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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-K
FOR ANNUAL AND TRANSITION REPORTS PURSUANT TO
SECTIONS 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
[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
[_] 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: 0-23431
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MILLER EXPLORATION COMPANY
(Exact Name of Registrant as Specified in Its Charter)
Delaware 38-3379776
(State or Other (I.R.S. Employer
Jurisdiction Identification No.)
of Incorporation or
Organization)
3104 Logan Valley Road, 49685-0348
Traverse City, Michigan
(Address of Principal (Zip Code)
Executive Offices)
Registrant's telephone number, including area code: (231) 941-0004
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Securities registered pursuant to Section 12(g) of the Act:
Title of each class
Common Stock, $0.01 Par Value
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Indicate by check mark whether the registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [_]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [_]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act) Yes [_] No [X]
Number of shares outstanding of the registrant's Common Stock, $0.01 par
value (excluding shares of treasury stock) as of March 17, 2003: 2,061,253
The aggregate market value of the registrant's voting stock held by
non-affiliates of the registrant as of June 28, 2002: $3,296,271
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the Company's June 19, 2003
annual meeting of stockholders are incorporated by reference in Part III of
this Form 10-K
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PART I
Item 1. Business.
General
Miller Exploration Company ("Miller" or the "Company") is an independent oil
and gas exploration and production company that has developed a base of
producing properties and inventory of prospects concentrated primarily in the
Mississippi Salt Basin of Central Mississippi and the Blackfeet Indian
Reservation. Miller emphasizes the use of 3-D seismic data analysis and
imaging, as well as other emerging technologies, to explore for and develop oil
and natural gas in its core exploration area. Miller is the successor to Miller
Oil Corporation ("MOC"), an independent oil and natural gas exploration and
production business first established in Michigan by members of the Miller
family in 1925. References herein to the "Company" or "Miller" are to Miller
Exploration Company, a Delaware corporation, and its subsidiaries and
predecessors.
On October 11, 2002, the Company effected a one-for-ten reverse stock split
that has been retroactively reflected in this Annual Report.
Core Exploration and Development Regions
Mississippi Salt Basin
The Company believes that the Mississippi Salt Basin, which extends from
Southwestern Alabama across central Mississippi into Northeastern Louisiana,
has numerous undeveloped shallow and deep prospects related to salt dome
geologic structures. A salt dome is a generally dome-shaped intrusion into
sedimentary rock that has a mass of salt as its core. The impermeable nature of
the salt dome structure may act as a mechanism to trap hydrocarbons migrating
through surrounding rock formations. These structures generally are found in
groups in geologic basins that provide the necessary conditions for their
formation. Salt domes are typically subsurface structures that are easily
identified with seismic surveys, but occasionally are visible as surface
expressions. These salt domes range in diameter from 1/2 mile to three miles
and vertically extend from 2,000 feet to nearly 20,000 feet in depth. Salt
domes similar to those of the Mississippi Salt Basin are a significant cause
for major oil and gas accumulations in the Texas and Louisiana Gulf Coast,
Northern Louisiana, East Texas and the offshore Gulf of Mexico. The Mississippi
Salt Basin has produced substantial amounts of oil and natural gas and
continues to be a very active exploration region. Oil and natural gas
discovered in the Mississippi Salt Basin have been produced from reservoirs
with various stratigraphic and structural characteristics, and may be found in
multiple horizons from approximately 3,500 feet to 19,000 feet in depth. Oil
and natural gas reserves around salt domes have been encountered in the Eutaw,
Lower Tuscaloosa, Washita-Fredericksburg, Paluxy, Rodessa, Sligo, Hosston and
Cotton Valley formations, all of which are normally pressured. While the
Company has focused most of its exploration efforts on the deeper Hosston
formation, the shallower horizons remain relatively under-developed. The
Company owns undeveloped leasehold interests in 12,012 gross acres (6,072 net
to the Company) covering 19 known salt domes and related salt structures in the
Mississippi Salt Basin.
With the use of 3-D seismic, the Company has been able to accurately
delineate the flanks of the salt domes and the associated fault patterns. The
Company's 400 square mile 3-D data base may facilitate the identification and
discovery of additional shallow and deep reserves. The Company has continued to
use technologically advanced seismic processing methods including prestack
depth migration on the 3-D data.
The Company owns an interest in 16 producing wells in the Mississippi Salt
Basin that had an aggregate average production rate as of December 31, 2002 of
32.4 million cubic feet of natural gas equivalent per day ("MMcfe/d") gross
(7.1 MMcfe/d net to the Company) at depths ranging from 10,800 to 17,900 feet.
Blackfeet Indian Reservation
The Company entered into an Exploration and Development Agreement (the
"EDA") with K2 America Corporation and K2 Energy Corporation (collectively
referred to as "K2" on June 17, 1998 to explore and
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develop approximately 150,000 gross leasehold acres on the Blackfeet Indian
Reservation (the "Reservation") located in Glacier County, Montana. The EDA
provides that Miller and K2 are equal partners in the K2/Blackfeet Indian
Mineral Development Act ("IMDA") Agreement executed between K2 and the
Blackfeet Tribe (the "Tribe") on March 9, 1998. Terms of the Agreement call for
Miller/K2 to drill three gross wells (1.5 net to the Company) and pay $0.6
million ($0.3 million net to the Company) to the Tribe by May 1, 1999 for which
30,000 gross acres (15,000 net to the Company) will be earned from the Tribe.
Three gross additional wells (1.5 net to the Company) must be drilled and $0.6
million paid ($0.3 million net to the Company) to the Tribe each subsequent
year for four years totaling 15 gross wells (7.5 net to the Company) and $3.0
million ($1.5 million net to the Company) in payments to the Tribe for which
150,000 gross acres (75,000 net to the Company) will be earned. The Tribe will
grant leases with a primary term of eight years and can be held by production
for 45 years and provides for a maximum combined royalty and production tax
burden of 35%. In May 2000, the Company filed a lawsuit against K2 to secure
its rights to develop Tribal acreage covered by the K2 Agreement. See "Legal
Proceedings" for a discussion of this litigation.
The Company entered into a separate IMDA Agreement with the Tribe (the
"Miller Agreement") covering 100,000 Tribal acres that was approved by the
Tribe on February 19, 1999. Terms of the Miller Agreement call for the Company
to pay $1.0 million to the Tribe upon approval and approximately $0.5 million
on the second and third anniversary of the February 19, 1999 Agreement. The
Company is also obligated to drill a minimum of two wells each year with a
total commitment of 10 wells over a five-year period. The Company will earn the
right to lease 10,000 acres with each well drilled, regardless of the outcome
of the well. Separate oil and gas leases covering 640-acre blocks will be
issued with a $2 per acre rental and an eight-year term. Pursuant to the terms
of the EDA executed on June 17, 1998, K2 was offered their exclusive right to
purchase 50% of the Company's interest in the Miller Agreement for cost plus
20% on June 7, 1999. K2 conditionally accepted this offer and, to date, has not
paid for its proportionate share of costs for said lands.
On June 3, 2002, the Company and the Blackfeet Tribal Business Council
entered into an Amended IMDA Agreement (the "Amended IMDA Agreement"). In
connection therewith, the Company deposited $525,000 with the Bureau of Indian
Affairs ("BIA") in anticipation of the review and approval of the Amended IMDA
Agreement by the BIA. Upon receipt of formal notice that the BIA had approved
the Amended IMDA Agreement on July 26, 2002, the $525,000 deposit was
distributed to the Tribe, and the Company had the right, but not the
obligation, to make a second payment of $525,000 within 120 days. The Company
did elect to make the second payment by the November 23, 2002, deadline. Terms
of the Amended IMDA Agreement, among other things, stipulate that the Company
assign to the Tribe a proportionate 2% overriding royalty interest on the
Company's net leasehold on all fee oil and gas leases that the Company owns or
hereafter acquires within the boundaries of the Reservation. The Company may
request an extension of its annual drilling commitment, provided that each
extension shall not exceed one year and the Tribe will not unreasonably
withhold its consent for extension. The amount the Company shall pay to the
Tribe for any extension of annual drilling commitments (which would include
both wells) shall be determined by multiplying $1.00 per acre per year times
the remaining acres not yet subject to the Company's right to convert to leases
at the time of the drilling extension request. Also, in the event the Company
decides not to drill any of the ten commitment wells, the Company may pay the
Tribe $50,000 in lieu of drilling a well ("In Lieu Payment"). In the event the
Company makes an In Lieu Payment, the Company would forfeit its right to lease
the 10,000 acres applicable to the commitment well that was not drilled.
During 2001 and 2000, the Company acquired 12,386 gross non-Tribal acres
(10,451 net to the Company) on the Reservation. The northern boundary of the
Reservation is located approximately 25 miles south of the Waterton, Lookout
Butte and Pincher Creek Fields (Alberta, Canada), which have produced in excess
of 3.8 trillion cubic feet of natural gas ("Tcf"), 0.3 Tcf and 0.5 Tcf,
respectively. The eastern boundary of the Reservation is outlined by the Cut
Bank Oil Field (Glacier County, Montana), which has produced in excess of 175
million barrels of oil ("MMBbl") and 309 Bcf of natural gas.
3
Volumes, Prices and Production Costs
The following table sets forth information with respect to the Company's
production volumes, average prices received and average production costs for
the periods indicated:
Year Ended December 31,
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2002 2001 2000
-------- -------- --------
Production:
Crude oil and condensate (MBbls).............. 139.2 159.6 205.3
Natural gas (MMcf)............................ 2,189.7 3,473.2 5,762.0
Natural gas equivalent (MMcfe)................ 3,024.9 4,430.9 6,993.8
Average sales prices:
Crude oil and condensate ($ per Bbl).......... $ 21.10 $ 21.90 $ 25.82
Natural gas ($ per Mcf)....................... 3.28 4.12 3.60
Natural gas equivalent ($ per Mcfe)........... 3.35 4.02 3.72
Average costs ($ per Mcfe):
Lease operating expenses and production taxes. $ 0.57 $ 0.66 $ 0.43
Depreciation, depletion and amortization...... 2.47 3.03 2.49
General and administrative.................... 0.67 0.42 0.30
Oil and Natural Gas Marketing and Major Customers
Most of the Company's oil and natural gas production is sold under price
sensitive or spot market contracts. The revenues generated by the Company's
operations are highly dependent upon the prices of and demand for oil and
natural gas. The price received by the Company for its oil and natural gas
production depends on numerous factors beyond the Company's control, including
seasonality, the condition of the United States economy, foreign imports,
political conditions in other oil-producing and natural gas-producing
countries, the actions of the Organization of Petroleum Exporting Countries and
domestic government regulation, legislation and policies. Crude oil and natural
gas commodity prices have been volatile and unpredictable during the past three
years. The wide commodity price fluctuations have had a significant impact on
the Company's results of operations, cash flow and liquidity. Although the
Company currently is not experiencing any significant involuntary curtailment
of its oil or natural gas production, market, economic and regulatory factors
in the future may materially affect the Company's ability to sell its oil or
natural gas production. For the year ended December 31, 2002, sales to the
Company's three largest customers were approximately 24%, 21%, and 19%,
respectively, of the Company's oil and natural gas revenues. Due to the
availability of other markets and pipeline connections, the Company does not
believe that the loss of any single oil or natural gas customer would have a
material adverse effect on the Company's results of operations or financial
condition.
Competition
The oil and gas industry is highly competitive in all of its phases. The
Company encounters competition from other oil and natural gas companies in all
areas of its operations, including the acquisition of seismic options and lease
options on properties. The Company's competitors include major integrated oil
and natural gas companies and numerous independent oil and natural gas
companies, individuals and drilling and income programs. Many of the Company's
competitors are large, well established companies with substantially larger
operating staffs and greater capital resources than the Company's and which, in
many instances, have been engaged in the exploration and production business
for a much longer time than the Company. Such companies may be able to pay more
for seismic and lease options on oil and natural gas properties and exploratory
prospects and to define, evaluate, bid for and purchase a greater number of
properties and prospects than the Company's financial or human resources
permit. The Company's ability to explore for oil and natural gas prospects, to
acquire additional properties and to discover reserves in the future will
depend upon its ability to evaluate and select suitable properties and to
consummate transactions in a highly competitive environment.
4
Title to Properties
The Company believes it has satisfactory title to all of its producing
properties in accordance with standards generally accepted in the oil and gas
industry. As is customary in the industry in the case of undeveloped
properties, little investigation of record title is made at the time of
acquisition (other than a preliminary review of local records). Investigations,
including a title opinion of legal counsel, generally are made before
commencement of drilling operations. To the extent title opinions or other
investigations reflect title defects, the Company, rather than the seller of
undeveloped property, typically is responsible to cure any such title defects
at the Company's expense. If the Company were unable to remedy or cure title
defect of a nature such that it would not be prudent to commence drilling
operations on the property, the Company could suffer a loss of its entire
investment in such property. The Company's properties are subject to customary
royalty, overriding royalty, carried, net profits, working and other similar
interests, liens incident to operating agreements, liens for current taxes and
other burdens. In addition, the Company's credit facility is secured by all oil
and natural gas interests and other properties of the Company.
Mississippi Tax Abatement
The State of Mississippi currently has a production tax abatement program
that exempts certain oil and natural gas production from state production
taxes. The exemption as it relates to the Company applies to, among other
things, discovery wells, exploratory wells, and wells developed as a result of
3-D seismic surveys. The exemption is phased out if the average monthly sales
price for oil and gas exceeds $25.00 per Bbl and $3.50 per Mcf, respectively.
The applicable production is exempt for up to five years and the exemption
expires June 30, 2003. In April 1999, the State of Mississippi enacted a bill
that reduced the production tax exemption to 3% of the value of oil and/or gas
for five years for exploratory wells or wells for which 3-D seismic was
utilized (three years for a development well) for wells drilled on or after
July 1, 1999, provided that the average monthly sales price of oil or gas does
not exceed $20 per barrel or $2.50 per Mcf of gas, respectively. The reduced
rate will be repealed on July 1, 2003. During 2002 and 2001, the production tax
exemption has phased in and out, due to the volatility of the average monthly
commodity prices as they relate to the pre-established price limits stipulated
in the state statutes.
Governmental Regulation
The Company's oil and natural gas exploration, production and related
operations are affected from time to time in varying degrees by political
developments and extensive rules and regulations promulgated by federal, state
and local agencies. Failure to comply with such rules and regulations can
result in substantial penalties. The regulatory burden on the oil and gas
industry increases the Company's cost of doing business and affects its
profitability. Although the Company believes it is in substantial compliance
with all applicable laws and regulations, the Company is unable to predict the
future cost or impact of complying with such laws because those laws and
regulations frequently are amended or reinterpreted.
State Regulation
The states in which the Company operates require permits for drilling
operations, drilling bonds and reports concerning operations, and impose other
requirements relating to the exploration and production of oil and natural gas.
These states also have statutes or regulations addressing conservation matters,
including provisions for the unitization or pooling of oil and natural gas
properties, the establishment of maximum rates of production from wells and the
regulation of spacing, plugging and abandonment of such wells. In addition,
state laws generally prohibit the venting or flaring of natural gas, regulate
the disposal of fluids used in connection with operations and impose certain
requirements regarding the ratability of production.
5
Federal Regulation
The Company's sales of natural gas are affected by the availability, terms
and cost of transportation. The price and terms for access to pipeline
transportation are subject to stringent and extensive regulation. The Federal
Energy Regulatory Commission ("FERC") regulates the transportation and sale of
natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 and
the Natural Gas Policy Act of 1978. In the past, the federal government has
regulated the prices at which oil and natural gas can be sold. While sales by
producers of natural gas and all sales of oil and natural gas liquids currently
can be made at uncontrolled market prices, Congress could reenact price
controls in the future.
In recent years, FERC has undertaken various initiatives to increase
competition within the natural gas industry. As a result of initiatives like
FERC Order 636, issued in April 1992, and its progeny, the interstate natural
gas transportation and marketing system has been substantially restructured to
remove various barriers and practices that historically limited non-pipeline
natural gas sellers, including producers, from effectively competing with
interstate pipelines for sales to local distribution companies and large
industrial and commercial customers. The most significant provisions of Order
No. 636 require that interstate pipelines provide transportation separate or
"unbundled" from their sales services, and require that pipelines provide firm
and interruptible transportation service on an open access basis that is equal
for all natural gas supplies. In many instances, the result of Order No. 636
and related initiatives has been to substantially reduce or eliminate the
interstate pipelines' traditional role as wholesalers of natural gas in favor
of providing only storage and transportation services. The courts have largely
affirmed the significant features of Order No. 636 and numerous related orders
pertaining to the individual pipelines, although certain appeals remain pending
and the FERC continues to review and modify its open access regulations.
In particular, the FERC has been conducting a broad review of its
transportation regulations, including how they operate in conjunction with
state proposals for retail gas market restructuring, whether to eliminate
cost-of-service rates for short-term transportation, whether to allocate all
short-term capacity on the basis of competitive auctions, and whether changes
to long-term transportation policies may also be appropriate to avoid a market
bias toward short-term contracts. In February 2000, the FERC issued Order No.
637 amending certain regulations governing interstate natural gas pipeline
companies in response to the development of more competitive markets for
natural gas and natural gas transportation. The goal of Order No. 637 is to
"fine tune" the open access regulation implemented by Order No. 626 to
accommodate subsequent changes in the market. Key provisions of Order No. 637
include (1) waiving the price ceiling for short-term capacity release
transactions until September 30, 2002, subject to review and possible
extension; (2) permitting pipelines to charge different maximum cost-based
rates for peak and off-peak times, and for contracts with different term
lengths; (3) encouraging auctions for pipeline capacity; (4) restricting the
ability of pipelines to impose penalties for imbalances, overruns, and
non-compliance with pipeline operational flow orders; and (5) requiring
pipelines to implement imbalance management services. Most major aspects of
Order No. 637 have been challenged on appeal. The Company cannot predict what
action the FERC will take on these matters in the future, or whether FERC's
actions will survive judicial review.
Similarly, the Texas Railroad Commission recently has changed its
regulations governing transportation and gathering services provided by
intrastate pipelines and gatherers to prohibit undue discrimination in favor of
affiliates. While the changes being implemented and considered by these federal
and state regulators would affect the Company only indirectly, they are
intended to further enhance competition in natural gas markets. Additional
proposals and proceedings that might affect the natural gas industry are
pending before Congress, FERC, state commissions and the courts. The natural
gas industry historically has been very heavily regulated; therefore, there is
no assurance that the less stringent regulatory approach recently pursued by
FERC and Congress will continue.
The price the Company receives from the sale of oil and natural gas liquids
is affected by the cost of transporting products to markets. Effective January
1, 1995, FERC implemented regulations establishing an indexing system for
transportation rates for oil pipelines, which, generally, would index such
rates to inflation,
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subject to certain conditions and limitations. The Company is not able to
predict with certainty the effect, if any, of these regulations on its
operations. However, the regulations may increase transportation costs or
reduce well head prices for oil and natural gas liquids.
Environmental Matters
The Company's operations and properties are subject to extensive and
changing federal, state and local laws and regulations relating to
environmental protection, including the generation, storage, handling,
emission, transportation and discharge of materials into the environment, and
relating to safety and health. The recent trend in environmental legislation
and regulation generally is toward stricter standards, and this trend will
likely continue. These laws and regulations may require the acquisition of a
permit or other authorization before construction or drilling commences;
restrict the types, quantities and concentration of various substances that can
be released into the environment in connection with drilling and production
activities; limit or prohibit construction, drilling and other activities on
certain lands lying within wilderness, wetlands and other protected areas;
require remedial measures to mitigate pollution from former operations such as
plugging abandoned wells; and impose substantial liabilities for pollution
resulting from the Company's operations. The permits required for various of
the Company's operations are subject to revocation, modification and renewal by
issuing authorities. Governmental authorities have the power to enforce
compliance with their regulations, and violators are subject to civil and
criminal penalties or injunction. Management believes that the Company is in
substantial compliance with current applicable environmental laws and
regulations, and that the Company has no material commitments for capital
expenditures to comply with existing environmental requirements. Nevertheless,
changes in existing environmental laws and regulations or in interpretations
thereof could have a significant impact on the Company, as well as the oil and
gas industry in general and thus the Company is unable to predict the ultimate
costs and effects of such continued compliance in the future.
The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA") and comparable state statutes impose strict, joint and several
liability on certain classes of persons who are considered to have contributed
to the release of a "hazardous substance" into the environment. These persons
include the owner or operator of a disposal site or sites where a release
occurred and companies that disposed or arranged for the disposal of the
hazardous substances released at the site. Under CERCLA such persons or
companies may be liable for the costs of cleaning up the hazardous substances
that have been released into the environment and for damages to natural
resources, and it is not uncommon for the neighboring land owners and other
third parties to file claims for personal injury, property damage and recovery
of response costs allegedly caused by the hazardous substances released into
the environment. The Resource Conservation and Recovery Act ("RCRA") and
comparable state statutes govern the disposal of "solid waste" and "hazardous
waste" and authorize imposition of substantial civil and criminal penalties for
noncompliance. Although CERCLA currently excludes petroleum from its definition
of "hazardous substance," state laws affecting the Company's operations impose
clean-up liability relating to petroleum and petroleum-related products. In
addition, although RCRA classifies certain oil field wastes as "non-hazardous,"
such exploration and production wastes could be reclassified as hazardous
wastes thereby making such wastes subject to more stringent handling and
disposal requirements.
The Company has acquired leasehold interests in several properties that for
many years have produced oil and natural gas. Although the Company believes
that the previous owners of these interests used operating and disposal
practices that were standard in the industry at the time, hydrocarbons or other
wastes may have been disposed or released on or under the properties. In
addition, several of the Company's properties are operated by third parties
whose treatment and disposal or release of hydrocarbons or other wastes is not
under the Company's control. These properties and the wastes disposed thereon
may be subject to CERCLA, RCRA and analogous state laws. Notwithstanding the
Company's lack of control over properties operated by others, the failure of
the operator to comply with applicable environmental regulations may, in
certain circumstances, adversely impact the Company.
7
Federal regulations require certain owners or operators of facilities that
store or otherwise handle oil, such as the Company, to prepare and implement
spill prevention, control countermeasure and response plans relating to the
possible discharge of oil into surface waters. The Oil Pollution Act of 1990,
as amended ("OPA"), contains numerous requirements relating to the prevention
of and response to oil spills into waters of the United States. For onshore
facilities that may affect waters of the United States, OPA requires an
operator to demonstrate $10.0 million in financial responsibility, and for
offshore facilities the financial responsibility requirement is at least $35.0
million. Regulations currently are being developed under federal and state laws
concerning oil pollution prevention and other matters that may impose
additional regulatory burdens on the Company. In addition, the federal Clean
Water Act and analogous state laws require permits to be obtained to authorize
discharge into surface waters or to construct facilities in wetland areas. With
respect to certain of its operations, the Company is required to maintain such
permits or meet general permit requirements. The Environmental Protection
Agency ("EPA") has adopted regulations concerning discharges of storm water
runoff. This program requires covered facilities to obtain individual permits,
participate in a group or seek coverage under an EPA general permit. The
Company believes that it will be able to obtain, or be included under, such
permits where necessary, and to make minor modifications to existing facilities
and operations that would not have a material effect on the Company.
Employees
As of March 17, 2003, the Company had 15 full-time employees. None of the
Company's employees are represented by any labor union. To optimize prospect
generation and development, the Company uses the services of independent
consultants and contractors to perform various professional services,
particularly in the area of seismic data mapping, acquisition of leases and
lease options, construction, design, well-site surveillance, permitting and
environmental assessment. Field and on-site productions operation services,
such as pumping, maintenance, dispatching, inspection and testing, generally
are provided by independent contractors. The Company believes that this use of
third-party service providers enhances its ability to contain general and
administrative expenses.
Offices
The Company currently leases approximately 10,500 square feet of office
space for its principal offices in Traverse City, Michigan, and is currently
pursuing an extension of the lease. The Company has sub-leased 1,400 square
feet of this office space. The Company also leases approximately 3,500 square
feet of office space in Jackson, Mississippi, that the Company intends extend
this lease on a month-to-month basis. The Company has closed its Houston,
Texas, office, and terminated all Houston office personnel.
Risks Associated with the Company's Business
Dependence on Exploratory Drilling Activities
The Company's revenues, operating results and future rate of growth are
substantially dependent upon the success of its exploratory drilling program.
Exploratory drilling involves numerous risks, including the risk that no
commercially productive oil or natural gas reservoirs will be encountered. The
cost of drilling, completing and operating wells is often uncertain, and
drilling operations may be curtailed, delayed or canceled as a result of a
variety of factors, including unexpected drilling conditions, pressure or
irregularities in formations, equipment failures or accidents, adverse weather
conditions, compliance with governmental requirements and shortages or delays
in the availability of drilling rigs and the delivery of equipment. Despite the
use of 2-D and 3-D seismic data and other advanced technologies, exploratory
drilling remains a speculative activity. Even when fully utilized and properly
interpreted, 2-D and 3-D seismic data and other advanced technologies only
assist geoscientists in identifying subsurface structures and do not enable the
interpreter to know whether hydrocarbons are in fact present in those
structures. In addition, the use of 2-D and 3-D seismic data and other advanced
technologies requires greater pre-drilling expenditures than traditional
drilling strategies, and the Company could incur losses as a result of such
expenditures. The Company's future drilling activities may not be successful.
There can be no assurance that the Company's overall drilling success rate or
its drilling success rate for activity
8
within a particular region will not decline. Curtailed and/or unsuccessful
drilling activities could have a material adverse effect on the Company's
business, results of operations and financial condition.
The Company may not have any option or lease rights in potential drilling
locations it identifies. Although the Company has identified numerous potential
drilling locations, there can be no assurance that they will ever be leased or
drilled or that oil or natural gas will be produced from these or any other
potential drilling locations. In addition, drilling locations initially may be
identified through a number of methods, some of which do not include
interpretation of 3-D or other seismic data. Actual drilling results are likely
to vary from such statistical results, and such variance may be material.
Similarly, the Company's drilling schedule may vary from its capital budget,
and there is increased risk of such variances from the 2003 capital expenditure
budget because of future uncertainties, including those described above. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations."
Operating Hazards and Uninsured Risks
The Company's operations are subject to hazards and risks inherent in
drilling for and producing and transporting oil and natural gas, such as fires,
natural disasters, explosions, encountering formations with abnormal pressures,
blowouts, craterings, pipeline ruptures and spills, uncontrollable flows of
oil, natural gas or well fluids, any of which can result in the loss of
hydrocarbons, environmental pollution, personal injury claims and other damage
to properties of the Company and others. The Company maintains insurance
against some but not all of the risks described above. In particular, the
insurance maintained by the Company does not cover claims relating to failure
of title to oil and natural gas leases, trespass during 2-D and 3-D survey
acquisition or surface change attributable to seismic operations and, except in
limited circumstances, losses due to business interruption. The Company may
elect to self-insure if management believes that the cost of insurance,
although available, is excessive relative to the risks presented. In addition,
pollution and environmental risks generally are not fully insurable. The
Company occasionally participates in wells on a non-operated basis, which may
limit the Company's ability to control the risks associated with oil and
natural gas operations. The occurrence of an event that is not covered, or not
fully covered, by insurance could have a material adverse effect on the
Company's business, financial condition and results of operations and
potentially could force the Company into bankruptcy.
Volatility of Oil and Natural Gas Prices
The Company's revenues and operating results are substantially dependent
upon the prevailing prices of, and demand for, oil and natural gas.
Historically, the markets for oil and natural gas have been volatile and are
likely to continue to be volatile in the future. Prices for oil and natural gas
are subject to wide fluctuation in response to relatively minor changes in the
supply of and demand for oil and natural gas, market uncertainty and a variety
of additional factors that are beyond the control of the Company. These factors
include global and domestic supplies of oil and natural gas, the ability of the
members of the Organization of Petroleum Exporting Countries to agree to and
maintain oil price and production controls, political instability or armed
conflict in oil-producing regions, the price and level of foreign imports, the
level of consumer demand, the price and availability of alternative fuels, the
availability of pipeline capacity, weather conditions, domestic and foreign
governmental regulations and taxes and the overall economic environment. It is
impossible to predict future oil and natural gas price movements with
certainty. Lower oil and natural gas prices also may reduce the amount of oil
and natural gas that the Company can produce economically.
The Company periodically reviews the carry value of its oil and natural gas
properties under the full cost accounting rules of the Securities and Exchange
Commission ("SEC"). Under these rules, capitalized costs of proved oil and
natural gas properties may not exceed the present value of estimated future net
revenues from proved reserves, discounted at 10%, and the lower of cost or
market value of unproved properties. Application of the "ceiling" test
generally requires pricing future revenue at the unescalated prices in effect
as of the end of each fiscal quarter and requires a writedown for accounting
purposes if the ceiling is exceeded, even if prices were depressed for only a
short period of time. The Company may be required to writedown the carrying
value of its
9
oil and natural gas properties when oil and natural gas prices are depressed or
unusually volatile. If a writedown is required, it would result in a charge to
earnings, but would not impact cash flow from operating activities. Once
incurred, a writedown of oil and natural gas properties is not reversible at a
later date (see "Management's Discussion and Analysis of Financial Condition
and Results of Operations").
Risks Associated with Management and Growth
Any increase in the Company's activities as an operator will increase its
exposure to operating hazards. The Company has relied in the past and expects
to continue to rely on project partners and independent contractors, including
geologists, geophysicists and engineers, that have provided the Company with
seismic survey planning and management, project and prospect generation, land
acquisition, drilling and other services. If the Company increases the number
of projects it is evaluating or in which it is participating, there will be
additional demands on the Company's financial, technical, operational and
administrative resources and continued reliance by the Company on project
partners and independent contractors, and these strains on resources,
additional demands and continued reliance may negatively affect the Company. In
the event the Company does not execute its short term goals of securing a
strategic joint venture partner or selling the Company or its assets, the
Company's ability to grow will depend upon a number of additional factors,
including its ability to obtain leases or options on properties, its ability to
acquire additional 3-D seismic data, its ability to identify and acquire new
exploratory sites, its ability to develop existing sites, its ability to
continue to retain and attract skilled personnel, its ability to maintain or
enter into new relationships with project partners and independent contractors,
the results of its drilling program, hydrocarbon prices, access to capital and
other factors. There can be no assurance that the Company will be successful in
achieving growth or any other aspect of its business strategy.
Reserve Replacement Risk
Except to the extent that the Company conducts successful exploration and
development activities or acquires properties containing proved reserves, or
both, the proved reserves of the Company will decline as reserves are produced.
The Company's future oil and natural gas production is highly dependent upon
its ability to economically find, develop or acquire reserves in commercial
quantities. The business of exploring for or developing reserves is capital
intensive. To the extent cash flow from operations is reduced and external
sources of capital become limited or unavailable, the Company's ability to make
the necessary capital investment to maintain or expand its asset base of oil
and natural gas reserves would be impaired. The Company occasionally
participates in wells as non-operator. The failure of an operator of the
Company's wells to adequately perform operations, or an operator's breach of
the applicable agreements, could adversely impact the Company. In addition,
there can be no assurance that the Company's future exploration and development
activities will result in additional proved reserves or that the Company will
be able to drill productive wells at acceptable costs. Furthermore, although
the Company's revenues could increase if prevailing prices for oil and natural
gas increase significantly, the Company's finding and development costs also
could increase.
Marketability of Production
The marketability of the Company's natural gas production depends in part
upon the availability, proximity and capacity of natural gas gathering systems,
pipelines and processing facilities. The Company delivers natural gas through
gas gathering systems and gas pipelines that it does not own. Federal and state
regulation of oil and natural gas production and transportation, tax and energy
policies, changes in supply and demand and general economic conditions all
could adversely affect the Company's ability to produce and market its oil and
natural gas. Any dramatic change in market factors could have a material
adverse effect on the Company's business, financial condition and results of
operations.
Dependence on Key Personnel
The Company has assembled a team of geologists, geophysicists and engineers,
most of whom are non-employee consultants and independent contractors, having
considerable experience in oil and natural gas
10
exploration and production, including applying 2-D and 3-D imaging technology.
The Company is dependent upon the knowledge, skills and experience of these
experts to provide 2-D and 3-D imaging and to assist the Company in reducing
the risks associated with its participation in oil and natural gas exploration
projects. In addition, the success of the Company's business also depends to a
significant extent upon the abilities and continued efforts of its management.
The Company does not maintain key-man life insurance with respect to any of its
employees. The loss of services of key management personnel or the Company's
technical experts and consultants, or the inability to attract additional
qualified personnel, experts or consultants, could have a material adverse
effect on the Company's business, financial condition, results of operations,
development efforts and ability to grow. There can be no assurance that the
Company will be successful in attracting and/or retaining its key management
personnel or technical experts or consultants.
Technological Changes
The oil and gas industry is characterized by rapid and significant
technological advancements and introductions of new products and services
utilizing new technologies. As others use or develop new technologies, the
Company may be placed at a competitive disadvantage, and competitive pressures
may force the Company to implement such new technologies at substantial costs.
In addition, other oil and gas companies may have greater financial, technical
and personnel resources that allow them to enjoy technological advantages and
may in the future allow them to implement new technologies before the Company.
There can be no assurance that the Company will be able to respond to such
competitive pressures and implement such technologies on a timely basis or at
an acceptable cost. One or more of the technologies currently utilized by the
Company or implemented in the future may become obsolete. In such cases, the
Company's business, financial condition and results of operations could be
materially adversely affected. If the Company is unable to utilize the most
advanced commercially available technology, the Company's business, financial
condition and results of operations could be materially and adversely affected.
Substantial Capital Projects
The Company makes and will continue to make varying levels of capital
expenditures in connection with its exploration and development projects. The
Company intends to finance these capital expenditures with cash flow from
operations as currently projected. Additional financing may be required in the
future to fund the Company's developmental and exploratory drilling and seismic
activities. No assurance can be given as to the availability or terms of any
such additional financing that may be required or that financing will continue
to be available under the existing or new financing arrangements. If additional
capital sources are not available to the Company, its drilling, seismic and
other activities may be curtailed and its business, financial conditions and
results of operations could be materially adversely affected.
Indebtedness
As of December 31, 2002, the Company had total indebtedness of $0.8 million.
The Company's indebtedness could have important consequences. For example, it
could (i) increase the Company's vulnerability to adverse economic and industry
conditions; (ii) require the Company to dedicate a substantial portion of its
cash flow from operations to payments on indebtedness, thereby reducing the
availability of its cash flow to fund working capital, capital expenditures and
other general corporate purposes; (iii) limit the Company's flexibility in
planning for, or reacting to, changes in its business and the oil and gas
industry; (iv) place the Company at a disadvantage compared to its competitors
that have less debt, on a relative basis, and (v) limit the Company's ability
to borrow additional funds. In addition, failing to comply with debt covenants
could result in an event of default which, if not cured or waived, could
adversely affect the Company.
Influence of Certain Stockholders
As of December 31, 2002, the Company's directors, executive officers and
certain of their affiliates, beneficially owned approximately 19% of the
Company's outstanding Common Stock. Guardian Energy
11
Management Corp. ("Guardian") also owns approximately 19% of the Company's
outstanding stock. Accordingly, if these stockholders act together, as a group,
they will be able to substantially control the outcome of stockholder votes,
including votes concerning the election of directors, the adoption or amendment
of provisions in the Company's Certificate of Incorporation or Bylaws and the
approval of mergers or other significant corporate transactions. The existence
of these levels of ownership concentrated in a few persons makes it unlikely
that any other holder of Common Stock will be able to affect the management or
direction of the Company. These factors also may have the effect of delaying or
preventing a change in the management or voting control of the Company.
Certain Antitakeover Considerations
The Company's Certificate of Incorporation and Bylaws include certain
provisions that may have the effect of delaying, deterring or preventing a
future takeover or change in control of the Company without the approval of the
Company's Board of Directors. Such provisions also may render the removal of
directors and management more difficult. Among other things, the Company's
Certificate of Incorporation and/or Bylaws: (i) provide for a classified Board
of Directors serving staggered three-year terms; (ii) impose restrictions on
who may call a special meeting of stockholders; (iii) include a requirement
that stockholder action be taken only by unanimous written consent or at
stockholder meetings; (iv) specify certain advance notice requirements for
stockholder nominations of candidates for election to the Board of Directors
and certain other stockholder proposals; and (v) impose certain restrictions
and supermajority voting requirements in connection with specified business
combinations not approved in advance by the Company's Board of Directors. In
addition, the Company's Board of Directors, without further action by the
stockholders, may cause the Company to issue up to 2.0 million shares of
preferred stock, $0.01 par value ("Preferred Stock"), on such terms and with
such rights, preferences and designations as the Board of Directors may
determine. Issuance of such Preferred Stock, depending upon the rights,
preferences and designations thereof, may have the effect of delaying,
deterring or preventing a change in control of the Company. Further, certain
provisions of the Delaware General Corporation Law (the "Delaware Law") impose
restrictions on the ability of a third party to effect a change in control and
may be considered disadvantageous by a stockholder.
Our Common Stock may be De-listed from the Nasdaq Small Cap Market
The Company's Common Stock currently is traded on the Nasdaq Small Cap
Market. Under the Nasdaq Small Cap Market rules, a company will be de-listed if
the closing stock price drops below $1.00 per share for 30 consecutive trading
days or the Company fails to maintain evidence of a market value of its
publicly held shares of at least $1.0 million. If the Company's stock were
de-listed from the Nasdaq Small Cap Market, the Company's stockholders would
find it more difficult to dispose of their shares or obtain accurate quotations
as to their market value, and the market price of the Company's stock would
likely decline further.
Forward-Looking Statements
This annual report on Form 10-K includes forward-looking statements made
pursuant to the safe harbor provisions of the Private Securities Litigation
Reform Act of 1995. Forward-looking statements can be identified by the words
"anticipates," "expects," "intends," "plans," "projects," "believes,"
"estimates" and similar expressions. The Company has based the forward-looking
statements relating to its operations on current expectations, estimates and
projections about the Company and the oil and gas industry in general. These
statements are not guarantees of future performance and involve risks,
uncertainties and assumptions that the Company cannot predict. In addition, the
Company has based many of these forward-looking statements on assumptions about
future events that may prove to be inaccurate. Accordingly, the Company's
actual outcomes and results may differ materially from what is expressed or
forecasted in the forward-looking statements. Any differences could result from
a variety of factors including the following: fluctuations in crude oil and
natural gas prices; failure or delays in achieving expected production from oil
and gas development projects; uncertainties inherent in predicting oil and gas
reserves and oil and gas reservoir performance; lack of exploration success;
12
disruption or interruption of the Company's production facilities due to
accidents or political events; availability of future financing alternatives;
availability of future equity infusions; ability to obtain promoted and carried
working interests for future capital expenditures; liability for remedial
actions under environmental regulations; liability resulting from litigation;
world economic and political conditions; and changes in tax and other laws
applicable to the Company's business.
Item 2. Properties.
Oil and Natural Gas Reserves
The Company's estimated total proved reserves of oil and natural gas as of
December 31, 2002 and 2001, and the present values of estimated future net
revenues attributable to these reserves as of those dates were as follows:
As of December 31,
----------------------
2002 2001
-------- ---------
(Dollars in thousands,
except per unit data)
Net Proved Reserves:
Crude oil (MBbl).................................................. 298.0 601.3
Natural gas (MMcf)................................................ 5,009.0 7,325.4
Natural gas equivalent (MMcfe).................................... 6,797.0 10,933.2
Net Proved Developed Reserves:
Crude oil (MBbl).................................................. 228.1 586.8
Natural gas (MMcf)................................................ 5,009.0 7,325.4
Natural gas equivalent (MMcfe).................................... 6,377.6 10,846.2
Estimated future net revenues before income taxes(1)................. $ 23,683 $ 20,414
Present value of estimated future net revenues before income taxes(2) $ 19,049 $ 16,457
Standardized measure of discounted estimated future net cash flows(3) $ 19,049 $ 16,457
- --------
(1) The period-end prices (net of applicable basis adjustments) for crude oil
were $27.50 per Bbl and $16.72 per Bbl at December 31, 2002 and 2001,
respectively. The period-end prices (net of applicable basis adjustments)
for natural gas were $4.88 per Mcf and $2.55 per Mcf at December 31, 2002
and 2001, respectively.
(2) The present value of estimated future net revenues attributable to the
Company's reserves was prepared using constant prices as of the calculation
date, discounted at 10% per annum on a pre-tax basis.
(3) The standardized measure of discounted estimated future net cash flows
represents discounted estimated future net cash flows attributable to the
Company's reserves after income taxes, calculated in accordance with
Statement of Financial Accounting Standards ("SFAS") No. 69. The balance in
2002 and 2001 has not been reduced by income taxes due to the tax basis of
the properties and net operating loss and depletion carryforwards.
The reserve estimates reflected above, as of December 31, 2002 and 2001,
were prepared by Miller and Lents, Ltd., independent petroleum engineers, and
are part of their reserve reports on the Company's oil and natural gas
properties.
In accordance with applicable requirements of the SEC, estimates of the
Company's proved reserves and future net revenues are made using sales prices
estimated to be in effect as of the date of such reserve estimates and are held
constant throughout the life of the properties (except to the extent a contract
specifically provides for escalation). Estimated quantities of proved reserves
and future net revenues therefrom are affected by oil and natural gas prices,
which have fluctuated widely in recent years. There are numerous uncertainties
inherent in estimating oil and natural gas reserves and their estimated values,
including many factors beyond the control of the Company. The reserve data set
forth in this Form 10-K represents only estimates. Reservoir engineering is a
subjective process of estimating underground accumulations of oil and natural
gas that cannot be measured in an
13
exact manner. The accuracy of any reserve estimate is a function of the quality
of available data and of engineering and geologic interpretation and judgment.
As a result, estimates of different engineers, including those used by the
Company, may vary. In addition, estimates of reserves are subject to revision
based upon actual production, results of future development and exploration
activities, prevailing oil and natural gas prices, operating costs and other
factors. The revisions may be material. Accordingly, reserve estimates often
are different from the quantities of oil and natural gas that ultimately are
recovered and are highly dependent upon the accuracy of the assumptions upon
which they are based. The Company's estimated proved reserves have not been
filed with or included in reports to any federal agency.
Estimates with respect to proved reserves that may be developed and produced
in the future often are based upon volumetric calculations and upon analogy to
similar types of reserves rather than actual production history. Estimates
based on these methods generally are less reliable than those based on actual
production history. Subsequent evaluation of the same reserves based upon
production history will result in variations in the estimated reserves and the
variations may be substantial.
Drilling Activities
The Company drilled, or participated in the drilling of, the following
number of wells during the periods indicated:
Year Ended December 31,
-----------------------------
2002 2001 2000
--------- --------- ---------
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
Exploratory Wells:
Oil............... -- -- -- -- 3 0.6
Natural gas....... -- -- -- -- 1 0.2
Non-productive.... 3 1.9 9 4.1 3 0.9
-- --- -- --- -- ---
Total......... 3 1.9 9 4.1 7 1.7
== === == === == ===
Development Wells(1):
Oil............... 3 0.3 4 1.2 1 0.1
Natural gas....... 1 0.1 1 0.2 -- --
Non-productive.... 1 0.2 1 -- -- --
-- --- -- --- -- ---
Total......... 5 0.6 6 1.4 1 0.1
== === == === == ===
At December 31, 2002, the Company was in the process of drilling and/or
completing 3 gross wells (0.4 net to the Company) that are not reflected in the
above table. Subsequent to December 31, 2002, two of the wells in process
became producing oil wells, while the third well will be plugged and abandoned.
Productive Wells and Acreage
Productive Wells
The following table sets forth the Company's ownership interest as of
December 31, 2002 in productive oil and natural gas wells in the areas
indicated:
Oil Natural Gas Total
--------- ----------- ---------
Region Gross Net Gross Net Gross Net
------ ----- --- ----- --- ----- ---
Mississippi Salt Basin 6 0.6 10 4.0 16 4.6
Alabama............... 3 0.2 -- -- 3 0.2
Michigan Basin........ -- -- 1 0.9 1 0.9
-- --- -- --- -- ---
Total.............. 9 0.8 11 4.9 20 5.7
== === == === == ===
14
Productive wells consist of producing wells and wells capable of production,
including wells waiting on pipeline connection. Wells that are completed in
more than one producing horizon are counted as one well. Of the gross wells
reported above, none are producing from multiple horizons.
Acreage
Undeveloped acreage includes leased acres on which wells have not been
drilled or completed to a point that would permit the production of commercial
quantities of oil and natural gas, regardless of whether such acreage contains
proved reserves. A gross acre is an acre in which an interest is owned. A net
acre is deemed to exist when the sum of fractional ownership interests in gross
acres equals one. The number of net acres is the sum of the fractional
interests owned in gross acres expressed as whole numbers and fractions
thereof. The following table sets forth the approximate developed and
undeveloped acreage in which the Company held a leasehold mineral or other
interest at December 31, 2002:
Developed Undeveloped Total
----------- --------------- ---------------
Region Gross Net Gross Net Gross Net
------ ----- ----- ------- ------- ------- -------
Mississippi Salt Basin 7,343 3,242 12,012 6,072 19,355 9,314
Montana(1)............ -- -- 262,366 170,511 262,366 170,511
Texas................. -- -- 5,240 802 5,240 802
Michigan Basin/Other.. 320 176 1,807 628 2,127 804
----- ----- ------- ------- ------- -------
Total.............. 7,663 3,418 281,425 178,013 289,088 181,431
===== ===== ======= ======= ======= =======
- --------
(1) An exploration agreement with K2 America Corporation and K2 Energy Corp. in
Montana, representing 150,000 gross, 75,000 net undeveloped acres above, is
currently involved in litigation. The Company does not represent nor can it
be assumed that the litigation will be favorably resolved. See "Legal
Proceedings" for a discussion of this litigation.
All of the leases for the undeveloped acreage summarized in the preceding
table will expire at the end of their respective primary terms unless the
existing leases are renewed or production has been obtained from the acreage
subject to the lease before that date, in which event the lease will remain in
effect until the cessation of production. To this end, the Company's projected
drilling schedule takes into consideration not only the attractiveness of
individual prospects, but the lease expirations as well. The following table
sets forth the minimum remaining terms of leases for the total gross and net
acreage at December 31, 2002:
Acres Expiring
---------------
Gross Net
------- -------
Twelve Months Ending:
December 31, 2003.. 4,929 2,595
December 31, 2004.. 4,781 2,393
December 31, 2005.. 1,479 1,151
Thereafter..... 277,899 175,292
------- -------
Total.......... 289,088 181,431
======= =======
Item 3. Legal Proceedings.
On May 1, 2000, the Company filed a lawsuit in the Federal District Court
for the District of Montana against K2 America Corporation and K2 Energy
Corporation (collectively referred to in this section as "K2"). The Company's
lawsuit included certain claims of relief and allegations by the Company
against K2, including breach of contract arising from failure by K2 to agree to
escrow, repudiation, and rescission; specific performance; declaratory relief;
partition of K2 lands that are subject to the K2 Agreement; negligence; and
15
tortuous interference with contract. The lawsuit is on file with the Federal
District Court for the District of Montana, Great Falls Division and is not
subject to protective order. In an order dated September 4, 2001, the Federal
District Court dismissed without prejudice the lawsuit against K2 and deferred
the case to the Blackfeet Tribal Court for determination of whether it has
jurisdiction over the claims made by the Company. The Company has filed a
complaint in Blackfeet Tribal Court in Montana against K2 substantially based
on the grounds asserted in the action previously filed in District Court, while
arguing to the Tribal Court that proper jurisdiction is with the Federal
District Court. K2 has since filed a counterclaim against the Company alleging
that alleged actions by the Company damaged K2 by denying K2 the ability to
participate in the Miller/Blackfeet IMDA and damaged K2's goodwill with Tribal
officials so as to impede other development initiatives on the Reservation. The
Company answered K2's counterclaim by asserting that any damages K2 may have
incurred were caused in whole or in part by their own negligence, conduct, bad
faith or fault. The Company believes the K2 counterclaim is without merit and
will continue to vigorously contest it. The Blackfeet Tribal Business Council
unanimously voted on May 1, 2002, to reaffirm the Company's 50% interest in the
K2/Blackfeet IMDA covering 150,000 net Tribal mineral acres, over-turning a
previous Tribal Business Council decision.
On May 1, 2000, the Company gave notice to the Blackfeet Tribal Business
Council demanding arbitration of all disputes as provided for under the
Miller/Blackfeet IMDA dated February 19, 1999, and pursuant to the K2/Blackfeet
IMDA dated May 30, 1997. The Bureau of Indian Affairs ("BIA") responded to the
Company's request for arbitration by stating that it was the BIA's position
that the Miller/Blackfeet IMDA was terminated. The Company filed an appeal
brief with the Interior Department Appeals Division.
On January 25, 2002, the Interior Department Appeals Division vacated the
BIA's purported termination of the Miller/Blackfeet IMDA to allow arbitration
to proceed. In order to avoid further delay and to avoid the uncertainty and
costs of further pursuing the dispute (including arbitration and litigation)
and to place the parties on a footing that will enable them to pursue a
productive business relationship, the Company and the Blackfeet Tribal Business
Council entered into the amended IMDA Agreement in June 2002.
The Company was a defendant in a lawsuit filed June 1, 1999 by Energy
Drilling Company ("Energy Drilling"), in the Parish of Catahoula, Louisiana
arising from a blowout of the Victor P. Vegas #1 well that was drilled and
operated by the Company. Energy Drilling, the drilling rig contractor on the
well, was claiming damages related to the destruction of their drilling rig and
related costs amounting to approximately $1.2 million, plus interest,
attorneys' fees and costs. In January 2001, the Federal District Court judge
ruled against the Company on two of the three claims filed in this case with
interest and day-rate charges left undetermined. This ruling was appealed by
the Company to the U.S. Fifth Circuit Court of Appeals with the lower court
ruling being upheld. This ruling is significant for oil and gas operators in
the industry using the Independent Association of Drilling Contractors'
("IADC") standard drilling contracts. The Circuit Court of Appeals interpreted
the IADC contract to assign responsibility for loss of the drilling
contractor's equipment to the operator under a catastrophic event not the fault
of the operator and without determining whether there was an unsound location.
In September 2002, the judgment amount totaling approximately $780,000 was paid
by the Company's insurance carrier.
In August 2002, the Court of Appeals ruled in favor of the Company on
disputed interest and day-rate charges. Energy Drilling has filed an appeal of
the Court of Appeals' decision, which remains unresolved. In February 2003, the
District Court ruled in favor of Energy Drilling on disputed attorney fees. The
Company has filed an appeal of this ruling.
The Company was named in a lawsuit brought by Victor P. Vegas, the landowner
of the surface location of the blowout well referenced above. The suit was
filed July 20, 1999 in the Parish of Orleans, Louisiana, claiming unspecified
damages related to environmental and other matters. Under a Department of
Environmental Quality ("DEQ") approved plan, site remediation has been
completed and periodic testing was being performed. On December 11, 2001, the
plaintiff submitted a remediation plan for more extensive clean-up and a
settlement demand. In February 2002, the Company filed a remediation plan with
the Louisiana DEQ for approval. In July
16
2002, the Civil District Court ruled that the DEQ would not have primary
jurisdiction and that a jury trial would be held.
During the fourth quarter of 2002, several meetings were held with the
plaintiff in an effort to resolve this matter. On January 10, 2003, a
confidential settlement agreement was signed, which releases the Company from
all liability from all present and future claims, subject to certain express
reservations associated with this property. The settlement agreement requires
that the Company pay the agreed to settlement amount by March 26, 2003 and
complete the clean up of the property in accordance with a final Louisiana DNR
Office of Conservation Compliance Order. The Company believes that all defense
costs, settlement costs and final clean up costs will be covered by its general
liability and well control insurance.
The Company believes it has meritorious defenses to the unresolved claims
discussed above and intends to vigorously contest them. The Company does not
believe that the final outcome of these matters will have a material adverse
effect on the Company's operating results, financial condition or liquidity.
Due to the uncertainties inherent in litigation, however, no assurances can be
given regarding the final outcome of each action.
Item 4. Submission of Matters to a Vote of Security Holders.
At the October 9, 2002, Special Meeting of the Common Stockholders, a
proposal to amend the Company's Certificate of Incorporation to effect a
reverse stock split of all of the outstanding shares of Common Stock of the
Company, at the ratio of one for ten was approved. The vote approving this
proposal was as follows:
For Against Abstain Votes Withheld
--- ------- ------- --------------
17,179,330 1,062,000 6,250 --
17
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
Matters.
On May 16, 2002, the Company received notification from the Nasdaq Stock
Market that the Company was not in compliance with the minimum bid requirements
for continued listing on the Nasdaq National Market. On May 22, 2002, the
Company requested an oral hearing before a Nasdaq Listing Qualifications Panel
to review the determination. The hearing took place on July 18, 2002, and on
September 3, 2002, the Company received a favorable ruling and notification of
Nasdaq's decision to extend the National Market listing of the Company's
securities. Also, on June 21, 2002, the Company received notice that it had not
maintained a minimum market value of publicly held shares of $5.0 million, as
required for continued listing on the Nasdaq National Market and was provided a
90-day grace period through September 19, 2002, to regain compliance. Both the
Nasdaq National Market and Small Cap Market have a $1 minimum trading price
requirement to remain listed. The Board approved and the Company requested
shareholder approval, for shareholders of record on September 5, 2002, to
affect a reverse stock split of one for ten to satisfy the minimum bid and
continued listing requirements. On September 27, 2002, the Company received
notification that Nasdaq had transferred the Company's securities to their
Small Cap Market because the Company was unable to raise the market value of
its publicly held shares to the $5.0 million minimum level within the grace
period provided. The one for ten reverse stock split proposal was approved at a
special meeting of the shareholders and the Company affected the reverse stock
split on October 11, 2002. Subsequent to the reverse stock split, the closing
bid price of the Company's stock surpassed the $1 minimum price, and has since
remained above said minimum.
As of September 5, 2002, the Company estimates that there were approximately
2,050 beneficial holders of its Common Stock.
The following table sets forth the high and low bid information for the
Company's Common Stock for the periods indicated, as reported by The Nasdaq
National Market, and commencing October 11, 2002, the Nasdaq Small Cap Market:
Year Ended December 31,
-------------------------
2002 2001
----------- -------------
High Low High Low
----- ----- ------ ------
First Quarter. $8.00 $4.00 $16.25 $10.63
Second Quarter 7.50 2.30 14.40 8.20
Third Quarter. 4.70 1.60 14.90 3.00
Fourth Quarter 2.20 0.70 11.90 6.00
The figures in this table have been adjusted to reflect the one-for-ten
reverse stock split. The Company has not in the past, and does not intend to
pay cash dividends on its Common Stock in the foreseeable future. The Company
currently intends to retain earnings, if any, for the future operation and
development of its business. The Company's credit facility contains provisions
that may have the effect of limiting or prohibiting the payment of dividends.
18
Item 6. Selected Financial Data
The following table presents selected historical consolidated financial data
of the Company as of the dates and for the periods indicated. The historical
consolidated financial data as of and for each of the five years in the period
ended December 31, 2002. The financial data is derived from the consolidated
financial statements which have been audited by Plante & Moran, PLLC, for the
year ended December 31, 2002 and Arthur Andersen LLP, independent public
accountants, for the years ended December 31, 2001, 2000, 1999, and 1998. The
following data should be read in conjunction with "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and the Consolidated
Financial Statements.
Year Ended December 31,
---------------------------------------------
2002 2001 2000 1999 1998
------- -------- ------- ------- --------
(In thousands, except per share data)
Statement of Operations Data:
Revenues:
Natural gas......................................... $ 7,182 $ 14,304 $20,745 $17,266 $ 18,336
Crude oil and condensate............................ 2,937 3,495 5,300 3,465 2,646
Other operating revenues............................ 161 269 522 200 169
------- -------- ------- ------- --------
Total operating revenues............................ 10,280 18,068 26,567 20,931 21,151
Operating expenses:
Lease operating expenses and production taxes....... 1,711 2,944 3,030 1,704 3,363
Depreciation, depletion and amortization............ 7,458 13,431 17,457 16,066 15,933
General and administrative.......................... 2,013 1,860 2,097 2,776 2,815
Cost ceiling writedown.............................. 7,000 15,500 -- -- 35,085
------- -------- ------- ------- --------
Total operating expenses........................ 18,182 33,735 22,584 20,546 57,196
------- -------- ------- ------- --------
Operating income (loss)................................ (7,902) (15,667) 3,983 385 (36,045)
Interest expense(1).................................... (631) (1,184) (4,322) (3,519) (1,635)
------- -------- ------- ------- --------
Loss before income taxes and extraordinary item........ (8,533) (16,851) (339) (3,134) (37,680)
Income tax provision (credit)(2)....................... (5,743) (459) 472 (1,152) 4,120
------- -------- ------- ------- --------
Net loss before extraordinary item..................... $(2,790) $(16,392) $ (811) $(1,982) $(41,800)
Extraordinary item--
Gain (loss) from early extinguishment of debt, less
applicable income taxes(3)........................ 2,432 -- (166) -- --
------- -------- ------- ------- --------
Net loss............................................... $ (358) $(16,392) $ (977) $(1,982) $(41,800)
Basic and diluted earnings (loss) per share............ $ (0.18) $ (8.43) $ (0.73) $ (1.57) $ (37.49)
Weighted average shares outstanding.................... 1,982 1,944 1,336 1,263 1,115
As of December 31,
---------------------------------------------
2002 2001 2000 1999 1998
------- -------- ------- ------- --------
(In thousands)
Balance Sheet Data (at end of period):
Working capital........................................ $(1,929) $ (3,941) $(1,383) $(4,200) $(15,925)
Oil and gas properties, net............................ 18,738 33,275 52,033 58,837 80,014
Total assets........................................... 20,849 37,587 59,878 68,611 85,968
Long-term debt, excluding current portion.............. -- 6,696 11,196 25,610 31,837
Equity................................................. 17,109 17,407 33,926 23,995 24,749
19
- --------
(1) A $1.7 million one-time non-cash charge related to the Guardian Transaction
(more fully described in Note 6 to the Consolidated Financial Statements)
was recorded in interest expense in 2000.
(2) Upon consummation of the Combination Transaction in 1998 (see Note 1 to the
Consolidated Financial Statements), the Company was required to record a
one-time non-cash charge to earnings of $5.4 million in connection with
establishing a deferred tax liability on the balance sheet in accordance
with SFAS No. 109, "Accounting for Income Taxes." Based on estimates of
future anticipated taxable income and also taking into consideration the
Company's net operating loss and depletion carryforwards of approximately
$35.2 million, the Company has determined that there should be no deferred
tax liability recorded on the Company's financial statements. Therefore,
the Company recorded a $5.7 million income tax credit to eliminate the
entire deferred tax liability balance in 2002.
(3) The extraordinary gain from early extinguishment of debt in 2002,
represents the outstanding principal balance and related accrued interest
associated with the note payable to Veritas DGC Land, Inc. that was
forgiven at December 31, 2002, as more fully described in Note 5 to the
Consolidated Financial Statements.
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.
Overview
Miller is an independent oil and gas exploration, development and production
company that has developed a base of producing properties and inventory of
prospects concentrated primarily in Mississippi.
Results of Operations
The following table summarizes production volumes, average sales prices and
average costs for the Company's oil and natural gas operations for the periods
presented (in thousands, except per unit amounts):
Year Ended December 31,
----------------------------
2002 2001 2000
-------- -------- --------
Production volumes:
Crude oil and condensate (MBbls).............. 139.2 159.6 205.3
Natural gas (MMcf)............................ 2,189.7 3,473.2 5,762.0
Natural gas equivalent (MMcfe)................ 3,024.9 4,430.9 6,993.8
Revenues:
Natural gas................................... $ 7,182 $ 14,304 $ 20,745
Crude oil and condensate...................... 2,937 3,495 5,300
Operating expenses:
Lease operating expenses and production taxes. $ 1,711 $ 2,944 $ 3,030
Depletion, depreciation and amortization...... 7,458 13,431 17,457
Cost ceiling writedown........................ 7,000 15,500 --
General and administrative.................... 2,013 1,860 2,097
Interest expense................................. $ 631 $ 1,184 $ 4,322
Extraordinary gain (loss)........................ $ 2,432 -- $ (166)
Net loss......................................... $ (358) $(16,392) $ (977)
Average sales prices:
Crude oil and condensate ($ per Bbl).......... $ 21.10 $ 21.90 $ 25.82
Natural gas ($ per Mcf)....................... 3.28 4.12 3.60
Natural gas equivalent ($ per Mcfe)........... 3.35 4.02 3.72
Average costs ($ per Mcfe):
Lease operating expenses and production taxes. $ 0.57 $ 0.66 $ 0.43
Depletion, depreciation and amortization...... 2.47 3.03 2.49
Cost ceiling writedown........................ 2.31 3.50 --
General and administrative.................... 0.67 0.42 0.30
20
Year Ended December 31, 2002 compared to Year Ended December 31, 2001
Oil and natural gas revenues for the year ended December 31, 2002 decreased
43% to $10.1 million from $17.8 million for the year ended December 31, 2001.
Oil and natural gas revenues for the years ended December 31, 2002 and 2001
include approximately $(0.2) million and $(1.9) million of hedging losses,
respectively (see "Risk Management Activities and Derivative Transactions"
below).
Production volumes for natural gas during the year ended December 31, 2002
decreased 37% to 2,190 MMcf from 3,473 MMcf for the year ended December 31,
2001. Oil production volumes decreased 13% to 139 MBbls for the year ended
December 31, 2002 compared to 160 MBbls for the same period of 2001. The
decrease in production is primarily attributable to a 66% reduction in capital
expenditures in 2002, less than expected results from recent drilling
activities, the sale of certain properties and normal production decline rates.
Average realized natural gas prices decreased 20% to $3.28 per Mcf for the year
ended December 31, 2002 from $4.12 per Mcf for the year ended December 31,
2001. This was due to decreased demand for natural gas as a result of an
abnormally mild 2001/2002 winter in the United States and the stagnant economy,
both of which depressed natural gas commodity prices for the first half of
2002. Average realized oil prices decreased 4% to $21.10 per barrel during the
year ended December 31, 2002 from $21.90 per barrel for the year ended December
31, 2001.
Lease operating expenses ("LOE") and production taxes for the year ended
December 31, 2002 decreased 42% to $1.7 million from $2.9 million for the year
ended December 31, 2001. The LOE component decreased 32% to $1.3 million from
$1.9 million due primarily to workovers on four wells in 2001. Three of the
workovers were unsuccessful and the respective wells were plugged and abandoned
in 2001.
Production taxes decreased 60% to $0.4 million for 2002 compared to $1.0
million for 2001. Production taxes attributable to Mississippi properties were
approximately 72% and 80% of the total for 2002 and 2001, respectively. The
State of Mississippi production tax is calculated by taking 6% of the gross
value of the crude oil and natural gas sold. Therefore, the decrease in
production tax expense is attributable to the decrease in oil and natural gas
revenues experienced on a year over year basis. The State of Mississippi has
enacted legislation that provides for production tax exemptions during periods
of low commodity prices. The exemptions apply when the state-wide average
monthly price for oil or natural gas falls below a level pre-determined by
statute. Due to oil and natural gas price volatility, the Mississippi
production tax exemptions have phased in and out over the past two years. In
2002, more exemptions were in effect; therefore, production taxes decreased.
The production tax exemptions are scheduled to expire on June 30, 2003, which
will make all Mississippi properties subject to the same 6% statutory rate.
Depreciation, depletion and amortization ("DD&A") expense for the year ended
December 31, 2002 decreased 44% to $7.5 million from $13.4 million for the year
ended December 31, 2001, primarily due to decreased production volumes and a
reduced property cost basis after ceiling test writedowns in the second quarter
of 2002 and in 2001.
General and administrative expense for the year ended December 31, 2002
increased 8% to $2.0 million from $1.9 million for the same period in 2001.
This increase is attributable to professional fees associated with a potential
asset acquisition transaction that was terminated in March 2002, expenses
related to the transfer of Company securities to the Nasdaq Small Cap Market
and related proxy costs for the Company's reverse stock split. These
non-recurring costs were partially offset by a reduction in salaries and
benefits, resulting from a reduction of eight full-time employees during 2002,
and a salary cut taken effective July 1, 2002, by certain management personnel.
With the closing of the Houston, Texas, office, a reduced staff level and other
cost cutting measures, the Company estimates general and administrative
expenses for 2003 will decrease to approximately $1.5 million.
Using unescalated period-end prices at June 30, 2002, of $3.24 per Mcf of
natural gas and $26.86 per barrel of oil, the Company recognized a non-cash
cost ceiling writedown of $7.0 million for the quarter then ended. The cost
ceiling writedown is attributable to the combined effect of the $5.7 million
reversal of deferred income taxes
21
as June 30, 2002 (as more fully discussed in Note 3 to the Consolidated
Financial Statements), less than expected results from drilling activities, the
inability to sell or drill prospects on favorable terms utilizing the Company's
existing leasehold and 3-D seismic database and a decrease in the value of the
Company's unproved properties as a result of the transfer of proprietary rights
in 3-D seismic data to Veritas (as more fully discussed in Note 5). The Company
recognized a non-cash cost ceiling writedown of $15.5 million for the year
ended December 31, 2001. Sharply lower commodity prices at period-end, less
than expected results from drilling activities and expiration of certain leased
acreage were the primary factors for the cost ceiling writedown in 2001.
Interest expense for the year ended December 31, 2002 decreased 47% to $0.6
million from $1.2 million for the year ended December 31, 2001. The lower
interest expense in 2002 is attributable to the combined effect of lower
interest rates on the Company's credit facility and note payable to Veritas DGC
Land Inc. ("Veritas"), lower average outstanding principal balances for the
aforementioned obligations and an approximate $160,000 decrease in interest
paid on royalty payments escheated to the State of Mississippi. It should also
be noted that approximately $0.2 million of the $0.6 million of 2002 interest
expense is a non-cash item and represents the interest obligation that Veritas
has agreed to extinguish, as more fully discussed below and in Note 5 to the
Consolidated Financial Statements.
On June 28, 2002, the Company entered into the Second Amendment to
Promissory Note, Warrant and Registration Rights Agreement ("Second Amendment
Agreement") with Vertias, as more fully discussed in Note 5 to the Consolidated
Financial Statements. Pursuant to the Second Amendment Agreement, if all
principal payments required prior to December 31, 2002, were made timely,
Veritas would agree to extinguish the remaining principal balance and
respective accrued interest totaling approximately $2.4 million. All required
payments were made timely by the Company, and the early extinguishment of debt
totaling $2.4 million has been reported as an extraordinary gain on the
Company's Statement of Operations for the year ended December 31, 2002. In
exchange for early extinguishment of debt, Veritas received, among other
things, the aforesaid principal payments, an overriding royalty interest in
certain leases of the Company, and received the proprietary rights to certain
3-D seismic data, as more fully discussed in Note 5 to the Consolidated
Financial Statements.
Net loss for the year ended December 31, 2002 decreased to $(0.4) million
from $(16.4) million for the year ended December 31, 2001, as a result of the
factors described above.
Year Ended December 31, 2001 compared to Year Ended December 31, 2000
Oil and natural gas revenues for the year ended December 31, 2001 decreased
32% to $17.8 million from $26.0 million for the year ended December 31, 2000.
Oil and natural gas revenues for the years ended December 31, 2001 and 2000
include approximately $(1.9) million and $(2.0) million of hedging losses,
respectively (see "Risk Management Activities and Derivative Transactions"
below).
Production volumes for natural gas during the year ended December 31, 2001
decreased 40% to 3,473 MMcf from 5,762 MMcf for the year ended December 31,
2000. Oil production volumes decreased 22% to 160 MBbls for the year ended
December 31, 2001 compared to 205 MBbls for the same period of 2000. The
decrease in production is primarily attributable to less than expected results
from recent drilling activities. Average realized natural gas prices increased
14% to $4.12 per Mcf for the year ended December 31, 2001 from $3.60 per Mcf
for the year ended December 31, 2000 due to high natural gas commodity prices
the Company experienced during the first quarter of 2001 that were partially
offset by low prices during the fourth quarter of 2001. Average realized oil
prices decreased 15% to $21.90 per barrel during the year ended December 31,
2001 from $25.82 per barrel for the year ended December 31, 2000 as oil
commodity prices fell due primarily to the effect of the depressed economy in
the United States during 2001 and the global oil supply imbalance.
Lease operating expenses ("LOE") and production taxes for the year ended
December 31, 2001 decreased 3% to $2.9 million from $3.0 million for the year
ended December 31, 2000. The LOE component was unchanged at $1.9 million for
2001 and 2000.
22
Production taxes, however, decreased 9% to $1.0 million for 2001 compared to
$1.1 million for 2000. The State of Mississippi production tax is calculated by
taking 6% of the gross value of the crude oil and natural gas sold. Therefore,
the change in production tax expense should approximate the same percentage
decrease that oil and natural gas revenues experienced on a year over year
basis. The State of Mississippi has enacted legislation that provides for
production tax exemptions during periods of low commodity prices. The
exemptions apply when the state-wide average monthly price for oil or natural
gas falls below a level pre-determined by Statute. Due to oil and natural gas
price volatility, the Mississippi production tax exemptions have phased in and
out over the past two years. The exemptions were phased out for more of 2001
compared to 2000, which partially offset the decrease in production taxes.
Depreciation, depletion and amortization ("DD&A") expense for the year ended
December 31, 2001 decreased 23% to $13.4 million from $17.5 million for the
year ended December 31, 2000, primarily due to decreased production volumes and
a reduced property cost basis after ceiling test writedowns in the second and
third quarters of 2001.
General and administrative expense for the year ended December 31, 2001
decreased 11% to $1.9 million from $2.1 million for the same period in 2000.
This decrease is attributable to continuing efforts to control costs.
Using unescalated period-end prices (net of applicable basis adjustments) at
December 31, 2001, of $2.55 per Mcf of natural gas and $16.72 per barrel of
oil, the Company has recognized a non-cash cost ceiling writedown of $15.5
million for the year then ended. Sharply lower commodity prices at period-end,
less than expected results from recent drilling activities and expiration of
leaseholds are the primary factors for the aggregate cost ceiling writedown.
Using unescalated period-end prices at December 31, 2000 of $8.65 per Mcfe, the
Company had no impairment of oil and gas properties.
Interest expense for the year ended December 31, 2001 decreased 73% to $1.2
million from $4.3 million for the year ended December 31, 2000. The higher
interest expense in 2000 is attributable to $1.7 million of non-cash interest
expense that was required to be recorded in connection with the Guardian
Convertible Note Payable and the issuance of common stock warrants to Guardian,
more fully discussed in "Capital Resources and Liquidity" below and in Note 6
to the Consolidated Financial Statements and higher effective interest rates
and average outstanding debt balance in 2000 compared to 2001.
On July 19, 2000, the Company entered into a senior credit facility with
Bank One, Texas, N.A. ("Bank One") which replaced the then existing credit
facility with Bank of Montreal. In connection with extinguishment of the debt
with Bank of Montreal, the Company reported an extraordinary loss, net of
income taxes of $0.2 million for the remaining unamortized debt expenses for
the year ended December 31, 2000.
Net loss for the year ended December 31, 2001 increased to $16.4 million
from $1.0 million for the year ended December 31, 2000, as a result of the
factors described above.
Capital Resources and Liquidity
Operating, Investing, and Financing Activities
The Company's primary ongoing source of liquidity is cash generated from
operations. Net cash provided by operating activities was $3.2 million, $13.4
million, and $16.1 million in 2002, 2001, and 2000, respectively. The decrease
in cash provided in 2002 compared to 2001 was primarily the result of a decline
in operating income caused by declining production and lower average commodity
prices. The decrease in cash provided in 2001 compared to 2000 was primarily
attributable to a decline in operating income caused by declining production.
The Company's primary use of cash has been for its exploration and
development activities and debt reduction. Net cash provided by (used in)
investing activities was $0.3 million, $(10.0) million, and $(7.6)
23
million in 2002, 2001, and 2000, respectively. The decrease in cash used in
2002 compared to 2001 was attributable to decreased exploration and development
expenditures and an increase in proceeds from the sale of oil and gas
properties. The increase in cash used in 2001 compared to 2000 was due
primarily to increased exploration and development expenditures.
The Company's primary uses of capital from financing activities have been to
pay down the balance of the Company's credit facility. Net cash used in
financing activities was $(3.7) million, $(5.5) million, and $(9.9) million in
2002, 2001, and 2000, respectively. The decrease in cash used in 2002 compared
to 2001 is attributable to a lower net reduction in long-term debt in 2002
compared to 2001. The decrease in cash used in 2001 compared to 2000 is
attributable to a lower net reduction in long-term debt and the result of the
$7.0 million in proceeds from the issuance of common stock in 2000.
Financing Arrangements
During the past few years the Company has financed various insurance policy
premiums. The amounts financed each year are less than $250,000, and the notes
payable are fully paid off by each fiscal year end. The terms of these notes
require monthly payments of principal and interest and the notes bear interest
at rates competitive with the Company's credit facility.
On July 18, 2000, the Company entered into a new senior credit facility with
Bank One, which replaced the then existing credit facility with Bank of
Montreal. The Bank One credit facility has a 30-month term with an interest
rate of either Bank One prime plus 2% or LIBOR plus 4%, at the Company's
option. The Company's obligations under the credit facility are secured by a
lien on all of its real and personal property. The maturity date of the credit
facility has been extended to August 1, 2003, from January 18, 2003. The
Company's new borrowing base determined by Bank One as of March 1, 2003, was
$3.75 million. Commencing April 1, 2003, the borrowing base will be reduced by
$0.25 million per month until maturity. At December 31, 2002, the outstanding
balance under the Company's credit facility with Bank One was $0.8 million.
The Bank One credit facility includes certain negative covenants that impose
restrictions on the Company with respect to, among other things, incurrence of
additional indebtedness, limitations on financial ratios, making investments
and mergers and consolidation. The Company requested and obtained a waiver
through August 1, 2003, from Bank One for non-compliance with the maintenance
of specified levels of commodity hedge covenants as required by the credit
facility.
On April 14, 1999, the Company issued a $4.7 million note payable to one of
its suppliers, Veritas DGC Land, Inc. (the "Veritas Note"), for the outstanding
balance due to Veritas for past services provided in 1998 and 1999. The
principal obligation under the Veritas Note was originally due on April 15,
2001. On July 19, 2000, the note was amended as more fully described below.
On April 14, 1999, the Company also entered into an agreement (the "Warrant
Agreement") to issue warrants to Veritas that entitle Veritas to purchase
shares of common stock in lieu of receiving cash payments for the accrued
interest obligations under the Veritas Note. The Warrant Agreement required the
Company to issue warrants to Veritas in conjunction with the signing of the
Warrant Agreement, as well as on the six and, at the Company's option, 12 and
18 month anniversaries of the Warrant Agreement. The warrants issued equal 9%
of the then current outstanding principal balance of the Veritas Note. The
number of shares issued upon exercise of the warrants issued on April 14, 1999,
and on the six-month anniversary was determined based upon a five-day weighted
average closing price of the Company's Common Stock at April 14, 1999. The
exercise price of each warrant is $0.10 per share. On April 14, 1999, warrants
exercisable for 32,276 shares of Common Stock were issued to Veritas in
connection with execution of the Veritas Note. On October 14, 1999 and April
14, 2000, warrants exercisable for another 32,276 and 45,500 shares,
respectively, of Common Stock were issued to Veritas. The Company ratably
recognized the prepaid interest into expense over the period to which it
related. For the year ended December 31, 2000, the Company recognized non-cash
interest expense of approximately
24
$752,000 related to the Veritas Note Payable. Effective November 1, 2000,
Veritas exercised 50,000 warrants to receive 49,693 shares (net of exercise
price) of Company common stock.
On July 19, 2000, the Company entered into the First Amendment to Promissory
Note, Warrant and Registration Rights Agreement ("First Amendment Agreement").
Under the terms of the First Amendment Agreement, the maturity of the Veritas
Note was extended to July 21, 2003 from April 15, 2001 and the expiration date
for all warrants issued was extended until June 21, 2004. The annual interest
rate was reduced to 93/4% from 18%, provided the entire Note balance was paid
in full by December 31, 2001. The Veritas note was not paid in full by December
31, 2001, and the interest rate was increased to 133/4% annually. Interest was
payable on each October 15 and April 15 until the note is paid in full. The
Company has paid additional interest of approximately $225,000 at the
incremental 4% rate for the period of October 15, 2000 through April 14, 2002.
Interest was required to be paid in warrants under the terms of the First
Amendment Agreement until the Company was in compliance with the net borrowing
base formula as defined in the Bank One credit facility, at which time interest
would only be paid in cash. Since October 15, 2000, all required interest
payments have been made in cash.
On June 28, 2002, the Company entered into the Second Amendment Agreement.
Concurrently with the execution of the Second Amendment Agreement, the Company
made a $600,000 principal payment. Under terms of the Second Amendment
Agreement, the Veritas Note was amended as follows: (1) The maturity of the
Veritas Note was changed to December 31, 2002 from July 21, 2003; (2) The
interest rate was changed to 93/4%; (3) The past due annual interest rate was
changed to 12% from 133/4%; and (4) Six principal payments of $150,000,
totaling $900,000 were required, and were payable on or before the last day of
each month commencing on July 31, 2002. In the event that all six principal
payments mentioned above were made timely, an interest payment was not due on
October 15, 2002, and Veritas would forgive the remaining principal balance of
$2.2 million and any accrued interest outstanding under the Veritas Note and
the Company would recognize a gain of approximately $2.4 million. In the event
that these six principal payments were not timely made, the entire principal
balance outstanding under the Veritas Note would be accelerated and become due
and payable upon demand and would accrue interest at the past due rate from the
date of the Second Amendment Agreement until the Veritas Note is paid in full.
At December 31, 2002, the Company has made all required principal payments
pursuant to the Second Amendment Agreement. Therefore, the remaining principal
balance and related accrued interest payable obligations have been extinguished
by Veritas and the Company has recorded a $2.4 million extraordinary gain as
reported in the Consolidated Statements of Operations for the year ended
December 31, 2002.
As an inducement for Veritas to enter into the Second Amendment Agreement:
(1) the Company has granted Veritas an overriding royalty interest on the
Company's entire leasehold that is not held by production and leases acquired
through July 31, 2003 (excluding leases within the boundaries of the Blackfeet
Indian Reservation); (2) the Company transferred its proprietary rights in
approximately 140 square miles of 3-D seismic data with respect to certain
areas within the Mississippi Salt Basin to Veritas in exchange for a 25-year
license allowing the Company the use of same data. The Company has also agreed
to an optional transfer fee on its currently licensed data, which in the
aggregate totals approximately $3.1 million in the event of a change in control
of the Company; and (3) certain Company Directors who own or control shares of
Common Stock of the Company and are considered major stockholders have agreed
to provide certain tag-along rights in the event one of these major
stockholders negotiates a sale of Company Common Stock with a private party.
The Second Amendment Agreement also extended the expiration date of the
warrants to July 31, 2004 from June 21, 2004.
Liquidity
The Company's primary ongoing source of liquidity is from cash generated
from operations and from the Company's use of available borrowing capacity
under its credit facility. During the course of the year, the amount
outstanding under the credit facility will vary, as the Company's approach is
to borrow under the facility as needed to fund capital expenditures and
pay-down the balance when cash is available in order to reduce interest charges.
25
As of December 31, 2002, the Company had a working capital deficit of $1.9
million, primarily due to decreased cash flow attributable to decreased
production volumes, lower commodity prices, and reclassification of the
outstanding credit facility balance to short term (as more fully described in
Note 5 to the Consolidated Financial Statements in "Item 1. Financial
Statements"). Also, approximately $1.2 million of current liabilities
represents suspended revenues owed primarily to unlocated royalty owners. If
the owners cannot be located, the revenues will be escheated to the State of
Mississippi after five years. As mentioned above, the remaining balance of the
Veritas note and related accrued interest was forgiven at December 31, 2002,
and the Company has recognized a $2.4 million extraordinary gain in its 2002
Consolidated Financial Statements. Actual capital expenditures for the year
ended December 31, 2002 were approximately $3.4 million compared to $10.0
million for the same period of 2001. The Company expects that it will utilize
its operational cash flows for 2003 to meet its working capital requirements
and fund its capital expenditures.
The Company's business plan for 2003 involves pursuing various opportunities
to identify strategic joint venture partners and/or to sell the Company or all
or a portion of its assets in an effort to maximize shareholder return.
Management of the Company believes the Company is presently a very good
prospect for potential joint venture partners and/or the sale of the Company or
its assets, given the higher commodity prices, solid production base in
Mississippi, prospect opportunities in Montana, Mississippi and Alabama and a
low debt level.
The Company has engaged a financial advisor, C. K. Cooper & Co., to assist
with execution of the business plan for 2003. Capital expenditures in 2003 for
exploration and development activities will be limited to select projects as
determined by the Company's Board of Directors until a decision is made
regarding the above mentioned strategic efforts.
The Company's revenues, profitability, and ability to borrow funds or obtain
additional capital are highly dependent on future oil and gas production and
prevailing prices of oil and natural gas. The production and sale of oil and
natural gas involves many factors that are subject to numerous uncertainties
including reservoir risk, mechanical failure, transportation issues, human
error, weather and volatile commodity prices.
The Company has experienced substantial working capital requirements,
primarily due to the Company's exploration and development program, less than
expected results from drilling activities and its debt reduction initiative.
While the Company believes that cash flow from operations should allow the
Company to implement its present business strategy, additional debt or equity
financing may be required to fund future operations. A significant decrease in
cash flow from operations or the inability to borrow under the credit facility
could have a material adverse effect on the Company, including curtailment of
any exploration activities and further cost cutting measures.
Future Financing Obligations
The Company's credit facility has been extended to August 1, 2003. Based
upon the Company's estimated oil and gas reserves at the end of 2002, the
Company believes it will have sufficient oil and gas assets to support its
borrowing base when the credit facility expires and, if necessary, the Company
would plan to either amend, extend or replace the credit facility (with the
same or alternative lender) before it expires. In the event the Company is
unable to amend, extend or replace the credit facility, the Company believes it
would be able to fulfill this obligation through the use of available cash
flows; the identification of additional sources for debt or equity financings;
or the sale of some or all of its oil and gas properties. However, these
expectations are dependent on several internal and external factors. If these
factors differ, from management's expectations, they could have a material
adverse effect on the Company's ability to meet future financing obligations
and cause the Company to curtail its exploration and development activities.
26
Off-Balance Sheet Arrangements
The Company does not have any off-balance sheet financing arrangements,
except for the operating lease obligations presented below.
Contractual Obligations and Commercial Commitments
Summarized below are the contractual obligations and other commercial
commitments of the Company as of December 31, 2002.
Payments Due by Period
------------------------------------
2007 and
Total 2003 2004 2005 2006 Beyond
----- ---- ----- ----- ---- --------
(in thousands)
Contractual Obligations
Long-Term Debt............................. $800 $800 $ -- $-- $ -- $--
Operating Leases........................... 60 60 -- -- -- --
---- ---- ---- --- ---- ---
Total Contractual Cash Obligations..... $860 $860 $ $-- $ -- $--
==== ==== ==== === ==== ===
Commitment Expiration by Period
-------------------------------------
2007 and
Total 2003 2004 2005 2006 Beyond
----- ---- ----- ----- ----- --------
(in thousands)
Commercial Commitments
Bank One Credit Facility*. $800 $800 $ -- $ -- $ -- $ --
- --------
* As of December 31, 2002, $0.8 million was outstanding under the credit
facility, which is included in the Long-Term Debt balance in the table
above. The credit facility matures on August 1, 2003, therefore, the $0.8
million outstanding balance is reported as current portion of long-term debt
in the Company's Consolidated Balance Sheets.
Risk Management Activities and Derivative Transactions
The Company uses a variety of financial derivative instruments
("derivatives") to manage exposure to fluctuations in commodity prices. To
qualify for hedge accounting, derivatives must meet the following criteria: (i)
the item to be hedged exposes the Company to price risk; and (ii) the
derivative reduces that exposure and is designated as a hedge.
Commodity Price Hedges
The Company periodically enters into certain derivatives for a portion of
its oil and natural gas production to achieve a more predictable cash flow, as
well as to reduce the exposure to price fluctuations. The Company's hedging
arrangements apply to only a portion of its production, provide only partial
price protection against declines in oil and natural gas prices and limit
potential gains from future increases in prices. Such hedging arrangements may
expose the Company to risk of financial loss in certain circumstances,
including instances where production is less than expected, the Company's
customers fail to purchase contracted quantities of oil or natural gas or a
sudden unexpected event materially impacts oil or natural gas prices. For
financial reporting purposes, gains and losses related to hedging are
recognized as oil and natural gas revenues during the period the hedge
transactions occur. The Company expects that the amount of hedge contracts that
it has in place will vary from time to time. For the years ended December 31,
2002, 2001, and 2000, the Company hedged 59%, 54%, and 54% of its oil and gas
production, respectively, and as of December 31, 2002, the Company had 0.3 Bcfe
of open oil and natural gas contracts for the months of January 2003 through
September 2003. If all of these open contracts had been settled as of December
31, 2002, the Company would have owed approximately $0.1 million.
27
The Company adopted SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities", amended by Statement No. 137, "Accounting for Derivative
Instruments and Hedging Activities-Deferral of the Effective Date of FASB
Statement No. 133" and Statement No. 138, "Accounting for Certain Derivatives
and Certain Hedging Activities" (hereinafter collectively referred to as SFAS
No. 133). SFAS No. 133 requires that every derivative instrument, including
certain derivative instruments embedded in other contracts, be recorded in the
balance sheet as either an asset or liability measured at its fair value. Refer
to Note 8 of the Consolidated Financial Statements for further discussion of
the adoption of SFAS No. 133.
Critical Accounting Policies
The results of operations, as presented above, are based on the application
of accounting principles generally accepted in the United States. The
application of these principles often requires management to make certain
judgments, assumptions, and estimates that may result in different financial
presentations. The Company believes that certain accounting principles are
critical in understanding its financial statements.
Full Cost Method of Accounting
The Company uses the full cost method of accounting for its oil and natural
gas properties. Under this method, all acquisition, exploration and development
costs, including any general and administrative costs that are directly
attributable to the Company's acquisition, exploration and development
activities, are capitalized in a "full cost pool" as incurred. The Company
records depletion of its full cost pool using the unit-of-production method.
SEC Regulation S-X, Rule 4-10 requires companies reporting on a full cost basis
to apply a ceiling test wherein the capitalized costs within the full cost
pool, net of deferred income taxes, may not exceed the net present value of the
Company's proved oil and gas reserves plus the lower of cost or market of
unproved properties. Any such excess costs should be charged against earnings.
Use of Estimates
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenue and expense during
the reporting periods. Accordingly, actual results could differ from these
estimates. Significant estimates include depreciation, depletion and
amortization of proved oil and natural gas properties. Oil and natural gas
reserve estimates, which are the basis for unit-of-production depletion and the
cost ceiling test, are inherently imprecise and are expected to change as
future information becomes available.
New Accounting Standards
In addition to the identified critical accounting policies discussed above,
future results could be affected by a number of new accounting standards that
recently have been issued.
SFAS No. 141, Business Combinations
SFAS No. 141, issued in July 2001, requires that all business combinations
initiated after June 30, 2001, be accounted for under the purchase method and
the use of the pooling-of-interests method is no longer permitted. The adoption
of SFAS No. 141, effective July 1, 2001, will result in the Company accounting
for any future business combinations under the purchase method of accounting,
but will not change the method of accounting used in previous business
combinations.
28
SFAS No. 142, Goodwill and Other Intangible Assets
SFAS No. 142, also issued in July 2001, requires that goodwill no longer be
amortized to earnings, but instead by reviewed for impairment on an annual
basis. The Company has no goodwill recorded as of December 31, 2001, so the
Company does not expect an impact from the adoption of this standard.
SFAS No. 143, Accounting for Asset Retirement Obligations
SFAS No. 143, issued in August 2001, requires adoption as of January 1,
2003. The standard requires entities to record the fair value of a liability
for an asset retirement obligation in the period in which the obligation is
incurred. When the liability is initially recorded, the entity capitalizes a
cost by increasing the carrying amount of the related long-lived asset. Over
time, the liability is accreted to its present value each period, and the
capitalized cost is depreciated over the useful life of the related asset. Upon
settlement of the liability, an entity either settles the obligation for its
recorded amount or incurs a gain or loss upon settlement. The Company is
currently studying the effects of the new standard.
SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets
SFAS No. 144, issued in October 2001, supersedes SFAS No. 121. The
accounting model for long-lived assets to be disposed of by sale applies to all
long-lived assets, including discontinued operations, and replaces the
provisions of APB Opinion No. 30 for the disposal of segments of a business.
SFAS No. 144 requires that those long-lived assets be measured at the lower of
carrying amount or fair value less cost to sell, whether reported in continuing
operations or in discontinued operations. SFAS No. 144 has been adopted
effective January 1, 2002; however, the Company has not been impacted from this
adoption since it follows the full cost method of accounting which requires
long-lived oil and gas property costs to be tested for impairment based on its
full cost ceiling (refer to previously referenced Critical Accounting Policies).
Effects of Inflation and Changes in Price
Crude oil and natural gas commodity prices have been very volatile and
unpredictable during the three year period ending December 31, 2002. The wide
fluctuations that have occurred during the past three years have had a
significant impact on the Company's results of operations, cash flow,
liquidity, and financial budgeting. Recent rates of inflation have had a
minimal effect on the Company.
Environmental and Other Regulatory Matters
The Company's business is subject to certain federal, state and local laws
and regulations relating to the exploration for, and the development,
production and transportation of, oil and natural gas, as well as environmental
and safety matters. Many of these laws and regulations have become more
stringent in recent years, often imposing greater liability on a larger number
of potentially responsible parties.
Although the Company believes it is in substantial compliance with all
applicable laws and regulations, the requirements imposed thereby frequently
change and become subject to interpretation, and the Company is unable to
predict the ultimate cost of compliance with these requirements or their effect
on its operations. Any suspensions, terminations or inability to meet
applicable bonding requirements could materially adversely affect the Company's
business, financial condition and results of operations. Although significant
expenditures may be required to comply with governmental laws and regulations
applicable to the Company, compliance has not had a material adverse effect on
the earnings or competitive position of the Company. Future regulations may add
to the cost of, or significantly limit, drilling activity. Refer to Note 9 of
the Consolidated Financial Statements for further discussion of legal and
environmental matters.
29
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Market Risk Information
The market risk inherent in the Company's derivatives is the potential loss
arising from adverse changes in commodity prices. The prices of oil and natural
gas are subject to fluctuations resulting from changes in supply and demand. To
reduce price risk caused by the market fluctuations, the Company's policy is to
hedge (through the use of derivatives) not more than 60% of future production.
Because commodities covered by these derivatives are substantially the same
commodities that the Company sells in the physical market, no special
correlation studies other than monitoring the degree of convergence between the
derivative and cash markets are deemed necessary. The changes in market value
of these derivatives have a high correlation to the price changes of oil and
natural gas.
A sensitivity analysis model was used to calculate the fair values of the
Company's derivatives rates in effect at December 31, 2002. The sensitivity
analysis involved increasing or decreasing the forward rates by a hypothetical
10% and calculating the resulting unfavorable change in the fair values of the
derivatives. The results of this analysis, which may differ from actual
results, showed this type of change would not have a material impact on the
fair value of the derivatives previously stated ($0.1) million at December 31,
2002 (as discussed in the "Risk Management Activities and Derivative
Transactions" section above).
Item 8. Financial Statements and Supplementary Data.
The information required hereunder is included in this report as set forth
in the "Index to Financial Statements" on Page F-1.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
None.
30
PART III
Item 10. Directors and Executive Officers of the Registrant.
The information regarding directors of the Company contained under the
captions "Board of Directors," "Executive Officers", "Section 16(a) Beneficial
Ownership Reporting Compliance", and "Code of Ethics" in the definitive Proxy
Statement for the Company's annual meeting of stockholders to be held on June
19, 2003 is here incorporated by reference.
Item 11. Executive Compensation.
The information contained under the captions "Compensation of Directors" and
"Executive Compensation" in the definitive Proxy Statement for the Company's
annual meeting of stockholders to be held on June 19, 2003 is here incorporated
by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
The information contained under the captions "Voting Securities," "Security
Ownership of Certain Beneficial Owners" and "Security Ownership of Management"
in the definitive Proxy Statement for the Company's annual meeting of
stockholders to be held on June 19, 2003 is here incorporated by reference.
Item 13. Certain Relationships and Related Transactions.
The information contained under the captions "Voting Securities," "Security
Ownership of Certain Beneficial Owners," "Security Ownership of Management" and
"Equity Compensation Plan Information" in the definitive Proxy Statement for
the Company's annual meeting of stockholders to be held on June 19, 2003 is
here incorporated by reference.
Item 14. Controls and Procedures.
Item 14(a). Evaluation of Disclosure Controls and Procedures
Within 90 days prior to the filing date of this report, the Company's chief
executive officer and chief financial officer carried out an evaluation of the
effectiveness of the Company's disclosure controls and procedures. Based on
that evaluation, the Company's chief executive officer and chief financial
officer believe (i) that the Company's disclosure controls and procedures are
designed to ensure that information required to be disclosed by the Company in
the reports it files under the Securities Exchange Act of 1934 is recorded,
processed, summarized and reported within the periods specified in the SEC's
rules and forms, and that such information is accumulated and communicated to
the Company's management as appropriate to allow timely decisions required
disclosure, and (ii) that the company's disclosure controls and procedures are
effective.
Item 14(b). Changes in Internal Controls
There have been no significant changes in the Company's internal controls or
in other factors that could significantly affect the Company's internal
controls subsequent to the evaluation referred to in Item 14(a) above, nor have
there been any corrective actions with regard to significant deficiencies or
material weaknesses.
31
PART IV
Item 15. Exhibits, Financial Statements, Schedules, and Reports on Form 8-K.
Item 15(a)(1). Financial Statements. See "Index to Financial Statements"
set forth on page F-1.
Item 15(a)(2). Financial Statement Schedules. Financial statement
schedules have been omitted because they are either not required, not
applicable or the information required to be presented is included in the
Company's financial statements and related notes.
Item 15(a)(3). Exhibits. The following exhibits are filed as a part of
this report.
Exhibit No. Description
- ----------- -----------
2.1 Exchange and Combination Agreement dated November 12, 1997. Previously filed as exhibit 2.1
to the Company's Registration Statement on Form S-1 (333-40383), and here incorporated by
reference.
2.2(a) Letter Agreement amending Exchange and Combination Agreement. Previously filed as an exhibit
to the Company's Registration Statement on Form S-1 (333-40383), and here incorporated by
reference.
2.2(b) Letter Agreement amending Exchange and Combination Agreement. Previously filed as an exhibit
to the Company's Registration Statement on Form S-1 (333-40383), and here incorporated by
reference.
2.2(c) Letter Agreement amending Exchange and Combination Agreement. Previously filed as an exhibit
to the Company's Registration Statement on Form S-1 (333-40383), and here incorporated by
reference.
2.3(a) Agreement for Purchase and Sale dated November 25, 1997 between Amerada Hess Corporation
and Miller Oil Corporation. Previously filed as an exhibit to the Company's Registration
Statement on Form S-1 (333-40383), and here incorporated by reference.
2.3(b) First Amendment to Agreement for Purchase and Sale dated January 7, 1998. Previously filed as
an exhibit to the Company's Registration Statement on Form S-1 (333-40383), and here
incorporated by reference.
3.1 Certificate of Incorporation of the Registrant. Previously filed as an exhibit to the Company's
Registration Statement on Form S-1 (333-40383), and here incorporated by reference.
3.2 Certificate of Amendment to the Certificate of Incorporation of the Registrant. Previously filed as
an exhibit to the Company's Quarterly Report on Form 10-Q filed on November 14, 2002.
3.3 Bylaws of the Registrant. Previously filed as an exhibit to the Company's Quarterly Report on
Form 10-Q for the quarter ended June 30, 1998, and here incorporated by reference.
4.1 Certificate of Incorporation. See Exhibit 3.1.
4.2 Bylaws. See Exhibit 3.3.
4.3 Form of Specimen Stock Certificate. Previously filed as an exhibit to the Company's Registration
Statement on Form S-1 (333-40383), and here incorporated by reference.
4.4 Warrant between Miller Exploration Company and Guardian Energy Management Corp. dated
July 11, 2000, exercisable for 1,562,500 shares of the Company's Common Stock. Previously
filed as an exhibit to the Company's Current Report on Form 8-K filed July 25, 2000, and here
incorporated by reference.
32
Exhibit No. Description
- ----------- -----------
4.5 Warrant between Miller Exploration Company and Guardian Energy Management Corp. dated
July 11, 2000, exercisable for 2,500,000 shares of the Company's Common Stock. Previously
filed as an exhibit to the Company's Current Report on form 8-K filed July 25, 2000, and here
incorporated by reference.
4.6 Warrant between Miller Exploration Company and Guardian Energy Management Corp. dated
July 11, 2000, exercisable for 9,000,000 shares of the Company's Common Stock. Previously
filed as an exhibit to the Company's Current Report on Form 8-K filed July 25, 2000, and here
incorporated by reference.
4.7 Amendment to Promissory Note, Warrant and Rights Agreement between Miller Exploration
Company and Veritas DGC Land, Inc., dated July 19, 2000. Previously filed as an exhibit to the
Company's Current Report on Form 8-K filed July 25, 2000, and here incorporated by
reference.
10.1(a) Stock Option and Restricted Stock Plan of 1997.* Previously filed as an exhibit to the Company's
Annual Report on Form 10-K for the year ended December 31, 1997, and here incorporated by
reference.
10.1(b) Amended and Restated Stock Option and Restricted Stock Plan of 1997 dated February 25, 2000.*
10.1(c) Amended and Restated Stock Option and Restricted Stock Plan of 1997 dated March 20, 2001.*
10.1(d) Amended and Restated Stock Option and Restricted Stock Plan of 1997 dated March 18, 2002.*
10.2(a) Form of Stock Option Agreement.* Previously filed as an exhibit to the Company's Annual
Report on Form 10-K for the year ended December 31, 1997, and here incorporated by
reference.
10.2(b) Form of Restricted Stock Agreement.* Previously filed as an exhibit to the Company's Annual
Report on Form 10-K for the year ended December 31, 1997, and here incorporated by
reference.
10.3 Form of Director and Officer Indemnity Agreement. Previously filed as an exhibit to the
Company's Registration Statement on Form S-1 (333-40383), and here incorporated by
reference.*
10.4 Lease Agreement between Miller Oil Corporation and C.E. and Betty Miller, dated July 24, 1996.
Previously filed as an exhibit to the Company's Registration Statement on Form S-1
(333-40383), and here incorporated by reference.
10.5 Letter Agreement dated November 10, 1997, between Miller Oil Corporation and C.E. Miller,
regarding sale of certain assets. Previously filed as an exhibit to the Company's Registration
Statement on Form S-1 (333-40383), and here incorporated by reference.
10.6 Amended Service Agreement dated January 1, 1997, between Miller Oil Corporation and Eagle
Investments, Inc. Previously filed as an exhibit to the Company's Registration Statement on
Form S-1 (333-40383), and here incorporated by reference.
10.7 Form of Registration Rights Agreement (included as Exhibit E to Exhibit 2.1). Previously filed as
an exhibit to the Company's Registration Statement on Form S-1 (333-40383), and here
incorporated by reference.
10.8 $2,500,000 Promissory Note dated November 26, 1997 between Miller Oil Corporation and the
C.E. Miller Trust. Previously filed as an exhibit to the Company's Registration Statement on
Form S-1 (333-40383), and here incorporated by reference.
33
Exhibit No. Description
- ----------- -----------
10.9 Form of Indemnification and Contribution Agreement among the Registrant and the Selling
Stockholders. Previously filed as an exhibit to the Company's Registration Statement on
Form S-1 (333-40383), and here incorporated by reference.
10.10 Agreement between Eagle Investments, Inc. and Miller Oil Corporation, dated April 1, 1999.
Previously filed as an exhibit to the Company's Annual Report on Form 10-K for the year
ended December 31, 1998, and here incorporated by reference.
10.11 $4,696,040.60 Note between Miller Exploration Company and Veritas DGC Land, Inc., dated
April 14, 1999. Previously filed as an exhibit to the Company's Annual Report on Form 10-K
for the year ended December 31, 1998, and here incorporated by reference.
10.12 Warrant between Miller Exploration Company and Veritas DGC Land, Inc., dated April 14, 1999.
Previously filed as an exhibit to the Company's Annual Report on Form 10-K for the year
ended December 31, 1998, and here incorporated by reference.
10.13 Registration Rights Agreement between Miller Exploration Company and Veritas DGC Land,
Inc., dated April 14, 1999. Previously filed as an exhibit to the Company's Annual Report on
Form 10-K for the year ended December 31, 1998, and here incorporated by reference.
10.14 Agreement between Eagle Investments, Inc. and Miller Exploration Company, dated March 16,
1999. Previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1999, and here incorporated by reference.
10.15 Agreement between Eagle Investments, Inc. and Miller Exploration Company, dated May 18,
1999. Previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1999, and here incorporated by reference.
10.16 Agreement between Eagle Investments, Inc. and Miller Exploration Company, dated May 27,
1999. Previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1999, and here incorporated by reference.
10.17 Agreement between Eagle Investments, Inc. and Miller Exploration Company, dated June 30,
1999. Previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1999, and here incorporated by reference.
10.18 Agreement between Eagle Investments, Inc. and Miller Exploration Company, dated October 18,
1999. Previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1999, and here incorporated by reference.
10.19(a) Form of Equity Compensation Plan for Non-Employee Directors Agreement dated December 7,
1998. Previously filed as an exhibit to the Company's Proxy Statement on Schedule 14A dated
May 13, 1999, and here incorporated by reference.
10.19(b) Amended and Restated Equity Compensation Plan for Non-Employee Directors dated
February 25, 2000. Previously filed as an exhibit to the Company's Proxy Statement on
Schedule 14A dated April 25, 2000, and here incorporated by reference.
10.19(c) Amended and Restated Equity Compensation Plan for Non-Employee Directors dated March 20,
2001.
10.19(d) Amended and Restated Equity Compensation Plan for Non-Employee Directors dated March 18,
2002.
10.20 Form of Employment Agreement for Lew P. Murray dated February 9, 1998.* Previously filed as
an exhibit to the Company's Annual Report on Form 10-K for the year ended December 31,
2000, and here incorporated by reference.
34
Exhibit No. Description
- ----------- -----------
10.21 Form of Employment Agreement for Michael L. Calhoun dated February 9, 1998.* Previously
filed as an exhibit to the Company's Annual Report on Form 10-K for the year ended
December 31, 2000, and here incorporated by reference.
10.22 Securities Purchase Agreement between Miller Exploration Company and Guardian Energy
Management Corp. dated July 11, 2000. Preciously filed as an exhibit to the Company's Current
Report on Form 8-K filed on July 25, 2000.
10.23 Promissory Note between Miller Exploration Company and Guardian Energy Management Corp.
dated July 11, 2000. Previously filed as an exhibit to the Company's Current Report on
Form 8-K filed on July 25, 2000.
10.24 Registration Rights Agreement between Miller Exploration Company and Guardian Energy
Management Corp. dated July 11, 2000. Previously filed as an exhibit to the Company's Current
Report on Form 8-K filed on July 25, 2000.
10.25 Form of Subscription Agreement between Miller Exploration Company and ECCO Investments,
LLC dated July 11, 2000. Previously filed as an exhibit to the Company's Current Report on
Form 8-K filed on July 25, 2000.
10.26 Form of Letter Agreement between Miller Exploration Company and Eagle Investments, Inc.
dated July 12, 2000. Previously filed as an exhibit to the Company's Current Report on Form
8-K filed on July 25, 2000.
10.27 Amended and Restated Credit Agreement between Miller Exploration Company and the
Subsidiaries of the Company and Bank One, Texas, N.A., dated July 18, 2000. Previously filed
as an exhibit to the Company's Quarterly Report on Form 10-Q filed on August 14, 2000.
10.28 Second Amendment to Promissory Note, Warrant and Registration Rights Agreement dated
June 28, 2002, between Veritas DGC Land, Inc. and Miller Exploration Company. Previously
filed as an exhibit to the Company's Quarterly Report on Form 10-Q filed on August 12, 2002.
10.29 Exploration and Development Agreement dated June 17, 1998, between K2 American
Corporation, K2 Energy Corporation and Miller Exploration Company.
10.30(a) Oil and Gas Exploration and Development Agreement dated February 19, 1999, between the
Blackfeet Tribal Business Council of the Blackfeet Indian Tribe of the Blackfeet Indian
Reservation and Miller Exploration Company.
10.30(b) Amended Oil and Gas Exploration Agreement dated June 3, 2002, between the Blackfeet Business
Council of the Blackfeet Indian Tribe of the Blackfeet Indian Reservation.
11.1 Computation of Earnings per Share.
21.1 Subsidiaries of the Registrant. Previously filed as an exhibit to the Company's Registration
Statement on Form S-1 (333-40383), and here incorporated by reference.
23.1 Consent of Miller and Lents, Ltd.
23.2 Consent of Plante & Moran, PLLC
24.1 Limited Power of Attorney.
- --------
/*/ Management contract or compensatory plan or arrangement.
35
Item 14(b). Reports on Form 8-K
The Company filed a report on Form 8-K on October 8, 2002. In the report,
the Company reported that on September 30, 2002, it had completed the sale of
its 35% working interest in the Pine Grove Field oil and gas assets located in
Jones County, Mississippi, to Bean Industries, Inc. for $3.75 million.
36
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
MILLER EXPLORATION COMPANY
By: /s/ KELLY E. MILLER
-----------------------------
Kelly E. Miller
President and Chief Executive
Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Name Title Date
---- ----- ----
/s/ *C. E. MILLER Chairman of the Board March 24, 2003
- -----------------------------
C. E. Miller
/s/ KELLY E. MILLER Director, (Principal March 24, 2003
- ----------------------------- Executive Officer)
Kelly E. Miller
/s/ DEANNA L. CANNON (Principal Financial and March 24, 2003
- ----------------------------- Accounting Officer)
Deanna L. Cannon
/s/ *ROBERT M. BOEVE Director March 24, 2003
- -----------------------------
Robert M. Boeve
/s/ *PAUL A. HALPERN Director March 24, 2003
- -----------------------------
Paul A. Halpern
/s/ *RICHARD J. BURGESS Director March 24, 2003
- -----------------------------
Richard J. Burgess
By: /s/ DEANNA L. CANNON
-------------------------
Deanna L. Cannon
Attorney-in-Fact
37
CERTIFICATION
I, Kelly E. Miller, certify that:
1. I have reviewed this annual report on Form 10-K of Miller Exploration
Company (the "registrant");
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiary, is made known to us by others within those
entities, particularly during the period in which this annual report is
being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the filing
date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors:
a) all significant deficiencies in the design or operation of the
internal controls which could adversely affect the registrant's ability
to record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
By: /s/ KELLY E. MILLER
-----------------------------
Kelly E. Miller
President and Chief Executive
Officer
Dated: March 24, 2003
38
CERTIFICATION
I, Deanna L. Cannon, certify that:
1. I have reviewed this annual report on Form 10-K of Miller Exploration
Company (the "registrant");
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiary, is made known to us by others within those
entities, particularly during the period in which this annual report is
being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the filing
date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors:
a) all significant deficiencies in the design or operation of the
internal controls which could adversely affect the registrant's ability
to record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
By: /s/ DEANNA L. CANNON
-----------------------------
Deanna L. Cannon
Chief Financial Officer
Dated: March 24, 2003
39
INDEX TO FINANCIAL STATEMENTS
Page
----
Consolidated Financial Statements of Miller Exploration Company
Report of Independent Public Accountants................................................... F-2
Consolidated Balance Sheets as of December 31, 2002 and 2001............................... F-4
Consolidated Statements of Operations for the Years Ended December 31, 2002, 2001 and 2000. F-5
Consolidated Statements of Equity for the Years Ended December 31, 2002, 2001 and 2000..... F-6
Consolidated Statements of Cash Flows for the Years Ended December 31, 2002, 2001 and 2000. F-7
Notes to Consolidated Financial Statements................................................. F-8
Supplemental Quarterly Financial Data (unaudited).......................................... F-29
F-1
REPORT OF INDEPENDENT PUBLIC ACCOUNTS
To The Board of Directors and Stockholders of Miller Exploration Company:
We have audited the accompanying consolidated balance sheet of Miller
Exploration Company (a Delaware corporation) and subsidiary, as of December 31,
2002, and the related consolidated statements of operations, shareholders'
equity and cash flows for the year then ended. These financial statements are
the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audits to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Miller Exploration Company
and subsidiary as of December 31, 2002, and the results of its operations and
its cash flows for the year then ended in conformity with accounting principles
generally accepted in the United States of America.
/s/ PLANTE & MORAN, PLLC
Grand Rapids, Michigan
February 28, 2003
F-2
ARTHUR ANDERSEN LLP
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders of Miller Exploration Company:
We have audited the accompanying consolidated balance sheets of MILLER
EXPLORATION COMPANY (a Delaware corporation) and subsidiary as of December 31,
2001 and 2000, and the related consolidated statements of operations, equity,
and cash flows for each of the three years in the period ended December 31,
2001. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Miller Exploration Company
and subsidiary as of December 31, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001, in conformity with accounting principles generally accepted
in the United States.
This report is a copy of a previously issued report and has not been
reissued by Arthur Andersen, L.L.P.
/s/ ARTHUR ANDERSEN LLP
Detroit, Michigan
March 8, 2002
F-3
MILLER EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands, except share amounts)
As of December 31,
--------------------
2002 2001
--------- ---------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents.................................................. $ 46 $ 201
Accounts receivable........................................................ 1,441 3,076
Inventories, prepaids and advances to operators............................ 324 523
--------- ---------
Total current assets................................................... 1,811 3,800
--------- ---------
OIL AND GAS PROPERTIES--at cost (full cost method):
Proved oil and gas properties.............................................. 155,189 146,649
Unproved oil and gas properties............................................ 2,375 11,244
Less-Accumulated depreciation, depletion and amortization.................. (138,826) (124,618)
--------- ---------
Net oil and gas properties............................................. 18,738 33,275
--------- ---------
OTHER ASSETS (Note 2)......................................................... 300 512
--------- ---------
Total assets........................................................... $ 20,849 $ 37,587
========= =========
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Current portion of long-term debt.......................................... $ 800 $ --
Accounts payable........................................................... 639 2,767
Accrued expenses and other current liabilities............................. 2,301 4,974
--------- ---------
Total current liabilities.............................................. 3,740 7,741
--------- ---------
LONG-TERM DEBT................................................................ -- 6,696
DEFERRED INCOME TAXES......................................................... -- 5,743
COMMITMENTS AND CONTINGENCIES (Note 9)
EQUITY (Note 6):
Common stock warrants, 960,050 and 1,335,050 outstanding at December 31,
2002 and 2001, respectively.............................................. 851 860
Preferred stock, $0.01 par value; 2,000,000 shares authorized; none
outstanding.............................................................. -- --
Common stock, $0.01 par value; 40,000,000 shares authorized; 1,992,186 and
1,947,886 shares outstanding at December 31, 2002 and 2001, respectively 20 19
Other comprehensive income (loss).......................................... (49) 89
Additional paid in capital................................................. 77,632 77,427
Retained deficit........................................................... (61,345) (60,988)
--------- ---------
Total equity........................................................... 17,109 17,407
--------- ---------
Total liabilities and equity........................................... $ 20,849 $ 37,587
========= =========
The accompanying notes are an integral part of these Consolidated Financial
Statements.
F-4
MILLER EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)
For the Year
Ended December 31,
--------------------------
2002 2001 2000
------- -------- -------
REVENUES:
Natural gas........................................ $ 7,182 $ 14,304 $20,745
Crude oil and condensate........................... 2,937 3,495 5,300
Other operating revenues........................... 161 269 522
------- -------- -------
Total operating revenues....................... 10,280 18,068 26,567
------- -------- -------
OPERATING EXPENSES:
Lease operating expenses and production taxes...... 1,711 2,944 3,030
Depreciation, depletion and amortization........... 7,458 13,431 17,457
General and administrative......................... 2,013 1,860 2,097
Cost ceiling writedown............................. 7,000 15,500 --
------- -------- -------
Total operating expenses....................... 18,182 33,735 22,584
------- -------- -------
OPERATING INCOME (LOSS)............................... (7,902) (15,667) 3,983
------- -------- -------
INTEREST EXPENSE:
Interest on notes and bank debt.................... (631) (1,184) (2,594)
Interest on capital transactions................... -- -- (1,728)
------- -------- -------
Total interest expense......................... (631) (1,184) (4,322)
------- -------- -------
LOSS BEFORE INCOME TAXES AND EXTRAORDINARY ITEM....... (8,533) (16,851) (339)
INCOME TAX PROVISION (CREDIT) (Note 3)................ (5,743) (459) 472
------- -------- -------
LOSS BEFORE EXTRAORDINARY ITEM........................ (2,790) (16,392) (811)
EXTRAORDINARY ITEM-GAIN (LOSS) FROM EARLY
EXTINGUISHMENT OF DEBT, LESS APPLICABLE INCOME TAXES 2,432 -- (166)
------- -------- -------
NET LOSS.............................................. $ (358) $(16,392) $ (977)
======= ======== =======
EARNINGS (LOSS) PER SHARE (Note 4)
Basic.............................................. $ (0.18) $ (8.43) $ (0.73)
======= ======== =======
Diluted............................................ $ (0.18) $ (8.43) $ (0.73)
======= ======== =======
The accompanying notes are an integral part of these Consolidated Financial
Statements.
F-5
MILLER EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF EQUITY
(In thousands)
Common Add'l Other
Stock Preferred Common Paid In Deferred Compensation Retained
Warrants Stock Stock Capital Compensation Income Deficit
-------- --------- ------ ------- ------------ ------------ --------
BALANCE--December 31, 1999....... $ 845 $-- $ 127 $66,690 $(48) $ -- $(43,619)
Issuance of restricted stock
and benefit plan shares...... -- -- -- 81 48 -- --
Common stock warrants
issued....................... 1,414 -- -- -- -- -- --
Common stock warrants
exercised.................... (500) -- 5 495 -- -- --
Issuance of non-employee
directors' shares............ -- -- 1 216 -- -- --
Issuance of common stock...... -- -- 60 9,088 -- -- --
Net loss...................... -- -- -- -- -- -- (977)
------ --- ----- ------- ---- ------- --------
BALANCE--December 31, 2000....... 1,759 -- 193 76,570 -- -- (44,596)
Common stock warrants
expired...................... (899) -- -- 463 -- -- --
Issuance of benefit plan
shares....................... -- -- 1 80 -- -- --
Issuance of non-employee
directors' shares............ -- -- 1 138 -- -- --
Adoption of new accounting
standard (Note 8)............ -- -- -- -- -- (5,685) --
Change in unrealized gains
(losses)..................... -- -- -- -- -- 5,774 --
Net loss...................... -- -- -- -- -- -- (16,392)
------ --- ----- ------- ---- ------- --------
BALANCE--December 31, 2001....... $ 860 $-- $ 195 $77,251 $ -- $ 89 $(60,988)
Common stock warrants.........
expired...................... (9) -- -- 6 -- -- --
Issuance of benefit plan......
shares....................... -- -- 2 74 -- -- --
Issuance of non-employee......
directors' shares............ -- -- 2 122 -- -- --
Change due to reverse stock
split........................ -- -- (179) 179 -- -- --
Change in unrealized gains
(losses)..................... -- -- -- -- -- (138) --
Net loss...................... -- -- -- -- -- -- (358)
------ --- ----- ------- ---- ------- --------
BALANCE--December 31, 2002....... $ 851 $-- $ 20 $77,632 $ -- $ (49) $(61,345)
====== === ===== ======= ==== ======= ========
Disclosure of Comprehensive Income:
For the Year Ended
December 31,
----------------------
2002 2001 2000
----- -------- -----
Net loss......................... $(358) $(16,392) $(977)
Other comprehensive income (loss) (138) 89 --
----- -------- -----
Total comprehensive loss...... $(496) $(16,303) $(977)
===== ======== =====
The accompanying notes are an integral part of these Consolidated Financial
Statements.
F-6
MILLER EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
For the Year Ended December 31
----------------------------
2002 2001 2000
-------- -------- --------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss.................................................................. $ (358) $(16,392) $ (977)
Adjustments to reconcile net loss to net cash from operating activities--
Depreciation, depletion and amortization.............................. 7,458 13,431 17,457
Cost ceiling writedown................................................ 7,000 15,500 --
Deferred income taxes................................................. (5,743) (459) 387
Warrants and stock compensation....................................... 196 (214) 1,262
Extraordinary item.................................................... (2,432) -- 166
Deferred revenue...................................................... -- (20) (34)
Changes in assets and liabilities--
Restricted cash..................................................... -- 69 (65)
Accounts receivable................................................. 1,635 1,398 106
Other current assets................................................ 113 (120) (272)
Other assets........................................................ (35) (41) 189
Accounts payable.................................................... (2,128) (805) 100
Accrued expenses and other current liabilities...................... (2,486) 1,046 (2,236)
-------- -------- --------
Net cash flows provided by operating activities.................. 3,220 13,393 16,083
-------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development expenditures.................................. (3,418) (9,972) (8,592)
Proceeds from sale of oil and gas properties and purchases of equipment,
net..................................................................... 3,743 22 947
-------- -------- --------
Net cash flows provided by (used in) investing activities........ 325 (9,950) (7,645)
-------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments of principal..................................................... (23,772) (21,698) (28,519)
Borrowing on long-term debt............................................... 20,072 16,164 11,639
Common stock proceeds..................................................... -- -- 7,022
-------- -------- --------
Net cash flows used in financing activities...................... (3,700) (5,534) (9,858)
-------- -------- --------
NET DECREASE IN CASH AND CASH EQUIVALENTS.................................. (155) (2,091) (1,420)
CASH AND CASH EQUIVALENTS AT BEGINNING OF THE PERIOD....................... 201 2,292 3,712
-------- -------- --------
CASH AND CASH EQUIVALENTS AT END OF THE PERIOD............................. $ 46 $ 201 $ 2,292
======== ======== ========
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid during the period for--
Interest.............................................................. $ 817 $ 978 $ 2,117
======== ======== ========
The accompanying notes are an integral part of these Consolidated Financial
Statements.
F-7
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Organization and Nature of Operations
The Combination Transaction
Miller Exploration Company ("Miller" or the "Company") was formed as a
Delaware corporation in November 1997 to serve as the surviving company upon
the completion of a series of combination transactions (the "Combination
Transaction"). The first part of the Combination Transaction included the
following activities: Miller acquired all of the outstanding capital stock of
Miller Oil Corporation ("MOC"), the Company's predecessor, and certain oil and
gas interests (collectively, the "Combined Assets") owned by Miller & Miller,
Inc., Double Diamond Enterprises, Inc., Frontier Investments, Inc., Oak Shores
Investments, Inc., Eagle Investments, Inc. (d/b/a Victory, Inc.) and Eagle
International, Inc. (the "affiliated entities," all Michigan corporations owned
by Miller family members who were beneficial owners of MOC) in exchange for an
aggregate consideration of approximately 530,000 shares of Common Stock of
Miller. The operations of all of these entities had been managed through the
same management team, and had been owned by the same members of the Miller
family. Miller completed the Combination Transaction concurrently with
consummation of an initial public offering (the "Offering").
Initial Public Offering
On February 9, 1998, the Company completed the Offering of its Common Stock
and concurrently completed the Combination Transaction. On that date, the
Company sold 550,000 shares of its Common Stock for an aggregate purchase price
of $44.0 million. On March 9, 1998, the Company sold an additional 6,250 shares
of its Common Stock for an aggregate purchase price of $0.5 million, pursuant
to the exercise of the underwriters' over-allotment option.
Other Transactions Completed Concurrently With the Initial Public Offering
In addition to the above combined activities of the Company, the second part
of the Combination Transaction that was consummated concurrently with the
Offering was the exchange by the Company of an aggregate of approximately
160,000 shares of Common Stock for interests in certain other oil and gas
properties that were owned by non-affiliated parties. Because these interests
were acquired from individuals who were not under the common ownership and
management of the Company, these exchanges were accounted for under the
purchase method of accounting. Under that method, the properties were recorded
at their estimated fair value at the date on which the exchange was consummated
(February 9, 1998).
In November 1997, the Company entered into a Purchase and Sale Agreement,
whereby the Company acquired interests in certain crude oil and natural gas
producing properties and undeveloped properties from Amerada Hess Corporation
for $48.8 million, net of post-closing adjustments. This purchase was
consummated concurrently with the Offering. This acquisition was accounted for
under the purchase method of accounting and was financed with the use of
proceeds from the Offering and with new bank borrowings.
Reverse Stock Split
On October 11, 2002, the Company affected a one-for-ten reverse stock split
that has been retroactively reflected in the Company's Consolidated Financial
Statements.
Principles of Consolidation
The consolidated financial statements of the Company include the accounts of
the Company and its subsidiaries after elimination of all intercompany accounts
and transactions.
F-8
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Nature of Operations
The Company is a domestic, independent energy company engaged in the
exploration, development and production of crude oil and natural gas. The
Company has established exploration efforts concentrated primarily in the
Mississippi Salt Basin of central Mississippi.
(2) Summary of Significant Accounting Policies
Oil and Gas Properties
The Company follows the full cost method of accounting and capitalizes all
costs related to its exploration and development program, including the cost of
nonproductive drilling and surrendered acreage. Such capitalized costs include
lease acquisition, geological and geophysical work, delay rentals, drilling,
completing and equipping oil and gas wells, together with internal costs
directly attributable to property acquisition, exploration and development
activities. Under this method, the proceeds from the sale of oil and gas
properties are accounted for as reductions to capitalized costs, and gains and
losses are not recognized. The capitalized costs are amortized on an overall
unit-of-production method based on total estimated proved oil and gas reserves.
Additionally, certain costs associated with major development projects and all
costs of unevaluated leases are excluded from the depletion base until reserves
associated with the projects are proved or until impairment occurs.
To the extent that capitalized costs within the full cost pool, net of
deferred income taxes, exceed the sum of discounted estimated future net cash
flows from proved oil and gas reserves (using unescalated prices and costs and
a 10% per annum discount rate) and the lower of cost or market value of
unproved properties, such excess costs are charged against earnings. The
Company did record a $7.0 million non-cash cost ceiling writedown for the
quarter ended June 30, 2002. The writedown was attributable to a decrease in
the value of the Company's unproved properties as a result of the transfer of
proprietary rights to 3-D seismic data to Veritas (as more fully discussed in
Note 5 to the Consolidated Financial Statements) and due to the fact that the
Company reversed the $5.5 million balance at June 30, 2002 of deferred income
taxes (as more fully discussed in Note 2 to the Consolidated Financial
Statements). Using unescalated period-end prices at (net of basis adjustments)
December 31, 2001, of $2.55 per Mcf of natural gas and $16.72 per barrel of
oil, the Company recognized a non-cash cost ceiling writedown of $7.0 million.
This was in addition to $8.5 million of cost ceiling writedowns previously
recognized by the Company in 2001. Using unescalated period-end prices (net of
basis adjustments) at December 31, 2000, of $8.65 per Mcfe, the Company had no
impairment of oil and gas properties for the year then ended.
Property and Equipment
Property and equipment is included in other assets in the accompanying
consolidated Balance Sheets and consists primarily of office furniture,
equipment and computer software and hardware. Depreciation and amortization are
calculated using straight-line and accelerated methods over the estimated
useful lives of the related assets. The estimated useful lives for each
category of fixed assets are: buildings and improvements (10-20 years); office
furniture and equipment (7-10 years) and computer software and hardware (3-5
years).
Revenue Recognition
Crude oil and natural gas revenues are recognized as production takes place
and the sale is completed and the risk of loss transfers to a third party
purchaser.
Other Operating Revenues
The majority of the other operating revenues are reimbursements for general
and administrative services that the Company performs on behalf of partners and
investors in jointly owned oil and gas properties. All other
F-9
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
management fees that were earned for exploration and development services have
been credited against oil and gas property costs.
Cash and Cash Equivalents
Cash and cash equivalents are comprised of cash and U.S. Government
securities with original maturities of three months or less.
Accounts Receivable
Accounts receivable are stated at net invoice amounts. An allowance for
doubtful accounts is established based on specific assessment of all invoices
based on historical loss experience. All amounts deemed to be uncollectible are
charged against the allowance for doubtful accounts in the period that
determination is made.
Inventories
Inventories consist of oil field casing, tubing and related equipment for
wells. Inventories are valued at the lower of cost (first-in, first-out method)
or market.
Reclassifications
Certain reclassifications have been made to the prior year financial
statements to conform with the 2002 presentation.
Use of Estimates
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenue and expense during
the reporting periods. Accordingly, actual results could differ from these
estimates. Significant estimates include depreciation, depletion and
amortization of proved oil and natural gas properties. Oil and natural gas
reserve estimates, which are the basis for unit-of-production depletion and the
cost ceiling test, are inherently imprecise and are expected to change as
future information becomes available.
Comprehensive Income (Loss)
On January 1, 2001, the Company adopted SFAS No. 133 regarding certain
financial derivative contracts used to hedge the price risk on future oil and
gas production. These contracts are required to be recognized at their fair
value in the Consolidated Balance Sheet as an asset or liability. The fair
value of remaining financial derivative contracts at December 31, 2002 is
approximately $(0.1) million. This amount is reflected in other current
liabilities in the Consolidated Balance Sheet with a corresponding amount in
other comprehensive income (loss).
Other
For significant accounting policies regarding income taxes, see Note 3; for
earnings per share, see Note 4; for financial instruments, see Note 7; for risk
management activities and derivative transactions, see Note 8; and for
stock-based compensation, see Note 10.
F-10
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(3) Income Taxes
The Company accounts for income taxes under the provisions of Statement of
Financial Accounting Standards ("SFAS") No. 109, "Accounting for Income Taxes."
SFAS No. 109 requires the asset and liability approach for income taxes. Under
this approach, deferred tax assets and liabilities are recognized based on
anticipated future tax consequences attributable to differences between
financial statement carrying amounts of assets and liabilities and their
respective tax bases.
The effective income tax rate for the Company for the years ended December
31, 2002, 2001 and 2000, was different than the statutory federal income tax
rate for the following reasons (in thousands):
2002 2001 2000
------- -------- -----
Net loss................................................... $ (358) $(16,392) $(977)
Add back:
Extraordinary item...................................... (2,432) -- 166
Income tax provision (credit)........................... (5,743) (459) 472
------- -------- -----
Pre-tax loss............................................... (8,533) (16,851) (339)
Income tax provision (credit) at the federal statutory rate (2,901) (5,729) (115)
Cost ceiling test writedown................................ 2,380 5,270
Reversal of deferred taxes................................. (5,743) -- --
Nondeductible interest expense............................. -- -- 587
Net operating loss carryforward............................ 521 -- --
All other, net............................................. -- -- --
------- -------- -----
Income tax provision (credit).............................. $(5,743) $ (459) $ 472
======= ======== =====
The components of the provision of income taxes for the year ended December
31, 2002, 2001 and 2000 are as follows (in thousands):
2002 2001 2000
------- ----- -----
Currently payable......... $ -- $ -- $ --
Deferred to future periods -- (459) 472
Reversal of deferred taxes (5,743) -- --
------- ----- -----
Total income taxes..... $(5,743) $(459) $ 472
======= ===== =====
F-11
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(3) Income Taxes (Continued)
The principal components of the Company's deferred tax assets (liabilities)
recognized in the balance sheet as of December 31, 2002 and 2001 are as follows
(in thousands):
2002 2001
-------- --------
Deferred tax assets (liabilities):
Unsuccessful well and lease costs. $ (6,676) $ (6,556)
Intangible drilling costs......... (12,434) (11,904)
Other property basis differences.. 7,776 827
Net operating loss carryforward... 11,334 11,890
Cost ceiling writedown............ 19,579 17,199
Less: Valuation allowance......... (19,579) (17,199)
-------- --------
Net deferred tax liability........... $ -- $ (5,743)
======== ========
At December 31, 2002, the Company had regular tax net operating loss
carryforwards of approximately $33.3 million. This loss carryforward amount
will expire during 2019. The Company also had a percentage depletion
carryforward of approximately $1.9 million at December 31, 2002, which is
available to offset future federal income taxes payable and has no expiration
date.
Based on estimates prepared as of June 30, 2002, of future anticipated
taxable income and also taking into consideration the Company's current net
operating loss and depletion deduction carryforwards, it has been determined
that there should be no accrual of future tax liability. Accordingly, at June
30, 2002, the Company recorded a $5.7 million income tax credit to reverse the
entire deferred income tax liability balance.
(4) Earnings Per Share
In accordance with the provisions of SFAS No. 128, "Earnings per Share,"
basic earnings per share is computed on the basis of the weighted-average
number of common shares outstanding during the periods. Diluted earnings per
share is computed based upon the weighted-average number of common shares plus
the assumed issuance of common shares for all potentially dilutive securities.
The computation of earnings per share for the year ended December 31, 2002,
2001 and 2000 is as follows (in thousands, except per share data):
2002 2001 2000
------- -------- ------
Net loss before extraordinary item attributable to basic and diluted EPS $(2,790) $(16,392) $ (811)
Extraordinary item...................................................... 2,432 -- (166)
------- -------- ------
Net loss................................................................ $ (358) $(16,392) $ (977)
======= ======== ======
Weighted average common shares outstanding applicable to basic EPS...... 1,982 1,944 1,336
Add: options and warrants............................................... -- -- --
------- -------- ------
Weighted average common shares outstanding applicable to diluted EPS.... 1,982 1,944 1,336
======= ======== ======
Net loss per share--Basic
Net loss before extraordinary item.................................. $ (1.41) $ (8.43) $(0.61)
Extraordinary item.................................................. 1.23 -- (0.12)
------- -------- ------
Net loss............................................................ $ (0.18) $ (8.43) $(0.73)
======= ======== ======
Net loss per share--Diluted
Net loss before extraordinary item.................................. $ (1.41) $ (8.43) $(0.61)
Extraordinary item.................................................. 1.23 -- (0.12)
------- -------- ------
Net loss............................................................ $ (0.18) $ (8.43) $(0.73)
======= ======== ======
F-12
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(4) Earnings Per Share (Continued)
Options and warrants were not included in the computation of diluted
earnings per share for the years ended December 31, 2002, 2001 and 2000 because
their effect was antidilutive.
(5) Notes Payable and Long-Term Debt
Notes Payable
During the past few years, the Company has financed various insurance policy
premiums. In January 2002, concurrent with the policy renewals, the Company
entered into a $71,893 note payable agreement to finance general liability and
workers' compensation insurance premiums. Terms of such note call for nine
monthly installment payments of $8,157, bearing interest at 5.05%. In February
2002, the Company entered into a $131,827 note payable agreement to finance
control of well, boiler and machinery, and personal property insurance
premiums. Terms of such note call for nine monthly installment payments of
$14,949, bearing interest at 4.91%. At December 31, 2002, these notes were
completely paid off.
Bank Debt
On July 18, 2000, the Company entered into a new senior credit facility with
Bank One, Texas, N.A. ("Bank One"), which replaced the existing credit facility
with Bank of Montreal. The new credit facility has a 30-month term with an
interest rate of either the Bank One prime rate plus 2% or LIBOR plus 4%, at
the Company's option. The Company's obligations under the credit facility are
secured by a lien on all of its real and personal property. The Company's new
borrowing base determined by Bank One as of March 1, 2003, was $3.75 million.
Commencing April 1, 2003, the borrowing base will be reduced $0.25 million each
month until maturity, which Bank One extended from January 18, 2003, to August
1, 2003. At December 31, 2002, the outstanding balance under the Company's
credit facility with Bank One was $0.8 million. The weighted average interest
rate for the credit facility at December 31, 2002, was 5.47%.
The Bank One credit facility includes certain covenants that impose
restrictions on the Company with respect to, among other things, incurrence of
additional indebtedness, limitations on financial ratios, making investments
and mergers and consolidation. The Company requested and obtained a waiver
through August 1, 2003, from Bank One for non-compliance with maintenance of
specified levels of commodity hedge covenants as required by the credit
facility.
Veritas Note
On April 14, 1999, the Company issued a $4.7 million note payable to one of
its suppliers, Veritas DGC Land, Inc. (the "Veritas Note"), for the outstanding
balance due to Veritas for past services provided in 1998 and 1999. The
principal obligation under the Veritas Note was originally due on April 15,
2001. On July 19, 2000, the note was amended as more fully described below.
On April 14, 1999, the Company also entered into an agreement (the "Warrant
Agreement") to issue warrants to Veritas that entitle Veritas to purchase
shares of common stock in lieu of receiving cash payments for the accrued
interest obligations under the Veritas Note. The Warrant Agreement required the
Company to issue warrants to Veritas in conjunction with the signing of the
Warrant Agreement, as well as on the six and, at the Company's option, 12 and
18 month anniversaries of the Warrant Agreement. The warrants issued equal 9%
of the then current outstanding principal balance of the Veritas Note. The
number of shares issued upon exercise of the warrants issued on April 14, 1999,
and on the six-month anniversary was determined based upon a five-day weighted
average closing price of the Company's Common Stock at April 14, 1999. The
exercise price of each warrant is $0.10 per share. On April 14, 1999, warrants
exercisable for 32,276 shares of Common Stock were
F-13
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(5) Notes Payable and Long-Term Debt (Continued)
issued to Veritas in connection with execution of the Veritas Note. On October
14, 1999 and April 14, 2000, warrants exercisable for another 32,276 and 45,500
shares, respectively, of Common Stock were issued to Veritas. The Company
ratably recognized the prepaid interest into expense over the period to which
it related. For the year ended December 31, 2000, the Company recognized
non-cash interest expense of approximately $752,000 related to the Veritas Note
Payable. Effective November 1, 2000, Veritas exercised 50,000 warrants to
receive 49,693 shares (net of exercise price) of Company common stock.
On July 19, 2000, the Company entered into the First Amendment to Promissory
Note, Warrant and Registration Rights Agreement ("First Amendment Agreement").
Under the terms of the First Amendment Agreement, the maturity of the Veritas
Note was extended to July 21, 2003 from April 15, 2001 and the expiration date
for all warrants issued was extended until June 21, 2004. The annual interest
rate was reduced to 9 3/4% from 18%, provided the entire Note balance was paid
in full by December 31, 2001. The Veritas note was not paid in full by December
31, 2001, and the interest rate was increased to 13 3/4% annually. Interest was
payable on each October 15 and April 15 until the note is paid in full. The
Company has paid additional interest of approximately $225,000 at the
incremental 4% rate for the period of October 15, 2000 through April 14, 2002.
Interest was required to be paid in warrants under the terms of the First
Amendment Agreement until the Company was in compliance with the net borrowing
base formula as defined in the Bank One credit facility, at which time interest
would only be paid in cash. Since October 15, 2000, all required interest
payments have been made in cash.
On June 28, 2002, the Company entered into the Second Amendment Agreement.
Concurrently with the execution of the Second Amendment Agreement, the Company
made a $600,000 principal payment. Under terms of the Second Amendment
Agreement, the Veritas Note was amended as follows: (1) The maturity of the
Veritas Note was changed to December 31, 2002 from July 21, 2003; (2) the
interest rate was changed to 9 3/4%; (3) the past due annual interest rate was
changed to 12% from 13 3/4%; and (4) six principal payments of $150,000,
totaling $900,000 were required, and were payable on or before the last day of
each month commencing on July 31, 2002. In the event that all six principal
payments mentioned above were made timely, an interest payment was not due on
October 15, 2002, and Veritas agreed to extinguish the remaining principal
balance of $2.2 million and any accrued interest outstanding under the Veritas
Note and the Company would recognize a gain of approximately $2.4 million. In
the event that these six principal payments were not timely made, the entire
principal balance outstanding under the Veritas Note would be accelerated and
become due and payable upon demand and would accrue interest at the past due
rate from the date of the Second Amendment Agreement until the Veritas Note is
paid in full. At December 31, 2002, the Company has made all required principal
payments pursuant to the Second Amendment Agreement. Therefore, the remaining
principal balance and related accrued interest payable obligations have been
extinguished and the Company has recorded a $2.4 million extraordinary gain as
reported in the Consolidated Statements of Operations for the year ended
December 31, 2002.
As an inducement for Veritas to enter into the Second Amendment Agreement:
(1) the Company has granted Veritas an overriding royalty interest on the
Company's entire leasehold that is not held by production and leases acquired
through July 31, 2003 (excluding leases within the boundaries of the Blackfeet
Indian Reservation); (2) the Company transferred its proprietary rights in
approximately 140 square miles of 3-D seismic data with respect to certain
areas within the Mississippi Salt Basin to Veritas in exchange for a 25-year
license allowing the Company the use of same data. The Company has also agreed
to an optional transfer fee on its previously proprietary and non-proprietary
3-D data, which in the aggregate totals approximately $3.1 million in the event
of a change in control of the Company; and (3) certain Company Directors who
own or control shares of Common Stock of the Company and are considered major
stockholders have agreed to provide certain tag-along rights in the event one
of these major stockholders negotiates a sale of Company Common Stock with a
F-14
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(5) Notes Payable and Long-Term Debt (Continued)
private party. The Second Amendment Agreement also extended the expiration date
of the warrants to July 31, 2004 from June 21, 2004
The Company's long-term debt consisted of the following as of December 31,
2002 and 2001 (in thousands):
2002 2001
---- ------
Bank One Credit Facility.............. $800 $3,000
Veritas Note.......................... -- 3,696
---- ------
Total.............................. 800 6,696
Less current portion of long-term debt 800 --
---- ------
$ -- $6,696
==== ======
The Company's credit facility has been extended to August 1, 2003. Based
upon the Company's estimated oil and gas reserves at the end of 2002, the
Company believes it will have sufficient oil and gas assets to support its
borrowing base when the credit facility expires and, if necessary, the Company
would plan to either amend, extend or replace the credit facility (with the
same or alternative lender) before it expires. In the event the Company is
unable to amend, extend or replace the credit facility, the Company believes it
would be able to fulfill this obligation through the use of available cash
flows; the identification of additional sources for debt or equity financings;
or the sale of some or all of its oil and gas properties. However, these
expectations are dependent on several internal and external factors. If these
factors differ, from management's expectations, they could have a material
adverse effect on the Company's ability to meet future financing obligations
and cause the Company to curtail its exploration and development activities.
(6) Capital Transactions and Common Stock Warrants
Capital Transactions
On July 11, 2000, the Company entered into a Securities Purchase Agreement
(the "Securities Purchase Agreement") with Guardian. Pursuant to the Securities
Purchase Agreement, the Company issued to Guardian a convertible promissory
note in the amount of $5.0 million, and three warrants exercisable, for
156,250, 250,000 and 900,000 shares of the Company's Common Stock,
respectively. Conversion of the note and exercise of the warrants were subject
to stockholder approval, which was obtained at a stockholder meeting on
December 7, 2000. Until the stockholders approved the conversion of the note,
the Company accrued interest at an amount equal to the prime rate plus 10% per
annum (or 19.5%). The accrual of interest was required under Emerging Issues
Task Force ("EITF") 85-17 even though no interest was owed on this note since
the stockholders approved the conversion of the note. Accordingly, the Company
incurred approximately $0.4 million of interest expense on this convertible
note during the year ended December 31, 2000.
Under accounting pronouncements in effect at the date of the transaction, in
determining the beneficial conversion feature of the Guardian convertible note,
the Company was required to assume that the fair value of the Guardian
transaction was the closing price of the Company's common stock on the
commitment date (July 11, 2000) which was the date the agreements were signed
($15.60 per share) versus the value agreed to by both parties of $13.50 per
share using various valuation methodologies. The difference between these
values of $2.10 per share resulted in a non-cash charge to interest expense of
$0.8 million on the date of stockholder approval of the note conversion. Also,
the Company was required to use a value of $15.60 per share of Company Common
Stock to allocate value to the warrants issued to Guardian. This also resulted
in a non-cash charge to interest expense of $0.5 million, making a total of
$1.3 million charge to interest expense related to valuation of
F-15
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(6) Capital Transactions and Common Stock Warrants (Continued)
the Guardian Transaction. These charges to interest expense are the result of
using a prescribed fair value for our stock in accounting for these
transactions which may not represent the actual value of the Guardian
Transaction.
On July 11, 2000, the Company also signed a letter agreement (the "Eagle
Transaction") to acquire an interest in certain undeveloped oil and gas
properties and $0.5 million in cash from Eagle, an affiliated entity controlled
by C. E. Miller, the Chairman of the Company, in exchange for a total of
185,186 shares of common stock. In addition, Eagle was issued warrants
exercisable for a total of 203,125 shares of common stock. Consummation of this
transaction with Eagle was approved by the stockholders at a meeting on
December 7, 2000.
Also on July 11, 2000, the Company entered into a Subscription Agreement
with ECCO Investments, LLC ("ECCO"), pursuant to which ECCO purchased 37,037
shares of the Company's common stock for an aggregate purchase price of $0.5
million or $13.50 per share.
Common Stock Warrants
At December 31, 2002, the Company has the following Common Stock Warrants
outstanding:
Warrants Exercise Price Expiration Date
-------- -------------- ---------------
60,050 shares. $ 0.10 July 31, 2004
900,000 shares $30.00 December 7, 2004
Warrants issued for 375,000 shares with an exercise price of $25.00 per
share expired on December 7, 2002 without being exercised.
(7) Financial Instruments
The following methods and assumptions were used to estimate the fair value
of each significant class of financial instruments:
Cash, Restricted Cash, Temporary Cash Investments, Accounts Receivables,
Accounts Payable and Notes Payable
The carrying amount approximates fair value because of the short maturity of
those instruments.
Long-Term Debt
The interest rate on the Credit Facility is reset as Bank One's prime rate
changes to reflect current market rates. Consequently, the carrying value of
the credit facility approximates fair value.
Hedging Arrangements
Refer to Note 8 for a description of the Company's price hedging
arrangements and the fair values of the arrangements.
F-16
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(8) Risk Management Activities and Derivative Transactions
The Company uses a variety of financial derivative instruments to manage
exposure to fluctuations in commodity prices. To qualify for hedge accounting,
derivatives must meet the following criteria: (i) the item to be hedged exposes
the Company to price risk; and (ii) the derivative reduces that exposure and is
designated as a hedge.
Commodity Price Hedges
The Company periodically enters into certain derivatives for a portion of
its oil and natural gas production to achieve a more predictable cash flow, as
well as to reduce the exposure to price fluctuations. The Company's hedging
arrangements apply to only a portion of its production, provide only partial
price protection against declines in oil and natural gas prices and limit
potential gains from future increases in prices. Such hedging arrangements may
expose the Company to risk of financial loss in certain circumstances,
including instances where production is less than expected, the Company's
customers fail to purchase contracted quantities of oil or natural gas or a
sudden unexpected event materially impacts oil or natural gas prices. For
financial reporting purposes, gains and losses related to hedging are
recognized as oil and natural gas revenues during the period the hedge
transactions occur. The Company expects that the amount of hedge contracts that
it has in place will vary from time to time. For the years ended December 31,
2002, 2001, and 2000, the Company hedged 59%, 54%, and 54% of its oil and gas
production, respectively, and as of December 31, 2002, the Company had 0.3 Bcfe
of open oil and natural gas contracts for the months of January 2003 through
September 2003. If all of these open contracts had been settled as of December
31, 2002, the Company would have owed approximately $0.1 million.
New Accounting Standard
In June 1998, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 133, "Accounting for Derivative Instruments and Hedging Activities",
amended by Statement No. 137, "Accounting for Derivative Instruments and
Hedging Activities-Deferral of the Effective Date of FASB Statement No. 133"
and Statement No. 138, "Accounting for Certain Derivatives and Certain Hedging
Activities" (hereinafter collectively referred to as SFAS No. 133). SFAS No.
133 requires that every derivative instrument, including certain derivative
instruments embedded in other contracts, be recorded in the balance sheet as
either an asset or liability measured at its fair value. SFAS No. 133 requires
that changes in the derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. Special accounting for
qualifying hedges allows a derivative's gains and losses to offset related
results on the hedged item in the income statement, and requires that a company
must formally document, designate and assess the effectiveness of transactions
that receive hedge accounting.
SFAS No. 133 was adopted by the Company as of January 1, 2001 and the
Company completed the process of identifying all derivative instruments,
determining fair market values of derivatives designating and documenting hedge
relationships, and evaluating the effectiveness of those hedge relationships.
Certain financial derivative contracts used to hedge the price risk on
future production qualify under the provisions of SFAS No. 133 as cash flow
hedges. These contracts are required to be recognized at their fair value in
the Consolidated Balance Sheet as an asset or liability. The fair value of
remaining financial derivative contracts at December 31, 2002 is approximately
$(0.1) million. This amount is reflected in other current liabilities in the
Consolidated Balance Sheet with a corresponding amount in other comprehensive
income (loss).
F-17
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(9) Commitments and Contingencies
Leasing Arrangements
The Company leases its office building in Traverse City, Michigan from a
related party. The lease term is for five years beginning in April 1998, and
contains an annual 4% escalation clause. In 2002, the Company sub- leased
approximately 1,400 square feet of its office space to an unrelated third party
through March 2003. The Company is currently pursuing an extension of the
Traverse City office lease. The Company has also leased office space in
Houston, Texas; Jackson, Mississippi; and Columbia, Mississippi; as well as
warehouse space in Columbia, Mississippi. The lease agreements in Houston and
Jackson were signed by the Company in February 1998 and April 1998,
respectively. Each lease has a five-year term. The lease for office and
warehouse space in Columbia was signed in June 2001 for a one-year term. The
Columbia office lease was allowed to expire on June 30, 2002, and the two
employees have relocated to a smaller Company-owned office at the Company's
Midway Dome Production Facility location. The Company has closed its Houston
office and terminated all Houston office personnel. The Company intends to
extend the Jackson office lease on a month-to-month basis. The staff in the
Jackson office has been reduced to two employees.
Future minimum lease payments required of the Company for years ending
December 31, are as follows (in thousands):
2003...... 60
Thereafter --
---
$60
===
Total net rent expense under these lease arrangements was $276,156,
$280,502, and $261,990 for the years ended December 31, 2002, 2001 and 2000
respectively.
Employee Benefit Plan
The Company has a qualified 401(k) savings plan (the "Plan") covering
substantially all eligible employees. The Plan provides for discretionary
matching contributions by the Company. Matching contributions have been made in
the form of Company stock. Contributions charged against operations totaled
$66,282, $74,139, and $50,650 for the years ended December 31, 2002, 2001, and
2000, respectively.
Litigation
On May 1, 2000, the Company filed a lawsuit in the Federal District Court
for the District of Montana against K2 America Corporation and K2 Energy
Corporation (collectively referred to in this section as "K2"). The Company's
lawsuit included certain claims of relief and allegations by the Company
against K2, including breach of contract arising from failure by K2 to agree to
escrow, repudiation, and rescission; specific performance; declaratory relief;
partition of K2 lands that are subject to the K2 Agreement; negligence; and
tortuous interference with contract. The lawsuit is on file with the Federal
District Court for the District of Montana, Great Falls Division and is not
subject to protective order. In an order dated September 4, 2001, the Federal
District Court dismissed without prejudice the lawsuit against K2 and deferred
the case to the Blackfeet Tribal Court for determination of whether it has
jurisdiction over the claims made by the Company. The Company has filed a
complaint in Blackfeet Tribal Court in Montana against K2 substantially based
on the grounds asserted in the action previously filed in District Court, while
arguing to the Tribal Court that proper jurisdiction is with the Federal
District Court. K2 has since filed a counterclaim against the Company alleging
F-18
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(9) Commitments and Contingencies (Continued)
that alleged actions by the Company damaged K2 by denying K2 the ability to
participate in the Miller/Blackfeet IMDA and damaged K2's goodwill with Tribal
officials so as to impede other development initiatives on the Reservation. The
Company answered K2's counterclaim by asserting that any damages K2 may have
incurred were caused in whole or in part by their own negligence, conduct, bad
faith or fault. The Company believes the K2 counterclaim is without merit and
will continue to vigorously contest it. The Blackfeet Tribal Business Council
unanimously voted on May 1, 2002, to reaffirm the Company's 50% interest
in the K2/Blackfeet IMDA covering 150,000 net Tribal mineral acres,
over-turning a previous Tribal Business Council decision.
On May 1, 2000, the Company gave notice to the Blackfeet Tribal Business
Council demanding arbitration of all disputes as provided for under the
Miller/Blackfeet IMDA dated February 19, 1999, and pursuant to the K2/Blackfeet
IMDA dated May 30, 1997. The Bureau of Indian Affairs ("BIA") responded to the
Company's request for arbitration by stating that it was the BIA's position
that the Miller/Blackfeet IMDA was terminated. The Company filed an appeal
brief with the Interior Department Appeals Division.
On January 25, 2002, the Interior Department Appeals Division vacated the
BIA's purported termination of the Miller/Blackfeet IMDA to allow arbitration
to proceed. In order to avoid further delay and to avoid the uncertainty and
costs of further pursuing the dispute (including arbitration and litigation)
and to place the parties on a footing that will enable them to pursue a
productive business relationship, the Company and the Blackfeet Tribal Business
Council entered into the amended IMDA Agreement.
The Company was a defendant in a lawsuit filed June 1, 1999 by Energy
Drilling Company ("Energy Drilling"), in the Parish of Catahoula, Louisiana
arising from a blowout of the Victor P. Vegas #1 well that was drilled and
operated by the Company. Energy Drilling, the drilling rig contractor on the
well, was claiming damages related to the destruction of their drilling rig and
related costs amounting to approximately $1.2 million, plus interest,
attorneys' fees and costs. In January 2001, the Federal District Court judge
ruled against the Company on two of the three claims filed in this case with
interest and day-rate charges left undetermined. This ruling was appealed by
the Company to the U.S. Fifth Circuit Court of Appeals with the lower court
ruling being upheld. This ruling is significant for oil and gas operators in
the industry using the Independent Association of Drilling Contractors'
("IADC") standard drilling contracts. The Circuit Court of Appeals interpreted
the IADC contract to assign responsibility for loss of the drilling
contractor's equipment to the operator under a catastrophic event not the fault
of the operator and without determining whether there was an unsound location.
In September 2002, the judgment amount totaling approximately $780,000 was paid
by the Company's insurance carrier.
In August 2002, the Court of Appeals ruled in favor of the Company on
disputed interest and day-rate charges. Energy Drilling has filed an appeal of
the Court of Appeals' decision, which remains unresolved. In February 2003, the
District Court ruled in favor of Energy Drilling on disputed attorney fees. The
Company has filed an appeal of this ruling.
The Company was named in a lawsuit brought by Victor P. Vegas, the landowner
of the surface location of the blowout well referenced above. The suit was
filed July 20, 1999 in the Parish of Orleans, Louisiana, claiming unspecified
damages related to environmental and other matters. Under a Department of
Environmental Quality ("DEQ") approved plan, site remediation has been
completed and periodic testing was being performed. On December 11, 2001, the
plaintiff submitted a remediation plan for more extensive clean-up and a
settlement demand. In February 2002, the Company filed a remediation plan with
the Louisiana DEQ for approval. In July 2002, the Civil District Court ruled
that the DEQ would not have primary jurisdiction and that a jury trial would be
held.
F-19
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(9) Commitments and Contingencies (Continued)
During the fourth quarter of 2002, several meetings were held with the
plaintiff in an effort to resolve this matter. On January 10, 2003, a
confidential settlement agreement was signed, which releases the Company from
all liability from all present and future claims, subject to certain express
reservations associated with this property. The settlement agreement requires
that the Company pay the agreed to settlement amount by March 26, 2003 and
complete the clean up of the property in accordance with a final Louisiana DNR
Office of Conservation Compliance Order. The Company believes that all defense
costs, settlement costs and final clean up costs will be covered by its general
liability and well control insurance.
The Company believes it has meritorious defenses to the unresolved claims
discussed above and intends to vigorously contest them. The Company does not
believe that the final outcome of these matters will have a material adverse
effect on the Company's operating results, financial condition or liquidity.
Due to the uncertainties inherent in litigation, however, no assurances can be
given regarding the final outcome of each action.
(10) Stock-Based Compensation
During 1997, the Company adopted the Stock Option and Restricted Stock Plan
of 1997 (the "1997 Plan"). The 1997 Plan primarily is used to grant stock
options. However, the 1997 Plan permits grants of restricted stock and tax
benefit rights if determined to be desirable to advance the purposes of the
1997 Plan. These stock options, restricted stock and tax benefit rights are
collectively referred to as "Incentive Awards." Persons eligible to receive
Incentive Awards under the 1997 Plan are directors, corporate officers and
other full-time employees of the Company and its subsidiaries. A maximum of
240,000 shares of Common Stock (subject to certain antidilution adjustments)
are available for Incentive Awards under the 1997 Plan.
Upon consummation of the Offering in February 1998, a total of 57,735 stock
options were granted by the Company to directors, corporate officers and other
full-time employees of the Company, and 10,950 shares of restricted stock were
granted to certain employees. Also in February 1998, the Company made a
one-time grant of an aggregate of 27,250 stock options to certain officers
pursuant to the terms of stock option agreements entered into between the
Company and the officers.
The restricted stock vested at cumulative increments of one-half of the
total number of restricted shares of Common Stock subject thereto, beginning on
the first anniversary of the date of grant. Because the shares of restricted
stock were subject to the risk of forfeiture during the vesting period,
compensation expense was recognized over the two-year vesting period as the
risk of forfeiture passed. In February 2000 and 1999, 4,350 and 6,600 shares,
respectively, of restricted stock either vested or was forfeited, and the
Company recognized compensation expense of approximately $0.1 million and $0.2
million, respectively, in each of those years.
During 2002, 2001 and 2000, total incentive stock options of 1,200, 55,200,
and 47,350, respectively, were issued to outside directors and employees under
the 1997 Plan. All of the stock options issued over the past three years have
been granted at or above the closing market prices on the date of grant so no
compensation cost has been recognized for these stock options.
On January 1, 2000, the Company granted 191,500 stock options to certain
employees with an exercise price of $0.10 per share. The options shall vest and
be exercisable when the normal trading average of the stock on the market
remains above the designated values for a period of five consecutive trading
days as follows:
Five-Day Daily Average
Target Percentage Vested
---------------------- -----------------
$20.00 40%
$27.50 30%
$35.00 30%
F-20
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(10) Stock-Based Compensation (Continued)
When it is probable that the five-day stock price target will be attained
(the "measurement date"), the Company will recognize compensation expense for
the differences between the quoted market price of the stock at this
measurement date less the $0.10 per share grant price times the number of
options that will vest. Management does not currently believe it is probable
that any of these targets will be attained during 2003, so no compensation
expense has been recorded yet for these options.
On October 31, 2000, the Company granted 250,000 stock options to employees
with an exercise price of $16.25 per share (the closing market price on the
date of grant). The right to exercise the options shall vest at a rate of
one-fifth per year beginning on the first anniversary of the grant date.
On April 6, 2001, the Company granted 19,000 stock options to the Chief
Executive Officer of the Company. Of those options, 10,000 were issued under
the same terms as those issued to certain employees on January 1, 2000, and the
remaining 9,000 stock options were issued under the same terms as those issued
on October 31, 2000.
On November 12, 2001, the Company granted 337,000 stock options to employees
with an exercise price of $12.50 per share. The right to exercise the options
shall vest at a rate of one-fifth per year beginning on the first anniversary
of the grant date.
The Company accounts for all stock options issued under the provisions and
related interpretations of Accounting Principles Board Opinion ("APB") No. 25,
"Accounting for Stock Issued to Employees." In accordance with SFAS No. 123,
"Accounting for Stock-Based Compensation," the Company intends to continue to
apply APB No. 25 for purposes of determining net income and to present the pro
forma disclosures required by SFAS No. 123.
The status of the restricted stock and stock options granted under the Stock
Option and Restricted Stock Plan of 1997 is as follows:
Restricted Stock Options
---------------- -----------------
Average
Number of Number Grant
Shares of Shares Price
---------------- --------- -------
Outstanding at December 31, 1999 4,350 77,475 $78.90
Granted...................... -- 47,350 9.60
Exercised.................... (4,350) -- --
Forfeited.................... -- (8,600) $53.60
------ ------- ------
Outstanding at December 31, 2000 -- 116,225 $52.40
Granted...................... -- 55,200 10.80
Exercised.................... -- -- --
Forfeited.................... -- (4,900) $54.50
------ ------- ------
Outstanding at December 31, 2001 -- 166,525 $38.60
Granted...................... -- 1,200 3.80
Exercised.................... -- -- --
Forfeited.................... -- (34,975) $29.13
------ ------- ------
Outstanding at December 31, 2002 -- 132,750 $40.72
====== ======= ======
F-21
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(10) Stock-Based Compensation (Continued)
The average fair value of shares granted during 2002, 2001 and 2000 was
$2.11, $7.42 and $9.50, respectively. The fair value of each option grant is
estimated using the Black-Scholes option-pricing model with the following
weighted-average assumptions used for estimating fair value:
Assumption 2002 2001 2000
---------- -------- -------- --------
Dividend Yield......... 0% 0% 0%
Risk-free interest rate 3.875% 4.5% 5.0%
Expected Life.......... 10 years 10 years 10 years
Expected volatility.... 37.9% 38.1% 33.5%
The following table summarizes certain information for the options
outstanding at December 31, 2002:
Options Outstanding Options Exercisable
----------------------------------------- -----------------------
Weighted Average Weighted Average Weighted Average
Range of Grant Prices Shares Remaining Life Grant Price Shares Grant Price
- --------------------- ------- ---------------- ---------------- ------ ----------------
$0.10 to $16.25.... 74,425 8.0 years $10.36 16,260 $14.92
$21.88 to $77.50... 2,800 5.7 years $53.97 1,920 $56.91
$80.00 to $101.25.. 55,525 5.1 years $80.75 44,420 $80.75
------- ------
Total........... 132,750 62,600
======= ======
The Company's pro forma net loss and earnings (loss) per share of common
stock had compensation costs been recorded in accordance with SFAS No. 123, are
presented below (in thousands except per share data):
As Reported Pro Forma
------------------------ -------------------------
2002 2001 2000 2002 2001 2000
------ -------- ------ ------ -------- -------
Net Loss................................. $ (358) $(16,392) $ (977) $ (952) $(16,817) $(1,385)
Earnings (loss) per share of Common Stock
Basic................................. $(0.18) $ (8.43) $(0.73) $(0.48) $ (8.65) $ (1.04)
Diluted............................... $(0.18) $ (8.43) $(0.73) $(0.48) $ (8.65) $ (1.04)
The effects of applying SFAS No. 123 in this pro forma disclosure should not
be interpreted as being indicative of future effects.
(11) Related Party Transactions
In July 1996, Miller Oil Corporation (predecessor to the Company) sold the
building it occupies to C. E. Miller (Chairman of the Company's Board) and
subsequently leased a substantial portion of the building under the terms of a
five-year lease agreement. The lease was renegotiated in 1998 for a five-year
term to increase the square footage being leased. (See Note 9). A gain on the
sale of the property of approximately $160,000 was realized. This gain was
deferred and is being amortized in proportion to the gross rental charges under
the operating lease.
During 1999, Eagle purchased a working interest in certain unproved oil and
gas properties from the Company for $3.9 million. The Company believes that the
purchase price was representative of the fair market value of these interests
and that the terms were consistent with those available to unrelated parties.
The Company repurchased certain of these properties in 2000 from Eagle, as more
fully described in Note 6.
F-22
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(11) Related Party Transactions (Continued)
On February 27, 2001, the Board of Directors (including the disinterested
directors) unanimously passed a resolution approving the sale of certain
working interests to and the participation of certain affiliates of the Company
(Guardian Energy Management Corp., Guardian Energy Exploration Corp., Robert
Boeve, and Eagle Investments, Inc.) or entities controlled by these affiliates
in joint exploration agreements for the development of the Illinois Basin
project and four Mississippi prospects. The terms offered under the joint
exploration agreements were substantially the same as those offered to third
parties on an arms-length basis. The terms included reimbursement to the
Company of certain lease acquisition and geological and geophysical expenses
incurred to date at the proportional interests acquired and certain rights to
the Company involving back-in after payout provisions ranging from 30% to 35%
on the Mississippi prospects. All development costs will be shared by the
Company and the participants on the basis of their proportional working
interests.
In May 2001, the Company contracted a broker to sell the Company's right,
title and interest in certain leases located in Michigan. The broker sold the
leases to a third party, which in turn subsequently sold the leases to a group
in which a member of the Company's Board of Directors had a 30% beneficial
ownership. The Company believes that the purchase price was representative of
the fair market value of these leases and that the terms were consistent with
those available to unrelated parties.
In the normal course of business, the Company from time to time will sell an
interest in a prospect to related parties or certain of their affiliates. The
terms of these sales are consistent with those available to unrelated parties.
(12) Concentrations of Risk
The Company extends credit to various companies in the oil and gas industry
in the normal course of business. Within this industry, certain concentrations
of credit risk exist. The Company, in its role as operator of co-owned
properties, assumes responsibility for payment to vendors for goods and
services related to joint operations and extends credit to co-owners of these
properties.
This concentration of credit risk may be similarly affected by changes in
economic or other conditions and may, accordingly, impact the Company's overall
credit risk. The Company periodically monitors its customers' and co-owners'
financial conditions.
The Company also has a significant concentration of properties in the
Mississippi Salt Basin, which are affected by changes in economic and other
conditions, including but not limited to crude oil and natural gas prices and
operating costs.
(13) Non-Cash Activities
In December 2000, the Company issued 148,149 shares of common stock and
203,125 warrants to Eagle in exchange for certain non-producing oil and gas
properties valued for financial reporting purposes at $2.6 million, as more
fully described in Note 6. Also, the Company recorded $1.7 million of non-cash
interest expense relating to the Guardian Convertible Promissory Note and the
issuance of common stock warrants to Guardian, as more fully described in Note
6.
The Company issued 24,350, 10,630, and 16,297 shares of common stock to its
directors during the years ended December 31, 2002, 2001 and 2000, respectively
as compensation as provided for under the Equity Compensation Plan for
Non-employee Directors. The Company issued 19,925, 7,021 and 4,954 shares of
common stock to the Company's 401(k) Savings Plan during the years ended
December 31, 2002, 2001 and 2000, respectively, representing the Company's
matching contribution to the Plan.
F-23
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(14) Significant Customers
Revenues from certain customers accounted for more than 10% of total crude
oil and natural gas sales as follows:
For the Year Ended
December 31,
-----------------
2002 2001 2000
---- ---- ----
BP Energy Company........................ 24% -- --
EOTT Energy Partners, L.P................ 21% 15% 16%
Aquila, Inc.............................. 19% 18% 11%
Duke Energy Trading and Marketing, L.L.C. 10% 25% 45%
Mirant Americas Energy Marketing, L.P.... -- 29% --
Southern Co. Energy Marketing, L.P....... -- 16% --
Reliant Energy Entex..................... -- -- 19%
(15) Supplemental Financial Information on Oil and Gas Exploration,
Development and Production
Activities (Unaudited)
The following information was prepared in accordance with the Supplemental
Disclosure Requirements of SFAS No. 69, "Disclosures About Oil and Gas
Producing Activities."
Users of this information should be aware that the process of estimating
quantities of "proved" and "proved developed" crude oil and natural gas
reserves is very complex, requiring significant subjective decisions in the
evaluation of all available geological, engineering and economic data for each
reservoir. The data for a given reservoir also may change substantially over
time as a result of numerous factors including, but not limited to, additional
development activity, evolving production history and continual reassessment of
the viability of production under varying economic conditions. Consequently,
material revisions to existing reserve estimates occur from time to time.
Although every reasonable effort is made to ensure that reserve estimates
reported represent the most accurate assessments possible, the significance of
the subjective decisions required and variances in available data for various
reservoirs make these estimates generally less precise than other estimates
presented in connection with financial statement disclosures.
Proved reserves represent estimated quantities of natural gas and crude oil
that geological and engineering data demonstrate, with reasonable certainty, to
be recoverable in future years from known reservoirs under economic and
operating conditions existing at the time the estimates were made.
Proved developed reserves are proved reserves expected to be recovered,
through wells and equipment in place and under operating methods being utilized
at the time the estimates were made.
The following estimates of proved reserves and future net cash flows as of
December 31, 2002, 2001, and 2000 have been prepared by Miller and Lents, Ltd.,
independent petroleum engineers. All of the Company's reserves are located in
the United States.
F-24
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(15) Supplemental Financial Information on Oil and Gas Exploration,
Development and Production Activities (Unaudited) (Continued)
Estimated Quantities of Proved Oil and Gas Reserves
The following table sets forth the Company's net proved and proved developed
reserves at December 31 for each of the three years in the period ended
December 31, 2002, and the changes in the net proved reserves for each of the
three years in the period then ended as estimated by petroleum engineers for
the respective periods as described in the preceding paragraph:
Total
--------------------
Oil (MBbl) Gas (MMcf)
---------- ----------
Estimated Proved Reserves
December 31, 1999................... 488.4 14,957.2
------ --------
Extensions and discoveries...... 418.8 694.1
Revisions and other changes..... (342.4) 1,228.0
Production...................... (205.3) (5,762.0)
Sale of reserves................ (30.0) (605.5)
------ --------
December 31, 2000................... 329.5 10,511.8
------ --------
Extensions and discoveries...... 302.4 967.1
Revisions and other changes..... 129.0 (680.3)
Production...................... (159.6) (3,473.2)
Sale of reserves................ -- --
------ --------
December 31, 2001................... 601.3 7,325.4
------ --------
Extensions and discoveries...... 51.2 27.3
Revisions and other changes..... 25.4 361.7
Production...................... (139.2) (2,189.7)
Sales of reserves............... (240.7) (515.7)
------ --------
December 31, 2002................... 298.0 5,009.0
====== ========
Estimated Proved Developed Reserves
December 31, 2000................... 301.8 10,511.7
====== ========
December 31, 2001................... 586.8 7,325.4
====== ========
December 31, 2002................... 228.1 5,009.0
====== ========
The following table summarizes the average year-end prices (net of basis
adjustments) used to estimate reserves in accordance with SEC guidelines.
2002 2001 2000
------ ------ ------
Natural gas (per mcf) $ 4.88 $ 2.55 $ 9.55
Oil (per barrel)..... $27.50 $16.72 $23.36
Standardized Measure of Discounted Future Net Cash Flows Relating To Proved
Oil and Gas Reserves
The following information has been developed utilizing procedures prescribed
by SFAS No. 69 and based on crude oil and natural gas reserve and production
volumes estimated by the Company's petroleum engineers. It may be useful for
certain comparison purposes, but should not be solely relied upon in evaluating
the Company or its performance. Further, information contained in the following
table should not be considered as representative of realistic assessments of
future cash flows, nor should the Standardized Measure of Discounted Future Net
Cash Flows be viewed as representative of the current value of the Company.
F-25
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(15) Supplemental Financial Information on Oil and Gas Exploration,
Development and Production
Activities (Unaudited) (Continued)
The future cash flows presented below are computed by applying year-end and
prices to year-end quantities of proved crude oil and natural gas reserves.
Future production and development costs are computed by estimating the
expenditures to be incurred in developing and producing the Company's proved
reserves based on year-end costs and assuming continuation of existing economic
conditions. It is expected that material revisions to some estimates of crude
oil and natural gas reserves may occur in the future, development and
production of the reserves may occur in periods other than those assumed and
actual prices realized and costs incurred may vary significantly from those
used.
Management does not rely upon the following information in making investment
and operating decisions. Such decisions are based upon a wide range of factors,
including estimates of probable as well as proved reserves, and varying price
and cost assumptions considered more representative of a range of possible
economic conditions that may be anticipated.
The following table sets forth the Standardized Measure of Discounted Future
Net Cash Flows from projected production of the Company's crude oil and natural
gas reserves at December 31, 2002, 2001 and 2000:
2002 2001 2000
------- ------- --------
(In thousands)
Future revenues(1)...................................... $32,637 $28,731 $108,088
Future production costs(2).............................. (8,606) (7,794) (16,412)
Future development costs(2)............................. (347) (523) (502)
------- ------- --------
Future net cash flows................................... 23,684 20,414 91,174
Discount to present value at 10% annual rate............ (4,634) (3,957) (16,265)
------- ------- --------
Present value of future net revenues before income taxes 19,049 16,457 74,909
Future income taxes discounted at 10% annual rate(3).... -- -- (8,235)
------- ------- --------
Standardized measure of discounted future net cash flows $19,049 $16,457 $ 66,674
======= ======= ========
- --------
(1) Crude oil and natural gas revenues are based on year-end prices with
adjustments for changes reflected in existing contracts. There is no
consideration for future discoveries or risks associated with future
production of proved reserves.
(2) Based on economic conditions at year-end. Does not include administrative,
general or financing costs. Does not consider future changes in development
or production costs.
(3) The 2002 and 2001 balance is not reduced by income taxes due to the tax
basis of the properties and net operating loss and depletion carryforwards.
F-26
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(15) Supplemental Financial Information on Oil and Gas Exploration,
Development and Production Activities (Unaudited) (Continued)
Changes in Standardized Measure of Discounted Future Net Cash Flows
The following table sets forth the changes in the Standardized Measure of
Discounted Future Net Cash Flows at December 31, 2002, 2001 and 2000:
2002 2001 2000
------- -------- --------
(In thousands)
New discoveries.......................... $ 886 $ 4,318 $ 5,561
Sales of reserves in place............... (2,731) -- (776)
Revisions to reserves.................... 1,415 (3,483) (5,073)
Sales, net of production costs........... (8,408) (14,855) (23,015)
Changes in prices........................ 19,009 (61,067) 91,684
Accretion of discount.................... 1,646 7,491 2,872
Income taxes............................. -- 8,235 (8,235)
Changes in timing of production and other (9,224) 9,144 (25,064)
------- -------- --------
Net change during the year............... $ 2,593 $(50,217) $ 37,954
======= ======== ========
Capitalized Cost Related to Oil and Gas Producing Activities
The following table sets forth the capitalized costs relating to the
Company's natural gas and crude oil producing activities at December 31, 2002
and 2001:
2002 2001
--------- ---------
(In thousands)
Proved properties......................................... $ 155,189 $ 146,649
Unproved properties....................................... 2,375 11,244
--------- ---------
157,564 157,893
Less--Accumulated depreciation, depletion and amortization (138,826) (124,618)
--------- ---------
$ 18,738 $ 33,275
========= =========
Cost Incurred In Oil and Gas Producing Activities
The acquisition, exploration and development costs disclosed in the
following tables are in accordance with definitions in SFAS No. 19, "Financial
Accounting and Reporting by Oil and Gas Producing Companies." Acquisition costs
include costs incurred to purchase, lease or otherwise acquire property.
Exploration costs include exploration expenses, additions to exploration wells
in progress and depreciation of support equipment used in exploration
activities. Development costs include additions to production facilities and
equipment, additions to development wells in progress and related facilities
and depreciation of support equipment and related facilities used in
development activities.
F-27
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(15) Supplemental Financial Information on Oil and Gas Exploration,
Development and Production Activities (Unaudited) (Continued)
The following table sets forth costs incurred related to the Company's oil
and gas activities for the years ended December 31:
2002 2001 2000
------ ------ -------
(In thousands)
Property acquisition costs $ 863 $1,310 $ 4,323
Exploration costs......... 996 1,057 1,928
Development costs......... 1,559 7,605 4,965
------ ------ -------
Total(1)............... $3,418 $9,972 $11,216
====== ====== =======
- --------
(1) Includes $2,624 in 2000 of non-cash, non-producing properties acquired from
Eagle as more fully described in Note 6.
Results of Operations From Oil and Gas Producing Activities
The following table sets forth the Company's results of operations from oil
and gas producing activities for the years ended December 31, 2002, 2001 and
2000. The results of operations below do not include general and administrative
expenses, income taxes and interest expense.
2002 2001 2000
------- -------- -------
(In thousands)
Operating Revenues:
Natural gas................................... $ 7,182 $ 14,304 $20,745
Crude oil and condensate...................... 2,937 3,495 5,300
------- -------- -------
Total operating revenues.................. 10,119 17,799 26,045
------- -------- -------
Operating expenses:
Lease operating expenses and production taxes. $ 1,711 $ 2,944 $ 3,030
Depreciation, depletion and amortization...... 7,458 13,431 17,457
Cost ceiling writedown........................ 7,000 15,500 --
------- -------- -------
Total operating expenses.................. 16,169 31,875 20,487
------- -------- -------
Results of operations............................ $(6,050) $(14,076) $ 5,558
======= ======== =======
F-28
MILLER EXPLORATION COMPANY
SUPPLEMENTAL QUARTERLY FINANCIAL DATA
Unaudited Quarterly Financial Information
Quarter Ended
----------------------------------
March 31 June 30 Sept. 30 Dec. 31
-------- ------- -------- -------
(In thousands, except per share data)
2002
Total Operating Revenues $1,836 $ 2,941 $ 2,086 $ 3,417
Operating Income (Loss). (449) (7,473) (143) 163
Net Income (Loss)....... (425) (2,156) (288) 2,511
Earnings per share:
Basic................ (0.22) (1.09) (0.14) 1.27
Diluted.............. (0.22) (1.09) (0.14) 1.27
2001
Total Operating Revenues $6,589 $ 4,782 $ 3,555 $ 3,142
Operating Income (Loss). 902 (7,581) (1,276) (7,712)
Net Income (Loss)....... 396 (7,743) (1,341) (7,704)
Earnings per share:
Basic................ 0.20 (3.98) (0.69) (3.96)
Diluted.............. 0.20 (3.98) (0.69) (3.96)
2000
Total Operating Revenues $5,723 $ 6,469 $ 7,037 $ 7,338
Operating Income........ 185 864 1,405 1,529
Net Income (Loss)....... (438) 30 245 (814)
Earnings per share:
Basic................ (0.34) 0.02 0.19 (0.55)
Diluted.............. (0.34) 0.02 0.14 (0.55)
In the opinion of the Company, the preceding quarterly information includes
all necessary adjustments necessary for a fair statement of the results of
operations for such periods. Earnings per share for each quarter are calculated
based upon the weighted average number of shares outstanding during each
quarter. As a result, adding the earnings per share for each quarter of a year
may not equal annual earnings per share due to changes in shares outstanding
throughout the year.
F-29
EXHIBIT INDEX
Exhibit No. Description
- ----------- -----------
2.1 Exchange and Combination Agreement dated November 12, 1997. Previously filed as exhibit 2.1
to the Company's Registration Statement on Form S-1 (333-40383), and here incorporated by
reference.
2.2(a) Letter Agreement amending Exchange and Combination Agreement. Previously filed as an exhibit
to the Company's Registration Statement on Form S-1 (333-40383), and here incorporated by
reference.
2.2(b) Letter Agreement amending Exchange and Combination Agreement. Previously filed as an exhibit
to the Company's Registration Statement on Form S-1 (333-40383), and here incorporated by
reference.
2.2(c) Letter Agreement amending Exchange and Combination Agreement. Previously filed as an exhibit
to the Company's Registration Statement on Form S-1 (333-40383), and here incorporated by
reference.
2.3(a) Agreement for Purchase and Sale dated November 25, 1997 between Amerada Hess Corporation
and Miller Oil Corporation. Previously filed as an exhibit to the Company's Registration
Statement on Form S-1 (333-40383), and here incorporated by reference.
2.3(b) First Amendment to Agreement for Purchase and Sale dated January 7, 1998. Previously filed as
an exhibit to the Company's Registration Statement on Form S-1 (333-40383), and here
incorporated by reference.
3.1 Certificate of Incorporation of the Registrant. Previously filed as an exhibit to the Company's
Registration Statement on Form S-1 (333-40383), and here incorporated by reference.
3.2 Certificate of Amendment to the Certificate of Incorporation of the Registrant. Previously filed as
an exhibit to the Company's Quarterly Report on Form 10-Q filed on November 14, 2002.
3.3 Bylaws of the Registrant. Previously filed as an exhibit to the Company's Quarterly Report on
Form 10-Q for the quarter ended June 30, 1998, and here incorporated by reference.
4.1 Certificate of Incorporation. See Exhibit 3.1.
4.2 Bylaws. See Exhibit 3.3.
4.3 Form of Specimen Stock Certificate. Previously filed as an exhibit to the Company's Registration
Statement on Form S-1 (333-40383), and here incorporated by reference.
4.4 Warrant between Miller Exploration Company and Guardian Energy Management Corp. dated
July 11, 2000, exercisable for 1,562,500 shares of the Company's Common Stock. Previously
filed as an exhibit to the Company's Current Report on Form 8-K filed July 25, 2000, and here
incorporated by reference.
4.5 Warrant between Miller Exploration Company and Guardian Energy Management Corp. dated
July 11, 2000, exercisable for 2,500,000 shares of the Company's Common Stock. Previously
filed as an exhibit to the Company's Current Report on form 8-K filed July 25, 2000, and here
incorporated by reference.
4.6 Warrant between Miller Exploration Company and Guardian Energy Management Corp. dated
July 11, 2000, exercisable for 9,000,000 shares of the Company's Common Stock. Previously
filed as an exhibit to the Company's Current Report on Form 8-K filed July 25, 2000, and here
incorporated by reference.
Exhibit No. Description
- ----------- -----------
4.7 Amendment to Promissory Note, Warrant and Rights Agreement between Miller Exploration
Company and Veritas DGC Land, Inc., dated July 19, 2000. Previously filed as an exhibit to the
Company's Current Report on Form 8-K filed July 25, 2000, and here incorporated by
reference.
10.1(a) Stock Option and Restricted Stock Plan of 1997.* Previously filed as an exhibit to the Company's
Annual Report on Form 10-K for the year ended December 31, 1997, and here incorporated by
reference.
10.1(b) Amended and Restated Stock Option and Restricted Stock Plan of 1997 dated February 25, 2000.*
10.1(c) Amended and Restated Stock Option and Restricted Stock Plan of 1997 dated March 20, 2001.*
10.1(d) Amended and Restated Stock Option and Restricted Stock Plan of 1997 dated March 18, 2002.*
10.2(a) Form of Stock Option Agreement.* Previously filed as an exhibit to the Company's Annual
Report on Form 10-K for the year ended December 31, 1997, and here incorporated by
reference.
10.2(b) Form of Restricted Stock Agreement.* Previously filed as an exhibit to the Company's Annual
Report on Form 10-K for the year ended December 31, 1997, and here incorporated by
reference.
10.3 Form of Director and Officer Indemnity Agreement. Previously filed as an exhibit to the
Company's Registration Statement on Form S-1 (333-40383), and here incorporated by
reference.*
10.4 Lease Agreement between Miller Oil Corporation and C.E. and Betty Miller, dated July 24, 1996.
Previously filed as an exhibit to the Company's Registration Statement on Form S-1
(333-40383), and here incorporated by reference.
10.5 Letter Agreement dated November 10, 1997, between Miller Oil Corporation and C.E. Miller,
regarding sale of certain assets. Previously filed as an exhibit to the Company's Registration
Statement on Form S-1 (333-40383), and here incorporated by reference.
10.6 Amended Service Agreement dated January 1, 1997, between Miller Oil Corporation and Eagle
Investments, Inc. Previously filed as an exhibit to the Company's Registration Statement on
Form S-1 (333-40383), and here incorporated by reference.
10.7 Form of Registration Rights Agreement (included as Exhibit E to Exhibit 2.1). Previously filed as
an exhibit to the Company's Registration Statement on Form S-1 (333-40383), and here
incorporated by reference.
10.8 $2,500,000 Promissory Note dated November 26, 1997 between Miller Oil Corporation and the
C.E. Miller Trust. Previously filed as an exhibit to the Company's Registration Statement on
Form S-1 (333-40383), and here incorporated by reference.
10.9 Form of Indemnification and Contribution Agreement among the Registrant and the Selling
Stockholders. Previously filed as an exhibit to the Company's Registration Statement on
Form S-1 (333-40383), and here incorporated by reference.
10.10 Agreement between Eagle Investments, Inc. and Miller Oil Corporation, dated April 1, 1999.
Previously filed as an exhibit to the Company's Annual Report on Form 10-K for the year
ended December 31, 1998, and here incorporated by reference.
10.11 $4,696,040.60 Note between Miller Exploration Company and Veritas DGC Land, Inc., dated
April 14, 1999. Previously filed as an exhibit to the Company's Annual Report on Form 10-K
for the year ended December 31, 1998, and here incorporated by reference.
Exhibit No. Description
- ----------- -----------
10.12 Warrant between Miller Exploration Company and Veritas DGC Land, Inc., dated April 14, 1999.
Previously filed as an exhibit to the Company's Annual Report on Form 10-K for the year
ended December 31, 1998, and here incorporated by reference.
10.13 Registration Rights Agreement between Miller Exploration Company and Veritas DGC Land,
Inc., dated April 14, 1999. Previously filed as an exhibit to the Company's Annual Report on
Form 10-K for the year ended December 31, 1998, and here incorporated by reference.
10.14 Agreement between Eagle Investments, Inc. and Miller Exploration Company, dated March 16,
1999. Previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1999, and here incorporated by reference.
10.15 Agreement between Eagle Investments, Inc. and Miller Exploration Company, dated May 18,
1999. Previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1999, and here incorporated by reference.
10.16 Agreement between Eagle Investments, Inc. and Miller Exploration Company, dated May 27,
1999. Previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1999, and here incorporated by reference.
10.17 Agreement between Eagle Investments, Inc. and Miller Exploration Company, dated June 30,
1999. Previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1999, and here incorporated by reference.
10.18 Agreement between Eagle Investments, Inc. and Miller Exploration Company, dated October 18,
1999. Previously filed as an exhibit to the Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1999, and here incorporated by reference.
10.19(a) Form of Equity Compensation Plan for Non-Employee Directors Agreement dated December 7,
1998. Previously filed as an exhibit to the Company's Proxy Statement on Schedule 14A dated
May 13, 1999, and here incorporated by reference.
10.19(b) Amended and Restated Equity Compensation Plan for Non-Employee Directors dated
February 25, 2000. Previously filed as an exhibit to the Company's Proxy Statement on
Schedule 14A dated April 25, 2000, and here incorporated by reference.
10.19(c) Amended and Restated Equity Compensation Plan for Non-Employee Directors dated March 20,
2001.
10.19(d) Amended and Restated Equity Compensation Plan for Non-Employee Directors dated March 18,
2002.
10.20 Form of Employment Agreement for Lew P. Murray dated February 9, 1998.* Previously filed as
an exhibit to the Company's Annual Report on Form 10-K for the year ended December 31,
2000, and here incorporated by reference.
10.21 Form of Employment Agreement for Michael L. Calhoun dated February 9, 1998.* Previously
filed as an exhibit to the Company's Annual Report on Form 10-K for the year ended
December 31, 2000, and here incorporated by reference.
10.22 Securities Purchase Agreement between Miller Exploration Company and Guardian Energy
Management Corp. dated July 11, 2000. Previously filed as an exhibit to the Company's Current
Report on Form 8-K filed on July 25, 2000.
10.23 Promissory Note between Miller Exploration Company and Guardian Energy Management Corp.
dated July 11, 2000. Previously filed as an exhibit to the Company's Current Report on
Form 8-K filed on July 25, 2000.
10.24 Registration Rights Agreement between Miller Exploration Company and Guardian Energy
Management Corp. dated July 11, 2000. Previously filed as an exhibit to the Company's Current
Report on Form 8-K filed on July 25, 2000.
Exhibit No. Description
- ----------- -----------
10.25 Form of Subscription Agreement between Miller Exploration Company and ECCO Investments,
LLC dated July 11, 2000. Previously filed as an exhibit to the Company's Current Report on
Form 8-K filed on July 25, 2000.
10.26 Form of Letter Agreement between Miller Exploration Company and Eagle Investments, Inc.
dated July 12, 2000. Previously filed as an exhibit to the Company's Current Report on
Form 8-K filed on July 25, 2000.
10.27 Amended and Restated Credit Agreement between Miller Exploration Company and the
Subsidiaries of the Company and Bank One, Texas, N.A., dated July 18, 2000. Previously filed
as an exhibit to the Company's Quarterly Report on Form 10-Q filed on August 14, 2000.
10.28 Second Amendment to Promissory Note, Warrant and Registration Rights Agreement dated
June 28, 2002, between Veritas DGC Land, Inc. and Miller Exploration Company. Previously
filed as an exhibit to the Company's Quarterly Report on Form 10-Q filed on August 12, 2002.
10.29 Exploration and Development Agreement dated June 17, 1998, between K2 America Corporation,
K2Energy Corporation, and Miller Exploration Company.
10.30(a) Oil and Gas Exploration and Development Agreement dated February 19, 1999, between the
Blackfeet Tribal Business Council of the Blackfeet Indian Tribe of the Blackfeet Indian
Reservation and Miller Exploration Company.
10.30(b) Amended Oil and Gas Exploration Agreement dated June 3, 2002, between the Blackfeet Business
Council of the Blackfeet Indian Tribe of the Blackfeet Indian Reservation.
11.1 Computation of Earnings per Share.
21.1 Subsidiaries of the Registrant. Previously filed as an exhibit to the Company's Registration
Statement on Form S-1 (333-40383), and here incorporated by reference.
23.1 Consent of Miller and Lents, Ltd.
23.2 Consent of Plante & Moran, PLLC
24.1 Limited Power of Attorney.
- --------
* Management contract or compensatory plan or arrangement.