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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-KSB/A
AMENDMENT NO. 2 TO
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year Commission file number 0-21702
ended December 31, 1997
MIDDLE BAY OIL COMPANY, INC.
(Exact Name of Registrant as Specified in Its Charter)
ALABAMA 63-1081013
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification No.)
1221 LAMAR STREET, SUITE 1020
HOUSTON, TEXAS 77010
(Address of Principal Executive Offices) (Zip Code)
Registrant's telephone number, including area code: (713) 759-6808
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange on
Title of Each Class Which Registered
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None N/A
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, $.02 Par Value
Check whether the Registrant (1) filed all reports required to be filed by
Section 13 or 15(d) of the Exchange Act during the past 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. [X]
Check if disclosure of delinquent filers in response to Item 405 of Regulation
S-B is not contained in this form, 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-KSB or any amendment to
this Form 10-KSB. [X]
Revenues of Registrant for fiscal year ended December 31, 1997 are $11,432,995.
The aggregate market value as of March 16, 1998 of voting stock held by
nonaffiliates of the Registrant was $6,409,463.
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Indicate the number of shares outstanding of each of the Registrant's classes of
common equity, as of the latest practicable date (applicable only to corporate
Registrants).
7,830,766 Shares of Common Stock, $.02 Par Value, as of March 16, 1998
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Item 13(a) includes the Index of Exhibits to be filed with the Securities and
Exchange Commission relative to this Report.
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This Amendment No. 2 on form 10-KSB/A contains expanded disclosure relating to
the prior issuance and conversion of Series "A" Preferred Stock. No other
information in the Report has been amended.
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Glossary of Terms
The following are definitions of certain technical terms used in this
Form 10-KSB in connection with the oil and gas exploration and development
business of the Company:
"Bbl" - One stock tank barrel or 42 U.S. Gallons liquid
volume, usually used herein in reference to crude oil or other liquid
hydrocarbons.
"Bcf" - One billion cubic feet; expressed, where gas sales
contracts are in effect, in terms of contractual temperature and pressure basis
and, where contracts are nonexistent, at 60 degrees Fahrenheit and 14.65 pounds
per square inch absolute.
"BOE" - Equivalent barrels of oil and, with reference to
natural gas, natural gas equivalents are determined using the ratio of six Mcf
of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
"Developed Acreage" - The number of acres which are allocated
or assignable to producing wells or wells capable of production.
"Development Well" - A well drilled as an additional well to
the same reservoir as other producing wells on a Lease, or drilled on an offset
Lease not more than one location away from a well producing from the same
reservoir.
"Exploratory Well" - A well drilled in search of a new
undiscovered pool of oil or gas, or to extend the known limits of a field under
development.
"Gross Acres or Wells" - The total acres or wells, as the case
may be, in which an entity has an interest, either directly or through an
affiliate.
"Lease" - Full or partial interests in an oil and gas lease,
oil and gas mineral rights, fee rights or other rights, authorizing the owner
thereof to drill for, reduce to possession and produce oil and gas upon payment
of rentals, bonuses and/or royalties. Oil and gas leases are generally acquired
from private landowners and federal and state governments.
"Mcf" - One thousand cubic feet; expressed, where gas sales
contracts are in effect, in terms of contractual temperature and pressure bases
and, where contracts are nonexistent, at 60 degrees Fahrenheit and 14.65 pounds
per square inch absolute.
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"Net Acres or Wells" - A party's interest in acres or wells
calculated by multiplying the number of Gross Acres or Gross Wells in which such
party has an interest by the fractional interest of such party in each such acre
or well.
"Operating Costs" - The expenses of producing oil or gas from
a formation, consisting of the costs incurred to operate and maintain wells and
related equipment and facilities, including labor costs, repair and maintenance,
supplies, insurance, production, severance and other production excise taxes.
"Producing Property" - A property (or interest therein)
producing oil and gas in commercial quantities or that is shut-in but capable of
producing oil and gas in commercial quantities, to which Producing Reserves have
been assigned by an independent petroleum engineer. Interests in a property may
include Working Interests, production payments, Royalty Interests and other
non-Working Interests.
"Prospect" - An area in which a party owns or intends to
acquire one or more oil and gas interests which is geographically defined on the
basis of geological data and which is reasonably anticipated to contain at least
one reservoir of oil, gas or other hydrocarbons.
"Proved Developed Reserves" - Proved Reserves which can be
expected to be recovered through existing wells with existing equipment and
operating methods.
"Proved Reserves" - The estimated quantities of crude oil,
natural gas and other hydrocarbons which, based upon geological and engineering
data, are expected to be produced from known oil and gas reservoirs under
existing economic and operating conditions, and the estimated present value
thereof based upon the prices and costs on the date that the estimate is made
and any price changes provided for by existing conditions.
"PV 10%" - The discounted future net cash flows for proved oil
and gas reserves computed using prices and costs, at the dates indicated, before
income taxes and a discount rate of 10%.
"Royalty Interest" - An interest in an oil and gas property
entitling the owner to a share of oil and gas production free of the costs of
production.
"Undeveloped Acreage" - Oil and gas acreage (including, in
applicable instances, rights in one or more horizons which may be penetrated by
existing well bores, but which have not been tested) to which Proved Reserves
have not been assigned by independent petroleum engineers.
"Working Interest" - The operating interest under a Lease
which gives the owner the right to drill, produce and conduct operating
activities on the property and a share of production, subject to all Royalty
Interests, and other burdens and to all costs of exploration, development and
operations and all risks in connection therewith.
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PART I
ITEM 1. DESCRIPTION OF BUSINESS
(a) Business Development
Middle Bay Oil Company, Inc. (the "Company") is an independent
oil and gas company engaged in the exploration, development and production of
oil and gas in the contiguous United States. The Company's strategy focuses on
increasing its reserves of crude oil and natural gas by the acquisition and
development of proved oil and gas properties primarily in the Mid-Continent and
Gulf Coast regions. The Company believes the current period reflects
historically low market prices for oil and gas and is focusing its efforts on
increasing reserves so that it will be well positioned to benefit in the event
of any future increases in demand for natural gas and oil. Consistent with these
efforts, the Company is participating on a limited basis in drilling and
development activities in other geographic regions of the contiguous United
States. In November, 1997, the Company relocated its principal executive offices
to 1221 Lamar Street, Suite 1020, Houston, Texas 77010. The Company's mailing
address is P.O. Box 53448, Houston, Texas 77052-3448. Its telephone number is
(713) 759-6808.
The Company was incorporated under the Alabama Business
Corporation Code on November 30, 1992. Effective December 31, 1992, all of the
assets of Bay City Consolidated Partners, L.P., an Alabama limited partnership
(the "Predecessor Partnership"), were transferred to the Company in exchange for
common stock of the Company. The Predecessor Partnership was then dissolved
under the Alabama Uniform Limited Partnership Act. The shares of common stock of
the Company then owned by the limited partnership were distributed to the
general partner and the limited partners prorata in accordance with their
respective interests in the limited partnership. References to the Company
include, as the context requires, the Predecessor Partnership.
On April 3, 1996, the Company entered into a Joint Expense and
Participation Agreement (the "Brigham Agreement") with Brigham Oil and Gas,
L.P., now Brigham Exploration Company ("Brigham"). The Brigham Agreement allowed
the Company to participate in all of the wells that Brigham drilled over the
12-month period beginning April 1, 1996. The Company advanced Brigham a total of
$1,945,000 to drill 61 wells, of which 43 were successfully completed.
On September 4, 1996, the Company entered into a stock
purchase agreement ("the Preferred Stock Agreement") with Kaiser Francis Oil
Company ("Kaiser-Francis") whereby Kaiser-Francis agreed to purchase 1,666,667
shares of Series A Preferred Stock (the "Series A") at $6.00 per share, for a
total investment of $10,000,000. On January 31, 1998, Kaiser-Francis converted
100% of the Series A shares into 3,333,334 common shares of the Company. Prior
to their conversion to common stock, the Series A were nonvoting and accrued
dividends at 8% per annum, payable quarterly in cash, and were convertible at
any time into two shares of common stock for each Series A share held prior to
January 1, 1998. The conversion rate decreased thereafter at 8% per annum.
Kaiser-Francis is a privately-held company whose majority shareholder is
George B. Kaiser.
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On December 17, 1996, the Company entered into an Agreement
and Plan of Merger (the "NPC Merger") with NPC Energy Corporation ("NPC"),
whereby NPC would be merged into the Company in exchange for Company common
stock and cash. The NPC Merger was approved by NPC's shareholders and closed on
December 31, 1996. NPC was a privately-owned domestic exploration and production
company with assets located in Kansas, Michigan, Oklahoma, Texas and Wyoming.
Pursuant to the NPC Merger, the Company issued 562,000 shares of its common
stock and paid $1,226,400 to NPC in exchange for all of the stock of NPC. The
cash funding for the NPC Merger was financed through the issuance of 166,667
shares of Series A for $1.0 million. The NPC Merger added approximately 503
thousand barrels of oil and 3,139 million cubic feet of gas, for a total proved
reserve value of $6.0 million (PV 10%) as of December 31, 1996, using December
31, 1996 prices.
On February 10, 1997, the Company entered into an Agreement
and Plan of Merger (the "Bison Merger") with Bison Energy Corporation ("Bison"),
whereby Bison was merged with a wholly-owned subsidiary of the Company in
exchange for Company common stock and cash. The Bison Merger was approved by
Bison's sole shareholder and closed on February 28, 1997. Bison was a
privately-held, domestic exploration and production company with assets located
in Kansas and Oklahoma. Pursuant to the Bison Merger, the Company issued
1,167,556 shares of its common stock and net cash consideration of $5,900,000 to
Bison in exchange for all of the stock of Bison. 562,000 shares of Company
common stock owned by Bison (as a result of the NPC Merger) were canceled at
closing. The cash portion of the Bison Merger was financed through the issuance
of 1,000,000 shares of Series A for $6.0 million. The Bison Merger added
approximately 951 thousand barrels of oil and 7,791 million cubic feet of gas,
for a total proved reserve value of $8.94 million (PV 10%) as of February 28,
1997, using December 31, 1997 prices.
On June 20, 1997, the Company entered into an Agreement and
Plan of Merger (the "Shore Merger") with Shore Oil Company ("Shore"), whereby
Shore was merged with a wholly-owned subsidiary of the Company in exchange for
Company common stock, Series B preferred stock (the "Series B"), cash and the
assumption of Shore debt. The Shore Merger was approved by Shore's shareholders
and closed on June 30, 1997. Shore was a privately-held, domestic exploration
and production company with oil and gas properties located primarily in Alabama,
Louisiana, Mississippi and Texas, as well as approximately 42,000 net mineral
acres in LaFourche, Terrebonne and St. Mary Parishes, Louisiana. Pursuant to the
Shore Merger, the Company issued 1,883,333 shares of its common stock, paid
Shore's indebtedness to its shareholders of $2,333,303 and assumed bank debt of
$2,105,000. In addition, the Company paid $200,000 in cash and issued 266,667
shares of Series B which are convertible into as many as 1,333,333 shares of
common stock over the next five years, contingent upon the results of drilling
and leasing activity on Shore's Louisiana mineral acreage. The cash funding for
the Shore Merger was financed through the issuance of 500,000 shares of Series A
for $3.0 million. The Shore Merger added approximately 965 thousand barrels of
oil and 1,364 million cubic feet of gas, for a total proved reserve value of
$6.0 million (PV 10%) as of July 1, 1997, using December 31, 1997 prices. The
Shore Merger also added approximately 42,000 net acres of fee minerals situated
in Lafourche, Terrebonne and St. Mary Parishes in Louisiana that were valued at
approximately $3.6 million at June 30, 1997.
In connection with the Shore Merger, effective August 25,
1997, the Bank of Oklahoma, National Association (the "Bank") converted the
Company's $15 million convertible credit facility into a $50 million convertible
credit facility. The credit facility requires monthly payments of interest only
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at a fixed rate of Libor plus 1.75% as long as the principal amount borrowed is
less than 75% of the current borrowing base of $15 million. If the principal
amount of the loan is greater than or equal to 75% of the borrowing base the
rate increases to Libor plus 2.00%. The Company has the option of switching to a
floating prime rate. The credit facility converts into a term note on March 31,
1998 payable in seventy-one consecutive equal monthly principal and interest
payments, with the remaining principal and interest payment due on March 31,
2004.
The credit facility is secured by a first mortgage on a
portion of the Company's existing properties selected by the Bank as collateral
from time to time, and the Bank has an option to collateralize 100% of the
Company's proved reserves. In the event that a mortgaged property is sold, upon
prior written consent of the Bank, the greater of 65% of the gross sales price
or 65% of the discounted present worth of the mortgaged property will be applied
to the outstanding principal balance of the loan in the inverse order of the due
date of scheduled monthly installments.
The significant financial covenants contained in the
Convertible Loan Agreement include a requirement that the Company maintain a
balance sheet current ratio of at least 0.9 to 1.0. The current ratio
computation excludes all accounts receivable from certain affiliates and current
maturities of long-term debt. The Convertible Loan requires the prior written
consent of the Bank before the Company can, among other things, (a) create or
assume any debt, with specified exceptions, (b) create or permit to exist any
liens on the mortgaged properties, with certain exceptions, (c) sell or dispose
of any property if such sale or disposition exceeds $150,000 per transaction, or
(d) merge into or consolidate into any other entity.
The initial borrowing base at closing of the $50 million
Convertible Loan on August 25, 1997, was $15 million. The borrowing base is
redetermined on March 31 and September 30, commencing September 30, 1997, by the
Bank's engineers or any other independent engineer using the Bank's pricing and
discount factors and the future net revenue expected to be produced from the
Company's oil and gas reserves. If at any time during the period of the loan
(and the period subsequent to the conversion to the term note) the collateral
borrowing base, as determined by the Bank, should be less than the aggregate
unpaid principal balance of the note, the collateral deficiency shall be cured
by making a cash prepayment on the note in the amount of the deficiency or by
increasing the monthly principal payments for the next six months to reduce the
principal balance to the projected borrowing base as of the next semiannual
redetermination date. As of December 31, 1997, the principal balance of the loan
was $10,956,298.
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(b) Business of the Company
The Company's oil and gas reserves are principally in
long-lived fields with well-established production histories. The Company's net
Proved Reserves, estimated as of December 31, 1997 by applying S.E.C.
assumptions, consisted of approximately 18,419 million cubic feet of gas and
2,933 thousand barrels of oil, with an aggregate present value before income
taxes, at a 10% discount, of $30,179,000. Approximately 80% of the reserves are
classified as proved developed producing, 7% are proved developed non-producing
and 13% are proved undeveloped. On an equivalent barrel basis, the proved
reserves are 55% gas. Recoverable volumes of gas increased 105% and recoverable
volumes of oil increased 111% over 1996 volumes. The PV10% of the oil and gas
reserves increased 34% over the 1996 amount of $22,465,000. The reserves are
located primarily in Alabama, Kansas, Louisiana, Oklahoma and Texas. A
substantial portion of the Company's natural gas production and Proved Reserves
consist of high BTU gas which, because of its rich liquid content and its
proximity to processing and transmission facilities, is generally sold at a
premium to Gulf Coast and Mid-Continent spot market prices. Substantially all of
the Company's oil production is sold at market responsive prices. All of the
Company's gas production, except for the gas sold in the Spivey Field, is sold
at market responsive prices.
Business Strategy. The Company's present business strategy is
to concentrate on expanding its asset base and cash flow primarily through
emphasis on the following activities:
- Increasing production, cash flow and asset value by
acquiring Producing Properties with stable production
rates, long reserve lives and potential for
exploitation and development;
- Building on the Company's existing base of operations
by concentrating its development activities in its
primary operating areas in the Gulf Coast and the
Mid-continent Regions;
- Acquiring additional properties with potential for
developmental drilling to maintain a significant
inventory of undeveloped Prospects and to enhance the
Company's foundation for future growth;
- Serving as operator of its wells to ensure technical
performance and reduce costs;
- Expanding its relationships with major and large
independent oil and gas companies to access their
undeveloped properties, seismic data and financial
resources;
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- Managing financial risk and mitigating technical risk
by:
- drilling in known productive trends with
multi-horizon geologic potential;
- diversifying investment over a large number
of wells in the Company's primary operating
areas;
- developing properties that provide a balance
between short and long reserve lives; and
- keeping a balanced reserve profile between
oil and gas; and
- Maintaining low general and administrative expenses
and increasing economies of scale to reduce per unit
operating costs and reserve acquisition costs.
Acquisition Policy. The Company continues to pursue a program
of actively acquiring producing oil and gas properties, with the goal of
increasing cash flow, reserves and value for the long-term benefit of its
stockholders.
The Company utilizes an acquisitions' screening approach with
its experienced management and technical staff which reviews potential property
against multiple criteria, both quantitative and subjective. The Company
generally seeks Producing Properties with established production histories. The
Company may operate the property acquired; however, the Company also considers
nonoperated property acquisitions.
In evaluating Producing Properties for potential acquisition,
production history, reservoir characteristics and available geologic data and
interpretations are analyzed to determine estimates of proved and other reserves
and cash flows expected to be recovered. Also evaluated are specific risks and
economic considerations associated with the property, including environmental
liabilities, risks of curtailment, condition of equipment and potential for
additional development opportunities. Sales contracts, operating agreements and
other contractual commitments, including take-or-pay clauses, market-out
clauses, gas balancing agreements, transportation agreements and reversionary
interests that may affect the cash flows from the property are also reviewed.
Drilling Activities. The Company has participated in drilling
operations primarily in Texas, Louisiana and Kansas. The Company's drilling
activity increased significantly in 1996 when the Company executed the Brigham
Agreement. The Company's drilling is funded principally from cash flow and is
highly dependent on the price of oil and gas. If the price of oil continues to
remain at or near the March 1998 levels, the amount of funds available for
drilling could be reduced.
For the twelve months ended December 31, 1997, the Company
drilled 42 gross wells; 23 Development Wells and 19 Exploratory Wells. Seventeen
of the Development Wells and 8 of the Exploratory Wells were successful. The
Company's drilling was concentrated in Kansas, Louisiana and Texas, where 14, 12
and 7 wells were drilled, respectively. The majority of the Kansas wells were
Development Wells drilled in the Spivey Field (the "Spivey Field"). Two
unsuccessful Exploratory Wells were drilled in the Reflection Ridge Prospect in
Stanton County, Kansas. No further exploration is anticipated on the Reflection
Ridge Prospect. For the three months ended March 31, 1997, the Company
participated in the drilling of 12 Exploratory Wells through the Brigham
Agreement. The Brigham Agreement ended March 31, 1997.
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Shore Oil Company #1, an Exploratory Well being drilled as of
December 31, 1997, was found to be unsuccessful in February, 1998. This
Exploratory Well was drilled on the Raceland Prospect in Lafourche Parish,
Louisiana which is located on the fee mineral acreage acquired in the Shore
Merger. The Company had prepaid approximately $300,000 in drilling cost as of
December 31, 1997 and expensed the costs in the fourth quarter when it was
determined that the well was abandoned.
For the twelve months ended December 31, 1996, the Company
drilled 54 wells, 5 Developmental Wells and 49 Exploratory Wells. Four of the
Developmental Wells and 31 of the Exploratory Wells were successful. For the
nine months ended December 31, 1996, the Company participated in the drilling of
49 Exploratory Wells through the Brigham Agreement. Forty wells were drilled in
Texas, seven in Oklahoma, one in Kansas and one in New Mexico. The Company also
participated in the drilling of four Developmental Wells in the Frymire
Waterflood Unit in Nolan County, Texas, three of which were successful and one
of which was a dry hole. One successful Developmental Well was drilled in the
Campbell Field in Major County, Oklahoma.
Drilling activities during 1997 added 22 thousand barrels of
oil and 705 million cubic feet of gas with estimated future net revenues,
discounted at 10%, of $851,000. Drilling activities during 1996 added 76
thousand barrels of oil and 392 million cubic feet of gas with estimated future
net revenues, discounted at 10%, of $1,966,000. For the years 1996 and 1997, oil
and gas reserves discovered through current year drilling accounted for 11% and
3%, respectively, of the year-end reserve value.
In 1995, the Company entered into a joint development
agreement, the Quarry Prospect, with Chesapeake Operating, Inc. ("COI"). The
agreement covers a 600-acre block of leases in Lea County, New Mexico assembled
by the Company and COI. The Quarry Prospect is believed to be a large strawn
algal mound that was initially identified through 2-D seismic and further
defined using 3-D seismic testing. In 1997, the Company acquired additional
leases in the prospect and sold 50% of the Quarry Prospect. The Company and COI
together retained 50% of the Quarry Prospect. If COI elects not to participate,
the Company's interest will be increased to 50%. The first well on the Quarry
Prospect is expected to spud in the second quarter of 1998 and will cost the
Company approximately $141,000 to drill and $66,000 to complete (assuming a 25%
working interest).
In July 1997, the Company executed an exploration agreement
with Brigham Exploration Company ("Brigham") for a 3-D seismic exploration
project on the Hawkins Ranch (the "Ranch") in Matagorda County, Texas. The Ranch
has been lease optioned for a 54 square mile 3-D seismic survey. The Company
purchased a 25% working interest through the lease selection phase of the
project for $225,000.
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The Company purchased a 12.5% working interest in the
Sherburne Prospect in Point Coupee Parish, Louisiana, in October, 1997 (the
"Sherburne Prospect"). The Sherburne Prospect consists of approximately 10,000
acres that are prospective in the Frio, Cockfield, Sparta and Wilcox formations.
The acreage is located in Southwest Point Coupee Parish between Krotz Springs
Field and the Fordoche Field. Production is at depths from 6,500' to 15,500'.
Swift Energy Company has a 62.5% working interest and will be the operator. A
private company holds the remaining 25%. The first well was spud on March 11,
1998 with an estimated dry hole cost to the Company of approximately $300,000.
In the foreseeable future, the Company's primary drilling
focus will be its participation in the Sherburne Prospect, the Ranch Prospect,
the Quarry Prospect and the development of the Spivey Field. The Company expects
to drill several Development Wells in the Spivey Field in Kansas in 1998. The
Company also expects several wells to be drilled on the Shore mineral acreage in
South Louisiana in 1998. In addition, the Company is continually evaluating
Prospects originated by its staff, other independent geologists or other oil and
gas companies. If review of a certain Prospect indicates that it may be
geologically and economically attractive, then the Company will attempt to
obtain a Lease on the applicable acreage or commit to a Working Interest in the
drilling Prospect. When the Company does participate in a Prospect, it will
typically acquire a fractional Working Interest in the Prospect, which may range
from small percentage interests in more expensive exploratory Prospects to a
majority interest in a lower cost or development Prospect. The Company believes
that such participation, which is common practice in the oil and gas industry,
allows for further diversification and reduction of risk.
Acquisitions and Mergers. Since its formation, the Company has
grown primarily through acquisitions of proven oil and gas reserves. For the
years 1993 through 1997, acquisitions of reserves accounted for 64%, 5%, 35%,
34% and 80% of the year-end discounted reserve value, respectively. The Company
has financed its acquisitions primarily by utilizing its credit facility with
the Bank and issuing common and preferred stock. (See "Company
Financing," below.)
In August 1997, the Company acquired a 5.74% working interest
in proved reserves in the Riceville Field in Vermilion Parish, Louisiana for
approximately $3.5 million. The acquisition was financed with $3 million in loan
proceeds and the remainder from cash on hand. The Riceville Acquisition added
approximately 63 thousand barrels of oil and 2,955 million cubic feet of gas to
the Company's proved reserves. A portion of the reserves is proved undeveloped.
The Riceville Acquisition had a PV10% of approximately $5.3 million, using
December 31, 1997 prices.
The Shore Merger in June 1997 added approximately 965 thousand
barrels of oil and 1,364 million cubic feet of gas to the Company's proved
reserves. A portion of the reserves consists of proven behind pipe and proven
undeveloped reserves. The Shore Merger had a PV 10% of approximately $6.0
million, using December 31, 1997 prices. The Shore Merger also added
approximately 42,000 net acres of minerals located in South Louisiana, which
were valued at $3.6 million at June 30, 1997.
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The Bison Merger in February, 1997 added approximately 951
thousand barrels of oil and 7,791 million cubic feet of gas to the Company's
proved reserves. A portion of the reserves consists of proven behind pipe and
proven undeveloped reserves. The Bison Merger had a PV 10% of approximately $8.9
million, using December 31, 1997 prices.
The NPC Merger in December, 1996 added approximately 503
thousand barrels of oil and 3,139 million cubic feet of gas to the Company's
proved reserves. A portion of the reserves consists of proven behind pipe and
proven undeveloped reserves. The NPC Merger had a PV 10% of approximately $6.0
million, using December 31, 1996 prices.
The Company is currently in the process of evaluating various
corporate acquisitions and potential mergers in exchange for common stock of the
Company. Management believes that corporate acquisitions and mergers are the
fastest way to achieve the Company's growth goals. In addition to achieving what
management perceives to be a proper critical mass, potential corporate
acquisitions or mergers are also considered as opportunities to build a more
diverse oil and gas property base for further development and exploration.
The price of oil has declined significantly since December 31,
1997 and, in March, 1998, reached the lowest level in ten years. The posted
price of WTI crude declined from approximately $15 per barrel on December 31,
1997 to approximately $13 per barrel on March 16, 1998. If oil prices remain at
or near these levels, the funds available for acquisitions could be reduced.
Company Financing. The Company has financed its acquisitions
with debt proceeds from the Bank, issuance of convertible preferred stock and
issuance of common stock. The Company currently has approximately $11 million
borrowed on the $50.0 million Convertible Loan with the Bank of Oklahoma
described under "Business Development," above. In 1997, the Company issued the
remaining $9.0 million in Series A Preferred Stock through its $10.0 million
Preferred Stock Agreement to finance portions of the Bison and Shore mergers.
This completed the funding of the $10.0 million Preferred Stock Agreement with
Kaiser-Francis, which was signed in September, 1996. In 1997, the Company issued
$3.627 million of Series B Preferred Stock to finance a portion of the Shore
Merger. The Company also issued its common stock in connection with the Bison
and Shore mergers. The Company's drilling activities have been financed
primarily through the Company's cash flow.
Subject to availability of bank financing, the Company will
continue to consider debt-financed acquisitions presented to it by the Company.
The Company intends to finance acquisitions by issuing common stock and/or
preferred stock when possible.
Competition, Markets and Regulation. Competition in the
exploration and property acquisition markets is intense. In seeking to obtain
desirable Leases and exploration Prospects, the Company faces competition from
both major and independent oil and gas companies, as well as from numerous
individuals. Many of these competitors have substantial financial resources
available to them, which makes for increased competition.
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The ability of the Company to market oil and gas from its
wells will depend upon numerous factors beyond its control, including, but not
limited to, the extent of domestic production and imports of oil and gas, the
proximity of the Company's production to existing pipelines, the availability of
capacity in such pipelines and state and federal regulation of oil and gas
production. There is no assurance that the Company will be able to market all of
the oil or gas produced by it or that favorable prices can be obtained for the
oil and gas it produces. In view of the uncertainties affecting the supply and
demand of oil and gas, the Company is unable to accurately predict future oil
and gas prices and demand, or the overall effect they will have on the Company.
Numerous federal and state laws and regulations affect the
Company's operations. In particular, oil and gas production operations are
affected by tax and other laws relating to the petroleum industry and any
changes in such laws and regulations. Some of the rules and regulations carry
substantial penalties for failing to comply. The regulatory burden on the oil
and gas industry increases the Company's cost of doing business. The Company's
activities are also subject to numerous federal, state and local environmental
laws and regulations governing the discharge of materials. In most cases, the
applicable regulatory requirements relate to water and air pollution control or
solid waste management measures. The Company believes the recent trend toward
stricter standards in environmental legislation, regulation and enforcement will
continue. To date, these laws have not had a significant impact on the Company
but no assurance can be given as to the effect of these laws on the Company in
the future.
Employees. As of December 31, 1997, the Company employs
seventeen full-time persons. The Company employs eleven full-time persons in its
Houston, Texas office, including four executive officers, whose functions are
associated with management, engineering, geology, land and legal, accounting,
financial planning and administration. The Company employs four full-time
persons in its Wichita, Kansas office, including one executive officer, a
geologist, an engineer and an administrative assistant. The Company also employs
one full-time supervisor for well operations in Oklahoma and one full-time
accountant in Mobile, Alabama.
ITEM 2. DESCRIPTION OF PROPERTY
(a) Real Estate Properties
The Company owns a historic home in Mobile, Alabama which
previously served as its corporate office before the Company's relocation to
Houston, Texas in November 1997. The Company has listed the property for sale.
(b) Oil and Gas Properties
More than 95% of the Company's oil and gas properties,
reserves and activities are located onshore in the continental United States,
primarily in Alabama, Kansas, Louisiana, Oklahoma and Texas. Estimates of total
proved net oil or gas reserves have not been filed with or included in reports
to any federal authority or agency. There are no quantities of oil or gas
subject to long-term supply or similar agreements with foreign governmental
authorities.
I-9
<PAGE> 13
The Company's largest oil and gas property, in terms of dollar
value, is the Spivey Field acquired in the Bison Merger. The Spivey Field,
located in Kingman and Harper Counties, South Central Kansas, was discovered in
1949. Development of oil and gas reserves from the Mississippian Chert
Formation, at an average drilling depth of 4,250 feet, has been continual since
discovery. Currently, approximately 585 active wells produce in the field. Great
lateral extent, thick pay sections, and long-lived production characterize the
reservoir.
The Spivey Field has cumulative gas production of over 75,000
million cubic feet. Gas is marketed to the spot markets and to the Spivey Gas
Plant (the "Plant"). Over 95% of Company gas is sold to the Plant under a life
of the lease casinghead tailgate gas contract. The Company owns approximately
11.5% ownership in the Plant and related gathering system. Warren Petroleum
Company, L.P., and NGC Corporation jointly operate the Plant. Ownership in the
Plant is redetermined annually, based on owner's throughput relative to total
throughput. Plant liquids (propane, butane and natural gas) are marketed from
the Plant to Murphy Energy. Residue gas is sold to KGE (fka Kansas Power and
Light) for a tailgate price of $2.91 per Mcf. The tailgate contract calls for an
annual escalation of $0.02 per Mcf. The Btu factor for the residue gas is 1.042.
Plant owners also receive the benefit of buying, stripping and reselling
"Non-Owner" field gas.
The Spivey Field has cumulative oil production of over 66.6
million barrels of oil. Lease oil is marketed to Koch Oil Company, via truck,
and a bonus above posted prices is received.
The Company operates approximately 80 wells in the Spivey
Field from a field office in Attica, Kansas, staffed by one foreman and two
Company pumpers. All oilfield services are present in the field. Exploration,
engineering and land functions are directed from the division office located in
Wichita, Kansas. The Company is continually developing its acreage position of
approximately 8,500 gross acres.
As of December 31, 1997, the Company has identified and
independent engineers have evaluated twenty-two proven undeveloped locations in
the Spivey Field with a PV 10% value of approximately $2.4 million. At December
31, 1997, the Plant was valued by independent engineers at $2.9 million PV 10%.
I-10
<PAGE> 14
The following table shows proved oil and gas reserves by major
field for the Company's largest producing fields at December 31, 1997. The
values represent the present value of estimated future net cash flows before
income taxes, discounted at 10%, assuming unescalated expenses and prices of
$16.18/Bbl and $2.54/MMBtu attributable to proved reserves at December 31, 1997,
as determined by several independent reserve engineers.
<TABLE>
<CAPTION>
Discounted Percentage Oil Gas
Field Name/ Primary Present of Total Reserves Reserves
County/State Operator Value Present Value (Bbls) (Mcf)
------------ -------- ----- ------------- ------ -----
(Dollars/quantities in thousands)
<S> <C> <C> <C> <C> <C>
Spivey Company $9,329 30.9% 993 11,415
Harper/Kingman, KS
Riceville Field Murphy 4,958 16.4% 50 2,244
Vermillion, LA
Hatters Pond Texaco 1,019 3.4% 71 187
Mobile, AL
Wright Field Hilcorp 735 2.4% 96 150
Vermilion, LA
Murphy Lake Amerada Hess 587 1.9% 99 --
St. Martin, LA
Lockhart Crossing Amoco 488 1.6% 10 270
Livingston, LA
Polo Field Lu-Ray 481 1.6% 141 5
Noble, OK
Abbeville Company 473 1.6% 3 279
Vermilion, LA
Okeene N.W. Ricks Expl. 443 1.5% 11 507
Major,OK
N. Frisco City Torch Energy 443 1.5% 33 32
Monroe, AL
Others Various 11,223 37.2% 1,426 3,330
-------- ----- ----- ------
Total $ 30,179 100.0% 2,933 18,419
======== ===== ===== ======
</TABLE>
As of December 31, 1997, the Bank has a first mortgage on all
of the fields listed in the above table. The Bank also has a first mortgage on
numerous additional fields not individually listed above which
I-11
<PAGE> 15
in total gives the Bank a first mortgage on approximately 75% of the Company's
total reserves (PV 10%) of $30,179,000 before income tax. The Company is
obligated, within five days of request by the Bank, to grant the Bank a first
and prior mortgage on any oil and gas properties owned or acquired by the
Company.
(c) Louisiana Fee Mineral Acreage
In the Shore Merger, the Company acquired approximately 42,321
net mineral acres, situated in Terrebonne, Lafourche and St. Mary Parishes in
Louisiana. Of the total acreage, 39,769 acres are non-producing and the
remainder is held by production under existing leases. The non-producing acreage
is located in the following parishes: 20,587 in Terrebonne (Montegut and Houma
areas), 11,128 acres in Lafourche (Raceland and Valentine areas) and 8,054 acres
in St. Mary Parish (Charenton area). The non-producing acreage currently under
lease and/or option has expiration dates as follows: 17,835 acres in 1998 and
5,722 acres in 2000. As of December 31, 1997, 16,212 acres were not under lease.
Royalty interest in the leases covering the non-producing minerals ranges from
20% to 25%. The mineral servitude prescription dates are estimated by the
Company to be as follows: 620 acres prescribed in 1997, 6,226 acres in 1999,
5,286 acres in 2002, 4,145 acres in 2004, 1,121 acres in 2005, 1,145 acres held
in perpetuity and the remaining acreage has prescription interrupted by
production. Effective April 1, 1992 Shore Oil Company sold the production rights
under tracts producing at that time and does not receive royalty income from the
sale of oil or gas on those tracts. Over 80% of the non-producing minerals have
been covered by 3-D seismic shot by third parties and provided to the Company at
no cost. During the period July 1, 1997 through December 31, 1997, the Company
received approximately $975,000 in lease bonus, delay rental and seismic option
income on the acreage. An independent oil and gas engineering firm valued the
acreage as of June 30, 1997 at $3,627,000. One unsuccessful Exploratory Well in
Lafourche Parish, the Shore Oil Company #1, was drilled on the fee mineral
acreage in 1997 and abandoned in February 1998.
(d) Productive Wells and Acreage
The following table depicts the number of gross and net
producing wells and related Developed and Undeveloped Acreage in which the
Company owned an interest for the period ended December 31, 1997 Undeveloped
Acreage is oil and gas acreage (including, in certain instances, rights in one
or more horizons which may be penetrated by existing well bores, but which have
not been tested) to which Proved Reserves have not been assigned by independent
petroleum engineers.
I-12
<PAGE> 16
The Company's net Developed Acreage is located primarily in
Oklahoma, Texas, Alabama, New Mexico and Kansas. The Company's net Undeveloped
Acreage is located in Kansas.
<TABLE>
<CAPTION>
Acreage
------------------------------------
Developed Undeveloped
--------- -----------
<S> <C> <C>
Gross Acres 239,646 9,758
Net Acres 20,337 8,643
Productive Wells
------------------------------------
Oil Gas
--- ---
<S> <C> <C>
Gross Wells 797.00 184.00
Net Wells 68.67 30.13
</TABLE>
Excluded from the acreage data are approximately 44,041 net mineral acres owned
by the Company, all of which are considered to have potential for oil and gas
exploration.
(e) Production, Prices and Costs
Below is a summary of the net production of oil and gas,
average sales prices and average production costs during each of the last three
fiscal years. The Company is not obligated to provide a fixed and determined
quantity of oil and gas in the future under existing contracts or agreements.
During the last three fiscal years, the Company has not had, nor does it now
have, any long-term supply or similar agreements with governments or
authorities.
<TABLE>
<CAPTION>
Fiscal Years Ended December 31,
-------------------------------------------
1995 1996 1997
---- ---- ----
<S> <C> <C> <C>
Crude Oil and Natural Gas Production:
Oil (Bbls) 107,025 108,626 253,849
Gas (Mcf) 916,954 982,709 1,929,298
Average Sales Prices:
Oil (per Bbl) $16.17 $20.26 $18.38
Gas (per Mcf) $1.52 $2.28 $2.39
Average Production Costs Per BOE(1) $5.25 $5.36 $6.69
</TABLE>
(1) The components of production costs may vary substantially among wells,
depending on the methods of recovery employed and other factors, but
generally include severance taxes, administrative overhead, maintenance
and repair, labor and utilities.
I-13
<PAGE> 17
(f) Drilling Activities
During the periods indicated, the Company drilled or
participated in the drilling of the following productive and nonproductive
Exploratory and Development Wells. All of the Company's drilling and production
activities are conducted with independent contractors.
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------
<S> <C> <C> <C>
Exploratory Wells: 1995 1996 1997
----- ------ ------
Productive
Gross 0 31 8
Net 0 0.987 0.452
Dry
Gross 0 18 11
Net 0 0.675 1.280
Development Wells:
Productive
Gross 0 4 17
Net 0 0.866 5.627
Dry
Gross 2 1 6
Net 0.418 0.250 4.150
Total Wells:
Productive
Gross 0 35 25
Net 0 1.853 6.079
Dry
Gross 2 19 17
Net 0.418 0.925 5.430
</TABLE>
As of March 16, 1998, the Company was drilling one Exploratory Well on the
Sherburne Prospect.
(g) Reserves
Note 11 to the Company's financial statements presents, among
other disclosures prepared pursuant to Statement of Financial Accounting
Standards No. 69, the estimated net quantities of the Company's proved oil and
gas reserves and the standardized measure of discounted future net cash flows
attributable to such reserves as of December 31, 1997. At December 31, 1997, the
Company's net Proved Reserves consisted of 2,933 thousand barrels of oil and
18,419 million cubic feet of gas, and net Proved Developed Reserves consisted of
2,580 thousand barrels of oil and 14,251 million cubic feet of gas. At December
31, 1997, the present value discounted at 10% for the Company's Proved oil and
gas reserves, before income taxes, was approximately $30,179,000. (See Note 11
to the Company's financial statements for additional detail on the Company's oil
and gas reserves.) Management of the Company, however, cautions against using
this data to determine the fair value of the Company's oil and gas properties or
for any other purpose because the price of oil and gas can be volatile. The
present value was computed using December 31, 1997 base oil prices of
I-14
<PAGE> 18
$16.18 per Bbl and base gas prices of $2.54 per MMBtu. Base prices were adjusted
for certain properties that either received a price above or below the base
price. There were no estimates or reserve reports of the Company's proved oil
and gas reserves filed with any governmental authority or agency during the year
ended December 31, 1997.
The following table sets forth the standardized measure (in
thousands of dollars) of future net cash flows of Proved Reserves and total
recoverable volumes of oil and gas from Proved Reserves attributable to the
Company's interest in oil and gas wells for the years ended December 31, 1997
through 1995:
<TABLE>
<CAPTION>
Recoverable Volumes
-------------------
Standardized Oil Gas
Year Ended Measure (MBbls) (MMcf)
---------- ------- ------- ------
<S> <C> <C> <C>
December 31, 1997 $24,493 2,933 18,419
December 31, 1996 $17,863 1,389 8,964
December 31, 1995 $9,250 778 6,371
</TABLE>
The increases in the standardized measure from 1995 to 1996
and 1996 to 1997 are due primarily to the NPC Merger in 1996 and the Bison and
Shore Mergers and Riceville Acquisition in 1997. For a detail of changes in oil
and gas reserves for the year, refer to Note 11 to the Company's financial
statements.
The reserve data set forth in this Form 10-KSB represents only
estimates. Reserve engineering is a subjective process of estimating underground
accumulations of crude 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 geological interpretation and adjustment.
As a result, estimates of different engineers often vary. In addition, results
of drilling, testing and production subsequent to the date of an estimate may
justify revisions of such estimates. Accordingly, reserve estimates often differ
from the quantities of crude oil and natural gas that are ultimately recovered.
Estimates of economically recoverable oil and natural gas reserves and of future
net revenues are based upon a number of variables and assumptions, including
future prices of oil and gas, all of which may vary considerably from actual
results. The reliability of such estimates is highly dependent upon the accuracy
of the assumptions from which they were based.
ITEM 3. LEGAL PROCEEDINGS
The Company is a defendant in various legal proceedings which are
considered routine litigation incidental to the Company's business, the
disposition of which management believes will not have a material effect on the
financial position or result of operations of the Company.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders of the
Company during the fourth quarter of the fiscal year ended December 31, 1997.
I-15
<PAGE> 19
PART II
ITEM 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
(a) Market Information
The Company Common Stock is quoted on the NASDAQ Small Cap
Market tier of the NASDAQ Stock Market under the symbol "MBOC". The Common Stock
began trading on NASDAQ Small Cap Market on September 29, 1995. At present, the
stock does not have any retail brokerage coverage. The following quotations
reflect inter-dealer prices, without retail mark-up, mark-down or commission,
and may not represent actual transactions:
<TABLE>
<CAPTION>
Period High Bid Low Bid
------ -------- -------
<S> <C> <C>
1996
First Quarter $3.38 $2.75
Second Quarter 3.38 2.75
Third Quarter 3.25 2.50
Fourth Quarter 6.00 3.00
1997
First Quarter $9.25 $5.50
Second Quarter 12.50 7.75
Third Quarter 11.50 8.75
Fourth Quarter 11.13 9.00
</TABLE>
On March 16, 1998, the closing price of the common stock was $5.13 bid and $6.50
asked.
(b) Holders
As of March 16, 1998, the Company had 738 holders of record of
its common stock, which does not include an unknown number of additional holders
whose stock is held in "street name."
(c) Dividends; Dividend Policy
The Company has never paid any dividends on its common stock.
The terms of the Company's credit facility with the Bank of
Oklahoma prohibit the Company from making distributions of any kind, type or
nature, cash or otherwise on its common stock. In any event, the Company expects
to retain all available earnings generated by its operations for the development
and growth of its business and does not anticipate paying any cash dividends in
the foreseeable future. Any future
II - 1
<PAGE> 20
determination as to the payment of dividends will be made at the discretion of
the Board of Directors and will depend on a number of factors, including the
future earnings, capital requirements, financial condition and future Prospects
of the Company, restrictions in the Company's current or future financing
agreements (such as the Convertible Loan) and any other factors as the Board of
Directors may deem relevant.
ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS
The following discussion should be read in conjunction with the
Company's financial statements and notes thereto set forth in Item 7.
(a) Results of Operations
The factors that most significantly affect the Company's
results of operations are (i) the sales price of crude oil and natural gas, (ii)
the level of production volumes, (iii) the level of lease operating expenses,
and (iv) the level of interest rates. Sales of production and level of borrowing
are significantly impacted by the Company's ability to maintain or increase its
production from existing oil and gas properties or through its exploration and
development activities. Sales prices received by the Company for oil and gas
have fluctuated significantly from period to period. The fluctuations in oil
prices during these periods reflect market uncertainty regarding the inability
of OPEC to control the production of its member countries, production from Iraq,
as well as concerns related to the global supply and demand for crude oil. Gas
prices received by the Company fluctuate generally with changes in the spot
market price for gas. Relatively modest changes in either oil or gas prices
significantly impact the Company's results of operations and cash flow and could
significantly impact the Company's borrowing capacity.
The table below details the changes in oil and gas revenues,
excluding plant and other revenues, caused by price and volume changes for the
years ending December 31, 1997, 1996 and 1995.
<TABLE>
<CAPTION>
1997 1996 1995
---------- -------- ---------
<S> <C> <C> <C>
Oil Revenues
Change due to volume $2,942,138 $ 32,436 $ 576,865
Change due to price (478,122) 437,285 102,558
Total change 2,464,016 469,271 679,423
Gas Revenues
Change due to volume $2,161,383 $149,921 $ 277,755
Change due to price 201,483 708,386 (182,391)
Total change 2,362,866 858,307 95,364
</TABLE>
(b) Fiscal 1997
Total revenues for the twelve months ended December 31, 1997,
of $11,433,000, were $6,546,000 higher than the same period in 1996. The
increase in total revenues was due primarily to higher
II - 2
<PAGE> 21
oil and gas revenues of $4,827,000, consisting primarily of a $2,464,000
increase in oil revenues and a $2,363,000 increase in gas revenues. Also
contributing to the revenue increase was $920,000 in revenue from gas processing
at the gas plant located at the Spivey Field and $975,000 in lease bonus and
delay rental income on the fee mineral acreage in Louisiana. The gas processing
plant was acquired in the February 28, 1997 Bison Merger. The increase in oil
and gas revenues from 1996 to 1997 was primarily the result of increases in
production which resulted from the Bison and Shore Mergers. Production from the
Bison and Shore Mergers is included from March 1 and July 1, 1997, respectively.
Production of oil and gas for the twelve months ended December 31, 1997,
increased 133% and 96%, respectively, over the comparable period. During the
twelve-month period ended December 31, 1997, the Company sold 254,000 barrels of
oil and 1,929,000 Mcf of gas, as compared to 109,000 barrels of oil and 983,000
Mcf of gas for the comparable period. Oil production for 1997 was 145,000
barrels higher due primarily to a 58,000 barrel increase from the Bison Merger
and a 76,000 barrel increase from the Shore Merger. Gas production in 1997 was
946,000 Mcf higher due primarily to a 521,000 Mcf increase from the Bison
Merger, a 335,000 Mcf increase from the Shore Merger and a 188,000 Mcf increase
from the Riceville Acquisition. The price received on the gas sold in 1997 of
$2.39 per Mcf was slightly higher than the $2.28 per Mcf received in the
comparable period. Oil prices in 1997 of $18.38 per barrel were 9% lower than
the $20.26 per barrel received in the comparable period.
The Company received approximately $975,000 in lease bonus and
delay rental income on the fee mineral acreage acquired in the Shore Merger over
the six-month period ending December 31, 1997.
The increase in total revenues of $6,546,000 was less than the
increase in total expenses, before income taxes, of $29,851,000. The principal
reasons for the increase in the overall level of expenses are (1) increased oil
and gas property impairment charge of $20,870,000; (2) increased lease operating
and depletion expenses of $5,715,000 from properties acquired in the Bison and
Shore Mergers which are included with the Company's expenses from March 1 and
July 1, respectively; and (3) increased G&A expenses of $1,699,000 due to
increased number of employees from the Bison and Shore Mergers and higher
overall administrative expenses due to the increased level of activity.
In the fourth quarter of 1997, the Company charged to
impairment expense $21,148,000 versus $278,000 in the comparable period. The
impairment expense was computed applying the guidelines of FAS #121 "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
of." This statement requires that long-lived assets be reviewed for impairment
when events or changes in circumstances indicate that the carrying value of such
assets may not be recoverable. This review consists of a comparison of the
carrying value of the asset with the asset's expected future undiscounted cash
flows without interest costs. Expected undiscounted future cash flow is defined
as "the future cash inflows expected to be generated by an asset less the future
cash outflows expected to be necessary to obtain those inflows (undiscounted and
without interest charges)." Independent oil and gas engineers determine the
expected future undiscounted cash flows. To determine the expected future
undiscounted cash flows of each property, the engineers estimated each
property's oil and gas reserves, relied on certain information supplied by the
Company regarding the oil and gas reserves, applied certain assumptions
regarding price and cost escalations, and applied certain discount factors for
risk, location, type of ownership interest, category of reserves, operational
characteristics and other factors. Estimates of expected future undiscounted
cash flows are to represent
II - 3
<PAGE> 22
management's best estimate based on reasonable and supportable assumptions and
projections. If the expected future undiscounted cash flows exceed the carrying
value of the asset, no impairment is recognized. If the carrying value of the
asset exceeds the expected future undiscounted cash flows, impairment exists and
is measured by the excess of the carrying value over the estimated fair value of
the asset. Fair value is defined in the statement as the "amount at which the
asset could be bought or sold in a current transaction between willing parties."
The impairment expense in the current period of $21,148,000
was primarily attributable to impairments on three fields--the Esther Field,
Spivey Field and Wellman Field--amounting to $8,394,000, $6,127,000 and
$2,257,000, respectively. The Esther and Wellman Fields were acquired in the
Shore Merger, and the Spivey Field was acquired in the Bison Merger. The
impairment on the Esther Field in Vermilion Parish, Louisiana was due primarily
to a change in the category of reserves from Proved Undeveloped to Probable
Undeveloped and changes in the economics of the development of the reserves. The
category of the reserves was changed due to an abandoned sidetrack attempt in
February, 1998 by the operator on the Proved Undeveloped Reserves. The
impairment on the Spivey Field was due primarily to a decrease in the level of
oil prices and changes in the economics of the Proved Undeveloped Reserves due
to information obtained from the wells drilled in 1997. The impairment on the
Wellman Field in Terry County, Texas was due primarily to decreases in oil
prices. Since July 1, 1997, the posted price of WTI crude oil has fallen from
approximately $18.00 per barrel to $15.00 per barrel at December 31, 1997or 17%.
The total oil equivalent reserves of the Wellman Field are 95% oil. The
remaining impairment expense of approximately $4,370,000 is attributable to
several fields. The principal reasons for the impairment on these fields are the
decrease in oil prices and the decrease or cessation of oil and gas production.
Lease operating expenses of $3,849,000 increased by
$2,333,000. The increase was due primarily to the Bison and Shore Mergers which
increased lease operating expenses $1,067,000 and $915,000, respectively.
Depletion expense of $4,567,000 increased by $3,382,000. Depletion increased
primarily due to the Bison and Shore Mergers which increased depletion by
$1,279,000 and $1,270,000, respectively. Interest expense of $671,000 increased
by $166,000 due to a higher loan balance. Dry-hole expense of $1,119,000
increased by $690,000 due primarily to abandonment costs on three unsuccessful
Exploratory Wells drilled in Louisiana--the Shore Oil Company #1, the Sabine #1
and the Middle Bay Oil Company #1--with dry-hole costs of $311,000, $177,000
and $168,000, respectively. General and administrative expense of $2,361,000
increased by $1,699,000, due primarily to higher salary expense of $724,000,
higher professional fees of $347,000, higher office expenses of $128,000, and
higher IRA/SEP/Other Bonus expenses of $123,000. The remaining increase in
general and administrative expenses was over several expense categories and was
due primarily to an increase in the overall level of activity at the Company as
a result of the Bison and Shore Mergers. The increase in salary expense is due
to increases in salaries of existing employees and salaries associated with
employees added in the Bison and Shore Mergers. At the time of the Bison Merger,
seven employees occupied the Wichita, Kansas office. Effective August 1, 1997,
only four employees will be occupying the Wichita, Kansas office--the President
of Bison, an engineer, geologist and secretary. The President of Shore, an
engineer and a secretary were added in the Shore Merger. In addition, the
Company hired a land manager in July to manage the Company's land and mineral
records and an accounting supervisor in October to assist with the increased
accounting workload. Stock compensation
II - 4
<PAGE> 23
expense of $202,000 increased by $202,000 due to the vesting of 50% of the
restricted stock granted to certain Company employees in February, 1997. The
remaining 50% will fully vest on June 30, 1998. Other expenses of $317,000
increased $285,000 over the comparable period. The primary reason for the
increase was expenses associated with the Bison and Shore Mergers.
The Company reported an operating loss of $23,024,000 for the
year ended December 31, 1997, as compared to an operating profit of $280,000 in
the comparable period.
The Company reported a deferred tax benefit of $7,451,000 for
the year ended 1997 versus a deferred tax expense of $70,000 in the comparable
period. The primary reason for the deferred tax benefit in 1997 was the oil and
gas reserve impairment on the properties acquired in the Bison and Shore Mergers
in 1997 and the NPC Merger in 1996. These three mergers were tax-free mergers,
and the tax basis of the oil and gas properties acquired were carried over on
the Company's books at the merger dates. For accounting purposes, the three
mergers were purchases and the oil and gas properties were recorded on the
Company's books at fair market value on the merger dates. The fair market value
was much higher than the carryover tax basis and a deferred tax liability at the
prevailing tax rate was recorded for the difference. The total deferred tax
liability that was recorded on the Company's books for the Bison, Shore and NPC
Mergers was approximately $12 million. When the impairment reduced the carrying
amount of the oil and gas properties for accounting purposes but not for tax
purposes, the difference between the accounting and tax basis of the properties
was reduced and the deferred tax liability was reduced accordingly, resulting in
a deferred tax benefit.
The Company reported a net loss of $15,579,000 versus net
income of $205,500 for the comparable period. The Company paid preferred
dividends of $605,000 in the current period and reported a net loss to common
stockholders of $16,184,000 versus net income available to common stockholders
of $205,000 for the comparable period. No preferred dividends were paid in 1996.
(c) Fiscal 1996
Total revenues for the twelve months ended December 31, 1996,
of $4,886,000, were $1,348,000 higher than the comparable period. The increase
in total revenues was due primarily to higher oil and gas revenues of
$1,236,000, consisting primarily of a $469,000 increase in oil revenues and a
$858,000 increase in gas revenues. Total revenues also increased due to higher
other income of $199,000, due primarily to a gas contract settlement of
$263,000. The increase in oil and gas revenues from 1996 to 1995 was primarily
the result of higher oil and gas prices. Production of oil and gas for the
twelve months ended December 31, 1996, increased 1% and 7%, respectively, over
the comparable period. During the twelve-month period ended December 31, 1996,
the Company sold 109,000 barrels of oil and 983,000 Mcf of gas, as compared to
107,000 barrels of oil and 917,000 Mcf of gas for the comparable period. Oil
production for 1996 was 1,600 barrels higher due to a 4,300 barrel increase from
the successful wells in the Brigham Agreement, a 500 barrel increase in existing
properties, and a decrease of 3,200 barrels from properties sold in 1996. Gas
production in 1996 was 66,000 Mcf higher due to a 25,000 Mcf increase from the
successful wells in the Brigham Agreement and a 78,000 Mcf increase in existing
properties offset by a decrease of
II - 5
<PAGE> 24
37,000 Mcf from properties sold in 1996. The price received on the gas sold in
1996 of $2.28 per Mcf was higher than the $1.51 per Mcf received in the
comparable period. Oil prices in 1996 of $20.26 per barrel were 25% higher than
the $16.17 per barrel received in the comparable period.
The increase in total revenues of $1,348,000 was more than the
increase in total expenses of $646,000. Increases in dry-hole costs and
depreciation and depletion expense accounted for approximately 91% of the total
expense increase.
Lease operating expenses of $1,516,000 increased by $79,000 as
a result of higher expenses on existing properties of $138,000 and expenses on
successful wells in the Brigham Agreement of $4,300 offset by reductions due to
properties sold in 1996 of $63,000. Interest expense of $505,000 decreased by
$15,000 due to lower interest rates and payments on principal in 1996. Dry-hole
expense increased by $346,000 due primarily to abandonment costs of $421,000
associated with the unsuccessful wells drilled in the Brigham Agreement.
Depletion expense of $1,397,000 increased by $256,000. Regular depletion of
$1,119,000 increased by $134,000 due primarily to higher depletion on existing
properties. Write-offs of proven properties in accordance with SFAS #121 of
$277,000 increased by $121,000. Of the total writedown, 75% is from three single
well fields in Louisiana. One of the fields was the Lake Decade Field which was
a major property in 1995. It contributed $91,000 to cash flow in 1996 before it
ceased producing in December 1996, resulting in an impairment expense of
$59,000. The other two fields, which produced very little in 1996, were minor
properties contributing less than $20,000 to cash flow in 1995, and producing
impairment losses of $95,000 and $55,000. The remaining impairment expense
resulted from several properties, none of which were significant properties in
terms of discounted present value and were primarily mature, small properties
that did not contribute significantly to the Company's cash flow in 1996 and
1995. Depreciation expense of $60,000 decreased $15,000 due to lower
depreciation on lease and well equipment and corporate office furniture and
fixtures which are depreciated on an accelerated method which declines over the
useful life of the asset. General and administrative expenses decreased by
$3,900, due primarily to the Company's lower 1996 SEP/IRA and 1% NPI
contributions of $12,000 compared to the $60,000 in contributions in 1995, lower
accounting expenses of $14,000 and lower miscellaneous expenses of $18,000 which
were partially offset by higher travel and entertainment expenses of $47,000 and
higher legal expenses of $12,000.
The Company reported an operating profit of $280,000 for the
year ended December 31, 1996 as compared to an operating loss of $421,000 in
1995. If the 1996 nonrecurring credits of $303,000 consisting of the gas
contract settlement of $263,00 and lease operating expense credit of $40,000,
were offset against the 1995 nonrecurring expenses of $62,000, the operating
loss would have decreased by $336,000.
The Company reported net income of $205,000 for the year ended
December 31, 1996, versus a net loss of $331,000 for the comparable period.
II - 6
<PAGE> 25
(d) Effects of Oil and Gas Price Fluctuations
Fluctuations in the price of crude oil and natural gas
significantly affect the Company's operations and the value of its assets. As a
result of the instability and volatility of crude oil and natural gas prices,
financial institutions have become more selective in the energy lending area and
have reduced the percentage of existing reserves that may qualify for the
borrowing base to support energy loans.
The Company's principal source of cash flow is the production
and sale of its crude oil and natural gas reserves which are depleting assets.
Cash flow from oil and gas production sales depends upon the quantity of
production and the price obtained for that production. An increase in prices
permits the Company to finance its operations to a greater extent with
internally-generated funds, allow the Company to obtain equity financing more
easily and lessens the difficulty of attracting financing alternatives available
to the Company from industry partners and nonindustry investors. However, price
increases heighten the competition for Leases and Prospects, increase the costs
of exploration and development activities and increase the risks associated with
the purchase of Producing Properties.
A decline in oil and gas prices (i) reduces the cash flow
internally generated by the Company, which in turn reduces the funds available
for servicing debt and exploring for and replacing oil and gas reserves, (ii)
increases the difficulty of obtaining equity financing, (iii) reduces the number
of Leases and Prospects available to the Company on reasonable economic terms
and (iv) increases the difficulty of attracting financing alternatives available
to the Company from industry partners and nonindustry investors. However, price
declines reduce the competition for Leases and Prospects and correspondingly
reduce the prices paid for Leases and Prospects. Furthermore, exploration and
production costs generally decline, although the decline may not be at the same
rate of decline of oil and gas prices.
Since September, 1997, the price of oil has declined
dramatically. The posted price of WTI crude oil has declined from a high of
approximately $20.00 per barrel in October 1997 to lows in March 1998 of
approximately $13.00 per barrel. The average posted price of WTI crude oil for
the year 1997 was approximately $18 per barrel. Approximately 55% of the
Company's proved developed producing oil and gas reserves, on a BOE basis, are
oil. If oil prices remain at or near the March 1998 levels, the Company's
revenue and cash flow will decrease relative to the year ended 1997. Gas prices
peaked in November 1997, but decreased and have not changed significantly since
December 1997.
(e) Seasonality
The results of operations of the Company are somewhat seasonal
due to seasonal fluctuations in the price for natural gas. Generally, natural
gas prices are higher in the first and fourth quarter of the year due to colder
winter weather and resulting higher demand for natural gas during these months.
Due to these seasonal fluctuations, results of operations for individual
quarterly periods may not be indicative of results on an annual basis.
II - 7
<PAGE> 26
(f) Inflation and Changing Prices
Inflation principally affects the costs required to drill,
complete and operate oil and gas wells. In recent years, inflation has had a
minimal effect on the operations of the Company. Costs have generally declined
over the near future due to the decrease in drilling activity in the United
States. Unless increasing oil and gas prices spur large increases in industry
activities, management believes costs will remain relatively stable over the
next year.
(g) Capital Resources and Liquidity -- Fiscal 1997 and Fiscal 1996
Cash flow from operations before working capital changes of
$2,925,000 increased $1,225,000 over the comparable period. This increase was
due a to $3,184,000 increase in oil and gas cash flow, an increase of $554,000
in other income offset by increases in general and administrative costs of
$1,654,000, dry-hole costs of $691,000, interest expense of $166,000 and $1,000
in current income taxes. Increased oil and gas operations cash flow before
working capital changes was principally the result of increases in oil and gas
production. The other income increase was due primarily to lease bonus and delay
rental income on the minerals acquired in the Shore Merger.
Cash flow from operating activities for the year ending
December 31, 1997, of $2,582,000 increased $1,193,000 over the comparable
period. Changes in working capital reduced cash flow by $32,000 over the
comparable period. Differences in the amount and timing of accrual and payment
of payables and the accrual and receipt of revenues account for the changes in
working capital.
Additions to oil and gas properties were higher than the
comparable period due to the Bison and Shore Mergers and increased acquisitions
and drilling in the current period. The increase in the amount of cash used for
debt payments was due primarily to the $2,105,000 refinancing of the term note
assumed in the Shore Merger and the $385,000 of payments and refinancing on the
note assumed in the NPC Merger. No principal payments have been required over
the period April 1, 1996 to December 31, 1997 on the Company's $6 million, $15
million and $50 million convertible loans. The increase in the proceeds from
debt issued was due to the refinancing of the notes assumed in the Shore and NPC
Mergers, $3,000,000 issued in the Riceville Acquisition and the financing of the
leasehold and seismic costs in the amount of $385,000 associated with the
Reflection Ridge Prospect. The increase in proceeds from issuance of preferred
stock was due to the preferred stock issued to finance portions of the Bison and
Shore Mergers.
The Company's operating activities provided net cash of
$2,582,000 for the year ending December 31, 1997. During this period, net cash
from operations and cash on hand was used principally for exploratory and
developmental drilling of $2,004,000, workovers of $431,000, exploration
prospects of $415,000 and proved property acquisitions of $921,000. Debt
proceeds were used to finance $3,000,000 of proved property acquisition and
$285,000 of prospects. Common stock was issued for $260,000 of proved property
acquisitions, excluding mergers. Of the $2,004,000 spent on exploratory and
developmental drilling, approximately $420,000 was spent in the Brigham
Agreement, $880,000 in the Spivey Field in Kansas, $100,000 in the Wellman Unit
in Texas, and the remainder was spent on several wells in Louisiana, Mississippi
and Oklahoma. Of the $431,000 spent on workovers, approximately $80,000 was
spent at Wild Fork Creek
II - 8
<PAGE> 27
Field in Alabama, $44,000 at the Wright Field in Louisiana, $30,000 at Magnolia
in Arkansas and $25,000 at Lake Trammel Field in Texas. The remaining amount was
spent on several different properties. The $700,000 total amount spent on
prospects consisted primarily of $286,000 on Reflection Ridge in Kansas,
$232,000 on Hawkins Ranch in Texas, $67,000 on the Sherburne Prospect in
Louisiana, $31,000 on the Quarry Prospect in New Mexico and $55,000 on S.
Highbaugh in Texas. The Company spent $7,140,000 on the Bison Merger. This
includes the $1,446,000 in non-oil and gas assets, which were subsequently sold
for the amount paid. The Company spent $514,000 on the Shore Merger. Amounts
spent on debt retirement consisted principally of the payment in full of the
note assumed in the Shore Merger of $2,105,000, monthly principal payments on
the $385,000 term note assumed in the NPC Merger and the refinancing of the NPC
term note of $274,000. The principal payments on the $6 million convertible loan
were suspended when the Company converted the $5.6 million term note to a $6
million convertible loan on April 3, 1996.
The Company incurred $1,119,000 in dry hole costs consisting
principally of three wells drilled in Louisiana and one well drilled in
Oklahoma. The Louisiana wells were the Shore Oil Company #1, the Sabine #1 and
the Middle Bay Oil Company #1 with dry-hole costs of $311,000, $177,000 and
$168,000, respectively. The Oklahoma well was the Hannah #1 with a dry hole cost
of $301,000.
The Company incurred $223,000 in geological and geophysical
costs ("G&G Costs") which consisted primarily of $130,000 in G&G costs on the
Reflection Ridge Prospect and $62,000 on the Hawkins Ranch Prospect. The above
discussion of capital costs does not include amounts expensed as dry hole and
G&G costs.
The Company had current assets of $4,223,000 and current
liabilities of $2,891,000, which resulted in working capital of $1,332,000 at
December 31, 1997. This was an increase of $546,000 from working capital of
$786,000 at December 31, 1996. Working capital increased primarily due to
increased cash flow from operations, cash proceeds from stock option exercises,
and no monthly principal payments on the Convertible Loan, offset partially by
increased amounts spent on exploratory and developmental drilling and working
capital changes. The current maturity of long-term debt was higher in 1997
because of the larger principal balance requiring payment in the following year.
In 1997, the $50 million Convertible Loan requires principal payments beginning
April 1, 1998 versus the $6 million Convertible Loan requiring principal
payments beginning October 1, 1997 in the comparable period. The Company's
current ratio of 2.78, calculated under the terms of the Convertible Loan which
excludes stockholder receivables and debt due under the $50 million Convertible
Loan, is in excess of the 0.90 to 1.00 required.
In general, because natural gas and oil reserves are depleted
by production, the Company's success is dependent upon the results of its
acquisition, development and exploration activities. The Company's strategy is
to acquire and develop proved producing and proved undeveloped properties,
enhance and exploit its existing properties for reserves and to invest in a
limited amount of exploratory and developmental drilling projects. The Company
expects to incur a minimum of $2,300,000 in capital expenditures over the next
twelve months for exploratory and developmental activities. The capital
expenditures for drilling are expected to be allocated to recomplete a well in
the Esther Field for $400,000, drill a well on the Sherburne Prospect for
$288,000, on the S. Highbaugh Prospect for $150,000, on the Quarry Prospect for
$140,000 and shoot,
II - 9
<PAGE> 28
process and interpret seismic and acquire leases on the Hawkins Ranch Prospect
for $1,300,000. The developmental and exploratory drilling activities will be
funded by internally generated cash flows. Capital expenditures above $2.3
million will be contingent on a number of factors including current and expected
prices of oil and gas, timing of completion of 3-D seismic data acquisition on
the Hawkins Ranch Prospect, results of exploration and development drilling and
potential additional mergers and acquisitions the Company is currently
evaluating.
As of March 16, 1998, the Company had funded the sidetracking
of the Kuehling #1 well in the Esther Field for $400,000 and a well in the S.
Highbaugh Prospect in Tyler County, Texas for $150,000. The operator abandoned
the recompletion attempt after encountering a split casing, and the well in S.
Highbaugh was a dry hole. In addition, the Company purchased additional interest
and seismic on the Hawkins Ranch Prospect for approximately $250,000.
Under the terms of the Janex Acquisition, the Company has a
contingent obligation to repurchase 142,107 common shares issued in the Janex
Acquisition, upon written notice delivered to the Company, beginning five years
after the closing date and continuing for thirty days thereafter, at a price of
$6.00 per share. This obligation shall terminate if the Company's stock trades
at a share price of $8.00 or greater for twenty consecutive trading days during
the thirty-six month period ending November 1, 1998. At the close of trading on
April 7, 1997, the Company's common stock had traded at an ask price that was
equal to, or exceeded, $8.00 per share for twenty consecutive trading days.
Therefore, the contingent obligation represented by the redeemable common stock
balance on the Company's balance sheet in the amount of $421,179 was
reclassified to additional paid-in capital effective April 7, 1997.
On April 3, 1996, the Bank converted its $5.6 million term
note into a $6.0 million, one-year, revolving line-of-credit (the "$6 million
Convertible Loan"), effective April 1, 1996. The $6 million Convertible Loan
required monthly payments of interest only at prime plus 1.5% and converted into
a term note payable in seventy-one consecutive equal monthly principal and
interest payments at prime plus 1.5%, with the remaining principal and interest
payment due on March 31, 2003. Effective, March 31, 1997, the Company refinanced
the $6 million Convertible Loan at its current principal balance of $5,186,596
with a $15 million Convertible Loan. The $15 million Convertible Loan required
monthly payments of interest only at prime for one year and converts into a term
note payable in seventy-one consecutive equal monthly principal and interest
payments at prime, with the remaining principal and interest payment due on
March 31, 2004. The $15 million Convertible Loan also required payment of a
commitment fee equal to an annual rate of three-eighths percent of the excess of
the borrowing base over the principal balance of the convertible note. Effective
September 1, 1997, the Company refinanced the $15 million Convertible Loan at
its current principal balance of $5,851,298 with a $50 million Convertible Loan.
The $50 million Convertible Loan requires monthly payments of interest only at a
fixed rate of Libor plus 1.75% as long as the principal amount of the loan is
less than 75% of the current borrowing base of $15 million. If the principal
amount of the loan is greater than or equal to 75% of the borrowing base, the
rate increases to Libor plus 2.75%. The Company has the option of switching to a
floating prime rate. The $50 million Convertible Loan converts into a term note
payable in seventy-one consecutive equal monthly principal and interest payments
at prime, with the remaining principal and interest payment due on March 31,
2004. The $50 million Convertible Loan also requires payment of a commitment
II - 10
<PAGE> 29
fee equal to an annual rate of three-eighths percent of the excess of the
borrowing base over the principal balance of the convertible note. The principal
balance of the $50 million Convertible Loan at December 31, 1997 was
$10,956,298.
On September 4, 1996, the Company signed a Preferred Stock
Agreement with Kaiser-Francis. The Preferred Stock Agreement provides for the
purchase of 1,666,667 shares of Series A by Kaiser-Francis over a five-year
period, beginning September 4, 1996, with minimum incremental investments of
$500,000 each. Each issuance is subject to approval by Kaiser-Francis of the use
of proceeds. The Series A is nonvoting and accrues dividends at 8% per annum,
payable quarterly in cash. At December 31, 1997, 100% of the Series A had been
issued to partially finance the NPC, Bison and Shore Mergers.
In connection with the Shore Merger effective June 30, 1997,
the Company issued 266,667 shares of Series B Preferred Stock ("Series B"). The
Series B is nonvoting and pays no dividends. The Series B has a liquidation
value of $7.50 per share and is junior to the Series A Preferred. For a period
of sixty-six months subsequent to June 30, 1997, any holder of the Series B may
convert all or any portion of Series B shares into Company common stock
("Common") at a ratio of one share of Common for each Series B share, or at any
time on or after January 1, 1998, the holders may convert pursuant to the
Alternative Conversion Method based on Cumulative Value. The Cumulative Value
(as defined in the Shore Merger Agreement) means the value attributable to the
approximately 42,000 net mineral acres located in South Louisiana. The
Cumulative Value shall initially be equal to $2 million, shall not exceed $10
million and shall be recomputed on an incremental basis as of December 31 of
each year following the merger date. The Cumulative Value consists primarily of
income from lease bonuses and delay rentals and the present value of proved
reserves discovered on the acreage. Upon expiration of the conversion period,
unless the Company has given notice to redeem the Series B, all of the shares of
Series B shall be automatically converted. In no event shall the aggregate total
number of shares of Common into which the Series B are converted be less than
266,667 shares or exceed 1,333,333 shares, unless further increased for any
anti-dilution provisions.
The Alternative Conversion Method shall be computed as of
December 31 of each year following the merger date of June 30, 1997, by
determining the incremental amounts by which the Cumulative Value increases over
the prior year's computation. Each incremental increase in the Cumulative Value,
when computed, shall be divided by $8,000,000, with the resulting quotient (the
"Alternative Conversion Factor") multiplied by 266,667 to determine the number
of Series B shares which would be available to be converted. The number of
Common shares into which the Series B would be converted shall be determined by
multiplying 1,066,666 times the then applicable Alternative Conversion Factor.
The procedure shall be repeated as of each December 31, with the applicable
number of Series B shares converted into Common shares. If on December 31 of any
year during the conversion period the aggregate Cumulative Value equals or
exceeds $10,000,000, then the remaining Series B shares will be convertible into
a number of Common shares equal to 1,333,333 shares less the aggregate number of
Common shares previously issued upon conversion
The Company's liquidity position and current and anticipated
cash flows from operations remain adequate for its general requirements.
However, because future cash flows and the availability of financing are subject
to a number of variables, such as the level of production and prices received
for gas and
II - 11
<PAGE> 30
oil, there can be no assurance that the Company's capital resources will be
sufficient to maintain planned levels of capital expenditures.
(h) Capital Expenditures -- Fiscal 1997 and Fiscal 1996
Total capital expenditures, excluding mergers, for oil and gas
properties in fiscal 1997 and 1996 were $7,316,000 and $1,597,000, respectively.
Total capital expenditures for mergers in 1997 and 1996 were $27,586,000 and
$2,618,000, respectively. Total capital expenditures for dry holes and G&G in
1997 and 1996 were $1,341,000 and $429,000, respectively.
Through March 16, 1998, the Company has spent approximately
$1,000,000 and is committed to spend an additional $1,300,000 for the remainder
of the year. Beyond these commitments, the Company's capital expenditures will
vary, depending on energy market conditions and other related economic factors.
The Company anticipates that its cash flow from operations will be adequate to
fund the drilling of the wells in the Esther Field, Sherburne, S. Highbaugh and
Quarry Prospects and to fund the seismic survey at Hawkins Ranch. As of March
16, 1998, the Company has approximately $4,000,000 of available credit through
the $50.0 million Convertible Loan. The funds available under the $50 million
Convertible Loan may be reduced at the next redetermination date on March 31,
1998, depending on the level of prices, rates of production and various other
factors. The Company intends to use the $50 million Convertible Loan to finance
proved property acquisitions. Whenever possible, the Company will use funds from
the sale of preferred stock and/or common stock to finance acquisitions.
The Company's liquidity position and current and anticipated
cash flows from operations are expected to remain adequate for its general
requirements over the next twelve months.
ITEM 7. FINANCIAL STATEMENTS
The Company's financial statements for the years ended December 31,
1997 and 1996 and the report of Schultz, Watkins & Company, independent
accountants, thereon are included in this Item 7.
[The remainder of this page has been intentionally left blank]
II - 12
<PAGE> 31
MIDDLE BAY OIL COMPANY, INC.
AUDITED CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1997 AND 1996
SCHULTZ, WATKINS & COMPANY
CERTIFIED PUBLIC ACCOUNTANTS
JACKSON, MISSISSIPPI
<PAGE> 32
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
No.
----
<S> <C>
Independent Auditors' Report.............................................. 1
Consolidated Balance Sheets............................................... 2
Consolidated Statements of Operations..................................... 3
Consolidated Statements of Changes in Stockholders' Equity................ 4
Consolidated Statements of Cash Flows..................................... 5
Notes to Consolidated Financial Statements................................ 6
</TABLE>
<PAGE> 33
SCHULTZ,
WATKINS & COMPANY
================================================================================
CERTIFIED PUBLIC ACCOUNTANTS
1437 Old Square Road
Suite 106
Jackson, MS 39211
Phone: 601-362-3312
FAX: 601-362-1623
Independent Auditors' Report
Board of Directors and Stockholders
Middle Bay Oil Company, Inc.
We have audited the accompanying consolidated balance sheets of Middle
Bay Oil Company, Inc. and subsidiaries as of December 31, 1997 and 1996, and the
related statements of operations, changes in stockholders' equity and cash flows
for the years then ended. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements 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 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 consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Middle Bay
Oil Company, Inc. and subsidiaries at December 31, 1997 and 1996, and the
results of their operations and their cash flows for the years then ended in
conformity with generally accepted accounting principles.
As discussed in Note 1 to the financial statements, the Company
restated its consolidated financial statements to exclude a valuation allowance
in presenting its net deferred income tax liability.
/s/ Schultz, Watkins & Company
Jackson, Mississippi
February 27, 1998
-1-
<PAGE> 34
MIDDLE BAY OIL COMPANY, INC.
Consolidated Balance Sheets
December 31
ASSETS
<TABLE>
<CAPTION>
1997 1996
------------ ------------
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents $ 1,587,184 $ 556,026
Accounts receivable 2,325,138 1,129,417
Other current assets 104,313 58,137
Assets held for resale 206,464 --
------------ ------------
Total current assets 4,223,099 1,743,580
NON-CURRENT ASSETS
Accounts receivable - stockholder (Note 3) 166,165 159,215
PROPERTY(at cost)(substantially pledged) (Notes 1&4)
Oil and gas (successful efforts method) 62,654,347 16,252,576
Other 837,205 354,603
------------ ------------
63,491,552 16,607,179
Less accumulated depletion, depreciation
and amortization (30,636,202) (5,332,517)
------------ ------------
32,855,350 11,274,662
OTHER ASSETS 7,958 7,523
------------ ------------
TOTAL ASSETS $ 37,252,572 $ 13,184,980
============ =============
</TABLE>
-2-
<PAGE> 35
LIABILITIES AND STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
1997 1996
------------ ----------
<S> <C> <C>
CURRENT LIABILITIES
Current maturities of long term debt (Note 4) $ 1,375,537 $ 554,601
Accounts payable - trade 1,176,680 381,870
Royalties payable 212,622 4,720
Other current liabilities 126,092 16,206
------------ ----------
Total current liabilities 2,890,931 957,397
LONG TERM DEBT (Note 4) 9,714,713 5,158,477
DEFERRED INCOME TAXES (Notes 1 & 5) 4,780,528 610,785
REDEMABLE COMMON STOCK (Note 8) -- 421,179
STOCKHOLDERS' EQUITY
Preferred stock, $.02 par, 5,000,000 shares
authorized with 1,666,667 shares designated
Series A, none other issued -- --
Cumulative convertible Series A 8% preferred
stock, $6 stated value, 1,666,667 designated,
1,666,667 and 166,667 shares issued and
outstanding at 12/31/97 and 12/31/96,
respectively, $10,000,000 aggregate liquidation
preference 10,000,000 1,000,000
Convertible preferred stock Series B, $7.50 stated
value, 266,667 shares issued and outstanding at
12/31/97. $2,000,000 aggregate liquidation
preference 3,627,000 --
Common stock, $.02 par value, 10,000,000 authorized,
4,519,206 and 1,880,917 shares issued and outstanding
at 12/31/97 and 12/31/96, respectively 90,392 37,618
Additional paid-in capital 23,029,299 6,049,442
Less redeemable common stock -- (421,179)
Unearned stock compensation (67,500) --
Accumulated deficit (16,744,751) (560,699)
Less cost of treasury stock; 21,773 shares
at 12/31/97 and 12/31/96 (68,040) (68,040)
------------ ------------
Total stockholders' equity 19,866,400 6,037,142
------------ ------------
COMMITMENTS AND CONTINGENCIES (Note 9)
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 37,252,572 $ 13,184,980
============ ============
</TABLE>
See accompanying notes to consolidated financial statements.
<PAGE> 36
MIDDLE BAY OIL COMPANY, INC.
Consolidated Statements of Operations
Years Ended December 31
<TABLE>
<CAPTION>
1997 1996
------------ ------------
<S> <C> <C>
REVENUES
Oil and gas sales $ 10,213,047 $ 4,474,786
Gain on sale of oil and gas properties 7,018 37,815
Delay rental and lease bonus income 975,347 --
Other 237,583 373,820
------------ ------------
Total revenue 11,432,995 4,886,421
COSTS AND EXPENSES
Operating expenses, including production taxes 3,848,627 1,516,011
Geological and geophysical costs 222,608 --
Abandonment costs 1,118,838 428,598
Impairments 21,147,823 277,483
Depletion, depreciation and amortization 4,567,063 1,184,713
Interest 671,081 504,945
Stock compensation expense 202,500 --
General and administrative 2,361,124 662,288
Other 317,469 32,012
------------ ------------
Total expenses 34,457,133 4,606,050
(LOSS) INCOME BEFORE INCOME TAX
(BENEFIT) EXPENSE (23,024,138) 280,371
INCOME TAX (BENEFIT)EXPENSE (Note 5)
Current 6,451 5,079
Deferred (7,451,249) 69,792
------------ ------------
(7,444,798) 74,871
------------ ------------
NET (LOSS)INCOME $(15,579,340) $ 205,500
Dividends to preferred stockholders (604,712) --
------------ ------------
NET (LOSS)INCOME AVAILABLE TO
STOCKHOLDERS $(16,184,052) $ 205,500
============ ============
NET (LOSS)INCOME PER SHARE
Basic $ (4.76) $ 0.15
============ ============
Diluted $ (4.76) $ 0.14
============ ============
WEIGHTED AVERAGE COMMON SHARES
OUTSTANDING
Basic 3,397,117 1,332,141
============ ============
Diluted 3,397,117 1,449,855
============ ============
</TABLE>
See accompanying notes to consolidated financial statements.
-3-
<PAGE> 37
MIDDLE BAY OIL COMPANY, INC.
Consolidated Statements of Changes in Stockholders' Equity
Years Ended December 31, 1997 and 1996
<TABLE>
<CAPTION>
Preferred Stock
--------------- ---------------- Common
Series A Series B Stock
------- ------ ---- -------- -------- ------
Shares Amount Shares Amount Shares Amount
--------- ----------- ------- ---------- --------- -------
<S> <C> <C> <C> <C> <C> <C>
BALANCE - 1/1/96 -- $ -- -- $ -- 1,318,917 $26,378
Common stock issued in
acquisition of NPC Energy
Corporation -- -- -- -- 562,000 11,240
Preferred stock issued 166,667 1,000,000 -- -- -- --
Conversion of redeemable
common stock to common
stock -- -- -- -- -- --
Net income -- -- -- -- -- --
Treasury stock acquired -
21,773 shares -- -- -- -- -- --
--------- ----------- ------- ---------- --------- -------
BALANCE - 12/31/96 166,667 1,000,000 -- -- 1,880,917 37,618
Common stock issued in
acquisition of NPC Energy
Corporation -- -- -- -- 33,463 677
Preferred Series A issued 1,500,000 9,000,000 -- -- -- --
Common stock issued in
acquisition of Bison Energy
Corporation -- -- -- -- 605,556 12,111
Common stock issued in
acquisition of Shore Oil
Company -- -- -- -- 1,883,333 37,667
Preferred Series B issued
in acquisition of
Shore Oil Company -- -- 266,667 3,627,000 -- --
Conversion of redeemable
common stock to common
stock -- -- -- -- -- --
Restricted stock awards -- -- -- -- 49,091 982
Stock options exercised -- -- -- -- 40,833 817
Purchase of oil and gas
working interests -- -- -- -- 26,013 520
Unearned stock
compensation -- -- -- -- -- --
Net loss -- -- -- -- -- --
8% Preferred stock Series
A dividends -- -- -- -- -- --
--------- ----------- ------- ---------- --------- -------
BALANCE - 12/31/97 1,666,667 $10,000,000 266,667 $3,627,000 4,519,206 $90,392
========= =========== ======= ========== ========= =======
</TABLE>
See accompanying notes to consolidated financial statements.
-4-
<PAGE> 38
<TABLE>
<CAPTION>
Additional Redeemable Unearned
Paid-in Common Stock Accumulated Treasury
Capital Stock Compensation Deficit Stock Total
------- ----- ------------ ------- ----- -----
<C> <C> <C> <C> <C> <C>
$ 4,093,682 $(852,642) $ -- $ (766,199) $ -- $ 2,501,219
1,955,760 -- -- -- -- 1,967,000
-- -- -- -- -- 1,000,000
-- 431,463 -- -- -- 431,463
-- -- -- 205,500 -- 205,500
-- -- -- -- (68,040) (68,040)
- ----------- --------- -------- ------------ -------- ------------
6,049,442 (421,179) -- (560,699) (68,040) 6,037,142
93,018 -- -- -- -- 93,695
-- -- -- -- -- 9,000,000
3,318,447 -- -- -- -- 3,330,558
12,938,498 -- -- -- -- 12,976,165
-- -- -- -- -- 3,627,000
-- 421,179 -- -- -- 421,179
269,018 -- -- -- -- 270,000
101,266 -- -- -- -- 102,083
259,610 -- -- -- -- 260,130
-- -- (67,500) -- -- (67,500)
-- -- -- (15,579,340) -- (15,579,340)
-- -- -- (604,712) -- (604,712)
- ----------- --------- -------- ------------ -------- ------------
$23,029,299 $ -- $(67,500) $(16,744,751) $(68,040) $ 19,866,400
=========== ========= ======== ============ ======== ============
</TABLE>
<PAGE> 39
MIDDLE BAY OIL COMPANY, INC.
Consolidated Statements of Cash Flows
Years Ended December 31
<TABLE>
<CAPTION>
1997 1996
-------- ------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net(loss) income $(15,579,340) $ 205,500
Adjustments to reconcile net(loss) income
to net cash provided by operating activities:
Depletion, depreciation and amoritization 4,567,065 1,184,713
Impairments 21,147,823 277,483
Deferred income taxes (7,451,249) 69,792
Bad debt expense 45,000 --
Unearned stock compensation 202,500 --
Gain on sale of assets (7,018) (37,814)
Changes in operating assets and liabilities:
(Increase) Decrease in receivables 243,777 (14,487)
Decrease in payables (438,355) (303,457)
Other (147,928) 7,648
------------ ------------
Net cash provided by operating activities 2,582,275 1,389,378
CASH FLOWS FROM INVESTING ACTIVITIES
Payment for acquisition of NPC Energy Corp.,
net of cash acquired of $633,712 -- (651,016)
Payment for acquisition of Bison Energy Corp.,
net of cash acquired of $994,367 (7,139,914) --
Payment for acquisition of Shore Oil Company
net of cash acquired of $2,057,467 (514,299) --
Capital expenditures:
Oil and gas properties (7,056,213) (1,596,966)
Office building and other (246,735) (8,188)
Proceeds from sales of:
Oil and gas properties 103,872 40,000
Timberland -- 75,000
Other 1,445,890 --
Advances to stockholders - net (6,950) (26,668)
------------ ------------
Net cash used in investing activities (13,414,349) (2,167,838)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds of bank loans 5,769,705 529,596
Principal payments on loans (2,497,533) (207,859)
Proceeds from issuance of preferred stock 9,000,000 1,000,000
Preferred stock dividends (604,712) --
Proceeds from common stock 195,772 --
Purchases of treasury stock -- (68,040)
------------ ------------
Net cash provided by financing activities 11,863,232 1,253,697
</TABLE>
-5-
(continued from opposite page)
<PAGE> 40
(continued from opposite page)
<TABLE>
<CAPTION>
1997 1996
------------ ------------
<S> <C> <C>
NET INCREASE IN CASH AND CASH
EQUIVALENTS FOR THE YEAR 1,031,158 475,235
Cash and cash equivalents - Beginning of year 556,026 80,791
------------ ------------
Cash and cash equivalents - End of year $ 1,587,184 $ 556,026
============ ============
SUPPLEMENTAL DISCLOSURES OF CASH FLOW
INFORMATION
Cash paid during the year for:
Interest $ 671,081 $ 504,945
============ ============
Income Taxes $ 6,451 $ 5,079
============ ============
Non-cash investing and financing activities:
Common stock issued in acquisition of
NPC Energy Corp. $ -- $ 1,967,000
============ ============
Conversion of redeemable common stock to common
stock (net of treasury shares acquired) $ 421,179 $ 363,423
============ ============
Common stock issued in acquisition of
Bison Energy Corp. $ 3,330,559 $ --
============ ============
Common stock issued in acquisition of
Shore Oil Company $ 12,976,165 $ --
============ ============
Preferred stock Series B issued in acquisition of
Shore Oil Company $ 3,627,000 $ --
============ ============
Debt assumed in acquisition of Shore Oil Company $ 2,105,000 $ --
============ ============
Common stock issued in property acquisition $ 260,130 $ --
============ ============
</TABLE>
See accompanying notes to consolidated financial statements.
<PAGE> 41
MIDDLE BAY OIL COMPANY, INC.
Notes to Consolidated Financial Statements
December 31, 1997 and 1996
(1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization
Middle Bay Oil Company, Inc. (the Company), was incorporated under the
laws of the state of Alabama on November 20, 1992. On December 31, 1996, the
Company acquired NPC Energy Corporation, and during 1997, the Company acquired
Bison Energy Corporation and Shore Oil Company (See Note 2). The Company is
engaged in the acquisition, development and production of oil and natural gas in
the contiguous United States.
Significant Accounting Policies
The Company's accounting policies reflect industry standards and
conform to generally accepted accounting principles. The more significant of
such policies are described below.
Principles of Consolidation
The consolidated financial statements include the accounts of the
Company and its wholly-owned subsidiaries. All significant intercompany balances
and transactions have been eliminated in consolidation.
Restatement of the 1997 Financial Statements
In 1998, the Company restated its 1997 financial statements to
correctly state deferred income taxes for improper inclusion of a valuation
allowance for deferred income taxes. This restatement resulted in an adjustment
decreasing the net loss and net loss available to stockholders by $1,125,542.
The net loss per share decreased $.34 as a result of the restatement.
Cash and Cash Equivalents
For purposes of the statements of cash flows, the Company classifies
all cash investments with original maturities of three months or less as cash.
Oil and Gas Property
The Company follows the successful efforts method of accounting for oil
and gas properties, and accordingly, capitalizes all direct costs incurred in
connection with the acquisition, drilling and development of productive oil and
gas properties. Costs associated with unsuccessful exploration are charged to
expense currently. Geological and geophysical costs and costs of carrying and
retaining unevaluated properties are charged to expense. Depletion, depreciation
and amortization of capitalized costs are computed separately for each property
based on the unit of production method using only proved oil and gas reserves.
In arriving at such rates, commercially recoverable reserves have been estimated
by independent petroleum engineering firms. The Company reviews its undeveloped
properties continually and charges them to expense on a property by property
basis when it is determined that they have been condemned by dry holes, or will
not be retained, sold or drilled upon.
Site Restoration, Dismantlement and Abandonment Costs
Site restoration, dismantlement and abandonment costs (P&A costs) are
common in the oil and gas industry in which the Company conducts operations. P&A
costs are costs associated with removing the facilities and equipment required
to operate a well and restoring the well site to specified conditions. P&A
procedures are governed by federal and state regulations and contractual
obligations. P&A costs are incurred when the oil and gas reserves of a well or
wells are depleted or when production drops to the point that it is no longer
economically feasible to produce.
-6-
<PAGE> 42
MIDDLE BAY OIL COMPANY, INC.
Notes to Consolidated Financial Statements
December 31, 1997 and 1996
Continued
(1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
Site Restoration, Dismantlement and Abandonment Costs (continued)
The Company, in conjunction with its independent engineers and the
operators of the wells, continually reviews its working interests with respect
to potential P&A costs. When conditions require that a well be plugged and
abandoned, the appropriate accounting procedures are followed. When a well, or
the last well of a group of proved properties ceases to produce or is no longer
economically feasible to produce, the entire cost related to the well or group
of wells, which includes estimated future dismantlement and abandonment cost,
is written off and gain or loss is recognized. Any additional liabilities
arising from P&A costs, net of salvage value of the equipment, are accrued in
the financial statements and charged to expense in the current period.
P&A costs are considered in the proved oil and gas reserve estimates as
disclosed in Note 11 - Supplemental Oil and Gas Reserve Information; and, if
material, the present value of the reserves is reduced accordingly.
As of December 31, 1997 and 1996, the P&A costs accrued were
immaterial.
Impairment of Long Lived Assets
Statement of Financial Accounting Standards No. 121 "Accounting for the
Impairment of Long Lived Assets and for Long Lived Assets to be disposed of"
(SFAS No.121) was issued in March 1995. This statement requires that long lived
assets be reviewed for impairment when events or changes in circumstances
indicate that the carrying value of such an asset may not be recoverable. This
review consists of a comparison of the carrying value of the asset to the
asset's expected future undiscounted cash flows without interest costs.
Estimates of expected future cash flows represent management's best
estimate based on reasonable and supportable assumptions and projections. If the
expected future cash flows are less than the carrying value of the asset, an
impairment exists and is measured as the excess of the carrying value over the
estimated fair value of the asset. Any impairment provisions recognized in
accordance with SFAS No. 121 are permanent and may not be restored in the
future.
In the fourth quarter of 1997 and 1996 the Company's proved properties
were assessed for impairment on an individual field basis and the Company
recorded impairment provisions of $21,147,823 and $277,483 respectively,
attributable to certain producing properties.
Prior to the adoption of SFAS No. 121, the Company assessed its proved
oil and gas properties on an individual field basis using management's best
estimate of the expected future cash flows from the producing properties.
Other Property and Equipment
Property and equipment are stated at cost and depreciation is computed
on the accelerated method over appropriate lives ranging from five to seven
years. Additions and betterments which provide benefits to several periods are
capitalized.
Environmental Liabilities
Environmental expenditures that relate to current or future revenues
are expensed or capitalized as appropriate. Expenditures that relate to an
existing condition caused by past operations, and do not contribute to current
or future revenue generation, are expensed. Liabilities are recorded when
environmental assessments and /or clean-ups are probable, and the costs can be
reasonably estimated. Generally, the timing of these accruals coincides with the
Company's commitment to a formal plan of action.
<PAGE> 43
MIDDLE BAY OIL COMPANY, INC.
Notes to Consolidated Financial Statements
December 31, 1997 and 1996
Continued
(1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
Revenue
Oil and gas revenues are recorded using the sales method, whereby the
Company recognizes revenues based on the amount of oil and gas sold to
purchasers on its behalf.
Income Taxes
The Company uses the asset and liability method of accounting for
income taxes required by the Statement of Financial Accounting Standards No.
109. Under the asset and liability method, deferred tax assets and liabilities
are determined by applying enacted statutory tax rates applicable to future
years to the difference between the financial statement and tax basis of assets
and liabilities.
Stock Based Compensation
In October 1995, The Financial Accounting Standards Board ("FASB")
issued SFAS No. 123, "Accounting for Stock Based Compensation", which
establishes financial accounting and reporting standards for stock based
compensation plans. Effective for fiscal years beginning after December 31,
1995, the statement provides the option to continue under the accounting
provisions of APB No. 25, while requiring proforma footnote disclosures of the
effects of net income and earnings per share, calculated as if the new method
had been implemented. The Company has adopted the financial reporting provisions
of SFAS No. 123 for 1997, but will continue under the accounting provisions of
APB Opinion 25.
Use of Estimates
Management of the Company has made a number of estimates and
assumptions relating to the reporting of assets and liabilities to prepare the
financial statements in conformity with generally accepted accounting
principles. Actual results could differ from those estimates.
Earnings Per Share
Effective December 31, 1997, the Company adopted SFAS No. 128,
"Earnings per Share." This statement establishes standards for computing and
presenting earnings per share, and requires, among other things, dual
presentation of basic and diluted earnings per share on the face of the
statement of operations. In accordance with SFAS No. 128, earnings per share and
weighted average shares outstanding have been restated to conform to this
statement for all periods presented.
Concentrations of Market Risk
The future results of the Company will be affected by the market prices
of oil and natural gas. The availability of a ready market for natural gas and
oil in the future will depend on numerous factors beyond the control of the
Company, including weather, production of other natural gas and crude oil,
imports, marketing of competitive fuels, proximity and capacity of oil and gas
pipelines and other transportation facilities, any oversupply or undersupply of
gas and oil, the regulatory environment, and other regional and political
events, none of which can be predicted with certainty.
<PAGE> 44
MIDDLE BAY OIL COMPANY, INC.
Notes to Consolidated Financial Statements
December 31, 1997 and 1996
Continued
(1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (concluded)
Concentrations of Credit Risk
Financial instruments which subject the Company to concentrations of
credit risk consist primarily of cash and accounts receivable. The Company
places its cash investments with high credit qualified financial institutions.
Risk with respect to receivables is concentrated primarily in the current
production revenue receivable from multiple oil and gas producers, both major
and independent, and is typical in the industry. The Company sold oil and gas
representing approximately 14% of its total production to one customer, Warren
Petroleum, for the year ended December 31, 1997.
Accounting Pronouncements
In June 1997, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 130, "Reporting Comprehensive Income." This statement establishes
standards for reporting and display of comprehensive income and its components
in the Company's financial statements. Comprehensive income includes all changes
in the Company's equity except investments by and distributions to owners and
includes, among other things, foreign currency translation adjustments. In June
1997, the FASB also issued SFAS No. 131, "Disclosures about Segments of an
Enterprise and Related Information." This statement establishes standards for
reporting information about operating segments in annual financial statements
and requires selected information about operating segments be included in
interim reports issued to shareholders. Both of these statements are effective
for financial statements for periods beginning after December 15, 1997. As both
SFAS Nos. 130 and 131 establish standards for reporting and display, the Company
does not expect the adoption of these statements to have a material impact on
its financial condition or results of operations.
(2) ACQUISITIONS
On December 31, 1996, the Company completed the acquisition of NPC
Energy Corporation ("NPC"). The transaction consisted of a merger (the "NPC
Merger") of NPC into the Company and its separate corporate existence ceased.
The cost of acquiring NPC was approximately $3.20 million, consisting
of the following (in thousands):
<TABLE>
<S> <C>
Estimated fair value of 562,000 shares
of MBOC common stock issued.............................. $ 1,967
Cash consideration......................................... 1,226
Legal and accounting expenses.............................. 35
-------
$ 3,228
=======
</TABLE>
The fair value of the securities issued in connection with the NPC
Merger was calculated assuming the price of the Company's common stock was $3.50
per share.
<PAGE> 45
MIDDLE BAY OIL COMPANY, INC.
Notes to Consolidated Financial Statements
December 31, 1997 and 1996
Continued
(2) ACQUISITIONS (continued)
The Company's purchase price was allocated to the assets and
liabilities of NPC based on estimates of the fair values with the remaining
purchase price allocated to proved oil and gas properties. No goodwill was
recorded in this transaction.
The allocation of the purchase price is summarized as follows:
(in thousands)
<TABLE>
<S> <C>
Working capital......................................... $ 775
Oil and gas properties (proved)......................... 3,378
Debt assumed............................................ (385)
Deferred income taxes................................... (540)
-------
$ 3,228
=======
</TABLE>
On February 28, 1997, the Company completed the acquisition of Bison
Energy Corporation ("BEC"). The transaction consisted of a merger (the "Bison
Merger") of BEC into Bison Energy Corporation-Alabama, a wholly-owned subsidiary
of the Company. On February 28, 1997, Bison Energy Corporation-Alabama merged
into BEC and its separate corporate existence ceased. BEC continues as a
wholly-owned subsidiary of the Company.
The cost of acquiring BEC was approximately $10 million, consisting of
the following (in thousands):
<TABLE>
<S> <C>
Estimated fair value of 605,556 shares
of MBOC common stock issued....................... $ 3,330
Cash consideration.................................. 6,654
Legal and accounting expenses....................... 35
----------
$ 10,019
==========
</TABLE>
The fair value of the securities issued in connection with the merger
was calculated using the price of the Company's common stock at the time the
Bison Merger was announced to the public of $5.50 per share.
The Company's purchase price was allocated to the consolidated assets
and liabilities of BEC based on estimates of the fair values with the remaining
purchase price allocated to proved oil and gas properties. No goodwill was
recorded in this transaction.
The allocation of the purchase price is summarized as follows: (in
thousands)
<TABLE>
<S> <C>
Working capital..................................... $ 714
Oil and gas properties (proved)..................... 13,268
Yard equipment...................................... 465
Deferred income taxes............................... (4,428)
-----------
$ 10,019
===========
</TABLE>
The price paid for BEC and the allocation of the purchase price, both
detailed above, excludes the $1,445,890 allocated to non-oil and gas assets that
were purchased in the merger and sold on March 3, 1997 for $1,445,890.
<PAGE> 46
MIDDLE BAY OIL COMPANY, INC.
Notes to Consolidated Financial Statements
December 31, 1997 and 1996
Continued
(2) ACQUISITIONS (continued)
On June 30, 1997, the Company completed the acquisition of Shore Oil
Company ("Shore"). The transaction consisted of a merger (the "Shore Merger") of
Shore into Shore Acquisition Company Inc., a wholly-owned subsidiary of the
Company. On June 30, 1997, Shore Acquisition Company merged into Shore and its
separate corporate existence ceased. Shore continues as a wholly-owned
subsidiary of the Company.
The cost of acquiring Shore was approximately $19 million, consisting
of the following (in thousands):
<TABLE>
<S> <C>
Estimated fair value of 1,883,333 shares
of MBOC common stock issued...................... $ 12,976
Estimated fair value of 266,667 shares
of MBOC Series B preferred stock................. 3,627
Cash consideration................................. 2,533
Legal and accounting expenses...................... 38
----------
$ 19,174
==========
</TABLE>
The fair value of the securities issued in connection with the merger
was calculated using the average price of the Company's common stock at the time
the Shore Merger was announced to the public and further adjusted for
tradability restrictions. An independent valuation firm determined the
tradability discount for the Company's common stock.
The Company's purchase price was allocated to the consolidated assets
and liabilities of Shore based on estimates of the fair values with the
remaining purchase price allocated to proved and unproved oil and gas
properties. No goodwill was recorded in this transaction.
The allocation of the purchase price is summarized as follows:
(in thousands)
<TABLE>
<S> <C>
Working capital.................................... $ 2,288
Oil and gas properties (proved and unproved)....... 20,688
Fee minerals....................................... 5,495
Debt assumed....................................... (2,105)
Deferred income taxes.............................. (7,192)
-----------
$ 19,174
===========
</TABLE>
<PAGE> 47
MIDDLE BAY OIL COMPANY, INC.
Notes to Consolidated Financial Statements
December 31, 1997 and 1996
Continued
(2) ACQUISITIONS (concluded)
The following pro forma data presents the results of the Company for
the twelve months ended December 31, 1997 and 1996, as if the acquisitions of
NPC, BEC and Shore had occurred on January 1, 1996. The pro forma results are
presented for comparative purposes only and are not necessarily indicative of
the results which would have been obtained had the acquisitions been consummated
as presented. The following data reflect pro forma adjustments for oil and gas
revenues, production costs, depreciation and depletion related to the properties
and businesses acquired, preferred stock dividends on preferred stock issued,
and the related income tax effects (in thousands, except per share amounts).
<TABLE>
<CAPTION>
Pro Forma (Unaudited)
1997 1996
--------- -----------
<S> <C> <C>
Total revenues.................................... $ 14,753 $ 15,068
Net loss.......................................... (22,466) (946)
Loss per diluted share............................ (6.61) (0.65)
</TABLE>
(3) RELATED PARTY TRANSACTIONS
The Company had a note receivable from Bay City Energy Group, Inc.
(successor entity to Bay City Minerals, Inc., effective September 26, 1995) a
significant stockholder, as of December 31, 1997 and 1996 in the amount of
$166,165 and $159,215 respectively. The principal balance of the note accrues
interest at 5% annually and is due January 1, 2001. The note is secured by
75,000 shares of Company common stock. Bay City Energy Group, Inc. made no cash
payments to the Company and was advanced $26,668 during the year ended December
31, 1996. Interest of $27,160 was accrued on the note as of December 31, 1997.
The Company rents office space from C.J. Lett III, a shareholder,
officer and director of the Company. The rent is $3,000 per month for three
years through February, 2000.
Gary R. Christopher, a shareholder and director of the Company, is
employed by Kaiser-Francis Oil Co., which owns approximately 43% of the common
stock of the Company.
<PAGE> 48
MIDDLE BAY OIL COMPANY, INC.
Notes to Consolidated Financial Statements
December 31, 1997 and 1996
Continued
(4) LONG-TERM DEBT
Long-term debt at December 31, 1997 and 1996, consisted of the
following:
<TABLE>
<CAPTION>
1997 1996
------------ -----------
<S> <C> <C>
Convertible Loan for $50,000,000 due March 31, 1998, secured by oil
and gas properties, monthly payments of interest only at LIBOR
plus 1.75%, convertible
into a 72 month term note on March 31, 1998 $ 10,956,298 $ --
Convertible loan for $6,000,000 due September 30, 1997, Secured by
oil and gas properties, monthly payments of interest only at
1.5% over prime, convertible into a 72
month term note on September 30, 1997 -- 5,186,596
Term note due August 31, 1998, secured by oil and gas
properties, repayable in monthly installments of $27,590
plus interest at 9.5% -- 385,089
Note, due 1/1/99, secured by office building, repayable in
monthly installments of $1,511 including interest at 73/4% 133,952 141,393
------------ -----------
Total 11,090,250 5,713,078
Less current maturities (1,375,537) (554,601)
------------ -----------
Long term debt excluding current maturities $ 9,714,713 $ 5,158,477
============ ===========
</TABLE>
On April 3, 1996, the Bank converted its $5.6 million term note into a
$6.0 million, one-year, revolving line-of-credit (the "6 million Convertible
Loan"), effective April 1, 1996. The $6 million Convertible Loan required
monthly payments of interest only at prime plus 1.5% and converted into a term
note payable in seventy-one consecutive equal monthly principal and interest
payments at prime plus 1.5%, with the remaining principal and interest payment
due on March 31, 2003. Effective March 31, 1997, the Company refinanced the $6
million Convertible Loan at its current principal balance of $5,186,596 with a
$15 million Convertible Loan. The $15 million Convertible Loan required monthly
payments of interest only at prime for one year and converts into a term note
payable in seventy-one consecutive equal monthly principal and interest payments
at prime, with the remaining principal and interest payment due on March 31,
2004. The $15 million Convertible Loan also required payment of a commitment fee
equal to an annual rate of three-eighths percent of the excess of the Borrowing
Base over the principal balance of the convertible note. Effective August 25,
1997, the Company refinanced the $15 million Convertible Loan at its current
principal balance of $5,851,298 with a $50 million Convertible Loan. The $50
million Convertible Loan requires monthly payments of interest only at a fixed
rate of Libor plus 1.75% as long as the principal amount of the loan is less
than 75% of the current borrowing base of $15 million. If the principal amount
of the loan is greater than or equal to 75% of the borrowing base the rate
increases to Libor plus 2.00%. The Company has the option of switching to a
floating prime rate. The $50 million Convertible Loan converts into a term note
<PAGE> 49
MIDDLE BAY OIL COMPANY, INC.
Notes to Consolidated Financial Statements
December 31, 1997 and 1996
Continued
(4) LONG-TERM DEBT (concluded)
payable in seventy-one consecutive equal monthly principal and interest payments
at prime, with the remaining principal and interest payment due on March 31,
2004. The $50 million Convertible Loan also requires payment of a commitment fee
equal to an annual rate of three-eighths percent of the excess of the Borrowing
Base over the principal balance of the convertible note. The principal balance
of the $50 million Convertible Loan at December 31, 1997 was $10,956,298.
The initial borrowing base of the $50 million Convertible Loan at
closing on August 25, 1997, was $15 million. The borrowing base will be
redetermined on March 31 and September 30, commencing September 30, 1997, by the
Bank's engineers or any other independent engineer using the Bank's pricing and
discount factors and the future net revenue expected to be produced from the
Company's oil and gas reserves. If at any time during the period of the
Convertible Loan (and the period subsequent to the conversion to the term note)
the collateral borrowing base, as determined by the Bank, should be less than
the aggregate unpaid principal balance of the note, the collateral deficiency
shall be cured by making a cash prepayment on the note in the amount of the
deficiency or by increasing the monthly principal payments for the next six
months to reduce the principal balance to the projected borrowing base as of the
next semiannual redetermination date.
The $50,000,000 convertible loan contains certain restrictive provisions
the most significant of which restricts additional borrowings, either directly
or indirectly, and payment of dividends. At December 31, 1997, the Company was
in compliance with all covenants specified in the agreement.
Aggregate amounts of expected required repayments of long term debt at
December 31, 1997 are as follows:
<TABLE>
<S> <C>
1998 $ 1,375,537
1999 1,954,001
2000 1,826,050
2001 1,826,050
2002 1,826,050
Thereafter 2,282,562
-------------
$ 11,090,250
</TABLE>
<PAGE> 50
MIDDLE BAY OIL COMPANY, INC.
Notes to Consolidated Financial Statements
December 31, 1997 and 1996
Continued
(5) INCOME TAXES
Income tax (benefit)expense for the years ended December 31 consisted
of the following:
<TABLE>
<CAPTION>
1997 1996
---- ----
<S> <C> <C>
Current $ 6,451 $ 5,079
Deferred (7,451,249) 69,792
------------ -----------
Total $ (7,444,798) $ 74,871
============ ===========
</TABLE>
The reconciliation of income tax computed at the U.S. federal statutory
tax rates to the provision for income taxes is as follows:
<TABLE>
<CAPTION>
1997 1996
---- ----
<S> <C> <C>
Income tax (benefit)expense at statutory rate $(7,828,207) $ 92,595
Increase(decrease) due to effect of graduated tax rates 96,853 (96,740)
Increase due to state taxes and other 286,556 79,016
----------- -----------
Income tax (benefit)expense $(7,444,798) $ 74,871
=========== ===========
</TABLE>
The Company's net deferred tax liability at December 31, 1997 and 1996
is as follows:
<TABLE>
<CAPTION>
1997 1996
---- ----
<S> <C> <C>
Deferred tax liability
Oil and Gas Properties $ 5,906,070 $ 817,079
Deferred tax asset
NOL carryforward (1,083,324) (164,076)
AMT tax credit carryforward (36,482) (36,482)
Other (5,736) (5,736)
------------ ----------
(1,125,542) (206,294)
Valuation allowance -- --
------------ ----------
Net deferred tax liability $ 4,780,528 $ 610,785
============ ==========
</TABLE>
As of December 31, 1997, the Company had net operating loss
carryforwards of $3,186,247 expiring in the years 2009 through 2011.
<PAGE> 51
MIDDLE BAY OIL COMPANY, INC.
Notes to Consolidated Financial Statements
December 31, 1997 and 1996
Continued
(6) RETIREMENT PLAN
All of the employees of the Company participate in a defined
contribution plan which provides for a maximum discretionary Company
contribution of 15% of total wages paid to employees for the year. The Company
contributed $51,560 and $5,000 to the plans for the years ended December 31,
1997 and 1996, respectively.
(7) STOCK OPTION AND STOCK APPRECIATION RIGHTS PLAN
At December 31, 1997, the Company had one fixed stock option plan, the
1995 Stock Option and Stock Appreciation Rights Plan (1995 Plan). The Company
applies APB Opinion 25, "Accounting for Stock Issued to Employees" and related
interpretations in accounting for the plan; accordingly, no compensation cost
has been recognized. Had compensation cost for the Company's 1995 Plan been
determined based on the fair value at the grant date for stock options granted
during 1997 and 1996 consistent with the method of FASB Statement 123,
"Accounting for Stock Based Compensation"' the Company's net income and earnings
per share would have been reduce to the pro forma amounts listed below:
<TABLE>
<CAPTION>
1997 1996
------------- ---------
<S> <C> <C> <C>
Net (Loss)Income As Reported $ (16,184,052) $ 205,500
Pro Forma (16,463,666) 189,657
Basic (loss)earnings per share As Reported $ (4.76) $ 0.15
Pro Forma (4.85) 0.14
Diluted (loss)earnings per share As Reported $ (4.76) $ 0.14
Pro Forma (4.85) 0.13
</TABLE>
The fair value of each option is estimated on the date of grant using
the Black-Scholes option-pricing model with the following assumptions used for
the grants in 1997 and 1996; no dividend yield; expected volatility of 60
percent and 50 percent, respectively; risk-free interest rate of 6.06% and
6.38%, respectively; and expected life of 3 years. At December 31, 1997, the
range of exercise prices and weighted average remaining contractual life of
options outstanding was $2.50 and $7.00 and 9.06 years, respectively.
The 1995 Plan
At December 31, 1997 there were 80,000 shares of common stock available
for grant under the 1995 plan. All of the options granted under the 1995 Plan
have an exercise price equal to the fair market value of the Company's common
stock at the date of the grant and expire ten (10) years from the date of grant
if not exercised. All of the options granted under the 1995 Plan are 100%
vested. The 1995 Plan is administered by the Compensation Committee of the Board
of Directors.
<PAGE> 52
MIDDLE BAY OIL COMPANY, INC.
Notes to Consolidated Financial Statements
December 31, 1997 and 1996
Continued
7) STOCK OPTION AND STOCK APPRECIATION RIGHTS PLAN (concluded)
Information relating to stock options is summarized below:
<TABLE>
<CAPTION>
Exercise Price
Shares Per Share
------ --------------
<S> <C> <C>
Options outstanding at January 1, 1996....................... -- --
Granted...................................................... 125,000 $ 2.50
---------
Options outstanding at December 31, 1996..................... 125,000 $ 2.50
Granted...................................................... 520,000 $ 6.07
Exercised.................................................... 40,833 $ 2.50
---------
Options outstanding at December 31, 1997..................... 604,167 $ 5.57
Options exercisable at December 31, 1997 604,167 $ 5.57
</TABLE>
Options to acquire 225,000 shares of the Company common stock at an
exercise price of $5.50 were granted outside of the 1995 Plan on February 13,
1997 to certain officers of the Company.
(8) CAPITAL STOCK
Preferred Stock
In connection with the merger with Shore Oil Company, effective June
30, 1997, the Company issued 266,667 shares of Series B Preferred Stock ("Series
B"). The Series B is nonvoting and pays no dividends. The Series B has a
liquidation value of $7.50 per share and is junior to the Series A Preferred.
For a period of sixty-six months subsequent to June 30, 1997 any holder of the
Series B may convert all or any portion of Series B shares into Company Common
Stock ("Common") at a ratio of one share of Common for each Series B share or at
any time on or after January 1, 1998, the holders may convert their Series B
Preferred shares based on a conversion method whereby the number of convertible
Series B Preferred shares is calculated as the increase in value of
approximately 40,000 acres of mineral interest owned by Shore at the end of the
year divided by $8,000,000 and multiplied by 266,667 shares. Each of the
convertible Series B Preferred shares is then multiplied by 1,066,000 to arrive
at the potential converted number of common shares. Upon expiration of the
conversion period, unless the Company has given notice to redeem the Series B,
all of the shares of Series B shall be automatically converted. In no event
shall the aggregate total number of shares of Common into which the Series B are
converted be less than 266,667 shares or exceed 1,333,333 shares, unless further
increased for any anti-dilution provisions.
<PAGE> 53
MIDDLE BAY OIL COMPANY, INC.
Notes to Consolidated Financial Statements
December 31, 1997 and 1996
Continued
(8) CAPITAL STOCK (continued)
Preferred Stock (concluded)
On September 4, 1996, the Company signed a stock purchase agreement
with Kaiser Francis Oil Company ("the Agreement"). Kaiser-Francis has agreed to
purchase 1,666,667 shares of Series A Preferred Stock ("Series A") at $6.00 per
share, for a total investment of $10,000,000. The parties agreed to a five-year
purchase period, effective September 4, 1996, with minimum incremental
investments of $500,000 each. Each issuance of Series A is subject to approval
by Kaiser-Francis of the use of proceeds. The Series A is nonvoting and accrues
dividends at 8% per annum, payable quarterly in cash. The Series A is
convertible at any time after issuance into shares of common stock at the rate
of two shares of common stock for each share of Series A before January 1, 1998.
The conversion rate decreases thereafter at 8% per annum. The Company will pay
the costs of registration of the Series A or the underlying common stock upon
request of Kaiser-Francis. The Company may redeem the Series A in whole or in
part, at any time after January 1, 2007 at a price of $6.00 per share. As of
December 31, 1997, 1,666,667 shares of the Series A had been issued.
Common Stock
On April 1, 1996, the Board of Directors authorized the repurchase of
up to $100,000 of Company common stock at a price per share not to exceed $3.25,
exclusive of brokerage costs. As of December 31, 1997 the Company had purchased
21,773 shares of common stock at a cost of $68,040.
Under the terms of the Janex Acquisition in 1993, the Company had a
contingent obligation to repurchase 142,107 common shares issued in the Janex
Acquisition, upon written notice delivered to the Company, beginning five years
after the closing date and continuing for thirty days thereafter, at a price of
$6.00 per share. This obligation will terminate if the Company's stock trades at
a share price of $8.00 or greater for twenty consecutive trading days during the
thirty-six month period ending November 1, 1998. At the close of trading on
April 7, 1997, the Company's common stock had traded at an ask price that was
equal to, or exceeded, $8.00 per share for twenty consecutive trading days.
Therefore, the contingent obligation represented by the redeemable common stock
balance on the Company's balance sheet in the amount of $421,179 was
reclassified to additional paid-in capital effective April 7, 1997.
On February 13, 1997, the Company awarded the President,
Vice-President/ Chief Financial Officer and Vice-President of Engineering stock
options to acquire 100,000, 62,500 and 62,500 shares of common stock,
respectively, at an exercise price of $5.50 per share. All of the options vested
on the date of grant. The exercise price was equal to the fair market value of
common stock on the date of grant. On the same date, the Company awarded to the
President, Vice-President/ Chief Financial Officer and Vice-President of
Engineering, 25,909, 11,591 and 11,591 shares of restricted stock of the
Company, respectively. The restricted stock awards are contingent on the
performance of services to the Company in the future with 50% of the restricted
shares being earned over the six month period July, 1997 to December 31, 1997
and 50% over the six month period January 1, 1998 to June 30, 1998. As of
December 31, 1997, 50% of the restricted stock awards had been earned.
On May 30, 1997, the Board of Directors granted options to acquire
85,000 shares of Company common stock under the 1995 Stock Option and Stock
Appreciation Rights Plan to certain key employees. All of the options vested on
the grant date of May 30, 1997 with an exercise price of $7.75 per share, which
was equal to the fair market value of common stock on the date of grant. The
options expire ten years from the date of grant if not exercised.
<PAGE> 54
MIDDLE BAY OIL COMPANY, INC.
Notes to Consolidated Financial Statements
December 31, 1997 and 1996
Continued
(8) CAPITAL STOCK (concluded)
Common Stock (concluded)
On February 6, 1997, the Board of Directors granted options to acquire
210,000 shares of Company common stock under the 1995 Stock Option and Stock
Appreciation Rights Plan to key employees and non-employee directors. All of the
options vested on the grant date of February 6, 1997 with an exercise price of
$6.00 per share, which was equal to the fair market value of common stock on the
date of grant. The options expire ten years from the date of grant if not
exercised.
On May 31, 1996, the Board of Directors granted options to acquire
125,000 shares of Company common stock under the 1995 Stock Option and Stock
Appreciation Rights Plan to key employees and non-employee directors. All of the
options vested on the grant date of May 31, 1996 with an exercise price of $2.50
per share, which was equal to the fair market value of common stock on the date
of grant. The options expire ten years from the date of grant if not exercised.
Earnings Per Share
The following table provides a reconciliation between basic and diluted
earnings (loss) per share:
<TABLE>
<CAPTION>
Weight Average Per
Common Shares Share
Net (Loss)Income Outstanding Amount
---------------- ------------- --------
<S> <C> <C> <C>
Year Ended December 31, 1997:
Basic earnings per share $(16,184,052) 3,397,117 $ (4.76)
Effect of dilutive stock options -- -- --
------------ --------- --------
Diluted earnings per share $(16,184,052) 3,397,117 $ (4.76)
============ ========= ========
Year Ended December 31, 1996 (restated):
Basic earnings per share $ 205,500 1,332,141 $ .15
Effect of dilutive stock options -- 117,714 (.01)
------------ --------- --------
Diluted earnings per share $ 205,500 1,449,855 $ .14
============ ========= ========
</TABLE>
At December 31, 1997, the Company had 604,167 stock options outstanding
with exercise prices ranging from $2.50 to $7.75 which were not included in the
computation of diluted earnings per share, because the effect of the assumed
exercise of these stock options would have an antidilutive effect on the
computation of diluted loss per share.
<PAGE> 55
MIDDLE BAY OIL COMPANY, INC.
Notes to Financial Statements
December 31, 1997 and 1996
Continued
(9) COMMITMENTS AND CONTINGENCIES
The Company is obligated under the terms of certain operating leases
for office space that expire over the next three years. Total rent expense was
$97,588 and $12,144 for the years ended December 31, 1997 and 1996,
respectively. Future minimum rental payments under the Company's leases total
$149,658, $114,912, and $6,000 for 1998, 1999, and 2000, respectively.
On April 3, 1996, the Company entered into a Joint Expense and
Participation Agreement with Brigham Oil & Gas, L.P. which allowed the Company
to participate in the drilling of ninety-one (91) onshore wells in Texas and
Oklahoma over the twelve month period beginning April 1, 1996. The Company
committed to fund $1,500,000 in drilling costs over this twelve month period. As
of December 31, 1997, the Company had advanced $1,944,499 in drilling and
completion costs to Brigham Oil and Gas, L.P. The Company is no longer required
to advance any additional money under the Agreement.
As of December 31, 1997, the Company is committed to pay approximately
$400,000 under various AFEs for work to be performed in 1998. The actual amounts
due may be higher or lower than the amounts estimated in the AFEs.
The Company is a defendant in various legal proceedings which are
considered routine litigation incidental to the Company's business, the
disposition of which management believes will not have a material effect on the
financial position or results of operations of the Company.
(10) SUBSEQUENT EVENTS
Recent Transactions
On January 31, 1998, Kaiser Francis Oil Company converted 100% of the
shares of the Series A Preferred stock into 3,333,334 common shares of the
Company.
On February 19, 1998, the Company commenced a cash tender offer for the
common shares of Enex Resources Corporation ("Enex") at a price of $15 per
share. As of February 10, 1998, there were 1,343,352 common shares of Enex
outstanding. On a diluted basis, there would be 1,486,352 shares outstanding.
The purpose of the tender offer is to acquire common shares that will represent
at least a majority of the outstanding common stock of Enex. The tender offer is
intended to result in the acquisition of 100% of Enex's outstanding common
stock. The tender offer is scheduled to expire on March 16, 1998, unless
extended. Enex is an independent oil and gas production and development company,
headquartered in Kingwood, Texas, with operations primarily in Texas. Enex
common stock trades on the NASDAQ National Market System.
<PAGE> 56
MIDDLE BAY OIL COMPANY, INC.
Notes to Consolidated Financial Statements
December 31, 1997 and 1996
Continued
(11) SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
CAPITALIZED COSTS AND COSTS INCURRED (UNAUDITED)
The following tables present the (1) capitalized costs related to oil
and gas producing activities and the related depreciation, depletion,
amortization and impairment and (2) costs incurred in oil and gas property
acquisition, exploration and development activities (in thousands).
<TABLE>
<CAPTION>
1997 1996
-------- --------
<S> <C> <C>
Capitalized Costs
- -----------------
Proved properties $ 56,441 $ 15,561
Nonproducing leasehold 6,118 376
Support equipment & facilities 95 315
Accumulated depreciation, depletion, amortization
and impairment (30,456) (5,237)
-------- --------
Net capitalized costs $ 32,198 $ 11,015
======== ========
Costs Incurred
- --------------
Proved properties $ 38,099 $ 3,402
Unproved properties 6,195 --
Exploration costs 1,912 1,453
Development costs 1,862 540
-------- --------
Total $ 48,068 $ 5,395
======== ========
Depletion, depreciation, amortization
and impairment $ 25,651 $ 1,433
======== ========
</TABLE>
ESTIMATED QUANTITIES OF RESERVES (UNAUDITED)
The Company has interests in oil and gas properties that are located
principally in Alabama, Louisiana, Kansas, New Mexico, Oklahoma and Texas. The
Company does not own or lease any oil and gas properties outside the United
States. There are no quantities of oil and gas subject to long-term supply or
similar agreements with any governmental agencies.
The Company retains independent engineering firms to provide annual
year end estimates of the Company's future net recoverable oil, gas and natural
gas liquids reserves. The information for 1997 is based upon estimates prepared
by Lee Keeling and Associates, Inc., Cawley, Gillespie and Associates, Inc.,
Ryder Scott Company, Huddleston & Company, Inc., and DeGoyler & MacNaughton,
which were engaged to perform an evaluation of the Company's oil and gas
reserves. The information for 1996 was prepared by Lee Keeling and Associates,
Inc. and Cawley, Gillespie and Associates, Inc. The reserve information was
prepared in accordance with guidelines established by the Securities and
Exchange Commission. Estimated proved net recoverable reserves as shown below
include only those quantities that can be expected to be commercially
recoverable at prices and costs in effect at the balance sheet dates under
existing regulatory practices and with conventional equipment and operating
methods. Proved developed reserves represent only those reserves expected to be
recovered through existing wells. Proved undeveloped reserves include those
reserves expected to be recovered from new wells or on undrilled acreage or from
existing wells on which a relatively major expenditure is required for
recompletion.
<PAGE> 57
MIDDLE BAY OIL COMPANY, INC.
Notes to Consolidated Financial Statements
December 31, 1997 and 1996
Continued
(11) SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (continued)
ESTIMATED QUANTITIES OF RESERVES (UNAUDITED) (continued)
Net quantities of proved developed and undeveloped reserves of natural
gas and crude oil, including condensate and natural gas liquids, are summarized
as follows:
<TABLE>
<CAPTION>
Years Ended
December 31
--------------------- ------------------------
1997 1996
----------- ---------- ---------- ----------
Oil Gas Oil Gas
Proved Reserves (Barrels) (Mcf) (Barrels) (Mcf)
- --------------- ---------- ----------- ---------- ----------
<S> <C> <C> <C> <C>
Beginning of year 1,389,945 8,964,238 777,550 6,370,830
Revisions of previous estimates (205,733) (1,431,708) 157,099 44,543
Extensions and discoveries 22,520 705,020 76,492 392,275
Purchases of reserves in place 1,980,117 12,110,748 503,156 3,139,299
Sale of reserves in place -- -- (15,726) --
Production for the year (253,849) (1,929,298) (108,626) (982,709)
---------- ----------- ---------- ----------
End of year 2,933,000 18,419,000 1,389,945 8,964,238
========== =========== ========== ==========
Proved Developed Reserves
- -------------------------
Beginning of year 1,266,421 8,142,820 770,334 6,306,604
========== =========== ========== ==========
End of year 2,580,000 14,251,000 1,266,421 8,142,820
========== =========== ========== ==========
</TABLE>
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED RESERVES
(UNAUDITED)
The following is a summary of the standardized measure of discounted
future net cash flows related to the Company's proved oil and gas reserves. For
these calculations, estimated future cash flows from estimated future production
of proved reserves are computed using oil and gas prices as of the end of each
period presented. Future development and production costs attributable to the
proved reserves were estimated assuming that existing conditions would continue
over the economic lives of the individual leases and costs were not escalated
for the future. Estimated future income taxes were calculated by applying
statutory tax rates (based on current law adjusted for permanent differences and
tax credits) to the estimated future pre-tax net cash flows related to proved
oil and gas reserves, less the tax basis of the properties involved.
<PAGE> 58
MIDDLE BAY OIL COMPANY, INC.
Notes to Consolidated Financial Statements
December 31, 1997 and 1996
Continued
(11) SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (continued)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED RESERVES
(UNAUDITED) (continued)
The Company cautions against using this data to determine the value of
its oil and gas properties. To obtain the best estimate of the fair value of the
oil and gas properties, forecasts of future economic conditions, varying
discount rates, and consideration of other than proved reserves would have to be
incorporated into the calculation. In addition, there are significant
uncertainties inherent in estimating quantities of proved reserves and in
projecting rates of production that impair the usefulness of the data.
The standardized measure of discounted future net cash flows relating
to proved oil and gas reserves are summarized as follows (in thousands):
<TABLE>
<CAPTION>
Years Ended
December 31
----------- ----------
1997 1996
---------- ----------
<S> <C> <C>
Future cash inflows $ 101,482 $ 61,813
Future production costs and development costs (54,358) (25,873)
Future income tax expenses (11,853) (7,361)
--------- ----------
Future net cash flows 35,271 28,579
10% discount to reflect timing of cash flows (10,778) (10,716)
--------- ----------
Standardized measure of discounted
future net cash flows $ 24,493 $ 17,863
========= ==========
</TABLE>
The following are the principal sources of changes in the standardized
measure of discounted future net cash flows (in thousands):
<TABLE>
<CAPTION>
Years Ended
December 31
1997 1996
--------- ---------
<S> <C> <C>
Beginning of year $ 17,863 $ 9,250
Sales of oil and gas, net of production cost (6,364) (2,959)
Net changes in price and production cost (11,108) 8,521
Extensions and discoveries 851 1,966
Purchase of reserves 20,293 6,006
Sale of reserves -- (29)
Revisions of quantity estimates and other 1,794 (2,551)
Net change in income taxes (1,082) (3,382)
Accretion of discount 2,246 1,041
--------- --------
End of year $ 24,493 $ 17,863
========= =========
</TABLE>
<PAGE> 59
MIDDLE BAY OIL COMPANY, INC.
Notes to Consolidated Financial Statements
December 31, 1997 and 1996
Concluded
(11) SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (concluded)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED RESERVES
(UNAUDITED) (concluded)
During recent years, there have been significant fluctuations in the
prices paid for crude oil in the world markets. The situation has had a
destabilizing effect on the crude oil posted prices in the United States,
including the posted prices paid by purchasers of the Company's crude oil. The
year end prices of oil and gas at December 31, 1997 and 1996, used in the above
table were $16.18 and $24.50 per barrel of oil and $2.54 and $3.70 per thousand
cubic feet of gas, respectively.
<PAGE> 60
ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Inapplicable.
[The remainder of this page has been intentionally left blank]
II - 42
<PAGE> 61
PART III
ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS;
COMPLIANCE WITH SECTION 16(A) OF THE EXCHANGE ACT
(a) Executive Officers and Directors
The following table sets forth the executive officers and
directors of the Company as of December 31, 1997. All directors serve for a
one-year term or until the next Annual Meeting of Shareholders of the Company.
The Board of Directors held three meetings during the fiscal year ended December
31, 1997. Each director attended all meetings of the Board. Executive officers
serve at the pleasure of the Board of Directors.
<TABLE>
<CAPTION>
Director
Name Age Position(s) Held Since
---- --- ---------------- -----
<S> <C> <C> <C>
John J. Bassett(1) 39 Chairman, President and 1989
Chief Executive Officer
C. J. Lett, III 40 Executive Vice President 1997
Frank C. Turner, II(2)(3) 37 Vice President and Chief N/A
Stephen W. Herod(3) 38 Vice President 1997
Financial Officer
Robert W. Hammons 44 Vice President N/A
Lynn M. Davis 49 Secretary and Treasurer N/A
Edward P. Turner, Jr.(1)(2) 68 Director 1989
Frank E. Bolling, Jr. 38 Director 1992
Alvin V. Shoemaker(4) 59 Director 1997
Gary R. Christopher 48 Director 1997
</TABLE>
(1) John J. Bassett and Edward P. Turner, Jr. were elected upon the
organization of Middle Bay Oil Company as a corporation in November, 1992.
Previously they served as directors of Bay City Minerals, Inc., the general
partner of the Predecessor Partnership.
(2) Edward P. Turner, Jr. and Frank C. Turner, II, are father and son.
(3) Mr. Herod replaced Frank C. Turner, II effective July 3, 1997.
III-1
<PAGE> 62
(4) Mr. Shoemaker replaced C. Noell Rather effective July 28, 1997.
John J. Bassett has served as President and a director of the
Company since 1992 and was elected Chairman of the Board of Directors in 1992.
He served as President of the general partner of the Predecessor Partnership
from 1987 to 1992. He also serves as a director and President of Bay City Energy
Group, Inc., a principal shareholder of the Company.
Stephen W. Herod has served as Vice President - Corporate
Development and a director of the Company since July 1, 1997. Mr. Herod served
as President and a director of Shore Oil Company from April, 1992 until the
merger of Shore and the Company on June 30, 1997. He joined Shore's predecessor
as Controller in February, 1991. In addition, Mr. Herod was employed by
Conquest Exploration Company from 1984 until 1991 in various financial
management positions, including Operations Accounting Manager. From 1981 to
1984, Mr. Herod was employed by Superior Oil Company as a financial analyst.
Frank C. Turner, II has served as Vice President and Chief
Financial Officer for the Company since its organization as a corporation in
1992. He had previously served as Vice President of Finance for the general
partner of the Predecessor Partnership since 1990. From 1987 to 1990, Mr. Turner
was employed by Sonat, Inc. as a financial analyst. He also serves as a director
and Vice President of Bay City Energy Group, Inc.
Robert W. Hammons was hired by the Company in April, 1992 as
a reservoir engineer. Mr. Hammons was appointed Vice President of Engineering of
the Company in 1993. Prior to his employment with the Company, he had worked
with Bay City Minerals, Inc. as an independent petroleum engineering consultant
since 1987. Prior to 1987, Mr. Hammons was employed as manager of reservoir
engineering for Marion Corporation.
Lynn M. Davis has been Secretary and Treasurer for the
Company since 1992. She has served as Secretary-Treasurer of the general partner
of the Predecessor Partnership since 1984 and as a director since 1988. Ms.
Davis also serves as a director and Secretary-Treasurer for Bay City Energy
Group, Inc.
Edward P. Turner, Jr. served as President of Bay City
Minerals, Inc. from 1975 to 1987. He is a member of the Alabama State Bar and a
managing partner of the law firm of Turner, Onderdonk, Kimbrough & Howell, P.A.,
in Chatom, Alabama. A substantial amount of his practice is devoted to oil and
gas law. Mr. Turner also serves as a director of Bay City Energy Group, Inc.
Frank E. Bolling, Jr. has been employed by Midstream Fuel
Services, Inc. as Vice President of Retail Operations since February, 1995.
Prior to his employment with Midstream, Mr. Bolling served as Vice President and
General Manager of Dantzler Bulk Plant, Inc., a distributor for Chevron U.S.A.,
Inc. with annual sales in excess of $25 million. Mr. Bolling served as sales
manager for Dantzler from 1987 to 1989. Prior to 1987, Mr. Bolling was employed
by Bay City Minerals, Inc.
Alvin V. Shoemaker is a former Chairman of the Board of
First Boston Corporation and former President of Blyth Eastman Paine Webber. He
has also worked for the U.S. Treasury. He has been Chairman of the Board of
Trustees of the University of Pennsylvania, Vice Chairman of the Securities
Industry
III-2
<PAGE> 63
Association and a director of Harcourt Brace Jovanovich, Royal Insurance of
America, the Council on Foreign Relations and the Wharton School of Finance
Board. Mr. Shoemaker is also a director of Hanover Compressor Company.
Gary R. Christopher is Acquisitions Coordinator of
Kaiser-Francis Oil Company, a position he has held since February, 1996. From
1991 to 1996, Mr. Christopher served as Senior Vice President and Manager of
Energy Lending for the Bank of Oklahoma. He continues to serve as a consultant
to the Bank of Oklahoma. Kaiser-Francis Oil Company owns 1,166,667 shares of the
Company's Series A Preferred stock; each such preferred share is convertible
into two shares of common stock.
C. J. Lett, III has served as Executive Vice President for the
Company since February 28, 1997. Mr. Lett is also President and a director of
Bison Energy Corporation, a position he has held since 1981.
(b) Compliance with Section 16(a) of the Exchange Act
Section 16(a) of the Securities Exchange Act of 1934 requires
the Company's directors and executive officers and any persons who own more than
10% of the Company's common stock to file with the Securities and Exchange
Commission reports of ownership and changes in ownership of such securities.
Based on representations from such persons, the Company believes that there was
no failure to file or delinquent filings under Section 16(a) of the Securities
Exchange Act of 1934 by any officer, director or beneficial owner of 10% or more
of the Company's common stock during 1997.
(c) Audit and Compensation Committees
The members of the Audit Committee are Gary R. Christopher,
Frank E. Bolling, Jr. and Alvin V. Shoemaker. The functions of the Audit
Committee include recommending to the Board of Directors the independent
auditors; reviewing and approving the planned scope of the annual audit;
proposing fee arrangements; reviewing the results of the annual audit; reviewing
the adequacy of the accounting and financial controls; reviewing the
independence of the independent auditors; approving all assignments to be
performed by the independent auditors; and instructing the independent auditors,
as deemed appropriate, to undertake special assignments.
The members of the Compensation Committee are John J. Bassett,
Edward P. Turner, Jr. and Frank E. Bolling, Jr. The functions of the
Compensation Committee are to approve or recommend for approval to the Board of
Directors, the compensation and remuneration arrangements for directors and
senior management.
III-3
<PAGE> 64
ITEM 10. EXECUTIVE COMPENSATION
(a) Summary Compensation Table
The following table sets forth the aggregate cash compensation
earned by and paid to the Company's executive officers for the periods ended
December 31, 1995 through December 31, 1997:
<TABLE>
<CAPTION>
Annual Compensation Long-Term Compensation
------------------------------------- -----------------------
Awards Payouts
------ -------
Securities
Underlying
Restr. Options/ All Other
Name and Other Annual Stock SARs LTIP Compensation
Principal Position Year Salary ($) Bonus ($) Compensation Awards($) (#) Payouts ($) ($)
------------------ ---- ---------- --------- ------------ --------- --- ----------- ---
<S> <C> <C> <C> <C> <C> <C> <C> <C>
John J. Bassett 1997 95,521 6,001 -- 129,545 132,000 -- 13,032
President & 1996 58,075 -- -- -- 20,000 -- 2,271
Chief Executive 1995 56,250 -- -- -- -- -- 11,371
Officer
Frank C. Turner, II 1997 85,729 6,000 -- 57,960 94,500 -- 16,250
Vice President & 1996 54,458 -- -- -- 20,000 -- 2,174
CFO 1995 50,083 -- -- -- -- -- 10,775
Robert W. Hammons 1997 85,729 6,000 -- 57,960 94,500 -- 12,500
Vice President - 1996 58,075 -- -- -- 20,000 -- 2,271
Engineering 1995 56,250 -- -- -- -- -- 11,360
</TABLE>
(b) Option Grants in Last Fiscal Year
The 1995 Stock Option and Stock Appreciation Rights Plan (the
"Plan") is administered by the Compensation Committee (the "Committee") of the
Board of Directors. At least two members of the Committee must be disinterested
nonemployee directors. The Committee is authorized to determine the employees,
including officers, to whom options or rights are granted. Each option or right
granted shall be on such terms and conditions consistent with the Plan as the
Committee may determine, but the duration of any option or right shall be not
greater than ten years or less than five years from the date of grant.
Options or rights grants shall be made under the Plan only to
persons who are officers or salaried employees of the Company or are nonemployee
directors. The aggregate number of shares of common stock of the Company which
could be subject to options or rights under the Plan during 1997 was 500,000.
During the fiscal year ended December 31, 1997, options covering 295,000 shares
were issued under the Plan.
The option price of shares covered by options granted under
the Plan may not be less than the fair market value at the time the option is
granted. The option price must be paid in full in cash or cash equivalent at the
time of purchase or prior to delivery of the shares in accordance with cash
payment arrangements acceptable to the Committee. If the Committee so
determines, the option price may also be paid in shares of the Company's common
stock already owned by the optionee. The Committee has discretion to
III-4
<PAGE> 65
determine the time or times when options become exercisable, within the limits
set forth in the Plan. All options and rights granted under the Plan will,
however, become fully exercisable if there is a change in control (as defined in
the Plan) of the Company.
The following table provides certain information with respect
to all options granted during the fiscal year ended December 31, 1997 to any
executive officer or director of the Company; 295,000 options were granted under
the Plan and 225,000 were granted outside of the Plan:
INDIVIDUAL GRANTS
<TABLE>
<CAPTION>
Number of
Securities % of Total
Underlying Options/SARs
Options/ Granted to
SARS Employees in Exercise or Base Expiration
Name Granted (#) Fiscal Year Price ($/Sh) Date
---- ----------- ----------- ------------ ----
<S> <C> <C> <C> <C>
John J. Bassett 100,000 19.0% 5.50 2/13/2007
32,000 6.0% 6.00 2/6/2007
Frank C. Turner, II 62,500 12.0% 5.50 2/13/2007
32,000 6.0% 6.00 2/6/2007
Robert W. Hammons 62,500 12.0% 5.50 2/13/2007
32,000 6.0% 6.00 2/6/2007
Lynn M. Davis 8,000 2.0% 6.00 2/6/2007
Edward P. Turner, Jr.* 21,400 4.0% 6.00 2/6/2007
Frank E. Bolling, Jr.* 21,400 4.0% 6.00 2/6/2007
C. Noell Rather** 21,200 4.0% 6.00 2/6/2007
</TABLE>
*Nonemployee director
**Former nonemployee director
III - 5
<PAGE> 66
(c) Aggregated Option Exercises in Last Fiscal Year and Option
Value Table as of December 31, 1997
The following table sets forth certain information concerning
each exercise of stock options during the year ended December 31, 1997, by each
of the named executive officers and directors and the aggregated fiscal year-end
value of the unexercised options of each such named executive officer and
director:
INDIVIDUAL GRANTS
<TABLE>
<CAPTION>
Number of Securities Value of Unexercised
Underlying Unexercised In-the-Money
Shares Options/SARs at Options/SARs at
Acquired Value FY End (#) FY End ($)
----------------------- ------------------------
Name on Exercise (#) Realized ($) Exer. Unexer. Exer. Unexer.
- ----------------------- --------------- ------------ ----------------------- ------------------------
<S> <C> <C> <C> <C> <C> <C>
John J. Bassett -- -- -- 152,000 -- 728,000
Frank C. Turner, II 20,000 115,000 20,000 94,500 150,000 409,250
Robert W. Hammons -- -- -- 114,500 -- 559,250
Lynn M. Davis 5,000 38,750 -- 8,000 37,500 32,000
Edward P. Turner, Jr.* -- -- -- 34,734 -- 185,600
Frank E. Bolling, Jr.* -- -- -- 34,733 -- 185,600
</TABLE>
*Nonemployee director
(d) Other Compensation Under Plans
The Company established a SEP/IRA retirement plan (the "SEP
Plan") in 1993 which allows for a maximum discretionary Company contribution of
15% of total wages paid to employees for the year. For the years ended December
31, 1997, 1996 and 1995, the Company contributed a total of $51,500, $5,000 and
$30,000 to the SEP Plan, respectively, including $32,064, $3,068 and $18,505,
respectively, for all executive officers as a group.
The Company established a 401-K Plan in October, 1997 which
allows for voluntary contributions by the employees and the employer. No Company
contributions were made in 1997.
The Company has no other retirement, pension/profit sharing
or other deferred compensation plan for its employees.
III-6
<PAGE> 67
(e) Long-Term Incentive Plan ("LTIP") Awards Table
In March, 1995, the Board of Directors adopted an employee
incentive compensation plan whereby the proceeds equivalent to 1% net profits
interest (the "net profits interest") in all oil and gas properties, drilling
prospects and divestitures acquired or made after January 1, 1994 are paid
into a fund for incentive compensation awards to employees. For the years ended
December 31, 1996 and 1995, the Company paid $6,916 and $30,000, respectively,
to employees through the employee incentive plan, including $4,897 and $21,245
for all executive officers as a group. No amount was paid into the plan in 1997.
(f) Directors' Fees
Directors of the Company receive a fee of $500 per meeting and
are reimbursed for documented travel expenses. Certain nonemployee directors
have received stock options for their services as directors (see "Option Grants
in Last Fiscal Year," above).
(g) Employee Contracts and Termination of Employment and
Change-in-Control Arrangements
Mr. Bassett and Mr. Hammons in January, 1997, signed
employment agreements with the Company which extend through January 31, 2002 and
January 31, 2000, respectively, with automatic one-year extensions upon each
anniversary date of the employment agreement thereafter unless either party
gives at least 30 days' notice of termination. Each employment agreement is
terminable by the Company before expiration of the term if such termination is
for cause (as specified in the employment agreement). The executive employment
agreements provide for an annual salary of not less than the base salaries of
$95,000 and $85,000, respectively, which amounts may be adjusted from time to
time by the Board of Directors upon the recommendation of the Compensation
Committee. They also provide for fringe benefits in accordance with the
Company's policies adopted from time to time for salaried executive employees
holding comparable positions.
Mr. Herod executed an employment agreement with the Company
with an effective date of July 1, 1997 and extending through June 30, 1999, with
automatic one-year extensions upon each anniversary date of the employment
agreement thereafter unless either party gives at least 30 days' notice of
termination. The employment agreement is terminable by the Company before
expiration of the term if such termination is for cause (as specified in the
employment agreement). The executive employment agreement provides for an annual
salary of not less than the base salary of $100,000, which amount may be
adjusted from time to time by the Board of Directors upon the recommendation of
the Compensation Committee. It also provides for fringe benefits in accordance
with the Company's policies adopted from time to time for salaried executive
employees holding comparable positions.
III-7
<PAGE> 68
ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
(a) Security Ownership of Certain Beneficial Owners
The following table sets forth the shares of the Company's
common and preferred stock beneficially owned by those persons known by the
Company to be the beneficial owner of more than five percent of the Company's
issued and outstanding common and preferred stock as of December 31, 1997:
<TABLE>
<CAPTION>
Title of Name and Address of Amount and Nature of Percent of
Class(6) Beneficial Owner Beneficial Ownership Class
----- ------------------- -------------------- -----
<S> <C> <C> <C>
Common C. J. Lett, III(1)(4) 1,197,556 13.8%
9320 East Central
Wichita, Kansas 67206
Common Kaiser-Francis Oil Company(4) 3,333,334 38.3%
6733 South Yale
Tulsa, Oklahoma 74136
Common Weskids, L.P.(2)(5) 843,687 10.0%
310 South Street
Morristown, NJ 07960
Common Weskids, Inc. 843,687 10.0%
310 South Street
Morristown, NJ 07960
Common Alvin V. Shoemaker(3)(4) 661,222 8.9%
8800 First Avenue
Stone Harbor, NJ 08247
Preferred Weskids, L.P.(5) 117,467 44.1%
Series B 310 South Street
Morristown, NJ 07960
Preferred Alvin V. Shoemaker(4) 117,466 44.1%
Series B 8800 First Avenue
Stone Harbor, NJ 08247
Preferred Stephen W. Herod(4) 15,867 5.9%
Series B 1110 Briar Ridge Drive
Houston, TX 77057
</TABLE>
III-8
<PAGE> 69
<TABLE>
<S> <C> <C> <C>
Preferred W. Tim Sexton(4) 15,867 5.9%
Series B 12010 Winwood
Houston, TX 77024
</TABLE>
(1) Mr. Lett has agreed that, for a period of one year from February 28, 1997,
his voting power will be restricted to not more than votes representing 20%
of the total number of shares of the Company's common stock issued and
outstanding and eligible to vote at the time in connection with any vote
taken or consent, waiver or ratification given in connection with the
election or removal of directors of the Company.
(2) Weskids, L.P. has agreed that, for a period of one year from June 30, 1997,
its voting power will be restricted to not more than votes representing 20%
of the total number of shares of the Company's common stock issued and
outstanding and eligible to vote at the time in connection with any vote
taken or consent, waiver or ratification given in connection with the
election or removal of directors of the Company.
(3) Mr. Shoemaker has agreed that, for a period of one year from June 30, 1997,
his voting power will be restricted to not more than votes representing 20%
of the total number of shares of the Company's common stock issued and
outstanding and eligible to vote at the time in connection with any vote
taken or consent, waiver or ratification given in connection with the
election or removal of directors of the Company.
(4) The nature of the beneficial ownership is sole voting and investment power.
(5) Weskids, L.P. is presently the beneficial owner and has sole voting and
disposition power of 843,687 shares of common stock and 117,467 shares of
Series B preferred stock immediately convertible into not less than 117,467
shares of the Company's common stock. The exact conversion ratio is
determined by the terms of the merger. Weskids, Inc. is the general
partner of Weskids, L.P. and effectively controls Weskids, L.P. The
officers and directors of Weskids, Inc. are as follows: J. Peter Simon,
director; William Edward Simon, Jr., director; Michael B. Lenard,
President; Mark J. Butler, Vice President/Treasurer; and Christine W.
Jenkins, Secretary.
(6) Series B preferred stock is convertible into common stock at a variable
ratio of not less than one-to-one.
III-9
<PAGE> 70
(b) Security Ownership of Management
The following table sets forth the shares of the Company's common
stock beneficially owned by each director and executive officer and all
directors and executive officers as a group, all as of February 28, 1998:
<TABLE>
<CAPTION>
CONV. PREFERRED NAME AND ADDRESS OF AMOUNT AND NATURE OF PERCENT OF
& OPTIONS STOCK BENEFICIAL OWNER BENEFICIAL OWNERSHIP(6) CLASS
--------- ----- ---------------- -------------------- ------
<S> <C> <C> <C> <C>
152,000 24,711 John J. Bassett 176,711 2.0%
4326 Noble Oak Trail
Houston, TX 77059
94,500 25,796 Frank C. Turner, II 120,296 1.4%
1406 Tallow Court
Seabrook, TX 77586
114,500 6,996 Robert W. Hammons 121,496 1.4%
915 Kentbury Court
Katy, TX 77450
8,000 5,000 Lynn M. Davis 13,000 0.1%
121 Donna Circle
Daphne, AL 36526
34,734 376,241 Edward P. Turner, Jr.(1) 410,975 4.7%
100 Central Avenue
Chatom AL 36518
15,000 1,182,556 C. J. Lett, III(2) 1,197,556 13.8%
9320 East Central
Wichita, KS 67206
34,734 -- Frank E. Bolling, Jr. 34,734 0.4%
3830 Kendale Drive
Gautier, MS 39553
-- 12,000 Gary R Christopher(3) 12,000 0.1%
6733 South Yale
Tulsa, OK 74136
117,466 661,222 Alvin V. Shoemaker(4) 778,688 8.9%
8800 First Avenue
Stone Harbor, NJ 08247
</TABLE>
III-10
<PAGE> 71
<TABLE>
<S> <C> <C> <C> <C>
15,867 109,816 Stephen W. Herod(5) 125,683 1.4%
1110 Briar Ridge Drive
Houston, TX 77057
All executive officers and
directors as a group
(10 persons) 2,991,139 34.3%
</TABLE>
(1) Includes 362,803 shares owned by Bay City Energy Group, Inc. in which
Mr. Turner has indirect voting control but not a direct beneficial
interest, and 13,438 shares over which Mr. Turner has sole voting and
dispositive power.
(2) Mr. Lett was named Executive Vice President of the Company on February
28, 1997 in connection with the Bison Merger (see "Business
Development"). Mr. Lett's voting rights are restricted until February
28, 1998 (see Item 11(a) above).
(3) Mr. Christopher is an officer of Kaiser-Francis Oil Company which is
the beneficial owner of 3,33,334 of the Company's common shares.
(4) Consists of 117,466 shares of Series B preferred stock convertible
into 117,466 common shares of the Company. Mr. Shoemaker's voting
rights are restricted until June 30, 1998 (see Item 11(a) above).
(5) Consists of 15,867 shares of Series B preferred stock convertible into
15,867 common shares of the Company. Mr. Herod's voting rights are
restricted in the same manner as Weskids, L.P. and Mr. Shoemaker.
(6) The nature of beneficial ownership for all shares is sole voting and
investment power.
(c) Changes in Control
There are no arrangements known to management which may result
in a change in control of the Company.
ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Edward P. Turner, Jr., a director of the Company, is managing partner
of the law firm of Turner, Onderdonk, Kimbrough & Howell, P.A., the Company's
general counsel for certain corporate and oil and gas matters. For the years
ended December 31, 1995 through 1997, the Company paid legal fees to Mr.
Turner's firm of $787, $1,560 and $2,874, respectively, for legal services. Mr.
Turner's firm charges the Company for its services on the same basis as it
charges other business clients for similar services rendered. The Company
intends to continue to use Mr. Turner's firm as its primary local counsel in
Alabama and will pay reasonable fees for such future services.
III-11
<PAGE> 72
Bay City Energy Group, Inc., is presently indebted to the Company in
the amount of $166,165 ($139,005 of principal and $27,160 of accrued interest).
The note payable was renegotiated on December 31, 1995 and is due in full on
January 1, 2001, plus interest at an annual fixed rate of 5%. The note payable
is secured by 75,000 shares of Company common stock. Edward P. Turner, Jr., a
director of the Company, has indirect voting control but not a beneficial
interest in Bay City Energy Group, Inc.
On December 31, 1996, NPC Energy Corp., then a company
indirectly controlled by C. J. Lett, III through Bison Energy Corporation
("Bison"), merged with the Company in exchange for 562,000 shares of common
stock of the Company and $1,226,400 cash. Subsequently, in February, 1997, the
Company acquired Bison as a wholly-owned subsidiary pursuant to an Agreement and
Plan of Merger whereby Mr. Lett received net cash consideration of $5.9 million
plus 1,167,556 shares of the Company's common stock, and the 562,000 shares held
by Bison (as a result of the NPC Merger) were canceled (see "Business
Development").
Gary R. Christopher, a director of the Company, is employed by
Kaiser-Francis Oil Company which directly owns 3,333,334 common shares or 42.57%
of the Company.
[The remainder of this page has been intentionally left blank.]
III-12
<PAGE> 73
PART IV
ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
<TABLE>
<CAPTION>
Sequential
Exhibit No. Description of Exhibit Page No.
----------- ---------------------- ----------
<S> <C> <C>
2.1 Agreement and Plan of Merger dated February 10, 1997
among the Company, Bison Energy Corporation, and C.J.
Lett(6) N/A
2.2 Agreement and Plan of Merger dated February 10, 1997
among the Company, Shore Oil Company, and its
shareholders(5) N/A
3.1 Articles of Incorporation(1) N/A
3.2 Articles of Amendment to Articles of Incorporation
reflecting reverse split(2) N/A
3.3 Articles of Amendment to Articles of Incorporation
designating preferences and rights of Series A
Preferred Stock(5) N/A
3.4 Articles of Amendment to Articles of Incorporation
designating preferences and rights of Series B
Preferred Stock(5) N/A
3.5 Bylaws(1) N/A
10.1 Executive Employment Agreement for John J. Bassett
dated January 30, 1997.(7) N/A
10.2 Executive Employment Agreement for Robert W. Hammons
dated January 30, 1997.(7) N/A
10.3 Executive Employment Agreement for Steve W. Herod dated
July 1, 1997.(7) N/A
11.1 Statement of Computation of Per-Share Earnings(7)
21.1 Subsidiaries of the Company(7) N/A
</TABLE>
IV-1
<PAGE> 74
(b) Reports on Form 8-K
None.
(1) Incorporated by reference to Exhibits to Registration Statement on Form
S-4 filed October 4, 1993.
(2) Incorporated by reference to Exhibits to definitive Proxy Statement filed
February 15, 1995.
(3) Incorporated by reference to Exhibits to definitive Proxy Statement filed
May 11, 1995.
(4) Incorporated by reference to Exhibits to Form 8-K filed September 19, 1996.
(5) Incorporated by reference to Exhibits to Form 8-K filed July 3, 1997.
(6) Incorporated by reference to Exhibits to Form 8-K filed February 25, 1997.
(7) Incorporated by reference to Exhibits to Form 10KSB/A filed May 15, 1998.
IV-2
<PAGE> 75
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
by the undersigned, thereunto duly authorized.
MIDDLE BAY OIL COMPANY, INC.
(Registrant)
By: /s/ John J. Bassett
---------------------------------------
John J. Bassett, President
October 16, 1998
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:
<TABLE>
<S> <C>
October 16, 1998 /s/ John J. Bassett
- ------------------------------------ -------------------------------------
Date John J. Bassett
Director, President Chief Executive
Operating Officer
October 16, 1998 /s/ C. J. Lett, III
- ------------------------------------ -------------------------------------
Date C. J. Lett, III
Executive Vice President and
Director
October 16, 1998 /s/ Stephen W. Herod
- ------------------------------------ -------------------------------------
Date Stephen W. Herod
Vice President and Director
October 16, 1998 /s/ Edward P. Turner, Jr.
- ------------------------------------ -------------------------------------
Date Edward P. Turner, Jr.
Director
October 16, 1998 /s/ Frank E. Bolling, Jr.
- ------------------------------------ -------------------------------------
Date Frank E. Bolling, Jr.
Director
October 16, 1998 /s/ Gary R. Christopher
- ------------------------------------ -------------------------------------
Date Gary R. Christopher
Director
October 16, 1998 /s/ Alvin V. Shoemaker
- ------------------------------------ -------------------------------------
Date Alvin V. Shoemaker
Director
</TABLE>
