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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
___________________
FORM 10-K
FOR ANNUAL AND TRANSITION REPORTS PURSUANT TO
SECTIONS 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1997
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from ____________________ to
____________________
Commission File Number: 0-23431
MILLER EXPLORATION COMPANY
(Exact Name of Registrant as Specified in Its Charter)
DELAWARE 38-3379776
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification No.)
3104 LOGAN VALLEY ROAD, TRAVERSE CITY, MICHIGAN 49685-0348
(Address of Principal Executive Offices) (Zip Code)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (616) 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 30, 1998: 12,492,597.
The aggregate market value of the registrant's voting stock held by
non-affiliates of the registrant as of March 30, 1998: $128,049,119.
DOCUMENTS INCORPORATED BY REFERENCE
No documents are incorporated by reference.
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PART I
ITEM 1. BUSINESS.
Miller Exploration Company ("Miller" or the "Company") is an
independent oil and gas exploration and production company with established
exploration efforts concentrated primarily in three regions: the
Mississippi Salt Basin, the onshore Gulf Coast region of Texas and
Louisiana and the Michigan Basin. Miller emphasizes the use of 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. Unless otherwise
indicated, references herein to the "Company" or "Miller" are to Miller
Exploration Company, a Delaware corporation, and its subsidiaries and
predecessors, and give pro forma effect to the Combination Transaction
(defined below). Certain terms related to the oil and gas industry
are defined in "Glossary of Certain Oil and Gas Terms" below.
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 an estimated $50.5 million 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.
In this filing, reference to historical combined financial information
of the Company means the historical combined results of the Company and the
Affiliated Entities. Reference to pro forma financial information of the
Company means the historical combined information, plus the contribution or
acquisition of the Combined Assets from the non-affiliated participants in
the Combination Transaction.
The Combination Transaction closed on February 9, 1998 in connection
with the closing of the Company's initial public offering of 5,500,000
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.
The Company has budgeted a significant increase in drilling activity
and plans to drill 42 wells (19.4 net to the Company) in 1998, 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 $44.3 million for
1998. Miller incurred expenditures for exploration and development activity of
$27.0 million with respect to the Company's interest in 31 gross wells (6.6
net to the Company) for the year ended December 31, 1997 and $21.1 million
with respect to the Company's interest in 25 gross wells (8.8 net to the
Company) for the year ended December 31, 1996. Estimated proved reserves
attributable to the Combined Assets have increased 189%, from 19.9 Bcfe as
of January 1, 1994 to 57.6 Bcfe as of December 31, 1997.
The Company's primary exploration effort currently is focused on the
Mississippi Salt Basin, which contains one of the largest onshore
concentrations of salt domes in North America. The Company owns interests
in approximately 68,000 gross leasehold acres (44,000 net to the Company)
in the Mississippi Salt Basin in prospective areas around 22 salt domes and
related salt structures, which the Company believes is one of the largest
strategic lease positions around the salt domes in the basin. Due to
innovations over the last few years, seismic technology now enables
geoscientists to generate improved imaging of the flanks of salt structures and
associated faulting, the primary hydrocarbon trapping mechanisms in this area.
The Company commenced its exploration activities in Mississippi in 1993 and has
participated in the drilling of 21 wells, 11 of which (52%) have been completed,
establishing commercial production around six salt domes. At December 31, 1997,
the Company also was in the process of drilling and/or completing five gross
(2.9 to the Company) wells. As of December 31, 1997, these wells had produced
33.6 Bcfe gross (21.8 Bcfe net to the Company) and had stablished estimated
gross proved reserves of 92.3 Bcfe (41.1 Bcfe net to the Company). In the
Mississippi Salt Basin, the Company has used technologically advanced seismic
data processing methods to reinterpret existing regional 2-D seismic data and
analyze and interpret newly acquired 2-D seismic data. In addition, the Company
currently is participating in multiple 3-D seismic acquisition projects in this
region, which the Company believes will improve the identification of potential
hydrocarbon traps.
The Company's prospects in the Gulf Coast region of Texas and
Louisiana also lend themselves to 3-D seismic-aided exploration due to the
geological complexity prevalent in this region. Since 1994, the Company
has participated in approximately 300 square miles of 3-D seismic surveys
and the drilling of 54 gross wells within the boundaries of these surveys.
Twenty-eight of the wells drilled have been completed as commercially
productive. As of December 31, 1997, the Company had 21 3-D supported wells
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with established estimated gross proved reserves of 35.1 Bcfe (5.8 Bcfe
net to the Company). The Company expects to participate in nine gross
wells (2.3 net to the Company) in this area in 1998, all of which are
supported by 3-D seismic data.
The Company's current operations in Michigan were developed after
1988, when the Company sold all of its producing properties to Conoco, Inc.
In the Michigan Basin, the Company has an interest in over 300 producing
wells within a leasehold position that is the result of prior successful
exploration efforts in the Niagaran Reef Trend. Miller's current Michigan
Basin production is predominantly long-lived, lower volume Antrim Shale
production, as compared to the higher volume wells of the onshore Gulf
Coast and Mississippi Salt Basin. The Company is continuing to pursue
additional exploration opportunities in the Michigan Basin.
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. 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 leasehold interests in 68,000 gross acres (44,000 net to the
Company) covering 22 known salt domes and related salt structures. The
Company's working interest partner in this basin is Key Production Company,
Inc. ("Key").
Salt domes are geologic structures formed by the upward thrusting of
subsurface salt accumulations towards the surface. Such structures
generally are found in groups in geologic basins that provided the
necessary conditions for their formation. Salt domes are typically
subsurface structures that easily are 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. The development
of the salt domes resulted in the formation of oil and gas traps. 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.
-3-
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 breeched 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, comprising an approximate 87.5%
working interest in the aggregate. 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 drillsites along the flanks of the salt domes. Based on the positive
results of the first several prospects drilled, MOC acquired leasehold
interests around 13 additional salt domes that it considered to be
prospective.
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 of the
salt dome or were too far off structure to encounter the anticipated
hydrocarbon trap. The Company currently believes that 3-D seismic imaging
will allow it to more effectively image such traps and better define the
size and location of its drilling targets. The Company believes that 3-D
seismic imaging will improve its ability to resolve and interpret such complex
geologic structures based on its effective use on similar onshore salt
domes in Texas and Louisiana, as well as offshore salt domes in the Gulf of
Mexico. The Company intends to utilize its reprocessed 2-D seismic
database to more effectively manage its 3-D seismic acquisition program.
The Company currently is acquiring or making arrangements to acquire
approximately 140 square miles of proprietary 3-D seismic data over and
around three of its salt dome prospects. Additionally, the Company is
participating in a 270 square mile multi-party 3-D seismic survey, a
portion of which will cover prospective acreage around four of the
Company's salt dome prospects.
The Company owns an interest in eight producing wells in the
Mississippi Salt Basin that had aggregate average production as of December
31, 1997 of 31.7 MMcfe/d gross (20.2 MMcfe/d net to the Company) at depths
-4-
ranging from 14,500 to 17,300 feet. Since the Company began its
exploration activity in Mississippi in 1993, it has participated in 21
wells drilled around six salt dome structures, 11 of which (52%)
established commercial production. At December 31, 1997, the Company also
was in the process of drilling and/or completing five (2.9 net to the Company
wells. The Company has 25 gross wells (14.1 net wells) budgeted in 1998 for the
Mississippi Salt Basin with a capital expenditure budget of $36.3 million,
including $9.3 million for the acquisition of 3-D seismic around seven salt
domes in 1998. This will provide 3-D seismic data on 11 of 25 Mississippi Salt
Basin wells budgeted for 1998. As of December 31, 1997, the Company's
Mississippi Salt Basin wells had produced 33.6 Bcfe gross (21.8 Bcfe net to the
Company) and had established 92.3 Bcfe gross (41.1 Bcfe net to the Company) of
estimated proved reserves.
ONSHORE GULF COAST OF TEXAS AND LOUISIANA
The Company believes that the onshore Gulf Coast area of Texas and
Louisiana is a high potential, multi-pay region that lends itself to 3-D
seismic-supported exploration due to its substantial structural and
stratigraphic complexity. The Company's current and anticipated 1998
drilling activities are expected to be as an active working interest
partner in select projects proposed by Dan A. Hughes Company (the "Hughes
Company") in Zapata, Webb, Duval, Karnes and McMullen Counties, Texas and
Cameron and Terrebonne Parishes, Louisiana, under an exploration agreement
to which the Company has been a party since 1994. Before accepting a
proposed prospect under the agreement, the Company undertakes a thorough
evaluation, considering geographic location, scale, geological and
geophysical model, anticipated drilling prospects, number of pay zones,
trend potential, expected project economics and access to market. The
Company incorporates its digital database, including geophysical,
geological and production data, and the opinions of regional geologists and
geophysicists in its participation decisions. Except within areas of
mutual interest ("AMI") formed around prospects offered under the
exploration agreement with the Hughes Company, the Company is free to
acquire leases, develop its own prospects and explore in the onshore Gulf
Coast region. The Company currently expects to continue its joint venture
relationships in the future, in addition to generating its own prospects in
the onshore Gulf Coast region.
TEXAS
The Company owns working interests in 33 wells in Texas that had
aggregate average production as of December 31, 1997 of 54.6 MMcfe/d gross
(5.8 MMcfe/d net to the Company) from depths ranging from 3,500 to 14,500
feet. Since the Company began its exploration in Texas in 1987, it has
participated in 263 square miles of 3-D seismic surveys and 70 wells, of
which 33 (47%) established commercial production. The Company has nine
gross wells (1.4 net wells) budgeted for 1998 in the Texas Gulf Coast
region with a 1998 capital expenditure budget of approximately $2.4
-5-
million. The wells that the Company currently intends to drill in 1998 are
3-D seismic-supported and these exploratory tests are expected to be drilled
on geologic structures where the Company has established commercial production
in its previous drilling attempts. As of December 31, 1997, the Company's
Texas wells had produced 8.8 Bcfe net to the Company and had established
estimated proved reserves of 3.0 Bcfe.
LOUISIANA
The Company owns working interests in producing properties in Cameron
and Terrebonne Parish, Louisiana that had aggregate average production as
of December 31, 1997 of 7.5 MMcfe/d gross (1.4 MMcfe/d net to the Company).
Since the Company began its exploration in Louisiana in 1995, it has
participated in 21 square miles of 3-D seismic surveys and 18 gross wells,
eight of which were completed as commercially productive, four of which
currently are producing. The Company has budgeted five wells (0.9 net to the
Company) for 1998 in the Louisiana area, with a 1998 capital expenditure
budget of approximately $0.9 million. The exploratory wells that are
budgeted for drilling in 1998 are 3-D seismic-supported and are in the
immediate area where the Company previously had established commercial
production. As of December 31, 1997, the Company's Louisiana wells had
produced a total of 7.8 Bcfe (1.0 Bcfe net to the Company) and had
established estimated gross proved reserves of 12.9 Bcfe (2.5 Bcfe net to
the Company).
MICHIGAN BASIN
The Company has been involved in oil and natural gas exploration and
production activities in the Michigan Basin since 1925. These activities
include operations in the Northern and Western Niagaran Reef Trend
(Silurian) and the Antrim Shale (Devonian) in Otsego, Montmorency and
Manistee Counties. Beginning in 1988 the Company participated in the
drilling of over 600 Antrim Shale wells. The Company currently has an
interest in over 300 Antrim Shale wells (in which it owns an average 12.5%
working interest), some of which have been assigned to third parties for
the purpose of monetizing the Section 29 tax credits available for
production from the assigned interests. The balance of the wells were sold
to fund the Company's exploration program. The majority of these Antrim
Shale wells are in Otsego County and produce from depths of approximately
1,300 to 1,600 feet.
Production from the Antrim Shale, including the Section 29 tax credits
available from such production, continues to be the Company's primary
producing property base in this region. As a result of its shallow
production in the Antrim Shale, the Company has an interest in
approximately 14,000 acres held by production in Otsego County, with its
deep rights being of interest, primarily for the Niagaran Reef Trend
located at depths of approximately 6,500 feet. The Company has an active
drilling program anticipated for the Antrim Shale in Montmorency County and
Manistee County at depths of approximately 1,400 feet. The Company has
-6-
approximately 8,700 gross acres leased in Manistee County, which is
expected to provide sufficient acreage for development of a field if the
drilling is deemed successful. The Company has a 100% working interest in
this project. The Company also has an active lease program in an area of
the Niagaran Reef Trend that the Company believes has been under-explored.
In addition, the Company is pursuing other on-going leasing efforts in
areas in the Michigan Basin. In 1998, the Company plans to evaluate a
4,500-acre lease block in Hillsdale County, with a 10 square mile 3-D
seismic survey. The project is located approximately 12 miles southwest of
the Albion-Scipio Field which has produced over 125 MBbl of oil and 200
Bcfe of natural gas. These wells are expected to be drilled to a depth of
approximately 3,500 feet to test the primary objective of the Trenton
formation (Ordovician).
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. and Key. 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 AMIs over and around 20 salt domes 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 AMIs. The agreements expire between March 1, 1998 and January
1, 2000, except with respect to AMIs where a joint operating agreement has
been executed, in which case 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
-7-
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. MOC is
generally the operator for leasehold acquisition and production operations,
and Key is generally the operator for 3-D seismic, drilling and completion
operations.
ONSHORE GULF COAST AGREEMENTS
MOC and the Hughes Company executed a Participation Agreement dated
January 1, 1994. Pursuant to the provisions of the Participation
Agreement, as extended for the years 1995 and 1996, MOC had the option to
participate with Hughes for a 25% of 8/8ths working interest in prospects
offered by the Hughes Company during calendar years 1994, 1995 and 1996.
Pursuant to participation letters, MOC elected to participate in a number
of prospects including the Destino Prospect in Duval County, Texas, the
Dilworth Prospect in McMullen County, Texas, the South Aviators Prospect in
Zapata County, Texas, the McCaskill Prospect in Karnes County, Texas, the
Mirando Hondo Prospect in Webb County, Texas, the Lapeyrouse Prospect in
Terrebonne Parish, Louisiana and the Northwest Kings Bayou Prospect in
Cameron Parish, Louisiana. Each of the participation letters identifies
the prospect, county and area covered therein. The Participation Agreement
requires MOC to pay its proportionate share of actual costs, an overhead
fee, prospect bonuses and certain back-in working interests at prospect
payout and program payout. The Participation Agreement provides a form of
Joint Operating Agreement which is to be executed as to each prospect. The
Joint Operating Agreement generally provides that the Hughes Company will
be the operator, that any party may propose to drill a well or other
operation subject to limitations with respect to concurrent wells and that
parties electing not to participate in a proposed operation are subject to
a 400% non-consent penalty. MOC is entitled to the benefit of any special
marketing arrangements or price structures that the Hughes Company is able
to negotiate in regard to the sale but may elect to market its share of oil
or natural gas in kind.
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
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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. As of December 31, 1997, the estimated remaining production
volume was 8.5 Bcfe, the estimated remaining dollar amount was $4.7
million and the volumetric threshhold was 4.7 Bcfe. The third production
payment and the additional contingent payment generally entitle MOC to
receive 96% of the net cash flow from additional specified volumes of
production attributable to the assigned interests. The reversionary
interest entitles MOC to a reassignment of 90% of the interests after a
larger specified volume of natural gas has been produced from the assigned
interests. MSLP also is obligated to make quarterly payments to MOC
equivalent to a percentage of the tax credits available under Section 29
with respect to natural gas produced and sold from the interests assigned.
MOC also has an option to repurchase the assigned interests for fair
market value after December 31, 2002, the expiration date of the Section
29 tax credits.
VOLUMES, PRICES AND PRODUCTION COSTS
The following table sets forth the historical combined information and
pro forma information of the Company with respect to production volumes,
average prices received and average production costs for the periods
indicated:
YEAR ENDED DECEMBER 31,
-----------------------------------------------
PRO FORMA
1997 1997 1996 1995
-------- -------- -------- --------
(Dollars in thousands, except per unit amounts)
Production:
Crude oil and condensate (Mbbls) . . . . . 206.8 47.4 46.5 31.6
Natural gas (Mmcf) . . . . . . . . . . . . 8,298.2 2,241.2 2,030.0 1,324.0
Natural gas equivalent (Mmcfe) . . . . . . 9,539.2 2,525.9 2,309.1 1,513.3
Average sales prices:
Crude oil and condensate ($ per Bbl) . . . $ 17.94 $ 20.33 $ 23.66 $ 22.68
Natural gas ($ per Mcfe) . . . . . . . . . 2.50 2.60 2.77 2.08
Natural gas equivalent ($ per Mcfe). . . . 2.57 2.69 2.91 2.29
Average Costs ($ per Mcfe):
Lease operating expenses and . . . . . . .
production taxes . . . . . . . . . . . $ 0.25 $ 0.58 $ 0.49 $ 0.51
Depreciation, depletion and amortization . 0.82 1.00 1.14 1.10
General and administrative . . . . . . . . 0.27 0.87 0.69 0.84
-9-
OIL AND NATURAL GAS MARKETING AND MAJOR CUSTOMERS
Most of the Company's oil and natural gas production is sold by its
operators 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. Decreases in the prices of oil and
natural gas could have an adverse effect on the carrying value of the
Company's proved reserves and the Company's revenues, profitability and
cash flow. 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, 1997, sales to the Company's three largest
customers on an historical combined basis were approximately 39%, 30% and
27%, 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 operations, to evaluate and select suitable
properties and to consummate transactions in a highly competitive
environment.
-10-
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.
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
participates in a substantial percentage of its 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.
-11-
FACILITIES
The Company currently leases approximately 8,000 square feet of office
space for its principal offices in Traverse City, Michigan. The Company
also leases approximately 3,300 square feet of office space in Houston,
Texas, approximately 1,300 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.
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 certain oil and
natural gas interests and other properties of the Company.
SECTION 29 TAX CREDIT
The natural gas production from wells drilled on certain of the
Company's properties in Otsego, Montmorency and Manistee Counties, Michigan
qualifies for the Section 29 tax credit. The Section 29 tax credit is an
income tax credit against regular federal income tax liability with respect
to sales of the Company's production of natural gas produced from tight gas
sand formations, subject to a number of limitations. Fuels qualifying for
the Section 29 tax credit must be produced from a well drilled or a
facility placed in service after November 5, 1990 and before January 1,
1993, and be sold before January 1, 2003.
The basic credit, which currently is approximately $1.03 per MMBtu of
natural gas produced from Antrim Shale, is computed by reference to the
price of crude oil and is phased out as the price of oil exceeds $23.50 in
1979 dollars (as adjusted for inflation) with complete phaseout if such
price exceeds $29.50 in 1979 dollars (as adjusted for inflation). Under
this formula, the commencement of phaseout would be triggered if the
-12-
average price for crude oil rose above approximately $48.00 per Bbl in
current dollars. The Company generated approximately $232,495 of Section
29 tax credits in 1997. The Section 29 tax credit may not be credited
against the alternative minimum tax, but under certain circumstances may be
carried over and applied against regular tax liability in future years.
Therefore, no assurances can be given that the Company's Section 29 tax
credits will reduce its federal income tax liability in any particular
year.
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 and wells developed as a result of 3-D seismic surveys.
The exemption is phased out if the sales price for oil exceeds $25.00 Bbl
or $3.50 per Mcf. The applicable production is exempt for up to five
years and expires July 1, 1999.
LOUISIANA TAX ABATEMENT
The State of Louisiana provides for an exemption from production taxes
for up to two years or until the well reaches payment (as defined by the
State of Louisiana's Department of Revenue and Taxation) and generally
applies to horizontal wells and to vertical wells over 15,000 feet. There
is also an exemption for discovery wells completed between September 30,
1994 and September 30, 1996, which lasts for two years or until the well
reaches payout.
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
-13-
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 Regulatory Commission ("FERC") regulates the transportation and sale
for resale 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
-14-
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 likely will continue. These laws and regulations may require the
acquisition of a permit or other authorization before construction or
drilling commences; restrict the types, quantities and concentration of
various substances that can be released into the environment in connection
with drilling and production activities; limit or prohibit construction,
drilling and other activities on certain lands lying within wilderness,
wetlands and other protected areas; require remedial measures to mitigate
pollution from former operations such as plugging abandoned wells; and
impose substantial liabilities for pollution resulting from the Company's
operations. The permits required for various of the Company's operations
are subject to revocation, modification and renewal by issuing authorities.
Governmental authorities have the power to enforce compliance with their
regulations, and violators are subject to civil and criminal penalties or
injunction. Management believes that the Company is in substantial
compliance with current applicable environmental laws and regulations, and
that the Company has no material commitments for capital expenditures to
comply with existing environmental requirements. Nevertheless, changes in
existing environmental laws and regulations or in interpretations thereof
-15-
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 numerous 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
-16-
States, OPA requires an operator to demonstrate $10.0 million in financial
responsibility, and for offshore facilities the financial responsibility
requirement is at least $35.0 million. Regulations currently are being
developed under federal and state laws concerning oil pollution prevention
and other matters that may impose additional regulatory burdens on the
Company. In addition, the federal Clean Water Act and analogous state laws
require permits to be obtained to authorize discharge into surface waters
or to construct facilities in wetland areas. With respect to certain of
its operations, the Company is required to maintain such permits or meet
general permit requirements. The Environmental Protection Agency ("EPA")
has adopted regulations concerning discharges of storm water runoff. This
program requires covered facilities to obtain individual permits,
participate in a group or seek coverage under an EPA general permit. The
Company believes that it will be able to obtain, or be included under, such
permits, where necessary, and to make minor modifications to existing
facilities and operations that would not have a material effect on the
Company.
EMPLOYEES
As of March 31, 1998, the Company had 32 full-time employees,
including three geologists and one engineer. As drilling production
activities increase, the Company intends to hire additional technical,
operational and administrative personnel as appropriate. 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.
GLOSSARY OF CERTAIN OIL AND GAS TERMS
The following are abbreviations and definitions of certain terms
commonly used in the oil and gas industry and this Form 10-K:
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in
reference to oil or other liquid hydrocarbons.
Bbl/d. One stock tank barrel of oil or other liquid hydrocarbons per
day.
Bcfe. One billion cubic feet of natural gas equivalent. In reference
to natural gas, natural gas equivalents are determined using the ratio of
-17-
6.0 Mcf of natural gas to 1.0 Bbl of oil, condensate of natural gas
liquids.
Btu. British thermal unit, which is the heat required to raise the
temperature of a one-pound mass of water from 58.5 to 59.5 degrees
Fahrenheit.
COMPLETION. The installation of permanent equipment for the
production of oil or natural gas.
DEVELOPED ACREAGE. The number of acres which are allocated or
assignable to producing wells or wells capable of production.
DEVELOPMENT WELL. A well drilled within the proved area of an oil or
natural gas reservoir to the depth of a stratigraphic horizon known to be
productive.
DRILLING COSTS. The costs associated with drilling and completing a
well (exclusive of seismic and land acquisition costs for that well and
future development costs associated with proved undeveloped reserves added
by the well) divided by total proved reserve additions.
DRY WELL. A well found to be incapable of producing either oil or
natural gas in sufficient quantities to justify completion of an oil or
natural gas well.
EXPLORATORY WELL. A well drilled to find and produce oil or natural
gas in an unproved area, to find a new reservoir in a field previously
found to be productive of oil or natural gas in another reservoir or to
extend a known reservoir.
FARM-IN or FARM-OUT. An agreement under which the owner of a working
interest in an oil and natural gas lease assigns the working interest or a
portion thereof to another party who desires to drill on the leased
acreage. The assignor usually retains a royalty or reversionary interest
in the lease. The interest received by an assignee is a "farm-in" while
the interest in the lease transferred by the assignor is a "farm-out."
FINDING AND DEVELOPMENT COSTS. Capital costs incurred in the
acquisition, exploration and development of proved oil and natural gas
reserves divided by proved reserve additions.
GROSS ACRES OR GROSS WELLS. The total acres or wells, as the case may
be, in which the Company has a working interest.
MBbl. One thousand barrels of oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet of natural gas.
-18-
Mcfe. One thousand cubic feet of natural gas equivalent.
MMBtu. One million Btus.
MMcf. One million cubic feet of natural gas.
MMcf/d. One million cubic feet of natural gas per day.
MMcfe. One million cubic feet of natural gas equivalent.
MMcfe/d. One million cubic feet of natural gas equivalent per day.
NET ACRES OR NET WELLS. Gross acres or wells multiplied, in each
case, by the percentage working interest owned by the Company.
NET PRODUCTION. Production that is owned by the Company less
royalties and production due others.
OIL. Crude oil or condensate.
OPERATING INCOME. Gross oil and natural gas revenue less applicable
production taxes and lease operating expenses.
OPERATOR. The individual or company responsible for the exploration,
development and production of an oil or natural gas well or lease.
PRESENT VALUE OF FUTURE NET REVENUES or PV-10. The pretax present
value of estimated future revenues to be generated from the production of
proved reserves calculated in accordance with SEC guidelines, net of
estimated production and future development costs, using prices and costs
as of the date of estimation without future escalation, without giving
effect to non-property related expenses such as general and administrative
expenses, debt service and depreciation, depletion and amortization, and
discounted using an annual discount rate of 10%.
PROVED DEVELOPED RESERVES. Reserves that can be expected to be
recovered through existing wells with existing equipment and operating
methods.
PROVED RESERVES. The estimated quantities of oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions.
PROVED UNDEVELOPED RESERVES. Reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where
a relatively major expenditure is required for recompletion.
-19-
ROYALTY. An interest in an oil and natural gas lease that gives the
owner of the interest the right to receive a portion of the production from
the leased acreage (or of the proceeds of the sale thereof), but generally
does not require the owner to pay any portion of the costs of drilling or
operating the wells on the leased acreage. Royalties may be either
landowner's royalties, which are reserved by the owner of the leased
acreage at the time the lease is granted, or overriding royalties, which
are usually reserved by an owner of the leasehold in connection with a
transfer to a subsequent owner.
SALT DOME. A generally dome-shaped intrusion into sedimentary rock
that has a mass of salt as its core. The impermeable nature of the salt
structure may act as a mechanism to trap hydrocarbons migrating through
surrounding rock formations.
SUCCESS RATE. The number of wells completed as a percentage of the
number of wells drilled.
2-D SEISMIC. The method by which a cross-section of the earth's
subsurface is created through the interpretation of reflecting seismic data
collected along a single source profile.
3-D SEISMIC. The method by which a three dimensional image of the
earth's subsurface is created through the interpretation of reflection
seismic data collected over a surface grid. 3-D seismic surveys allow for
a more detailed understanding of the subsurface than do conventional
surveys and contribute significantly to field appraisal, development and
production.
WORKING INTEREST. An interest in an oil and natural gas lease that
gives the owner of the interest the right to drill for and produce oil and
natural gas on the leased acreage and requires the owner to pay a share of
the costs of drilling and production operations.
ITEM 2. PROPERTIES.
OIL AND NATURAL GAS RESERVES
The Company's estimated total proved reserves of oil and natural gas
as of December 31, 1997 and 1996, and the present values of estimated
future net revenues attributable to these reserves as of those dates were
as follows:
-20-
AS OF DECEMBER 31,
----------------------------
1997 1996
--------- ---------
(Dollars in thousands,
except per unit data)
Net Proved Reserves:
Crude oil (Mbbl) . . . . . . . . . . . . . . . . . . . . . . . . . . 1,169.7 1,353.9
Natural gas (Mmcf) . . . . . . . . . . . . . . . . . . . . . . . . . 50,553.4 56,394.2
Natural gas equivalent (Mmcfe) . . . . . . . . . . . . . . . . . . . 57,571.6 64,517.6
Net Proved Developed Reserves:
Crude oil (Mbbl) . . . . . . . . . . . . . . . . . . . . . . . . . . 452.1 534.6
Natural gas (Mmcf) . . . . . . . . . . . . . . . . . . . . . . . . . 37,744.1 37,489.6
Natural gas equivalent (Mmcfe) . . . . . . . . . . . . . . . . . . . 40,456.7 40,697.5
Estimated future net revenues before income taxes . . . . . . . . . $ 87,970 $ 159,778
Present value of estimated future net revenues before income taxes $ 63,201 $ 116,336
Standardized measure of discounted estimated future net cash flows $ 46,618 $ 97,185
- ---------------------
The average prices for crude oil were $17.67 per Bbl at December 31,
1997 and $25.23 per Bbl at December 31, 1996. The average prices for
natural gas were $2.26 per Mcf at December 31, 1997 and $3.27 per Mcf
at December 31, 1996.
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.
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 No. 69.
The reserve estimates reflected above were prepared by S.A. Holditch &
Associates (as to Michigan Basin reserves) and Miller and Lents, Ltd. (as
to non-Michigan Basin 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
-21-
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:
-22-
YEAR ENDED DECEMBER 31,
--------------------------------------------------
1997 1996 1995
------------ ------------- --------------
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
Exploratory Wells:
Oil . . . . . . . . . . . . . . . 2 0.3 -- -- 4 1.7
Natural gas . . . . . . . . . . . 2 0.6 4 0.8 8 5.3
Non-productive. . . . . . . . . . 8 1.8 13 6.4 15 5.2
--- ---- ---- ---- ----- -----
Total. . . . . . . . . . . . . 12 2.7 17 7.2 27 12.2
=== ==== ==== ==== ===== =====
Development Wells:
Oil . . . . . . . . . . . . . . . 3 0.6 6 1.2 3 1.7
Natural gas . . . . . . . . . . . 11 2.3 -- -- 8 2.6
Non-productive. . . . . . . . . . 5 1.0 2 0.4 1 .5
--- ---- ---- ---- ----- -----
Total. . . . . . . . . . . . . 19 3.9 8 1.6 12 4.8
=== ==== ==== ==== ===== =====
- ---------------
Includes 2 gross (2.0 net to the Company) Antrim Shale wells for the
year ended December 31, 1995.
Includes 5 gross (0.7 net to the Company) Antrim Shale wells for the
year ended December 31, 1995 and 9 gross (1.3 net to the Company)
Antrim Shale wells for the year ended December 31, 1997.
At December 31, 1997, the Company was in the process of drilling
and/or completing 5 gross (2.9 net to the Company) wells that are not
reflected in the table.
PRODUCTIVE WELLS AND ACREAGE
PRODUCTIVE WELLS
The following table sets forth the Company's ownership interest as of
December 31, 1997 in productive oil and natural gas wells in the areas
indicated:
-23-
REGION OIL NATURAL GAS TOTAL
------ ------------- ------------- -------------
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
Mississippi Salt Basin . . . . . . -- -- 8 6.9 8 6.9
Onshore Gulf Coast
Texas . . . . . . . . . . . . . 11 2.0 22 3.0 33 5.0
Louisiana . . . . . . . . . . . -- -- 4 0.6 4 0.6
Michigan Basin/Other . . . . . . . 1 0.1 308 34.3 309 34.4
--- --- --- ---- --- ----
Total . . . . . . . . . . . . 12 2.1 342 44.8 354 46.9
=== === === ==== === ====
Productive wells consist of producing wells and wells capable of
production, including wells waiting on pipeline connection. Wells that are
completed in more than one producing horizon are counted as one well. Of
the gross wells reported above, none had 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, 1997:
REGION DEVELOPED UNDEVELOPED TOTAL
------ ---------------- ---------------- ----------------
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
Mississippi Salt Basin . . . . . . . . . 5,280 4,480 63,134 39,897 68,414 44,377
Onshore Gulf Coast
Texas. . . . . . . . . . . . . . . 9,308 1,286 22,967 6,461 32,275 7,747
Louisiana. . . . . . . . . . . . . 687 162 18,658 2,427 19,345 2,589
Michigan Basin/Other. . . . . . . . . 20,414 1,318 40,374 21,720 60,788 23,038
------ ----- ------- ------ ------- ------
Total. . . . . . . . . . . . . . 35,689 7,246 145,133 70,505 180,822 77,751
====== ===== ======= ====== ======= ======
-24-
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 gross and net undeveloped acreage at December 31, 1997:
ACRES EXPIRING
-----------------------
GROSS NET
------- ------
Twelve Months Ending:
December 31, 1998 . . . . . . . . . . . . . . . . . . 3,241 405
December 31, 1999 . . . . . . . . . . . . . . . . . . 40,579 11,532
December 31, 2000 . . . . . . . . . . . . . . . . . . 23,186 12,420
Thereafter. . . . . . . . . . . . . . . . . . . . . . 113,816 53,394
------- ------
Total. . . . . . . . . . . . . . . . . . . . . . . 180,822 77,751
======= ======
ITEM 3. LEGAL PROCEEDINGS.
The Company is not currently named as a defendant in any lawsuits
and/or administrative proceedings arising in the ordinary course of
business.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
During the fourth quarter of 1997, and before consummation of the
Offering, one matter was submitted to a vote of security holders. On
November 17, 1997, the Company's sole stockholder approved the Company's
Stock Option and Restricted Stock Plan of 1997.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS.
As of March 31, 1998, the Company estimates that there were
approximately 2,253 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.
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The Company's Common Stock is traded on The Nasdaq Stock Market under
the symbol "MEXP." From February 9, 1998 until March 27, 1998, the high
and low sales prices for the Company's Common Stock were $7 5/8 and
$10 3/8, respectively.
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 has entered into a credit
facility that contains provisions that may have the effect of limiting or
prohibiting the payment of dividends.
In connection with its formation, on November 17, 1997 the Company
issued 100 shares of Common Stock to Kelly E. Miller as sole trustee of the
Kelly E. Miller Trust. The Company issued such shares to Mr. Miller upon
his payment of $100 in a transaction exempt under Section 4(2) of the
Securities Act of 1933, as amended (the "Securities Act").
The Company entered into an Exchange and Combination Agreement
effective November 12, 1997 (the "Combination Agreement") with certain
trusts for the benefit of Mr. Miller and members of his family, certain
affiliated oil and gas exploration companies and certain oil and gas
exploration companies who are business partners and investors with MOC, the
Company's predecessor.
The assets contributed to the Company under the Combination Agreement
included the capital stock of MOC and interests in oil and gas properties
in which MOC also had an interest. In exchange for these assets, the
individuals and entities received a number of shares of Common Stock of the
Company proportionate to the value of their ownership interests in the
assets. The percentage interest of each person's interest in the assets
being contributed was established in the Combination Agreement.
The shares of Common Stock issued in connection with the Combination
Transaction were offered and sold by the Company without registration, in
reliance upon the exemption from registration made available under
Section 4(2) of the Securities Act and Rules 501-503 and 506-508 of
Regulation D promulgated thereunder. On December 1, 1997, the Registrant
filed with the SEC a Form D with respect to the exempt offering, in
accordance with the requirements of Rule 503.
USE OF PROCEEDS FROM THE COMPANY'S OFFERING
The Company's Registration Statement on Form S-1 (Registration No.
333-40383), as amended, with respect to the Offering of shares of the
Company's Common Stock, par value $0.01 per share, was declared effective
by the SEC on February 4, 1998. The Offering commenced on February 5,
1998, and has since terminated, resulting in (i) the sale by the Company of
5,500,000 shares of Common Stock on February 9, 1998; (ii) the sale by
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certain stockholders of the Company (the "Selling Stockholders") of 250,000
shares of Common Stock on February 9, 1998; (iii) the sale by the Company
of 62,500 shares of Common Stock on March 9, 1998 pursuant to the exercise
of the underwriters' over-allotment option on March 4, 1998; and (iv) the
sale by the Selling Stockholders of 200,000 shares of Common Stock on March
9, 1998 pursuant to the exercise of the underwriters' over-allotment option
on March 4, 1998. The shares sold constitute all of the shares of Common
Stock covered by the Registration Statement other than 600,000 shares with
respect to which the underwriters did not exercise their over-allotment
option. The managing underwriters for the offering were Bear, Stearns &
Co. Inc., Raymond James & Associates, Inc. and Stephens Inc.
The aggregate price to the public for the shares sold by the Company
in the Offering, including the over-allotment, was $44.5 million. The
expenses incurred by the Company with respect to the Offering were as
follows:
Underwriter Discounts and Commissions. . . . . . . . . . . . $3.1 million
Other Expenses . . . . . . . . . . . . . . . . . . . . . . . 1.0 million
------------
Total . . . . . . . . . . . . . . . . . . . . . . . . $4.1 million
============
The amount of other expenses set forth above is a reasonable estimate of
such amount. None of such payments were direct or indirect payments to the
Company's directors or officers or their associates, to persons owning 10%
or more of any class of equity securities of the Company or to affiliates
of the Company.
The net proceeds to the Company from the Offering were $40.4 million.
As of March 31, 1998, the Company used such net proceeds as follows:
(i) to repay $8.3 million of indebtedness outstanding under the Company's
prior revolving credit facilities, and (ii) to fund a portion of the
$50.5 million purchase price for assets acquired in the Combination
Transaction, including repayment of a $2.5 million loan made to the Company
by the C.E. Miller Trust to fund a down payment made in connection with the
Combination Transaction. Except as set forth in clause (ii), none of such
payments were direct or indirect payments to the Company's directors or
officers or their associates, to persons owning 10% or more of any class of
equity securities of the Company or to affiliates of the Company.
ITEM 6. SELECTED FINANCIAL DATA.
The following table presents selected historical combined financial
data of the Company as of the dates and for the periods indicated. The
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historical combined financial data as of and for each of the four years in
the period ended December 31, 1997 is derived from the combined financial
statements which have been audited by Arthur Andersen LLP, independent
public accountants. The historical combined financial data as of and for
the year ended December 31, 1993 is unaudited. The following table also
sets forth certain pro forma income tax, net income and earnings per share
information. Pro forma data is based on numerous assumptions and is not
necessarily indicative of the results of future operations of the Company.
Historical earnings per share has been omitted since such information is
not meaningful and the historically combined Company is 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 combined financial statements.
YEAR ENDED DECEMBER 31,
-------------------------------------------------------
1997 1996 1995 1994 1993
------- ------- ------- ------- -------
(In thousands, except per share data)
Statement of Operations Data:
Revenues:
Crude oil and condensate . . . . . . . . . $ 964 $ 1,101 $ 715 $ 672 $ 817
Natural gas. . . . . . . . . . . . . . . . 5,819 5,614 2,748 2,424 3,749
Other operating income . . . . . . . . . . 629 395 296 167 268
------- ------- ------- ------- -------
Total operating income . . . . . . . . 7,412 7,110 3,759 3,263 4,834
Operating expenses:
Lease operating expenses and
production taxes . . . . . . . . . . . 1,478 1,123 777 811 539
Depreciation, depletion and
amortization . . . . . . . . . . . . . 2,520 2,629 1,666 1,009 1,300
General and administrative . . . . . . . . 2,186 1,591 1,270 1,200 1,086
------- ------- ------- ------- -------
Total operating expenses . . . . . . . 6,184 5,343 3,713 3,020 2,925
------- ------- ------- ------- -------
Operating income. . . . . . . . . . . . . . . 1,228 1,767 46 243 1,909
Interest expense. . . . . . . . . . . . . . . (1,200) (1,139) (1,017) (810) (634)
Lawsuit settlement. . . . . . . . . . . . . . -- -- 3,521 -- --
------- ------- ------- ------- -------
Net income (loss) . . . . . . . . . . . . . . $ 28 $ 628 $ 2,550 $ (567) $ 1,275
======= ======= ======= ======= =======
Pro forma income before taxes . . . . . . $11,148
Pro forma provision for income taxes. . . 2,710
-------
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Pro forma net income. . . . . . . . . . . $ 8,438
=======
Pro forma basic and diluted earnings per
share. . . . . . . . . . . . . . . $ 0.68
=======
Pro forma weighted average shares
outstanding. . . . . . . . . . . . . . 12,493
=======
YEAR ENDED DECEMBER 31,
-------------------------------------------------------
1997 1996 1995 1994 1993
------- ------- ------- ------- -------
(In thousands)
Balance Sheet Data (at end of period):
Working capital . . . . . . . . . . . . . . . $(5,985) $(2,682) $(1,980) $(1,769) $ (434)
Oil and gas properties, net . . . . . . . . . 23,968 20,732 17,731 14,257 14,150
Total assets. . . . . . . . . . . . . . . . . 30,428 24,050 20,005 16,444 17,702
Long-term debt, including notes payable . . . 8,178 12,881 9,801 9,442 9,213
Equity. . . . . . . . . . . . . . . . . . . . 16,113 7,769 7,410 5,596 6,787
- --------------------
Gives pro forma effect to the application of federal and state income
taxes to the Company as if it were a taxable corporation for the
periods presented. Upon consummation of the Combination Transaction,
the Company was required to record a one-time non-cash charge to
earnings in connection with establishing a deferred tax liability on
the balance sheet in accordance with SFAS No. 109, "Accounting for
Income Taxes." If the Combination Transaction had been consummated
for the periods presented, such charge would have been approximately
$5.4 million.
Pro forma basic and diluted earnings per share has been computed
assuming that the shares of Common Stock issued in connection with the
Combination Transaction and with the Offering have been outstanding
since January 1, 1997.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
UNLESS OTHERWISE INDICATED, THE HISTORICAL INFORMATION CONTAINED IN
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS REFERS TO THE HISTORICAL COMBINED OPERATIONS OF THE COMPANY
WITHOUT GIVING EFFECT TO THE COMBINATION TRANSACTION.
-29-
OVERVIEW
Miller is an independent oil and gas company with its current
exploration efforts concentrated in the Mississippi Salt Basin, the onshore
Gulf Coast region of Texas and Louisiana and the Michigan Basin. The
Company has an established production base in each area.
In 1972, the Miller family began to acquire a substantial and
strategic leasehold position and apply emerging seismic technology to
discover oil and natural gas reserves in the Northern Michigan Niagaran
Reef Trend. The Company also explored and had production in Texas,
Wyoming, North Dakota and Montana. In 1988, the Miller family and their
affiliated companies sold their producing properties to Conoco, Inc.,
reserving the undeveloped acreage in the Michigan Basin. After the Conoco,
Inc. sale, the Company shifted its focus to development of the Antrim Shale
formation in its Northern Michigan leases. Since 1988, the Company has
participated in drilling over 600 commercially productive Antrim Shale
wells. Since 1993, the Company has developed its base of properties and
inventory of prospects in Mississippi, Louisiana and Texas.
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
directly are 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. To the extent that such capitalized costs in the full
cost pool (net of depreciation, depletion and amortization and related
deferred taxes) exceed the present value (using a 10% discount rate) of
estimated future net after-tax cash flows from proved oil and natural gas
reserves, such excess costs are charged to operations. The Company has not
been required to make any such write-downs. Once incurred, a write-down of
oil and natural gas properties is not reversible at a later date.
The Company was organized as a Delaware corporation in November 1997
to serve as the surviving company in the Combination Transaction. Pursuant
to the agreements among the Company and the owners of the Combined Assets,
the Company issued to those owners approximately 6.3 million shares of
Common Stock and an estimated $50.5 million in cash in exchange for the
contributed assets.
Because the Company, MOC and the Affiliated Entities share common
ownership and management, the combination of those particular Combined
Assets was accounted for as a reorganization of entities as prescribed by
SEC Staff Accounting Bulletin ("SAB") No. 47. The unaffiliated entities
participating in the Combination Transaction were not under the common
ownership and management of the Company. Consequently, the Company
accounted for the acquisition of those unaffiliated assets under the
purchase method of accounting, under which the properties were recorded at
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their estimated fair value on February 9, 1998, the date on which the
Combination Transaction was consummated.
Before the Offering, the Company was not subject to federal income
taxation because MOC and the Affiliated Entities were not tax reporting
entities but, instead, taxes relating to the operations of MOC and the
Affiliated Entities were required to be paid by the owners thereof as S
corporations. As a result, the Company did not pay any taxes for any of
these periods nor do the combined financial statements include any deferred
tax liability, on a historical basis. Upon consummation of the Offering,
the Company became subject to taxation as a C corporation.
For the reasons described above, the combined financial statements do
not include a provision for deferred tax liabilities. At December 31,
1997, the estimated tax basis of the Company's net assets was approximately
$16.0 million less than the basis for financial accounting purposes. The
difference is primarily the result of deductions for oil and natural gas
property costs for tax purposes in excess of the recorded expense for
financial accounting purposes. As a result, upon consummation of the
Combination Transaction, the Company was required to record a one-time non-
cash charge to earnings for the deferred tax liability in accordance with
SFAS No. 109, "Accounting for Income Taxes." If the Combination Transaction
had been consummated at December 31, 1997, such charge would have been
approximately $5.4 million.
RESULTS OF OPERATIONS
The following table summarizes production volumes, average sales
prices, operating revenues and average costs for the Company's oil and
natural gas operations for the periods presented:
YEAR ENDED DECEMBER 31,
-----------------------------------
1997 1996 1995
-------- -------- --------
(Dollars in thousands,
except per unit amounts)
Production volumes:
Crude oil and condensate (Mbbls). . . . . . . . . . . . . 47.4 46.5 31.6
Natural gas (Mmcf). . . . . . . . . . . . . . . . . . . . 2,241.2 2,030.0 1,324.0
Natural gas equivalent (Mmcfe). . . . . . . . . . . . . . 2,525.9 2,309.1 1,513.3
Average sales prices:
Crude oil and condensate ($ per Bbl). . . . . . . . . . . $ 20.33 $ 23.66 $ 22.68
Natural gas ($ per Mcf) . . . . . . . . . . . . . . . . . 2.60 2.77 2.08
Natural gas equivalent ($ per Mcfe) . . . . . . . . . . . 2.69 2.91 2.29
-31-
Operating revenues:
Crude oil and condensate . . . . . . . . . . . . . . . . $ 964 $ 1,101 $ 715
Natural gas . . . . . . . . . . . . . . . . . . . . . . . 5,819 5,614 2,748
Average Costs ($ per Mcfe):
Lease operating expenses and production taxes . . . . . . $ 0.58 $ 0.49 $ 0.51
Depletion, depreciation and amortization. . . . . . . . . 1.00 1.14 1.10
General and administrative 0.87 0.69 0.84
YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996
Oil and natural gas revenues for the year ended December 31, 1997
increased 1% to $6.8 million from $6.7 million for the same period in 1996.
Production volumes for natural gas during the year ended December 31, 1997
increased 10% to 2,241.2 MMcf from 2,030.0 MMcf for the same period in
1996. Average natural gas prices decreased 6% to $2.60 per Mcf for the
year ended December 31, 1997 from $2.77 per Mcf in the same period in 1996.
Production volumes for oil during the year ended December 31, 1997
increased 2% to 47.4 MBbls from 46.5 MBbls for the same period in 1996.
Average oil prices decreased 14% to $20.33 per barrel during the year ended
December 31, 1997 from $23.66 per barrel in the same period in 1996. This
decrease in oil prices primarily is attributable to cyclical fluctuations
in the spot market for oil.
Lease operating expenses and production taxes for the year ended
December 31, 1997 increased 32% to $1.5 million from $1.1 million for the
same period in 1996. Lease operating expenses and production taxes
increased primarily due to increased production as described above and an
increase in operating expenses per equivalent unit to $0.58 per Mcfe for
the year ended December 31, 1997 from $0.49 per Mcfe in the same period in
1996.
Depreciation, depletion and amortization ("DD&A") expense for the year
ended December 31, 1997 decreased 4% to $2.5 million from $2.6 million for
the same period in 1996. This decrease was due to increased production,
offset by a 12% decrease in the 1997 depletion rate to $1.00 per Mcfe from
$1.14 per Mcfe for the year ended December 31, 1996. This decrease in the
depletion rate was the result of a reduction in costs subject to DD&A
because of property sales.
General and administrative expense for the year ended December 31,
1997 increased 37% to $2.2 million from $1.6 million for the same period in
1996, as a result of increases in the number of employees and related
salaries, benefits and employee bonuses.
Interest expense for the year ended December 31, 1997 increased 5% to
$1.2 million from $1.1 million in the same period in 1996. Increases in
interest expense were due to increased debt levels in late 1996 and 1997
incurred to finance substantial leasehold acquisition activities in the
Mississippi Salt Basin area.
-32-
Net income for the year ended December 31, 1997 decreased to $0.03
million from $0.6 million for the same period in 1996, as a result of the
factors described above.
YEAR ENDED DECEMBER 31, 1996 COMPARED TO THE YEAR ENDED DECEMBER 31, 1995
Oil and natural gas revenues for 1996 increased 94% to $6.7 million
from $3.5 million in 1995. Production volumes for natural gas in 1996
increased 53% to 2,030.0 MMcf from 1,324.0 MMcf in 1995. Average natural
gas prices increased 33% to $2.77 per Mcf in 1996 from $2.08 per Mcf in
1995. Production volumes for oil in 1996 increased 47% to 46.5 MBbls from
31.6 MBbls in 1995. Average oil prices increased 4% to $23.66 per Bbl in
1996 from $22.68 per Bbl in 1995. The increase in oil and natural gas
production was due primarily to new wells being successfully drilled and
completed during 1996, along with recompletions of existing wells.
Lease operating expenses and production taxes for 1996 increased 45%
to $1.1 million from $0.8 million in 1995. Lease operating expenses and
production taxes increased due to increased production generated from new
oil and natural gas wells drilled and completed since December 31, 1995.
Operating expenses per equivalent unit in 1996 decreased to $0.49 per Mcfe
from $0.51 per Mcfe in 1995. The per unit cost decreased as a result of
increased production of natural gas which had lower per unit operating
costs.
DD&A expense for 1996 increased 58% to $2.6 million from $1.7 million
in 1995. This increase was due to the increase in oil and natural gas
production as well as a 4% increase in the depletion rate ($1.14 per Mcfe
in 1996 from $1.10 per Mcfe in 1995).
General and administrative expense for 1996 increased 25% to $1.6
million from $1.3 million for 1995 due primarily to an increase in
directors' fees, salaries and wages and office rent.
Interest expense for 1996 increased 12% to $1.1 million from $1.0
million in 1995 due to increased debt levels in 1996.
Net income for 1996 decreased to $0.6 million from $2.5 million in
1995 as a result of the factors described above, plus a $3.5 million
favorable lawsuit settlement received by the Company in 1995.
LIQUIDITY AND CAPITAL RESOURCES
Historically, the Company's primary sources of capital have been funds
generated by operations, capital contributions and borrowings, primarily
from MOC's shareholders and under bank credit facilities. The Company had
working capital deficits of $6.0 million at December 31, 1997 and $2.7
million at December 31, 1996.
-33-
The Company has entered into a credit facility with Bank of Montreal,
Houston Agency ("BOM"). The credit facility consists of a three-year
revolving line of credit converting to a three-year term loan. The amount
of credit available during the revolving period and the debt allowed during
the term period may not exceed the Company's "borrowing base," or the
amount of debt that BOM and the other lenders under the credit facility
agree can be supported by the cash flow generated by the Company's
producing and non-producing proved oil and natural gas reserves. Under the
credit facility the initial borrowing base is $23.0 million and may not
exceed $75.0 million. Amounts advanced under the credit facility bear
interest, payable quarterly, at either (i) BOM's announced prime rate or
(ii) the London Inter-Bank Offered Rate plus a margin rate ranging from
0.75% to 1.625%, as selected by the Company. In addition, the Company is
assessed a commitment fee equal to 0.375% of the unused portion of the
borrowing base, payable quarterly in arrears, until the termination of the
revolving period. At the termination of the revolving period, the
revolving line of credit will convert to a three-year term loan with
principal payable in 12 equal quarterly installments. The credit facility
includes certain negative covenants that impose limitations on the Company
and its subsidiaries with respect to, among other things, distributions
with respect to its capital stock, 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, including its oil and natural gas properties. The Company
borrowed $15.0 million under the credit facility to complete the
Combination Transaction and to repay all other outstanding indebtedness.
Pursuant to a promissory note dated November 26, 1997, the C.E. Miller
Trust loaned on an unsecured basis $2.5 million to MOC, with interest at
the prime rate, which MOC used to fund a down payment made in connection
with the Combination Transaction. A portion of the proceeds from the
Offering were used to repay the loan.
In 1991, the shareholders of MOC loaned to MOC an aggregate of $7.6
million, with interest at 2% over the prime rate, pursuant to separate loan
agreements. On December 1, 1997, the shareholders of MOC contributed the
indebtedness to MOC as capital pursuant to the Combination Agreement,
resulting in cancellation of the indebtedness. Such cancellation is not
expected to result in income to the Company for federal income tax
purposes.
At December 31, 1997 and 1996, the Company had an approximate notes
payable balance of $5.0 million and $4.0 million, respectively, which
represented a borrowing against a $5.0 million bank line-of-credit bearing
interest at the bank's prime rate and another $1.0 million line-of-credit,
which bore interest at the bank's prime rate plus 0.25%. These notes were
paid in full during February 1998 from the proceeds of the Offering.
-34-
During 1996, the Company also entered into a $1.0 million term loan
payable to a bank, with interest at the prime rate, maturing September
2000. At December 31, 1997 and 1996 the balance of the term loan was $0.7
million and $0.9 million, respectively. The term loan was paid in full
during February 1998 from the proceeds of the Offering.
The Company has budgeted unrisked capital expenditures of approximately
$44.3 million for 1998. Substantially all of the capital expenditures will be
used to fund 3-D seismic surveys, drilling and development activities and
leasehold acquisitions in the Company's project areas. The actual amounts
of capital expenditures and number of wells drilled may differ
significantly from such estimates.
The Company intends to fund its budgeted capital expenditures through
the end of 1998 from cash flow from operations and borrowings under the
credit facility.
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. Declines in prices received for oil and natural
gas may have an adverse effect on the Company's financial condition,
liquidity, ability to finance capital expenditures and results of
operations. Lower prices also may impact 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 programs and its increased participation
percentages and technology enhancement programs. While the Company
believes that cash flow from operations and borrowings under the credit
facility should allow the Company to implement its present business
strategy through 1998, additional financing may be required in the future
to fund the Company's growth, development and exploration program and
continued technological enhancement. In the event such capital resources
are not available to the Company, its exploration and other activities may
be curtailed.
HEDGING
In 1997, the Company began using certain hedging instruments (e.g.,
NYMEX futures contracts) for a portion of its 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
-35-
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 hedges that it
has in place will vary from time to time but at no time does it expect that
hedging activities will be of material significance.
The Company's hedging strategy is to maximize its return on investment
through hedging a portion of its activities relating to natural gas price
volatility. While this strategy should help the Company reduce its
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 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. During 1995 and 1996, the Company did not hedge any of
its oil or natural gas production, and for the year ended December 31,
1997, the Company had hedged 5.5% of its natural gas production.
EFFECTS OF INFLATION AND CHANGES IN PRICE
The Company's results of operations and cash flows are affected by
changing oil and natural gas prices. If the price of oil and natural gas
increases (decreases), there could be a corresponding increase (decrease)
in the operating cost that the Company is required to bear for operations,
as well as an increase (decrease) in revenues. Recent rates of inflation
have had a minimal effect on the Company.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In 1997, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 130, "Reporting Comprehensive Income" and SFAS No. 131, "Disclosures
about Segments of an Enterprise and Related Information," each of which
will require expanded disclosures effective for 1998. The Company does not
expect the application of these statements to have any effect on its
financial position, liquidity or results of operations.
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 by laws and regulations frequently
are changed and subject to interpretation, and the Company is unable to
predict the ultimate cost of compliance with these requirements or their
-36-
effect on its operations. Any suspensions, terminations or inability to
meet applicable bonding requirements could materially adversely affect the
Company's business, financial condition and results of operations.
Although significant expenditures may be required to comply with
governmental laws and regulations applicable to the Company, compliance has
not had a material adverse effect on the earnings or competitive position
of the Company. Future regulations may add to the cost of, or
significantly limit, drilling activity.
COMPUTER MODIFICATIONS FOR YEAR 2000
The Year 2000 issue exists because many computer systems and
applications abbreviate dates by eliminating the first two digits of the
year, assuming that these two digits would always be "19." Unless
corrected, this shortcut is expected to cause problems when the century
date occurs. On that date, some computer programs may recognize the date
as January 1, 1900 instead of January 1, 2000. This may cause the
Company's systems to incorrectly process critical financial and operational
information, or stop processing altogether. Additionally, computer
applications may be affected before January 1, 2000, if calculations into
the year 2000 are involved.
The Company has a plan to address the Year 2000 issue and will
continue to assess the impact of the Year 2000 issue on the remainder of
its computer-based systems and applications throughout 1998. If the
Company's plans are not successful, there could be a significant disruption
of the Company's ability to bill customers and pay suppliers, as well as a
possible slowdown of certain computer-dependent processes. Based on
currently available information, management presently does not anticipate
that the costs to address the Year 2000 issues or potential operating
disruptions will have an adverse impact on the Company's financial
conditions, results of operations or liquidity.
FORWARD-LOOKING STATEMENTS
This discussion and analysis of financial condition and results of
operations, and other sections of this Form 10-K, contain forward-looking
statements that are based on management's beliefs, assumptions, current
expectations, estimates and projections about the oil and gas industry, the
economy and about the Company itself. Words such as "anticipates,"
"believes," "estimates," "expects," "forecasts," "intends," "is likely,"
"plans," "predicts," "projects," variations of such words and similar
expressions are intended to identify such forward-looking statements.
These statements are not guarantees of future performance and involve
certain risks, uncertainties and assumptions ("Future Factors") that are
difficult to predict with regard to timing, extent, likelihood and degree
of occurrence. Therefore, actual results and outcomes may differ materially
from what may be expressed or forecasted in such forward-looking
statements. Furthermore, the Company undertakes no obligation to update,
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amend or clarify forward-looking statements, whether as a result of new
information, future events or otherwise.
Future Factors include, but are not limited to the results of the
Company's exploratory drilling activities, volatility of oil and natural
gas prices, uncertainty of estimates of oil and natural gas reserves,
implementation of the Company's growth strategy and its management of
future growth, substantial capital requirements associated with the
Company's operations, risks related to replacement of oil and natural gas
reserves, operating hazards and uninsured risks, competition, government
regulation and environmental matters, the Company's hedging policies and
transactions, marketability of production, dependence on key personnel,
technological changes and shortages of drilling rigs, equipment, supplies
and personnel. These are representative of the Future Factors that could
cause a difference between an ultimate actual outcome and a preceding
forward-looking statement.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Not applicable for fiscal year 1997.
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.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The following table sets forth certain information regarding the
directors, executive officers and certain key employees of the Company:
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NAME AGE POSITION
---- --- --------
DIRECTORS TERM EXPIRING IN 1999
C.E. "Gene" Miller . . . . . . . . . . . . . . . . 68 Chairman of the Board and Director
Frank M. Burke, Jr.. . . . . . . . . . . . . . . . 58 Director
DIRECTORS TERM EXPIRING IN 2000
Kelly E. Miller. . . . . . . . . . . . . . . . . . 43 President, Chief Executive Officer
and Director
Dan A. Hughes, Jr. . . . . . . . . . . . . . . . . 40 Director
DIRECTORS TERM EXPIRING IN 2001
William J. Baumgartner . . . . . . . . . . . . . . 42 Vice President-Finance, Chief Financial
Officer, Secretary and Director
William Casey McManemin. . . . . . . . . . . . . . 37 Director
Kenneth J. Foote . . . . . . . . . . . . . . . . . 41 Director
EXECUTIVE OFFICERS WHO ARE NOT DIRECTORS
Douglas A. Bell. . . . . . . . . . . . . . . . . . 38 Vice President-Production
Michael L. Calhoun . . . . . . . . . . . . . . . . 38 Vice President-Operations
Lew P. Murray. . . . . . . . . . . . . . . . . . . 41 Vice President-Exploration
CERTAIN KEY EMPLOYEES
Charles A. Morrison. . . . . . . . . . . . . . . . 48 Exploration Manager
Curtiss R. Yeiter. . . . . . . . . . . . . . . . . 41 Treasurer
Set forth below is a description of the backgrounds of the directors,
executive officers and certain key employees of the Company.
C.E. "GENE" MILLER has served as the Chairman of the Board and a
director of the Company since its founding in 1997 and of MOC since MOC's
founding in 1986. Since 1982, Mr. Miller has served as President,
Secretary and Treasurer of Eagle Investments, Inc. ("Eagle"), an oil and
gas investment company affiliated with the Company, and since 1990 has
served as President, Secretary and Treasurer of Eagle International, Inc.,
("Eagle International"), an international oil and gas development company
also affiliated with the Company. Mr. Miller has been involved in the
domestic oil and gas industry for over 35 years, primarily in Michigan and
Texas. Mr. Miller is a past president of the Michigan Oil and Gas
Association and also served as a director of that organization. Mr. Miller
previously served as a vice president and director and on the Executive
Committee of the Independent Petroleum Association of America, and as a
director of the National Stripper Well Association. In addition, Mr.
Miller has been involved in a number of civic activities and is a member of
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several boards of directors. Mr. Miller is the father of Kelly E. Miller,
the Company's President and Chief Executive Officer, and the father-in-law
of Douglas A. Bell, the Company's Vice President-Production.
KELLY E. MILLER has served as the President, Chief Executive Officer
and a director of the Company since its founding in 1997 and as President
and a director of MOC since MOC's founding in 1986. Since 1982, Mr. Miller
has served as a Vice President of Eagle. Mr. Miller serves on the Board of
Governors of the Independent Petroleum Association of America and the
Boards of Directors of the Michigan Oil and Gas Association and Republic
Bancorp, Inc. (NASDAQ). Mr. Miller has been involved in the oil and gas
industry since 1978, focusing his efforts in the areas of strategic
planning, prospect development, acquisition and administration. Mr. Miller
received a B.S. degree with a major in Petroleum Geology and a B.B.A.
degree with a major in Petroleum Land Management from the University of
Oklahoma. Mr. Miller also completed the Owner/President Management Program
(OPM) through the Harvard University Graduate School of Business. Mr.
Miller is a Certified Petroleum Geologist with the American Association of
Petroleum Geologists, an international geological organization. Mr. Miller
is the son of C.E. Miller, the Company's Chairman of the Board, and the
brother-in-law of Douglas A. Bell, the Company's Vice President-Production.
WILLIAM J. BAUMGARTNER has served as the Vice President-Finance, Chief
Financial Officer and Secretary and as a director of the Company since its
founding in 1997 and as Vice President-Finance and Chief Financial Officer
of MOC since 1991. Mr. Baumgartner previously held the positions of
Controller, Treasurer and Secretary of MOC. Mr. Baumgartner was employed
in public accounting and with various independent oil and gas exploration
entities before joining MOC in 1985. Mr. Baumgartner graduated from Ferris
State College in 1979 with a B.S. degree in Accounting. Mr. Baumgartner is
a member of the Michigan Oil and Gas Association and the Independent Petroleum
Association of America.
FRANK M. BURKE, JR. has served as a director of the Company since
February 2, 1998. Mr. Burke has served as Chairman, Chief Executive
Officer and Managing General Partner of Burke, Mayborn Company, Ltd., a
private investment and consulting company located in Dallas, Texas, since
1984. Burke, Mayborn Company Ltd. provides strategic and financial
consulting to selected individuals and entities. From 1960 to 1984, Mr.
Burke was associated with Peat, Marwick, Mitchell & Co., an international
firm of certified public accountants. Mr. Burke was elected partner in
1968, and served as a member of the Peat Marwick Board of Directors from
1978 to 1984. During the same period Mr. Burke served as Chairman, Energy
Group for Peat Marwick International and National Director of Energy and
Natural Resources for Peat Marwick in the United States. Mr. Burke
presently serves as a director of Kaneb Services, Inc. (NYSE), Kaneb Pipe
Line Partners, L.P. (NYSE) and CMS NOMECO Oil & Gas Co., a wholly owned
subsidiary of CMS Energy Corporation (NYSE). In addition, Mr. Burke serves
on the board of directors of numerous private corporations.
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DAN A. HUGHES JR. has served as a director of the Company since
February 2, 1998. Mr. Hughes is a partner in Dan A. Hughes Company, an oil
and gas exploration company located in Beeville, Texas, and has served as
Exploration Manager of Dan A. Hughes Company since 1985. Mr. Hughes
currently serves on the Regional Board of Trustees for the Independent
Petroleum Association of America and as Vice President for the Lower Gulf
Coast District for Texas Mid-Continent Oil & Gas Association. Mr. Hughes
has been active in the oil and gas industry for more than 20 years,
overseeing exploration and development activities in Texas and Louisiana,
as well as internationally. Mr. Hughes received a B.B.A. degree from Texas
A&M University and attended Texas A&M University for post graduate studies
in geology. Mr. Hughes is involved in a number of civic activities and is
a member of several boards of directors and executive committees.
WILLIAM CASEY MCMANEMIN has served as a director of the Company since
February 2, 1998. Mr. McManemin is a Registered Professional Engineer in
the state of Texas and received a B.S. degree in Petroleum Engineering from
Texas A&M University. Since 1988 Mr. McManemin has served as an officer,
shareholder and director of the Manager of SASI Minerals Company and the
General Partner of Spinnaker Royalty Company, L.P. In addition, since
September 1993, Mr. McManemin has served as an officer, shareholder and
director of the General Partner of Republic Royalty Company. All of such
companies are engaged in oil and gas property acquisition, exploration and
development, including activities in several of the same regions and areas
in which the Company's present and past activities are located. In
addition to membership in numerous oil and gas industry associations, Mr.
McManemin is a member of the Executive Committee of the Board of Trustees
of The St. Mark's School of Texas.
KENNETH J. FOOTE has served as a director of the Company since
February 2, 1998. Mr. Foote has served as a managing director of First
National Acceptance Company, a private financial services company, since
1987. Mr. Foote's primary responsibilities are in the areas of financial
analysis, taxation and strategic planning. Additionally, Mr. Foote is a
director of First National Bank of Michigan. From 1979 to 1982, Mr. Foote
worked for the public accounting firm of Arthur Andersen LLP and became a
Certified Public Accountant during that time. From 1982 to 1987, Mr. Foote
was a principal in two real estate ventures before joining First National
Acceptance Company. Mr. Foote has a A.B. in economics from Princeton
University and received his masters in accounting from New York University.
LEW P. MURRAY has served as Vice President-Exploration of the Company
since its founding in 1997 and of MOC since January 1996. Mr. Murray holds
a B.S. degree with a major in Geology from the University of Oklahoma. Mr.
Murray is a Certified Petroleum Geologist with the American Association of
Petroleum Geologists. Mr. Murray served as Exploration Manager of MOC from
1992 until 1996 and has been involved in the exploration program of MOC and
its affiliates since 1981. Mr. Murray's primary responsibilities involve
the review and recommendations of all domestic and international prospects.
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DOUGLAS A. BELL has served as Vice President-Production of the Company
since its founding and of MOC since January 1996. In addition, Mr. Bell
has served in various production-related capacities with affiliates of MOC
since his graduation from Lake Superior State University in 1981. Mr.
Bell's primary responsibilities include production operations, well
completions and reserve analysis. Mr. Bell is the son-in-law of C.E.
Miller, the Company's Chairman of the Board, and the brother-in-law of
Kelly E. Miller, the Company's President and Chief Executive Officer.
MICHAEL L. CALHOUN has served as Vice President-Operations of the
Company since January 12, 1998. Mr. Calhoun is a Registered Professional
Engineer in the state of Texas and received a B.S. degree in Petroleum
Engineering and a B.A. degree in Business Administration from the
University of Texas. In addition Mr. Calhoun received a Masters in
Business Administration from Southern Methodist University. Since 1989,
Mr. Calhoun has served in several capacities for Amerada Hess Corporation,
including as a Financial Analyst, Manager of Production, Planning and
Control, District Superintendent and, most recently, as Operations Manager
for the Gulf Coast District. From 1987 to 1989, Mr. Calhoun served as an
engineer for Greenwich Oil Corporation in Dallas, Texas, and from 1985 to
1987 as a field engineer for the Texas Railroad Commission.
CURTISS R. YEITER, C.P.A. has served as Treasurer of the Company since
its founding in 1997 and Controller of MOC since 1993. Mr. Yeiter
graduated from Northern Michigan University with a B.S. degree in
Accounting and became a Certified Public Accountant in 1982. Mr. Yeiter
was employed by the public accounting firm of BDO Seidman, LLP from 1979
until 1989 at which time he began employment with MOC. Mr. Yeiter's
primary responsibilities involve financial reporting, management of
accounting and information systems and personnel management.
CHARLES A. MORRISON has served as Exploration Manager of the Company
since December 1, 1997. Since 1981 Mr. Morrison has been the President of
Charles A. Morrison Consulting Geophysicist, Inc. located in Jackson,
Mississippi. Mr. Morrison graduated from Louisiana Tech University with a
B.S. degree in Geology. Before forming Charles A. Morrison Consulting
Geophysicist, Inc., Mr. Morrison served in a geophysical capacity with
several companies, including Western Geophysical Company, Cities Service
Oil Company and T.H. Clements and Associates. Mr. Morrison has been
responsible for the acquisition of over 30 3-D seismic surveys in the Upper
Gulf Coast region and has been involved in the interpretation of over 60
3-D seismic surveys in a consulting capacity.
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Exchange Act requires the Company's directors and
officers, and persons who own more than 10% of the Company's Common Stock,
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to file with the SEC reports of ownership and changes in ownership of
shares of Common Stock of the Company. Directors, officers and greater
than 10% holders are required by Securities and Exchange Commission
regulations to furnish the Company with copies of all Section 16(a) forms
they files. To the Company's knowledge, based solely on its review of the
copies of such reports furnished to the Company or written representations
from certain reporting persons that no reports on Form 5 were required for
those persons during the fiscal year ended December 31, 1997, the Company
believes that its officers and directors complied with all applicable
filing requirements during the Company's last fiscal year, except that the
initial Form 3s for the Company's officers and directors were filed on
February 12, 1998.
ITEM 11. EXECUTIVE COMPENSATION.
The following table sets forth certain summary information concerning
the compensation paid by MOC to its Chief Executive Officer and each of the
other persons who serve as executive officers of the Company whose annual
salary and bonus exceeded $100,000 (the "named executive officers") for the
fiscal year ended December 31, 1997. The table does not include
perquisites and other personal benefits for individuals for whom the
aggregate amount of such compensation does not exceed the lesser of (i)
$50,000 or (ii) 10% of individual combined salary and bonus for the named
executive officers in that year.
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION
--------------------------------------------------------
NAME AND OTHER ANNUAL ALL OTHER
PRINCIPAL POSITION YEAR SALARY BONUS COMPENSATION COMPENSATION
- ------------------------------ ---- ------ ----- ---------------- ------------
Kelly E. Miller, President and
Chief Executive Officer 1997 $ 275,000 $ 207,708 $ 9,500 $ 91,374
William J. Baumgartner, Vice
President-Finance, Chief
Financial Officer and
Secretary 1997 125,000 30,000 9,295 15,233
Lew P. Murray, Vice
President-Exploration 1997 100,000 25,000 7,800 29,580
- ------------
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Includes contributions made by MOC to its 401(k) Savings Plan on
behalf of the individuals listed.
Includes $168 for travel accident insurance and $91,206 for royalty
program participation.
Includes $168 for travel accident life insurance, $421 for life
insurance, $5,721 for royalty program participation and $8,923 for
tax credit participation.
Includes $168 for travel accident insurance, $391 for life insurance
and $29,021 for royalty program participation.
EMPLOYMENT AGREEMENTS
The Company has entered into employment agreements with each of
Messrs. Kelly Miller, Baumgartner, Calhoun, Murray and Morrison that
provide for an annual base salary in an amount not less than $250,000 for
Mr. Miller, $150,000 for Mr. Baumgartner, $135,000 for Mr. Calhoun,
$140,000 for Mr. Murray and $150,000 for Mr. Morrison. Messrs. Miller,
Baumgartner, Calhoun, Murray and Morrison also have received option grants,
pursuant to the Stock Option and Restricted Stock Plan of 1997 (the "1997
Stock Option Plan") to purchase 60,000, 97,500, 25,000, 100,000 and 55,000
shares, respectively, of Common Stock. The exercise price of the options
is $8.00 per share, except that for 11,350 of Mr. Miller's 60,000 shares,
the exercise price is $8.80. The options vest at the rate of one-fifth per
year beginning on the first anniversary of the grant date. Pursuant to the
1997 Stock Option Plan, the Company also granted to Messrs. Kelly Miller,
Baumgartner, Calhoun, Murray and Morrison 60,000, 22,500, 2,000, 15,000 and
10,000 shares of restricted Common Stock, respectively, which begin to vest
at cumulative annual increments of one-half of the total number of
restricted shares beginning on the first anniversary of the grant date.
The Company made a one-time grant of 270,000 and 2,500 stock options
to Messrs. Kelly Miller and Baumgartner, respectively, pursuant to the
terms of stock option agreements entered into between the Company and the
named individuals. The exercise price of the options is $8.00 per share
and the options vest at the rate of one-fifth per year beginning on the
first anniversary of the grant date.
Each of the employment agreements of Messrs. Miller, Baumgartner,
Calhoun, Murray and Morrison has an initial three-year term. At the end of
the first year of such initial term and on every anniversary thereafter,
the term of each employment agreement automatically will be extended for
one year, so that the remaining term of the agreement will never be less
than two years. Under each agreement, the officer's employment may be
terminated upon his death or "disability," for "cause" or "good reason,"
(as those terms are defined in the employment agreement) or for any reason
-44-
upon 60 days' notice by the employee or at will by the Company. Upon
discretionary termination of employment by the Company or termination by
the employee for good reason, the employee's salary and benefits will be
continued for a period to be determined by the Company's Board of
Directors. Upon death, disability, discretionary termination by the
employee or termination for cause, no severance pay will be paid.
Each of the employment agreements provides that the employee is
eligible to participate in the Company's employee benefit plans, including
the Company's matching 401(k) Savings Plan and the 1997 Stock Option Plan.
Each of the employment agreements contains certain confidentiality
obligations. In addition, in each agreement the employee agrees not to
compete against the Company for a period of six months following
termination in any county or parish in which the Company has a leasehold
interest or active or pending seismic programs.
CERTAIN OTHER ARRANGEMENTS
The Company paid a cash bonus upon consummation of the Offering to
Messrs. Kelly Miller, Baumgartner, Murray, Yeiter, Bell and C.W. Measley,
Jr. of $100,000, $60,000, $40,000, $50,000, $10,000 and $15,000,
respectively.
EMPLOYEE BENEFIT PLANS
STOCK OPTION AND RESTRICTED STOCK PLAN OF 1997
GENERAL. On November 17, 1997, the Company and its stockholder
adopted the 1997 Stock Option Plan. The Board of Directors contemplates
that the 1997 Stock Option Plan primarily will be used to grant stock
options. However, the 1997 Stock Option Plan permits grants of restricted
stock and tax benefit rights if determined to be desirable to advance the
purposes of the 1997 Stock Option Plan. In this Form 10-K, stock options,
restricted stock and tax benefit rights are referred to as "Incentive
Awards."
Persons eligible to receive Incentive Awards under the 1997 Stock
Option Plan (with certain limitations discussed below) are directors,
corporate officers and other full-time employees of the Company and its
subsidiaries.
A maximum of 1,200,000 shares of Common Stock (subject to certain
antidilution adjustments) are available for Incentive Awards under the 1997
Stock Option Plan. The 1997 Stock Option Plan is not qualified under
Section 401(a) of the Internal Revenue Code of 1986, as amended (the
"Code"), and is not subject to the Employee Retirement Income Security Act
of 1974.
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The 1997 Stock Option Plan is administered by the Stock Plan Committee
of the Board of Directors. The 1997 Stock Option Plan requires the Stock
Plan Committee to consist of at least two members, all of whom qualify as
"non-employee directors" as defined in Rule 16b-3 under the Securities
Exchange Act of 1934, as amended. The Board of Directors, in its
discretion, also may require that the members of the Stock Plan Committee
be "outside directors" as defined in the rules issued pursuant to Section
162(m) of the Code. The Stock Plan Committee makes determinations, subject
to the terms of the 1997 Stock Option Plan, as to the persons to receive
Incentive Awards, the amount of Incentive Awards to be granted to each
person, the terms of each grant and all other determinations necessary or
advisable for administration of the 1997 Stock Option Plan. The Stock Plan
Committee may amend the terms of Incentive Awards granted under the 1997
Stock Option Plan from time to time in a manner consistent with the 1997
Stock Option Plan; provided, that no amendment may be effective relating to
a particular Incentive Award without the consent of the relevant
participant, except to the extent the amendment operates solely to the
benefit of the participant.
The 1997 Stock Option Plan took effect on November 17, 1997 and,
unless earlier terminated by the Board of Directors, the 1997 Stock Option
Plan will terminate on November 16, 2007. No award may be made under the
1997 Stock Option Plan after that date. The Company intends to register
shares covered by the 1997 Stock Option Plan under the Securities Act.
STOCK OPTIONS. Under the 1997 Stock Option Plan, participants may be
granted stock options. Certain stock options that may be granted to
employees under the 1997 Stock Option Plan may qualify as incentive stock
options as defined in Section 422(b) of the Code ("Incentive Stock
Options"). Other stock options will not be Incentive Stock Options within
the meaning of the Code. Stock options may be granted at any time before
the termination of the 1997 Stock Option Plan according to its terms or by
action of the Stock Plan Committee.
The Stock Plan Committee will set forth the terms of individual grants
of stock options in stock option agreements that will contain such terms
and conditions, consistent with the provisions of the 1997 Stock Option
Plan, as the Stock Plan Committee determines to be appropriate. These
restrictions may include vesting requirements to encourage long-term
ownership of shares. The Company will receive no consideration upon the
award of options. The option price per share will be determined by the
Stock Plan Committee; provided, that the option price for an Incentive
Stock Option will be a price equal to or higher than the "market value" of
the Company's Common Stock on the date of grant. Each non-employee
director automatically is granted an option on the date of each annual
meeting of stockholders to purchase 3,000 shares of Common Stock at an
exercise price per share equal to 100% of the fair market value of the
Common Stock on the date each option is granted.
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Although the term of each stock option will be determined by the Stock
Plan Committee, no Incentive Stock Option will be exercisable under the
1997 Stock Option Plan after 10 years from the date it was granted.
Options generally will be exercisable for limited periods of time if an
option holder is terminated from employment with the Company or its
subsidiaries without cause, dies or becomes disabled. If an option holder
is terminated for cause, the option holder will forfeit all rights to
exercise any outstanding options. No individual participant may be
granted, during any calendar year, options to purchase more than 10% of the
total number of shares of Common Stock available under the 1997 Stock
Option Plan. The Stock Plan Committee may permit an option holder to
exercise an option for an extended period, which may not extend beyond the
earlier of either three years from the date of termination or the date on
which the options expire by their terms, if (i) the option holder retires
after age 62 or upon any other age determined by the Stock Plan Committee
("Normal Retirement"), (ii) the option holder voluntarily terminates
employment with the written consent of the Stock Plan Committee after the
option holder has attained 55 years of age and completed 15 years of
service ("Early Retirement") or (iii) the option holder voluntarily
terminates employment and the Stock Plan Committee determines the
termination to be in the best interests of the Company ("Consensual
Severance").
Following consummation of the Offering, options under the 1997 Stock
Option Plan were granted to directors, officers and certain employees of
the Company to purchase a total of 566,500 shares of Common Stock at $8.00
per share and 11,350 at $8.80 per share. These awards included options to
Messrs. Kelly Miller, Baumgartner, Calhoun, Murray, Bell and Morrison to
purchase 60,000, 97,500, 25,000, 100,000, 40,000 and 55,000 shares of
Common Stock, respectively. All such options have a term of 10 years and
become exercisable in cumulative annual increments of one-fifth of the
total number of shares of Common Stock subject thereto, beginning on the
first anniversary of the date of grant.
Upon consummation of the Offering, each non-employee director of the
Company was granted an option to purchase 10,000 shares of Common Stock.
Any person who first becomes a non-employee director automatically will be
granted, on the date of his or her election, an option to purchase 10,000
shares of Common Stock. In addition, on the first business day following
the date on which each annual meeting of the Company's stockholders is
held, each non-employee director then serving automatically will be granted
an option to purchase 3,000 shares of Common Stock. Each option granted to
non-employee directors will (i) have a 10-year term, (ii) have an exercise
price per share equal to the fair market value of a Common Stock share on
the date of grant ($8.00 in the case of options granted upon consummation
of the Offering) and (iii) become exercisable in cumulative annual
increments of one-fifth of the total number of shares of Common Stock
subject thereto, beginning on the first anniversary of the date of grant.
-47-
If a non-employee director resigns from the Board without the consent of a
majority of the other directors, such director's options may be exercised
only to the extent they were exercisable on the resignation date. The
Board of Directors of the Company has adopted a policy providing that
directors are expected to maintain, directly or indirectly, a minimum
investment in the Company of approximately $100,000.
RESTRICTED STOCK. In addition to the authority to grant stock options
under the 1997 Stock Option Plan, the 1997 Stock Option Plan allows the
Stock Option Committee to award restricted stock. Restricted stock is
subject to such terms and conditions, consistent with the provisions of the
1997 Stock Option Plan, as the Stock Plan Committee from time to time may
determine. As with stock option grants, the Stock Plan Committee will set
forth the terms of individual awards of restricted stock in restricted
stock agreements. If a participant's employment or director or officer
status is terminated during the restricted period set by the Stock Plan
Committee for any reason other than death or disability, or any additional
reason as may be permitted by the Stock Plan Committee, then any shares of
restricted stock still subject to restrictions will be forfeited. Unless
the Stock Plan Committee provides otherwise in a restricted stock
agreement, if a participant's employment or director or officer status is
terminated during the restricted period by reason of death or disability,
the restrictions on the participant's shares will terminate automatically
as of the date of death or disability. The Stock Plan Committee, in its
discretion, may provide that all or part of the restrictions on the
restricted stock will lapse upon termination if the termination is by
reason of Consensual Severance, Normal Retirement or Early Retirement.
Without Stock Plan Committee authorization, a recipient of restricted
stock may not sell, exchange, transfer, pledge, assign or otherwise dispose
of such stock other than to the Company or by will or the laws of descent
or distribution. In addition, the Stock Plan Committee may impose other
restrictions on shares of restricted stock. However, holders of restricted
stock will enjoy all other rights of stockholders with respect to
restricted stock, including the right to vote restricted shares at
stockholders' meetings and the right to receive all dividends paid with
respect to restricted stock. Any securities received by a holder of
restricted stock pursuant to a stock dividend, stock split,
recapitalization or reorganization will be subject to the same terms,
conditions and restrictions that are applicable to the restricted stock for
which such shares are received.
The Stock Plan Committee may provide that upon the occurrence of a
"change in control" of the Company (as defined in the 1997 Stock Option
Plan), all restricted stock or other Incentive Awards immediately would
become fully vested, nonforfeitable or otherwise no longer subject to any
restriction. The Stock Plan Committee may provide in the restricted stock
agreement that the number of shares that automatically will vest will be
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limited in value to the extent that any payments that are deemed "parachute
payments" as defined in Section 280G9(b)(2) of the Code would not be
subject to the excise tax imposed by Section 4999 of the Code.
Following consummation of the Offering, Messrs. Kelly Miller,
Baumgartner, Calhoun, Murray and Morrison were awarded 60,000, 22,500,
2,000, 15,000 and 10,000 shares of restricted Common Stock, respectively.
As described above, an individual's restricted stock agreement may provide
that shares automatically will vest upon a change in control and that such
shares so vested will be limited in value to the extent deemed parachute
payments, as defined in the Code. The restricted shares will begin to vest
at cumulative annual increments of one-half of the total number of
restricted shares of Common Stock subject thereto, beginning on the first
anniversary of the date of grant. At the time of issuance of the
restricted shares, compensation expense of $0.9 million was deferred.
Because the restricted shares are subject to the risk of forfeiture during
the vesting period, compensation expense (equivalent to $8.00, the Offering
price per share) will be recognized ratably over the two-year vesting
period as the risk of forfeiture passes.
TAX BENEFIT RIGHTS. The Stock Plan Committee also may grant tax
benefit rights under the 1997 Stock Option Plan. As with options and
restricted stock, the Stock Plan Committee will set forth the terms and
conditions of tax benefit rights granted and the participants to receive
tax benefit rights in written agreements. A tax benefit right entitles a
participant to receive a cash payment from the Company or its subsidiaries
to encourage the participant to exercise his or her options. The amount of
the payment may not exceed the amount calculated by multiplying the
ordinary income, if any, realized by the participant for federal tax
purposes as a result of the exercise of a non-Incentive Stock Option, or as
a result of the disqualifying disposition of shares acquired under an
Incentive Stock Option, by the maximum federal income tax rate (including
any surtax or similar charge or assessment) for corporations, plus the
applicable state and local tax imposed on the exercise of the option or
disqualifying disposition. Tax benefit rights may be granted only with
respect to a stock option issued and outstanding or to be issued under the
1997 Stock Option Plan or any prior plans. A participant may refuse the
issuance of a tax benefit right if the effect of the tax benefit right
would disqualify an Incentive Stock Option, change the date of the grant or
exercise price or impair the participant's existing stock options.
The following table summarizes the number of stock options and
restricted stock grants that were received by certain individuals under the
1997 Stock Option Plan:
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NUMBER OF SHARES OF
NAME OPTIONS RESTRICTED STOCK
---- --------------- --------------------
Kelly E. Miller . . . . . . . . . . . . . . . . . . . . 60,000 60,000
William J. Baumgartner. . . . . . . . . . . . . . . . . 97,500 22,500
Lew P. Murray . . . . . . . . . . . . . . . . . . . . . 100,000 15,000
Douglas A. Bell . . . . . . . . . . . . . . . . . . . . 40,000 --
Michael L. Calhoun. . . . . . . . . . . . . . . . . . . 25,000 2,000
Frank M. Burke, Jr. . . . . . . . . . . . . . . . . . . 10,000 --
Kenneth J. Foote. . . . . . . . . . . . . . . . . . . . 10,000 --
Dan A. Hughes, Jr.. . . . . . . . . . . . . . . . . . . 10,000 --
William Casey McManemin . . . . . . . . . . . . . . . . 10,000 --
Directors and executive officers as a group . . . . . . 362,500 99,500
All employees as a group (other than directors and
executive officers). . . . . . . . . . . . . . . . . 215,350 10,000
- ------------------------
The exercise price for options granted was $8.00, the Offering price,
except that the exercise price for 11,350 of the options granted to
Mr. Miller was $8.80, 110% of the Offering price.
Options become exercisable in cumulative annual increments of one-
fifth of the total number of shares of Common Stock subject thereto,
beginning on the first anniversary of the date of grant.
Shares of restricted stock will begin to vest at cumulative annual
increments of one-half of the total number of shares subject thereto,
beginning on the first anniversary of the date of the grant.
ONE-TIME STOCK OPTION GRANT
The Company made a one-time grant of 270,000 and 2,500 stock options
to Messrs. Kelly Miller and Baumgartner, respectively, pursuant to the
terms of stock option agreements entered into between the Company and the
named individuals. The exercise price of the options is $8.00 per share
and the options vest at the rate of one-fifth per year beginning on the
first anniversary of the grant date.
401(K) SAVINGS PLAN
In connection with the Combination Transaction, the Company adopted
MOC's 401(k) Savings Plan (the "Savings Plan"). The Savings Plan is
available to all full-time employees upon commencement of their employment
and provides for discretionary matching contributions by the Company. The
funds in the Savings Plan are invested in equity and bond funds at the
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election of the participant. The Company-paid matching contributions under
the Savings Plan vest at a rate of 20% per year, beginning after three
years of service. The Savings Plan balances that have vested generally are
paid at an employee's termination of employment or retirement.
LIFE INSURANCE PROGRAM
The Company provides, at its sole cost, life insurance in the face
amount of $150,000 on each of the lives of Messrs. Baumgartner and Murray,
each of whom is entitled to designate the beneficiary of the insurance
proceeds. Upon their death, $150,000 will be paid to the beneficiary
designated by Messrs. Baumgartner or Murray. During 1997, the Company paid
$421 and $391 in premiums for Messrs. Baumgartner's and Murray's respective
policies.
TRAVEL INSURANCE PROGRAM
The Company provides to each of Messrs. Kelly Miller, C.E. Miller,
Baumgartner, Calhoun, Murray and Bell, as well as to C.W. Measley, Jr.,
Land Manager of the Company and MOC, travel accident insurance in the face
amount of $100,000 at no cost. The insurance covers accidental death and
disability in the course of business or personal travel anywhere in the
world. Each covered person is entitled to designate the beneficiary of the
insurance proceeds. During 1997, the Company paid $168 in premiums for
each of the policies.
TAX CREDIT AND ROYALTY PARTICIPATION PROGRAMS
TAX CREDIT PARTICIPATION PROGRAM. On April 14, 1995, MOC established
the Credit Participation Program (the "Tax Program"), which was designed to
reward, recognize and retain key employees of MOC who participated in an
instrumental manner in the acquisition, sale and/or brokerage of production
of oil and natural gas from non-conventional sources that qualified for
certain tax credits under Section 29 of the Code. Under the terms of the
Tax Program, participants were entitled to a percentage of any money
received by the Tax Program, including fees, reimbursements, down-payments
and credits from brokerage transactions. After payment of expenses, money
was allocated among and distributed to participants, pursuant to a
participant's annual allocation percentages, as determined by a majority
vote of MOC's shareholders. If MOC acquired properties for the purpose of
the acquisition of Section 29 Credits and MOC sold all or any part of the
properties to which such credits applied, the distribution of the proceeds
for the Tax Program was net of the total invested capital plus a 10%
return. If a participant's employment was terminated, any distributions
pursuant to the Tax Program terminated and the balance of current and
future distributions to the participant remained in the Tax Program to be
allocated and distributed by MOC in its discretion.
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As of December 31, 1997, Mr. Baumgartner was the only participant in
the Tax Program. Payments made to Mr. Baumgartner in 1997 amounted to
$8,923. The Tax Program was terminated concurrently with consummation of
the Offering.
ROYALTY PARTICIPATION PROGRAM. On December 31, 1992, MOC established
the Employee Participation Program (the "Royalty Program"), which was
designed to provide an incentive for certain key employees to contribute to
the success of MOC. Under the terms of the Royalty Program, participants
received a percentage of the overriding royalty working interest on all
prospects generated by MOC. A maximum of 1/32nd of 8/8ths overriding
royalty working interest was reserved for the Royalty Program on all
prospects generated by MOC. If less than a 1/32nd of 8/8ths overriding
royalty was reserved on such prospects, participants were assigned a
proportionate share of the overriding royalty that MOC retained. A sliding
scale overriding royalty was reserved against MOC's retained net revenue
interest, proportionately adjusted to MOC's working interest in any
specific property. The net revenue scale was used whether MOC retained an
overriding royalty on its prospects, acquired a working interest from a
third party or sold or distributed working interests to an entity owned by
a shareholder of MOC. The Royalty Program was limited to those properties
that MOC had an initial working interest in and the overriding royalty was
not applied to farm-outs by MOC, sale of lease positions, purchase of
reserves or recovery from lawsuits. If a participant's employment
terminated, any overriding royalties previously assigned to the participant
reverted to MOC. In the event of a participant's death, any royalties due
to the participant were allocated to a beneficiary or trust designated by
the participant.
As of December 31, 1997, the following individuals participated in the
Royalty Program: Mr. Kelly Miller had a 40% interest in the royalty
interest; Mr. Baumgartner had a 7.5% interest in the royalty interest; and
Mr. Murray had a 15% interest in the royalty interest. The stated
percentages for Messrs. Miller and Murray applied to prospects of MOC as of
January 1, 1996. To the extent that a prospect was included in the Royalty
Program before January 1, 1996, with respect to those properties, Messrs.
Miller and Murray had a 32% and 8% interest in such royalties,
respectively, as of December 31, 1997. During 1997 Messrs. Miller,
Baumgartner and Murray received $91,206, $5,721 and $29,021, respectively,
under the Royalty Program. The Royalty Program was terminated concurrently
with consummation of the Offering.
COMPENSATION OF DIRECTORS. Directors who are not employees of the
Company receive a $15,000 annual retainer fee plus $500 for attendance at
each regular meeting of the Board of Directors and $1,000 for attendance at
each committee meeting. Directors who also are employees of the Company
receive no annual retainer and are not compensated for attendance at Board
or committee meetings. The Company also reimburses directors for expenses
associated with attending Board and committee meetings.
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Upon consummation of the Offering, each non-employee director of the
Company was granted an option to purchase 10,000 shares of Common Stock.
Any person who first becomes a non-employee director automatically will be
granted, on the date of his or her election, an option to purchase 10,000
shares of Common Stock. In addition, on the first business day following
the date on which each annual meeting of the Company's stockholders is
held, each non-employee director then serving automatically will be granted
an option to purchase 3,000 shares of Common Stock. Each option granted to
non-employee directors will (i) have a 10-year term, (ii) have an exercise
price per share equal to the fair market value of a Common Stock share on
the date of grant ($8.00 in the case of options granted upon consummation
of the Offering) and (iii) become exercisable in cumulative annual
increments of one-fifth of the total number of shares of Common Stock
subject thereto, beginning on the first anniversary of the date of grant.
If a non-employee director resigns from the Board without the consent of a
majority of the other directors, such director's options may be exercised
only to the extent they were exercisable on the resignation date.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The following table sets forth certain information regarding the
beneficial ownership of the Company's Common Stock as of March 9, 1998 of
(i) each person the Company knows to be the beneficial owner of 5% or more
of the outstanding shares of Common Stock, (ii) each executive officer
listed in the Summary Compensation Table, (iii) each director of the
Company and (iv) all executive officers and directors of the Company as a
group.
AMOUNT AND NATURE OF BENEFICIAL
OWNERSHIP OF COMMON STOCK
-----------------------------------------------
SOLE VOTING SHARED VOTING TOTAL
AND DISPOSITIVE OR DISPOSITIVE BENEFICIAL PERCENT
NAME OF BENEFICIAL OWNER POWER POWER OWNERSHIP OF CLASS
------------------------ --------------- -------------- ------------- --------
C.E. Miller . . . . . . . . . . . . . . 1,415,234 -- 1,415,234 11.33%
Kelly E. Miller . . . . . . . . . . . . 1,008,319 400 1,008,719 8.07%
David A. Miller . . . . . . . . . . . . 718,945 -- 718,945 5.75%
3104 Logan Valley Road
Traverse City, Michigan 49685
Daniel R. Miller. . . . . . . . . . . . 868,840 -- 868,840 6.96%
3104 Logan Valley Road
Traverse City, Michigan 49685
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Sue Ellen Bell. . . . . . . . . . . . . 833,218 -- 833,218 6.67%
3104 Logan Valley Road
Traverse City, Michigan 49685
William J. Baumgartner. . . . . . . . . . . 9,300 -- 9,300
Lew P. Murray . . . . . . . . . . . . . . . -- 200 200
Douglas A. Bell . . . . . . . . . . . . -- 833,218 833,218 6.67%
Frank M. Burke, Jr.. . . . . . . . . . 12,500 -- 12,500
Kenneth J. Foote. . . . . . . . . . . . . . 43,390 43,390
Dan A. Hughes, Jr. . . . . . . . . . . 26,541 26,541
William Casey McManemin. . . . . . . . 12,500 1,042,480 1,054,980 8.34%
SASI Minerals Company . . . . . . . . . . . 1,042,480 -- 1,042,480 8.34%
1201 Market Street, Suite 1402
Wilmington, Delaware 19801
Executive Officers and Directors
as a group. . . . . . . . . . . . . . . . 2,527,784 1,876,298 4,404,082 35.25%
- -------------------------
Less than 1%.
The number of shares stated are based on information provided by
each person listed and include shares personally owned of record by
the person and shares which, under applicable regulations, are
considered to be otherwise beneficially owned by the person.
Excludes the following shares that may be acquired through the
exercise of stock options and restricted stock granted under the
1997 Stock Option Plan and pursuant to the one-time grant to Messrs.
Miller and Baumgartner described above:
NUMBER OF SHARES OF
NAME OPTIONS RESTRICTED STOCK
---- ------- ----------------
Kelly E. Miller. . . . . . . . . . 330,000 60,000
William J. Baumgartner . . . . . . 100,000 22,500
Lew P. Murray. . . . . . . . . . . 100,000 15,000
Douglas A. Bell. . . . . . . . . . 40,000 --
Frank M. Burke, Jr.. . . . . . . . 10,000 --
Kenneth J. Foote . . . . . . . . . 10,000 --
Dan A. Hughes, Jr. . . . . . . . . 10,000 --
William Casey McManemin. . . . . . 10,000 --
These numbers include shares over which the listed person is legally
entitled to share voting or dispositive power by reason of joint
ownership, trust or other contract right, and shares held by
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spouses, children or other relatives over whom the listed person may
have substantial influence by reason of relationship.
Includes 228,549 shares held by the Kelly E. Miller Retained Annuity
Trust #1, 228,549 shares held by the Daniel R. Miller Retained
Annuity Trust #1, 342,823 shares held by the David A. Miller
Retained Annuity Trust #1 and 228,549 shares held by the Sue Ellen
Bell Retained Annuity Trust #1, with respect to each of which C.E.
Miller is the sole trustee. Also includes 264,199 shares held by
Eagle and 122,565 shares held by Eagle International, each of which
is owned by a revocable trust of which C.E. Miller is the sole
trustee.
Includes 924,195 shares held by the Kelly E. Miller Trust, a
revocable trust of which Kelly E. Miller is the sole trustee, and
84,024 shares held by Miller and Miller, Inc., which is owned by a
revocable trust of which Kelly E. Miller is the sole trustee.
Excludes 228,549 shares held by the Kelly E. Miller Retained Annuity
Trust #1, of which Kelly E. Miller's father, C.E. Miller, is the
sole trustee and of which Kelly E. Miller and trusts for the benefit
of his children are the beneficiaries.
Includes 634,921 shares held by the David A. Miller Trust, a
revocable trust of which David A. Miller is the sole trustee, and
84,024 shares held by Oak Shores Investments, Inc., which is owned
by a revocable trust of which David A. Miller is the sole trustee.
Excludes 342,823 shares held by the David A. Miller Retained Annuity
Trust #1, of which David A. Miller's father, C.E. Miller, is the
sole trustee and of which David A. Miller and trusts for the benefit
of his children are the beneficiaries.
Includes 794,196 shares held by the Daniel R. Miller Trust, a
revocable trust of which Daniel R. Miller is the sole trustee, and
74,634 shares held by Double Diamond Enterprises, Inc., which is
owned by a revocable trust of which Daniel R. Miller is the sole
trustee. Excludes 228,549 shares held by the Daniel R. Miller
Retained Annuity Trust #1, of which Daniel R. Miller's father, C.E.
Miller, is the sole trustee and of which Daniel R. Miller and trusts
for the benefit of his children are the beneficiaries.
Includes 749,194 shares held by the Sue E. Bell Trust, a revocable
trust of which Sue E. Bell is the sole trustee, and 84,024 shares
held by Frontier Investments, Inc., which is owned by a revocable
trust of which Sue E. Bell is the sole trustee. Excludes 228,549
shares held by the Sue Ellen Bell Retained Annuity Trust #1, of
which Sue E. Bell's father, C.E. Miller, is the sole trustee and of
which Sue E. Bell and trusts for the benefit of her children are the
beneficiaries.
Includes only those shares held by Mr. Bell's spouse, Sue Ellen
Bell. Mr. Bell disclaims beneficial ownership of these shares.
Includes 6,500 shares held by Burke, Mayhorn Company, Ltd. and 3,000
shares held by TTC Burke, Ltd., which are private consulting and
investment companies controlled by Mr. Burke.
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Includes only those shares held by the Hughes Company, of which Mr.
Hughes is Exploration Manager and in which Mr. Hughes is a partner.
Includes only those shares held by SASI Minerals Company. William
McManemin is an officer, director and shareholder of the Manager of
SASI Minerals Company and disclaims beneficial ownership of these
shares.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
THE COMBINATION TRANSACTION
The Company was formed as a Delaware corporation as part of the
combination of MOC with certain oil and natural gas interests owned by
companies beneficially owned by individual members of the Miller family and
certain oil and natural gas interests owned by certain business partners
and investors. William Casey McManemin, a director of the Company, is an
officer, shareholder and director of the Manager of SASI Minerals Company,
which exchanged interests in oil and natural gas properties for shares of
Common Stock in the Combination Transaction. Kenneth J. Foote, a director
of the Company, also exchanged interests in oil and natural gas properties
for shares of Common Stock in the Combination Transaction.
REGISTRATION RIGHTS AGREEMENT
The Company entered into a Registration Rights Agreement with each
person who became a stockholder of the Company upon consummation of the
Combination Transaction. The Registration Rights Agreement provides each
such person certain piggyback registration rights with respect to their
shares of Common Stock.
TRANSACTIONS WITH C.E. MILLER AND AFFILIATES
The following information describes agreements or transactions between
MOC and C.E. Miller, Chairman of the Board and a director of the Company
and MOC, or his affiliates:
SERVICE AGREEMENT. MOC has entered into an Amended Service Agreement
dated January 1, 1997, amending a prior service agreement, with Eagle,
an oil and gas exploratory company beneficially owned by C.E. Miller. Under
the amended agreement, MOC provides Eagle with administrative, technical,
consulting and other services required by Eagle to operate its business in
the ordinary course. These services include, among others, developing
prospects, coordinating, permitting, drilling and facility construction and
operation, maintaining joint venture relationships and providing accounting,
financial, tax and budget-preparation services. As compensation for its
services, Eagle has agreed to pay MOC a fixed fee of $50,000 per calendar
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quarter, subject to annual adjustments to be negotiated by MOC and Eagle, as
well as additional fees for specialized services as agreed by the parties.
Eagle also agreed to reimburse MOC its out-of-pocket expenses incurred in
providing the services. Either party may terminate the agreement at any time
upon 60 days' prior notice. Eagle paid MOC $200,000, $100,000 and $50,000
under the service arrangement in 1997, 1996 and 1995, respectively, which the
Company believes is adequate compensation for the services provided to
Eagle.
1997 DRILLING PROGRAM. MOC has entered into a 1997 Drilling Program
Exploration and Participation Agreement dated August 15, 1997 with Eagle
and certain companies affiliated with MOC who participated in the
Combination Transaction. Under the agreement, MOC and the affiliated
companies contributed certain drilling inventory consisting of 13 prospects
that had a high probability of drilling operations beginning by December
31, 1997, and that had pipelines and facilities in place, acreage and
rights of way acquired and drilling units or unitization agreements
secured. As consideration for the contribution of the wells, Eagle agreed
to pay 100% of the actual acreage, seismic, dry hole cost and cost of
completion and facilities through the tanks of the working interest
represented by MOC and the affiliated companies. Eagle will receive a
proportionate 50% of MOC's and the affiliated companies' rights to all
depths that exist within the drilling unit or unitized area. In addition,
MOC and the affiliated companies agreed to contribute the use of their
existing facilities used for any common operations, such as production
platforms, flowlines, pipelines or rights of way. MOC and the affiliated
companies have the option to contribute additional prospects to Eagle, but
only upon the consent of C.E. Miller. The parties terminated the agreement
upon consummation of the Offering.
SALE OF NON-STRATEGIC ASSETS. In an effort to divest certain non-strategic
assets before consummation of the Combination Transaction and the
Offering, MOC sold to Eagle working and royalty interests in certain oil
and natural gas properties located in Michigan and Texas, as well as MOC's
interests in all wells, facilities and equipment associated with such
properties. The properties are located in areas where the Company does not
intend to focus its exploration and production activities. No part of the
Company's 1997 or 1998 capital budgets is allocated to the properties. The
purchase price was $507,411, payable in cash and was distributed to the
shareholders of MOC. The Company believes that the purchase price was
representative of the fair market value of the interests being sold.
SALE AND LEASE OF PRINCIPAL OFFICES. In July 1996 MOC sold its
principal offices located at 3104 Logan Valley Road, Traverse City,
Michigan to C.E. Miller and Betty Miller for $700,000. The Company is
leasing the premises from Mr. and Mrs. Miller under a five-year lease
expiring in August 2001. The lease provides that the rent on the premises
-57-
is $6,058 a month for the first full 11 months of the lease and thereafter
increases by 4% each year. The Company believes that the rental rate is
representative of the fair market rental rate for the premises and that the
purchase price was representative of the fair market value of the property
at the time of sale.
LOAN TO MOC. Pursuant to a promissory note dated November 26, 1997,
C.E. Miller, as trustee of the C.E. Miller Trust, loaned $2.5 million to
MOC, which MOC used to fund a down payment made in connection with the
Combination Transaction. The loan was paid in full during February 1998
from the proceeds received in the Offering.
SHAREHOLDER NOTES
In 1991, the shareholders of MOC loaned to MOC an aggregate of $7.6
million pursuant to separate loan agreements. As of December 31, 1997, no
principal payments had been made on the indebtedness, and all interest due
and payable by that date had been paid. The shareholders of MOC
contributed the indebtedness to the Company as capital in connection with
the Combination Transaction, which resulted in cancellation of the
indebtedness. Such cancellation is not expected to result in income to the
Company for federal income tax purposes.
TAX CREDIT AND ROYALTY PARTICIPATION PROGRAMS
The Company established the Tax Program and the Royalty Program under
which certain key employees were entitled to receive a stated percentage of
tax credits received by the Tax Program and/or royalties paid on certain
prospects generated by the Company. The participants' rights to
participate in the Tax Program and the Royalty Program terminated upon
consummation of the Offering.
CONSULTING AGREEMENT
MOC and Frank M. Burke, Jr., a director of the Company, entered into a
Consulting Agreement dated June 1, 1996, as subsequently amended. Pursuant
to the Consulting Agreement, Mr. Burke provides MOC, as an independent
contractor, certain financial, tax, strategic, marketing and other
consulting services as requested by MOC. As compensation for these
services, MOC has agreed to pay Mr. Burke a fee of $275 per hour. This fee
is scheduled to increase to $325 per hour for services provided during 1998
and to $375 per hour for services provided during and after 1999. MOC also
has agreed to reimburse Mr. Burke reasonable travel and other out-of-pocket
expenses. The initial term of the Consulting Agreement was 12 months and
automatically is renewed for successive 12-month periods unless terminated
by either party upon 30 days' prior notice. For the year ended December
31, 1997, MOC had paid Mr. Burke a total of $30,738 in fees and expenses.
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CERTAIN EXPLORATION PROGRAMS
A portion of the Company's exploration activities have been, and are
expected to continue to be, conducted as an active working interest partner
in select projects proposed in Texas and Louisiana by the Hughes Company
under an exploration agreement in effect since 1994. Dan A. Hughes, Jr., a
director of the Company, is a partner in and Exploration Manager of the
Hughes Company. At the time the exploration agreement was entered into,
Mr. Hughes was not a director of the Company. Revenues attributable to
these properties were approximately $2.0 million and $1.3 million as of
December 31, 1997 and December 31, 1996, respectively. The Company
currently projects capital expenditures with respect to these properties of
approximately $2.9 million in 1998.
In addition, the Company had provided to its affiliated oil and
natural gas exploration companies opportunities to invest in certain oil
and natural gas exploration and development projects in which the Company
already had an interest. In exchange for their interests in a project, the
affiliated companies, which were under common ownership with MOC, were
required to pay their proportionate share of a $50,000 prospect fee charged
by the Company, 110% of the associated drilling costs and their
proportionate share of the royalty interests allocated to the Royalty
Program. This program terminated upon consummation of the Offering.
Any future material transactions between the Company and its
affiliates will be approved by a majority of the disinterested directors of
the Company.
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.
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ITEM 14(a)(3). EXHIBITS.
(a) EXHIBITS
EXHIBIT NO. DESCRIPTION
2.1 Exchange and Combination Agreement dated November 12,
1997. Previously filed as an exhibit 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 Registration Statement on Form
S-1 (333-40383), and here incorporated by reference.
4.1 Certificate of Incorporation. See Exhibit 3.1.
4.2 Bylaws. See Exhibit 3.2.
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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.
10.1(b) Form of Stock Option Agreement.
10.1(c) Form of Restricted Stock Agreement.
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 Form of Employment Agreement for Kelly E. Miller,
William J. Baumgartner, Lew P. Murray and Charles A.
Morrison. Previously filed as an exhibit to the
Company's Registration Statement on Form S-1 (333-40383),
and here incorporated by reference.
10.4 Lease Agreement between Miller Oil Corporation and C.E.
and Betty Miller, dated July 24, 1996. Previously filed
as an exhibit to the Company's Registration Statement on
Form S-1 (333-40383), and here incorporated by
reference.
10.5 Letter Agreement dated November 10, 1997, between Miller
Oil Corporation and C.E. Miller, regarding sale of
certain assets. Previously filed as an exhibit to the
Company's Registration Statement on Form S-1 (333-40383),
and here incorporated by reference.
10.6 Amended Service Agreement dated January 1, 1997, between
Miller Oil Corporation and Eagle Investments, Inc.
Previously filed as an exhibit to the Company's
Registration Statement on Form S-1 (333-40383), and here
incorporated by reference.
10.7 Form of Registration Rights Agreement (included as
Exhibit E to Exhibit 2.1). Previously filed as an
exhibit to the Company's Registration Statement on Form
S-1 (333-40383), and here incorporated by reference.
10.8 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
-61-
Registration Statement on Form S-1 (333-40383), and here
incorporated by reference.
10.9 $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.
10.10 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.
10.11 Credit Agreement between Miller Oil Corporation and Bank
of Montreal dated February 9, 1998.
10.12 Guaranty Agreement by Miller Exploration Company in
favor of Bank of Montreal dated February 9, 1998.
10.13 $75,000,000 Promissory Note of Miller Oil Corporation to
Bank of Montreal dated February 9, 1998.
10.14 Mortgage (Michigan) between Miller Oil Corporation and
James Whitmore, as trustee for the benefit of Bank of
Montreal, dated February 9, 1998.
10.15 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.
10.16 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.
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.
-62-
24.1 Limited Power of Attorney.
27.1 Financial Data Schedule.
____________________
Filed herewith.
Management contract or compensatory plan or arrangement.
-63-
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be
signed on its behalf by the undersigned, thereunto duly authorized.
MILLER EXPLORATION COMPANY
By */s/Kelly E. Miller
Kelly E. Miller
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
March 31, 1998 By */s/C. E. Miller
C. E. Miller
Chairman of the Board
March 31, 1998 By */s/Kelly E. Miller
Kelly E. Miller, Director
(Principal Executive Officer)
March 31, 1998 By */s/William J. Baumgartner
William J. Baumgartner, Director
(Principal Financial and Accounting
Officer)
March 31, 1998 By */s/Frank M. Burke, Jr.
Frank M. Burke, Jr., Director
March 31, 1998 By */s/Dan A. Hughes, Jr.
Dan A. Hughes, Jr., Director
-64-
March 31, 1998 By */s/William Casey McManemin
William Casey McManemin, Director
March 31, 1998 By */s/Kenneth J. Foote
Kenneth J. Foote, Director
*By /s/William J. Baumgartner
William J. Baumgartner, Director
Attorney-in-Fact
-65-
INDEX TO FINANCIAL STATEMENTS
PAGE
COMBINED FINANCIAL STATEMENTS OF MILLER EXPLORATION COMPANY AND
AFFILIATED ENTITIES
Report of Independent Public Accountants . . . . . . . . . . . . . . . F-2
Combined Balance Sheets as of December 31, 1997 and 1996 . . . . . . . F-3
Combined Statements of Operations for the Years Ended
December 31, 1997, 1996 and 1995 . . . . . . . . . . . . . . . . . . . F-4
Combined Statements of Equity for the Years Ended
December 31, 1997, 1996 and 1995 . . . . . . . . . . . . . . . . . . . F-5
Combined Statements of Cash Flows for the Years Ended
December 31, 1997, 1996 and 1995 . . . . . . . . . . . . . . . . . . . F-6
Notes to Combined Financial Statements . . . . . . . . . . . . . . . . F-7
Supplemental Quarterly Financial Data (unaudited). . . . . . . . . . . F-20
STATEMENTS OF THE MILLER EXPLORATION COMPANY ACQUIRED PROPERTIES:
Report of Independent Public Accountants . . . . . . . . . . . . . . . F-21
Historical Statements of Revenues and Direct Operating
Expenses for the Years Ended December 31, 1997, 1996 and
1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-22
Notes to Historical Statements of Revenues and Direct
Operating Expenses . . . . . . . . . . . . . . . . . . . . . . . . . . F-23
UNAUDITED PRO FORMA COMBINED FINANCIAL DATA:
Pro Forma Statement of Operations for the Year Ended
December 31, 1997 (unaudited). . . . . . . . . . . . . . . . . . . . . F-26
Pro Forma Balance Sheet as of December 31, 1997 (unaudited). . . . . . F-27
F-1
ARTHUR ANDERSEN LLP
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders of
Miller Exploration Company:
We have audited the accompanying combined balance sheets of MILLER
EXPLORATION COMPANY (a Delaware corporation) and affiliated entities
identified in Note 1 (collectively, the "Company") as of December 31, 1997
and 1996, and the related combined statements of operations, equity, and
cash flows for each of the three years in the period ended December 31,
1997. 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 combined financial position of the
Company as of December 31, 1997 and 1996, and the combined results of their
operations and their cash flows for each of the three years in the period
ended December 31, 1997, in conformity with generally accepted accounting
principles.
/s/ ARTHUR ANDERSEN LLP
Detroit, Michigan
March 13, 1998
F-2
MILLER EXPLORATION COMPANY AND AFFILIATED ENTITIES
COMBINED BALANCE SHEETS
AS OF DECEMBER 31,
-----------------
1997 1996
-------- -------
(IN THOUSANDS)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . $ 146 $ 410
Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . 2,109 2,246
Inventories and prepaid expenses. . . . . . . . . . . . . . . . . 87 113
Advances to operators . . . . . . . . . . . . . . . . . . . . . . 907 385
Other current assets (Note 2) . . . . . . . . . . . . . . . . . . 2,936 --
-------- -------
Total current assets. . . . . . . . . . . . . . . . . . . . . . 6,185 3,154
-------- -------
OIL AND GAS PROPERTIES at cost (full cost method):
Proved oil and gas properties . . . . . . . . . . . . . . . . . . 29,324 27,883
Unproved oil and gas properties . . . . . . . . . . . . . . . . . 7,069 2,811
Less-Accumulated depreciation, depletion and amortization . . . . (12,425) (9,962)
-------- -------
Net oil and gas properties. . . . . . . . . . . . . . . . . . 23,968 20,732
-------- -------
PROPERTY AND EQUIPMENT NET . . . . . . . . . . . . . . . . . . . . . . 275 164
-------- -------
Total assets. . . . . . . . . . . . . . . . . . . . . . . . . $ 30,428 $24,050
======== =======
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Notes payable . . . . . . . . . . . . . . . . . . . . . . . . . . $ 7,454 $ 3,942
Current portion of long-term debt . . . . . . . . . . . . . . . . 243 216
Accounts payable. . . . . . . . . . . . . . . . . . . . . . . . . 3,831 891
Accounts payable related parties. . . . . . . . . . . . . . . . . 39 218
Oil and gas distributions payable . . . . . . . . . . . . . . . . 289 307
Accrued interest. . . . . . . . . . . . . . . . . . . . . . . . . 50 223
Other accrued expenses. . . . . . . . . . . . . . . . . . . . . . 264 39
-------- -------
Total current liabilities . . . . . . . . . . . . . . . . . . 12,170 5,836
-------- -------
F-3
LONG-TERM DEBT . . . . . . . . . . . . . . . . . . . . . . . . . . . . 481 8,723
DEFERRED REVENUE . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,664 1,722
COMMITMENTS AND CONTINGENCIES (NOTE 7)
EQUITY:
Preferred stock, $0.01 par value; 2,000,000 shares authorized;
none outstanding. . . . . . . . . . . . . . . . . . . . . . . -- --
Common stock, $0.01 par value; 20,000,000 shares authorized; 100
shares outstanding. . . . . . . . . . . . . . . . . . . . . . -- --
Combined equity . . . . . . . . . . . . . . . . . . . . . . . . . 8,588 72
Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . 7,525 7,697
-------- -------
Total equity. . . . . . . . . . . . . . . . . . . . . . . . . 16,113 7,769
-------- -------
Total liabilities and equity. . . . . . . . . . . . . . . . . $ 30,428 $24,050
======== =======
The accompanying notes are an integral part of these combined
financial statements.
F-4
MILLER EXPLORATION COMPANY AND AFFILIATED ENTITIES
COMBINED STATEMENTS OF OPERATIONS
FOR THE YEAR
ENDED DECEMBER 31,
-------------------------------
1997 1996 1995
---- ---- ----
(IN THOUSANDS)
REVENUES:
Natural gas. . . . . . . . . . . . . . . . . . . . $5,819 $5,614 $2,748
Crude oil and condensate . . . . . . . . . . . . . 964 1,101 715
Other operating revenues . . . . . . . . . . . . . 629 395 296
------ ------ ------
Total operating revenues . . . . . . . . . . . 7,412 7,110 3,759
------ ------ ------
OPERATING EXPENSES:
Lease operating expenses and production taxes. . . 1,478 1,123 777
Depreciation, depletion and amortization . . . . . 2,520 2,629 1,666
General and administrative . . . . . . . . . . . . 2,186 1,591 1,270
------ ------ ------
Total operating expenses . . . . . . . . . . . 6,184 5,343 3,713
------ ------ ------
OPERATING INCOME . . . . . . . . . . . . . . . . . . . 1,228 1,767 46
------ ------ ------
INTEREST EXPENSE . . . . . . . . . . . . . . . . . . . (1,200) (1,139) (1,017)
------ ------ ------
LAWSUIT SETTLEMENT . . . . . . . . . . . . . . . . . . -- -- 3,521
------ ------ ------
NET INCOME . . . . . . . . . . . . . . . . . . . . . . $ 28 $ 628 $2,550
====== ====== ======
The accompanying notes are an integral part of these combined
financial statements.
F-5
MILLER EXPLORATION COMPANY AND AFFILIATED ENTITIES
COMBINED STATEMENTS OF EQUITY
COMBINED RETAINED TOTAL
EQUITY EARNINGS EQUITY
-------- -------- ------
(IN THOUSANDS)
BALANCE December 31, 1994 . . . . . . . . . . . . . . . . . . . . . $ 277 $5,319 $ 5,596
Contributions and return of capital, net. . . . . . . . . . . . (136) -- (136)
Net income. . . . . . . . . . . . . . . . . . . . . . . . . . . -- 2,550 2,550
Dividends declared. . . . . . . . . . . . . . . . . . . . . . . -- (600) (600)
------ ------ -------
BALANCE December 31, 1995 . . . . . . . . . . . . . . . . . . . . . 141 7,269 7,410
Contributions and return of capital, net. . . . . . . . . . . . (69) -- (69)
Net income. . . . . . . . . . . . . . . . . . . . . . . . . . . -- 628 628
Dividends declared. . . . . . . . . . . . . . . . . . . . . . . -- (200) (200)
------ ------ -------
BALANCE December 31, 1996 . . . . . . . . . . . . . . . . . . . . . 72 7,697 7,769
Contributions and return of capital, net. . . . . . . . . . . . 8,516 -- 8,516
Net income. . . . . . . . . . . . . . . . . . . . . . . . . . . -- 28 28
Dividends declared. . . . . . . . . . . . . . . . . . . . . . . -- (200) (200)
------ ------ -------
BALANCE December 31, 1997 . . . . . . . . . . . . . . . . . . . . . $8,588 $7,525 $16,113
====== ====== =======
The accompanying notes are an integral part of these combined
financial statements.
F-6
MILLER EXPLORATION COMPANY AND AFFILIATED ENTITIES
COMBINED STATEMENTS OF CASH FLOWS
FOR THE YEAR ENDED
DECEMBER 31,
---------------------------------
1997 1996 1995
---- ---- ----
(IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income . . . . . . . . . . . . . . . . . . . . . . . . . $ 28 $ 628 $ 2,550
Adjustments to reconcile net income to net cash from
operating activities
Depreciation, depletion and amortization . . . . . . . 2,520 2,629 1,666
Deferred revenue . . . . . . . . . . . . . . . . . . . (58) (27) (21)
Lawsuit settlement . . . . . . . . . . . . . . . . . . -- -- (3,521)
Changes in assets and liabilities
Accounts receivable. . . . . . . . . . . . . . . . . 137 (1,010) (200)
Other current assets . . . . . . . . . . . . . . . . (3,432) (360) 67
Accounts payable . . . . . . . . . . . . . . . . . . 2,761 252 (60)
Oil and gas distributions payable. . . . . . . . . . (18) 74 20
Other accrued expenses . . . . . . . . . . . . . . . 52 (24) 10
------- ------- -------
Net cash flows provided by operating activities . 1,990 2,162 511
------- ------- -------
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development expenditures. . . . . . . . . . . (8,822) (6,184) (6,323)
Advance payment of natural gas sales. . . . . . . . . . . . . -- 185 1,439
Proceeds from sale of oil and gas properties and purchases
of equipment, net. . . . . . . . . . . . . . . . . . . . . 2,955 1,256 1,212
Proceeds from lawsuit settlement. . . . . . . . . . . . . . . -- -- 3,521
------- ------- -------
Net cash flows used in investing activities. . . . . (5,867) (4,743) (151)
------- ------- -------
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments of principal . . . . . . . . . . . . . . . . . . . . (572) (55) --
Net borrowing on notes payable. . . . . . . . . . . . . . . . 3,512 2,785 359
Long-term debt borrowing. . . . . . . . . . . . . . . . . . . -- 350 --
Contributions and return of capital, net. . . . . . . . . . . 873 (69) (136)
Payments of dividends . . . . . . . . . . . . . . . . . . . . (200) (200) (600)
------- ------- -------
Net cash flows provided by (used in) financing
activities. . . . . . . . . . . . . . . . . . . . 3,613 2,811 (377)
------- ------- -------
F-7
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS . . . . . . . . . . . . . . . . . . . . . . . . . (264) 230 (17)
CASH AND CASH EQUIVALENTS AT BEGINNING OF THE
PERIOD. . . . . . . . . . . . . . . . . . . . . . . . . . . . 410 180 197
------- ------- -------
CASH AND CASH EQUIVALENTS AT END OF THE PERIOD. . . . . . . . . . $ 146 $ 410 $ 180
======= ======= =======
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid during the period for
Interest . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,373 $ 1,122 $ 1,005
======= ======= =======
The accompanying notes are an integral part of these combined
financial statements.
F-8
MILLER EXPLORATION COMPANY AND AFFILIATED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS
(1) ORGANIZATION, COMBINATION AND NATURE OF OPERATIONS
THE COMBINATION TRANSACTION
Miller Exploration Company ("Miller") was recently formed as a
Delaware corporation 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 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. (all
Michigan corporations owned by the Miller family members who are beneficial
owners of MOC) in exchange for an aggregate consideration of approximately
5.3 million shares of common stock of Miller (the "Common Stock"). The
operations of all of these entities have been managed through the same
management team, and have been owned by the same members of the Miller
family. Miller completed the Combination Transaction concurrently with the
consummation of an initial public offering (the "Offering") of its Common
Stock in February 1998 (see Note 15).
PRINCIPLES OF COMBINATION
The accompanying combined financial statements include the accounts of
Miller, MOC and the other affiliated entities described above, all of which
share common ownership and management (collectively, the "Company"). 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
combined accounts 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.
OTHER TRANSACTIONS COMPLETED CONCURRENTLY WITH THE 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
F-9
MILLER EXPLORATION COMPANY AND AFFILIATED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS - (CONTINUED)
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. The combined financial
statements do not include the activities of these non-affiliated interests.
In November 1997, the Company entered into a Purchase and Sale
Agreement (the "Agreement"), whereby the Company acquired interests in
certain crude oil and natural gas producing properties and undeveloped
properties from Amerada Hess Corporation ("AHC") for approximately $50.5
million, subject to adjustment. This purchase, contemplated by the
Agreement, was consummated concurrently with the Company's Offering. This
acquisition was accounted for under the purchase method of accounting. The
acquisition was financed with the use of proceeds from the Offering and
with new bank borrowings. The combined financial statements do not include
the activities of these AHC interests.
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 three
provinces: the Mississippi Salt Basin of central Mississippi; the onshore
Gulf Coast region of Texas and Louisiana; and the Michigan Basin.
(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
F-10
MILLER EXPLORATION COMPANY AND AFFILIATED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS - (CONTINUED)
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 (net of accumulated depreciation,
depletion and amortization) exceed the sum of discounted estimated future
net cash flows from proved oil and gas reserves (using unescalated prices
and costs and a 10% per annum discount rate) and the lower of cost or
market value of unproved properties, such excess costs are charged against
earnings. The Company did not have any such charges against earnings during
the years ended December 31, 1997, 1996 or 1995.
INCOME TAXES
Before consummation of the Offering, the Company and the combined
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 combined affiliated
entities. Accordingly, no provision was made for income taxes in the
accompanying combined financial statements.
Due to the use of different methods for tax and financial reporting
purposes in accounting for various transactions, including intangible
drilling costs and geological and geophysical costs, and for the sale of
oil and gas properties, 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, $5.8 million and $5.9 million at December 31,
1997, 1996 and 1995 respectively, would have been recorded for this
difference, with a corresponding reduction in retained earnings.
Additionally, had the Company been a taxpaying entity before consummation
of the Offering, an income tax provision (credit) of approximately
$(310,000), $(10,000) and $830,000 would have been recorded for the years
ended December 31, 1997, 1996 and 1995, respectively.
FINANCIAL INSTRUMENTS
The fair value of short-term financial instruments, including cash and
cash equivalents, accounts receivable, accounts payable and accrued
expenses approximate their carrying amounts in the financial statements due
to the short maturity of such instruments.
F-11
MILLER EXPLORATION COMPANY AND AFFILIATED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS - (CONTINUED)
The fair value of notes payable and long-term debt approximate their
carrying amounts in the financial statements as the individual borrowings
bear interest at floating market interest rates.
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.
HEDGING ACTIVITIES
In 1997, the Company began to periodically enter into hedging
arrangements to manage price risks related to crude oil and natural gas
sales and not for speculative purposes. The Company's hedging arrangements
apply only to a portion of its production, provide only partial price
protection against declines in crude oil and natural gas prices and limit
potential gains from future increases in prices. For financial reporting
purposes, gains and losses related to hedging are recognized as income when
the hedged transaction occurs. Historically, gains and losses from hedging
activities have not been material. During 1995 and 1996, the Company did
not hedge any of its crude oil or natural gas production. As of December
31, 1997, the Company had the following volumes of open natural gas
contracts:
F-12
MILLER EXPLORATION COMPANY AND AFFILIATED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS - (CONTINUED)
VOLUME
PRODUCTION PERIOD (MMcf) PRICE/Mcf
----------------- ------ ---------
January 1998 . . . . . . . . . . . 0.9 $ 3.23
February 1998. . . . . . . . . . . 0.9 2.89
March 1998 . . . . . . . . . . . . 0.9 2.59
EARNINGS PER SHARE
Earnings per share has been omitted from the combined statements of
operations since such information is not meaningful and the historically
combined Company is not a separate legal entity with a singular capital
structure. Pro forma earnings per share is presented in the "Pro Forma Data
(unaudited)" section using the weighted average number of common shares
outstanding after giving effect to the Combination Transaction and the
Offering.
OTHER CURRENT ASSETS
At December 31, 1997, other current assets included a $2.5 million
down payment of the purchase price to AHC at the time of the signing of the
Agreement. Additionally, $0.4 million of costs directly attributable to
the Offering have been deferred, and will be charged against the gross
proceeds of the Offering.
RECLASSIFICATIONS
Certain reclassifications have been made to the prior year financial
statements to conform with the 1997 presentation.
STOCK-BASED COMPENSATION
In October 1995, the Financial Accounting Standards Board ("FASB")
issued Statement of Financial Accounting Standards ("SFAS") No. 123,
"Accounting for Stock-Based Compensation." In general, SFAS No. 123
recommends that all stock-based compensation given to employees in exchange
for their services be expensed based on the fair value of the options
granted. During 1997, 1996 and 1995, the Company did not offer any stock-
based compensation to employees, therefore, this standard does not have an
impact on the Company's combined financial statements (see Note 7).
F-13
MILLER EXPLORATION COMPANY AND AFFILIATED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS - (CONTINUED)
PRO FORMA DATA (UNAUDITED)
The pro forma unaudited combined financial data set forth below has
been prepared to give effect to the Combination Transaction and the
Offering and the application of the estimated net proceeds therefrom as if
the Combination Transaction and the Offering occurred on January 1, 1997.
The pro forma unaudited combined financial data is based on numerous
assumptions and is not necessarily indicative of future results of
operations. Pro forma basic and diluted earnings per share has been
computed assuming that the 100 shares issued in connection with the
organization of the Company, 6,929,997 shares issued in connection with the
Combination Transaction and 5,562,500 shares issued in connection with the
Offering have been outstanding since January 1, 1997.
FOR THE YEAR
ENDED DECEMBER 31,
1997
--------------------
(In thousands, except
per share data)
Total operating revenues. . . . . . . . . $25,114
Operating income. . . . . . . . . . . . . 12,273
Net income before income taxes. . . . . . 11,148
Net income. . . . . . . . . . . . . . . . 8,438
Pro forma basic and diluted earnings
per share. . . . . . . . . . . . . . . . $ 0.68
Weighted average number of shares
outstanding. . . . . . . . . . . . . . . 12,493
There were no reconciliation items required between basic and
diluted earnings per share.
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
F-14
MILLER EXPLORATION COMPANY AND AFFILIATED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS - (CONTINUED)
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.
(3) ACCOUNTS RECEIVABLE
Accounts receivable consisted of the following components:
DECEMBER 31, DECEMBER 31,
1997 1996
------ ------
(IN THOUSANDS)
Joint interest receivable . . . . . . $1,318 $1,227
Oil and gas revenue receivable. . . . 791 1,003
Advance billings receivable . . . . . -- 16
------ ------
Total accounts receivable . . . . . . $2,109 $2,246
====== ======
Joint interest receivable represents exploration, development and
production costs paid by the Company on behalf of joint owners in excess of
amounts collected from them. At December 31, 1997 and 1996, the joint
interest receivable balance due from related parties total $957,802 and
$655,263, respectively.
Oil and gas revenue receivable represents the Company's portion of
revenue attributable to production that was uncollected at year end.
Advance billings receivable represents the uncollected portion of
amounts billed by the Company to joint owners in advance of when the
related well costs have been incurred.
F-15
MILLER EXPLORATION COMPANY AND AFFILIATED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS - (CONTINUED)
(4) PROPERTY AND EQUIPMENT - NET
Property and equipment - net 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 5
to 20 years.
Depreciation expense for property and equipment totaled $57,355,
$54,259 and $58,827 for the years ended December 31, 1997, 1996 and 1995,
respectively.
(5) 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 will receive 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 are reflected on a gross basis in
the accompanying combined financial statements and the associated proved
reserves also are reflected in the accompanying supplemental oil and gas
disclosures to the combined financial statements.
During 1995 and 1996, the Company also received advance cash payments
from MSLP of approximately $1.4 million and $185,000, respectively. These
proceeds have been recorded as deferred revenue, which will be recognized
in income as the natural gas volumes under the agreement are delivered.
The payments to be received by the Company, arising from this
agreement, are collateralized by a mortgage on the respective natural gas
properties.
(6) NOTES PAYABLE AND LONG-TERM DEBT
At December 31, 1997 and 1996, the Company had a notes payable balance
of approximately $4.9 million and approximately $3.9 million, respectively,
which represented a borrowing against a $5.0 million bank line-of-credit
bearing interest at the bank's prime rate and another $1.0 million line-
of-credit, which bore interest at the bank's prime rate plus 0.25%. These
notes were collateralized by the Company's reserved interest in the
F-16
MILLER EXPLORATION COMPANY AND AFFILIATED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS - (CONTINUED)
natural gas properties discussed in Note 5. These notes were paid in
full during February 1998 from the proceeds of the Offering.
In November 1997, the Chairman of the Company loaned to MOC $2.5
million, pursuant to a promissory note with interest at the prime rate, for
the purpose of making a down payment in connection with the AHC
acquisition. This note was paid in full during February 1998 from the
proceeds of the Offering.
During 1996, the Company also entered into a $1.0 million term loan
payable to a bank, with interest at the prime rate, maturing September
2000. At December 31, 1997 and 1996 the balance of the term-loan was
approximately $0.7 million and approximately $0.9 million, respectively.
The term loan was paid in full during February 1998 from the proceeds of
the Offering.
The Company also had unsecured notes payable to stockholders, with
interest payable quarterly at 2% over the prime rate. The notes were due in
October 2006 and were subordinate to the two notes payable and the term-
loan. On December 1, 1997, these stockholders contributed the indebtedness
to MOC as capital, resulting in the cancellation of the indebtedness. At
December 31, 1996, the balance of the notes payable to stockholders was
approximately $8.0 million. The weighted average interest rate for all of
the Company's borrowings was 9.6% and 10.0% as of December 31, 1997 and
1996, respectively.
Minimum principal payments on notes payable and long-term debt as of
December 31, 1997 were as follows:
(IN THOUSANDS)
1998. . . . . . . . . . . . . . $7,697
1999. . . . . . . . . . . . . . 264
2000. . . . . . . . . . . . . . 217
------
$8,178
======
In connection with the Offering, in February 1998, the Company entered
into a credit facility (the "New Credit Facility") with Bank of Montreal,
F-17
MILLER EXPLORATION COMPANY AND AFFILIATED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS - (CONTINUED)
Houston Agency ("BOM"). The New Credit Facility consists of a three-year
revolving line of credit converting to a three-year term loan. The amount
of credit available during the revolving period and the debt allowed during
the term period may not exceed the Company's "borrowing base," or the
amount of debt that BOM and the other lenders under the New Credit Facility
agree can be supported by the cash flow generated by the Company's
producing and non-producing proved oil and gas reserves. The initial
borrowing base is $23.0 million and may not exceed $75.0 million. Amounts
advanced under the New Credit Facility bear interest, payable quarterly, at
either (i) BOM's announced prime rate or (ii) the London Inter-Bank Offered
Rate plus a margin rate ranging from 0.75% to 1.625%, as selected by the
Company. In addition, the Company is assessed a commitment fee equal to
0.375% of the unused portion of the borrowing base, payable quarterly in
arrears, until the termination of the revolving period. At the termination
of the revolving period, the revolving line of credit will convert to a
three-year term loan with principal payable in 12 equal quarterly
installments. The New Credit Facility includes certain negative covenants
that impose limitations on the Company and its subsidiaries with respect
to, among other things, distributions with respect to its capital stock,
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 New Credit Facility are secured by
a lien on all real and personal property of the Company, including its oil
and gas properties. The Company borrowed $15.0 million under the New
Credit Facility to complete the Combination Transaction, and to repay all
other outstanding indebtedness described above.
(7) 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. In September 1997, the Company signed into a new
lease agreement in Houston for five additional years.
Future minimum lease payments required of the Company for years ending
December 31, are as follows:
F-18
MILLER EXPLORATION COMPANY AND AFFILIATED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS - (CONTINUED)
(IN THOUSANDS)
1998 . . . . . . . . . . . . . . . $128
1999 . . . . . . . . . . . . . . . 132
2000 . . . . . . . . . . . . . . . 135
2001 . . . . . . . . . . . . . . . 103
2002 . . . . . . . . . . . . . . . 53
Thereafter . . . . . . . . . . . . 9
----
$560
====
Total net rent expense under these lease arrangements was $103,464,
$59,735 and $18,009 for the years ended December 31, 1997, 1996 and 1995,
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. Contributions charged against
operations totaled $64,348, $42,278 and $38,714 for the years ended
December 31, 1997, 1996 and 1995, respectively.
TAX CREDIT AND ROYALTY PARTICIPATION PROGRAMS
Various employees were eligible to participate in the Company's Tax
Credit and Royalty Participation Programs, which were designed to provide
incentive for certain key employees of the Company. Under the programs, the
employees were entitled to receive cash payments from the Company, based on
overriding royalty working interests, fees, reimbursements and other
financial items. These payments to the employees, which have been charged
against operations, totaled $134,916, $116,236 and $139,365 for the years
ended December 31, 1997, 1996 and 1995, respectively. These programs were
terminated upon the consummation of the Offering (see Note 15).
STOCK OPTIONS AND RESTRICTED STOCK
During 1997, the Company adopted the 1997 Stock Option Plan. The Board
of Directors contemplates that the 1997 Stock Option Plan primarily will be
F-19
MILLER EXPLORATION COMPANY AND AFFILIATED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS - (CONTINUED)
used to grant stock options. However, the 1997 Stock Option Plan permits
grants of restricted stock and tax benefit rights if determined to be
desirable to advance the purposes of the 1997 Stock Option 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 Stock Option Plan are directors, corporate officers
and other full-time employees of the Company and its subsidiaries. A
maximum of 1,200,000 shares of Common Stock (subject to certain
antidilution adjustments) are available for Incentive Awards under the 1997
Stock Option Plan. Upon consummation of the Offering in February 1998, a
total of 577,850 Incentive Awards were granted by the Company to directors,
corporate officers and other full-time employees of the Company.
Additionally, upon consummation of the Offering, 109,500 restricted shares
were transferred to certain employees. At the time of the issuance of the
restricted shares, compensation expense of approximately $0.9 million was
deferred. The restricted shares will begin to vest at cumulative increments
of one-half of the total number of restricted shares of Common Stock
subject thereto, beginning on the first anniversary of the date of grant.
Because the restricted shares are subject to the risk of forfeiture during
the vesting period, compensation expense (equivalent to the Offering price
per share of $8.00) will be recognized ratably over the two-year vesting
period as the risk of forfeiture passes.
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.
OTHER
In the normal course of business, the Company may be a party to
certain lawsuits and administrative proceedings. Management cannot predict
the ultimate outcome of any pending or threatened litigation or of actual
or possible claims; however, management believes resulting liabilities, if
any, will not have a material adverse impact upon the Company's financial
position or results of operations.
(8) 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 7). The Company realized
F-20
MILLER EXPLORATION COMPANY AND AFFILIATED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS - (CONTINUED)
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.
The Company provides technical and administrative services to a
corporation controlled by a related party. In connection with this
arrangement, $200,000, $100,000 and $50,000 were recognized as management
fee income (see Note 12) for the years ended December 31, 1997, 1996 and
1995, respectively.
(9) LAWSUIT SETTLEMENT
In November 1995, the Company received approximately $3.5 million as
its respective share of an inverse condemnation lawsuit settlement which is
reported in the 1995 combined statement of operations.
(10) FINANCIAL INSTRUMENTS WITH OFF-BALANCE SHEET RISK AND CONCENTRATIONS
TO CREDIT RISK
OFF-BALANCE SHEET RISK
The Company does not consider itself to have any material financial
instruments with off-balance sheet risks.
CONCENTRATIONS OF CREDIT RISK
Financial instruments that potentially subject the Company to credit
risk include cash on deposit with one financial institution in which these
deposits exceed the Federally insured amount.
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.
F-21
MILLER EXPLORATION COMPANY AND AFFILIATED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS - (CONTINUED)
(11) NON-CASH FINANCING ACTIVITIES
During 1996, the Company transferred $1.0 million of its outstanding
note payable balance to a five-year term-loan, as more fully discussed in
Note 6. This non-cash financing activity has been excluded from the
combined statement of cash flows.
During 1997, the stockholders contributed approximately $7.6 million
of notes payable to MOC as capital, as more fully disclosed in Note 6.
This non-cash financing activity has been excluded from the combined
statement of cash flows.
(12) OTHER OPERATING REVENUES
The majority of the other operating revenues are reimbursements for
general and administrative activities that the Company performs on behalf
of other companies in the oil and gas industry. All other management fees
that were earned for exploration and development activities have been
credited to oil and gas property costs.
(13) 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,
----------------------
1997 1996 1995
---- ---- ----
Amerada Hess Corporation . . . . 39% 51% 44%
Dan A. Hughes Company . . . . . 30% 19% 7%
Muskegon Development Co. . . . . 27% 24% 37%
F-22
MILLER EXPLORATION COMPANY AND AFFILIATED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS - (CONTINUED)
(14) NEW ACCOUNTING STANDARDS
In 1997, the FASB issued SFAS No. 130, "Reporting Comprehensive
Income" and SFAS No. 131, "Disclosures about Segments of an Enterprise and
Related Information," each of which will require expanded disclosures
effective for 1998. The Company does not expect the application of these
statements to have any effect on its financial position, liquidity or
results of operations.
(15) SUBSEQUENT EVENTS
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 5,500,000 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.
(16) 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.
F-23
MILLER EXPLORATION COMPANY AND AFFILIATED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS - (CONTINUED)
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, 1997 and 1996 have been prepared by S.A. Holditch and
Associates (as to Michigan reserves) and Miller and Lents, Ltd. (as to non-
Michigan reserves), independent petroleum engineers. Estimates as of
December 31, 1995 and 1994 have been prepared by the Company's petroleum
engineers. All of the Company's reserves are located in the United States.
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, 1997, 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:
F-24
MILLER EXPLORATION COMPANY AND AFFILIATED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS - (CONTINUED)
TOTAL
------------------------
OIL (MBbl) GAS (MMcf)
---------- ----------
Estimated Proved Reserves
December 31, 1994. . . . . . . . . . . . . . . . . . . 191.7 18,458.1
Revisions and other changes. . . . . . . . . . . . (114.5) (7,491.2)
Extensions and discoveries . . . . . . . . . . . . 102.0 6,134.4
Production . . . . . . . . . . . . . . . . . . . . (31.6) (1,324.0)
Sales of reserves. . . . . . . . . . . . . . . . . (12.6) (15.1)
------ --------
December 31, 1995. . . . . . . . . . . . . . . . . . . 135.0 15,762.2
Revisions and other changes. . . . . . . . . . . . 40.3 2,054.0
Extensions and discoveries . . . . . . . . . . . . 514.9 553.7
Purchase of reserves . . . . . . . . . . . . . . . -- 1,016.1
Production . . . . . . . . . . . . . . . . . . . . (46.5) (2,030.0)
------ --------
December 31, 1996. . . . . . . . . . . . . . . . . . . 643.7 17,356.0
Revisions and other changes. . . . . . . . . . . . 161.6 (1,129.5)
Extensions and discoveries . . . . . . . . . . . . 10.6 3,629.8
Production . . . . . . . . . . . . . . . . . . . . (47.4) (2,241.2)
------ --------
December 31, 1997. . . . . . . . . . . . . . . . . . . 768.5 17,615.1
Estimated Proved Developed Reserves
December 31, 1995. . . . . . . . . . . . . . . . . 55.8 12,625.5
====== ========
December 31, 1996. . . . . . . . . . . . . . . . . 121.0 15,221.2
====== ========
December 31, 1997. . . . . . . . . . . . . . . . . 130.2 13,964.4
====== ========
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
F-25
MILLER EXPLORATION COMPANY AND AFFILIATED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS - (CONTINUED)
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.
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, 1997, 1996 and 1995:
1997 1996 1995
---- ---- ----
(IN THOUSANDS)
Future revenues . . . . . . . . . . . . . . . $ 54,896 $ 74,300 $ 56,792
Future production costs . . . . . . . . . . . (19,091) (21,326) (18,278)
Future development costs . . . . . . . . . . . (5,300) (4,348) (1,711)
-------- -------- --------
Future net cash flows. . . . . . . . . . . . . . . 30,505 48,626 36,803
Discount to present value at 10% annual rate . . . (10,571) (18,561) (14,449)
-------- -------- --------
Standardized measure of discounted future net
cash flows . . . . . . . . . . . . . . . . . $ 19,934 $ 30,065 $ 22,354
======== ======== ========
- -------------
F-26
MILLER EXPLORATION COMPANY AND AFFILIATED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS - (CONTINUED)
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.
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.
Does not include income taxes as the Company was not subject to
federal income taxes until consummation of the Offering in
February 1998. Had the Company been subject to federal income taxes,
the pro forma Standardized Measure of Discounted Future Net Cash Flows
at December 31, 1997 would have been $13,977.
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, 1997, 1996 and 1995:
1997 1996 1995
---- ---- ----
(IN THOUSANDS)
New discoveries. . . . . . . . . . . . . . . . . . $ 4,059 $ 6,318 $ 11,786
Purchase of reserves . . . . . . . . . . . . . . . -- 1,102 --
Sales of reserves in place . . . . . . . . . . . . -- -- (127)
Revisions to reserves. . . . . . . . . . . . . . . 350 7,887 (16,759)
Sales, net of production costs . . . . . . . . . . (5,305) (5,592) (2,685)
Changes in prices. . . . . . . . . . . . . . . . . (22,280) (184) 27,251
Accretion of discount. . . . . . . . . . . . . . . 3,006 2,235 1,619
Changes in timing of production and other. . . . . 10,039 (4,055) (14,920)
-------- ------- --------
Net change during the year . . . . . . . . . . . . $(10,131) $ 7,711 $ 6,165
======== ======= ========
F-27
MILLER EXPLORATION COMPANY AND AFFILIATED ENTITIES
NOTES TO COMBINED 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,
1997 and 1996:
1997 1996
---- ----
(IN THOUSANDS)
Proved properties . . . . . . . . . . . . . . . . . $ 29,324 $ 27,883
Unproved properties . . . . . . . . . . . . . . . . 7,069 2,811
-------- --------
36,393 30,694
Less Accumulated depreciation, depletion
and amortization. . . . . . . . . . . . . . . . . (12,425) (9,962)
-------- --------
$ 23,968 $ 20,732
======== ========
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:
F-28
MILLER EXPLORATION COMPANY AND AFFILIATED ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS - (CONTINUED)
1997 1996 1995
---- -------- ----
(IN THOUSANDS)
Property acquisition costs. . . . . . . . . . . . $4,577 $2,264 $1,123
Exploration costs . . . . . . . . . . . . . . . . 2,226 2,340 2,130
Development costs . . . . . . . . . . . . . . . . 2,019 1,580 3,070
------ ------ ------
Total . . . . . . . . . . . . . . . . . . . . $8,822 $6,184 $6,323
====== ====== ======
- ----------
Includes $757 for the acquisition of proved producing properties.
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,
1997, 1996 and 1995. The results of operations below do not include general
and administrative expenses, general taxes and interest expense.
1997 1996 1995
---- ---- ----
(IN THOUSANDS)
Operating Revenues-
Natural gas . . . . . . . . . . . . . . . . . . $5,819 $5,614 $2,748
Crude oil and condensate. . . . . . . . . . . . 964 1,101 715
------ ------ ------
Total operating revenues . . . . . . . . . . 6,783 6,715 3,463
------ ------ ------
Operating expenses-
Lease operating expenses and production taxes . 1,478 1,123 777
Depreciation, depletion and amortization. . . . 2,520 2,629 1,666
------ ------ ------
Total operating expenses . . . . . . . . . . 3,998 3,752 2,443
------ ------ ------
Results of operations . . . . . . . . . . . . . . . $2,785 $2,963 $1,020
====== ====== ======
F-29
MILLER EXPLORATION COMPANY AND AFFILIATED ENTITIES
SUPPLEMENTAL QUARTERLY FINANCIAL DATA - (CONTINUED)
UNAUDITED QUARTERLY FINANCIAL INFORMATION
QUARTER ENDED
----------------------------------------------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31
-------- ------- -------- -------
(In thousands)
1997
Total Operating Revenues . . . . . $2,308 $1,539 $1,572 $1,993
Operating Income (Loss). . . . . . 903 115 259 (49)
Net Income (Loss). . . . . . . . . 721 (93) (253) (347)
1996
Total Operating Revenues . . . . . $1,440 $1,622 $1,868 $2,180
Operating Income . . . . . . . . . 288 382 677 420
Net Income . . . . . . . . . . . . 81 125 352 70
F-30
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders of
Miller Exploration Company:
We have audited the accompanying historical statements of revenues and
direct operating expenses of the Miller Exploration Company Acquired
Properties identified in Note 1 ("Historical Summaries") for each of the
three years in the period ended December 31, 1997. The Historical Summaries
are the responsibility of Miller Exploration Company's management. Our
responsibility is to express an opinion on the Historical Summaries based
on our audits.
We have 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 Historical Summaries
are free of material misstatement. An audit includes examining on a test
basis, evidence supporting the amounts and disclosures in the Historical
Summaries. An audit also includes assessing the accounting principles used
and significant estimates made by management, as well as evaluating the
overall presentation of the Historical Summaries. We believe that our
audits provide a reasonable basis for our opinion.
The accompanying Historical Summaries were prepared for the purpose of
complying with the Securities and Exchange Commission's rules for inclusion
in Form 10-K as described in Note 1 and is not intended to be a
complete presentation of the Miller Exploration Company Acquired
Properties' revenues and expenses.
In our opinion, the Historical Summaries present fairly, in all
material respects, the revenues and direct operating expenses of the Miller
Exploration Company Acquired Properties for each of the three years in the
period ended December 31, 1997, in conformity with generally accepted
accounting principles.
/s/ ARTHUR ANDERSEN LLP
Detroit, Michigan
March 13, 1998
F-31
MILLER EXPLORATION COMPANY ACQUIRED PROPERTIES
HISTORICAL STATEMENTS OF REVENUES AND
DIRECT OPERATING EXPENSES
FOR THE YEAR ENDED
DECEMBER 31,
--------------------------------
1997 1996 1995
---- ---- ----
(IN THOUSANDS)
REVENUES:
Natural gas. . . . . . . . . . . . . . . . . . . . . . . $15,086 $15,232 $3,810
Crude oil and condensate . . . . . . . . . . . . . . . . 2,822 4,037 2,274
------- ------- ------
Total revenues . . . . . . . . . . . . . . . . . . . . . . . 17,908 19,269 6,084
DIRECT OPERATING EXPENSES:
Lease operating expenses and severance taxes . . . . . . 1,024 1,153 388
------- ------- ------
REVENUES IN EXCESS OF DIRECT OPERATING
EXPENSES . . . . . . . . . . . . . . . . . . . . . . . . . $16,884 $18,116 $5,696
======= ======= ======
The accompanying notes are an integral part of these statements.
F-32
MILLER EXPLORATION COMPANY ACQUIRED PROPERTIES
NOTES TO HISTORICAL STATEMENTS OF REVENUES AND
DIRECT OPERATING EXPENSES
(1) BASIS OF PRESENTATION
The accompanying statements of revenues and direct operating expenses
of the oil and natural gas producing properties represent the interests in
certain producing properties historically owned by several unrelated
investors and by the Amerada Hess Corporation ("AHC") (collectively, the
"Acquired Properties"). The interests in the unrelated investors'
properties were exchanged for shares of common stock of Miller Exploration
Company (the "Company") concurrently with the Company's initial public
offering. The interests in the AHC properties were acquired by the Company
for approximately $50.5 million, subject to adjustment, as part of a
Purchase and Sale Agreement between the Company and AHC. All of these
Acquired Properties are part of the Company's Combination Transaction, as
defined elsewhere in this filing.
The accompanying statements of revenues and direct operating expenses
for each of the three years in the period ended December 31, 1997 do not
include general and administrative expenses, interest income or expense, a
provision for depreciation, depletion and amortization or any provision for
income taxes. This is because these types of indirect operating costs are
not available for these properties as the properties have not been
maintained as a separate pool or business. In addition, historical expenses
are not necessarily indicative of the costs to be incurred by the Company
since these Acquired Properties will be recorded using a new cost basis
(under the purchase method of accounting).
Historical financial information reflecting the financial position,
results of operations and cash flows of the Acquired Properties are not
presented because the entire acquisition cost will be assigned to the oil
and gas property interests. Accordingly, the historical statements of
revenues and direct operating expenses have been presented in lieu of the
financial statements required under Rule 3-05 and Staff Accounting Bulletin
No. 80 of the Securities and Exchange Commission Regulations S-X.
(2) SUPPLEMENTAL FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES
ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES (UNAUDITED)
Reserve information and future net cash flows as of December 31, 1997
and 1996 are based on reports prepared by Miller and Lents, Ltd.,
independent petroleum engineers for the Company, using prices and costs in
effect at each year-end. Estimates as of December 31, 1995 and 1994 have
been presented by the Company's petroleum engineers. All of the Acquired
Properties' reserves are located in the United States.
F-33
MILLER EXPLORATION COMPANY ACQUIRED PROPERTIES
NOTES TO HISTORICAL STATEMENTS OF REVENUES AND
DIRECT OPERATING EXPENSES-(CONTINUED)
Proved reserves are estimated quantities of crude oil and natural gas
which geological and engineering data demonstrate with reasonable certainty
to be recoverable in future years from known reservoirs under existing
economic and operating conditions. Proved developed reserves are those
which are expected to be recovered through existing wells with existing
equipment and operating methods. Listed below are the net quantities of
proved reserves and proved developed reserves for the Acquired Properties.
OIL (MBbls) GAS (MMcf)
----------- ----------
Proved reserve at December 31, 1994. . . . . . . . . . . . 521.6 12,813.3
Extensions and discoveries . . . . . . . . . . . . . . . . 814.4 35,467.1
Revisions and other changes. . . . . . . . . . . . . . . . (392.7) (5,927.4)
Production . . . . . . . . . . . . . . . . . . . . . . . . (132.8) (2,789.7)
------ --------
Proved reserves at December 31, 1995 . . . . . . . . . . . 810.5 39,563.3
Extensions and discoveries . . . . . . . . . . . . . . . . 173.8 1,640.7
Revisions and other changes. . . . . . . . . . . . . . . . (84.9) 4,156.3
Production . . . . . . . . . . . . . . . . . . . . . . . . (189.1) (6,322.5)
------ --------
Proved reserves at December 31, 1996 . . . . . . . . . . . 710.3 39,037.8
Extensions and discoveries . . . . . . . . . . . . . . . . 21.5 1,326.6
Revisions and other changes. . . . . . . . . . . . . . . . (171.2) (1,369.1)
Production . . . . . . . . . . . . . . . . . . . . . . . . (159.4) (6,057.0)
------ --------
Proved reserves at December 31, 1997 . . . . . . . . . . . 401.2 32,938.3
====== ========
Proved developed reserves at December 31, 1995 . . . . . . 693.7 29,996.3
====== ========
Proved developed reserves at December 31, 1996 . . . . . . 413.6 22,268.7
====== ========
Proved developed reserves at December 31, 1997 . . . . . . 321.9 23,779.6
====== ========
F-34
MILLER EXPLORATION COMPANY ACQUIRED PROPERTIES
NOTES TO HISTORICAL STATEMENTS OF REVENUES AND
DIRECT OPERATING EXPENSES-(CONTINUED)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO
PROVED OIL AND GAS RESERVES (UNAUDITED)
The "Standardized Measure of Discounted Future Net Cash Flows Relating
to Proved Oil and Gas Reserves" ("Standardized Measure") is a disclosure
requirement under SFAS No. 69. The Standardized Measure does not purport to
present the fair market value of the proved oil and natural gas reserves.
This would require consideration of expected future economic and operating
conditions, which are not taken into account in calculating the
Standardized Measure.
Under the Standardized Measure, future cash inflows were estimated by
applying year-end prices, adjusted for fixed and determinable escalations,
to the estimated future production of year-end proved reserves. Future cash
inflows were reduced by estimated future production and development costs
based on year-end costs to determine pre-tax cash inflows. Future net cash
inflows were discounted using a 10% annual discount rate to arrive at the
Standardized Measure. The following Standardized Measure and changes in the
Standardized Measure are based on the reserve estimates done at December
31, 1997, 1996 and 1995 on the basis of prices and costs at those
respective dates.
Set forth below is the Standardized Measure relating to proved oil and
gas reserves at December 31, 1997, 1996 and 1995:
1997 1996 1995
---- ---- ----
(IN THOUSANDS)
Future revenues . . . . . . . . . . . . . . . . . . . . . . $ 80,277 $141,946 $132,785
Future production costs . . . . . . . . . . . . . . . . . . (16,739) (23,164) (19,874)
Future development costs . . . . . . . . . . . . . . . . . (6,073) (7,631) (7,588)
-------- -------- --------
Future net cash flows . . . . . . . . . . . . . . . . . . . . . 57,465 111,151 105,323
Discount to present value at 10% annual rate. . . . . . . . . . (14,198) (24,880) (24,976)
-------- -------- --------
Standardized measure of discounted future net cash flows . $ 43,267 $ 86,271 $ 80,347
======== ======== ========
- ------------
F-35
MILLER EXPLORATION COMPANY ACQUIRED PROPERTIES
NOTES TO HISTORICAL STATEMENTS OF REVENUES AND
DIRECT OPERATING EXPENSES-(CONTINUED)
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.
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.
Does not include income taxes as the Company was not subject to
federal income taxes until consummation of the Offering in
February 1998. Had the Company been subject to federal income taxes,
the pro forma Standardized Measure at December 31, 1997 would have
been $32,641.
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
RELATING TO PROVED OIL AND GAS RESERVES (UNAUDITED)
The following is an analysis of the changes in the Standardized
Measure during 1997, 1996 and 1995:
1997 1996 1995
---- ---- ----
(IN THOUSANDS)
New discoveries . . . . . . . . . . . . . . . . . . . . . . . $ 1,938 $ 3,656 $ 34,965
Revisions to reserves . . . . . . . . . . . . . . . . . . . . (8,762) 12,315 (17,945)
Sales, net of production costs. . . . . . . . . . . . . . . . (16,884) (18,116) (5,696)
Changes in prices . . . . . . . . . . . . . . . . . . . . . . (42,094) (6,626) 21,400
Accretion of discount . . . . . . . . . . . . . . . . . . . . 8,627 8,035 2,178
Changes in timing and other . . . . . . . . . . . . . . . . . 14,171 6,660 23,667
-------- -------- --------
Net change during the year. . . . . . . . . . . . . . . . . . $(43,004) $ 5,924 $ 58,569
======== ======== ========
F-36
UNAUDITED PRO FORMA COMBINED FINANCIAL DATA
The pro forma unaudited combined financial data set forth below has
been prepared to give effect to the Combination Transaction and the
Offering and the application of the estimated net proceeds therefrom. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations-Overview." The pro forma unaudited statement of operations for
the year ended December 31, 1997 was prepared on the basis that the
Combination Transaction and the Offering occurred on January 1, 1997. The
pro forma unaudited balance sheet as of December 31, 1997 was prepared on
the basis that the Combination Transaction and the Offering occurred on
December 31, 1997. Pro forma data give effect to the revenues and direct
operating expenses of the properties acquired from the non-affiliated
participants in the Combination Transaction (the "Acquired Properties"). In
addition, the pro forma data are based on assumptions and include
adjustments as explained in the notes to the unaudited pro forma combined
financial statements and are not necessarily indicative of the results of
future operations of the Company. The following financial information
should be read in conjunction with "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and the combined financial
statements.
UNAUDITED PRO FORMA STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 1997
PRO
COMBINED ACQUIRED PRO FORMA FORMA
COMPANY PROPERTIES ADJUSTMENTS COMBINED
-------- ---------- ----------- --------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
Revenues:
Natural gas. . . . . . . . . . $ 5,819 $15,086 $ (131) $20,774
Crude oil and condensate . . . 964 2,822 (75) 3,711
Other operating expenses . . . 629 629
------- ------- ------- -------
7,412 17,908 (206) 25,114
Operating Expenses:
Lease operating expenses and
production taxes. . . . . . 1,478 1,024 (79) 2,423
Depreciation, depletion and
amortization. . . . . . . . 2,520 5,292 7,812
General and administrative . . 2,186 420 2,606
------- ------- ------- -------
6,184 1,024 5,633 12,841
------- ------- ------- -------
Operating income . . . . . . . . . . . 1,228 16,884 (5,839) 12,273
------- ------- ------- -------
F-37
Interest expense . . . . . . . . . . . (1,200) 75 (1,125)
------- ------- ------- -------
Income before income taxes . . . . . . 28 16,884 (5,764) 11,148
Provision for income taxes . . . . . . -- -- (2,710) 2,710
------- ------- ------- -------
Net income . . . . . . . . . . . . . . $ 28 $16,884 $(8,474) $ 8,438
======= ======= ======= =======
Basic and diluted earnings per
common share . . . . . . . . . . . . $ 0.68
=======
Weighed average common shares
outstanding. . . . . . . . . . . . . 12,493 12,493
======= =======
F-38
UNAUDITED PRO FORMA BALANCE SHEET
AS OF DECEMBER 31, 1997
COMBINED PRO FORMA PRO FORMA
ASSETS COMPANY ADJUSTMENTS COMBINED
-------- ----------- ---------
(In thousands)
Current Assets:
Cash. . . . . . . . . . . . . . . . . . . $ 146 $ 41,385 $ 3,353
15,000
(8,178)
(45,000)
Accounts receivable . . . . . . . . . . . 2,109 2,109
Inventories and prepaid expenses. . . . . 87 87
Advances to operators . . . . . . . . . . 907 907
Other current assets. . . . . . . . . . . 2,936 (436) --
(2,500)
-------- -------- --------
6,185 271 6,456
-------- -------- --------
Oil and gas properties, net . . . . . . . . . . . 23,968 50,500 86,731
12,770
(507)
Property and equipment, net . . . . . . . . . . . 275 275
-------- -------- --------
Total assets. . . . . . . . . . . . . . . $ 30,428 $ 63,034 $ 93,462
======== ======== ========
LIABILITIES AND EQUITY
Current Liabilities:
Notes payable . . . . . . . . . . . . . . $ 7,454 $ (7,454) $ --
Current portion of long-term debt . . . . 243 (243) --
Accounts payable. . . . . . . . . . . . . 4,159 564 4,723
Accrued interest. . . . . . . . . . . . . 50 50
Other accrued expenses. . . . . . . . . . 264 264
-------- -------- --------
. . . . . . . . . . . . . . . . 12,170 (7,133) 5,037
-------- -------- --------
Long-term debt . . . . . . . . . . . . . . . . . 481 (481) --
New credit facility . . . . . . . . . . . . . . . -- 15,000 15,000
Deferred revenue. . . . . . . . . . . . . . . . . 1,664 1,664
Other non-current liabilities . . . . . . . . . . -- 3,000 3,000
Deferred income taxes . . . . . . . . . . . . . . -- 2,030 7,465
5,435
F-39
Equity:
Preferred stock . . . . . . . . . . . . . -- --
Common stock. . . . . . . . . . . . . . . -- 55 124
69
Additional paid-in capital. . . . . . . . -- 40,330 61,172
10,671
(507)
(5,435)
16,113
Combined equity . . . . . . . . . . . . . 8,588 (8,588) --
Retained earnings . . . . . . . . . . . . 7,525 (7,525) --
-------- -------- --------
Total equity. . . . . . . . . . . . . . . 16,113 45,183 61,296
-------- -------- --------
Total liabilities and equity. . . $ 30,428 $ 63,034 $ 93,462
======== ======== ========
- ----------
Notes to unaudited pro forma combined financial data:
To reflect the elimination of operating results from certain non-
strategic oil and natural gas assets that were sold by the Company
prior to the Combination Transaction.
To reflect the estimated additional depreciation, depletion and
amortization expense resulting from the acquisition of the Acquired
Properties and the sale of certain non-strategic assets using the
unit-of-production method applied to the basis of the properties
acquired and sold.
To reflect estimated incremental general and administrative expenses
expected to be incurred as a direct result of increased operations
after the Combination Transaction. Such expenses are primarily from
increased salaries and additional new employees to perform
administrative and operational activities ($0.5 million per year) and
the elimination of the Royalty Participation Program ($0.1 million per
year). Excluded from this amount is $275,000 of non-recurring bonuses
paid to certain employees of the Company in connection with the
consummation of the Offering.
To reflect the reduction in interest expense attributable to MOC
shareholder notes being contributed in connection with the Combination
Transaction, resulting in the cancellation of the indebtedness, the
cancellation of other indebtedness with the use of proceeds from the
Offering (see (i) below) and the increase in interest expense from the
new borrowing under the New Credit Facility (see (h) below).
Gives pro forma effect to the application of federal and state income
taxes to the Company as if it were a taxable corporation for the
periods presented. Upon the consummation of the Combination
Transaction, the Company was required to record a one-time non-cash
charge to earnings in connection with establishing a deferred tax
liability on the balance sheet in accordance with SFAS No. 109,
F-40
"Accounting for Income Taxes." If the Combination Transaction had been
consummated for the periods presented, such charge would have been
approximately $5.4 million. The ultimate amount of the recorded charge
is dependent upon a number of factors and cannot be determined until
consummation of the Combination Transaction. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations-Overview."
To reflect the issuance of Common Stock in exchange for certain of the
Combined Assets in the Combination Transaction and the issuance of
Common Stock in the Offering.
To reflect the estimated net proceeds of the Offering.
To reflect borrowings under the New Credit Facility to fund the
purchase price for the cash portion of the Combination Transaction.
To reflect the use of proceeds to repay certain outstanding
indebtedness.
To reflect the purchase price for the cash portion of the Combination
Transaction and the associated cash payment due at the time of the
Combination Transaction and other non-current liabilities necessary to
finance this portion of the Combination Transaction.
To reflect the fair value of the Combined Assets contributed by the
unaffiliated entities in the Combination Transaction, a deferred tax
liability in accordance with SFAS No.109, "Accounting for Income
Taxes," for the difference between the financial reporting basis and
the tax basis of the Combined Assets contributed and the exchange of
Common Stock for certain of these assets.
To reflect the reduction in the cost basis of the non-strategic
properties sold prior to consummation of the Combination Transaction,
and the payment of these proceeds to MOC's existing shareholders.
To reflect a deferred tax liability in accordance with SFAS No. 109,
"Accounting for Income Taxes," for the difference between the
financial reporting basis and the tax basis of the Company, after
consummation of the Combination Transaction.
To reflect the reclassification of combined equity and the
reclassification of retained earnings as additional paid-in capital,
upon MOC's termination of its S corporation status.
F-41
EXHIBIT INDEX
Exhibit No. Description
2.1 Exchange and Combination Agreement dated November 12, 1997.
Previously filed as an exhibit 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 Registration Statement on Form S-1 (333-40383),
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.
10.1(b) Form of Stock Option Agreement.
10.1(c) Form of Restricted Stock Agreement.
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 Form of Employment Agreement for Kelly E. Miller, William J.
Baumgartner, Lew P. Murray and Charles A. Morrison.
Previously filed as an exhibit to the Company's Registration
Statement on Form S-1 (333-40383), and here incorporated by
reference.
10.4 Lease Agreement between Miller Oil Corporation and C.E. and
Betty Miller, dated July 24, 1996. Previously filed as an
exhibit to the Company's Registration Statement on Form S-1
(333-40383), and here incorporated by reference.
10.5 Letter Agreement dated November 10, 1997, between Miller Oil
Corporation and C.E. Miller, regarding sale of certain assets.
Previously filed as an exhibit to the Company's Registration
Statement on Form S-1 (333-40383), and here incorporated by
reference.
10.6 Amended Service Agreement dated January 1, 1997, between
Miller Oil Corporation and Eagle Investments, Inc. Previously
filed as an exhibit to the Company's Registration Statement on
Form S-1 (333-40383), and here incorporated by reference.
10.7 Form of Registration Rights Agreement (included as Exhibit E
to Exhibit 2.1). Previously filed as an exhibit to the
Company's Registration Statement on Form S-1 (333-40383), and
here incorporated by reference.
10.8 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.
-2-
10.9 $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.
10.10 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.
10.11 Credit Agreement between Miller Oil Corporation and Bank of
Montreal dated February 9, 1998.
10.12 Guaranty Agreement by Miller Exploration Company in favor of
Bank of Montreal dated February 9, 1998.
10.13 $75,000,000 Promissory Note of Miller Oil Corporation to Bank
of Montreal dated February 9, 1998.
10.14 Mortgage (Michigan) between Miller Oil Corporation and James
Whitmore, as trustee for the benefit of Bank of Montreal,
dated February 9, 1998.
10.15 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.
10.16 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.
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.
24.1 Limited Power of Attorney.
27.1 Financial Data Schedule.
____________________
Filed herewith.
Management contract or compensatory plan or arrangement.
-3-