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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.
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(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.
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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