- -------- -------- --------
Income before income taxes........................ 33,365 34,000 28,306 1,445
Income taxes............................................. 11,634 11,931 9,409 --
-------- -------- -------- --------
Net income........................................ $ 21,731 22,069 18,897 1,445
-------- -------- -------- --------
Basic earnings per share/unit............................ $ 324.65 357.16 350.65 33.02
======== ======== ======== ========
Diluted earnings per share/unit.......................... $ 324.43 356.71 350.49 33.02
======== ======== ======== ========
Weighted average number of common shares/units:
Basic................................................... 66,937 61,790 53,893 43,767
Diluted................................................. 66,982 61,867 53,918 43,767
See accompanying notes to consolidated financial statements.
29
KENTUCKY RIVER PROPERTIES LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS'/UNITHOLDERS' EQUITY AND COMPREHENSIVE INCOME
(In thousands, except share data)
Amount
(par value Additional Accumulated
Shares/ of $25 paid-in comprehensive Retained Unitholders'
Units per share) capital income earnings equity Total
------- ---------- ---------- ------------- -------- ----------- -------
Predecessor Company:
Balance, December 31, 1999.............. 74,545 $1,865 1,642 319 120,718 -- 124,544
Comprehensive Income:
Net income............................ -- -- -- -- 21,731 -- 21,731
Unrealized gains on securities:
Net unrealized change in investment
securities, net of tax of $1,219..... -- -- -- 2,263 -- -- 2,263
-------
Total Comprehensive Income............ 23,994
-------
Dividends............................. -- -- -- -- (12,794) -- (12,794)
Common stock acquired................. (11,530) (289) -- -- (33,573) -- (33,862)
Stock options exercised............... 16 1 45 -- -- -- 46
------- ------ ----- ------ ------- ------- -------
Balance, December 31, 2000.............. 63,031 1,577 1,687 2,582 96,082 -- 101,928
Comprehensive Income:
Net income............................ -- -- -- -- 22,069 -- 22,069
Unrealized loss on securities:
Net unrealized change in investment
securities, net of tax of $(626)..... -- -- -- (1,196) -- -- (1,196)
-------
Total Comprehensive Income............ 20,873
-------
Dividends............................. -- -- -- -- (14,608) -- (14,608)
Common stock acquired................. (1,788) (46) -- -- (5,627) -- (5,673)
Stock options exercised............... 33 1 95 -- -- -- 96
------- ------ ----- ------ ------- ------- -------
Balance, December 31, 2001.............. 61,276 1,532 1,782 1,386 97,916 -- 102,616
------- ------ ----- ------ ------- ------- -------
Comprehensive Income:
Net income............................ -- -- -- -- 18,897 -- 18,897
Unrealized loss on securities:
Net unrealized change in investment
securities, net of tax of $(536)..... -- -- -- (1,048) -- -- (1,048)
-------
Total Comprehensive Income............ 17,849
-------
Dividends............................. -- -- -- -- (14,283) -- (14,283)
Common stock acquired................. (21,491) (538) -- -- (85,426) -- (85,964)
Stock options exercised............... 629 16 1,777 -- -- -- 1,793
Investment in successor company....... -- -- -- (567) -- -- (567)
------- ------ ----- ------ ------- ------- -------
Balance, November 30, 2002.............. 40,414 $1,010 3,559 (229) 17,104 -- 21,444
======= ====== ===== ====== ======= ======= =======
Successor Company:
Balance, December 1, 2002 40,414 $ -- -- 567 -- 21,895 22,462
Comprehensive Income:
Net income............................ -- -- -- -- -- 1,445 1,445
Unrealized loss on securities:
Net unrealized change in investment
securities, net of tax of $(0)....... -- -- -- (65) -- -- (65)
-------
Total Comprehensive Income............ 1,380
-------
Partnership units issued.............. 6,007 -- -- -- -- 24,028 24,028
------- ------ ----- ------ ------- ------- -------
Balance, December 31, 2002.............. 46,421 $ -- -- 502 -- 47,368 47,870
======= ====== ===== ====== ======= ======= =======
See accompanying notes to consolidated financial statements.
30
KENTUCKY RIVER PROPERTIES LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Successor
Predecessor Company Company
------------------------------ --------
For the For the
Period Period
From From
For the Year Ended January December
1, 2002 1, 2002
December 31, through through
------------------- November December
2000 2001 30, 2002 31, 2002
-------- -------- -------- --------
Cash flows from operating activities:
Net income.......................................... $ 21,731 22,069 18,897 1,445
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Unrealized loss on investment in limited
partnership....................................... -- -- -- 1,125
Unrealized losses on trading securities............ 2,743 4,983 -- --
Depreciation, depletion and amortization........... 662 645 181 88
(Gain) loss on sales of securities, net............ (7,772) (3,441) (309) 24
Gain on sale of land and improvements.............. (1,604) (2,203) (2,420) (2)
Gain on sale of equipment.......................... (36) (4,525) (7) --
Deferred income taxes.............................. (1,438) (2,143) (1,149) --
Purchase of trading securities..................... (11,189) (6,082) (97) --
Proceeds from sale of trading securities........... 21,843 10,427 19,466 --
Changes in assets and liabilities:
Decrease (increase) in accounts
receivable--trade.............................. 419 (1,144) (1,204) (973)
(Increase) decrease in accrued interest
receivable..................................... (87) 412 64 (3)
Decrease (increase) in income tax receivable..... 2,190 (3,018) 2,999 --
(Increase) decrease in other receivables and
prepaid expenses............................... (2) 2 (38) (2,202)
(Decrease) increase in accounts payable and
accrued expenses............................... (650) 432 727 (358)
Increase (decrease) in income taxes payable...... 236 (239) (1) --
-------- -------- -------- --------
Net cash provided by (used in) operating
activities.................................... 27,046 16,175 37,109 (856)
-------- -------- -------- --------
Cash flows from investing activities:
Proceeds from sale of available-for-sale
securities......................................... 20,192 20,966 36,390 --
Proceeds from maturities of held-to-maturity
securities......................................... 39,700 41,828 132,411 --
Purchases of securities:
Available-for-sale................................. (18,595) (5,119) (18,527) --
Held-to-maturity................................... (25,878) (46,821) (111,810) (17,948)
Purchases of properties and equipment............... (301) (452) (926) (72)
Proceeds from sale of properties and equipment...... 39 6,552 7 --
Proceeds from sale of land and improvements......... 4,099 2,811 4,073 2
Purchases of land and improvements.................. (271) (129) (85) --
-------- -------- -------- --------
Net cash provided by (used in) investing
activities................................... 18,985 19,636 41,533 (18,018)
-------- -------- -------- --------
Cash flows from financing activities:
Dividends paid...................................... (12,794) (14,608) (14,283) --
Repurchase of common stock.......................... (33,862) (5,673) (85,964) --
Proceeds from sale of common stock under stock
plan............................................... 46 96 1,793 --
Proceeds from letter of credit borrowing............ -- -- 3,000 --
Repayment of letter of credit borrowing............. -- -- -- (3,000)
Proceeds from issuance of membership units.......... -- -- -- 24,028
Transfer of assets and liabilities - restructuring.. -- -- -- (371)
-------- -------- -------- --------
Net cash (used in) provided by financing
activities.................................... (46,610) (20,185) (95,454) 20,657
-------- -------- -------- --------
Net (decrease) increase in cash and cash
equivalents.................................. (579) 15,626 (16,812) 1,783
Cash and cash equivalents, beginning of period........ 5,062 4,483 20,109 3,297
-------- -------- -------- --------
Cash and cash equivalents, end of period.............. $ 4,483 20,109 3,297 5,080
======== ======== ======== ========
Cash paid for income taxes............................ $ 10,819 17,561 7,791 --
======== ======== ======== ========
See accompanying notes to consolidated financial statements.
31
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)
--------
32
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.
33
(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
34
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.
35
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
2001
--------------------------------------
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
2002
--------------------------------------
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.
36
(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...................................... -- -- --
------- ------ ------
$ -- -- --
======= ====== ======
37
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 --
======== ======== ======== ========
38
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
39
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:
40
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.
41
Predecessor Company Successor Company
2001 2002
------------------- ------------------
Carrying Fair Carrying Fair
amount value amount value
--------- -------- -------- --------
Financial assets:
Investment securities................. $ 60,228 60,388 19,322 19,319
Cash and cash equivalents............. 20,109 20,109 5,080 5,080
Other assets:
Accounts receivable-trade........... 4,334 4,334 6,512 6,512
Income tax receivable............... 3,388 3,388 172 172
Accrued interest receivable......... 98 98 3 3
Investment in limited partnership... 2,574 2,574 1,156 1,156
Other............................... 10 10 2,244 2,244
========= ======== ======== ========
Financial liabilities:
Accounts payable, accrued expenses
and income taxes payable............ $ 714 714 269 269
========= ======== ======== ========
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
42
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. Changes In and Disagreements With Accountants on Accounting and
Financial Disclosure.
Not applicable.
PART III
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.
Name Age Position
- ---- --- -------------------------------------------------
Rutheford B. Campbell, Jr. 59 Manager
Catesby W. Clay........... 79 Manager
Gary I. Conley............ 55 Executive Vice President General Counsel & Manager
Carroll R. Crouch......... 48 Secretary & Treasurer
Robert L. Frantz.......... 77 Manager
James G. Kenan III........ 58 Chairman
Peter Kirill, Jr.......... 57 Manager
Chiswell D. Langhorne, Jr. 62 Vice-Chairman
Danny S. Maggard.......... 49 Chief Engineer
Fred N. Parker............ 49 Chief Executive Officer, President & Manager
William T. Young, Jr...... 54 Manager
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.
43
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. 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.
44
Securities All Other
Bonus(2) Underlying Options Compensation(3)
Name and Principal Position(1) Year Salary ($) ($) (#) ($)
- --------------------------- ---- ---------- -------- ------------------ ---------------
James G. Kenan III............ 2002 $ 92,225 $27,474 - $11,796
Chairman of the 2001 89,784 26,935 24(4) 12,397
Board of Directors 2000 92,408 27,722 33(4) 14,870
Fred N. Parker................ 2002 184,997 55,432 - 17,256
President and Chief 2001 179,976 53,993 44(4) 16,090
Executive Officer 2000 172,512 51,754 40(4) 14,870
Gary I. Conley................ 2002 176,473 52,838 - 17,256
Executive Vice President 2001 171,024 51,307 42(4) 16,090
and General Counsel 2000 162,876 48,863 38(4) 14,870
Danny S. Maggard.............. 2002 105,929 31,711 - 12,421
Chief Engineer 2001 101,640 30,492 25(4) 12,380
2000 97,424 29,227 23(4) 8,767
Carroll R. Crouch............. 2002 94,397 28,252 - 12,502
Secretary & Treasurer 2001 86,616 25,985 21(4) 11,390
2000 81,952 24,586 19(4) 10,259
(1) No named executive officer received perquisites or other personal benefits,
securities or other property that, in the aggregate, exceeded ten percent of
such executive's total annual salary and bonus. (2) We traditionally pay a
semi-annual bonus equivalent to 30% of base salary. (3) Consists of our
contributions to the profit sharing plan and director fees. (4) Option grants
shown represent options to purchase shares of the Predecessor Company.
Aggregated Option Exercises and Fiscal Year-End Values
The following table sets forth certain information with respect to our executive
officers named in the Summary Compensation Table concerning the exercise of
options during 2002. As a result of the restructuring there are no unexercised
options held by those individuals as of the end of 2002.
Shares Aggregate
Acquired on Value
Exercise Realized
Name (#) ($)(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.
45
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.
Kentucky River Properties LLC
Successor Company
Membership Units
Beneficially Owned
on March 24, 2003
-------------------------
Percent of
Units Units
Beneficially Beneficially
Name(l) Owned(n) Owned
- ------- ------------ ------------
Kentucky River Coal Corporation (Predecessor Company)(a).... 40,414 87.1
Carroll R. Crouch(j)........................................ 57 (k)
Gary I. Conley(h)........................................... 28 (k)
Danny S. Maggard(i)......................................... 27 (k)
Rutheford B. Campbell, Jr................................... -- --
Catesby W. Clay(a).......................................... -- --
Robert L. Frantz............................................ -- --
James G. Kenan III(a)....................................... -- --
Peter Kirill, Jr.(a)........................................ -- --
Chiswell D. Langhorne, Jr.(a)............................... -- --
Fred N. Parker(a)........................................... -- --
William T. Young, Jr.(a).................................... -- --
All directors and executive officers as a group (11 persons) 40,526 87.3
Kentucky River Coal Corporation
Predecessor Company and
Majority Shareholder of
Successor Company
Shares Beneficially Owned
on March 24, 2003
-------------------------
Percent of
Shares Shares
Beneficially Beneficially
Name(m) Owned(n) Owned
- ------- ------------ ------------
Chiswell D. Langhorne, Jr.(b)............................... 8,466 20.9
Catesby W. Clay(c).......................................... 7,633 18.9
James G. Kenan III(d)....................................... 7,048 17.4
William T. Young, Jr.(e).................................... 1,400 3.5
Peter Kirill, Jr.(f)........................................ 521 1.3
Fred N. Parker(g)........................................... 160 (k)
Rutheford B. Campbell, Jr................................... -- --
Gary I. Conley(h)........................................... -- --
Carroll R. Crouch(j)........................................ -- --
Robert L. Frantz............................................ -- --
Danny S. Maggard(i)......................................... -- --
All directors and executive officers as a group (11 persons) 20,990 51.9
46
(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. 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. 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.
47
PART IV
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.
48
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.
NAME TITLE DATE
- ---- ----- ----
/s/ Rutheford B. Campbell, Jr. March 27, 2003
- -------------------------------
Rutheford B. Campbell, Jr. Manager
/s/ Catesby W. Clay March 27, 2003
- -------------------------------
Catesby W. Clay Manager
/s/ Gary I. Conley March 27, 2003
- -------------------------------
Gary I. Conley Manager
/s/ Robert L. Frantz March 27, 2003
- -------------------------------
Robert L. Frantz Manager
/s/ James G. Kenan III March 27, 2003
- -------------------------------
James G. Kenan III Chairman
/s/ Peter Kirill, Jr. March 27, 2003
- -------------------------------
Peter Kirill, Jr. Manager
/s/ Chiswell D. Langhorne, Jr. March 27, 2003
- -------------------------------
Chiswell D. Langhorne, Jr. Vice-Chairman
/s/ Fred N. Parker March 27, 2003
- -------------------------------
Fred N. Parker President, CEO & Manager
(Principal Executive Officer)
/s/ William T. Young, Jr. March 27, 2003
- -------------------------------
William T. Young, Jr. Manager
/s/ Carroll R. Crouch March 27, 2003
- -------------------------------
Carroll R. Crouch Secretary & Treasurer
(Principal Financial Officer,
Principal Accounting Officer
49
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
50
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
51