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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, 2000
[_] 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
MILLER EXPLORATION COMPANY
(Exact Name of Registrant as Specified in Its Charter)
Delaware 38-3379776
(State or Other Jurisdiction of (I.R.S. Employer Identification No.)
Incorporation or Organization)
3104 Logan Valley Road 49685-0348
Traverse City, Michigan (Zip Code)
(Address of Principal Executive Offices)
Registrant's telephone number, including area code: (231) 941-0004
Securities registered pursuant to Section 12(g) of the Act:
Title of each class
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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. [_]
Number of shares outstanding of the registrant's Common Stock, $0.01 par
value (excluding shares of treasury stock) as of March 20, 2001: 19,336,949
The aggregate market value of the registrant's voting stock held by non-
affiliates of the registrant as of March 20, 2001: $24,171,186
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the Company's May 25, 2001
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.
Miller Exploration Company ("Miller" or the "Company") is an independent oil
and gas exploration and production company with exploration efforts
concentrated primarily in the Mississippi Salt Basin of Central Mississippi.
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.
The Company was organized in connection with the combination (the
"Combination Transaction") of MOC and interests in oil and natural gas
properties owned by certain affiliated entities and interests in such
properties owned by certain business partners and investors.
The Combination Transaction closed on February 9, 1998 in connection with
the closing of the Company's initial public offering of 5.5 million shares of
Common Stock (the "Offering"). The Offering, including the sale of an
additional 62,500 shares of Common Stock by the Company on March 9, 1998
pursuant to the exercise of the underwriters' over-allotment option, resulted
in net proceeds to the Company of approximately $40.4 million after expenses.
Miller incurred expenditures for exploration and development activity of
$8.6 million with respect to the Company's interest in 8 gross wells (1.8 net
to the Company) for the year ended December 31, 2000 and $10.3 million with
respect to the Company's interest in 9 gross wells (5.5 net to the Company) for
the year ended December 31, 1999. At December 31, 2000, the Company also had 3
gross wells (1.3 net to the Company) in the process of drilling and/or
completing. In 2000, the Company also acquired undeveloped oil and gas
properties valued for financial statement reporting purposes at $2.6 million
from Eagle Investments Inc. ("Eagle") in exchange for shares of Company common
stock and warrants. The Company currently plans to drill 19 wells (8.9 net to
the Company) in 2001, 9 of which will be exploratory wells in the Mississippi
Salt Basin. The Company anticipates 2001 capital expenditures for exploration
and development activity in all of its areas of concentration will be
approximately $10.0 million.
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 a number of under-developed salt domes. 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 geologic
structures were formed by the upward thrusting of subsurface salt accumulations
towards the surface. 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. The salt domes of
the Mississippi Salt Basin were formed in the Cretaceous period. 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. This 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. The Company owns undeveloped leasehold interests in 44,376
gross acres (21,780 net to the Company) covering 21 known salt domes and
related salt structures.
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The Company believes that the key to exploiting salt dome prospects
effectively is the accurate delineation of a salt dome's flanks, with the
recognition of fault patterns and the location of fault blocks with large
reserve potential. While reinterpreted 2-D seismic data provided the Company's
explorationists with better imaging of a salt dome's subsurface structures, it
proved to have limitations in defining the exact locations of the flanks of a
salt dome. In 1998, the Company acquired approximately 400 square miles of 3-D
seismic data in the Mississippi Salt Basin. The Company believes that wells
drilled on the 3-D data demonstrate that the 3-D seismic more effectively
images the edge of the salt dome, identifying areas that had not been seen on
the 2-D seismic, in addition to providing better definition of the size and
location of future drilling targets. 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 15 producing wells in the Mississippi Salt
Basin that had an aggregate average production rate as of December 31, 2000 of
40.5 million cubic feet of natural gas equivalent per day ("MMcfe/d") gross
(13.6 MMcfe/d net to the Company) at depths ranging from 10,800 to 17,900 feet.
Since the Company began its exploration activity in Mississippi in 1993, it has
participated in 28 2-D seismic supported and 11 3-D seismic supported wells
drilled around 13 salt dome structures, with 14 of the 2-D wells (50%) and six
of the 3-D wells (55%) establishing commercial production. At December 31,
2000, the Company also was in the process of drilling and/or completing 3 3-D
wells (1.3 net to the Company). The Company has 9 gross wells (2.8 net to the
Company) budgeted in 2001 for the Mississippi Salt Basin with a capital
expenditure budget of $8.7 million, including $1.6 million for land and seismic
costs. All 9 of the Mississippi Salt Basin wells budgeted for 2001 will be
based on 3-D seismic data
Blackfeet Indian Reservation
The Company entered into an Exploration and Development Agreement (the
"EDA") with K2 Energy Corporation on June 17, 1998 to explore and 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 Agreement (the "K2
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 "Item 3--Legal Proceedings" for a
discussion of this litigation.
The Company entered into a separate Indian Mineral Development Act ("IMDA")
Agreement with the Tribe covering 100,000 Tribal acres that was approved
February 26, 1999 (the "Miller Agreement"). 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
26, 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. In
addition to the standard force majeure language, Miller negotiated the ability
for a one-year extension of the drilling commitment for which the Tribe agreed
the extension would not be unreasonably withheld. The terms of the extension
were $2 per acre up to a maximum of $200,000 prorated for the number of months
the extension was granted. The specific provisions of the Miller Agreement
provide that the Company will not ask for an unreasonable amount of time nor
will the Tribe unreasonably withhold its consent. The Company will earn 20,000
acres with each set of two wells drilled, regardless of the outcome of the
wells. A separate oil and gas lease covering 640 acres 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
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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 said lands. 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 Agreement dated February 19, 1999, and
pursuant to the K2 Agreement dated May 30, 1997. In February 2001, the Company
deposited the $0.5 million record anniversary payment stipulated in the Miller
Agreement into an escrow account pending resolution of disputes with the Tribe
mentioned above.
During 2000, the Company acquired 10,492 gross non-Tribal acres (10,492 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.
Joint Venture Exploration, Participation and Farm-out Agreements
The Company is a party to the following joint venture exploration,
participation, farm-out and other agreements:
Mississippi Salt Basin Agreements
Since March 1993, the Company has entered into a series of joint venture
exploration agreements and farm-out agreements with Amerada Hess Corporation,
Liberty Energy Corporation, Bonray, Inc., Key Production Company Inc. ("Key"),
Remington Oil & Gas Corp. ("Remington") and Eagle. These agreements govern the
rights and obligations of the Company and the other working-interest owners
with respect to lease acquisition, seismic surveys, drilling and development of
specified geographic areas of mutual interest (AMI's) over and around 20 salt
domes and related salt structures in Southern Mississippi within the
Mississippi Salt Basin. The joint venture exploration agreements began to
expire January 1, 2000, except with respect to AMI's in which the Company and
its partners have established production and where joint operating agreements
have been executed. In the case where joint operating agreements have been
executed, the term extends as long as any lease within that AMI remains in
effect.
In October 1999, the Company executed a joint venture agreement with
Remington covering multiple salt domes in the Mississippi Salt Basin. The terms
of the joint venture arrangement provided an up front cash payment to the
Company with the opportunity to participate in the drilling of five prospects
in the Company's Mississippi Salt Basin Project. Remington earned a position in
undeveloped acreage ranging from 14% to 40% working interest in the prospects
by paying a disproportionate share of drilling costs in the five-well program.
Blackfeet Indian Reservation Agreements
See "Blackfeet Indian Reservation" for a discussion of the Company's joint
venture agreements in that area.
4
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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2000 1999 1998
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Production:
Crude oil and condensate (MBbls).......... 205.3 255.9 247.6
Natural gas (MMcf)........................ 5,762.0 7,593.8 8,953.3
Natural gas equivalent (MMcfe)............ 6,993.8 9,129.2 10,438.7
Average sales prices:
Crude oil and condensate ($ per Bbl)...... $ 25.82 $ 13.54 $ 10.69
Natural gas ($ per Mcf)................... 3.60 2.27 2.05
Natural gas equivalent ($ per Mcfe)....... 3.72 2.27 2.01
Average costs ($ per Mcfe):
Lease operating expenses and production
taxes.................................... $ 0.43 $ 0.19 $ 0.32
Depreciation, depletion and amortization.. 2.49 1.76 1.53
General and administrative................ 0.30 0.34 0.33
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 1998, 1999,
and 2000, with spot market prices for crude oil falling below $10 per Bbl, and
then rising over $34 per Bbl, and natural gas prices dropping below $1.00 per
Mcf and then climbing up above $10 per Mcf during this three-year period. These
wide 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, 2000, sales to the Company's three
largest customers were approximately 65%, 16%, and 11%, 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
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prospects, to acquire additional properties and to discover reserves in the
future will depend upon its ability to conduct its operations, to evaluate and
select suitable properties and to consummate transactions in a highly
competitive environment.
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 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 enacted a bill that reduces the production tax
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
2000, the State of Mississippi notified the Company that all price ceilings had
been exceeded which effectively phased out any tax abatements. The Company has
paid the full production tax on all Mississippi oil and gas production since
June 2000.
Governmental Regulation
The Company's oil and natural gas exploration, production and related
operations are subject to 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.
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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 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
"unbundle" 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. Although Order No. 636
largely has been upheld on appeal, several appeals remain pending in related
restructuring proceedings. It is difficult to predict when these remaining
appeals will be completed or their impact on the Company.
FERC has announced several important transportation-related policy
statements and proposed rule changes, including a statement of policy and a
request for comments concerning alternatives to its traditional cost-of-service
ratemaking methodology to establish the rates interstate pipelines may charge
for their services. A number of pipelines have obtained FERC authorization to
charge negotiated rates as one such alternative. In February 1997, FERC
announced a broad inquiry into issues facing the natural gas industry to assist
FERC in establishing regulatory goals and priorities in the post-Order No. 636
environment. 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 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, 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
7
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.
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
8
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 20, 2001, the Company had 23 full-time employees, including two
geologists, a geophysicist and two engineers. None of the Company's employees
are represented by any labor union. The Company believes its relations with its
employees are good. 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.
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 within a particular region will not
decline. 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 2001 capital 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
9
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.
Volatility of Oil and Natural Gas Prices
The Company's revenues, operating results and future rate of growth 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 worldwide 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. A return to the significantly lower
oil and gas prices experienced in 1998 and early 1999, as compared to
historical averages, would likely have a material adverse effect on the
Company's financial condition, liquidity, ability to finance planned capital
expenditures and results of operations. 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 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.
Risks Associated with Management and Implementation of Growth Strategy
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. As 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.
The Company's ability to continue its growth will depend upon a number of
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.
10
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,
some of whom are non-employee consultants and independent contractors, having
considerable experience in oil and natural gas 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.
11
Substantial Capital Projects
The Company makes and will continue to make capital expenditures in its
exploration and development projects. The Company intends to finance these
capital expenditures with cash flow from operations. 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, 2000, the Company had total indebtedness of $12.2
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 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, 2000, the Company's directors, executive officers and
certain of their affiliates, beneficially owned approximately 41% of the
Company's outstanding Common Stock. Guardian Energy Management Corp.
("Guardian") also owns approximately 19% of the Company's outstanding stock.
Accordingly, these stockholders, as a group, may be able to 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.
12
Forward-Looking Statements
This annual report on Form 10-K includes forward-looking statements within
the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the
Securities Exchange Act of 1934. 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; disruption or interruption of the Company's production
facilities due to accidents or political events; 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, 2000 and 1999, and the present values of estimated future net
revenues attributable to these reserves as of those dates were as follows:
As of December 31,
-------------------
2000 1999
--------- ---------
(Dollars in
thousands, except
per unit data)
Net Proved Reserves:
Crude oil (MBbl).................................. 329.5 488.4
Natural gas (MMcf)................................ 10,511.7 14,957.2
Natural gas equivalent (MMcfe).................... 12,488.7 17,887.6
Net Proved Developed Reserves:
Crude oil (MBbl).................................. 301.8 460.1
Natural gas (MMcf)................................ 10,511.7 14,944.5
Natural gas equivalent (MMcfe).................... 12,322.5 17,705.1
Estimated future net revenues before income
taxes(1)........................................... $ 91,174 $ 34,917
Present value of estimated future net revenues
before income taxes(2)............................. $ 74,909 $ 28,720
Standardized measure of discounted estimated future
net cash flows(3).................................. $ 66,674 $ 28,720
- --------
(1) The average prices for crude oil were $23.36 per Bbl at December 31, 2000
and $22.29 per Bbl at December 31, 1999. The average prices for natural gas
were $9.55 per Mcf at December 31, 2000 and $2.12 per Mcf at December 31,
1999.
(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 2000
balance was computed using year end prices that were significantly higher
than historical levels. Using a price of $5.02 per Mcfe which represents
the February 2001 period end prices, the standardized measure amount would
be $57.2 million. The balance in 1999 has not been reduced by income taxes
due to the tax basis of the properties and a net operating loss
carryforward.
13
The reserve estimates reflected above, as of December 31, 2000 and 1999,
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 Securities and Exchange
Commission ("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 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,
------------------------------
2000 1999 1998
--------- --------- ----------
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ----
Exploratory Wells:
Oil...................................... 3 0.6 1 0.4 1 0.2
Natural gas.............................. 1 0.2 1 1.0 8 2.6
Non-productive........................... 3 0.9 4 2.2 18 8.6
--- --- --- --- --- ----
Total.................................. 7 1.7 6 3.6 27 11.4
=== === === === === ====
Development Wells(1):
Oil...................................... 1 0.1 1 0.9 4 0.8
Natural gas.............................. -- -- 1 0.6 -- --
Non-productive........................... -- -- 1 0.4 2 1.8
--- --- --- --- --- ----
Total.................................. 1 0.1 3 1.9 6 2.6
=== === === === === ====
- --------
(1) At December 31, 2000, the Company was in the process of drilling and/or
completing 3 gross wells (1.3 net to the Company) that are not reflected
in the table.
14
Productive Wells and Acreage
Productive Wells
The following table sets forth the Company's ownership interest as of
December 31, 2000 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.................. 4 0.3 11 7.5 15 7.8
Michigan Basin/Other.................... 1 0.1 1 1.0 2 1.1
--- --- ----- ----- --- ---
Total................................. 5 0.4 12 8.5 17 8.9
=== === ===== ===== === ===
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, 2000:
Developed Undeveloped Total
----------- --------------- ---------------
Region Gross Net Gross Net Gross Net
------ ----- ----- ------- ------- ------- -------
Mississippi Salt Basin........ 7,443 4,565 44,376 21,780 51,819 26,346
Montana(1).................... -- -- 260,492 185,492 260,492 185,492
Onshore Gulf Coast
Texas....................... -- -- 5,240 802 5,240 802
Louisiana................... -- -- 741 494 741 494
Michigan Basin/Other.......... 320 180 6,667 5,191 6,997 5,371
----- ----- ------- ------- ------- -------
Total..................... 7,763 4,745 317,526 213,759 325,289 218,504
===== ===== ======= ======= ======= =======
- --------
(1) The Blackfeet Project in Montana is currently involved in litigation. The
Company does not represent nor can it be assumed that the litigation will
be favorably resolved. See "Item 3--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. Subsequent to December 31, 2000, the
Company acquired the right to explore on 35,824 gross (23,286 net to the
Company) undeveloped acres in the Illinois Basin. To this end, the Company's
projected drilling schedule takes into consideration not only the
attractiveness of individual prospects, but the lease
15
expirations as well. The following table sets forth the minimum remaining terms
of leases for the total gross and net acreage at December 31, 2000:
Acres Expiring
---------------
Gross Net
------- -------
Twelve Months Ending:
December 31, 2001....................................... 14,470 7,358
December 31, 2002....................................... 20,512 8,610
December 31, 2003....................................... 3,998 2,175
Thereafter............................................ 286,309 200,361
------- -------
Total................................................. 325,289 218,504
======= =======
Facilities
The Company currently leases approximately 10,500 square feet of office
space for its principal offices in Traverse City, Michigan. In November 2000,
the Company sub-leased 1,500 square feet of this office space for an initial
one-year term. The Company also leases approximately 5,200 square feet of
office space in Houston, Texas, approximately 3,500 square feet of office space
in Jackson, Mississippi and approximately 2,000 square feet of office space and
3,600 square feet of warehouse space in Columbia, Mississippi.
Item 3. Legal Proceedings.
On May 1, 2000, the Company filed a lawsuit in the United States 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 includes 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 United
States District Court for the District of Montana, Great Falls Division and is
not subject to protective order. Discovery is currently underway.
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
dated February 19, 1999, and pursuant to the K2 Agreement dated May 30, 1997.
The disputes for which the Company demands arbitration include, but are not
limited to, the unreasonable withholding of a consent to a drilling extension
as provided for in the Miller Agreement, as well as a determination by the
Tribe dated March 16, 2000, that certain wells which the Company proposed to
drill "would not satisfy the mandatory drilling obligations" under the K2
Agreement. The Company contends the K2 Agreement gives the Company, as lessee,
and not the Tribe, the exclusive right to drill sites and determine well
depths. The Company has had several meetings with the new Tribal Council
elected in July 2000, and is working toward resolution of these matters.
The Company has been named as 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, is claiming damages related to their destroyed drilling
rig and related costs amounting to approximately $1.2 million, plus interest,
attorneys' fees and costs. In January 2001, the District Court judge ruled
against the Company on two of the three claims filed in this case with damages
left undetermined. This ruling is being appealed to the U.S. Fifth Circuit
Court of Appeals. In the event the Company does not prevail in the appeal, any
resulting damages owed would be covered by insurance.
16
The Company has been 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.
The Company has been named in a lawsuit brought by Charles Strictland,
employee of BJ Services, Inc., on September 30, 1999. The suit claimed damages
of $1.0 million for personal injuries allegedly suffered at a well site
operated by the Company. The judge ruled in favor of the Company at the trial
that was held March 8, 2001.
The Company had been named among several co-defendants in a lawsuit brought
by Eric Parkinson, husband and personal representative of the Estate of Kelly
Anne Parkinson (deceased). The amended complaint was filed December 13, 1999,
in the County of Hillsdale, Michigan, claiming an unspecified amount plus
interest and attorney fees for suffering the loss of the deceased care,
comfort, society and support. Kelly Anne Parkinson was killed in an automobile
accident on February 2, 1999, while traveling on a county road located next to
land wherein the Company is lessee of underground mineral rights. The plaintiff
alleged that the accident was the result of mud dragged on the road from the
leased property and alleged that the Company was negligent in its duty to
conduct its operations at the site with reasonable care. This case was settled
and all claims dismissed in February 2001. All defense costs and the settlement
amount will be covered by the Company's insurance.
The Company believes it has meritorious claims or defenses to the items
discussed above and intends to vigorously pursue these lawsuits. 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. The Company
currently believes any costs resulting from each of the lawsuits mentioned
above would be covered by the Company's insurance.
Item 4. Submission of Matters to a Vote of Security Holders.
At the December 7, 2000 Special Meeting of Common Stockholders, the
following proposals were voted upon:
. The issuance to Guardian of 3,703,704 shares of common stock upon the
conversion of a $5.0 million promissory note.
. The issuance to Guardian of up to 13,062,500 shares of the Company's
Common Stock upon the exercise by Guardian of warrants to purchase
1,562,500 shares of common stock for $1.35 per share, 2,500,000 shares
of common stock for $2.50 per share, and 9,000,000 shares of common
stock for $3.00 per share.
This proposal was approved by the Company's Stockholders.
For Against Abstain
--- ------- -------
7,877,663 127,600 35,485
. A transaction with Eagle, whereby Eagle would:
(a) pay the Company $500,000 in cash,
(b) assign to the Company a 50% interest in certain of the non-
producing oil and gas leasehold interests which the Company had
previously conveyed to Eagle, and
(c) grant the Company an exclusive right of first offer on the sale of
Eagle's producing and non-producing asset base in the Mississippi
Salt Basin,
in exchange for which the Company would:
(i) issue to Eagle 1,851,811 shares of Common Stock, and
17
(ii) issue to Eagle warrants to purchase 781,250 shares of Common
Stock at $1.35 and 1,250,000 shares of common stock at $2.50
per share, respectively, as well as the subsequent right to
exercise such warrants.
This proposal was approved by the Company's Stockholders.
For Against Abstain
--- ------- -------
7,153,774 850,539 36,335
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
Matters.
The Company's Common Stock is traded on The Nasdaq National Market under
the symbol "MEXP."
As of March 15, 2001, the Company estimates that there were approximately
2,200 beneficial holders of its Common Stock. The Company consummated the
Offering on February 9, 1998. Before that time, there was no public market for
the Company's Common Stock.
The following table sets forth the high and low bid information for the
Company's Common Stock for the periods indicated, all as reported by The
Nasdaq National Market:
Year Ended December 31,
---------------------------------
2000 1999
----------------- ---------------
High Low High Low
-------- -------- ------- -------
First Quarter........................... $2 15/16 $ 15/16 $5 $2
Second Quarter.......................... 1 5/8 3/4 2 5/16 9/16
Third Quarter........................... 2 1 1/8 3 9/32 1 3/4
Fourth Quarter.......................... 2 1/8 15/16 2 3/16 3/4
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.
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 1,562,500, 2,500,000 and 9,000,000 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.
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 1,851,851 shares of common stock. In addition, Eagle was issued
warrants exercisable for a total of 2,031,250 shares of common stock.
Consummation of this transaction with Eagle also was approved by the
stockholders at a meeting on December 7, 2000.
On July 11, 2000, the Company also entered into a Subscription Agreement
with ECCO Investments, LLC ("ECCO"), pursuant to which ECCO purchased 370,370
shares of the Company's common stock for an aggregate purchase price of $0.5
million or $1.35 per share.
The securities issued in each of these transactions were issued in private
placements exempt from registration under Section 4(2) of the Securities Act
of 1933 and in conformity with the requirements of Rule 506 under Regulation
D. Each of the purchasers in each of these transactions was an accredited
investor. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations" for a discussion of the use of the proceeds of these
transactions.
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, 2000 is derived from the consolidated financial statements
which have been audited by Arthur Andersen LLP, independent public accountants.
Earnings per share has been omitted for all periods prior to 1998 since such
information is not meaningful and the historically combined Company (prior to
the Combination Transaction) was not a separate legal entity with a single
capital structure. 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,
--------------------------------------------
2000 1999 1998 1997 1996
------- ------- -------- ------- -------
(In thousands, except per share data)
Statement of Operations Data:
Revenues:
Natural gas.................. $20,745 $17,266 $ 18,336 $ 5,819 $ 5,614
Crude oil and condensate..... 5,300 3,465 2,646 964 1,101
Other operating revenues..... 522 200 169 395 263
------- ------- -------- ------- -------
Total operating revenues... 26,567 20,931 21,151 7,178 6,978
Operating expenses:
Lease operating expenses and
production taxes............ 3,030 1,704 3,363 1,478 1,123
Depreciation, depletion and
amortization................ 17,457 16,066 15,933 2,520 2,629
General and administrative... 2,097 2,776 2,815 1,952 1,459
Cost ceiling writedown....... -- -- 35,085 -- --
------- ------- -------- ------- -------
Total operating expenses... 22,584 20,546 57,196 5,950 5,211
------- ------- -------- ------- -------
Operating income (loss)........ 3,983 385 (36,045) 1,228 1,767
Interest expense(1)............ (4,322) (3,519) (1,635) (1,200) (1,139)
------- ------- -------- ------- -------
Income (loss) before income
taxes and extraordinary item.. (339) (3,134) (37,680) 28 628
Income tax provision
(credit)(2)................... 472 (1,152) 4,120 -- --
------- ------- -------- ------- -------
Net income (loss) before
extraordinary item............ $ (811) $(1,982) $(41,800) $ 28 $ 628
Extraordinary item--loss from
early extinguishment of debt,
less applicable income taxes.. 166 -- -- -- --
------- ------- -------- ------- -------
Net income (loss).............. $ (977) $(1,982) $(41,800) $ 28 $ 628
Basic and diluted earnings
(loss) per share.............. $ (0.07) $ (0.16) $ (3.75)
Weighted average shares
outstanding................... 13,361 12,632 11,153
As of December 31,
--------------------------------------------
2000 1999 1998 1997 1996
------- ------- -------- ------- -------
(In thousands)
Balance Sheet Data (at end of
period):
Working capital................ $(1,383) $(4,200) $(15,925) $(5,985) $(2,682)
Oil and gas properties, net.... 52,033 58,837 80,014 23,968 20,732
Total assets................... 59,878 68,611 85,968 30,428 24,050
Long-term debt, excluding
current portion............... 11,196 25,610 31,837 481 8,723
Equity......................... 33,926 23,995 24,749 16,113 7,769
- --------
(1) A $1.7 million one-time non-cash charge related to the Guardian Transaction
(more fully described in Note 8 to the Consolidated Financial Statements)
was recorded in interest expense in 2000.
(2) Upon consummation of the Combination Transaction in 1998, 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."
19
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. The Company was organized in
connection with the Combination Transaction. The Combined Assets consist of
MOC, interests in oil and natural gas properties from the Affiliated Entities
and interests in such properties owned by certain business partners and
investors. The Combination Transaction closed on February 9, 1998 in connection
with the closing of the Offering. The Offering, including the sale of an
additional 62,500 shares of Common Stock by the Company on March 9, 1998
pursuant to the exercise of the underwriters' over-allotment option, resulted
in net proceeds to the Company of approximately $40.4 million after expenses.
For further discussion of the Offering and the Combination Transaction, see
Note 1 to the Consolidated Financial Statements.
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.
On December 7, 2000, the Common Stockholders of the Company approved certain
transactions with Guardian and Eagle that, among other things, required the
Company to record non-cash interest expense in the aggregate of approximately
$1.7 million during the year ended December 31, 2000. These transactions are
more fully discussed in Note 8 to the Consolidated Financial Statements.
20
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,
--------------------------
2000 1999 1998
------- ------- --------
Production volumes:
Crude oil and condensate (MBbls).......... 205.3 255.9 247.6
Natural gas (MMcf)........................ 5,762.0 7,593.8 8,953.3
Natural gas equivalent (MMcfe)............ 6,993.8 9,129.2 10,438.7
Revenues:
Natural gas............................... $20,745 $17,266 $ 18,336
Crude oil and condensate.................. 5,300 3,465 2,646
Operating expenses:
Lease operating expenses and production
taxes.................................... $ 3,030 $ 1,704 $ 3,363
Depletion, depreciation and amortization.. 17,457 16,066 15,933
General and administrative................ 2,097 2,776 2,815
Interest expense............................ $ 4,322 $ 3,519 $ 1,635
Net loss.................................... $ (977) $(1,982) $(41,800)
Average sales prices:
Crude oil and condensate ($ per Bbl)...... $ 25.82 $ 13.54 $ 10.69
Natural gas ($ per Mcf)................... 3.60 2.27 2.05
Natural gas equivalent ($ per Mcfe)....... 3.72 2.27 2.01
Average costs ($ per Mcfe):
Lease operating expenses and production
taxes.................................... $ 0.43 $ 0.19 $ 0.32
Depletion, depreciation and amortization.. 2.49 1.76 1.53
General and administrative................ 0.30 0.34 0.33
Year Ended December 31, 2000 compared to Year Ended December 31, 1999
Oil and natural gas revenues for the year ended December 31, 2000 increased
26% to $26.0 million from $20.7 million for the year ended December 31, 1999.
Oil and natural gas revenues for the years ended December 31, 2000 and 1999
include approximately $2.0 million and $0.3 million of hedging losses,
respectively (see "Risk Management Activities and Derivative Transactions"
below). Production volumes for natural gas during the year ended December 31,
2000 decreased 24% to 5,762 MMcf from 7,594 MMcf for the year ended December
31, 1999. This decrease is attributable to declining production in the
Mississippi Salt Basin properties. The Company installed compressors on all
Company-operated properties in the Salt Basin and have reperforated and
conducted other stimulation techniques to boost and/or stabilize production
rates. The Company will continue to evaluate wells for various workover
projects which will be funded by the Company's operating cash flows. The effect
on natural gas production of the sale of the Company's Antrim Shale properties
in Michigan and certain non-strategic producing properties in Louisiana and
Texas in early 1999 have been offset by increased production from non-Antrim
Shale production in the Michigan Basin during 2000. Average natural gas prices
increased 59% to $3.60 per Mcf for the year ended December 31, 2000 from $2.27
per Mcf for the year ended December 31, 1999 due to improved natural gas
commodity prices during 2000. Oil production volumes decreased 20% to 205 MBbls
for the year ended December 31, 2000 compared to 256 MBbls the same period of
1999. Decreased production in the Mississippi Salt Basin accounted for 18% of
the change with the remaining 2% decline being attributable to the sale of
producing properties in Louisiana and Texas in early 1999 and in June 2000. The
Company believes the installation of compressors in mid-2000 and the ongoing
evaluation of the Company's producing wells for additional stimulation
potential will help to
21
slow production decline rates. Average oil prices increased 91% to $25.82 per
barrel during the year ended December 31, 2000 from $13.54 per barrel for the
year ended December 31, 1999 as oil commodity prices rebounded in 2000.
Lease operating expenses ("LOE") and production taxes for the year ended
December 31, 2000 increased 76% to $3.0 million from $1.7 million for the year
ended December 31, 1999. LOE increased 27% to $1.9 million for 2000 compared to
$1.5 million for 1999. This increase is comprised of a $0.6 million increase in
expenses attributable to Mississippi Salt Basin wells and a $0.2 decrease in
expenses resulting from the sale of producing properties in Michigan, Louisiana
and Texas during 1999 and 2000. Compressor installation and related rental
expenses and the costs of various reperforation and well stimulation projects
account for the increased LOE on the Salt Basin properties.
Production taxes increased 450% to $1.1 million for 2000 compared to $0.2
million for 1999. Substantially all of this increase is attributable to the
Salt Basin properties. Since June 2000, the average crude oil and natural gas
prices exceeded the price ceiling established by the State of Mississippi,
therefore exemption from the 7% production tax established by Mississippi
Statute no longer applied. Also, since the Mississippi production tax is
calculated by taking 7% of the gross value of the crude oil and natural gas,
the upward trend in the amount of production tax expense followed the
substantial increase in commodity prices that occurred during 2000.
Depreciation, depletion and amortization ("DD&A") expense for the year ended
December 31, 2000 increased 9% to $17.5 million from $16.1 million for the year
ended December 31, 1999.
General and administrative expense for the year ended December 31, 2000
decreased 25% to $2.1 million from $2.8 million for the same period in 1999.
This decrease is attributable to the cost reduction plan implemented in May
1999. The primary components of the general and administrative expense
reduction include; (1) a $0.7 million decrease in salaries, wages, and related
employee benefits; (2) a $0.2 million decrease in legal and professional fees;
and (3) a $0.1 million decrease in travel expenses. These decreases were offset
by a $0.3 million reduction in the amount of capitalized general and
administrative expenses in 2000.
Using unescalated period-end prices at December 31, 2000 of $8.65 per Mcfe,
the Company had no impairment of oil and gas properties. Using unescalated
period-end prices at December 31, 1999, of $2.38 per Mcfe, the Company would
have recognized a non-cash impairment of oil and gas properties in the amount
of approximately $1.2 million pre-tax. However, on the basis of the improvement
in pricing experienced subsequent to period-end of $2.80 per Mcfe in March
2000, the Company determined that a writedown was not required.
Interest expense for the year ended December 31, 2000 increased 22% to $4.3
million from $3.5 million for the year ended December 31, 1999. This increase
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
"Liquidity and Capital Resources" below and in Note 8 to the Consolidated
Financial Statements. Had the $1.7 million interest expense entry not been
required, interest expense would have actually decreased by 25% to $2.6 million
from $3.5 million. This decrease is attributable to a 58% reduction in total
debt to $12.2 million at December 31, 2000 from $29.1 million at December 31,
1999 and the lower interest rate provided for under the Credit Facility
agreement with the Company's new lender, Bank One, Texas, N.A. ("Bank One").
On July 19, 2000, the Company entered into a senior credit facility with
Bank One which replaced the 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.
Net loss for the year ended December 31, 2000 decreased to $1.0 million from
$2.0 million for the year ended December 31, 1999, as a result of the factors
described above.
22
Year Ended December 31, 1999 compared to Year Ended December 31, 1998
Oil and natural gas revenues for the year ended December 31, 1999 decreased
1% to $20.7 million from $21.0 million for the year ended December 31, 1998.
Oil and natural gas revenues for the years ended December 31, 1999 and 1998
include approximately ($0.3) million and $0.8 million of hedging (losses)
gains, respectively (see "Risk Management Activities and Derivative
Transactions" below). Production volumes for natural gas during the year ended
December 31, 1999 decreased 15% to 7,594 MMcf from 8,953 MMcf for the year
ended December 31, 1998. This decrease is attributable to the sales of the
Company's Antrim Shale gas properties in Michigan and certain non-strategic
properties in Texas and Louisiana that occurred earlier in 1999. The combined
proceeds from these property sales amounted to $7.6 million of which $7.1
million was applied to the Company's outstanding debt balance.
The 23% decrease in natural gas production volumes attributable to these
sold properties was partially offset by a 2% increase in natural gas produced
from the Mississippi Salt Basin properties for the year ended December 31, 1999
compared to the same period of 1998. Average natural gas prices increased 11%
to $2.27 per Mcf for the year ended December 31, 1999 from $2.05 per Mcf for
the year ended December 31, 1998 due to improved natural gas commodity prices
during the third and fourth quarters of 1999. Despite an 11% increase in oil
production volumes for the Mississippi Salt Basin properties, total oil
production for the year ended December 31, 1999 increased only 3% to 256 MBbls
from 248 MBbls for the year ended December 31, 1998. Reduced oil production
attributable to sold properties in Texas and Louisiana offset the production
increases from the Mississippi Salt Basin properties. Average oil prices
increased 27% to $13.54 per barrel during the year ended December 31, 1999 from
$10.69 per barrel for the year ended December 31, 1998 as oil commodity prices
rebounded in the third and fourth quarters of 1999.
Lease operating expenses and production taxes for the year ended December
31, 1999 decreased 49% to $1.7 million from $3.4 million for the year ended
December 31, 1998. This decrease was primarily comprised of an approximate $1.0
million reduction in LOE attributable to properties in Texas, Louisiana and
Michigan that were sold in 1999. Savings of approximately $0.5 million in 1999
compared to 1998 resulted from fewer well workovers in 1999 compared to 1998
and more efficient use of the Company's field operations personnel and much
less dependence on contract pumping services. There was also an approximate
$0.3 million decrease in production taxes associated with the sale of producing
properties in 1999, partially offset by a $0.1 million increase in taxes
attributable to new wells in Mississippi and Michigan that commenced initial
production during 1999.
DD&A expense for the year ended December 31, 1999 increased 1% to $16.1
million from $16.0 million for the year ended December 31, 1998.
General and administrative expense for the year ended December 31, 1999 of
$2.8 million was unchanged from the same period in 1998. Although general and
administrative expense actually decreased by $0.4 million for 1999 compared to
1998 due to a cost reduction plan implemented in May 1999, fees received as
reimbursement of general and administrative expense costs also decreased by
$0.4 million, leaving reported general and administrative expense for the year
ended December 31, 1999 unchanged from the level reported for the same period
of the prior year.
Using unescalated period-end prices at December 31, 1999, of $2.38 per Mcfe,
the Company would have recognized a non-cash impairment of oil and gas
properties in the amount of approximately $1.2 million pre-tax. However, on the
basis of the improvement in pricing experienced subsequent to period-end, the
Company determined that a writedown was not required. At December 31, 1998, the
Company recorded a non-cash cost ceiling writedown of $35.1 million. The
writedown was the combined result of a large downward revision in oil and gas
reserve quantities and depressed commodity prices. The large 8.2 Bcfe downward
revision of the Company's proved oil and gas reserves at December 31, 1998 was
comprised of a 4.3 Bcfe reduction in proved undeveloped reserves as a result of
unsuccessful drilling activity and a 3.9 Bcfe reduction in proved producing
reserves. Proved producing reserves decreased as a result of unanticipated
pressure and production declines and by a reduction in the economic lives of
producing reserves caused by the lower commodity prices being realized at
December 31, 1998. Disappointing 2-D seismic-supported drilling results during
1998 and drilling
23
cost overruns on two non-operated properties also contributed to the cost
ceiling writedown. The Company based its ceiling test determination on a price
of $1.78 per Mcfe, which represented the March 1999 closing commodity prices.
Interest expense for the year ended December 31, 1999 increased 115% to $3.5
million from $1.6 million for the year ended December 31, 1998. This
substantial interest expense increase is attributable to a higher average debt
level in 1999 compared to 1998, due to substantial 3-D seismic acquisition
costs, and exploration and development activity in the third and fourth
quarters of 1998 that increased the outstanding debt balance. Also contributing
to higher interest expense in 1999 was the interest expense associated with the
Veritas Note Payable, more fully discussed in Note 7 to the Consolidated
Financial Statements, and the prime plus 3.5% interest rate that became
effective with the Second Amendment to the Credit Facility Agreement dated
April 14, 1999, compared to the previous libor based rate effective during
1998.
Net loss for the year ended December 31, 1999 decreased to $2.0 million from
$41.8 million for the year ended December 31, 1998, as a result of the factors
described above.
Liquidity and Capital Resources
Liquidity
The Company's primary source of liquidity is cash generated from operations.
Net cash provided by operating activities was $16.1 million, $12.9 million, and
$18.8 million in 2000, 1999 and 1998, respectively. The increase in cash
provided in 2000 compared to 1999 was primarily attributable to improved
operating results because of the significantly increased commodity prices in
2000 and to drilling advances received from joint interest partners relating to
the drilling of wells. The decrease in cash provided in 1999 compared to 1998
was principally due to the reduced payables in 1999 because of an effort by the
Company to more effectively manage our cash flow requirements, including
processing of payables on a more timely basis.
Net cash provided by (used in) investing activities was $(7.6) million, $4.0
million, and $(94.9) million in 2000, 1999, and 1998, respectively. The
increase in cash used in 2000 compared to 1999 was due to a $13.3 million
decrease in proceeds from the sale of oil and gas properties offset by a
decrease in exploration and development expenditures of $1.7 million. The
decrease in cash used in 1999 compared to 1998 was principally due to an
increase in property sales of $11.2 million in 1999, a decrease in exploration
and development expenditures of $36.7 million in 1999 and a decrease in the
acquisition of properties of $51.0 million in 1999.
Net cash provided by (used in) financing activities was $(9.9) million,
$(13.2) million, and $75.9 million in 2000, 1999, and 1998, respectively. The
decrease in cash used in 2000 compared to 1999 was primarily a result of $7.0
million in proceeds from the issuance of common stock offset by a reduction in
net borrowings on long-term debt. The decrease in cash provided in 1999
compared to 1998 was primarily a result of the proceeds from the Company's
initial public offering in 1998 and a reduction in net borrowings in 1999.
Capital Resources
Historically, the Company's primary sources of capital have been funds
generated by operations, and borrowings under bank credit facilities.
Concurrently with the Offering, a credit facility was entered into with Bank
of Montreal, Houston Agency. The credit facility, as amended, required
principal reductions and included certain negative covenants that imposed
limitations on the Company and its subsidiary with respect to, among other
things, distributions with respect to our capital stock, limitations on
financial ratios, the creation or incurrence of liens, restrictions on proceeds
from sales of oil and gas properties, the incurrence of additional
indebtedness, making loans and investments and mergers and consolidations. The
Company's obligations under the credit facility were secured by a lien on all
of its real and personal property. Commencing April 1999, the interest rate
under this facility was increased to Bank of Montreal's prime plus 3.5%.
24
On July 19, 2000, the Company entered into a new senior credit facility with
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 under the new
credit facility is 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 new credit
facility required the Company to make monthly principal payments of $500,000
from August 1, 2000 until the borrowing base re-determination that occurred on
January 1, 2001. The new borrowing base determined by Bank One as of December
31, 2000 is $9.0 million, less the amount due Amerada Hess Corporation ("AHC")
in 2001. The next scheduled borrowing base re-determination with Bank One is in
July 2001.
The Company made principal payments of approximately $14.4 million and $15.0
million, for the years ended December 31, 2000, and 1999, respectively, under
the credit facility with Bank of Montreal and Bank One. At December 31, 2000,
the outstanding debt balance under the Company's credit facility with Bank One
was $7.5 million.
The Bank One credit facility includes certain negative covenants that impose
restrictions on us with respect to, among other things, incurrence of
additional indebtedness, limitations on financial ratios, making investments
and mergers and consolidation.
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 $0.01 per share. On April 14, 1999, warrants
exercisable for 322,752 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 322,752 and 454,994 shares,
respectively, of Common Stock were issued to Veritas. The Company ratably
recognizes the prepaid interest into expense over the period to which it
relates. For the years ended December 31, 2000 and 1999, the Company recognized
non-cash interest expense of approximately $752,000 and $600,000, respectively,
related to the Veritas Note Payable. The Warrant Agreement was also amended on
July 19, 2000.
Under the terms of the amended note and warrant agreements, the maturity of
the Veritas Note was extended from April 15, 2001 to July 21, 2003 and the
expiration date for all warrants issued was extended until June 21, 2004. The
annual interest rate has been reduced from 18% to 9 %, provided the entire note
balance is paid in full by December 31, 2001. If all principal and interest
under the Veritas Note is not paid by December 31, 2001, then the note bears
interest at 13 % until paid in full. As of December 31, 2000, the Company has
only recognized interest expense on the outstanding Veritas Note at 9 3/4%
since it is believed that the principal balance will be paid in full by
December 31, 2001. Interest accrues at the reduced rate from and after October
15, 2000 and is payable commencing April 15, 2001 and continuing on each
October 15 and April 15 until principal is paid in full. Interest was required
to be paid in warrants under the terms of the Warrant Agreement until the
Company is in compliance with the net borrowing base formula as defined in the
Bank One credit facility agreement, at which time interest will only be paid in
cash.
25
Under the amended Veritas Note, a principal payment of $500,000 was made on
July 19, 2000, the effective date of the amendment, and another $500,000
payment was made in December 2000. The balance due Veritas was $3.7 million at
December 31, 2000 with the entire balance classified as long-term in the
accompanying financial statements.
Any additional proceeds derived from the exercise of warrants issued or from
other debt or equity transactions must be used to pay interest and principal on
the amended Veritas Note until paid in full. Effective November 1, 2000,
Veritas exercised 500,000 warrants to receive 496,923 shares (net of exercise
price) of Company common stock.
In connection with the closing of the AHC property acquisition on February
9, 1998, the Company issued a non-interest bearing note payable to AHC (the
"AHC Note"). The Company had obtained a six-month extension of the $1.0 million
payment due AHC from February 2000 to August 2000. This payment was made on
August 3, 2000. Also, the $1.5 million payment due February 2001 has been
divided into three quarterly installments of $500,000 each, payable commencing
February 2001. A substantial portion of the first quarter 2001 payment was made
in December 2000.
Refer to Note 8 of the Consolidated Financial Statements for further
information regarding capital resources, specifically the Guardian and Eagle
Transactions in 2000.
At December 31, 2000, the Company had a working capital deficit of $0.3
million (excluding the current portion of long-term debt). Management plans to
meet these working capital requirements from operational cash flows.
The Company anticipates 2001 capital expenditures will be approximately
$10.0 million. Capital expenditures will be used to fund drilling and
development activities, the acquisition of additional seismic data and
processing and leasehold acquisitions and extensions in the Company's project
areas. The actual amounts of capital expenditures and number of wells drilled
may differ significantly from such estimates. Actual capital expenditures for
the year ended December 31, 2000 were approximately $8.6 million. The Company
also acquired undeveloped oil and gas properties valued for financial reporting
purposes at $2.6 million from Eagle in exchange for shares of the Company's
common stock and warrants, as more fully described in Note 8 to the
Consolidated Financial Statements. The Company intends to fund its 2001
budgeted capital expenditures through operational cash flow.
The Company's revenues, profitability, future growth and ability to borrow
funds or obtain additional capital, and the carrying value of its properties,
substantially are dependent on prevailing prices of oil and natural gas. The
Company cannot predict future oil and natural gas price movements with
certainty. A return to the significantly lower oil and gas prices experienced
in 1998 and early 1999, as compared to historical averages, would likely have
an adverse effect on the Company's financial condition, liquidity, ability to
finance capital expenditures and results of operations. Lower oil and natural
gas prices also may reduce the amount of reserves that can be produced
economically by the Company.
The Company has experienced and expects to continue to experience
substantial working capital requirements primarily due to the Company's active
exploration and development program. While the Company believes that cash flow
from operations and improved commodity prices should allow the Company to
implement its present business strategy through 2001, additional debt or equity
financing may be required during the remainder of 2001 and in the future to
fund the Company's growth, development and exploration program, and to satisfy
its existing obligations. The failure to obtain and exploit such capital
resources could have a material adverse effect on the Company, including
further curtailment of its exploration and other activities.
26
Risk Management Activities and Derivative Transactions
The Company uses a variety of derivative instruments ("derivatives") to
manage exposure to fluctuations in commodity prices and interest rates. To
qualify for hedge accounting, derivatives must meet the following criteria: (i)
the item to be hedged exposes the Company to price or interest rate risk; and
(ii) the derivative reduces that exposure and is designated as a hedge.
Commodity Price Hedges
The Company periodically enters into certain derivatives (e.g., NYMEX
futures contracts) 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, 2000, 1999, and 1998, the Company hedged 54%, 45%, and 36% of its
oil and gas production, respectively, and as of December 31, 2000, the Company
had 2.0 Bcfe of open oil and natural gas contracts for the months of January
2001 through December 2001. Refer to Note 10 of the Consolidated Financial
Statements for further discussion of price risk management and derivative
activities.
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 has been adopted by the Company as of January 1, 2001 and the
Company has 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. Management estimates
that the effect of adopting SFAS No. 133 as of January 1, 2001 would increase
liabilities by approximately $5.7 million with a corresponding decrease in
other comprehensive income in the Consolidated Statement of Equity since the
contracts outstanding on the date meet the specific hedge accounting criteria.
Approximately $3.9 million of the $5.7 million amount represents the liability
estimated for the contracts settling in the first quarter of 2001. The amount
of hedge loss actually realized on these contracts settled in the first quarter
of 2001 was $2.2 million. Management estimates that the liability and
corresponding balance of other comprehensive income that would be reported in
the Consolidated Statement of Equity is approximately $1.4 million as of March
10, 2001.
27
Effects of Inflation and Changes in Price
Crude oil and natural gas commodity prices have been volatile and
unpredictable during 1998, 1999 and 2000, with crude oil prices falling below
$10 per Bbl and rising close to $34 per Bbl, and natural gas prices dropping
below $1 per Mcf and then climbing up above $10 per Mcf during this two-year
time period. These wide fluctuations have had a significant impact on the
Company's results of operations, cash flow and liquidity. 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.
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 and interest rates. 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) 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, 2000. 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 (as discussed in the "New
Accounting Standard" 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.
28
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" and "Section 16(a)
Beneficial Ownership Reporting Compliance" in the definitive Proxy Statement
for the Company's annual meeting of stockholders to be held on May 25, 2001 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 May 25, 2001 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 May 25, 2001 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" and "Security Ownership of Management"
in the definitive Proxy Statement for the Company's annual meeting of
stockholders to be held on May 25, 2001 is here incorporated by reference.
PART IV
Item 14. Exhibits, Financial Statements, Schedules, and Reports on Form 8-K.
Item 14(a)(1). Financial Statements. See "Index to Financial Statements" set
forth on page F-1.
Item 14(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 14(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.
29
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 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 3.2.
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.
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) 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.
10.1(c) 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.
10.2 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.*
10.3 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.
10.4 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.
30
10.5 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.
10.6 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.
10.7 Consulting Agreement dated June 1, 1996 between Miller Oil Corporation
and Frank M. Burke, Jr., with amendment. 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 Credit Agreement between Miller Oil Corporation and Bank of Montreal
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, 1997, and
here incorporated by reference.
10.11 Guaranty Agreement by Miller Exploration Company in favor of Bank of
Montreal 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,
1997, and here incorporated by reference.
10.12 $75,000,000 Promissory Note of Miller Oil Corporation to Bank of
Montreal 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,
1997, and here incorporated by reference.
10.13 Mortgage (Michigan) between Miller Oil Corporation and James Whitmore,
as trustee for the benefit of Bank of Montreal, 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, 1997, and here incorporated by
reference.
10.14 Mortgage, Deed of Trust, Assignment of Production, Security Agreement
and Financing Statement (Mississippi) between Miller Oil Corporation and
James Whitmore, as trustee for the benefit of
Bank of Montreal, 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, 1997, and here incorporated by reference.
10.15 Mortgage, Deed of Trust, Assignment of Production, Security Agreement
and Financing Statement (Texas) between Miller Oil Corporation and James
Whitmore, as trustee for the benefit of Bank of Montreal, 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, 1997, and here incorporated
by reference.
10.16 First Amendment to Credit Agreement among Miller Oil Corporation and
Bank of Montreal dated June 24, 1998. 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.
10.17 Second Amendment to Credit Agreement between Miller Oil Corporation and
Bank of Montreal 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.
10.18 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.
31
10.19 $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.
10.20 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.
10.21 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.
10.22 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.
10.23 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.
10.24 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.
10.25 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.
10.26 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.
10.27 Form of Equity Compensation Plan for Non-Employee Directors Agreement
dated December 7, 1998. Previously filed as an exhibit to the Company's
Annual Report on Form 10-K for the year ended December 31, 1999, and
here incorporated by reference.
10.28 Third Amendment to Credit Agreement among Miller Oil Corporation and
Bank of Montreal dated October 29, 1999. Previously filed as an exhibit
to the Company's Annual Report on Form 10-K for the year ended December
31, 1999, and here incorporated by reference.
10.29 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, 1999, and here incorporated by
reference.
10.30 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, 1999, and here incorporated by
reference.
10.31 Form of Stock Option Agreement granted to Lew P. Murray dated January 1,
2000.* Previously filed as an exhibit to the Company's Annual Report on
Form 10-K for the year ended December 31, 1999, and here incorporated by
reference.
10.32 Fourth Amendment to Credit Agreement among Miller Oil Corporation and
Bank of Montreal dated March 20, 2000. Previously filed as an exhibit to
the Company's Annual Report on Form 10-K for the year ended December 31,
1999, and here incorporated by reference.
10.33 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.
32
10.34 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.
10.35 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.
10.36 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.
10.37 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.
10.38 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.
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 S.A. Holditch & Associates.
23.2 Consent of Miller and Lents, Ltd.
23.3 Consent of Arthur Andersen LLP.
24.1 Limited Power of Attorney.
- --------
* Management contract or compensatory plan or arrangement.
Item 14(b). The Company filed no reports on Form 8-K during the last quarter
of 2000.
33
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
/s/ Kelly E. Miller
By __________________________________
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.
Signature Title Date
--------- ----- ----
/s/ *C. E. Miller Chairman of the Board March 23, 2001
_________________________________
C. E. Miller
/s/ Kelly E. Miller Director (Principal Executive
Officer) March 23, 2001
_________________________________
Kelly E. Miller
/s/ Deanna L. Cannon (Principal Financial and
Accounting March 23, 2001
_________________________________
Deanna L. Cannon Officer)
/s/ *Robert M. Boeve Director March 23, 2001
_________________________________
Robert M. Boeve
/s/ *Paul A. Halpern Director March 23, 2001
_________________________________
Paul A. Halpern
/s/ *William Casey McManemin Director March 23, 2001
_________________________________
William Casey McManemin
/s/ *Kenneth J. Foote Director March 23, 2001
_________________________________
Kenneth J. Foote
/s/ *Richard J. Burgess Director March 23, 2001
_________________________________
Richard J. Burgess
/s/ Deanna L. Cannon
*By _________________________
Deanna L. Cannon
Attorney-in-Fact
34
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, 2000 and 1999............ F-3
Consolidated Statements of Operations for the Years Ended December 31,
2000,
1999 and 1998.......................................................... F-4
Consolidated Statements of Equity for the Years Ended December 31, 2000,
1999 and 1998.......................................................... F-5
Consolidated Statements of Cash Flows for the Years Ended December 31,
2000,
1999 and 1998.......................................................... F-6
Notes to Consolidated Financial Statements.............................. F-7
Supplemental Quarterly Financial Data (unaudited)....................... F-27
F-1
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 subsidiaries as of December
31, 2000 and 1999, and the related consolidated statements of operations,
equity, and cash flows for each of the three years in the period ended December
31, 2000. 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
subsidiaries as of December 31, 2000 and 1999, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2000, in conformity with accounting principles generally accepted
in the United States.
/s/ Arthur Andersen LLP
Detroit, Michigan
March 9, 2001
F-2
MILLER EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands, except share amounts)
As of
December 31,
------------------
2000 1999
-------- --------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents................................ $ 2,292 $ 3,712
Restricted cash (Note 3)................................. 69 4
Accounts receivable...................................... 4,474 4,580
Inventories, prepaids and advances to operators.......... 316 640
-------- --------
Total current assets................................... 7,151 8,936
-------- --------
OIL AND GAS PROPERTIES--at cost (full cost method):
Proved oil and gas properties............................ 131,872 115,040
Unproved oil and gas properties.......................... 16,109 22,678
Less-Accumulated depreciation, depletion and
amortization............................................ (95,948) (78,881)
-------- --------
Net oil and gas properties............................. 52,033 58,837
-------- --------
OTHER ASSETS (Note 2)...................................... 694 838
-------- --------
Total assets........................................... $ 59,878 $ 68,611
======== ========
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Current portion of long-term debt........................ $ 1,034 $ 3,500
Accounts payable......................................... 3,572 3,472
Accrued expenses and other current liabilities........... 3,928 6,164
-------- --------
Total current liabilities.............................. 8,534 13,136
-------- --------
LONG-TERM DEBT............................................. 11,196 25,610
DEFERRED INCOME TAXES...................................... 6,202 5,816
DEFERRED REVENUE........................................... 20 54
COMMITMENTS AND CONTINGENCIES (Note 11)
EQUITY:
Common stock warrants, 15,694,248 outstanding at December
31, 2000................................................ 1,759 845
Preferred stock, $0.01 par value; 2,000,000 shares
authorized; none outstanding............................ -- --
Common stock, $0.01 par value; 40,000,000 shares
authorized;19,302,254 shares outstanding at December 31,
2000.................................................... 193 127
Additional paid in capital............................... 76,570 66,690
Deferred compensation.................................... -- (48)
Retained deficit......................................... (44,596) (43,619)
-------- --------
Total equity........................................... 33,926 23,995
-------- --------
Total liabilities and equity........................... $ 59,878 $ 68,611
======== ========
The accompanying notes are an integral part of these Consolidated Financial
Statements.
F-3
MILLER EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)
For the Year Ended
December 31,
--------------------------
2000 1999 1998
------- ------- --------
(Note 1)
REVENUES:
Natural gas..................................... $20,745 $17,266 $ 18,336
Crude oil and condensate........................ 5,300 3,465 2,646
Other operating revenues........................ 522 200 169
------- ------- --------
Total operating revenues...................... 26,567 20,931 21,151
------- ------- --------
OPERATING EXPENSES:
Lease operating expenses and production taxes... 3,030 1,704 3,363
Depreciation, depletion and amortization........ 17,457 16,066 15,933
General and administrative...................... 2,097 2,776 2,815
Cost ceiling writedown.......................... -- -- 35,085
------- ------- --------
Total operating expenses...................... 22,584 20,546 57,196
------- ------- --------
OPERATING INCOME (LOSS)........................... 3,983 385 (36,045)
------- ------- --------
INTEREST EXPENSE:
Interest on notes and bank debt................. (2,594) (3,519) (1,635)
Interest on capital transactions................ (1,728) -- --
------- ------- --------
Total interest expense.......................... (4,322) (3,519) (1,635)
------- ------- --------
LOSS BEFORE INCOME TAXES AND EXTRAORDINARY ITEM... (339) (3,134) (37,680)
INCOME TAX PROVISION (CREDIT) (Note 4)............ 472 (1,152) 4,120
------- ------- --------
LOSS BEFORE EXTRAORDINARY ITEM.................... (811) (1,982) (41,800)
EXTRAORDINARY ITEM-LOSS FROM EXTINGUISHMENT OF
DEBT, LESS APPLICABLE INCOME TAXES............... (166) -- --
------- ------- --------
NET LOSS.......................................... $ (977) $(1,982) $(41,800)
======= ======= ========
EARNINGS (LOSS) PER SHARE (Note 5)
Basic........................................... $ (0.07) $ (0.16) $ (3.75)
======= ======= ========
Diluted......................................... $ (0.07) $ (0.16) $ (3.75)
======= ======= ========
The accompanying notes are an integral part of these Consolidated Financial
Statements.
F-4
MILLER EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF EQUITY
(In thousands)
Common Add'l
Stock Preferred Common Paid In Deferred Combined Retained
Warrants Stock Stock Capital Compensation Equity Deficit
-------- --------- ------ ------- ------------ -------- --------
BALANCE--December 31,
1997................... $ -- $ -- $ -- $ -- $-- $8,588 $ 7,525
Net loss and capital
prior to
S Corporation
termination.......... -- -- -- -- -- 172 (163)
S Corporation
termination.......... -- -- -- 16,122 -- (8,760) (7,362)
Common stock
issuance............. -- -- 56 39,983 -- -- --
Combination
transaction.......... -- -- 69 10,156 -- -- --
Restricted stock
issuance............. -- -- 1 875 (876) -- --
Net loss after S
Corporation
Termination.......... -- -- -- -- -- -- (41,637)
------ ----- ----- ------- ---- ------ --------
BALANCE--December 31,
1998................... -- -- 126 67,136 (876) -- (41,637)
Issuance of restricted
stock and benefit
plan shares.......... -- -- -- (500) 794 -- --
Issuance of non-
employee directors'
shares............... -- -- 1 88 -- -- --
Common stock warrants
issued............... 845 -- -- -- -- -- --
Forfeiture of
restricted shares.... -- -- -- (34) 34 -- --
Net loss.............. -- -- -- -- -- -- (1,982)
------ ----- ----- ------- ---- ------ --------
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)
====== ===== ===== ======= ==== ====== ========
The accompanying notes are an integral part of these Consolidated Financial
Statements.
F-5
MILLER EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
For the Year Ended
December 31,
----------------------------
2000 1999 1998
-------- -------- --------
(Note 1)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss........................................ $ (977) $ (1,982) $(41,800)
Adjustments to reconcile net income (loss) to
net cash from operating activities--
Depreciation, depletion and amortization...... 17,457 16,066 15,933
Cost ceiling writedown........................ -- -- 35,085
Deferred income taxes....................... 387 (1,067) (1,052)
Warrants and stock compensation............... 1,262 1,228 --
Extraordinary item............................ 166 -- --
Deferred revenue.............................. (34) (34) (49)
Changes in assets and liabilities--
Restricted cash............................. (65) (4) --
Accounts receivable......................... 106 (621) (1,850)
Other current assets........................ (272) -- 2,952
Other assets................................ 189 48 (118)
Accounts payable............................ 100 (3,347) 6,786
Accrued expenses and other current
liabilities................................ (2,236) 2,599 2,962
-------- -------- --------
Net cash flows provided by operating
activities............................... 16,083 12,886 18,849
-------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development expenditures........ (8,592) (10,265) (46,950)
Acquisition of properties....................... -- -- (51,011)
Proceeds from sale of oil and gas properties and
purchases of
equipment, net................................. 947 14,296 3,065
-------- -------- --------
Net cash flows provided by (used in)
investing activities..................... (7,645) 4,031 (94,896)
-------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments of principal........................... (28,519) (15,717) (5,178)
Borrowing on long-term debt..................... 11,639 2,490 35,500
Common stock proceeds........................... 7,022 -- 45,601
-------- -------- --------
Net cash flows provided by (used in)
financing activities..................... (9,858) (13,227) 75,923
-------- -------- --------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS...................................... (1,420) 3,690 (124)
CASH AND CASH EQUIVALENTS AT BEGINNING OF THE
PERIOD........................................... 3,712 22 146
-------- -------- --------
CASH AND CASH EQUIVALENTS AT END OF THE PERIOD.... $ 2,292 $ 3,712 $ 22
======== ======== ========
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid during the period for--Interest....... $ 2,117 $ 3,033 $ 1,571
======== ======== ========
The accompanying notes are an integral part of these Consolidated Financial
Statements.
F-6
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 5.3 million 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 5.5 million shares of its Common Stock for an aggregate purchase
price of $44.0 million. On March 9, 1998, the Company sold an additional 62,500
shares of its Common Stock for an aggregate purchase price of $0.5 million,
pursuant to the exercise of the underwriters' over-allotment option.
The consolidated financial statements as of and for the year ended December
31, 1998 include the accounts of the Company and its subsidiaries after taking
into effect the Offering and the Combination Transaction.
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 1.6
million 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
("AHC") 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.
In February 1998, MOC terminated its S corporation status which required the
Company to reclassify combined equity and retained earnings as additional paid-
in capital.
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-7
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Principles of Combination
The Combination Transaction was accounted for as a reorganization of
entities under common control in a manner similar to a pooling-of-interests, as
prescribed by Securities and Exchange Commission ("SEC") Staff Accounting
Bulletin No. 47 because of the high degree of common ownership among, and the
common control of, the combined entities.
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. Using
unescalated period-end prices at December 31, 2000, of $8.65 per Mcfe, the
Company had no impairment of oil and gas properties. Using unescalated period-
end prices at December 31, 1999, of $2.38 per Mcfe, the Company would have
recognized a non-cash impairment of oil and gas properties in the amount of
approximately $1.2 million pre-tax. However, on the basis of the improvements
in pricing experienced subsequent to period-end of $2.80 per Mcfe in March
2000, the Company determined that a writedown was not required.
At December 31, 1998, the Company recognized a non-cash cost ceiling
writedown in the amount of $35.1 million. The Company based its ceiling test
determination on a price of $1.78 per Mcfe, which represented the March 1999
closing commodity prices. Had the Company used unescalated period-end prices at
December 31, 1998 of $1.92 per Mcfe, the Company would have recognized a cost
ceiling writedown of $31.1 million.
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).
F-8
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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.
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.
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.
Reclassifications
Certain reclassifications have been made to the prior year financial
statements to conform with the 2000 presentation.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles 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)
As of December 31, 2000 and 1999, the Company does not have any
comprehensive income (loss) other than the net income (loss) for the periods
presented.
Other
For significant accounting policies regarding income taxes, see Note 4; for
earnings per share, see Note 5; for financial instruments, see Note 9; for risk
management activities and derivative transactions, see Note 10; and for stock-
based compensation, see Note 12.
(3) Restricted Cash
In 1999, the Company entered into escrow agreements at the request of
certain joint interest partners regarding the drilling of certain wells
operated by the Company. Terms of the escrow agreements require the parties to
the agreements to deposit their proportionate share of the estimated costs of
drilling each subject well into a separate escrow account. The escrow account
is controlled by an independent third party agent and is restricted to the sole
purpose of processing payments to vendors and suppliers for charges and
expenses associated with the drilling of the wells covered by the escrow
agreements. The amounts recorded as restricted cash in the Consolidated Balance
Sheets represent the Company's share of funds on deposit in the escrow
accounts. Once the agreed upon drilling procedures have been completed, any
remaining funds in the escrow accounts will be promptly returned to the
respective joint interest partners in the same proportion as the original
contributions into the escrow accounts.
F-9
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(4) 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.
Before consummation of the Offering, the Company and the affiliated entities
either elected to be treated as S corporations under the Internal Revenue Code
or were otherwise not taxed as entities for federal income tax purposes. The
taxable income or loss has therefore been allocated to the equity owners of the
Company and the affiliated entities. Due to the use of different methods for
tax and financial reporting purposes in accounting for various transactions,
the Company has temporary differences between its tax basis and financial
reporting basis. Had the Company been a taxpaying entity before consummation of
the Offering, a deferred tax liability of approximately $5.4 million would have
been recorded for this difference, with a corresponding reduction in retained
earnings.
Included in the deferred income tax provision for the year ended December
31, 1998, is a one-time non-cash accounting charge of $5.4 million to record
net deferred tax liabilities, for the differences between tax basis and
financial reporting basis, upon consummation of the Offering and the
termination of MOC's S corporation status. The effective income tax rate for
the Company for the years ended December 31, 2000, 1999 and 1998, was different
than the statutory federal income tax rate for the following reasons (in
thousands):
2000 1999 1998
----- ------- --------
Net loss......................................... $(977) $(1,982) $(41,800)
Add back:
Extraordinary item............................. 166 -- --
Income tax provision (credit).................. 472 (1,152) 4,120
----- ------- --------
Pre-tax loss..................................... (339) (3,134) (37,680)
Income tax provision (credit) at the federal
statutory rate.................................. (115) (1,066) (12,811)
Deferred tax liabilities recorded upon the
Offering........................................ -- -- 5,392
Valuation allowance.............................. -- -- 11,700
Nondeductible interest expense................... 587 -- --
All other, net................................... -- (86) (161)
----- ------- --------
Income tax provision (credit).................... $ 472 $(1,152) $ 4,120
===== ======= ========
The components of the provision of income taxes for the year ended December
31, 2000, 1999 and 1998 are as follows (in thousands):
2000 1999 1998
----- ------- --------
Currently payable................................ $ -- $ -- $ --
Deferred to future periods....................... 472 (1,152) 4,120
----- ------- --------
Total income taxes............................... $ 472 $(1,152) $ 4,120
===== ======= ========
F-10
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The principal components of the Company's deferred tax assets (liabilities)
recognized in the balance sheet as of December 31, 2000 and 1999 are as follows
(in thousands):
2000 1999
-------- --------
Deferred tax liabilities:
Unsuccessful well and lease costs.................... $ (6,435) $ (3,576)
Intangible drilling costs............................ (9,497) (4,540)
Financial statement carrying value in excess of tax
basis of assets..................................... (1,670) (2,800)
Deferred tax assets:
Ceiling test writedown............................... 11,700 11,700
Net operating loss carryforward...................... 11,400 5,100
-------- --------
Net deferred tax assets................................ 5,498 5,884
Less: Valuation allowance.............................. (11,700) (11,700)
-------- --------
Net deferred tax liability............................. $ (6,202) $ (5,816)
======== ========
SFAS No. 109 requires that the Company record a valuation allowance when it
is more likely than not that some portion or all of the deferred tax assets
will not be realized. In the fourth quarter of 1998, the Company recorded a
$35.1 million cost ceiling writedown. The writedown and significant tax net
operating loss carryforwards resulted in a net deferred tax asset at December
31, 1998. The Company believes it is more likely than not that a portion of the
deferred tax assets will not be realized, therefore, the Company has recorded a
valuation allowance. At December 31, 2000, the Company had regular tax net
operating loss carryforwards of approximately $34.0 million. This loss
carryforward amount will expire during 2017. The Company also had a percentage
depletion carryforward of approximately $1.2 million at December 31, 2000,
which is available to offset future federal income taxes payable and has no
expiration date.
(5) 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.
F-11
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The computation of earnings per share for the year ended December 31, 2000,
1999 and 1998 is as follows (in thousands, except per share data):
2000 1999 1998
------- ------- --------
Net loss before extraordinary item attributable
to basic and
diluted EPS................................... $ (811) $(1,982) $(41,800)
Extraordinary item............................. (166) -- --
------- ------- --------
Net loss....................................... $ (977) $(1,982) $(41,800)
======= ======= ========
Weighted average common shares outstanding
applicable to
basic EPS..................................... 13,361 12,633 11,153
Add: options and warrants...................... -- -- --
------- ------- --------
Weighted average common shares outstanding
applicable to
diluted EPS................................... 13,361 12,633 11,153
======= ======= ========
Net loss per share--Basic
Net loss before extraordinary item........... $ (0.06) $ (0.16) $ (3.75)
Extraordinary item........................... (0.01) -- --
------- ------- --------
Net loss..................................... $ (0.07) $ (0.16) $ (3.75)
======= ======= ========
Net loss per share--Diluted
Net loss before extraordinary item........... $ (0.06) $ (0.16) $ (3.75)
Extraordinary item........................... (0.01) -- --
------- ------- --------
Net loss..................................... $ (0.07) $ (0.16) $ (3.75)
======= ======= ========
Options and warrants were not included in the computation of diluted
earnings per share for the years ended December 31, 2000, 1999 and 1998 because
their effect was antidilutive.
(6) Net Production Payments
During 1995, the Company transferred a limited-term working interest, based
on specified volumes, in certain natural gas producing properties to Miller
Shale Limited Partnership ("MSLP"), an affiliated entity. Under the terms of
the agreement, the Company received payments equal to 97% of the net profits
from MSLP, as defined in the agreement, arising from the production of those
properties. The payments received by the Company were reflected on a gross
basis in the accompanying consolidated financial statements and the associated
proved reserves also were reflected in the accompanying supplemental oil and
gas disclosures to the consolidated financial statements.
In June 1999, the Company sold its interest in the above properties, which
included the above-referenced net production payment stream for $4.5 million of
which $4.0 million was used to reduce the Company's outstanding Credit Facility
balance (see Note 7).
(7) Long-Term Debt
Bank Debt
Concurrently with the Offering, the Company entered into a credit facility
(the "Credit Facility") with Bank of Montreal, Houston Agency ("Bank of
Montreal"). The Credit Facility, as amended, required principal reductions and
included certain negative covenants that imposed limitations on the
Company and its subsidiary with respect to, among other things,
distributions with respect to capital stock, limitations on financial ratios,
the creation or incurrence of liens, restrictions on proceeds from sales of oil
and
F-12
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
gas properties, the incurrence of additional indebtedness, making loans and
investments and mergers and consolidations. The obligations under the Credit
Facility were secured by a lien on all real and personal property of the
Company. Commencing April 1999, the interest rate under this facility was
increased to Bank of Montreal's prime rate plus 3.5%.
On July 11, 2000, a principal payment of $4.9 million was made to reduce the
outstanding balance under the Credit Facility to $11.5 million. On July 19,
2000, the Company entered into a new senior credit facility with Bank One,
which replaced the existing credit facility with Bank of Montreal. The new
credit facility has a 30-month term with an interest of either the Bank One
prime rate plus 2% or LIBOR plus 4% at the Company's option. Under the new
credit facility the Company was required to make monthly payments of $500,000
from August 1, 2000, until the borrowing base re-determination that occurred on
January 1, 2001. The new borrowing base determined by Bank One as of December
31, 2000 is $9.0 million, less the amount due AHC in 2001. The next scheduled
borrowing base re-determination with Bank One is in July 2001. The outstanding
Bank One credit facility balance is $7.5 million at December 31, 2000.
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 obligations under the new credit facility
are secured by a lien on all of the Company's real and personal property.
Other
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 $0.01 per share. On April 14, 1999, warrants
exercisable for 322,752 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 322,752 and 454,994 shares,
respectively, of Common Stock were issued to Veritas. The Company ratably
recognizes the prepaid interest into expense over the period to which it
relates. For the years ended December 31, 2000 and 1999, the Company recognized
non-cash interest expense of approximately $752,000 and $600,000, respectively,
related to the Veritas Note Payable. The Warrant Agreement was also amended on
July 19, 2000.
Under the terms of the amended note and warrant agreements, the maturity of
the Veritas Note was extended from April 15, 2001 to July 21, 2003 and the
expiration date for all warrants issued was extended until June 21, 2004. The
annual interest rate has been reduced from 18% to 9 %, provided the entire note
balance is paid in full by December 31, 2001. If all principal and interest
under the Veritas Note is not paid by December 31, 2001, then the note bears
interest at 13 % until paid in full. As of December 31, 2000, the
F-13
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Company has only recognized interest expense on the outstanding Veritas Note at
9 3/4% since it is believed that the principal balance will be paid in full by
December 31, 2001. Interest accrues at the reduced rate from and after October
15, 2000 and is payable commencing April 15, 2001 and continuing on each
October 15 and April 15 until principal is paid in full. Interest was required
to be paid in warrants under the terms of the Warrant Agreement until the
Company is in compliance with the net borrowing base formula as defined in the
Bank One credit facility agreement, at which time interest will only be paid in
cash.
Under the amended Veritas Note, a principal payment of $500,000 was made on
July 19, 2000, the effective date of the amendment, and another $500,000
payment was made in December 2000. The balance due Veritas was $3.7 million at
December 31, 2000 with the entire balance classified as long-term in the
accompanying financial statements.
Any additional proceeds derived from the exercise of warrants issued or from
other debt or equity transactions must be used to pay interest and principal on
the amended Veritas Note until paid in full. Effective November 1, 2000,
Veritas exercised 500,000 warrants to receive 496,923 shares (net of exercise
price) of Company common stock.
In connection with the closing of the AHC property acquisition on February
9, 1998, the Company issued a non-interest bearing note payable to AHC (the
"AHC Note"). The Company had obtained a six-month extension of the $1.0 million
payment due AHC from February 2000 to August 2000. This payment was made on
August 3, 2000. Also, the $1.5 million payment due February 2001 has been
divided into three quarterly installments of $500,000 each, payable commencing
February 2001. A substantial portion of the first quarter 2001 payment was made
in December 2000.
The Company's long-term debt consisted of the following as of December 31,
2000 and 1999 (in thousands):
2000 1999
------- -------
BMO Credit Facility..................................... $ -- $21,914
Bank One Credit Facility................................ 7,500 --
Veritas Note............................................ 3,696 4,696
AHC Note................................................ 1,034 2,500
------- -------
Total................................................. 12,230 29,110
Less current portion of long-term debt................ (1,034) (3,500)
------- -------
$11,196 $25,610
======= =======
(8) 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
1,562,500, 2,500,000 and 9,000,000 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 is required under Emerging Issues
Task Force ("EITF") 85-17 even though no interest is owed on this note since
the stockholders approved the conversion of the note. Accordingly, the Company
has incurred approximately $0.4 million of interest expense during the year
ended December 31, 2000.
F-14
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Under current accounting pronouncements, 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 ($1.56 per share) versus the value agreed
to by both parties of $1.35 per share using various valuation methodologies.
The difference between these values of $.21 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 $1.56
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 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
1,851,851 shares of common stock. In addition, Eagle was issued warrants
exercisable for a total of 2,031,250 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 also entered into a Subscription
Agreement with ECCO Investments, LLC ("ECCO"), pursuant to which ECCO purchased
370,370 shares of the Company's common stock for an aggregate purchase price of
$0.5 million or $1.35 per share.
Common Stock Warrants
At December 31, 2000, the Company has the following Common Stock Warrants
outstanding:
Exercise
Holder of Warrants Price Expiration Date
------------------ -------- ----------------
Guardian:
1,562,500 shares.............................. $1.35 December 7, 2001
2,500,000 shares.............................. 2.50 December 7, 2002
9,000,000 shares.............................. 3.00 December 7, 2004
Eagle:
781,250 shares................................ 1.35 December 7, 2001
1,250,000 shares.............................. 2.50 December 7, 2002
Veritas:
600,498 shares................................ 0.01 June 21, 2004
(9) 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.
F-15
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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 10 for a description of the Company's price hedging
arrangements and the fair values of the arrangements.
(10) Risk Management Activities and Derivative Transactions
The Company uses a variety of derivative instruments to manage exposure to
fluctuations in commodity prices and interest rates. To qualify for hedge
accounting, derivatives must meet the following criteria: (i) the item to be
hedged exposes the Company to price or interest rate risk; and (ii) the
derivative reduces that exposure and is designated as a hedge.
Commodity Price Hedges
The Company periodically enters into certain derivatives (e.g., NYMEX
futures contracts) 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, 2000, 1999, and 1998, the Company hedged 54%, 45%, and 36% of its
oil and gas production, respectively, and as of December 31, 2000, the
Company had 2.0 Bcfe of open oil and natural gas contracts for the months of
January 2001 through December 2001. If all of these open contracts had been
settled on December 31, 2000, the Company would have had to pay approximately
$5.7 million as of December 31, 2000 to settle those contracts.
(11) 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 1998 and contains
an annual 4% escalation clause. In November 2000, the Company sub-leased
approximately 1,500 square feet of its office space to an unrelated third party
for one year. The Company also leases 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 September 1997 and April 1998, respectively. Each lease has a five
year term. The lease for office and warehouse space in Columbia was assumed
through the purchase of certain oil and gas properties from AHC in February
1998, as more fully discussed in Note 1. The Columbia lease term ends in June
2001.
F-16
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Future minimum lease payments required of the Company for years ending
December 31, are as follows (in thousands):
2001......................................... 261
2002......................................... 258
2003......................................... 59
2004......................................... --
Thereafter................................... --
----
$578
====
Total net rent expense under these lease arrangements was $261,990, $255,078
and $198,547 for the years ended December 31, 2000, 1999 and 1998 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. Commencing in July 1998, matching
contributions have been in the form of Company stock. Contributions charged
against operations totaled $50,650, $189,421 and $66,359 for the years ended
December 31, 2000, 1999 and 1998, respectively.
Tax Credit and Royalty Participation Programs
Various employees were eligible to participate in the Company's Tax Credit
and Royalty Participation Programs, which were designed to provide incentive
for certain key employees of the Company. Under the programs, the employees
were entitled to receive cash payments from the Company, based on overriding
royalty working interests, fees, reimbursements and other financial items.
These payments to the employees, which were charged against operations, totaled
$54,611 for the year ended December 31, 1998. These programs were terminated
upon the consummation of the Offering in February 1998.
Other
The Company has been named as 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, is claiming damages related to their destroyed drilling
rig and related costs amounting to approximately $1.2 million, plus interest,
attorneys' fees and costs. In January 2001, the District Court judge ruled
against the Company on two of the three claims filed in this case with damages
left undetermined. This ruling is being appealed to the U.S. Fifth Circuit
Court of Appeals. In the event the Company does not prevail in the appeal, any
resulting damages owed would be completely covered by insurance.
The Company has been 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.
The Company has been named in a lawsuit brought by Charles Strictland,
employee of BJ Services, Inc., on September 30, 1999. The suit claimed damages
of $1.0 million for personal injuries allegedly suffered at a well site
operated by the Company. The judge ruled in favor of the Company at the trial
held March 8, 2001.
F-17
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The Company had been named among several co-defendants in a lawsuit brought
by Eric Parkinson, husband and personal representative of the Estate of Kelly
Anne Parkinson (deceased). The amended complaint was filed December 13, 1999,
in the County of Hillsdale, Michigan, claiming an unspecified amount plus
interest and attorney fees for suffering the loss of the deceased care,
comfort, society and support. Kelly Anne Parkinson was killed in an automobile
accident on February 2, 1999, while traveling on a county road located next to
land wherein the Company is lessee of underground mineral rights. The plaintiff
alleged that the accident was the result of mud dragged on the road from the
leased property and alleged that the Company was negligent in its duty to
conduct its operations at the site with reasonable care. This case was settled
and all claims dismissed in February 2001. All defense costs and the settlement
amount will be covered by the Company's insurance.
The Company believes it has meritorious defenses to the claims discussed
above and intends to vigorously defend these lawsuits. 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. The Company currently
believes any costs resulting from each of the lawsuits mentioned above would be
covered by the Company's insurance.
(12) 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 1.9
million 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 577,350 stock
options were granted by the Company to directors, corporate officers and other
full-time employees of the Company, and 109,500 shares of restricted stock were
granted to certain employees. Also in February 1998, the Company made a one-
time grant of an aggregate of 272,500 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, 43,500 and 66,000 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 2000, 1999 and 1998, total incentive stock options of 473,500, 28,000
and 914,950, respectively, were issued to outside directors and employees under
the 1997 Plan. Stock options totaling 1,224,950 of the 1,416,450 options issued
over the past three years have been granted at 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 $0.01 per share. The right to exercise the
options shall vest and be exercisable when the normal trading
F-18
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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 Percentage
Target Vested
------- ----------
$2.00 40%
$2.75 30%
$3.50 30%
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 $0.01 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 2001, 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 $1.625 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.
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
---------- ----------------------
Number of Number of Average
Shares Shares Grant Price
---------- --------- -----------
Outstanding at January 1, 1998............. -- -- --
Granted.................................. 109,500 914,950 $8.08
Exercised................................ -- -- --
Forfeited................................ -- (500) 8.00
Outstanding at December 31, 1998........... 109,500 914,450 $8.08
Granted.................................. -- 28,000 3.11
Exercised................................ (54,750) -- --
Forfeited................................ (11,250) (167,700) 8.19
Outstanding at December 31, 1999........... 43,500 774,750 $7.89
Granted.................................. -- 473,500 0.96
Exercised................................ (43,500) -- --
Forfeited................................ -- (86,000) $5.36
------- --------- -----
Outstanding at December 31, 2000........... -- 1,162,250 $5.24
======= ========= =====
F-19
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The average fair value of shares granted during 2000, 1999 and 1998 was
$0.95, $1.68, and $4.10, 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 2000 1999 1998
---------- -------- -------- --------
Dividend Yield.............................. 0% 0% 0%
Risk-free interest rate..................... 5.0% 6.5% 5.5%
Expected Life............................... 10 years 10 years 10 years
Expected volatility......................... 33.5% 25.5% 25.7%
The following table summarizes certain information for the options
outstanding at December 31, 2000:
Options
Options Outstanding Exercisable
---------------------------- ----------------
Weighted Weighted Weighted
Average Average Average
Remaining Grant Grant
Range of Grant Prices Shares Life Price Shares Price
--------------------- --------- --------- -------- ------- --------
$0.01 to $10.13................ 1,162,250 8.1 years $5.24 280,700 $7.98
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
------------------------- --------------------------
2000 1999 1998 2000 1999 1998
------ ------- -------- ------- ------- --------
Net Loss................ $ (977) $(1,982) $(41,800) $(1,385) $(2,384) $(42,229)
Earnings (loss) per
share of Common Stock
Basic................. $(0.07) $ (0.16) $ (3.75) $ (0.10) $ (0.19) $ (3.79)
Diluted............... $(0.07) $ (0.16) $ (3.75) $ (0.10) $ (0.19) $ (3.79)
The effects of applying SFAS No. 123 in this pro forma disclosure should
not be interpreted as being indicative of future effects.
(13) Related Party Transactions
In July 1996, 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 11). The Company realized a gain on the sale
of the property of approximately $160,000. This gain was deferred and is being
amortized in proportion to the gross rental charges under the operating lease.
Until March 1999, the Company provided technical and administrative
services to Eagle. In connection with this arrangement, $66,667 and $200,000
were recognized as management fee income (see Note 16) for the years ended
December 31, 1999 and 1998, respectively.
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 re-purchased certain of these properties in 2000 from
Eagle, as more fully described in Note 8.
(14) 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
F-20
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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.
(15) Non-Cash Activities
In December 2000, the Company issued 1,481,481 shares of common stock and
2,031,250 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 8. 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
8.
The Company issued 162,969 and 38,479 shares of common stock to its
directors during the year ended December 31, 2000 and 1999, respectively as
compensation as provided for under the Equity Compensation Plan for Non-
employee Directors. The Company issued 49,539 and 48,178 shares of common stock
to the Company's 401(k) Savings Plan during the year ended December 31, 2000
and 1999, respectively, the Company's matching contribution to the Plan.
In 1999, the Company reclassified approximately $1.5 from deferred revenue
to capitalized oil and gas property costs as more fully discussed in Note 6.
During 1998, the Company recorded a one-time non-cash charge of approximately
$5.4 million for the termination of MOC's S corporation status, as discussed in
Note 4; acquired certain oil and gas properties owned by non-affiliated parties
for approximately $12.8 million of its Common Stock, as discussed in Note 1;
and converted an accounts payable balance of $3.8 million into a note payable,
as discussed in Note 7.
(16) Other Operating Revenues
The majority of the other operating revenues are reimbursements for general
and administrative activities that the Company performs on behalf of partners
and investors in jointly owned oil and gas properties. All other management
fees that were earned for exploration and development activities have been
credited against oil and gas property costs.
(17) 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,
----------------
2000 1999 1998
---- ---- ----
Pan Canadian Energy Services Inc........................ 65% 73% 50%
EOTT.................................................... 16% 16% 9%
Utilicorp............................................... 11% -- % -- %
Amerada Hess Corporation................................ 1% 2% 12%
Dan A. Hughes Company................................... -- % 2% 21%
F-21
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(18) 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, 2000, 1999 and 1998 have been prepared by Miller and Lents, Ltd.
(as to non-Michigan Antrim Shale reserves) and as of December 31, 1998 by S.A.
Holditch and Associates (as to Michigan Antrim Shale reserves), independent
petroleum engineers. All of the Company's reserves are located in the United
States.
F-22
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(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, 2000, 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 Gas
(MBbl) (MMcf)
------ --------
Estimated Proved Reserves
December 31, 1997..................................... 768.5 17,615.1
Extensions and discoveries.......................... 130.1 5,863.7
Purchases of reserves............................... 308.3 23,086.7
Revisions and other changes......................... 63.3 (8,586.1)
Production.......................................... (247.6) (8,953.3)
Sales of reserves................................... (30.9) (104.2)
------ --------
December 31, 1998..................................... 991.7 28,921.9
------ --------
Extensions and discoveries.......................... 60.4 880.3
Revisions and other changes......................... (175.1) 2,391.1
Production.......................................... (255.9) (7,593.8)
Sales of reserves................................... (132.7) (9,642.3)
------ --------
December 31, 1999..................................... 488.4 14,957.2
------ --------
Extensions and discoveries.......................... 418.8 694.0
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 10,511.7
====== ========
Estimated Proved Developed Reserves
December 31, 1998..................................... 991.7 28,641.6
====== ========
December 31, 1999..................................... 460.1 14,944.5
====== ========
December 31, 2000..................................... 301.8 10,511.7
====== ========
The following table summarizes the average year-end prices used to estimate
reserves in accordance with SEC guidelines.
2000 1999 1998
------ ------ -----
Natural gas (per mcf)................................ $ 9.55 $ 2.12 $2.01
Oil (per barrel)..................................... $23.36 $22.29 $8.85
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-23
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(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, 2000, 1999 and 1998:
2000 1999 1998
-------- ------- --------
(In thousands)
Future revenues (1)........................... $108,088 $42,556 $ 66,975
Future production costs (2)................... (16,412) (7,237) (20,930)
Future development costs (2).................. (502) (402) (1,532)
-------- ------- --------
Future net cash flows......................... 91,174 34,917 44,513
Discount to present value at 10% annual rate.. (16,265) (6,197) (8,088)
-------- ------- --------
Present value of future net revenues before
income taxes................................. 74,909 28,720 36,425
Future income taxes discounted at 10% annual
rate (3)..................................... (8,235) -- --
-------- ------- --------
Standardized measure of discounted future net
cash flows (4)............................... $ 66,674 $28,720 $ 36,425
======== ======= ========
- --------
(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 1999 and 1998 balance is not reduced by income taxes due to the tax
basis of the properties and a net operating loss carryforward.
(4) The 2000 balance was computed using year end prices that were significantly
higher than historical levels. Using a price of $5.02 per Mcfe which
represents the February 2001 period ending prices, the standardized measure
would be $57.2 million.
F-24
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(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, 2000, 1999 and 1998:
2000 1999 1998
-------- -------- --------
(In thousands)
New discoveries................................ $ 5,561 $ 2,640 $ 8,185
Purchase of reserves........................... -- -- 55,803
Sales of reserves in place..................... (776) (7,003) (167)
Revisions to reserves.......................... (5,073) 3,262 (18,635)
Sales, net of production costs................. (23,015) (19,027) (17,619)
Changes in prices.............................. 91,684 13,615 (9,675)
Accretion of discount.......................... 2,872 3,643 1,993
Income taxes................................... (8,235) -- --
Changes in timing of production and other...... (25,064) (4,835) (3,394)
-------- -------- --------
Net change during the year..................... $ 37,954 $ (7,705) $ 16,491
======== ======== ========
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, 2000
and 1999:
2000 1999
-------- --------
(In thousands)
Proved properties...................................... $131,872 $115,040
Unproved properties.................................... 16,109 22,678
-------- --------
147,981 137,718
Less--Accumulated depreciation, depletion and
amortization.......................................... (95,948) (78,881)
-------- --------
$ 52,033 $ 58,837
======== ========
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-25
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The following table sets forth costs incurred related to the Company's oil
and gas activities for the years ended December 31:
2000 1999 1998
------- ------- --------
(In thousands)
Property acquisition costs (1)..................... $ 4,323 $ 1,818 $ 60,974
Exploration costs.................................. 1,928 2,572 32,142
Development costs.................................. 4,965 5,875 17,615
------- ------- --------
Total (2)...................................... $11,216 $10,265 $110,731
======= ======= ========
- --------
(1) Includes $19,556 in 1998 for the acquisition of proved producing
properties.
(2) Includes $2,624 in 2000 of non-cash, non-producing properties acquired
from Eagle as more fully described in Note 8. Includes $12,770 in 1998 of
non-cash of proved producing and unproved properties acquired in
connection with the Combination Transaction as more fully described in
Note 1.
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, 2000, 1999 and
1998. The results of operations below do not include general and administrative
expenses, income taxes and interest expense.
2000 1999 1998
------- ------- ---------
(In thousands)
Operating Revenues:
Natural gas................................... $20,745 $17,266 $ 18,336
Crude oil and condensate...................... 5,300 3,465 2,646
------- ------- ---------
Total operating revenues.................... 26,045 20,731 20,982
------- ------- ---------
Operating expenses:
Lease operating expenses and production
taxes........................................ $ 3,030 $ 1,704 3,363
Depreciation, depletion and amortization...... 17,457 16,066 15,933
Cost ceiling writedown........................ -- -- 35,085
------- ------- ---------
Total operating expenses.................... 20,487 17,770 54,381
------- ------- ---------
Results of operations........................... $ 5,558 $ 2,961 $ (33,399)
======= ======= =========
F-26
MILLER EXPLORATION COMPANY
SUPPLEMENTAL QUARTERLY FINANCIAL DATA
Unaudited Quarterly Financial Information
Quarter Ended
----------------------------------
June Sept.
March 31 30 30 Dec. 31
-------- ------ ------ --------
(In thousands, except per share
data)
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................................. (0.03) 0.00 0.02 (0.05)
Diluted............................... (0.03) 0.00 0.02 (0.05)
1999
Total Operating Revenues................ $ 4,873 $4,851 $5,492 $ 5,715
Operating Income........................ 108 59 171 47
Net Loss................................ (288) (576) (546) (572)
Earnings per share:
Basic................................. (0.02) (0.05) (0.04) (0.05)
Diluted............................... (0.02) (0.05) (0.04) (0.05)
1998
Total Operating Revenues................ $ 4,118 $5,608 $5,649 $ 5,776
Operating Income (Loss)................. 39 1,066 592 (37,742)
Net Income (Loss)....................... (5,581) 601 100 (36,920)
Earnings per share:
Basic................................. (0.79) 0.05 0.01 (3.02)
Diluted............................... (0.79) 0.05 0.01 (3.02)
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
thoughout the year.
F-27