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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, 1999
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File Number: 0-23431
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MILLER EXPLORATION COMPANY
(Exact Name of Registrant as Specified in Its Charter)
Delaware 38-3379776
(I.R.S. Employer
(State or Other Jurisdiction of Identification No.)
Incorporation or Organization)
49685-0348
3104 Logan Valley Road, Traverse City,
Michigan (Zip Code)
(Address of Principal Executive
Offices)
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Registrant's telephone number, including area code: (231) 941-0004
Securities registered pursuant to Section 12(g) of the Act:
Title of each class
Common Stock, $0.01 Par Value
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, 2000: 12,704,208
The aggregate market value of the registrant's voting stock held by non-
affiliates of the registrant as of March 20, 2000: $17,468,286
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the Company's May 26, 2000
annual meeting of stockholders are incorporated by reference in Part III of
this Form 10-K
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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. Miller
Exploration Company ("Miller" or 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.
PART I
Item 1. Business.
The Company is an independent oil and gas exploration and production company
with exploration efforts concentrated primarily in the Mississippi Salt Basin
and the Blackfeet Indian Reservation in Northwest Montana. 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 areas. 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 (collectively, the
"Combined Assets").
The Combined Assets consist of MOC, interests in oil and natural gas
properties from oil and natural gas exploration companies beneficially owned
by members of the Miller family (the "Affiliated Entities") and interests in
such properties owned by certain business partners and investors, including
Amerada Hess Corporation ("AHC"), Dan A. Hughes, Jr. and SASI Minerals
Company. No assets other than those in which MOC or the Affiliated Entities
had an interest were part of the Combined Assets. The Company and the owners
of the Combined Assets entered into separate agreements that provided for the
issuance of approximately 6.9 million shares of the Company's Common Stock and
the payment of $48.8 million (net of post-closing adjustments) in cash to
certain participants in the Combination Transaction in exchange for the
Combined Assets. The issuance of the shares and the cash payment were
completed upon consummation of the Company's initial public offering.
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
$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 and $47.0
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million with respect to the Company's interest in 33 gross wells (14.0 net to
the Company) for the year ended December 31, 1998. The Company currently plans
to drill 11 wells (3.9 net to the Company) in 2000, the majority of which are
exploratory wells in the Mississippi Salt Basin. The Company's capital
expenditure budget for both exploration and development activity in all of its
areas of concentration is an unrisked $7.4 million for 2000.
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 significant 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. Such 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 in depth 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 57,583 gross acres (29,224 net to the
Company) covering 20 known salt domes and related salt structures.
Until the late 1980s, geological models of the salt domes in the Mississippi
Salt Basin generally assumed that either the extreme and rapid growth of the
salt structure breached the seals of any formations trapping hydrocarbons
against the domes or that the growth of the salt domes occurred after
hydrocarbons had migrated through the region, in either case, leaving the
formations around the salt domes nonproductive. From 1987 to 1991, Oryx Energy
Corporation ("Oryx") drilled three successful wells on Mississippi salt dome
structures, proving that the flanks of these salt domes were productive. AHC
purchased Oryx's entire interest in this area, and in 1993 MOC acquired a
12.5% working interest from AHC in approximately 35,000 gross acres
surrounding seven domes. As part of the Combination Transaction, the Company
acquired all of AHC's reserves and leasehold interests in these properties,
resulting in an approximate 87.5% working interest in the aggregate to the
Company. The Company selectively reprocessed an extensive 2-D seismic database
that had been acquired over these salt dome prospects, and further acquired
new 2-D seismic to improve the selection of the drill sites along the flanks
of the salt domes. Based on the positive results of the first several
prospects drilled, MOC acquired leasehold interests around 15 additional salt
domes and related salt structures that it considered to be prospective.
Subsequently, the Company has sold down its interest in the salt domes to
generate cash flow for 3-D seismic survey costs, exploration activity and to
pay down the Company's outstanding debt.
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 the 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. The Company believes that all of its unsuccessful
salt dome wells have either encountered the interior salt core of the salt
dome or were too far off structure to encounter the anticipated hydrocarbon
trap. In
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1998, the Company acquired approximately 400 square miles of 3-D seismic data
in the Mississippi Salt Basin. 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 12 producing wells in the Mississippi Salt
Basin that had an aggregate average production rate as of December 31, 1999 of
36.6 million cubic feet of natural gas equivalent per day ("MMcfe/d") gross
(20.9 MMcfe/d net to the Company) at depths ranging from 10,800 to 17,300
feet. Since the Company began its exploration activity in Mississippi in 1993,
it has participated in 28 2-D seismic supported and four 3-D seismic supported
wells drilled around 10 salt dome structures, with 14 of the 2-D wells (50%)
and two of the 3-D wells (50%) establishing commercial production. At December
31, 1999, the Company also was in the process of drilling and/or completing
three 3-D wells (.6 net to the Company). Subsequent to December 31, 1999, two
of these wells were completed and determined to be commercially productive
resulting in an aggregate 3-D supported success rate of 57%. The third well is
still being completed. The Company has a back-in after payout in a 3-D well
that became commercially productive in November 1999 which increases the 3-D
supported well success rate to 63%. The Company also participated in a 3-D
well drilled in January 2000 with logged pay that, if successfully completed,
would boost the 3-D success rate to 67%. The Company has 8 gross wells (2.4
net to the Company) budgeted in 2000 for the Mississippi Salt Basin with a
capital expenditure budget of $7.0 million, including $0.4 million for a new
3-D seismic survey around a currently productive salt dome. All 8 of the
Mississippi Salt Basin wells budgeted for 2000 will be based on 3-D seismic
data
Blackfeet Indian Reservation
In 1998, the Company entered into a joint venture program with K2 Energy
Corporation ("K2") to explore on the Blackfeet Indian Reservation (the
"Reservation") located in Glacier County, Montana. At December 31, 1999, the
Company owned an interest in 150,000 gross leasehold acres (75,000 net to the
Company) in the Reservation under an Indian Mineral Development Act ("IMDA")
agreement with K2, as operator. The initial three wells under the K2 agreement
were drilled in 1999. The Company submitted completion recommendations to K2,
but never received a response or the completion information on the initial
wells. The lack of communication with K2 has aggravated an already strained
relationship. The Company has submitted three drilling proposals to fulfill
its 2000 drilling commitment to its partner and operator, K2, with plans to
begin drilling in mid-summer 2000.
In February 1999, the Company entered into a separate IMDA agreement
("Miller Agreement") with the Blackfeet Indian Tribe (the "Tribe") covering
100,000 Tribal acres on the Reservation. The Miller Agreement gives the
Company the ability to pay up to $0.2 million for a one-year extension of the
two-well annual drilling commitment. The specific provision provides that the
Company will not ask for an unreasonable time extension nor will the Tribe
unreasonably withhold its consent. In November 1999, the Company requested an
extension until July 31, 2000, and received a letter from the Tribe on March
2, 2000, stating that the Company has not fulfilled its drilling obligation.
The Tribe has not acknowledged the drilling extension provision of the
contract. The Company believes that the extension has been unreasonably
withheld, which is a violation of the contract. The Company notified the Tribe
on March 14, 2000, and has demanded the return of the initial $1.0 million
bonus paid in May 1999, and is also currently evaluating additional options.
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 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 approximately 175 million barrels of oil ("MMBbl") and 309 Bcf of
natural gas. In 1999, the Company incurred $2.1 million in leasehold, 2-D
seismic and drilling/completion costs on this project.
3
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 AHC, Liberty Energy
Corporation, Bonray, Inc., Key Production Company Inc. ("Key"), and Remington
Oil & Gas Corp. ("Remington"). 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. Pursuant to these agreements, the Company has acquired and will have
the right to acquire a portion of the working interest in leases owned or
acquired by the parties within the AMI's. The joint venture exploration
agreements begin to expire January 1, 2000, except with respect to AMI's 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.
Under the joint venture agreement between MOC and Key, if either party
elects not to participate on a proposed 3-D seismic program proposed by the
other party, the non-participating party will farm-out its non-producing
leasehold interest in that dome, retaining an option to participate after
payout of the seismic expenses and the drilling and completion expenses of the
exploratory well, for a proportionally reduced 25% working interest in the
exploratory well. The non-participating party will retain 25% of its original
leasehold interest outside the initial well but within the identified dome
area. Without mutual agreement, no more than two 3-D seismic surveys will be
committed to and/or conducted concurrently. Either party may propose an
Initial Exploratory Well, defined as the first exploratory well proposed and
drilled on each dome after a 3-D program has been conducted. A party electing
not to participate in an Initial Exploratory Well is obligated to assign to
the proposing party its interest in leases within that dome area to the depth
drilled by the Initial Exploratory Well. For wells drilled without conducting
a 3-D survey, a non-participating party is subject to a 400% non-consent
penalty.
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 provide 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 will earn 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. Remington and Miller will also be reviewing the merits of a
3-D survey over the Dry Creek Dome, wherein Remington will have the option to
earn 50% of the undeveloped acreage at the Company's Dry Creek Dome by paying
the first $900,000 of a 3-D seismic shoot.
Blackfeet Indian Reservation Agreements
The Company entered into an Exploration and Development Agreement (the
"EDA") with K2 on June 17, 1998 to explore and develop approximately 150,000
gross leasehold acres on 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 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
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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%. The Company has met
all its obligations for 1999 under these agreements.
The Company entered into a separate IMDA Agreement with the Tribe covering
100,000 Tribal acres that was approved February 26, 1999 (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 each anniversary for two
years. 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 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 K2/Miller
Agreement executed on June 17, 1998, K2 was offered their exclusive right to
purchase 50% of the Company's interest in the Miller Agreement for cost plus
20% on June 7, 1999. K2 conditionally accepted this offer and, to date, has
not paid for its proportionate share of said lands.
Michigan Basin Agreements
MOC entered into a Purchase and Sale Agreement dated as of January 1, 1995
with Miller Shale Limited Partnership ("MSLP") for the purpose of monetizing
the Section 29 tax credits available from most of its Antrim gas wells in
Michigan, and a Purchase and Sale Agreement dated as of November 1, 1996 with
MSLP for the purpose of selling part of the reversionary interest retained by
MOC under the prior Purchase and Sale Agreement. MSLP is a Michigan limited
partnership owned 1% by the general partner, Miller Shale S.V., L.L.C., an
affiliate of MOC, and 99% by the limited partner, Far Gas Acquisitions
Corporation, an unrelated party. As a result, pursuant to the terms of the two
Purchase and Sale Agreements, MOC has assigned its interest in the wells,
leases, equipment and other property to MSLP, reserving three separate
production payments, an additional contingent payment and a reversionary
interest. The first and second production payments generally entitle MOC to
receive 97% of the net cash flow from the assigned properties until a
specified dollar amount or specified volume is achieved from production
attributable to the assigned interests. The third production payment and the
additional contingent payment generally entitle MOC to receive 96% of the net
cash flow from additional specified volumes of production attributable to the
assigned interests. The reversionary interest entitles MOC to a reassignment
of 90% of the interests after a larger specified volume of natural gas has
been produced from the assigned interests. MSLP also is obligated to make
quarterly payments to MOC equivalent to a percentage of the tax credits
available under Section 29 with respect to natural gas produced and sold from
the interests assigned. MOC also has an option to repurchase the assigned
interests for fair market value after December 31, 2002, the expiration date
of the Section 29 tax credits. In June 1999, the Company sold its interest in
all of its Antrim Shale properties located in Michigan, including the
production payments mentioned above to an unrelated third party for $4.5
million.
5
Volumes, Prices and Production Costs
The following table sets forth information of the Company with respect to
production volumes, average prices received and average production costs for
the periods indicated:
Year Ended December 31,
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1999 1998 1997
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Production:
Crude oil and condensate (Mbbls)................. 255.9 247.6 47.4
Natural gas (MMcf)............................... 7,593.8 8,953.3 2,241.2
Natural gas equivalent (MMcfe)................... 9,129.2 10,438.7 2,525.9
Average sales prices:
Crude oil and condensate ($ per Bbl)............. $ 13.54 $ 10.69 $ 20.33
Natural gas ($ per Mcf).......................... 2.27 2.05 2.60
Natural gas equivalent ($ per Mcfe).............. 2.27 2.01 2.69
Average Costs ($ per Mcfe):
Lease operating expenses and production taxes.... $ 0.19 $ 0.32 $ 0.58
Depreciation, depletion and amortization......... 1.76 1.53 1.00
General and administrative....................... 0.34 0.33 0.87
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
and 1999, with spot market prices for crude oil falling below $10 per Bbl, and
then rising close to $30 per Bbl, and natural gas prices dropping below $1 per
Mcf and then climbing up above $3 per Mcf during this two-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, 1999, sales to the Company's four
largest customers were approximately 73%, 16%, 3% and 3%, respectively, of the
Company's oil and natural gas revenues. Due to the availability of other
markets and pipeline connections, the Company does not believe that the loss
of any single oil or natural gas customer would have a material adverse effect
on the Company's results of operations or financial condition.
Competition
The oil and gas industry is highly competitive in all of its phases. The
Company encounters competition from other oil and natural gas companies in all
areas of its operations, including the acquisition of seismic options and
lease options on properties. The Company's competitors include major
integrated oil and natural gas companies and numerous independent oil and
natural gas companies, individuals and drilling and income programs. Many of
the Company's competitors are large, well established companies with
substantially larger operating staffs and greater capital resources than the
Company's and which, in many instances, have been engaged in the exploration
and production business for a much longer time than the Company. Such
companies may be able to pay more for seismic and lease options on oil and
natural gas properties and exploratory prospects and to define, evaluate, bid
for and purchase a greater number of properties and prospects than the
Company's financial or human resources permit. The Company's ability to
explore for oil and natural gas prospects, to acquire additional properties
and to discover reserves in the future will depend upon its ability to conduct
its
6
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 severance
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 expires June 30, 2003. In April
1999, the State enacted a bill that reduces the severance 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.
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.
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
7
Regulatory Commission ("FERC") regulates the transportation and sale of
natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 and
the Natural Gas Policy Act of 1978. In the past, the federal government has
regulated the prices at which oil and natural gas can be sold. While sales by
producers of natural gas and all sales of oil and natural gas liquids
currently can be made at uncontrolled market prices, Congress could reenact
price controls in the future.
In recent years, FERC has undertaken various initiatives to increase
competition within the natural gas industry. As a result of initiatives like
FERC Order 636, issued in April 1992 and its progeny, the interstate natural
gas transportation and marketing system has been substantially restructured to
remove various barriers and practices that historically limited non-pipeline
natural gas sellers, including producers, from effectively competing with
interstate pipelines for sales to local distribution companies and large
industrial and commercial customers. The most significant provisions of Order
No. 636 require that interstate pipelines provide transportation separate or
"unbundled" from their sales service, 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 areas; require remedial measures to mitigate pollution from former
operations such as plugging abandoned wells;
8
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 of or released on or under the properties.
In addition, most 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 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.
9
Employees
As of March 20, 2000, 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 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.
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 variance from the 2000 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
Drilling activities are subject to many risks, including the risk that no
commercially productive reservoirs will be encountered. There can be no
assurance that new wells drilled by the Company will be productive or that the
Company will recover all or any portion of its investment. Drilling for oil
and natural gas may involve unprofitable efforts, not only from dry wells, but
from wells that are productive but do not produce sufficient net revenues to
return a profit after drilling, operating and other costs. The cost of
drilling, completing and operating wells is often uncertain. The Company's
drilling operations may be curtailed, delayed or canceled as a result of
numerous factors, many of which are beyond the Company's control, including
title problems, weather conditions, compliance with governmental requirements
and shortages or delays in the delivery of equipment and services. The
Company's future drilling activities may not be successful and, if
unsuccessful, such failure may have a material adverse effect on the Company's
future results of operations and financial condition.
10
In addition, the Company's use of 3-D seismic technology requires greater
pre-drilling expenditures than traditional drilling strategies. Although the
Company believes that its use of 3-D seismic technology will increase the
probability of success, unsuccessful wells are likely to occur. There can be
no assurance that the Company's drilling program will be successful or that
unsuccessful drilling efforts will not have a material adverse effect on the
Company.
The Company's operations are subject to hazards and risks inherent in
drilling for and producing and transporting oil and natural gas, such as
fires, natural disasters, explosions, encountering formations with abnormal
pressures, blowouts, craterings, pipeline ruptures and spills, uncontrollable
flows of oil, natural gas or well fluids, any of which can result in the loss
of hydrocarbons, environmental pollution, personal injury claims and other
damage to properties of the Company and others. The Company maintains
insurance against some but not all of the risks described above. In
particular, the insurance maintained by the Company does not cover claims
relating to failure of title to oil and natural gas leases, trespass during 2-
D and 3-D survey acquisition or surface change attributable to seismic
operations and, except in limited circumstances, losses due to business
interruption. The Company may elect to self-insure if management believes that
the cost of insurance, although available, is excessive relative to the risks
presented. In addition, pollution and environmental risks generally are not
fully insurable. The Company occasionally participates in wells on a non-
operated basis, which may limit the Company's ability to control the risks
associated with oil and natural gas operations. The occurrence of an event
that is not covered, or not fully covered, by insurance could have a material
adverse effect on the Company's business, financial condition and results of
operations.
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 of Growth 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,
11
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.
Reserve Replacement Risk
In general, production from oil and natural gas properties declines as
reserves are depleted, with the rate of decline depending on reservoir
characteristics. 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
12
adverse effect on the Company's business, financial condition, results of
operations, development efforts and ability to grow. There can be no assurance
that the Company will be successful in attracting and/or retaining its key
management personnel or technical experts or consultants.
Technological Changes
The oil and gas industry is characterized by rapid and significant
technological advancements and introductions of new products and services
utilizing new technologies. As others use or develop new technologies, the
Company may be placed at a competitive disadvantage, and competitive pressures
may force the Company to implement such new technologies at substantial costs.
In addition, other oil and gas companies may have greater financial, technical
and personnel resources that allow them to enjoy technological advantages and
may in the future allow them to implement new technologies before the Company.
There can be no assurance that the Company will be able to respond to such
competitive pressures and implement such technologies on a timely basis or at
an acceptable cost. One or more of the technologies currently utilized by the
Company or implemented in the future may become obsolete. In such cases, the
Company's business, financial condition and results of operations could be
materially adversely affected. If the Company is unable to utilize the most
advanced commercially available technology, the Company's business, financial
condition and results of operations could be materially and adversely
affected.
Substantial Capital Projects
The Company makes and will continue to make 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.
Substantial Indebtedness
As of December 31, 1999, the Company had total indebtedness of $29.1
million. The Company's substantial 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, 1999, the Company's directors, executive officers and
certain of their affiliates, beneficially owned approximately 38% of the
Company's outstanding Common 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.
13
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.
Item 2. Properties.
Oil and Natural Gas Reserves
The Company's estimated total proved reserves of oil and natural gas as of
December 31, 1999 and 1998, and the present values of estimated future net
revenues attributable to these reserves as of those dates were as follows:
As of December 31,
-----------------------
1999 1998
----------- -----------
(Dollars in thousands,
except per unit data)
Net Proved Reserves:
Crude oil (Mbbl)................................. 488.4 991.7
Natural gas (MMcf)............................... 14,957.2 28,921.9
Natural gas equivalent (MMcfe)................... 17,887.6 34,872.1
Net Proved Developed Reserves:
Crude oil (Mbbl)................................. 460.1 991.7
Natural gas (MMcf)............................... 14,944.5 28,641.6
Natural gas equivalent (MMcfe)................... 17,705.1 34,591.8
Estimated future net revenues before income
taxes(1).......................................... $ 34,917 $ 44,513
Present value of estimated future net revenues
before income taxes(2)............................ $ 28,720 $ 36,425
Standardized measure of discounted estimated future
net cash flows(3)................................. $ 28,720 $ 36,425
- --------
(1) The average prices for crude oil were $22.29 per Bbl at December 31, 1999
and $8.85 per Bbl at December 31, 1998. The average prices for natural gas
were $2.12 per Mcf at December 31, 1999 and $2.01 per Mcf at December 31,
1998.
(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 balances
are not reduced by income taxes due to the tax basis of the properties and
a net operating loss carryforward.
14
In June 1999, the Company sold its interest in all Michigan Basin Antrim
Shale properties.
The reserve estimates reflected above, as of December 31, 1999, were
prepared by Miller and Lents, Ltd., and as of December 31, 1998, by S.A.
Holditch & Associates (as to Michigan Basin Antrim Shale reserves) and Miller
and Lents, Ltd. (as to non-Michigan Basin Antrim Shale reserves), independent
petroleum engineers, and are part of their reserve reports on the Company's
oil and natural gas properties.
In accordance with applicable requirements of the SEC, estimates of the
Company's proved reserves and future net revenues are made using sales prices
estimated to be in effect as of the date of such reserve estimates and are
held constant throughout the life of the properties (except to the extent a
contract specifically provides for escalation). Estimated quantities of proved
reserves and future net revenues therefrom are affected by oil and natural gas
prices, which have fluctuated widely in recent years. There are numerous
uncertainties inherent in estimating oil and natural gas reserves and their
estimated values, including many factors beyond the control of the Company.
The reserve data set forth in this Form 10-K represents only estimates.
Reservoir engineering is a subjective process of estimating underground
accumulations of oil and natural gas that cannot be measured in an 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,
------------------------------
1999 1998 1997
--------- ---------- ---------
Gross Net Gross Net Gross Net
----- --- ----- ---- ----- ---
Exploratory Wells:
Oil......................................... 1 0.4 1 0.2 2 0.3
Natural gas................................. 1 1.0 8 2.6 2 0.6
Non-productive.............................. 4 2.2 18 8.6 8 1.8
--- --- --- ---- --- ---
Total..................................... 6 3.6 27 11.4 12 2.7
=== === === ==== === ===
Development Wells(1):
Oil......................................... 1 0.9 4 0.8 3 0.6
Natural gas................................. 1 0.6 -- -- 11 2.3
Non-productive.............................. 1 0.4 2 1.8 5 1.0
--- --- --- ---- --- ---
Total..................................... 3 1.9 6 2.6 19 3.9
=== === === ==== === ===
- --------
(1) Includes nine gross Antrim Shale wells (1.3 net to the Company) for the
year ended December 31, 1997.
15
At December 31, 1999, the Company was in the process of drilling and/or
completing three gross wells (0.6 net to the Company) that are not reflected
in the table. Subsequent to December 31, 1999, two of these wells were
determined to be commercially productive. Three of the non-productive
exploratory wells drilled during 1999 were in Montana with total capital
expenditures of approximately $0.8 million.
Productive Wells and Acreage
Productive Wells
The following table sets forth the Company's ownership interest as of
December 31, 1999 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.................... 2 0.6 10 7.9 12 8.5
Onshore Gulf Coast
Texas................................... 4 0.2 6 0.2 10 0.4
Michigan Basin/Other...................... 1 .1 1 1.0 2 1.1
--- --- ----- ----- --- ----
Total................................. 7 0.9 17 9.1 24 10.0
=== === ===== ===== === ====
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 completions.
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, 1999:
Developed Undeveloped Total
------------ --------------- ---------------
Gross Net Gross Net Gross Net
------ ----- ------- ------- ------- -------
Mississippi Salt Basin.......... 5,600 4,401 57,583 29,224 63,183 33,625
Montana......................... -- -- 250,000 175,000 250,000 175,000
Onshore Gulf Coast
Texas......................... 4,134 129 5,240 802 9,374 931
Louisiana..................... -- -- 2,993 575 2,993 575
Michigan Basin/Other............ 400 260 9,454 6,027 9,854 6,287
------ ----- ------- ------- ------- -------
Total....................... 10,134 4,790 325,270 211,628 335,404 216,418
====== ===== ======= ======= ======= =======
All of the leases for the undeveloped acreage summarized in the preceding
table will expire at the end of their respective primary terms unless the
existing leases are renewed or production has been obtained from the acreage
subject to the lease before that date, in which event the lease will remain in
effect until the cessation of production. To this end, the Company's
forecasted drilling schedule takes into consideration not only the
attractiveness of individual prospects, but the lease expirations as well. The
following table sets forth the minimum remaining terms of leases for the total
gross and net acreage at December 31, 1999:
16
Acres Expiring
---------------
Gross Net
------- -------
Twelve Months Ending:
December 31, 2000.......................................... 30,044 15,280
December 31, 2001.......................................... 11,652 4,595
December 31, 2002.......................................... 13,901 6,244
Thereafter................................................. 279,807 190,299
------- -------
Total.................................................... 335,404 216,418
======= =======
Facilities
The Company currently leases approximately 10,500 square feet of office
space for its principal offices in Traverse City, Michigan. 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.
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.
The Company has been named in 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 is claiming
damages of $1.0 million for personal injuries allegedly suffered at a well
site operated by the Company.
The Company has 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 alleges that the accident was the result of mud dragged on the road
from the leased property and alleges that the Company was negligent in its
duty to conduct its operations at the site with reasonable care.
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.
Item 4. Submission of Matters to a Vote of Security Holders.
During the fourth quarter of 1999, no matter was submitted to a vote of
security holders, through the solicitation of proxies or otherwise.
17
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 20, 2000, 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 sales prices for the
Company's Common Stock for the periods indicated, all as reported by The
Nasdaq National Market:
High Low
---- ---
Year Ended December 31, 1999:
First Quarter............................................ $ 5 $ 2
Second Quarter........................................... 2 5/16 9/16
Third Quarter............................................ 3 9/32 1 3/4
Fourth Quarter........................................... 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.
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, 1999 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,
--------------------------------------------
1999 1998 1997 1996 1995
------- -------- ------- ------- -------
(In thousands, except per share data)
Statement of Operations Data:
Revenues:
Natural gas.................. $17,266 $ 18,336 $ 5,819 $ 5,614 $ 2,748
Crude oil and condensate..... 3,465 2,646 964 1,101 715
Other operating revenues..... 558 829 629 395 296
------- -------- ------- ------- -------
Total operating revenues... 21,289 21,811 7,412 7,110 3,759
Operating expenses:
Lease operating expenses and
production taxes............ 1,704 3,363 1,478 1,123 777
Depreciation, depletion and
amortization................ 16,066 15,933 2,520 2,629 1,666
General and administrative... 3,134 3,475 2,186 1,591 1,270
Cost ceiling writedown....... -- 35,085 -- -- --
------- -------- ------- ------- -------
Total operating expenses... 20,904 57,856 6,184 5,343 3,713
------- -------- ------- ------- -------
Operating income (loss)........ 385 (36,045) 1,228 1,767 46
Interest expense............... (3,519) (1,635) (1,200) (1,139) (1,017)
Lawsuit settlement............. -- -- -- -- 3,521
------- -------- ------- ------- -------
Income (loss) before income
taxes......................... (3,134) (37,680) 28 628 2,550
------- ------- -------
Income tax provision (credit)
(1)........................... (1,152) 4,120
------- --------
Net income (loss).............. $(1,982) $(41,800) $ 28 $ 628 $ 2,550
======= ======== ======= ======= =======
Basic and diluted earnings
(loss) per share.............. $ (0.16) $ (3.75)
======= ========
Weighted average shares
outstanding................... 12,632 11,153
------- --------
As of December 31,
--------------------------------------------
1999 1998 1997 1996 1995
------- -------- ------- ------- -------
(In thousands)
Balance Sheet Data (at end of
period):
Working capital................ $(4,200) $(15,925) $(5,985) $(2,682) $(1,980)
Oil and gas properties, net.... 58,837 80,014 23,968 20,732 17,731
Total assets................... 69,686 85,968 30,428 24,050 20,005
Long-term debt, excluding
current portion............... 25,610 31,837 481 8,723 7,643
Equity......................... 23,995 24,749 16,113 7,769 7,410
- --------
(1) Upon consummation of the Combination Transaction, 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 and Montana.
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, including AHC, Dan A. Hughes, Jr.
and SASI Minerals Company. No assets other than those in which MOC or the
Affiliated Entities had an interest were part of the Combined Assets. The
Company and the owners of the Combined Assets entered into separate agreements
that provided for the issuance of approximately 6.9 million shares of the
Company's Common Stock and the payment of $48.8 million (net of post-closing
adjustments) in cash to certain participants in the Combination Transaction in
exchange for the Combined Assets. The issuance of the shares and the cash
payment were completed upon consummation of the Company's Offering.
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. 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, the Company has determined that a writedown is not
required.
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,
-----------------------------------------------------
1999 1998 1997 1999 1998 1997
------- -------- ------- ------- -------- -------
(Historical) (Pro Forma)
Production volumes:
Crude oil and
condensate (Mbbls).... 255.9 247.6 47.4 255.9 261.2 206.8
Natural gas (MMcf)..... 7,593.8 8,953.3 2,241.2 7,593.8 9,646.2 8,298.2
Natural gas equivalent
(MMcfe)............... 9,129.2 10,438.7 2,525.9 9,129.2 11,213.4 9,539.2
Revenues:
Natural gas............ $17,266 $ 18,336 $ 5,819 $17,266 $ 19,810 $20,774
Crude oil and
condensate............ 3,465 2,646 964 3,465 2,833 3,711
Operating expenses:
Lease operating
expenses and
production taxes...... $ 1,704 $ 3,363 $ 1,478 $ 1,704 $ 3,571 $ 2,423
Depletion, depreciation
and amortization...... 16,066 15,933 2,520 16,066 16,537 7,812
General and
administrative........ 3,134 3,475 2,186 3,134 3,175 2,606
Interest expense......... $ 3,519 $ 1,635 $ 1,200 $ 3,519 $ 1,635 $ 1,125
Net income (loss)........ $(1,982) $(41,800) $ 28 $(1,983) $(35,158) $ 8,438
Average sales prices:
Crude oil and
condensate ($ per
Bbl).................. $ 13.54 $ 10.69 $ 20.33 $ 13.54 $ 10.85 $ 17.94
Natural gas ($ per
Mcf).................. 2.27 2.05 2.60 2.27 2.05 2.50
Natural gas equivalent
($ per Mcfe).......... 2.27 2.01 2.69 2.27 2.02 2.57
Average costs ($ per
Mcfe):
Lease operating
expenses and
production taxes...... $ 0.19 $ 0.32 $ 0.58 $ 0.19 $ 0.32 $ 0.25
Depletion, depreciation
and amortization...... 1.76 1.53 1.00 1.76 1.47 0.82
General and
administrative........ 0.34 0.33 0.87 0.34 0.28 0.27
Because of the significance of the Combination Transaction which occurred on
February 9, 1998, the results of operations have been presented above on a pro
forma and historical basis. The results of operations described below will
compare historical 1999 year end results of operations to pro forma 1998 year
end results of operations and pro forma 1998 year end results of operations to
pro forma 1997 year end results of operations. For additional information
regarding the Combination Transaction, see Note 1 to the Consolidated
Financial Statements.
Historical Year Ended December 31, 1999 compared to Pro Forma Year Ended
December 31, 1998
Oil and natural gas revenues for the year ended December 31, 1999 decreased
8% to $20.7 million from $22.6 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 21% to 7,594 MMcf from 9,646 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
21
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 declined 2% to 256 MBbls from
261 MBbls for the year ended December 31, 1998. Reduced oil production
attributable to sold properties in Texas and Louisiana mentioned above offset
the production increases from the Mississippi Salt Basin properties. Average
oil prices increased 25% to $13.54 per barrel during the year ended December
31, 1999 from $10.85 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 52% to $1.7 million from $3.6 million for the year ended
December 31, 1998. Lease operating expenses and production taxes decreased due
to the combined effect of decreased production associated with the sale of
producing properties, as described above, and cost efficiencies realized by
the Company on its operated Mississippi Salt Basin properties during 1999.
Depreciation, depletion and amortization ("DD&A") expense for the year ended
December 31, 1999 decreased 3% to $16.1 million from $16.5 million for the
year ended December 31, 1998.
General and administrative expense for the year ended December 31, 1999
decreased 1% to $3.1 million from $3.2 million for the same period in 1998.
General and administrative costs started decreasing in 1999 due to a cost
reduction plan approved by the Company's board of directors in March 1999.
After removal of all non-cash items, general and administrative expense for
the year ended December 31, 1999 decreased 16% when compared to the same
period of 1998. General and administrative expense for the year ended December
31, 1999 includes the following non-cash items: 1) 401(k) contributions and
director fees which were satisfied with Company common stock and compensation
expense for the vested portion of restricted stock issued in February 1998, in
connection with the Initial Public Offering. General and administrative
expense for the year ended December 31, 1998 includes director fees paid in
Company common stock as a non-cash expense.
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, the Company has determined that a writedown is not
required.
At December 31, 1998, the Company recorded a non-cash cost ceiling writedown
of $34.4 million. The writedown was the combined result of a large downward
revision in oil and gas reserve quantities and depressed commodity prices.
Disappointing 2-D seismic-supported drilling results during 1998 and drilling
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 Liquidity
and Capital Resources below and in Note 7, 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 by $33.2 million to
$(2.0 million) from $(35.2 million) for the year ended December 31, 1998, as a
result of the factors described above.
Pro Forma Year Ended December 31, 1998 compared to Pro Forma Year Ended
December 31, 1997
Oil and natural gas revenues for the year ended December 31, 1998 decreased
8% to $22.6 million from $24.5 million for the year ended December 31, 1997.
Oil and natural gas revenues for the year ended December 31, 1998 include
approximately $0.8 million of hedging gains (see "Risk Management Activities
and Derivative
22
Transactions" below). Production volumes for natural gas during the year ended
December 31, 1998 increased 16% to 9,646 MMcf from 8,298 MMcf for the year
ended December 31, 1997. Average natural gas prices decreased 18% to $2.05 per
Mcf for the year ended December 31, 1998 from $2.50 per Mcf for the year ended
December 31, 1997. Production volumes for oil during the year ended December
31, 1998 increased 26% to 261 MBbls from 207 MBbls for the year ended December
31, 1997. Average oil prices decreased 40% to $10.85 per barrel during the
year ended December 31, 1998 from $17.94 per barrel in the year ended December
31, 1997. The oil and gas industry suffered through a year of historically low
oil prices in 1998, caused by a global influx of crude oil supply brought on
by increased Middle-East exports combined with a weaker demand from Asian
markets that were experiencing an economic recession. The natural gas market
also was depressed as a result of abnormally mild winters caused by a strong
El Nino weather pattern that affected the United States during the past two
heating seasons. The Company would have experienced an even larger decrease in
revenue had it not been for the natural gas hedging gains of approximately
$0.8 million and the fact that only 12% of total operating revenues for 1998
were attributable to oil production.
Lease operating expenses and production taxes for the year ended December
31, 1998 increased 47% to $3.6 million from $2.4 million for the year ended
December 31, 1997. Lease operating expenses and production taxes increased
primarily due to increased production as described above and to several
workover projects that were completed during the year in an attempt to enhance
production during a period of low commodity prices.
Depreciation, depletion and amortization ("DD&A") expense for the year ended
December 31, 1998 increased 112% to $16.5 million from $7.8 million for the
year ended December 31, 1997. This increase was due to a 79% increase in the
1998 depletion rate to $1.47 per Mcfe from $.82 per Mcfe for the year ended
December 31, 1997. The higher depletion rate was the combined result of
increased production, an increase in costs subject to DD&A and a downward
revision in estimated proved oil and gas reserves.
General and administrative expense for the year ended December 31, 1998
increased 22% to $3.2 million from $2.6 million for the same period in 1997.
The rise in general and administrative costs is primarily attributable to
added expenses associated with the Company's initial year as a public company.
These incremental expenses include legal and professional fees paid to
attorneys and accountants, increased rents related to office facilities in
Mississippi and increased salaries and benefits due to additional financial,
technical, operational and administrative staff added during the year.
At December 31, 1998, the Company recorded a non-cash cost ceiling writedown
of $34.4 million. The writedown was the combined result of a large downward
revision in oil and gas reserve quantities and depressed commodity prices.
Disappointing 2-D seismic-supported drilling results and drilling cost
overruns also contributed to the cost ceiling writedown. The Company based its
ceiling test determination on a price of $1.78 per Mcfe, which represents the
March 1999 closing commodity prices.
Interest expense for the year ended December 31, 1998 increased 45% to $1.6
million from $1.1 million for the year ended December 31, 1997, as a result of
increased debt levels in 1998 for substantial exploration and development
activities in the Mississippi Salt Basin area.
Net income (loss) for the year ended December 31, 1998 decreased by $43.6
million from $(35.2) to $8.4 million for the year ended December 31, 1997, as
a result of the factors described above.
Liquidity and Capital Resources
Historically, the Company's primary sources of capital have been funds
generated by operations, and borrowings under bank credit facilities.
The Company has a credit facility (the "Credit Facility") with Bank of
Montreal, Houston Agency ("BMO"). The Credit Facility includes certain
negative covenants that impose limitations on the Company and its subsidiary
with respect to, among other things, distributions with respect to its capital
stock, limitations on financial ratios, the creation or incurrence of liens,
the incurrence of additional indebtedness, making loans and investments and
mergers and consolidations. The obligations of the Company under the Credit
Facility are secured by a lien on all real and personal property of the
Company. At December 31, 1999, $21.9 million was outstanding under the Credit
Facility.
23
On April 14, 1999, the Company and BMO entered into the Second Amendment to
the Credit Facility. The Second Amendment stipulated, among other things, that
the Company submit a revised reserve report to BMO by October 1, 1999 for a
re-determination of the borrowing base and pay a $300,000 re-determination
fee.
On October 29, 1999, the re-determination fee was paid, and the Company and
BMO entered into the Third Amendment to the Credit Facility which included:
(i) terms requiring the Company to make principal payments to BMO during the
period beginning with October 1999 through February 2000, (ii) terms requiring
that all outstanding borrowings bear interest at BMO's prime rate plus 3.5%;
(iii) revision or waiver of certain negative covenant provisions through
September 30, 2000; (iv) a requirement to submit a revised reserve report to
BMO by April 1, 2000 for a re-determination of the borrowing base; (v) a
requirement that all proceeds from the sales of proved or unproved oil and gas
properties, prior to the re-determination date, must be used to reduce the
principal amount outstanding under the Credit Facility; and (vi) a requirement
for an amendment fee payable to BMO in an amount equal to 2% of the
outstanding balance of the Credit Facility at the April re-determination date.
Final maturity of the Credit Facility was set at January 1, 2001. Total
principal payments of $5.1 million were made under the Third Amendment with
the remaining $1.9 million waived through letter agreements subsequent to
December 31, 1999.
On March 20, 2000, the Company entered into a Fourth Amendment with BMO
which continued all of the provisions of the Third Amendment with the
exception of the following changes: i) extension of the final maturity date of
the Credit Facility to April 1, 2001; and ii) requirement of a $1.0 million
principal payment by March 31, 2000. At the April re-determination date, the
Company may be required to make additional payments of principal to the extent
its outstanding borrowings exceed the borrowing base. To the extent that
additional payments are required, management believes these would be fulfilled
from available cash flows, and would not have a material adverse effect on the
Company's operating results, financial condition or liquidity.
On April 14, 1999, the Company issued a $4.7 million note payable to one its
suppliers, Veritas DGC Land, Inc. (the "Veritas Note Payable"), for the
outstanding balance due to Veritas for past services provided in 1998 and
1999. The balance due Veritas was $4.7 million at December 31, 1999, and has
been classified as long-term debt in the accompanying financial statements.
The principal obligation under the Veritas Note Payable is due on April 15,
2001. Management plans to fulfill the principal obligation under the Veritas
Note Payable from available cash flows, property sales and other financing
sources.
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 the Company's Common Stock in lieu of receiving cash payments for
the accrued interest obligations under the Veritas Note Payable. The Warrant
Agreement requires 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 to be issued must equal 9% of the then current outstanding principal
balance of the Veritas Note Payable. The number of shares to be 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 Payable. On October 14, 1999, the six-month
anniversary of the Warrant Agreement, warrants exercisable for another 322,752
shares of Common Stock were issued to Veritas.
The Company has the option, in lieu of issuing warrants, to make a cash
payment to Veritas at the 12 and 18 month anniversaries equivalent to 9% of
the then current principal balance of the Veritas Note Payable. The number of
shares to be issued on the 12 and 18 month anniversaries will be based upon a
five-day weighted average closing price of the Company's common stock at April
14, 2000. Under the terms of the Warrant Agreement, all warrants issued will
expire on April 15, 2002. In addition, the Company also entered into an
agreement with Veritas that (i) requires the Company to file a registration
statement with the SEC to register shares of Common Stock that are issuable
upon exercise of the above warrants and (ii) grants certain piggy-back
registration rights in connection with the warrants.
24
In connection with the closing of the AHC acquisition on February 9, 1998,
the Company has a non-interest bearing note payable to AHC (the "AHC Note
Payable") of $2.5 million (at December 31, 1999) which is payable on the
annual anniversary dates of the closing as follows: $1.0 million in 2000 and
$1.5 million in 2001. The Company has obtained a 60-day extension of the $1.0
million payment from February 2000 to April 2000.
At December 31, 1999, the Company had a working capital deficit of $0.7
million (excluding the current portion of long-term debt). Management plans to
meet these working capital requirements from available cash flows, property
sales and other financing sources.
The Company has budgeted capital expenditures of approximately an unrisked
$7.4 million for 2000. Capital expenditures will be used to fund drilling and
development activities, the shooting of a new 3-D seismic survey 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, 1999 were approximately $10.3 million. The Company intends to fund its
2000 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 2000, additional debt or
equity financing may be required during the remainder of 2000 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.
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
In 1997, the Company began using 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 hedged transactions occur. The Company expects that the amount of hedge
contracts that it has in place will vary from time to time.
The Company's hedging strategy is to maximize its return on investment
through hedging a portion of its activities relating to oil and natural gas
price volatility. While this strategy should help the Company reduce its
25
exposure to price risks, it also limits the Company's potential gains from
increases in market prices for natural gas. The Company intends to continue to
hedge up to 50% of its oil and natural gas production to retain a portion of
the potential for greater upside from increases in natural gas prices, while
limiting to some extent the Company's exposure to declines in natural gas
prices. For the year ended December 31, 1999, the Company had hedged 45% of
its oil and natural gas production, and as of December 31, 1999, the Company
had 0.9 Bcfe of open oil and natural gas contracts for the months of January
2000 through March 2000.
Interest Rate Hedge
The Company entered into an interest rate swap agreement, effective November
2, 1998, to exchange the variable rate interest payment obligation under the
Credit Facility without exchanging the underlying principal amount. This
agreement converts the variable rate debt to fixed rate debt to reduce the
impact of interest rate fluctuations. The notional amount is used to measure
interest to be paid or received and does not represent the exposure to credit
loss. The notional amount of the Company's interest rate swap was $25.0
million at December 31, 1998, and had a fair value of approximately $0.2
million. During March 1999, the Company terminated its interest rate swap
agreement and received $0.3 million, which is being recognized in earnings
ratably as the related outstanding loan balance is amortized.
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, 1999. 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.
Effects of Inflation and Changes in Price
Crude oil and natural gas commodity prices have been volatile and
unpredictable during 1998 and 1999, with crude oil prices falling below $10
per Bbl and rising close to $30 per Bbl, and natural gas prices dropping below
$1 per Mcf and then climbing up above $3 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
26
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.
Year 2000 Readiness Disclosure
The Company has completed its Year 2000 Readiness Plan ("Year 2000 Plan")
which focused on the Company's computer systems and any embedded computer
chips integrated into Company operated oil and gas production related
equipment. Implementation of the Year 2000 Plan included an assessment and
complete inventory of computer hardware/software systems plus oil and gas
production equipment. The Company identified, remediated and tested those
critical systems that were not year 2000 compliant to prevent any business
disruption.
The Company expensed the cost of software upgrades as incurred and utilized
Company personnel to execute the various phases of the Year 2000 Plan. The
total costs to implement the Year 2000 Plan was less than $10,000 and did not
have a material effect on the Company's financial position, liquidity or
results of operations.
The Company does not anticipate any year 2000 related matters to develop
subsequent to the 1999 year-end, but the Company will continue to monitor its
systems for any such developments.
New Accounting Standard
In 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133
establishes accounting and reporting standards requiring 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 is effective for fiscal years beginning after June 15, 2000.
The Company has not yet quantified the impacts of adopting SFAS No. 133 on its
financial statements and has not determined the timing of or method of its
adoption of SFAS No. 133. However, SFAS No. 133 could increase volatility in
earnings and other comprehensive income.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
The information required hereunder is included in "Management's Discussion
and Analysis of Financial Condition and Results of Operations--Risk Management
Activities and Derivative Transactions" in Item 7, which is incorporated by
reference in this Item 7A.
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.
27
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 26, 2000 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 26, 2000 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 26, 2000 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 26, 2000 is here incorporated by reference.
28
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.
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.
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.
29
Exhibit
No. Description
------- -----------
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.
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.
30
Exhibit
No. Description
------- -----------
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.
10.28 Third Amendment to Credit Agreement among Miller Oil Corporation and
Bank of Montreal dated October 29, 1999.
10.29 Form of Employment Agreement for Lew P. Murray dated February 9, 1998.
10.30 Form of Employment Agreement for Michael L. Calhoun dated February 9,
1998.
10.31 Form of Stock Option Agreement granted to Lew P. Murray dated January
1, 2000.
10.32 Fourth Amendment to Credit Agreement among Miller Oil Corporation and
Bank of Montreal dated March 20, 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.
27.1 Financial Data Schedule.
- --------
* Management contract or compensatory plan or arrangement.
Item 14(b). The Company filed no reports on Form 8-K during the last quarter of
1999.
31
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
POWER OF ATTORNEY
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 24, 2000
______________________________________
C. E. Miller
/s/ Kelly E. Miller Director (Principal Executive March 24, 2000
______________________________________ Officer)
Kelly E. Miller
/s/ Deanna L. Cannon (Principal Financial and March 24, 2000
______________________________________ Accounting Officer)
Deanna L. Cannon
/s/ Frank M. Burke, Jr.* Director March 24, 2000
______________________________________
Frank M. Burke, Jr.
/s/ Dan A. Hughes, Jr.* Director March 24, 2000
______________________________________
Dan A. Hughes, Jr.
/s/ William Casey McManemin* Director March 24, 2000
______________________________________
William Casey McManemin
/s/ Kenneth J. Foote* Director March 24, 2000
______________________________________
Kenneth J. Foote
/s/ Richard J. Burgess* Director March 24, 2000
______________________________________
Richard J. Burgess
/s/ Deanna L. Cannon Attorney-in-Fact
*By: _________________________________
Deanna L. Cannon
32
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, 1999 and 1998............ F-3
Consolidated Statements of Operations for the Years Ended December 31,
1999, 1998 and 1997.................................................... F-4
Consolidated Statements of Equity for the Years Ended December 31, 1999,
1998 and 1997.......................................................... F-5
Consolidated Statements of Cash Flows for the Years Ended December 31,
1999, 1998 and 1997.................................................... F-6
Notes to Consolidated Financial Statements.............................. F-7
Supplemental Quarterly Financial Data (unaudited)....................... F-25
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, 1999 and 1998, and the related consolidated statements of operations,
equity, and cash flows for each of the three years in the period ended
December 31, 1999. 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 generally accepted auditing
standards. 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, 1999 and 1998, and the results of their
operations and their cash flows for each of the three years in the period
ended December 31, 1999, in conformity with generally accepted accounting
principles.
/s/ Arthur Andersen LLP
Detroit, Michigan
March 24, 2000
F-2
MILLER EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands, except share amounts)
As of December
31,
------------------
1999 1998
-------- --------
(Note 1)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents................................ $ 3,712 $ 22
Restricted cash (Note 3)................................. 1,079 --
Accounts receivable...................................... 4,580 3,959
Inventories, prepaids and advances to operators.......... 640 978
-------- --------
Total current assets................................... 10,011 4,959
-------- --------
OIL AND GAS PROPERTIES--at cost (full cost method):
Proved oil and gas properties............................ 115,040 103,272
Unproved oil and gas properties.......................... 22,678 39,995
Less-Accumulated depreciation, depletion and
amortization............................................ (78,881) (63,253)
-------- --------
Net oil and gas properties............................. 58,837 80,014
-------- --------
OTHER ASSETS (Note 2)...................................... 838 995
-------- --------
Total assets........................................... $ 69,686 $ 85,968
======== ========
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Current portion of long-term debt........................ $ 3,500 $ 10,500
Accounts payable......................................... 3,472 6,819
Accrued expenses and other current liabilities........... 7,239 3,565
-------- --------
Total current liabilities.............................. 14,211 20,884
-------- --------
LONG-TERM DEBT............................................. 25,610 31,837
DEFERRED INCOME TAXES...................................... 5,816 6,883
DEFERRED REVENUE........................................... 54 1,615
COMMITMENTS AND CONTINGENCIES (Note 10)
EQUITY:
Common stock warrants.................................... 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; 12,681,244 shares outstanding at December
31, 1999................................................ 127 126
Additional paid in capital............................... 66,690 67,136
Deferred compensation.................................... (48) (876)
Retained deficit......................................... (43,619) (41,637)
-------- --------
Total equity........................................... 23,995 24,749
-------- --------
Total liabilities and equity........................... $ 69,686 $ 85,968
======== ========
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,
---------------------------
1999 1998 1997
------- -------- --------
(Note 1) (Note 1)
REVENUES:
Natural gas...................................... $17,266 $ 18,336 $ 5,819
Crude oil and condensate......................... 3,465 2,646 964
Other operating revenues......................... 558 829 629
------- -------- -------
Total operating revenues....................... 21,289 21,811 7,412
------- -------- -------
OPERATING EXPENSES:
Lease operating expenses and production taxes.... 1,704 3,363 1,478
Depreciation, depletion and amortization......... 16,066 15,933 2,520
General and administrative....................... 3,134 3,475 2,186
Cost ceiling writedown........................... -- 35,085 --
------- -------- -------
Total operating expenses....................... 20,904 57,856 6,184
------- -------- -------
OPERATING INCOME (LOSS)............................ 385 (36,045) 1,228
------- -------- -------
INTEREST EXPENSE................................... (3,519) (1,635) (1,200)
------- -------- -------
INCOME (LOSS) BEFORE INCOME TAXES.................. (3,134) (37,680) 28
------- -------- -------
INCOME TAX PROVISION (CREDIT) (Note 4)............. (1,152) 4,120
------- --------
NET INCOME (LOSS).................................. $(1,982) $(41,800) $ 28
======= ======== =======
EARNINGS (LOSS) PER SHARE (Note 5)
Basic............................................ $ (0.16) $ (3.75)
======= ========
Diluted.......................................... $ (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,
1996................... $-- $ -- $-- $ -- $ -- $ 72 $ 7,697
Contributions and
return of capital,
net.................. -- -- -- -- -- 8,516 --
Net income............ -- -- -- -- -- -- 28
Dividends declared.... -- -- -- -- -- -- (200)
---- ----- ---- ------- ----- ------ --------
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)
==== ===== ==== ======= ===== ====== ========
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,
----------------------------
1999 1998 1997
-------- -------- --------
(Note 1) (Note 1)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)................................ $ (1,982) $(41,800) $ 28
Adjustments to reconcile net income (loss) to net
cash from operating activities--
Depreciation, depletion and amortization....... 16,066 15,933 2,520
Cost ceiling writedown......................... -- 35,085 --
Deferred income taxes.......................... (1,067) (1,052) --
Deferred revenue............................... (34) (49) (58)
Changes in assets and liabilities--
Restricted cash.............................. (1,079) -- --
Accounts receivable.......................... (621) (1,850) 137
Other current assets......................... -- 2,952 (3,432)
Other assets................................. 48 (118) --
Accounts payable............................. (3,347) 6,786 2,761
Accrued expenses and other current
liabilities................................. 3,674 2,962 34
-------- -------- -------
Net cash flows provided by operating
activities................................ 11,658 18,849 1,990
-------- -------- -------
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development expenditures......... (10,265) (46,950) (8,822)
Acquisition of properties........................ -- (51,011) --
Proceeds from sale of oil and gas properties and
purchases of equipment, net..................... 14,296 3,065 2,955
-------- -------- -------
Net cash flows provided by (used in)
investing activities...................... 4,031 (94,896) (5,867)
-------- -------- -------
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments of principal............................ (15,717) (5,178) (572)
Borrowing on long-term debt...................... 2,490 35,500 3,512
Contributions, return of capital and stock
proceeds, net................................... 1,228 45,601 873
Payments of dividends............................ -- -- (200)
-------- -------- -------
Net cash flows provided by (used in)
financing activities...................... (11,999) 75,923 3,613
-------- -------- -------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS....................................... 3,690 (124) (264)
CASH AND CASH EQUIVALENTS AT BEGINNING OF THE
PERIOD............................................ 22 146 410
-------- -------- -------
CASH AND CASH EQUIVALENTS AT END OF THE PERIOD..... $ 3,712 $ 22 $ 146
======== ======== =======
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid during the period for--
Interest......................................... $ 3,033 $ 1,571 $ 1,373
======== ======== =======
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. The financial
statements for the period ending in 1997 include the accounts of the Company
and its affiliated entities (as defined above) before 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). The financial statements for the period ending
in 1997 do not include the activities of these non-affiliated interests.
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. The financial
statements for the period ending in 1997 do not include the activities of
these AHC interests.
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.
F-7
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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.
Principles of Combination
The accompanying financial statements for the period ending in 1997 include
the accounts of Miller, MOC and the other affiliated entities (as defined
above), all of which share common ownership and management. 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. Accordingly, the accompanying accounts for the
period ending in 1997 have been prepared using the historical costs and
results of operations of the affiliated entities. There were no differences in
accounting methods or their application among the combining entities. All
intercompany balances have been eliminated.
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 and the Blackfeet Indian
Reservation of the southern Alberta Basin in Montana.
(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, 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, the Company has determined that a writedown is 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. The Company did not have any such charges against earnings during the
year ended December 31, 1997.
F-8
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Property and Equipment
Property and equipment is included in other assets in the accompanying
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, which typically range from five to 20 years.
Revenue Recognition
Crude oil and natural gas revenues are recognized as production takes place
and the sale is completed and the risk of loss transfers to a third party
purchaser.
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 1999 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.
Other
For significant accounting policies regarding income taxes, see Note 4; for
earnings per share, see Note 5; for financial instruments, see Note 8; for
risk management activities and derivative transactions, see Note 9; and for
stock-based compensation, see Note 11.
(3) Restricted Cash
In 1999, the Company entered into escrow agreements at the request of
certain joint venture 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.
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. Accordingly, no provision was made
for income taxes in the accompanying financial statements for the period
ending in 1997.
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, 1999 and 1998, was different than
the statutory federal income tax rate for the following reasons (in
thousands):
1999 1998
------- --------
Net loss................................................ $(1,982) $(41,800)
Add back:
Income tax provision (credit)......................... (1,152) 4,120
------- --------
Pre-tax loss............................................ (3,134) (37,680)
Income tax provision (credit) at the federal statutory
rate................................................... (1,066) (12,811)
Deferred tax liabilities recorded upon the Offering..... -- 5,392
Valuation allowance..................................... -- 11,700
All other, net.......................................... (86) (161)
------- --------
Income tax provision (credit)........................... $(1,152) $ 4,120
======= ========
The components of the provision of income taxes for the year ended December
31, 1999 and 1998 are as follows (in thousands):
1999 1998
------- ------
Currently payable........................................... $ -- $ --
Deferred to future periods.................................. (1,152) 4,120
------- ------
Total income taxes.......................................... $(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, 1999 and 1998 are as
follows (in thousands):
1999 1998
-------- --------
Deferred tax liabilities:
Unsuccessful well and lease costs.................... $ (3,075) $ (3,655)
Intangible drilling costs............................ (3,905) (3,923)
Financial statement carrying value in excess of tax
basis of purchased assets........................... (1,268) (1,503)
Other................................................ (568) (807)
Deferred tax assets:
Net operating loss carryforward...................... 14,700 14,705
-------- --------
Net deferred tax assets................................ 5,884 4,817
Less: Valuation allowance.............................. (11,700) (11,700)
-------- --------
Net deferred tax liability............................. $ (5,816) $ (6,883)
======== ========
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, 1999, the Company had regular
tax net operating loss carryforwards of approximately $3.0 million. This loss
carryforward amount will expire during 2012. The Company also had a percentage
depletion carryforward of approximately $0.9 million at December 31, 1999,
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.
Earnings per share has been omitted from the statement of operations for the
year ended December 31, 1997, since such information is not meaningful and the
historically combined Company (prior to the Combination Transaction) was not a
separate legal entity with a singular capital structure. The computation of
earnings per share for the year ended December 31, 1999 and 1998 is as follows
(in thousands, except per share data):
1999 1998
------- --------
Net loss attributable to basic and diluted EPS.......... $(1,982) $(41,800)
Average common shares outstanding applicable to basic
EPS.................................................... 12,633 11,153
Add: options treasury shares and restricted stock -- --
------- --------
Average common shares outstanding applicable to diluted
EPS.................................................... 12,633 11,153
Earnings (loss) per share:
Basic................................................. $ (0.16) $ (3.75)
------- --------
Diluted............................................... $ (0.16) $ (3.75)
------- --------
Options and restricted stock were not included in the computation of diluted
earnings per share for the years ended December 31, 1999 and 1998 because
their effect was antidilutive.
F-11
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(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.
During 1995 and 1996, the Company also received advance cash payments from
MSLP of approximately $1.6 million. These proceeds were recorded as deferred
revenue, and were recognized in income as the natural gas volumes under the
agreement are delivered.
In June 1999, the Company sold its interest in the Antrim Shale properties
located in Michigan, which includes 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). The remaining
deferred revenue discussed above has been credited to the Company's
capitalized cost pool.
(7) Long-Term Debt
The Company has entered into a credit facility (the "Credit Facility") with
Bank of Montreal, Houston Agency ("BMO"). The Credit Facility includes certain
negative covenants that impose limitations on the Company and its subsidiary
with respect to, among other things, distributions with respect to its capital
stock, limitations on financial ratios, the creation or incurrence of liens,
the incurrence of additional indebtedness, making loans and investments and
mergers and consolidations. The obligations of the Company under the Credit
Facility are secured by a lien on all real and personal property of the
Company. At December 31, 1999, $21.9 million was outstanding under the Credit
Facility.
On April 14, 1999, the Company and BMO entered into the Second Amendment to
the Credit Facility. The Second Amendment stipulated, among other things, that
the Company would submit a revised reserve report to BMO by October 1, 1999
for a re-determination of the borrowing base and pay a $300,000 re-
determination fee.
On October 29, 1999, the re-determination fee was paid, and the Company and
BMO entered into the Third Amendment to the Credit Facility which included:
(i) terms requiring the Company to make principal payments to BMO during the
period beginning with October 1999 through February 2000, (ii) terms requiring
that all outstanding borrowings bear interest at BMO's prime rate plus 3.5%;
(iii) revision or waiver of certain negative covenant provisions through
September 30, 2000; (iv) a requirement to submit a revised reserve report to
BMO by April 1, 2000 for a re-determination of the borrowing base; (v) a
requirement that all proceeds from the sales of proved or unproved oil and gas
properties, prior to the re-determination date, must be used to reduce the
principal amount outstanding under the Credit Facility; and (vi) a requirement
for an amendment fee payable to BMO in an amount equal to 2% of the
outstanding balance of the Credit Facility at the April re-determination date.
Final maturity of the Credit Facility was set at January 1, 2001. Total
principal payments of $5.1 million were made under the Third Amendment with
the remaining $1.9 million waived through letter agreements subsequent to
December 31, 1999.
On March 20, 2000, the Company entered into a Fourth Amendment with BMO
which continued all of the provisions of the Third Amendment with the
exception of the following changes: i) extension of the final maturity date of
the Credit Facility to April 1, 2001; and ii) requirement of a $1.0 million
principal payment by March 31, 2000. At the April re-determination date, the
Company may be required to make additional payments
F-12
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
of principal to the extent its outstanding borrowings exceed the borrowing
base. To the extent that additional payments are required, management believes
these would be fulfilled from available cash flows, and would not have a
material adverse effect on the Company's operating results, financial
condition or liquidity.
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 Payable"), for the
outstanding balance due to Veritas for past services provided in 1998 and
1999. The balance due Veritas was $4.7 million at December 31, 1999, and has
been classified as long-term debt in the accompanying financial statements.
The principal obligation under the Veritas Note Payable is due on April 15,
2001. Management plans to fulfill the principal obligation under the Veritas
Note Payable from available cash flows, property sales and other financing
sources.
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 the Company's Common Stock in lieu of receiving cash payments for
the accrued interest obligations under the Veritas Note Payable. The Warrant
Agreement requires 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 to be issued must equal 9% of the then current outstanding principal
balance of the Veritas Note Payable. The number of shares to be issued upon
exercise of the warrants issued on April 14, 1999 and on the six-month
anniversary is 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 Payable. On October 14, 1999, the six-month
anniversary of the Warrant Agreement, warrants exercisable for another 322,752
shares of Common Stock were issued to Veritas.
The Company has the option, in lieu of issuing warrants, to make a cash
payment to Veritas at the 12 and 18 month anniversaries equivalent to 9% of
the then current principal balance of the Veritas Note Payable. The number of
shares to be issued on the 12 and 18 month anniversaries will be based upon
the five-day weighted average closing price of the Company's common stock at
April 14, 2000. Under the terms of the Warrant Agreement, all warrants issued
will expire on April 15, 2002. In addition, the Company also entered into an
agreement with Veritas that (i) requires the Company to file a registration
statement with the SEC to register shares of Common Stock that are issuable
upon exercise of the above warrants and (ii) grants certain piggy-back
registration rights in connection with the warrants.
In connection with the closing of the AHC acquisition on February 9, 1998,
the Company has a non-interest bearing note payable to AHC (the "AHC Note
Payable") of $2.5 million (at December 31, 1999) which is payable on the
annual anniversary dates of the closing as follows: $1.0 million in 2000 and
$1.5 million in 2001. The Company has obtained a 60-day extension of the $1.0
million payment from February 2000 to April 2000.
The Company's long-term debt consisted of the following as of December 31,
1999 and 1998 (in thousands):
1999 1998
-------- -------
BMO Credit Facility....................................... $ 21,914 $35,500
Veritas Note Payable...................................... 4,696 3,837
AHC Note Payable.......................................... 2,500 3,000
-------- -------
Total................................................... 29,110 42,337
Less current portion of long-term debt.................... (3,500) (10,500)
-------- -------
$(25,610) $31,837
======== =======
F-13
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The Company's minimum principal requirements as of December 31, 1999 are as
follows (in thousands):
2000................................. $ 3,500
2001................................. 25,610
-------
$29,110
=======
(8) Financial Instruments
The following methods and assumptions were used to estimate the fair value
of each significant class of financial instruments:
Cash, Restricted Cash, Temporary Cash Investments, Accounts Receivables,
Accounts Payable and Notes Payable
The carrying amount approximates fair value because of the short maturity of
those instruments.
Long-Term Debt
The interest rate on the Credit Facility is reset as BMO'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 9 for a description of the Company's price hedging
arrangements and the fair values of the arrangements.
(9) 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
In 1997, the Company began using 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 hedged 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, 1999, 1998 and 1997, the Company hedged 45%, 36% and 1% of
its oil and gas production, respectively, and as of December 31, 1999, the
Company had 0.9 Bcfe of open oil and natural gas contracts for the months of
January 2000 through March, 2000.
F-14
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Interest Rate Hedge
The Company entered into an interest rate swap agreement, effective November
2, 1998, to exchange the variable rate interest payment obligation under the
Credit Facility without exchanging the underlying principal amount. This
agreement converts the variable rate debt to fixed rate debt to reduce the
impact of interest rate fluctuations. The notional amount is used to measure
interest to be paid or received and does not represent the exposure to credit
loss. The notional amount of the Company's interest rate swap was $25.0
million at December 31, 1998, and had a fair value of approximately $0.2
million. During March 1999, the Company terminated its interest rate swap
agreement and received $0.3 million, which is being recognized in earnings
ratably as the related outstanding loan balance is amortized.
(10) 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 1996 and contains
an annual 4% escalation clause. 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.
Future minimum lease payments required of the Company for years ending
December 31, are as follows (in thousands):
2000.................................... $259
2001.................................... 213
2002.................................... 147
2003.................................... 32
2004.................................... --
Thereafter.............................. --
----
$651
====
Total net rent expense under these lease arrangements was $255,078, $198,547
and $103,464 for the years ended December 31, 1999, 1998 and 1997,
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 $189,421, $66,359, and $64,348 for the years ended
December 31, 1999, 1998 and 1997, 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
F-15
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
working interests, fees, reimbursements and other financial items. These
payments to the employees, which were charged against operations, totaled
$54,611 and $134,916 for the years ended December 31, 1998 and 1997,
respectively. 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.
The Company has been named in 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 is claiming
damages of $1.0 million for personal injuries allegedly suffered at a well
site operated by the Company.
The Company has been named 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 alleges that the accident was the
result of mud dragged on the road from the leased property and alleges that
the Company was negligent in its duty to conduct its operations at the site
with reasonable care.
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 the lawsuits mentioned above would be
covered by the Company's insurance.
(11) Stock-Based Compensation
During 1997, the Company adopted the Stock Option and Restricted Stock Plan
of 1997 (the "1997 Plan"). The Board of Directors contemplates that the 1997
Plan primarily will be 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 1.2 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. During 1999 and
1998, incentive stock options of 25,000 and 54,600, respectively, were issued
to outside directors and new employees under the 1997 Plan.
F-16
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Since the above stock options have been granted at market price, no
compensation cost has been recognized for stock options granted under the 1997
Plan. The restricted stock vests at cumulative increments of one-half of the
total number of restricted stock of Common Stock subject thereto, beginning on
the first anniversary of the date of grant. Because the shares of restricted
stock are subject to the risk of forfeiture during the vesting period,
compensation expense is recognized over the two-year vesting period as the
risk of forfeiture passes. In February 1999, 54,750 shares of restricted stock
vested, and the Company recognized compensation expense of approximately $0.2
million, accordingly.
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 average of the
stock on the market remains above the designated values for a period of five
consecutive trading days as follows:
Percentage
Five-Day Daily Average Target Vested
----------------------------- ----------
$2.00........................................................... 40%
$2.75........................................................... 30%
$3.50........................................................... 30%
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 Number Average
of Shares of Shares Grant Price
---------- --------- -----------
Outstanding at January 1, 1998............. -- -- --
Granted.................................. 109,500 904,950 $8.08
Exercised................................ -- -- --
Forfeited................................ -- (500) 8.00
Outstanding at December 31, 1998........... 109,500 904,450 $8.08
Granted.................................. -- 25,000 3.11
Exercised................................ (54,750) -- --
Forfeited................................ (11,250) (167,700) 8.19
------- -------- -----
Outstanding at December 31, 1999........... 43,500 761,750 $7.89
======= ======== =====
The average fair value of shares granted during 1999 and 1998 was $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 1999 1998
---------- -------- --------
Dividend Yield............................................. 0% 0%
Risk-free interest rate.................................... 6.5% 5.5%
Expected Life.............................................. 10 years 10 years
Expected volatility........................................ 25.5% 25.7%
F-17
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The following table summarizes certain information for the options
outstanding at December 31, 1999:
Options
Options Outstanding Exercisable
-------------------------- ----------------
Weighted Weighted Weighted
Average Average Average
Range of Remaining Grant Grant
Grant Prices Shares Life Price Shares Price
------------ ------- --------- -------- ------- --------
$2.19 to $10.13.................. 761,750 9 years $7.89 147,350 $8.05
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
----------------- -----------------
1999 1998 1999 1998
------- -------- ------- --------
Net loss............................. $(1,982) $(41,800) $(2,384) $(42,229)
Earnings (loss) per share of Common
Stock
Basic.............................. $ (0.16) $ (3.75) $ (0.19) $ (3.79)
Diluted............................ $ (0.16) $ (3.75) $ (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.
(12) Related Party Transactions
In July 1996, the Company sold the building it occupies to a related party
and subsequently leased a substantial portion of the building under the terms
of a five-year lease agreement (see Note 10). 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 a corporation controlled by a related party. In connection with this
arrangement, $66,667, $200,000 and $200,000 were recognized as management fee
income (see Note 15) for the years ended December 31, 1999, 1998 and 1997,
respectively.
A certain stockholder and director of the Company has controlling interest
in a corporation that is the operator of jointly owned properties. Payments to
this operator for the Company's proportionate share of leasehold, seismic,
drilling and operating expenses amounted to $794,319 (net of $1,126,321 in
control of well insurance reimbursements), $7,370,718, and $2,038,938 in 1999,
1998 and 1997, respectively. This operator also paid the Company crude oil and
natural gas revenues as disclosed in Note 16.
A certain stockholder and director of the Company is a principal in an
organization that provides consulting services to the Company. Consulting fees
paid to this organization amounted to $30,738 for 1997. There were no
consulting fees paid to this organization in 1999 or 1998.
During 1999, an affiliated entity 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.
F-18
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(13) Concentrations of Risk
The Company extends credit to various companies in the oil and gas industry
in the normal course of business. Within this industry, certain concentrations
of credit risk exist. The Company, in its role as operator of co-owned
properties, assumes responsibility for payment to vendors for goods and
services related to joint operations and extends credit to co-owners of these
properties.
This concentration of credit risk may be similarly affected by changes in
economic or other conditions and may, accordingly, impact the Company's
overall credit risk. The Company periodically monitors its customers' and co-
owners' financial conditions.
The Company also has a significant concentration of properties in the
Mississippi Salt Basin, which are affected by changes in economic and other
conditions, including but not limited to crude oil and natural gas prices and
operating costs.
(14) Non-Cash Activities
During 1999, the Company issued 38,479 shares (with a value of $89,000 at
the date of issue) of common stock as compensation for 1998 director fees, as
provided for under the Equity Compensation Plan for Non-employee Directors;
and 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. During 1997, the stockholders contributed approximately
$7.6 million of notes payable to MOC as capital.
(15) 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.
(16) 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,
--------------
1999 1998 1997
---- ---- ----
Carthage Energy Services Inc.................................. 73% 50% --%
EOTT.......................................................... 16% 9% --%
Muskegon Development Co....................................... 3% 7% 27%
Dan A. Hughes Company......................................... 2% 21% 30%
Amerada Hess Corporation...................................... 2% 12% 39%
F-19
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(17) 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, 1999, 1998 and 1997 have been prepared by Miller and Lents, Ltd.
(as to non-Michigan Antrim Shale reserves) and as of December 31, 1998 and
1997 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-20
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, 1999, and the changes in the net proved reserves for each of the
three years in the period then ended as estimated by petroleum engineers for
the respective periods as described in the preceding paragraph:
Total
---------------------
Oil (MBbl) Gas (Mmcf)
---------- ----------
Estimated Proved Reserves
December 31, 1995..................................... 135.0 15,762.2
Extensions and discoveries........................... 514.9 553.7
Purchase of reserves................................. -- 1,016.1
Revisions and other changes.......................... 40.3 2,054.0
Production........................................... (46.5) (2,030.0)
------ --------
December 31, 1996..................................... 643.7 17,356.0
Extensions and discoveries........................... 10.6 3,629.8
Revisions and other changes.......................... 161.6 (1,129.5)
Production........................................... (47.4) (2,241.2)
------ --------
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
====== ========
Estimated Proved Developed Reserves
December 31, 1996.................................... 121.0 15,221.2
====== ========
December 31, 1997.................................... 130.2 13,964.4
====== ========
December 31, 1998.................................... 991.7 28,641.6
====== ========
December 31, 1999.................................... 460.1 14,944.5
====== ========
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-21
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The future cash flows presented below are based on sales prices and cost
rates in existence as of the date of the projections. 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, 1999, 1998 and 1997:
1999 1998 1997
------- -------- --------
(In thousands)
Future revenues(1)............................ $42,556 $ 66,975 $ 54,896
Future production costs(2).................... (7,237) (20,930) (19,091)
Future development costs(2)................... (402) (1,532) (5,300)
------- -------- --------
Future net cash flows......................... 34,917 44,513 30,505
Discount to present value at 10% annual rate.. (6,197) (8,088) (10,571)
------- -------- --------
Present value of future net revenues before
income taxes................................. 28,720 36,425 19,934
Future income taxes discounted at 10% annual
rate(3)...................................... -- -- --
------- -------- --------
Standardized measure of discounted future net
cash flows................................... $28,720 $ 36,425 $ 19,934
======= ======== ========
- --------
(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. Does not
include income taxes for 1997 as the Company was not subject to federal
income taxes until consummation of the Offering in February 1998.
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, 1999, 1998 and 1997:
1999 1998 1997
-------- -------- --------
(In thousands)
New discoveries............................... $ 3,213 $ 9,962 $ 4,059
Purchase of reserves.......................... -- 55,803 --
Sales of reserves in place.................... (7,003) (167) --
Revisions to reserves......................... 3,262 (18,635) 350
Sales, net of production costs................ (19,027) (17,619) (5,305)
Changes in prices............................. 16,571 (11,776) (22,280)
Accretion of discount......................... 3,643 1,993 3,006
Changes in timing of production and other..... (8,364) (3,070) 10,039
-------- -------- --------
Net change during the year.................... $ (7,705) $ 16,491 $(10,131)
======== ======== ========
F-22
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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, 1999
and 1998:
1999 1998
-------- --------
(In thousands)
Proved properties...................................... $115,040 $103,272
Unproved properties.................................... 22,678 39,995
-------- --------
137,718 143,267
Less--Accumulated depreciation, depletion and
amortization.......................................... (78,881) (63,253)
-------- --------
$ 58,837 $ 80,014
======== ========
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.
The following table sets forth costs incurred related to the Company's oil
and gas activities for the years ended December 31:
1999 1998 1997
------- -------- ------
(In thousands)
Property acquisition costs(1)....................... $ 1,818 $ 60,974 $4,577
Exploration costs................................... 2,572 32,142 2,226
Development costs................................... 5,875 17,615 2,019
------- -------- ------
Total(2).......................................... $10,265 $110,731 $8,822
======= ======== ======
- --------
(1) Includes $19,556 in 1998 and $757 in 1996 for the acquisition of proved
producing properties.
(2) Includes $12,770 in 1998 of non-cash acquisitions of proved producing and
unproved properties in connection with the Combination Transaction as more
fully described in Note 1.
F-23
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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, 1999, 1998 and
1997. The results of operations below do not include general and
administrative expenses, income taxes and interest expense.
1999 1998 1997
------- -------- ------
(In thousands)
Operating Revenues:
Natural gas...................................... $17,266 $ 18,336 $5,819
Crude oil and condensate......................... 3,465 2,646 964
------- -------- ------
Total operating revenues....................... 20,731 20,982 6,783
------- -------- ------
Operating expenses:
Lease operating expenses and production taxes.... $ 1,704 $ 3,363 $1,478
Depreciation, depletion and amortization......... 16,066 15,933 2,520
Cost ceiling writedown........................... -- 35,085 --
------- -------- ------
Total operating expenses....................... 17,770 54,381 3,998
------- -------- ------
Results of operations.............................. $ 2,961 $(33,399) $2,785
======= ======== ======
F-24
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)
1999
Total Operating Revenues................... $ 4,980 $4,960 $5,545 $ 5,804
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................... $ 4,236 $5,727 $5,858 $ 5,990
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)
1997
Total Operating Revenues................... $ 2,308 $1,538 $1,685 $ 1,881
Operating Income (Loss).................... 903 115 242 (32)
Net Income (Loss).......................... 721 (93) (290) (310)
F-25
EXHIBIT INDEX
Exhibit
No. Description
------- -----------
2.1 Exchange and Combination Agreement dated November 12, 1997. Previously
filed as exhibit 2.1 to the Company's Registration Statement on Form
S-1 (333-40383), and here incorporated by reference.
2.2(a) Letter Agreement amending Exchange and Combination Agreement.
Previously filed as an exhibit to the Company's Registration Statement
on Form S-1 (333-40383), and here incorporated by reference.
2.2(b) Letter Agreement amending Exchange and Combination Agreement.
Previously filed as an exhibit to the Company's Registration Statement
on Form S-1 (333-40383), and here incorporated by reference.
2.2(c) Letter Agreement amending Exchange and Combination Agreement.
Previously filed as an exhibit to the Company's Registration Statement
on Form S-1 (333-40383), and here incorporated by reference.
2.3(a) Agreement for Purchase and Sale dated November 25, 1997 between
Amerada Hess Corporation and Miller Oil Corporation. Previously filed
as an exhibit to the Company's Registration Statement on Form S-1
(333-40383), and here incorporated by reference.
2.3(b) First Amendment to Agreement for Purchase and Sale dated January 7,
1998. Previously filed as an exhibit to the Company's Registration
Statement on Form S-1 (333-40383), and here incorporated by reference.
3.1 Certificate of Incorporation of the Registrant. Previously filed as an
exhibit to the Company's Registration Statement on Form S-1 (333-
40383), and here incorporated by reference.
3.2 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.
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.
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.
Exhibit
No. Description
------- -----------
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.
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.
Exhibit
No. Description
------- -----------
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.
10.28 Third Amendment to Credit Agreement between Miller Oil Corporation and
Bank of Montreal dated October 29, 1999.
10.29 Form of Employment Agreement for Lew P. Murray dated February 9, 1998.
10.30 Form of Employment Agreement for Michael L. Calhoun dated February 9,
1998.
10.31 Form of Stock Option Agreement granted to Lew P. Murray dated January
1, 2000.
10.32 Fourth Amendment to Credit Agreement among Miller Oil Corporation and
Bank of Montreal dated March 20, 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.
27.1 Financial Data Schedule.
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* Management contract or compensatory plan or arrangement.