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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-KSB
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998 COMMISSION FILE NUMBER 0-21702
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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 Identification
Incorporation or Organization) No.)
1221 LAMAR STREET, SUITE 1020, 77010
HOUSTON, TEXAS (Zip Code)
(Address of Principal Executive Offices)
Registrant's telephone number, including area code: (713) 759-6808
Securities registered pursuant to Section 12(b) of the Act:
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TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
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None N/A
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Securities registered pursuant to Section 12(g) of the Act:
Common Stock, $.02 Par Value
Securities registered pursuant to Securities Act of 1933:
Series C Convertible Redeemable Preferred Stock, $.02 Par Value
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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. Yes /X/ No
/ /
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, 1998 are
$17,702,578.
The aggregate market value as of March 19, 1999 of voting stock held by
nonaffiliates of the Registrant was $3,777,828.
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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).
8,530,589 Shares of Common Stock, $.02 Par Value, as of March 19, 1999
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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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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.
"MINERAL SERVITUDE"--A right that grants use of another's property for the
purpose of extracting the minerals.
"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.
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"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.
"PROVED UNDEVELOPED RESERVES"--Reserves that are expected to be recovered
from new wells on undrilled acreage or from existing wells where a relatively
major expenditure is required for recompletion.
"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) COMPANY OVERVIEW
Middle Bay Oil Company, Inc. (the "Company" or "Middle Bay") 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
Gulf Coast and Mid-Continent regions. Middle Bay believes the current period
reflects historically low market prices for oil and natural gas and is focusing
its efforts on increasing reserves and production 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 exploration drilling in the Gulf Coast and Mid-Continent
regions of the contiguous United States. In November 1997, Middle Bay relocated
its principal executive offices from Mobile, Alabama 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 and
liabilities 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 Middle Bay. The Predecessor Partnership was then
dissolved under the Alabama Uniform Limited Partnership Act. The shares of
common stock of Middle Bay 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.
This document includes "forward-looking statements" within the meaning of
various provisions of the Securities Act and Securities Exchange Act of 1934, as
amended (the "Exchange Act"). The words "expect," "estimate," "anticipate,"
"predict," "believe," and similar expressions and variations thereof are
intended to identify forward-looking statements. All statements, other than
statements of historical facts, included in this document that address
activities, events, or developments that the Company expects or anticipates will
or may occur in the future, including such things as estimated future net
revenues from oil and natural gas reserves and the present value thereof, future
capital expenditures (including the amount and nature thereof), business
strategy and measures to implement strategy, competitive strengths, goals,
expansion, and growth of Middle Bay's business and operations, plans, references
to future success, references to intentions as to future matters and other such
matters are forward-looking statements and include statements regarding
interest, belief or current expectations of the Company, its directors, or its
officers regarding such matters. These statements are based on certain
assumptions and analyses made by Middle Bay in light of its experience and its
perception of historical trends, current conditions and expected future
developments as well as other factors it believes are appropriate under the
circumstances. However, whether actual results and developments will conform
with the Company's expectations and predictions is subject to a number of risks
and uncertainties, including the risk factors discussed in this document,
general economic, market or business conditions, the opportunities (or lack
thereof) that may be presented to and pursued by Middle Bay, competitive actions
by other oil and gas companies, changes in laws or regulations, and other
factors, many of which are beyond the control of the Company. Consequently, all
of the forward-looking statements made in this document are qualified by these
cautionary statements and there can be no assurance that the actual results or
developments anticipated by Middle Bay will be realized or, even if
substantially realized, that they will have the expected consequences to or
effects on the Company or its business or operations.
(b) BUSINESS OF THE COMPANY
The Company's oil and gas reserves are principally in long-lived fields with
well-established production histories. Middle Bay's net Proved Reserves,
estimated as of December 31, 1998 by applying S.E.C
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assumptions, consisted of approximately 43,483 million cubic feet of gas and
3,342 thousand barrels of oil and natural gas liquids, with an aggregate present
value before income taxes, at a 10% discount, of $38,894,000. Approximately 79%
of the reserves are classified as proved developed producing, 8% are proved
developed non-producing and 13% are proved undeveloped. On an equivalent barrel
basis, the proved reserves are 68% gas. Recoverable volumes of gas increased
136% and recoverable volumes of oil increased 14% over 1997 volumes. The PV 10%
of the oil and gas reserves increased 29% over the 1997 amount of $30,179,000.
The reserves are located primarily in Alabama, Kansas, Louisiana, Oklahoma and
Texas. A substantial portion of Middle Bay'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 Middle
Bay'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 Middle Bay'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 development drilling
and to maintain an inventory of undeveloped Prospects 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;
- 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, administrative and
reserve acquisition costs.
ACQUISITION POLICY. Middle Bay continues to actively pursue a program of
acquiring producing oil and gas properties in either asset purchase or corporate
merger transactions, with the goal of increasing cash flow, reserves and value
for the long-term benefit of its stockholders.
The Company utilizes an acquisition screening approach with its experienced
management and technical staff that reviews potential acquisition properties
against multiple criteria, both quantitative and subjective. Middle Bay
generally seeks Producing Properties with established production histories. The
Company may operate the property acquired; however, Middle Bay also considers
non-operated 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
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balancing agreements, transportation agreements and reversionary interests that
may affect the cash flows from the property are also reviewed.
DRILLING ACTIVITIES. Middle Bay has participated in drilling operations
primarily in Texas, Louisiana and Kansas. The Company's drilling activity
increased significantly in 1996 when the Company entered into the Brigham
Agreement, described below. Middle Bay'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 December 1998 levels, the amount of funds available for
drilling could be reduced.
During the year ended December 31, 1998, Middle Bay drilled 23 gross wells;
14 Development Wells and 9 Exploratory Wells. Twelve of the Development Wells
and one of the Exploratory Wells were successful. The Company's drilling was
concentrated in Texas and Louisiana, where 13 and 5 wells were drilled,
respectively. In Texas, Middle Bay's drilling was concentrated in the Lake
Tramel West and Carthage fields. There were four wells drilled on the Company's
South Louisiana mineral acreage, three were unsuccessful Exploratory Wells and
one Development Well which was completed as a producer, the Shore Oil Company #1
in St. Mary Parish. One successful Exploratory Well was drilled on the Sherburne
Prospect, Point Coupee Parish, Louisiana. After evaluation of additional seismic
data, no further drilling is expected on the Sherburne Prospect.
The Quarry #1, an Exploratory Well being drilled as of December 31, 1998,
was plugged and abandoned in February 1999. This Exploratory Well was drilled on
the Quarry Prospect, Lea County, New Mexico. Middle Bay had prepaid
approximately $125,000 in drilling costs as of December 31, 1998 and expensed
the costs in the fourth quarter when it was determined the well was
unsuccessful.
For the twelve months ended December 31, 1997, Middle Bay 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, Middle Bay
participated in the drilling of 12 Exploratory Wells through the Brigham
Agreement. The Brigham Agreement ended March 31, 1997.
The 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 $311,000 in drilling costs as of December 31, 1997 and
expensed the costs in the fourth quarter when it was determined that the well
was abandoned.
Drilling activities during 1998 added 104 thousand barrels of oil and 290
million cubic feet of gas with estimated future net revenues, discounted at 10%,
of $732,000. 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. For the years 1997 and 1998, oil and gas reserves
discovered through current year drilling accounted for 3% and 2%, respectively,
of the year-end reserve value.
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 was lease
optioned for a 3-D seismic survey with Brigham serving as the operator. Middle
Bay purchased a 25% working interest through the lease selection phase of the
project for $225,000 and in July 1998 purchased an additional 2.5% carried
working interest for $251,250. This project involves approximately 142 square
miles of 3-D seismic data. A total of 94 square miles of new data was shot
during 1998 and merged into 60 square miles of existing 3-D data acquired in
early 1998 that covers acreage adjacent to the Ranch. Final processing of the
data was completed in November 1998 and interpretation is ongoing. Nine
prospects have been identified to date in the Miocene, Discorbis "B" and Tex
Miss Frio formations at depths between 6,000' and 15,000'. A total of
approximately 4,000 gross acres
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are currently under lease on and near the Ranch. At December 31, 1998, the
Company had incurred approximately $1,316,000 on the Hawkins Ranch project for
land, seismic and other costs.
During December 1998, the Company and Brigham sold a portion of their
interest in the Ranch project to Adams Resources Exploration Corporation for a
total of $2,000,000. In January 1999, Middle Bay received $500,000 of the
proceeds and currently owns a 20% working interest in the Ranch project. The
first well on the Hawkins Ranch project, the Ling Prospect, is expected to spud
in early March 1999. Two additional wells, on the Marlin and Amberjack
prospects, are expected to be drilled in the second quarter of 1999. The
proceeds from the sale of interest will fund the majority of Middle Bay's
portion of the drilling costs on the first three wells.
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 is the operator. A private company holds the
remaining 25%. The first well, the PMMI #1, was drilled and successfully
completed in the Sparta formation in June 1998. After evaluation of additional
seismic data shot in the third quarter of 1998, no further drilling is expected
on the Sherburne Prospect.
On April 3, 1996, the Company entered into a Joint Expense and Participation
Agreement (the "Brigham Agreement") with Brigham. The Brigham Agreement allowed
Middle Bay 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 (70%) were successfully completed.
In the foreseeable future, the Company's primary drilling focus will be its
participation in the Ranch Prospect and the development of the Spivey Field.
Middle Bay expects to drill several Development Wells in the Spivey Field in
Kansas in 1999, depending on oil prices. The Company also expects several wells
to be drilled on the Shore mineral acreage in South Louisiana in 1999. In
addition, Middle Bay 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 Middle
Bay 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 proved oil and gas reserves. For the years
1996 through 1998, acquisitions of reserves accounted for 27%, 67% and 59% of
the year-end before tax 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.)
On December 17, 1996, Middle Bay 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 Middle Bay 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, Middle Bay 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. In
addition, NPC had approximately $.8 million in working capital and $.4 million
in bank debt.
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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 Middle Bay 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 paid cash consideration of $6,654,000 to Bison in exchange
for all of the stock of Bison. 562,000 shares of Middle Bay 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. In addition, Bison had approximately $.7 million in working
capital.
On June 20, 1997, Middle Bay 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 Middle Bay 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 40,000 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, Middle Bay 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 South 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. In addition, Shore had approximately $2.3 million in working capital.
The Shore Merger also added approximately 40,000 net acres of fee minerals
situated in Lafourche, Terrebonne and St. Mary Parishes in Louisiana that were
valued by an independent oil and gas engineering firm at approximately $3.6
million at June 30, 1997.
In August 1997, the Company acquired a 5.74% working interest in proved
reserves with a January 1, 1997 effective date in the Riceville Field in
Vermilion Parish, Louisiana for approximately $3.5 million (the "Riceville
Acquisition"). 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. Using December 31, 1997 prices, the Riceville Acquisition had a
PV 10% of approximately $5.3 million.
On March 27, 1998, pursuant to a cash tender offer that commenced February
19, 1998, the Company acquired 1,064,432 common shares (79.2%) of Enex Resources
Corporation ("Enex") at $15.00 per share for $15,966,480 (the "Enex
Acquisition"). Middle Bay later acquired 9,747 additional shares of Enex in open
market transactions for $68,194 that increased its ownership in Enex to 80.0% at
December 31, 1998. Enex is a publicly traded (OTC Bulletin Board symbol: ENEX),
independent oil and gas development and production company with properties
located primarily in Texas. In addition, Enex is the general partner of Enex
Consolidated Partners, L. P., (the "Enex Partnership), a publicly held New
Jersey limited partnership whose primary business is oil and gas development and
production. Enex owns a 4.1% general partner interest and a 56.24% limited
partner interest in the Enex Partnership. The Enex Acquisition added
approximately 955 thousand barrels of oil and 18,950 million cubic feet of gas,
for a total proved reserve value of $15.9 million (PV 10%) as of March 31, 1998,
using December 31, 1998 prices. The proved reserve information related to the
Enex Acquisition is on a consolidated basis and includes 100% of the proved
reserves of Enex and the Enex Partnership. In addition, Enex had approximately
$5.6 million in working capital and no long-term debt.
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As part of the Enex Acquisition, the Company entered into a consulting
agreement, effective April 15, 1998, with the former President of Enex that
provides for monthly payments of $20,000 until the agreement expires on May 18,
2002. The monthly payments serve as consideration for consulting services, a
covenant not to compete and a preferential right to purchase certain oil and gas
acquisitions which the former president controls or proposes to acquire during
the term of the agreement. Middle Bay's total obligation under the consulting
agreement is $960,000.
On April 16, 1998, Middle Bay acquired substantially all of the oil and gas
assets of Service Drilling Co., LLC and certain affiliates ("Service Drilling")
in exchange for 666,000 shares of Company common stock and $6,500,000 cash for a
total acquisition cost of $10,054,775. Service Drilling is a privately held,
domestic exploration and production company with oil and gas properties located
primarily in Oklahoma and the Texas Panhandle. The Service Drilling acquisition
added approximately 299 thousand barrels of oil and 12,047 million cubic feet of
gas, for a total reserve value of $7.2 million (PV 10%) as of the effective date
of March 1, 1998, using December 31, 1998 prices.
On December 30, 1998, the Company closed on an exchange offer (the "Exchange
Offer") that began November 27, 1998 for limited partnership units of the Enex
Partnership. The $11.9 million transaction involved the issuance of 2,177,481
shares of Middle Bay's Series C preferred stock (the "Series C") and payment of
approximately $539,000 cash in exchange for the outstanding limited partnership
interests of the Enex Partnership, the transfer of the Enex Partnership's assets
and liabilities to Middle Bay, and the dissolution of the Enex Partnership.
Pursuant to the Exchange Offer, each partnership unit was valued at $10.43 and
the unitholders had the option of exchanging their units for the Series C (at a
conversion ratio of 2.086 Series C shares for each of the total 1,102,631
partnership units) or exercising dissenters' rights and receiving a cash payment
for their interests. The Company paid approximately $516,000 to unitholders who
exercised dissenters' rights, which was financed with bank debt, and
approximately $23,000 to unitholders in lieu of issuing fractional shares. In
addition, Middle Bay incurred approximately $431,000 in transaction costs
related to the Exchange Offer. Enex was general partner of the Enex Partnership
and owned 56.24% of the total outstanding limited partnership units. The intent
of the Exchange Offer was to acquire the 43.76% limited partnership units of the
Enex Partnership that the Company (through Enex) did not currently own.
Subsequent to the Exchange Offer, Enex owns 1,293,522 Series C shares, equal to
59.4% of the total outstanding Series C preferred stock. The total number of
Series C shares not held by the Company is 1,142,663, consisting of the 883,959
shares issued to holders of the 43.76% of limited partnership units not held by
Enex and 258,704 shares attributable to the 20% minority interest shareholders
of Enex.
The Series C pays cumulative cash dividends at the rate of 10% per year
(payable semi-annually on March 31 and September 30), has a $5.00 per share
liquidation preference and each Series C share is convertible at any time into
one share of Middle Bay common stock. After January 1, 2000, the Company may, at
its option, redeem the Series C for the liquidation value plus accrued
dividends. Middle Bay has applied to list the Series C on the NASDAQ Small Cap
Market.
The Enex Partnership acquisition added approximately 628 thousand barrels of
oil and 8,638 million cubic feet of gas, for a total proved reserve value of
$9.7 million (PV 10%) as of the effective date of October 1, 1998, using
December 31, 1998 prices. The proved reserve information related to the Enex
Partnership acquisition is on a consolidated basis and includes 100% of the
proved reserves of the Enex Partnership. In addition, the Enex Partnership had
approximately $1.0 million in working capital and no long-term debt. The Enex
Partnership properties are located primarily in Texas.
Middle Bay is currently in the process of evaluating various corporate
acquisitions and potential mergers in exchange for common and/or preferred stock
in the Company. Management believes that corporate acquisitions and mergers are
the fastest way to achieve Middle Bay'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.
I-6
<PAGE>
The price of oil has declined significantly since December 31, 1997 and, in
December 1998, reached the lowest level in over ten years. The posted price of
WTI crude declined from approximately $15.00 per barrel on December 31, 1997 to
approximately $9.50 per barrel on December 31, 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 Banks, issuance of convertible preferred stock and issuance of
common stock. Middle Bay's drilling activities have been financed primarily
through the Company's cash flow.
On September 4, 1996, Middle Bay 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 Middle Bay. At December 31,
1998, Kaiser-Francis owned 39.1% of the Company's outstanding common stock.
Prior to their conversion to common stock, the Series A shares 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 based in Tulsa, Oklahoma
whose majority shareholder is George B. Kaiser.
During 1997, the Company issued $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. In 1997, Middle Bay issued $3.627 million of Series B
Preferred Stock to finance a portion of the Shore Merger. In 1998, the Company
issued 2,177,481 shares of Series C preferred stock with a liquidation value of
approximately $10.9 million in connection with the Enex Partnership acquisition.
Middle Bay also issued its common stock in connection with the NPC, Bison and
Shore mergers as well as the Service Drilling acquisition.
In connection with the Enex Acquisition, effective March 27, 1998, the
Company entered into a new reducing revolving credit facility (the "$100 million
Revolver") with Compass Bank, N.A., as agent and lender, and Bank of Oklahoma,
N. A., as a participant lender, (collectively, the "Banks"). The $100 million
Revolver provided for an initial borrowing base of $29.0 million. The initial
borrowing base was reduced to $27.5 million ten days after the effective date
and further reduced by $275,000 per month, beginning May 1, 1998 and ending
October 1, 1998. In conjunction with the closing of the Service Drilling
acquisition on April 16, 1998, the borrowing base was increased to $32.6 million
and the monthly borrowing base reduction was increased to $330,000. Effective
October 1, 1998, the semi-annual borrowing base redetermination date, the
borrowing base was calculated to be $28.9 million with monthly borrowing base
reductions of $250,000 beginning November 1, 1998. Effective January 1, 1999,
upon the closing of the Enex Partnership acquisition, the borrowing base
determined at October 1, 1998 was adjusted to $33.1 million and the monthly
borrowing base reduction was increased to $290,000. The borrowing base at
December 31, 1998 was $32.5 million and the next semi-annual borrowing base
redetermination date is April 1, 1999.
The principal is due at maturity, April 1, 2001. Monthly principal payments
are made as required in order that the outstanding principal balance does not
exceed the borrowing base. Interest is payable monthly and is calculated at the
prime rate. The Company may also elect to calculate interest under the LIBOR
rate option, as defined in the agreement. Under the LIBOR rate option, interest
is calculated at the LIBOR rate plus (a) 2.00% if the outstanding loan balance
and letters of credit are equal to or greater than 75% of the borrowing base,
(b) 1.75% if the outstanding loan balance and letters of credit are equal to or
less than 75% or greater than 50% of the borrowing base, (c) 1.50% if the
outstanding loan balance and letters of credit are equal to or less than 50% of
the borrowing base. LIBOR interest is payable at maturity of the LIBOR loan
which cannot be less than thirty days.
At December 31, 1998, the loan balance was $27,454,567 and there was
approximately $1,163,647 of outstanding letters of credit. As of December 31,
1998, the Company was paying LIBOR plus 2.00% on a sixty day LIBOR loan for
$25,469,605 and prime on $1,984,962. The amount available under the borrowing
base on the $100 million Revolver was $3.9 million at December 31, 1998.
I-7
<PAGE>
As of December 31, 1998, the amount available under the borrowing base on
the $100 million Revolver was approximately $3.9 million. Assuming no other
changes, the amount available to be borrowed under the borrowing base at April
1, 1999 will be approximately $3.0 million. Middle Bay expects that the Banks
will complete the April 1, 1999 borrowing base redetermination by May 1, 1999.
The Company also expects that the borrowing base will be less than the amount
determined at the October 1, 1998 redetermination, adjusted for the monthly
borrowing base reductions. The decrease is expected to be caused primarily by
normal production declines and lower oil and gas pricing scenarios used by the
Banks to value oil and gas reserves for loan purposes. Pursuant to the terms of
the $100 million Revolver, if the borrowing base is less than the outstanding
principal balance plus outstanding letters of credit, Middle Bay has sixty days,
after receipt of written notice from the Banks, to cure the excess by
prepayment, providing additional collateral or a combination of both. The
Company is unable to predict the April 1, 1999 borrowing base. At the completion
of the April 1, 1999 redetermination, Middle Bay does not expect to be required
to make any prepayments or provide any additional collateral that would be
material to the financial condition of the Company.
The Company paid a facility fee equal to 3/8% of the initial borrowing base
and is required to pay 3/8% on any future increase in the borrowing base within
five days of written notice. Middle Bay is required to pay a quarterly
commitment fee on the unused portion of the borrowing base of 1/2% if the
outstanding loan balance plus letters of credit are greater than 50% of the
borrowing base or 3/8% if the outstanding loan balance plus letters of credit
are less than or equal to 50% of the borrowing base. The Company is required to
pay a letter of credit fee on the date of issuance or renewal of each letter of
credit equal to the greater of $500 or 1 1/2% of the face amount of the letter
of credit.
Middle Bay has granted to the Banks liens on substantially all of the
Company's oil and gas properties, whether currently owned or hereafter acquired,
and a negative pledge on all other oil and gas properties.
The $100 million Revolver requires, among other things, a cash flow coverage
ratio of 1.25 to 1.00 and a current ratio, excluding current maturities under
the $100 million Revolver, of 0.9 to 1.00, determined on a quarterly basis.
Under the terms of the $100 million Revolver, when mortgaged properties are
sold the borrowing base shall be reduced, and if necessary, proceeds from the
sales of properties shall be applied to the debt outstanding in an amount equal
to the loan value attributable to such properties sold. Of the total net
proceeds received from oil and gas property sales in 1998 of approximately
$4,784,000, $2,145,000 was used to repay principal on the $100 million Revolver.
In connection with the Shore Merger, effective August 25, 1997, the Bank of
Oklahoma, National Association converted the Company's then $15 million
convertible credit facility into a $50 million convertible credit facility. As
of December 31, 1997, the principal balance of the loan was $10,956,298.
Concurrent with the closing of the Enex Acquisition on March 27, 1998, the loan
balance was paid in full and refinanced as part of the $100 million Revolver.
Subject to availability of bank financing, Middle Bay will continue to
consider asset purchase transactions that meet the Company's acquisition
criteria. The Company currently has approximately $28.0 million borrowed on the
$100 million Revolver. Middle Bay intends to finance corporate mergers and
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.
The ability of Middle Bay 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 Middle Bay
I-8
<PAGE>
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 Middle Bay.
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 Middle Bay'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. Middle Bay 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 Middle Bay in the future.
EMPLOYEES. As of December 31, 1998, the Company employed 27 full-time
persons. Middle Bay employs 16 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 five full-time persons in its Wichita,
Kansas office, including one executive officer, a geologist, an engineer and two
administrative assistants. Middle Bay 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
Middle Bay owned a historic home in Mobile, Alabama, which previously served
as its corporate office before the Company's relocation to Houston, Texas in
November 1997. Middle Bay sold the property in December 1998 for $190,500. The
Company retired a $127,809 mortgage on the property, paid $11,241 in closing
costs and added the remaining proceeds of $51,450 to working capital.
(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.
The Company's largest oil and gas property, in terms of reserve volumes and
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. Middle Bay owns approximately 11.5% ownership
in the Plant and related gathering system. Warren Petroleum Company, L.P., and
Dynegy, Inc. (formerly NGC Corporation) jointly operate the Plant. Ownership in
the Plant is redetermined annually, based on each owner's throughput relative to
total throughput. Plant liquids (propane, butane and natural gasoline) are
marketed from the Plant to Murphy Energy. Residue gas is sold to KGE (f/k/a
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.
I-9
<PAGE>
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.
Middle Bay operates 74 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 evaluating and developing its acreage position of approximately
8,800 gross acres.
As of December 31, 1998, Middle Bay has identified and independent engineers
have evaluated 12 proved undeveloped locations in the Spivey Field with a PV 10%
value of approximately $.9 million. At December 31, 1998, the Plant was valued
by independent engineers at a $3.0 million PV 10%.
The following table shows proved oil and gas reserves by major field for the
Company's largest producing fields at December 31, 1998. The values represent
the present value of estimated future net cash flows before income taxes,
discounted at 10%, assuming unescalated expenses and prices of $9.50/Bbl and
$2.10/Mcf attributable to proved reserves at December 31, 1998, as determined by
Lee Keeling & Associates, Inc. and H. J. Gruy and Associates, Inc., 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 $ 7,459 19.2% 1,117 7,172
Harper/Kingman, KS
Riceville ..................................... Murphy 4,626 11.9% 57 2,555
Vermillion, LA
Segundo ....................................... Company 2,781 7.2% 0 8,133
Webb, TX
West Stigler .................................. Company 2,472 6.4% 0 5,282
Haskell, OK
East Seven Sisters ............................ Vastar 1,804 4.6% 0 2,108
Duval, TX
Stratton ...................................... Union Pacific 1,543 4.0% 81 1,494
Nueces/Kleberg, TX
Sawyer ........................................ Louis Dreyfus 1,383 3.4% 4 1,148
Sutton, TX
Hatter's Pond ................................. Texaco 787 2.0% 64 575
Mobile, AL
Lockhart Crossing ............................. Amoco 770 2.0% 17 747
Livingston, LA
Brooken ....................................... Company 704 1.8% 0 1,659
Haskell, OK
Others ........................................ Various 14,565 37.5% 2,002 12,610
----------- ----- ----- -----------
Total.......................................... $ 38,894 100.0% 3,342 43,483
----------- ----- ----- -----------
----------- ----- ----- -----------
</TABLE>
As of December 31, 1998, the Banks have a first mortgage on all of the
fields listed in the above table. The Banks also have a first mortgage on
numerous additional fields not individually listed above. Middle Bay is
obligated, within five days of request by the Banks, to grant the Banks a first
and prior mortgage on any oil and gas properties owned or acquired by the
Company.
I-10
<PAGE>
(c) LOUISIANA FEE MINERAL ACREAGE
In the Shore Merger, Middle Bay acquired approximately 40,342 net mineral
acres, situated in Terrebonne, Lafourche and St. Mary Parishes in South
Louisiana. Of the total acreage, 37,194 acres are non-producing, 2,528 acres are
held by production under existing leases and 620 acres prescribed in October
1997. The non-producing acreage is located in the following parishes: 18,704 in
Terrebonne (Montegut and Houma areas), 12,630 acres in Lafourche (Raceland and
Valentine areas) and 8,388 acres in St. Mary Parish (Charenton area). A total of
8,973 acres of the non-producing acreage are currently under lease and/or option
agreements with expiration dates as follows: 4,267 acres in 1999, 4,570 acres in
2000 and 136 acres in 2001. As of December 31, 1998, 28,221 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: 6,226 acres in 1999, 5,286 acres in 2002, 4,145 acres
in 2004, 1,189 acres in 2005, 1,145 acres held in perpetuity and the remaining
21,730 acres 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 85% of the non-producing minerals have been covered by 3-D seismic shot by
third parties and provided to the Company at no cost. For the period July 1,
1997 through December 31, 1997 and during 1998, the Company received
approximately $975,000 and $217,000, respectively, 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. In Terrebonne
Parish, two Exploratory Wells, the Middle Bay Oil Co. #1 and the Shore Oil Co.
#1, were drilled and abandoned in March and May 1998, respectively. A successful
Development Well in St. Mary Parish, the Shore Oil Company #1, was completed and
began production during November 1998. One unsuccessful Exploratory Well in St.
Mary Parish, the Middle Bay Oil Company #1, was drilled and abandoned in
December 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 Middle Bay owned an interest
for the period ended December 31, 1998. The Company operated approximately 275
wells at December 31, 1998. 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.
Middle Bay's net Developed Acreage is located primarily in Oklahoma, Texas,
Alabama, Louisiana, and Kansas. The Company's net Undeveloped Acreage is located
primarily in Kansas.
<TABLE>
<CAPTION>
ACREAGE
-------------------------
DEVELOPED UNDEVELOPED
----------- ------------
<S> <C> <C>
Gross Acres......................................................... 248,670 11,282
Net Acres........................................................... 40,548 8,454
<CAPTION>
PRODUCTIVE WELLS
-------------------------
OIL GAS
----------- ------------
<S> <C> <C>
Gross Wells......................................................... 276.00 212.00
Net Wells........................................................... 78.78 49.93
</TABLE>
Excluded from the acreage data are approximately 41,441 net mineral acres owned
by the Company, all of which are considered to have potential for oil and gas
exploration.
I-11
<PAGE>
(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.
Middle Bay 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,
--------------------------------------
1996 1997 1998
---------- ------------ ------------
<S> <C> <C> <C>
Crude Oil and Natural Gas Production:
Oil (Bbls).................................................... 108,626 283,849 581,457
Gas (Mcf)..................................................... 982,709 1,929,298 3,846,679
Average Sales Prices:
Oil (per Bbl)................................................. $ 20.26 $ 18.06 $ 11.52
Gas (per Mcf)................................................. $ 2.28 $ 2.39 $ 2.00
Average Production Costs Per BOE(1)............................. $ 5.36 $ 6.71 $ 6.38
</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.
(f) DRILLING ACTIVITIES
During the periods indicated, Middle Bay 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,
-------------------------------
1996 1997 1998
--------- --------- ---------
<S> <C> <C> <C>
Exploratory Wells:
Productive
Gross.............................................................. 31 8 1
Net................................................................ 0.987 0.452 0.125
Dry
Gross.............................................................. 18 11 8
Net................................................................ 0.675 1.280 0.793
Development Wells:
Productive
Gross.............................................................. 4 17 12
Net................................................................ 0.866 5.627 1.508
Dry
Gross.............................................................. 1 6 2
Net................................................................ 0.250 4.150 1.100
Total Wells:
Productive
Gross.............................................................. 35 25 13
Net................................................................ 1.853 6.079 1.633
Dry
Gross.............................................................. 19 17 10
Net................................................................ 0.925 5.430 1.893
</TABLE>
I-12
<PAGE>
As of March 23, 1999, Middle Bay was drilling one Exploratory Well on the
Ranch 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 Middle Bay's proved oil and gas reserves and
the standardized measure of discounted future net cash flows attributable to
such reserves as of December 31, 1998. At December 31, 1998, the Company's net
Proved Reserves consisted of 3,342 thousand barrels of oil and 43,483 million
cubic feet of gas, and net Proved Developed Reserves consisted of 3,118 thousand
barrels of oil and 36,731 million cubic feet of gas. At December 31, 1998, the
present value discounted at 10% for Middle Bay's Proved oil and gas reserves,
before income taxes, was approximately $38,894,000. (See Note 11 to the
Company's financial statements for additional detail on Middle Bay's oil and gas
reserves.) Management of the Company, however, cautions against using this data
to determine the fair value of Middle Bay'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, 1998 base oil prices of $9.50 per Bbl and
base gas prices of $2.10 per Mcf. 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, 1998.
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, 1996 through
1998:
<TABLE>
<CAPTION>
RECOVERABLE VOLUMES
----------------------
STANDARDIZED OIL GAS
YEAR ENDED MEASURE (MBBLS) (MMCF)
- ---------------------------------------------------------------------- ------------ ----------- ---------
<S> <C> <C> <C>
December 31, 1998..................................................... $ 38,893 3,342 43,483
December 31, 1997..................................................... $ 24,493 2,933 18,419
December 31, 1996..................................................... $ 17,863 1,389 8,964
</TABLE>
The increases in the standardized measure from 1996 to 1997 and 1997 to 1998
are due primarily to the Bison Merger, Shore Merger and Riceville Acquisition in
1997 and the Enex Acquisition and Service Drilling transactions in 1998. 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 Middle Bay'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.
I-13
<PAGE>
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders of Middle Bay
during the fourth quarter of the fiscal year ended December 31, 1998.
I-14
<PAGE>
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>
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
1998
First Quarter.......................................................... $ 10.00 $ 5.75
Second Quarter......................................................... 8.00 5.13
Third Quarter.......................................................... 5.13 3.00
Fourth Quarter......................................................... 3.50 1.88
</TABLE>
On March 12, 1999, the closing price of the common stock was $2.00 bid and
$2.25 asked.
(b) HOLDERS
As of March 12, 1999, the Company had 686 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 Compass Bank 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 on its common stock
in the foreseeable future. Any future determination as to the payment of common
stock 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 and any
other factors as the Board of Directors may deem relevant.
The Company is obligated to pay dividends on its Series C Preferred Stock in
the amount of $571,332 per year. The Company has received a waiver from Compass
Bank for the payment of dividends on the Series C Preferred Stock as long as no
default or event of default exists or would exist as a result of the payment of
the Series C Preferred Stock dividends.
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.
II-1
<PAGE>
(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, (iv) the
level of interest rates and (v) the level of general and administrative
expenses. Sales of production and level of borrowing capacity 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 increase (decrease) in oil and gas revenues,
excluding plant and other revenues, caused by price and volume changes for the
years ending December 31, 1998, 1997 and 1996.
<TABLE>
<CAPTION>
1998 1997 1996
------------- ------------ ----------
<S> <C> <C> <C>
Oil Revenues
Change due to volume........................................ $ 5,375,279 $ 3,549,922 $ 32,436
Change due to price......................................... (3,801,075) (644,906) 437,285
Total change................................................ 1,574,204 2,905,016 469,721
Gas Revenues
Change due to volume........................................ $ 4,578,268 $ 2,161,383 $ 149,921
Change due to price......................................... (1,507,115) 201,483 708,386
Total change................................................ 3,071,153 2,362,866 858,307
</TABLE>
(b) FISCAL 1998
For the current period, the revenues and expenses attributable to the Enex
Acquisition and the Enex Partnership Acquisition are included for the period
April through December and those attributable to the Service Acquisition are
included for the months of May through December. For the comparable period, the
revenues and expenses attributable to the Bison Merger are included for the
period March through December, the Shore Merger for the period July through
December and the Riceville Acquisition for the period August through December.
Total revenues for the current period, of $17,703,000, were $6,270,000
higher than the comparable period. The increase in total revenues was due
primarily to higher oil and gas revenues of $4,798,000 and higher gain on the
sale of properties. During the current period lease bonus and rental income on
the mineral acreage acquired in the Shore Merger decreased $758,000 and other
revenues increased $282,000.
Oil and gas revenues of $15,011,000 increased $4,798,000, consisting of a
$1,574,000 increase in oil revenues, a $3,071,000 increase in gas revenues and a
$153,000 increase in other revenues. The increase in oil and gas revenues was
the result of higher oil and gas production. Production of oil increased 105%
and production of gas increased 99%, over the comparable period. The oil
production increase of 297,000 barrels and the gas production increase of
1,918,000 Mcf, were due primarily to the Riceville Acquisition which closed in
1997, and the Enex and Service Acquisitions which closed in 1998. During the
current period, the Company sold 581,000 barrels of oil and 3,847,000 Mcf of
gas, as compared to 284,000 barrels and 1,929,000 Mcf for the comparable period.
The average price received on the gas sold in the current period of $2.00 per
Mcf was 16% lower than the $2.39 per Mcf received in the comparable period. The
average price received on the oil sold in 1998 of $11.52 per barrel was 36%
lower than the $18.06 per barrel received in the comparable period. For the
comparable period, production of oil was increased 30,000 barrels and oil
revenues were increased $441,000 due to a reclassification.
II-2
<PAGE>
The Company received $217,000 in lease bonus and delay rental income on the
fee mineral acreage acquired in the Shore Merger in the current period versus
$975,000 in the comparable period. The decrease in leasing activity is the
primary reason for the decline in income. The Company did not have any acreage
revert to the surface owners in the current period.
The gain on the sale of properties of $1,953,000 in the current period was
primarily the result of sales of non-strategic properties and was $1,946,000
higher than the comparable period. Also included in the current period gain is a
$365,000 gain on the sale of 20% of the Company's 25% interest in the Hawkins
Ranch Prospect.
Other income in the current period of $520,000 increased $284,000 over the
comparable period. Other income consisted principally of a lawsuit settlement
and an accounts payable settlement.
Total expenses for the current period of $27,106,000 were $7,351,000 lower
than the comparable period. The principal reason for the expense decrease was a
decrease in the impairment charge of $16,984,000 to $4,164,000 versus
$21,148,000 in the comparable period. The lower impairment charge was partially
offset by a $3,953,000 increase in lease operating expenses, a $2,549,000
increase in depreciation, depletion and amortization and a $1,906,000 increase
in general and administrative expenses.
In the current period, the Company charged to impairment expense $4,164,000
versus $21,148,000 in the comparable period. The impairment expense was computed
applying the guidelines of SFAS No. 121 "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed of." The impairment
expense in the current period of $4,164,000 was primarily attributable to oil
and gas impairments of $4,092,000 on four fields--Wellman, Murphy Lake,
Abbeville and Magnolia. The Wellman, Murphy Lake and Abbeville Fields were
acquired in the Shore Merger in 1997 and the Magnolia Field was acquired in
1995. The Wellman, Murphy Lake and Magnolia Fields are oil fields whose value
declined due to the decrease in oil prices. The impairment on the Abbeville
Field was due to an unsuccessful recompletion attempt on the Goldberg #2 well.
The reserves had been classified as proved behind pipe. The remaining oil and
gas impairment expense of approximately $1,300,000 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.
The non-oil and gas impairment of approximately $72,000 is a $39,000 impairment
of transaction costs in the postponed Enex Merger and a $33,000 impairment on
oilfield equipment.
Lease operating expenses of $7,801,000 increased by $3,953,000. The increase
was due primarily to expenses associated with the properties acquired in the
Enex and Service Acquisitions.
Geological and geophysical expenses of $878,000 increased by $655,000. The
primary geological and geophysical expenses in the current period include
approximately $716,000 on Hawkins Ranch Prospect and $135,000 on Sherburne
Prospect.
Depletion, depreciation and amortization expense of $7,116,000 increased by
$2,549,000. Depletion increased primarily due to the depletion associated with
the properties acquired in the Enex and Service Acquisitions.
Dry-hole expense of $503,000 decreased by $615,000 due to less drilling
activity in the current period. The dryhole costs in the current period is due
primarily to abandonment costs on two unsuccessful Exploratory Wells, the
Dishman #1 well in the South Highbaugh Prospect in Texas and the Quarry #1 well
in the Quarry Prospect in New Mexico, with dryhole costs of $197,000 and
$125,000, respectively. Additional dryhole expense of $118,000 was for two wells
in the Reflection Ridge Prospect in Kansas. The remaining dryhole expense of
$63,000 was attributable to several additional wells.
Interest expense of $1,972,000 increased by $1,301,000 due to a higher loan
balance. The loan balance increased as a result of the funds borrowed to finance
the Enex Acquisition in March and to partially finance the Service Acquisition
in April.
II-3
<PAGE>
Stock compensation of $266,000 increased by $64,000. The increase was due to
the granting of a warrant to purchase 75,000 shares of Company common stock to a
consultant. The warrant fully vested on January 1, 1999 and was expensed in the
current period.
General and administrative expense of $4,267,000 increased by $1,906,000,
due primarily to higher salary expense of $752,000, higher professional fees of
$310,000 and higher office expenses of $195,000. The increase in salary expense
was due to increases in salaries of existing employees, salaries of new
employees and salaries associated with employees added in the Enex Acquisition.
At December 31, 1998, the Company had twenty-seven full-time executive and
clerical employees and five Enex employees. The increase in professional fees
was due to higher accounting and engineering expenses related to a change in
auditors and increased reserve report needs. The Company also experienced an
increase in rent due to the Company previously owning its office in Mobile,
Alabama versus renting office space since the Company's move to Houston in
November 1997. The remaining increase in general and administrative expenses are
over several categories and were due to the increase in the overall activity of
the Company's business.
Other expenses of $139,000 decreased $179,000 over the comparable period
The Company reported an operating loss before minority interest of
$9,404,000 for the current period, compared to an operating loss of $23,024,000
in the comparable period. Due to the Enex Acquisition, the Company records a
minority interest on its income statement to remove the net income or loss
attributable to the minority interest owners of Enex. For the six-month period
ending September 30, the minority interest accounted for the income or loss for
Enex and the Enex Partnership. For the three-month period ending December 31,
the minority interest accounted only for the Enex operations since the Enex
Partnership was merged into the Company effective October 1. In the current
period the minority interest increased the operating loss by $15,089. The
Company did not have a minority interest in the comparable period.
The Company reported a deferred tax benefit of $2,830,000 for the current
period versus a deferred tax benefit of $7,451,000 in the comparable period. The
primary reason for the deferred tax benefit in the current period was the oil
and gas reserve impairment, depletion expense and intangible drilling costs.
The Company reported a net loss of $6,589,000 versus a net loss of
$15,579,000 for the comparable period. The Company paid preferred dividends of
$68,000 in the current period and $605,000 in the comparable period and reported
a net loss to common stockholders of $6,657,000 in the current period versus a
net loss to common stockholders of $16,184,000 in the comparable period.
(c) FISCAL 1997
For the current period, the revenues and expenses attributable to the Bison
Merger are included for the period March through December, the Shore Merger for
the period July through December and the Riceville Acquisition for the period
August through December.
Total revenues for the current period of $11,433,000, were $6,546,000 higher
than the comparable period. The increase in total revenues was due primarily to
higher oil and gas revenues of $5,738,000. Revenue from lease bonus and delay
rental income received on the fee mineral acreage in Louisiana increased
$975,000. Gain on the sale of properties decreased by $31,000 and other income
decreased by $136,000.
Oil and gas revenues of $10,213,000 increased $5,738,000, consisting of a
$2,905,000 increase in oil revenues, a $2,363,000 increase in gas revenues and a
$470,000 increase in other oil and gas revenues. The increase in oil and gas
revenues was primarily the result of increases in production which resulted from
the Bison and Shore Mergers. Production of oil and gas for the current period,
increased 160% and 96%, respectively, over the comparable period. During the
current period, the Company sold 284,000 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 the current period was 175,000 barrels
higher due primarily to production attributable to the Bison and Shore Mergers.
Gas production in the current period was 946,000 Mcf higher due primarily to
production attributable to Bison and Shore Mergers and the Riceville
II-4
<PAGE>
Acquisition. The price received on the gas sold in the current period of $2.39
per Mcf was slightly higher than the $2.28 per Mcf received in the comparable
period. Oil prices in the current period of $18.06 per barrel were 11% lower
than the $20.26 per barrel received in the comparable period. For the current
period, production of oil was increased 30,000 barrels and oil revenues were
increased $441,000 due to a reclassification.
The gain on sale of properties in the current period of $7,000 decreased
$31,000. Only a small number of oil and gas properties were sold in the current
and 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 in the current
period. The Company had no lease bonus or delay rental income in the comparable
period.
Other income of $237,000 decreased $136,000 over the comparable period.
Other income in the current period and comparable period consisted of various
items related to the general business activity of the Company.
Total expenses of $34,457,000 increased $29,851,000 over the comparable
period. The principal reasons for the increase in the overall level of expenses
were increased oil and gas property impairment charge by $20,870,000, increased
lease operating expenses by $2,333,000, increased depletion expenses by
$3,382,000 and increased general and administrative expenses by $1,699,000.
In the fourth quarter of the current period, 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 SFAS No. 121
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed of."
The impairment expense in the current period of $21,148,000 was primarily
attributable to impairments on three fields--the Esther, Spivey and Wellman. 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 fell from approximately $18.00 per barrel to $15.00 per barrel
at December 31, 1997 or 17%. The total oil equivalent reserves of the Wellman
Field are 95% oil. The remaining impairment expense of approximately $4,400,000
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 expenses associated with the properties acquired in the
Bison and Shore Mergers.
Depletion expense of $4,567,000 increased by $3,382,000. Depletion increased
primarily due to the depletion associated with the properties acquired in the
Bison and Shore Mergers.
Interest expense of $671,000 increased by $166,000 due to a higher loan
balance. The loan balance increased as a result of the funds borrowed to finance
the Riceville Acquisition.
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. Dryhole costs of $463,000 was attributable to several additional
wells.
II-5
<PAGE>
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 and higher office expenses of $128,000. 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 occupied 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 1997 to manage the Company's land and mineral records and an
accounting supervisor in October 1997 to assist with the increased accounting
workload.
Stock compensation 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 current period
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 current
period versus 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.
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.
(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, allows 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.
II-6
<PAGE>
Since October, 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 December 1998 of approximately $8.00 per
barrel. Oil prices in March 1999 had recovered to approximately $12.50 per
barrel. Gas prices peaked in November 1997, and on average, have declined
slightly during the current period.
(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.
(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 recently 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 1998 AND FISCAL 1997
Cash flow from operating activities for the current period of $2,068,000
decreased $1,633,000 over the comparable period. The decrease in cash flow was
due primarily to higher geological and geophysical, interest and general and
administrative expenses, offset by increases in cash flow from oil and gas
properties (oil and gas revenue less lease operating and production taxes) and
working capital changes. Cash flow from oil and gas properties increased
$846,000 over the comparable period. Oil and gas prices decreased 36% and 16%,
respectively, while oil and gas production increased 105% and 99%, respectively.
The change in working capital increased cash flow by $1,698,000 over the
comparable period. The change in working capital was caused principally by
timing differences in the payment of expenses and receipt of revenues.
Cash additions to oil and gas properties were lower than the comparable
period due primarily to the $3.5 million Riceville Acquisition in August 1997.
The cash spent on acquisitions is higher due to the Enex Acquisition that closed
March 27, 1998 and the Service Acquisition that closed April 16, 1998. The
Company acquired approximately 79.2% of Enex common stock for cash in a tender
offer and substantially all of the oil and gas assets of Service Drilling for
cash and common stock. The increase in the amount of cash used for debt payments
was due primarily to the replacing of the $50 million Convertible Loan, with a
principal balance of $10,956,000, with the $100 million Revolver and principal
payments of $5,015,000 on the $100 million Revolver. No monthly principal
payments were required over the period April 1, 1997 to March 31, 1998 on the
Company's $6 million, $15 million and $50 million Convertible Loans. The
increase in the proceeds from debt issued was due to proceeds from the $100
million Revolver which were used to replace the $50 million Convertible Loan, to
finance the Enex Acquisition and to partially finance the Service Acquisition.
No preferred stock was issued for cash in the current period versus the $9
million issued under the Preferred Stock Agreement with Kaiser-Francis in the
comparable period. Kaiser-Francis converted all of the Series A Preferred Stock
on January 31, 1998.
The Company's operating activities provided net cash of $2,068,000 for the
current period. During this period, net cash from operations, cash from property
sales and cash on hand was used principally for acquisitions and exploratory and
developmental drilling. Approximately $925,000 was spent on exploratory drilling
and approximately $2,690,000 was spent on developmental drilling. The principal
exploratory wells in the current period were the S. Highbaugh Prospect
($197,000), the Quarry Prospect ($125,000) and the Sherburne Prospect
($421,000). The principal developmental wells drilled in the current period were
the Kuehling #1 sidetrack ($548,000) in the Esther Field, several wells in the
Lake Trammel Field ($207,000), a recompletion on a well in the Abbeville Field
($248,000), a recompletion on the Baker well in the Riceville Field ($222,000)
and recompletions and drilling in the Spivey ($179,000) and Wellman ($124,000)
II-7
<PAGE>
Fields. The remaining $485,000 of capital expenditures on oil and gas was
attributable to leasehold and proved property acquisitions. The Company spent
approximately $15,960,000 on the Enex Acquisition which was financed entirely
with debt proceeds from the $100 million Revolver. The Company spent
approximately $6,500,000, excluding post-closing adjustments, on the cash
portion of the Service Acquisition, $1,000,000 from cash on hand and the
remainder with proceeds from the $100 million Revolver.
Amounts spent on debt retirement consisted principally of the replacement of
the $50 million convertible loan and principal payments on the $100 million
Revolver. The Company paid approximately $1,348,000 in cash distributions to the
minority interest partners in the Enex Partnership for the six-month period
ending September 30. The Company spent approximately $431,000 on registration
costs related to the registration of the Series C issued in the Enex Partnership
Acquisition.
Cash spent on other assets consisted principally of costs related to the
deal costs on the postponed Enex Merger, computer equipment and software.
The Company had current assets of $4,939,000 and current liabilities of
$4,800,000, which resulted in working capital of $139,000 as of December 31,
1998. This was a decrease of $1,206,000 from the working capital of $1,344,000
as of December 31, 1997. Working capital decreased primarily due to the higher
trade payables and amounts payable to dissenters and fractional shareholders in
the Enex Partnership Acquisition. Accounts payable increased because of the
increased number of properties and increased drilling activity.
On August 13, 1998 the Oil and Gas Asset Clearinghouse auctioned several
hundred oil and gas properties owned by the Company. The auctioned properties
included properties acquired in the Enex and Service Acquisitions. Certain
non-strategic properties were subject to minimum bid. The majority of the
properties were sold by auction with no minimum bids. The Company received net
proceeds of $2,635,000 from the sale of properties at the auction.
During the current period, the Company also sold certain other non-strategic
oil and gas properties in private sales for gross proceeds of $2,149,000. The
remaining $28,000 of property sales proceeds was attributable to miscellaneous
sales.
Under the terms of the $100 million Revolver, when mortgaged properties are
sold the borrowing base shall be reduced, and if necessary, proceeds from the
sales of properties shall be applied to the debt outstanding in an amount equal
to the loan value attributable to such properties sold. Of the total proceeds
received from property sales, $2,145,000 was used to repay principal on the $100
million Revolver.
On December 31, 1998 the Company sold 20% of its 25% interest in the Hawkins
Ranch Prospect for $500,000. The proceeds from the sale were collected in
January 1999 and are expected to be used to fund the drilling of the first three
wells at Hawkins Ranch.
$100 MILLION LINE OF CREDIT
In conjunction with the Enex Acquisition on March 27, 1998 the Company
entered into a new debt agreement with Compass Bank and Bank of Oklahoma (the
"Banks"). The new debt agreement is a $100 million reducing, revolving line of
credit (the "$100 million Revolver") with current borrowings under a term note
maturing April 1, 2001. The entire principal balance of the Company's $50
million Convertible Loan at the Bank of Oklahoma was replaced with the $100
million Revolver. The Bank of Oklahoma is a participating lender with Compass
Bank.
The amount the Company can borrow is based upon the borrowing base. The
borrowing base and the monthly borrowing base reduction amounts are redetermined
semi-annually by unanimous consent of the lenders. The principal is due at
maturity, April 1, 2001. Monthly principal payments are made as required in
order that the outstanding principal balance plus outstanding letters of credit
does not exceed the borrowing base. Interest is payable monthly and is
calculated at the prime rate. The Company may elect to calculate interest under
the Libor rate, as defined in the agreement. The Libor rate increases by (a)
2.00% if the outstanding loan balance and letters of credit are equal to or
greater than 75% of the borrowing
II-8
<PAGE>
base, (b) 1.75% if the outstanding loan balance and letters of credit are less
than 75% or greater than 50% of the borrowing base or (c) 1.50% if the
outstanding loan balance and letters of credit are equal to or less than 50% of
the borrowing base.
The $100 million Revolver provided for an initial borrowing base of $29
million. The initial borrowing base was reduced to $27.5 million within ten days
after the effective date and further reduced by $275,000 per month, beginning
May 1, 1998 and ending October 1, 1998. In conjunction with the Service
Acquisition, the borrowing base was increased to $32.6 million and the monthly
borrowing base reductions were increased to $330,000. Effective October 1, 1998,
the semi-annual borrowing base redetermination date, the borrowing base was
calculated to be approximately $28.9 million with monthly borrowing base
reductions of $250,000 beginning November 1, 1998. Effective January 1, 1999,
due to the closing of the Enex Partnership Acquisition, the borrowing base
determined at October 1, 1998 was adjusted to $33.1 million with monthly
borrowing base reductions of $290,000 beginning November 1, 1998. The borrowing
base at December 31, 1998 was $32.5 million and the next semi-annual borrowing
base redetermination date is April 1, 1999.
At December 31, 1998 the Company had borrowed $27,454,000 and had $1,164,000
of outstanding letters of credit. In the current period, the Company made
$1,370,000 of required principal payments, $2,145,000 in payments from property
sales proceeds and a $1,500,000 bridge payment ten days after the close of the
Enex Acquisition. The Company is currently paying Libor plus 2.00% on a sixty
day Libor loan for $25,470,000 and prime on $1,985,000.
At December 31, 1998, the amount available under the borrowing base on the
$100 million revolver was approximately $3.9 million. Assuming no other changes,
the amount available to be borrowed at April 1 will be approximately $3.0
million. The Company expects that the Banks will complete the April 1 borrowing
base redetermination by May 1, 1999. The Company also expects that the borrowing
base will be less than the amount determined at the October 1, 1998
redetermination, adjusted for the monthly borrowing base reductions. The decline
is expected to be caused primarily by normal production declines and lower oil
and gas pricing scenarios used by the Banks to value the oil and gas reserves
for loan purposes. Pursuant to the terms of the $100 million Revolver, if the
borrowing base is less than the outstanding principal balance plus outstanding
letters of credit the Company has sixty days, after receipt of notice from the
Banks, to cure the excess by prepayment, providing additional collateral or a
combination of both. The Company is unable to predict the April 1 borrowing
base. While there can be no assurance, at the completion of the April 1
redetermination, the Company does not expect to be required to make any
prepayments or provide any additional collateral that would be material to the
financial condition of the Company.
The Company paid a facility fee equal to 3/8% of the initial borrowing base
and is required to pay 3/8% on any future increase in the borrowing base within
five days of written notice. The Company is required to pay a quarterly
commitment fee on the unused portion of the borrowing base of 1/2 % if the
outstanding loan balance plus letters of credit are greater than 50% of the
borrowing base or 3/8% if the outstanding loan balance plus letters of credit
are less than or equal to 50% of the borrowing base. The Company is required to
pay a letter of credit fee on the date of issuance or renewal of each letter of
credit equal to the greater of $500 or 1 1/2 % of the face amount of the letter
of credit.
The Company has granted to the Banks liens on substantially all of the
Company's oil and natural gas properties, whether currently owned or hereafter
acquired, and a negative pledge on all other oil and gas properties.
The $100 million Revolver requires, among other things, a cash flow coverage
ratio of 1.25 to 1.00 and a current ratio, excluding the current maturity of the
$100 million Revolver, of 0.9 to 1.00, determined on a quarterly basis. As of
December 31, 1998 the Company was in compliance with the cash flow and current
ratio covenants. Because the borrowing base was increased at the October 1
redetermination, no debt payments were required in the current quarter. The only
debt payments made in the current quarter were the mortgage payments on the
Company's former office in Mobile, Alabama.
II-9
<PAGE>
Under the terms of the $100 million Revolver, when mortgaged properties are
sold the borrowing base shall be reduced, and if necessary, proceeds from the
sales of properties shall be applied to the debt outstanding in an amount equal
to the loan value attributable to such properties sold.
The $100 million Revolver includes other covenants prohibiting cash
dividends, distributions, loans, advances to third parties in excess of
$100,000, or sales of assets greater than 10% of the aggregate net present value
of the oil and gas properties in the borrowing base. Compass Bank has granted
the Company a waiver allowing the Company to pay the dividends to holders of
Series C as long as no default or event of default exists or would exist as a
result of any Series C dividend payment.
SERIES C PREFERRED STOCK
In connection with the Enex Partnership Merger, on December 29, 1998, the
Company issued 2,177,481 shares of Series C Preferred Stock ("Series C") in
exchange for 100% of the Enex Partnership units. The holders of Series C are
entitled to receive cumulative cash dividends in an amount per share of $0.50
per year (10% annual rate), payable semi-annually on March 31 and September 30
of each year. These dividends are payable in preference to and prior to the
payment of any dividend or distribution to any holder of Company common stock or
other junior security. The Series C dividends begin to accrue on December 30,
1998. The Series C has a liquidation preference of $5.00 per share plus an
amount equal to all accumulated, accrued and unpaid dividends. The liquidation
preference of Series C ranks on parity with the Series B Preferred Stock.
Each share of Series C is convertible into one share of Company common
stock. On or after January 1, 2000, the Company may redeem all or a portion of
the Series C, at its option, at a purchase price of $5.00 per share, plus an
amount equal to all accumulated, accrued and unpaid dividends.
The Series C is generally nonvoting; however, holders of Series C are
entitled to vote on any amendment, alteration or appeal of any provision of the
Company's Articles of Incorporation which would adversely affect any holder's
rights and preferences.
As a result of its limited partnership interest in the Enex Partnership,
Enex owns 1,293,522 shares of the Series C. Through its eighty percent ownership
of Enex, 80% (or 1,034,818) of the shares are attributable to the Company.
SERIES B PREFERRED STOCK
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 Company's Series A Preferred Stock. Until
December 31, 2002, any holder of the Series B may convert all or any portion of
Series B shares into Company Common Stock ("Common") at the greater ratio of (i)
one share of Common for each share of Series B or (ii) at a ratio based upon the
"Alternative Conversion Factor." The Alternative Conversion Factor is determined
by dividing the net increase in value of approximately 40,000 net mineral acres
owned by the Company in South Louisiana by $8,000,000 and multiplying the
product by 1,066,000 to arrive at the potential number of total Common shares
all holders would receive upon conversion. 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. Upon expiration of the conversion period, unless the
Company has given notice to redeem the Series B, all of the shares of the Series
B shall be automatically converted.
Since the merger date of June 30, 1997 the value of the fee minerals has not
increased to a level where the alternative conversion rate is more beneficial
than the initial conversion rate of one to one. As of December 31, 1998, no
additional shares of Series B have been issued.
II-10
<PAGE>
SERIES A PREFERRED STOCK
On September 4, 1996, the Company signed a stock purchase agreement with
Kaiser Francis Oil Company ("the Agreement"). The Agreement provided for the
purchase of 1,666,667 shares of Series A Preferred Stock ("Series A") at $6.00
per share, over a five-year period beginning September 4, 1996 with minimum
incremental investments of $500,000 each. Each issuance of Series A was subject
to approval by Kaiser-Francis of the use of proceeds. The Series A was nonvoting
and accrued dividends at 8% per annum, payable quarterly in cash. The Series A
was convertible at any time after issuance into shares of common stock at the
rate of two shares of common stock for each share of Preferred before January 1,
1998. At December 31, 1997, all of the Series A had been issued and on January
31, 1998, all of the Series A was converted into 3,333,334 shares of Company
common stock.
THE ENEX ACQUISITION
On March 27, 1998, the Company acquired 1,064,432 shares of the common stock
of Enex, for $15 cash per share pursuant to the Company's tender offer that
began February 19, 1998. The Enex shares acquired by the Company represent 79.2%
of the total outstanding Enex common stock. The Company applied the purchase
method of accounting to the Enex Acquisition. The purchase price of $15,966,000
was financed with proceeds from the Company's $100 million Revolver. The Company
also incurred approximately $60,934 in legal, accounting and printing expenses
and issued 33,825 shares of Company common stock for finders fees to unrelated
third parties.
Over a three-week period ending December 23, 1998, the Company acquired an
additional 0.80% of Enex common stock for approximately $68,000.
As part of the Enex Acquisition, the Company entered into a consulting
agreement, effective April 15, 1998, with the former president of Enex that
provides for monthly payments of $20,000 until expiration of the agreement on
May 18, 2002. The present value of the agreement, applying a 10% discount rate,
is approximately $788,000 and is included in Other Liabilities (current and long
term). The monthly payments serve as consideration for consulting, a covenant
not to compete and a preferential right to purchase certain oil and gas
acquisitions which the former president controls or proposes to acquire during
the term of the agreement. The Company will reimburse the former president each
month for reasonable and necessary business expenses incurred in connection with
the performance of consulting services. The agreement survives the former
president and his spouse and is nonassignable.
Enex, a Delaware corporation, is an independent oil and gas production and
development company headquartered in Kingwood, Texas with operations primarily
in Texas. Enex engages primarily in managing and acquiring producing oil and gas
properties, and does not engage in significant drilling activities. Enex
operates over 100 wells in South Texas. Before the tender offer, the Enex shares
traded on the NASDAQ Stock Market National Market System under the symbol ENEX.
The Enex shares are currently traded on the OTC Bulletin Board. Concurrent with
the closing of the Enex Acquisition, the Enex Board of Directors resigned and
were replaced by the persons who constitute the Company's Board of Directors.
Enex is presently being operated as a majority-owned subsidiary of the Company.
In addition to managing and acquiring direct interests in producing oil and
gas properties, Enex served as general partner of the Enex Partnership until its
sale to the Company, effective October 1, 1998. See the discussion below
concerning the sale of the Enex Partnership to the Company. Approximately 73% of
Enex's estimated future net revenues from proved reserves at December 31, 1997
is attributable to its interests in the Enex Partnership and approximately 27%
is attributable to the properties owned directly by the Enex, after deducting
the minority interest share of the Enex Partnership. As general partner, Enex
had a 4.1% interest in the net revenues and gains generated by properties owned
by the Enex Partnership. In addition to the general partner interest, Enex owned
a 56.2% limited partner interest in the Enex Partnership. Based on the Company's
80% ownership of Enex, the Company had an effective limited partner ownership of
the Enex Partnership of 44.9%.
II-11
<PAGE>
Because the Company's ownership of Enex is greater than 50%, the Company's
consolidated financial statements at December 31, 1998 include 100% of the
accounts of Enex subsequent to the acquisition date. Until the sale of the Enex
Partnership, effective October 1, 1998, Enex consolidated 100% of the Enex
Partnership on its books for financial reporting purposes because its ownership
in the Enex Partnership was greater than 50%. The minority interest on the
Company's balance sheet reflects the equity interest of the minority owners in
Enex (20%).
The operations of Enex for the six-month period ending September 30, which
included the operations of the Enex Partnership until its sale effective October
1, 1998, were included in the financial statements of the Company. The
operations of Enex for the three-month period ending December 31, which excluded
the operations of the Enex Partnership, were also included in the financial
statements of the Company.
On October 31, 1998 the office lease in Kingwood where Enex and the Enex
Partnership were headquartered expired. The Company has moved the majority of
the current files and records for Enex and the Enex Partnership to the Houston
office and has rented a small office in Kingwood where the accounting staff of
Enex and the Enex Partnership will continue to operate until the end of the
first quarter of 1999.
THE ENEX MERGER
On July 17, 1998, the Securities and Exchange Commission declared effective
a registration statement filed under the Securities Act of 1933 for the merger
of Enex into the Company (the "Enex Merger"). A special meeting of the
stockholders of Enex was held on August 20, 1998 to approve the Enex Merger. Due
to market conditions, the Company voted against the Enex Merger. Due to the
postponement of the Enex Merger, the Company impaired deal costs related to the
Enex Merger by approximately $38,000.
THE ENEX PARTNERSHIP MERGER
The Enex Partnership is a New Jersey limited partnership that was formed on
June 30, 1997 from the combination of thirty-four Enex Oil and Gas Limited
Partnerships. The Enex Partnership, headquartered in Kingwood, Texas, is engaged
in the oil and gas business through the ownership of various interests in oil
and gas properties. At October 1, 1998, Enex owned 56.24% of the outstanding
limited partner units and the remaining 43.76% was owned by several thousand
limited partners.
On December 29, 1998 the Company closed an exchange of 2.086 shares of
Series C Preferred stock for each Enex Partnership unit (the "Exchange Offer").
In connection with the Exchange Offer, the Company submitted a proposal to
investors in the Enex Partnership to amend the partnership agreement to provide
for the transfer of all of the assets and liabilities of the Enex Partnership to
the Company as of October 1, 1998 and dissolve the Enex Partnership. The Company
issued 2,177,481 Series C shares for 100% of the outstanding limited partner
units. Enex was issued 1,293,522 Series C shares for its 56.24% ownership of the
Enex Partnership. The remaining 883,959 Series C shares were issued to the
limited partners that elected to take Series C shares in lieu of cash. Certain
dissenting limited partners and fractional shares will be paid cash in January
1999. Because of the dissenting limited partners, Enex owns 59.4% of the Series
C shares.
The operations of the Enex Partnership for the nine-month period ending
December 31 were included in the financial statements of the Company due to the
Company's acquisition of Enex on March 27, 1998. Subsequent to October 1, 1998,
no minority interest was recorded related to the operations of the Enex
Partnership as it was dissolved.
II-12
<PAGE>
FUTURE CAPITAL REQUIREMENTS
The Company has made and will continue to make, substantial capital
expenditures for acquisition, development and exploration of oil and natural gas
reserves. In fact, because the Company's principal natural gas and oil reserves
are depleted by production, its success is dependent upon the results of its
acquisition, development and exploration activities.
The Company expects to incur a minimum of approximately $500,000 in capital
expenditures over the next twelve months. The Company expects that available
cash, cash flows from operations and cash proceeds from asset sales of certain
non-core properties will be sufficient to fund the planned capital expenditures
through 1999 in addition to funding interest and principal requirements on the
$100 million Revolver. However, the Company may require additional borrowings
under the $100 million Revolver or additional equity funding to raise additional
capital to fund any acquisitions.
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 oil, there can be no assurance that the Company's capital resources will be
sufficient to maintain planned levels of capital expenditures and accordingly,
oil and natural gas revenues and operating results may be adversely affected.
At December 31, 1998, the amount available under the borrowing base on the
$100 million revolver was approximately $3.9 million. Assuming no other changes,
the amount available to be borrowed at April 1 will be approximately $3.0
million. The Company expects that the Banks will complete the April 1 borrowing
base redetermination by May 1, 1999. The Company also expects that the borrowing
base will be less than the amount determined at the October 1, 1998
redetermination, adjusted for the monthly borrowing base reductions. The decline
is expected to be caused primarily by normal production declines and lower oil
and gas pricing scenarios used by the Banks to value the oil and gas reserves
for loan purposes. If the borrowing base is less than the outstanding principal
balance plus outstanding letters of credit the Company has sixty days, after
receipt of notice from the Banks, to cure the excess by prepayment, providing
additional collateral or a combination of both. The Company is unable to predict
the April 1 borrowing base. While there can be no assurance, at the completion
of the April 1 redetermination, the Company does not expect to be required to
make any prepayments or provide any additional collateral that would be material
to the financial condition of the Company. However, depending on the amount of
prepayment, if any is required, the Company may have to raise additional cash to
meet this commitment.
Amounts spent on debt retirement due to reductions in the borrowing base,
reduce the cash available to spend on acquisition, development and exploration
activities and, accordingly, oil and natural gas revenues and operating results
may be adversely affected.
By the end of the first quarter of 1999, the Company expects to have the
operations of Enex and the Enex Partnership fully consolidated into its
operations at the Company's headquarters in Houston. It is expected that the
Company will realize certain cost savings in the consolidation of these
operations.
YEAR 2000 COMPLIANCE
Readers are cautioned that the forward-looking statements contained in the
following Year 2000 discussion should be read in conjunction with the Company's
disclosures under the heading "Forward-Looking Statements." The disclosures also
constitute a "Year 2000 Readiness Disclosure" and "Year 2000 Statement" within
the meaning of the Year 2000 Information and Readiness Disclosure Act of 1998.
STATEMENT OF READINESS
The Company has undertaken various initiatives to ensure that its hardware,
software and equipment will function properly with respect to dates before and
after January 1, 2000. For this purpose, the phrase "hardware, software and
equipment" includes systems that are commonly thought of as Information
Technology systems ("IT"), as well as those Non-Information Technology systems
("Non-IT") and equipment which include embedded technology. IT systems include
computer hardware and software and other
II-13
<PAGE>
related systems. Non-IT systems include certain oil and gas production and field
equipment, gathering systems, office equipment, telephone systems, security
systems and other miscellaneous systems. The Non-IT systems present the greatest
readiness challenge since identification of embedded technology is difficult and
because the Company is, to a great extent, reliant on third parties for Non-IT
compliance.
The Company has formed a Year 2000 ("Y2K") Project team, which is chaired by
its Chief Financial Officer, Frank C. Turner, II. The team includes corporate
staff and representatives from the Company's business units. In response to the
possible risks posed to the Company, the team has developed a Y2K Plan (the
"Plan") which includes guidelines for inventory, assessment, remediation,
testing and contingency planning.
The following categories represent the mission-critical operational systems
of the Company. A "mission-critical system" is a system that is vital to the
successful continuation of a core business activity. An application may be
mission critical if it interfaces with a designated mission-critical system.
Each system has been evaluated by the Company as to (a) the risks to the Company
in the event of the most reasonably likely worst case scenario (the "Worst Case
Scenario"); (b) the status of the Company's remediation plan, if any ("Status");
and (c) the Company's contingency plans, if any ("Contingency Plans").
ACCOUNTING SOFTWARE SYSTEMS. The Company relies solely on the software
accounting packages ("Accounting Packages") to provide management with various
reports that allow managers to determine the cash flow and profitability of
individual properties and of the Company as a whole. Management also relies on
the Accounting Packages to provide financial information necessary to prepare
quarterly and annual financial reports that are sent to the Securities and
Exchange Commission, NASDAQ Stock Market, banks and stockholders. In addition,
the Company relies on the Accounting Packages to process and print checks to be
sent to working and royalty interest owners for their share of the monthly oil
and gas sales, to process and print checks for payment to vendors and to process
and print monthly joint-interest statements to be sent to working interest
owners in Company-operated oil and gas properties. Under a Worst Case Scenario,
all accounting functions would have to be completed manually, significantly
hindering the Company's ability to complete the above-described mission-critical
systems.
<TABLE>
<S> <C>
Status: The Company has updated its accounting systems. Testing is scheduled to
be completed by April 30, 1999.
Contingency Plans: The Company is currently considering contingency plans for processing
its accounting data. Depending on the results of the testing phase,
contingency plans will be developed.
</TABLE>
CONTROL SYSTEMS AND IMBEDDED TECHNOLOGY. These systems include the
equipment used to produce, monitor, control, sell and record hydrocarbon
production, including all artificial lift equipment, storage, measurement and
control facilities and third-party systems and technology interrelated to the
Company's business. Under a Worst Case Scenario, multiple fields of oil and gas
would lose the ability to account for the amount of hydrocarbon production,
temporarily shutting down the field(s) until the malfunctioning part(s) could be
repaired or replaced. This is not expected to materially adversely effect the
Company.
<TABLE>
<S> <C>
Status: The only mission-critical field operated by the Company is the Spivey
Field, whose production operations are not affected by Y2K issues. The
Spivey Field is affected by a third-party operated gas plant that
processes the field's natural gas and may be subject to Y2K issues.
Refer to "Third Party Systems-Gas Plant" for a discussion of the gas
plant at the Spivey Field. The operations of the remaining fields were
not materially affected by Y2K issues.
Contingency Plans: The Company will continue to monitor the operations at its field
locations and develop contingency planning if an exposure becomes
apparent.
</TABLE>
THIRD-PARTY SYSTEMS--OIL AND GAS PURCHASERS. The Company utilizes
third-party purchasers to sell the oil and gas produced from the wells in which
it has a working or royalty interest. The Company also
II-14
<PAGE>
depends on third-party purchasers to remit to the Company its share of the
proceeds from the sales of oil and gas. The Company does not directly sell any
oil and gas produced from the wells in which it has a working or royalty
interest and does not take any oil or gas in kind as an alternative to cash
payment. Under a Worst Case Scenario, multiple major purchasers would be
temporarily shut down due to Y2K issues, materially adversely effecting the
Company's revenues.
<TABLE>
<S> <C>
Status: Based upon the diversity of purchasers, the Company believes that no
single purchaser is a mission-critical purchaser. The Y2K team does not
anticipate that a problem with any single purchaser for a reasonable
period of time beyond 2000 will force the Company to curtail or shut
down its operations. Although no single purchaser is a mission-critical
purchaser, the loss of a major purchaser or multiple minor purchasers
due to Y2K problems would affect the Company. The Company has obtained
information about the top ten purchasers and their Y2K readiness. All
but two of the top ten purchasers have formal Y2K Plans and are working
to upgrade any mission-critical systems that are affected by Y2K. The
other two purchasers acknowledge that certain systems will be affected
by Y2K and have been undertaking plans to upgrade these systems.
Contingency Plans: The Company continues to monitor the Y2K status of its major
purchasers. Should a purchaser not become Y2K compliant, the Company
will identify alternative purchasers for its production and, if
necessary, temporarily shut-in production.
</TABLE>
THIRD-PARTY SYSTEMS--GAS PLANT. Over 95% of the gas produced in the Spivey
Field, a mission-critical system, is sold to a gas plant under a life of the
lease casinghead tailgate gas contract. The Company owns approximately 11.5% of
the gas plant and related gathering system. Colt Resources Corporation operates
the plant. Under a Worst Case Scenario, the gas plant could be shut down which
could materially adversely effect the Company.
<TABLE>
<S> <C>
Status: The Company has received a letter from the operator of the Spivey plant
stating that the Spivey plant's control systems and embedded technology
are not Y2K affected and that its accounting and processing systems are
Y2K compliant.
Contingency Plans: A short-term interruption of gas sales would not materially affect the
Company's operations. If the Spivey plant experiences problems with an
expected duration in excess of one month, the Company has identified
alternative gas markets it could utilize.
</TABLE>
THIRD-PARTY SYSTEMS--BANKING. The Company relies on its banks to deposit
checks payable to the Company and credit the checks to the appropriate accounts.
The Company also relies on its banks to credit third-party accounts for payment.
A Worst Case Scenario would occur if the Company's principal bank is unable to
provide certain services for an extended period of time due to Y2K, causing the
Company to be materially adversely affected.
<TABLE>
<S> <C>
Status: The Company's principal bank currently has a formal Y2K Plan in effect
and anticipates that all non-compliant, in-house mission-critical
systems will be substantially remediated by December 31, 1998 and
substantially completed by March 31, 1999 for vendor-supported systems.
The Company's principal bank expects to have all of its non-compliant,
mission-critical systems Y2K compliant by June 30, 1999.
Contingency Plans: The Company intends to have cash on hand sufficient to cover short-term
emergency payments and payroll. The Company also plans to open accounts
with other institutions in the event its principal bank is unable to
rectify its problems in a timely manner. The Company has no long-term
contingency plans in the event of a system-wide failure of banking
institutions.
</TABLE>
II-15
<PAGE>
THIRD-PARTY SYSTEMS--SUPPORT FUNCTIONS. The primary material support
functions provided by third parties are electrical service, communication
service and office space. Under a Worst Case Scenario, all primary support
functions would be hindered in the short term.
<TABLE>
<S> <C>
Status: All vendors of these services have reported that formal Y2K remediation
plans are in effect and will be substantially complete by September 30,
1999.
Contingency Plans: Short-term (less than two weeks) interruptions of services will not
materially adversely effect the Company. The Company will be able to
conduct business on a reduced scale using alternative business methods.
Longer-term interruptions may materially adversely effect the Company.
The Company has no plans sufficient to fully offset the effect of
long-term interruptions.
</TABLE>
COMPUTER OPERATING SYSTEMS AND APPLICATION SOFTWARE SYSTEMS. The Company
relies solely on its personal computer systems to access the accounting software
package through the Company's computer network. In addition, certain schedules
and databases that are used for critical functions rely on spreadsheet and
work-processing applications that are run on the Company's personal computer
systems.
<TABLE>
<S> <C>
Status: All systems appear to be Y2K ready.
Contingency Plans: Operations could be performed manually until non-functioning equipment
or software is repaired or replaced
</TABLE>
COSTS OF Y2K COMPLIANCE
The costs incurred by the Company to implement the Plan were not material to
the Company's financial condition or results of operations. The Company does not
expect any future costs related to the Plan to be material to the Company's
financial condition or results of operations.
THE RISKS OF Y2K ISSUES
The Company presently believes that Y2K issues will not pose significant
operational problems. However, if all significant Y2K issues are not properly
identified or assessed, remediation and testing are not effected timely, the Y2K
issues, either individually or in combination, may materially and adversely
impact the Company's results of operations, liquidity and financial condition or
materially and adversely affect its relationships with its business partners.
Additionally, the misrepresentation of compliance by other entities or the
persistent, universal failure of financial, transportation or other economic
systems will likely have a material and adverse impact on the Company's
operations or financial condition for which it cannot adequately prepare.
ITEM 7. FINANCIAL STATEMENTS
The Company's financial statements for the years ended December 31, 1998 and
1997 and the independent auditors' reports thereon are included in this Item 7.
[The remainder of this page has been intentionally left blank]
II-16
<PAGE>
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
-----
<S> <C>
Reports of Independent Auditors............................................................................ F-2
Consolidated Balance Sheets as of December 31, 1998 and 1997............................................... F-4
Consolidated Statements of Operations for the years ended December 31, 1998 and 1997....................... F-5
Consolidated Statements of Cash Flows for the years ended December 31, 1998 and 1997....................... F-6
Consolidated Statements of Stockholders' Equity for the years ended December 31, 1998 and 1997............. F-7
Notes to Consolidated Financial Statements................................................................. F-8
</TABLE>
F-1
<PAGE>
REPORT OF INDEPENDENT AUDITORS
The Board of Directors and Stockholders
Middle Bay Oil Company, Inc.
We have audited the accompanying consolidated balance sheet of Middle Bay
Oil Company, Inc. and subsidiaries as of December 31, 1998, and the related
consolidated statements of operations, changes in stockholders' equity and cash
flows for the year 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 audit.
We conducted our audit 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 audit provides 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 as of December 31, 1998, and the results of
their operations and their cash flows for the year then ended in conformity with
generally accepted accounting principles.
KPMG LLP
Houston, Texas
March 26, 1999
F-2
<PAGE>
REPORT OF INDEPENDENT AUDITORS
The Board of Directors and Stockholders
Middle Bay Oil Company, Inc.
We have audited the accompanying consolidated balance sheet of Middle Bay
Oil Company, Inc. and subsidiaries as of December 31, 1997, and the related
statements of operations, changes in stockholders' equity and cash flows for the
year 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 audit.
We have conducted our audit 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 audit provides 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 as of December 31, 1997, and the results of
their operations and their cash flows for the year then ended in conformity with
generally accepted accounting principles.
SCHULTZ, WATKINS & COMPANY
Jackson, Mississippi
February 27, 1998
F-3
<PAGE>
MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31
ASSETS
<TABLE>
<CAPTION>
1998 1997
------------ ------------
<S> <C> <C>
CURRENT ASSETS...........................................................................
Cash and cash equivalents.............................................................. $ 1,040,096 $ 1,587,184
Accounts receivable.................................................................... 3,309,043 2,352,679
Accounts receivable--Insurance Claim................................................... 448,083 --
Other current assets................................................................... 141,364 89,021
Assets held for resale................................................................. -- 206,464
------------ ------------
Total current assets................................................................. 4,938,586 4,235,348
NON-CURRENT ASSETS
Accounts receivable--stockholder....................................................... 173,115 166,165
PROPERTY (at cost)
Oil and gas (successful efforts method) 90,849,439 62,654,328
Other.................................................................................. 795,323 822,806
------------ ------------
91,644,762 63,477,134
Less accumulated depletion, depreciation and amortization.............................. (39,073,584) (30,636,202)
------------ ------------
52,571,178 32,840,932
OTHER ASSETS............................................................................. 257,938 10,127
------------ ------------
TOTAL ASSETS............................................................................. $ 57,940,817 $ 37,252,572
------------ ------------
------------ ------------
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Current maturities of long term debt................................................... $ -- $ 1,375,537
Accounts payable--Trade................................................................ 3,643,241 1,176,680
Accounts payable--Enex, LP Dissenters and Fractional Shares............................ 538,750 --
Accounts payable--Revenue.............................................................. 342,931 308,981
Other current liabilities.............................................................. 275,010 29,737
------------ ------------
Total current liabilities............................................................ 4,799,932 2,890,935
LONG TERM DEBT........................................................................... 27,454,567 9,714,713
DEFERRED INCOME TAXES.................................................................... 1,733,167 4,780,528
OTHER LIABILITIES........................................................................ 437,949 --
MINORITY INTEREST........................................................................ 957,369 --
STOCKHOLDERS' EQUITY..................................................................... -- --
Preferred stock, $.02 par, 5,000,000 shares authorized with 266,667 shares designated
Series B and 2,177,481 designated Series C, none other issued........................ -- --
Cumulative convertible Series A 8% preferred stock, $6 stated value, No shares
outstanding at 12/31/98 and 1,666,667 shares issued and outstanding at 12/31/97,
$10,000,000 aggregate liquidation preference......................................... -- 10,000,000
Convertible preferred stock Series B, $7.50 stated value, 266,667 shares issued and
outstanding at 12/31/98 and 12/31/97. $2,000,000 aggregate liquidation preference.... 3,627,000 3,627,000
Convertible preferred stock Series C, $5.00 stated value, 1,142,663 shares issued and
outstanding at 12/31/98. $5,713,317 aggregate liquidation preference................. 5,281,937 --
Common stock, $.02 par value, 10,000,000 authorized, 8,552,365 and 4,519,206 shares
issued and outstanding at 12/31/98 and 12/31/97, respectively........................ 171,055 90,392
Additional paid-in capital............................................................. 36,947,588 23,029,299
Unearned stock compensation............................................................ -- (67,500)
Accumulated deficit.................................................................... (23,401,707) (16,744,755)
Treasury stock; 21,773 shares at 12/31/98 and 12/31/97................................. (68,040) (68,040)
------------ ------------
Total stockholders' equity........................................................... 22,557,833 19,866,396
------------ ------------
COMMITMENTS AND CONTINGENCIES
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY............................................... $ 57,940,817 $ 37,252,572
------------ ------------
------------ ------------
</TABLE>
See accompanying notes to consolidated financial statements.
F-4
<PAGE>
MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIAIRES
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31
<TABLE>
<CAPTION>
1998 1997
------------- --------------
<S> <C> <C>
REVENUES
Oil and gas sales and plant income.............................................. $ 15,011,354 $ 10,213,047
Gain on sale of properties...................................................... 1,953,362 7,018
Delay rental and lease bonus income............................................. 217,404 975,347
Other........................................................................... 520,458 237,583
------------- --------------
Total revenues................................................................ 17,702,578 11,432,995
COSTS AND EXPENSES
Lease operating, production taxes and plant costs............................... 7,801,249 3,848,627
Geological and geophysical...................................................... 877,643 222,608
Dryhole......................................................................... 503,444 1,118,838
Impairments..................................................................... 4,164,184 21,147,823
Depletion, depreciation and amortiziation....................................... 7,116,116 4,567,063
Interest........................................................................ 1,971,595 671,081
Stock compensation.............................................................. 266,445 202,500
General and administrative...................................................... 4,266,727 2,361,124
Other........................................................................... 138,855 317,469
------------- --------------
Total costs and expenses...................................................... 27,106,258 34,457,133
LOSS BEFORE INCOME TAX BENEFIT AND MINORITY INTEREST.............................. (9,403,680) (23,024,138)
INCOME TAX EXPENSE (BENEFIT)
Current......................................................................... -- 6,451
Deferred........................................................................ (2,829,762) (7,451,249)
------------- --------------
(2,829,762) (7,444,798)
MINORITY INTEREST................................................................. 15,089 --
------------- --------------
NET LOSS.......................................................................... $ (6,589,007) $ (15,579,340)
Dividends to preferred stockholders............................................... (67,945) (604,712)
------------- --------------
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS...................................... $ (6,656,952) $ (16,184,052)
------------- --------------
------------- --------------
NET LOSS PER SHARE
Basic........................................................................... $ (0.83) $ (4.76)
------------- --------------
------------- --------------
Diluted......................................................................... $ (0.83) $ (4.76)
------------- --------------
------------- --------------
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic........................................................................... 8,050,108 3,397,117
------------- --------------
------------- --------------
Diluted......................................................................... 8,050,108 3,397,117
------------- --------------
------------- --------------
</TABLE>
See accompanying notes to consolidated financial statements.
F-5
<PAGE>
MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31
<TABLE>
<CAPTION>
1998 1997
----------- -----------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss............................................................................ $(6,589,007) $(15,579,340)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and amortization.......................................... 7,070,916 4,567,063
Impairments....................................................................... 4,164,184 21,147,823
Deferred income tax benefit....................................................... (2,829,762) (7,451,249)
Bad debt expense.................................................................. 20,000 45,000
Abandonment expense............................................................... 45,200 --
Dryhole costs..................................................................... 503,444 1,118,838
Stock compensation................................................................ 266,445 202,500
Gain on sale of assets............................................................ (1,953,362) (7,018)
Minority interest................................................................. 15,089 --
Changes in operating assets and liabilities, net of acquisition effects:
(Increase) Decrease in receivables................................................ (108,892) 243,779
Increase (Decrease) in payables................................................... 1,541,025 (438,355)
(Increase) Decrease in other assets............................................... (76,995) (147,928)
----------- -----------
Net cash provided by operating activities........................................... 2,068,285 3,701,113
CASH FLOWS FROM INVESTING ACTIVITIES
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)
Payment for acquisition of 80% of Enex Resources Corp., net of cash acquired of
$4,698,211....................................................................... (11,403,189) --
Payment for acquisition of assets of Service Drilling Co., LLC.................... (6,328,208) --
Capital expenditures:
Oil and gas properties.......................................................... (4,100,252) (8,175,051)
Other assets.................................................................... (322,816) (246,735)
Proceeds from sale of:
Oil and gas properties.......................................................... 4,812,326 103,872
Other assets.................................................................... 390,927 1,445,890
Advances to stockholder........................................................... (6,950) (6,950)
----------- -----------
Net cash used in investing activities......................................... (16,958,162) (14,533,187)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds of bank loans.............................................................. 32,469,604 5,769,705
Principal payments on loans......................................................... (16,105,287) (2,497,533)
Proceeds from issuance of preferred stock........................................... -- 9,000,000
Preferred stock dividends........................................................... (67,945) (604,712)
Partnership distributions........................................................... (1,348,098) --
Proceeds from common stock.......................................................... -- 195,772
Registration costs of Series C preferred stock...................................... (431,380) --
Other............................................................................... (174,105) --
----------- -----------
Net cash provided by financing activities..................................... 14,342,789 11,863,232
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS FOR THE YEAR..................... (547,088) 1,031,158
Cash and cash equivalents--Beginning of year........................................ 1,587,184 556,026
----------- -----------
Cash and cash equivalents--End of year.............................................. $ 1,040,096 $ 1,587,184
----------- -----------
----------- -----------
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
CASH PAID DURING THE YEAR FOR:
Interest.......................................................................... $ 1,657,362 $ 601,582
----------- -----------
----------- -----------
Income Taxes...................................................................... -- $ 6,451
----------- -----------
----------- -----------
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Common stock issued as finders' fee in Enex Resources Corp. tender offer............ $ 245,232 $ --
----------- -----------
----------- -----------
Present value of consulting agreement of former president of Enex Resources Corp.... $ 788,563 $ --
----------- -----------
----------- -----------
Common stock issued in asset acquisition from Service Drilling Corp. LLC............ $ 3,554,774 $ --
----------- -----------
----------- -----------
Preferred stock issued in acquisition of Enex Consolidated Partners, LP............. $ 5,713,317 $ --
----------- -----------
----------- -----------
Conversion of redeemable common stock to common stock (net of treasury shares
acquired)......................................................................... $ -- $ 421,179
----------- -----------
----------- -----------
Common stock issued in acquisition of Bison Energy Corp............................. $ -- $ 3,330,558
----------- -----------
----------- -----------
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
F-6
<PAGE>
MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY
YEARS ENDED DECEMBER 31, 1998 AND 1997
<TABLE>
<CAPTION>
PREFERRED STOCK
----------------------------------------------------------------------
SERIES A SERIES B SERIES C COMMON STOCK
------------------------ --------------------- --------------------- --------------------
SHARES AMOUNT SHARES AMOUNT SHARES AMOUNT SHARES AMOUNT
---------- ------------ --------- ---------- --------- ---------- --------- ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
BALANCE--1/1/97............... 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
Preferred A Conversion........ (1,666,667) (10,000,000) -- -- -- -- 3,333,334 66,667
Shares issued as finders fee
in Enex Tender Offer........ -- -- -- -- -- -- 33,825 676
Service Drilling Co.
Acquisition................. -- -- -- -- -- -- 666,000 13,320
Restricted stock awards
earned...................... -- -- -- -- -- -- -- --
Enex Consolidated Partners
Acquisition................. -- -- -- -- 1,142,663 5,713,317 -- --
Preferred Stock Registration
Costs....................... -- -- -- -- -- (431,380) -- --
Warrants issued as
compensation................ -- -- -- -- -- -- -- --
Net loss...................... -- -- -- -- -- -- -- --
8% Preferred stock Series A
dividend.................... -- -- -- -- -- -- -- --
---------- ------------ --------- ---------- --------- ---------- --------- ---------
ENDING BALANCE-- 12/31/98..... -- $ -- 266,667 $3,627,000 1,142,663 $5,281,937 8,552,365 $ 171,055
---------- ------------ --------- ---------- --------- ---------- --------- ---------
---------- ------------ --------- ---------- --------- ---------- --------- ---------
<CAPTION>
ADDITIONAL REDEEMABLE
PAID-IN COMMON UNEARNED STOCK ACCUMULATED TREASURY
CAPITAL STOCK COMPENSATION DEFICIT STOCK TOTAL
----------- ----------- -------------- ------------ ----------- ------------
<S> <C> <C> <C> <C> <C> <C>
BALANCE--1/1/97............... $ 6,049,442 $(421,179) $ -- $ (560,703) $ (68,040) $ 6,037,138
Common stock issued in
acquisition of NPC Energy
Corporation................. 93,018 -- -- -- -- 93,695
Preferred Series A issued..... -- -- -- -- -- 9,000,000
Common stock issued in
acquisition of Bison Energy
Corporation................. 3,318,447 -- -- -- -- 3,330,558
Common stock issued in
acquisition of Shore Oil
Company..................... 12,938,498 -- -- -- -- 12,976,165
Preferred Series B issued in
acquisition of Shore Oil
Company..................... -- -- -- -- -- 3,627,000
Conversion of redeemable
common stock to common
stock....................... -- 421,179 -- -- -- 421,179
Restricted stock awards....... 269,018 -- -- -- -- 270,000
Stock options exercised....... 101,266 -- -- -- -- 102,083
Purchase of oil and gas
working interests........... 259,610 -- -- -- -- 260,130
Unearned stock compensation... -- -- (67,500) -- -- (67,500)
Net loss...................... -- -- -- (15,579,340) -- (15,579,340)
8% Preferred stock Series A
dividends................... -- -- -- (604,712) -- (604,712)
----------- ----------- -------------- ------------ ----------- ------------
BALANCE--12/31/97............. 23,029,299 -- (67,500) (16,744,755) (68,040) 19,866,396
Preferred A Conversion........ 9,933,333 -- -- -- -- --
Shares issued as finders fee
in Enex Tender Offer........ 244,556 -- -- -- -- 245,232
Service Drilling Co.
Acquisition................. 3,541,454 -- -- -- -- 3,554,774
Restricted stock awards
earned...................... -- -- 67,500 -- -- 67,500
Enex Consolidated Partners
Acquisition................. -- -- -- -- -- 5,713,317
Preferred Stock Registration
Costs....................... -- -- -- -- -- (431,380)
Warrants issued as
compensation................ 198,946 -- -- -- -- 198,946
Net loss...................... -- -- -- (6,589,007) -- (6,589,007)
8% Preferred stock Series A
dividend.................... -- -- -- (67,945) -- (67,945)
----------- ----------- -------------- ------------ ----------- ------------
ENDING BALANCE-- 12/31/98..... $36,947,588 $ -- $ -- ($23,401,707) $ (68,040) $ 22,557,833
----------- ----------- -------------- ------------ ----------- ------------
----------- ----------- -------------- ------------ ----------- ------------
</TABLE>
See accompanying notes to consolidated financial statements.
F-7
<PAGE>
MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1998 and 1997
(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. Effective March 27, 1998, the
Company acquired 79.2% of Enex Resources Corporation ("Enex") and effective
April 16, 1998, the Company acquired the assets of Service Drilling Co., LLC
("Service Drilling"). Effective October 1, 1998, the Company acquired 100% of
Enex Consolidated Partners, L.P. ("Enex Partnership"), a limited partnership of
which Enex owned greater than a 50% interest. In 1997, the Company acquired
Bison Energy Corporation and Shore Oil Company. The Company is engaged in the
acquisition, development and production of oil and natural gas in the contiguous
United States. The Company considers its business to be a single operating
segment.
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,
its wholly-owned subsidiary and Enex, an 80% owned subsidiary. The equity of
minority interest in Enex is shown in the consolidated statements as "minority
interest". All significant intercompany balances and transactions have been
eliminated in consolidation.
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. Gains and losses are recorded on sales of
entire interests in proved or unproved properties. For the years ended December
31, 1998 and 1997, the Company realized gains on sales of properties of
$1,953,000 and $7,000, respectively.
The Company reviews long-lived assets 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, assuming escalated prices, are
F-8
<PAGE>
MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1998 and 1997
(1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
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.
The Company estimates discounted future net cash flows to determine fair value.
Any impairment provisions recognized are permanent and may not be restored in
the future.
For the years 1998 and 1997, the Company's proved properties were assessed
for impairment on an individual field basis and the Company recorded impairment
provisions of $4,092,000 and $21,148,000 respectively, attributable to certain
producing properties.
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 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. P&A costs are governed by federal and state regulations and contractual
obligations.
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. Estimated P&A costs (net of salvage value) are amortized
through depletion using the units-of-production method.
As of December 31, 1998, the Company's estimated P&A were approximately
$495,000, of which approximately $26,200 was amortized as of December 31, 1998.
The Company's estimated P&A costs at December 31, 1997 were immaterial.
OTHER PROPERTY AND EQUIPMENT
Other 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.
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 under which 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. The effect on
deferred
F-9
<PAGE>
MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1998 and 1997
(1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
tax assets and liabilities of a change in tax rates is recognized as part of the
provision for income taxes in the period that includes the enactment date.
STOCK BASED COMPENSATION
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. The
statement provides the option to continue under the accounting provisions of APB
Opinion 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 adopted the financial reporting provisions of SFAS No.
123, but continues under the accounting provisions of APB Opinion No. 25.
EARNINGS PER SHARE
Basic earnings per share is based on the weighted average shares outstanding
without any dilutive effects considered. Diluted earnings per share reflects
dilution from all potential common shares, including options, warrants and
convertible preferred stock.
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.
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. No single customer accounted for
greater than 10% of the Company's total oil and gas sales for the year ended
December 31, 1998. The Company sold oil and gas representing approximately 14%
of its total oil and gas sales to one customer, Warren Petroleum Company, L.P.,
for the year ended December 31, 1997.
ACCOUNTING PRONOUNCEMENTS
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities". SFAS No. 133 standardizes the accounting
for and disclosures of derivative instruments, including certain derivative
instruments embedded in other contracts. The statement is effective for the
Company beginning after January 1, 2000. As the Company historically has not
entered into derivative instruments for non-trading (hedging) purposes or for
trading purposes, the Company does not expect this statement to have a material
impact on its financial condition or results of operations upon implementation.
F-10
<PAGE>
MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1998 and 1997
(1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
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.
RECLASSIFICATIONS
Certain reclassifications of prior period amounts have been made to conform
to the current presentation.
(2) ACQUISITIONS
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 was merged into the Company in
January, 1998.
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 Company common stock
issued........................................................... $ 3,330
Cash consideration................................................. 6,654
Legal and accounting expenses...................................... 35
---------
Total.............................................................. $ 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.
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)
---------
Total.............................................................. $ 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.
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
F-11
<PAGE>
MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1998 and 1997
(2) ACQUISITIONS (Continued)
and its separate corporate existence ceased. Shore continued as a wholly-owned
subsidiary of the Company until it was merged into the Company in January 1998.
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 Company common stock
issued........................................................... $ 12,976
Estimated fair value of 266,667 shares of Company Series B
preferred stock.................................................. 3,627
Cash consideration................................................. 2,533
Legal and accounting expenses...................................... 38
---------
Total.............................................................. $ 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.
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)
---------
Total.............................................................. $ 19,174
---------
---------
</TABLE>
On March 27, 1998, the Company acquired 1,064,432 common shares,
approximately 79.2%, of Enex for $15,966,480. The Company purchased the common
shares of Enex through a cash tender offer that commenced February 19, 1998 (the
"Enex Acquisition"). The Company also incurred approximately $60,934 in legal,
accounting and printing expenses and issued 33,825 shares of Company common
stock for finders fees to unrelated third parties. At the time, Enex was general
partner of Enex Consolidated Partners, L.P., (the "Enex Partnership"), a New
Jersey limited partnership whose principal business is oil and gas exploration
and production. Enex's general partner interest was 4.1%. Enex also owned an
approximate 56.2% limited partner interest in Enex Partnership.
As part of the Enex Acquisition, the Company entered into a consulting
agreement, effective April 15, 1998, with the former president of Enex that
provides for monthly payments of $20,000 until expiration of the agreement on
May 18, 2002. The monthly payments serve as consideration for consulting, a
covenant not to compete and a preferential right to purchase certain oil and gas
acquisitions which the former president controls or proposes to acquire during
the term of the agreement. The Company will reimburse the former president each
month for reasonable and necessary business expenses incurred in connection with
the performance of consulting services. The agreement survives the former
president and his spouse and is nonassignable. At December 31, 1998, the present
value of the agreement, applying a 10% discount, is
F-12
<PAGE>
MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1998 and 1997
(2) ACQUISITIONS (Continued)
approximately $677,949. The long-term portion of the agreement is classified as
other liabilities in the financial statements.
The cost of acquiring 79.2% of Enex was allocated using the purchase method
of accounting to the consolidated assets and liabilities of Enex based on
estimates of the fair values with the remaining purchase price allocated to
proved oil and gas properties.
The allocation of the purchase price is summarized as follows: (in
thousands)
<TABLE>
<S> <C>
Working capital.................................................... $ 5,640
Oil and gas properties (proved and unproved)....................... 19,090
Minority interest.................................................. (7,669)
---------
Total.............................................................. $ 17,061
---------
---------
</TABLE>
Over the three-week period ended December 23, 1998, the Company acquired an
additional 0.80% (9,747 common shares) of Enex common stock for approximately
$68,000.
On April 16, 1998, the Company acquired substantially all of the oil and gas
assets of Service Drilling Co., LLC and certain affiliates ("Service Drilling"),
in exchange for 666,000 shares of Company common stock and $6,500,000 in cash
for a total acquisition cost of $10,054,774, before post-closing adjustments
(the "Service Acquisition"). The fair value of the securities issued in
connection with the Service Acquisition was calculated using the price of the
Company's common stock at the time the Service Acquisition 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 effective date of the acquisition was March 1, 1998 and the cost was
allocated using the purchase method of accounting.
On December 29, 1998, the Company completed the acquisition of the Enex
Partnership (the "Enex Partnership Acquisition"). The transaction consisted of
an exchange offer whereby the Company offered to exchange 2.086 shares of Series
C Preferred stock ("Series C") for each Enex Partnership unit (the "Exchange
Offer"). In connection with the Exchange Offer, the Company submitted a proposal
to investors in the Enex Partnership to amend the partnership agreement to
provide for the transfer of all of the assets and liabilities of the Enex
Partnership to the Company as of October 1, 1998 and dissolve the Enex
Partnership. The Exchange Offer was approved on December 29, 1998 and the
Company issued 2,177,481 Series C shares for 100% of the outstanding limited
partner units. At the close of the Exchange Offer, the Enex Partnership had
1,102,631 units outstanding. Enex was issued 1,293,522 Series C shares for its
56.2% ownership of the Enex Partnership. The remaining 883,959 Series C shares
were issued to the limited partners that elected to take Series C shares in lieu
of cash. Certain dissenting limited partners and fractional shareholders were
paid $538,750 in January 1999. Because of the dissenting limited partners, Enex
owns 59.4% of the Series C shares, of which 20% relating to the minority
interest (258,704 shares) are considered outstanding and held by third parties
in the consolidated financial statements at December 31, 1998.
The intent of the Exchange Offer was to acquire the 43.8% of the outstanding
limited partner units that the Company did not currently own. The tables below
present the consideration paid for 100% of the Enex Partnership and for the
43.8% of the Enex Partnership not owned by Enex.
F-13
<PAGE>
MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1998 and 1997
(2) ACQUISITIONS (Continued)
The cost of acquiring 100% of the outstanding limited partner units was
approximately $11.9 million, consisting of the following (in thousands):
<TABLE>
<S> <C>
Estimated fair value of 2,177,481 shares of Company Series C
preferred stock.................................................. 10,887
Cash consideration................................................. 539
Legal, accounting and other expenses............................... 431
---------
Total.............................................................. $ 11,857
---------
---------
</TABLE>
As Enex is consolidated into the Company's financial statements, the number
of shares outstanding and the value of the shares outstanding attributable to
the 43.8% of the Enex Partnership not owned by Enex and the minority interest
owners of Enex (20%) is 1,142,663 and $5,713,317, respectively. The cost of
acquiring the outstanding limited partner units that were not owned by Enex was
approximately $6.7 million, consisting of the following (in thousands):
<TABLE>
<S> <C>
Estimated fair value of 1,142,663 shares of Company Series C
preferred stock.................................................. 5,713
Cash consideration................................................. 539
Legal, accounting and other expenses............................... 431
---------
Total.............................................................. $ 6,683
---------
---------
</TABLE>
The Company's purchase price was allocated to the assets and liabilities of
the Enex Partnership based on estimates of the fair values with the remaining
purchase price allocated to proved oil and gas properties. The registration
costs of approximately $431,000 reduced the value of the Series C shares issued.
Because the Enex Partnership was consolidated in the financial statements of the
Company as of the effective date of October 1, 1998, the preliminary purchase
price allocation below shows the effect of the acquisition on the consolidated
financial statements (in thousands):
<TABLE>
<S> <C>
Working capital.................................................... (539)
Oil and gas properties............................................. (23)
Minority interest.................................................. 5,844
---------
Series C Preferred Stock........................................... $ 5,282
---------
---------
</TABLE>
F-14
<PAGE>
MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1998 and 1997
(2) ACQUISITIONS (Continued)
The following pro forma data presents the results of the Company for the
twelve months ended December 31, 1998 and 1997, as if the acquisitions of BEC,
Shore, Service, Enex and the Enex Partnership had occurred on January 1, 1997.
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>
PROFORMA
---------------------
1998 1997
--------- ----------
(UNAUDITED)
<S> <C> <C>
Total revenues......................................................... $ 21,232 $ 32,341
Net loss available to stockholders..................................... (7,413) (14,607)
Net loss per share available to stockholders........................... (0.87) (2.84)
</TABLE>
(3) RELATED PARTY TRANSACTIONS
The Company has a note receivable from Bay City Energy Group, Inc., a
shareholder of the Company, as of December 31, 1998 and 1997 in the amount of
$173,115 and $166,165 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. Interest of $34,110 was accrued on the
note as of December 31, 1998.
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. Mr. Lett has common stock ownership in two oil service
companies that provide services to the Company. The Company paid approximately
$148,000 and $88,000 to these companies for the years ended 1998 and 1997,
respectively.
The Company loaned Frank C. Turner II, Vice-President and Chief Financial
Officer, $14,400 in September 1998 to pay income taxes associated with the
exercise of incentive options. The balance at December 31, 1998 was $14,400.
Gary R. Christopher, a shareholder and director of the Company, is employed
by Kaiser-Francis Oil Co., which owns approximately 39% of the common stock of
the Company.
(4) ACCOUNTS RECEIVABLE-INSURANCE CLAIM
The Company owns a 100% working interest in the Louis Mayard #1 (the "Well")
well located in the Esther Field in Vermillion Parish, Louisiana. Due to a
failed recompletion attempt and the inability of the Company to shut in the Well
using normal operating methods, the Company incurred approximately $1,856,000 to
gain control of the Well using special crews. On November 4, 1998, the insurance
company made a partial payment to the Company under its well control insurance
policy of approximately $1,408,000. At December 31, 1998, the Company had
recorded the estimated remaining amount due from the insurance company in
current assets as Accounts Receivable-Insurance Claim.
F-15
<PAGE>
MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1998 and 1997
(5) LONG-TERM DEBT
Long-term debt at December 31, 1998 and 1997, consisted of the following:
<TABLE>
<CAPTION>
1998 1997
------------- -------------
<S> <C> <C>
Reducing revolving line of credit up to $100,000,000 due April 1, 2001,
secured by oil and gas properties, monthly borrowing base reductions of
$290,000 effective November 1, 1998 and monthly payments of interest at
LIBOR plus 2.00% and prime. At December 31, 1998 the LIBOR rate and the
prime rate were 5.07% and 7.75%, respectively.......................... $ 27,454,567 --
Convertible Loan for $50,000,000 due September 30, 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 September 30, 1998..... -- $ 10,956,298
Note, due 1/1/99, secured by office building, repayable in monthly
installments of $1,511 including interest at 7 3/4%.................... -- 133,952
------------- -------------
Total.................................................................... 27,454,567 11,090,250
Less current maturities.................................................. -- (1,375,537)
------------- -------------
Long tem debt excluding current maturities............................... $ 27,454,567 $ 9,714,713
------------- -------------
------------- -------------
</TABLE>
Effective March 27, 1998 the Company entered into a new reducing revolving line
of credit agreement (the "$100 million Revolver") with Compass Bank, as agent
and lender, and Bank of Oklahoma, as a participant lender, (collectively, the
"Banks"). The $100 million Revolver provided for an initial borrowing base of
$29 million. The initial borrowing base was reduced to $27.5 million ten days
after the effective date and further reduced by $275,000 per month, beginning
May 1, 1998 and ending October 1, 1998. In conjunction with the Service
Acquisition, the borrowing base was increased to $32.6 million and the monthly
borrowing base reductions were increased to $330,000. Effective October 1, 1998,
the semi-annual borrowing base redetermination date, the borrowing base was
calculated to be approximately $28.9 million with monthly borrowing base
reductions of $250,000 beginning November 1, 1998. Effective January 1, 1999,
due to the closing of the Enex Partnership Acquisition, the borrowing base
determined at October 1, 1998 was adjusted to $33.1 million with monthly
borrowing base reductions of $290,000 beginning November 1, 1998. The borrowing
base at December 31, 1998 was $32.5 million and the next semi-annual borrowing
base redetermination date is April 1, 1999.
The principal is due at maturity, April 1, 2001. Monthly principal payments
are made as required in order that the outstanding principal balance plus
outstanding letters of credit does not exceed the borrowing base. Interest is
payable monthly and is calculated at the prime rate. The Company may also elect
to calculate interest under the Libor rate, as defined in the agreement. The
Libor rate increases by (a) 2.00% if the outstanding loan balance and letters of
credit are equal to or greater than 75% of the borrowing base, (b) 1.75% if the
outstanding loan balance and letters of credit are less than 75% or greater than
50% of the borrowing base or (c) 1.50% if the outstanding loan balance and
letters of credit are equal to or less than 50% of the borrowing base. Libor
interest is payable at maturity of the Libor loan which cannot be less than
thirty days.
F-16
<PAGE>
MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1998 and 1997
(5) LONG-TERM DEBT (Continued)
At December 31, 1998 the Company had borrowed $27,454,567 and had $1,163,647
of outstanding letters of credit. As of December 31, 1998, the Company is paying
Libor plus 2.00% on a sixty day Libor loan for $25,469,605 and prime on
$1,984,962.
At December 31, 1998, the amount available under the borrowing base on the
$100 million revolver was approximately $3.9 million. Assuming no other changes,
the amount available to be borrowed at April 1 will be approximately $3.0
million. The Company expects that the Banks will complete the April 1 borrowing
base redetermination by May 1, 1999. The Company also expects that the borrowing
base will be less than the amount determined at the October 1, 1998
redetermination, adjusted for the monthly borrowing base reductions. The decline
is expected to be caused primarily by normal production declines and lower oil
and gas pricing scenarios used by the Banks to value the oil and gas reserves
for loan purposes. Pursuant to the terms of the $100 million Revolver, if the
borrowing base is less than the outstanding principal balance plus outstanding
letters of credit the Company has sixty days, after receipt of notice from the
Banks, to cure the excess by prepayment, providing additional collateral or a
combination of both. The Company is unable to predict the April 1 borrowing
base. While there can be no assurance, at the completion of the April 1
redetermination, the Company does not expect to be required to make any
prepayments or provide any additional collateral that would be material to the
financial condition of the Company.
Amounts spent on debt retirement due to reductions in the borrowing base
reduce the cash available to spend on acquisition, development and exploration
activities, and accordingly, oil and natural gas revenues and operating results
may be adversely affected.
The Company paid a facility fee equal to 3/8% of the initial borrowing base
and is required to pay 3/8% on any future increase in the borrowing base within
five days of written notice. The Company is required to pay a quarterly
commitment fee on the unused portion of the borrowing base of 1/2% if the
outstanding loan balance plus letters of credit are greater than 50% of the
borrowing base or 3/8% if the outstanding loan balance plus letters of credit
are less than or equal to 50% of the borrowing base. The Company is required to
pay a letter of credit fee on the date of issuance or renewal of each letter of
credit equal to the greater of $500 or 1 1/2% of the face amount of the letter
of credit.
The Company has granted to the Banks liens on substantially all of the
Company's oil and natural gas properties, whether currently owned or hereafter
acquired, and a negative pledge on all other oil and gas properties.
The $100 million Revolver requires, among other things, a cash flow coverage
ratio of 1.25 to 1.00 and a current ratio, excluding current maturities of the
$100 million Revolver, of 0.9 to 1.00, determined on a quarterly basis.
F-17
<PAGE>
MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1998 and 1997
(5) LONG-TERM DEBT (Continued)
Aggregate amounts of expected required repayments of long term debt at
December 31, 1998 are as follows:
<TABLE>
<S> <C>
1999........................................................... --
2000........................................................... 3,058,214
2001........................................................... 24,396,353
2002........................................................... --
2003........................................................... --
Thereafter..................................................... --
----------
$27,454,567
----------
----------
</TABLE>
(6) INCOME TAXES
Income tax (benefit) expense for the years ended December 31 consisted of
the following:
<TABLE>
<CAPTION>
1998 1997
------------- -------------
<S> <C> <C>
Current......................................................... $ -- $ 6,451
Deferred........................................................ (2,829,762) (7,451,249)
------------- -------------
Total......................................................... $ (2,829,762) $ (7,444,798)
------------- -------------
------------- -------------
</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>
1998 1997
------------- -------------
<S> <C> <C>
Income tax benefit at statutory rate............................ $ (3,197,251) $ (7,828,207)
Increase in valuation allowance................................. 352,363 --
Increase due to state taxes and other........................... 15,126 383,409
------------- -------------
Income tax benefit.............................................. $ (2,829,762) $ (7,444,798)
------------- -------------
------------- -------------
</TABLE>
The Company's net deferred tax liability at December 31, 1998 and 1997 is as
follows:
<TABLE>
<CAPTION>
1998 1997
------------- -------------
<S> <C> <C>
Deferred tax liability
Oil and Gas Properties........................................ $ 4,087,073 $ 5,906,070
------------- -------------
Deferred tax asset
NOL carryforward.............................................. (4,056,660) (1,083,324)
AMT tax credit carryforward................................... (36,482) (36,482)
Other......................................................... (394,570) (5,736)
------------- -------------
(4,487,712) (1,125,542)
------------- -------------
Valuation allowance............................................. 2,133,806
------------- -------------
Net deferred tax liability...................................... $ 1,733,167 $ 4,780,528
------------- -------------
------------- -------------
</TABLE>
F-18
<PAGE>
MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1998 and 1997
(6) INCOME TAXES (Continued)
In assessing the realizability of deferred tax assets, management considers
whether it is more likely than not that some portion or all of the deferred tax
asset will not be realized. Management considers the scheduled reversal of
deferred tax liabilities, projected future taxable income, and tax planning
strategies in making this assessment. Based upon projections for future taxable
income over the periods which the deferred tax assets are deductible and the
Section 382 limitation discussed below, management believes it is more likely
than not that the Company will realize the benefits of these deductible
differences, net of the existing valuation allowances at December 31, 1998. The
valuation allowance increased $2,133,806 during 1998. No valuation allowance was
recorded in 1997.
In March 1998, the Company acquired Enex which had a net operating loss
carryforward of approximately $5,200,000. These net opertaing losses expire in
varying amounts through 2012, and their utilization is limited due to an
ownership change pursuant to Section 382 triggered by the Company's acquisition
of Enex. The 1998 increase in valuation allowance includes amounts attributable
to the Enex Acquisition.
(7) RETIREMENT PLAN
All of the employees of the Company participate in a defined contribution
plan that provides for a maximum discretionary Company contribution of 15% of
total wages paid to employees for the year. The Company contributed $51,500 to
the plan for the year ended December 31, 1997. No contributions were made to the
plan for the year ending December 31, 1998.
F-19
<PAGE>
MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1998 and 1997
(8) STOCK OPTION AND STOCK APPRECIATION RIGHTS PLAN
At December 31, 1998, the Company had one fixed stock option plan, the 1995
Stock Option and Stock Appreciation Rights Plan (the "1995 Plan"). The Company
applies the intrinsic value method for accounting for stock based compensation
in accordance with APB Opinion No. 25, "Accounting for Stock Issued to
Employees" and related interpretations; accordingly, no compensation cost has
been recognized, as the exercise price of each option equals the market price of
the Company's Common Stock on the date of grant. 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 1998 and 1997, the Company's net loss and loss
per share would have been increased to the pro forma amounts listed below:
<TABLE>
<CAPTION>
1998 1997
------------- --------------
<S> <C> <C> <C>
Net loss...................................... As Reported $ (6,656,952) $ (16,184,052)
Pro Forma (7,145,580) (16,463,666)
Basic loss.................................... As Reported $ (0.83) $ (4.76)
Pro Forma (0.89) (4.85)
Diluted loss.................................. As Reported $ (0.83) $ (4.76)
Pro Forma (0.89) (4.85)
</TABLE>
The weighted average fair value of stock options granted during 1998 and
1997 was $2.97 and $2.77 per share, respectively. 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 1998 and 1997; no dividend
yield; expected volatility of 77 percent and 60 percent, respectively; weighted
average risk-free interest rate of 4.93% and 6.07%, respectively; and expected
life of 3 years. At December 31, 1998, the range of exercise prices and weighted
average remaining contractual life of options outstanding was $2.50 to $7.75 and
5.57 years, respectively.
At December 31, 1998 there were 633,000 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.
Information relating to stock options is summarized below:
<TABLE>
<CAPTION>
AVERAGE
EXERCISE PRICE
SHARES PER SHARE
--------- ---------------
<S> <C> <C>
Options and warrants outstanding at January 1, 1997........................... 125,000 $ 2.50
Granted....................................................................... 520,000 $ 6.07
Exercised..................................................................... (40,833) $ 2.50
---------
Options and warrants outstanding at December 31, 1997......................... 604,167 $ 5.57
Granted....................................................................... 307,000 $ 5.57
---------
Options and warrants outstanding at December 31, 1998......................... 911,167 $ 5.57
---------
---------
Options and warrants exercisable at December 31, 1998......................... 911,167 $ 5.57
---------
---------
</TABLE>
F-20
<PAGE>
MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1998 and 1997
(8) STOCK OPTION AND STOCK APPRECIATION RIGHTS PLAN (Continued)
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. Warrants to acquire 75,000 shares of the
Company common stock at an exercise price of $5.00 were granted outside of the
1995 Plan on September 15, 1998 to a consultant (See Note 9). Both grants are
included in the table above.
(9) STOCKHOLDERS' EQUITY
PREFERRED STOCK-SERIES A
On September 4, 1996, the Company signed a stock purchase agreement with
Kaiser Francis Oil Company ("Kaiser-Francis"). Kaiser-Francis 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 was subject to approval
by Kaiser-Francis of the use of proceeds. The Series A was nonvoting and accrued
dividends at 8% per annum, payable quarterly in cash. The Series A was
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 for every full year (excluding partial years)
thereafter at 8% per annum. As of December 31, 1997, 1,666,667 shares of the
Series A had been issued. On January 31, 1998 Kaiser-Francis converted 100% of
the Series A into 3,333,334 common shares of the Company.
PREFERRED STOCK-SERIES B
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 Company's Series A Preferred Stock. Until
December 31, 2002, any holder of the Series B may convert all or any portion of
Series B shares into Company Common Stock ("Common") at the greater ratio of (i)
one share of Common for each share of Series B or (ii) at a ratio based upon the
"Alternative Conversion Factor." The Alternative Conversion Factor is determined
by dividing the net increase in value of approximately 40,000 net mineral acres
owned by the Company in South Louisiana by $8,000,000 and multiplying the
product by 1,066,000 to arrive at the potential number of total Common shares
all holders would receive upon conversion. 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. Upon expiration of the conversion period, unless the
Company has given notice to redeem the Series B, all of the shares of the Series
B shall be automatically converted.
Since the merger date of June 30, 1997 the value of the fee minerals has not
increased to a level where the alternative conversion rate is more beneficial
than the initial conversion rate of one to one. As of December 31, 1998, no
additional shares of Series B have been issued.
PREFERRED STOCK-SERIES C
In connection with the Enex Partnership Merger, on December 29, 1998, the
Company issued 2,177,481 shares of Series C Preferred Stock ("Series C") in
exchange for 100% of the Enex Partnership units. The holders of Series C are
entitled to receive cumulative cash dividends in an amount per share of $0.50
per year (10% annual rate), payable semi-annually on March 31 and September 30
of each year.
F-21
<PAGE>
MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1998 and 1997
PREFERRED STOCK-SERIES C (CONTINUED)
These dividends are payable in preference to and prior to the payment of any
dividend or distribution to any holder of Company common stock or other junior
security. The Series C dividends begin to accrue on December 30, 1998. Compass
Bank has granted the Company a waiver allowing the Company to pay the dividends
on the Series C as long as no default or event of default exists or would exist
as a result of any Series C dividend payment. The Series C has a liquidation
preference of $5.00 per share plus an amount equal to all accumulated, accrued
and unpaid dividends. The liquidation preference of Series C ranks on parity
with the Series B.
Each share of Series C is convertible into one share of Company common
stock. On or after January 1, 2000, the Company may redeem all or a portion of
the Series C, at its option, at a purchase price of $5.00 per share, plus an
amount equal to all accumulated, accrued and unpaid dividends.
The Series C is generally nonvoting; however, holders of Series C are
entitled to vote on any amendment, alteration or appeal of any provision of the
Company's Articles of Incorporation which would adversely affect any holder's
rights and preferences.
As a result of its limited partnership interest in the Enex Partnership,
Enex owns 1,293,522 shares of the Series C of which the Company owns 80%, or
1,034,818 shares through its 80% ownership of Enex.
COMMON STOCK
On February 13, 1997, the Company awarded to the President, Vice-President
Chief Financial Officer and Vice-President Engineering, 25,909, 11,591 and
11,591 shares of restricted stock of the Company, respectively. The restricted
stock awards were 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 1, 1997 to December 31, 1997 and 50% over the six month period
January 1, 1998 to June 30, 1998. As of December 31, 1998, all restricted shares
were earned.
WARRANTS
On September 15, 1998 the Company entered into a consulting agreement with
Edward K. Andrew ("Andrew") for a term of five years beginning January 1, 1999.
As compensation, the Company granted to Andrew a warrant to purchase 75,000
shares of Company common stock at a price of $5.00. The warrants vested over the
period September 15, 1998 to January 1, 1999. The estimated fair value of the
warrants of $198,946 was determined at the date of grant and charged to stock
compensation expense over the vesting period.
F-22
<PAGE>
MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1998 and 1997
(9) STOCKHOLDERS' EQUITY (Continued)
EARNINGS PER SHARE
The following table provides a reconciliation between basic and diluted
earnings (loss) per share:
<TABLE>
<CAPTION>
WEIGHT AVERAGE
COMMON SHARES PER SHARE
NET LOSS OUTSTANDING AMOUNT
-------------- --------------- -----------
<S> <C> <C> <C>
Year Ended December 31, 1998:
Basic earnings per share........................................... $ (6,656,952) 8,050,108 $ (0.83)
Effect of dilutive stock options................................... -- -- --
Diluted earnings per share......................................... $ (6,656,952) 8,050,108 $ (0.83)
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)
</TABLE>
At December 31, 1998 and 1997, the Company had a weighted average of 849,890
and 542,249, combined stock options and warrants outstanding, respectively,
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. At December
31, 1998 and 1997, the Company had shares of convertible preferred stock
outstanding that were convertible into 1,409,330 and 3,600,001 shares of common
stock, respectively, and dividends of $67,945 and $604,712, respectively, which
were not included in the computation of diluted earnings per share, because the
effect of the assumed conversion of these preferred shares would have an
antidilutive effect on the computation of diluted loss per share.
(10) COMMITMENTS AND CONTINGENCIES
The Company is obligated under the terms of certain operating leases for
office space that expire over the next two and one-half years. Total rent
expense was $268,477 and $97,588 for the years ended December 31, 1998 and 1997,
respectively. Future minimum rental payments under the Company's leases total
$119,366, $75,720, and $34,860 for 1999, 2000, and 2001, respectively.
As of December 31, 1998, the Company had $1,163,647 of irrevocable standby
letters of credit outstanding.
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.
F-23
<PAGE>
MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1998 and 1997
(11) SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
CAPITALIZED COSTS AND COSTS INCURRED
The following tables present the capitalized costs related to oil and gas
producing activities and the related depreciation, depletion, amortization and
impairment and costs incurred in oil and gas property acquisition, exploration
and development activities (in thousands).
<TABLE>
<CAPTION>
1998 1997
---------- ----------
<S> <C> <C>
CAPITALIZED COSTS
Proved properties......................................................................... $ 84,325 $ 56,536
Nonproducing leasehold.................................................................... 6,524 6,118
Accumulated depreciation, depletion, amortization and impairment.......................... (38,810) (30,456)
---------- ----------
Net capitalized costs................................................................... $ 52,039 $ 32,198
---------- ----------
---------- ----------
COSTS INCURRED
Proved properties......................................................................... $ 28,878 $ 38,099
Unproved properties....................................................................... 337 6,195
Exploration costs......................................................................... 1,802 1,912
Development costs......................................................................... 3,041 1,862
---------- ----------
Total................................................................................... $ 34,058 $ 48,068
---------- ----------
---------- ----------
Depletion, depreciation, amortization and impairment...................................... $ 11,013 $ 25,651
---------- ----------
---------- ----------
</TABLE>
ESTIMATED QUANTITIES OF RESERVES
The Company has interests in oil and gas properties that are located
principally in Alabama, Louisiana, Kansas, 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 year-end
estimates of the Company's future net recoverable oil, gas and natural gas
liquids reserves. In 1998, such estimates were prepared by Lee Keeling and
Associates, Inc. and H.J. Gruy & Associates, Inc. In 1997, such estimates were
prepared by Lee Keeling and Associates, Inc., Cawley, Gillespie and Associates,
Inc., Ryder Scott Company, Huddleston & Company, Inc., and DeGoyler &
MacNaughton. 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.
F-24
<PAGE>
MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1998 and 1997
(11) SUPPLEMENTAL OIL AND GAS INFORMATION (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
--------------------------------------------------
1998 1997
------------------------ ------------------------
OIL OIL
PROVED RESERVES (BARRELS) GAS (MCF) (BARRELS) GAS (MCF)
- ------------------------------------------------------------ ---------- ------------ ---------- ------------
<S> <C> <C> <C> <C>
Beginning of year........................................... 2,933,000 18,419,000 1,389,945 8,964,238
Revisions of previous estimates............................. (277,291) (82,742) (205,733) (1,431,708)
Extensions and discoveries.................................. 103,506 290,347 22,520 705,020
Purchases of reserves in place.............................. 1,254,663 30,997,247 1,980,117 12,110,748
Sale of reserves in place................................... (90,373) (2,294,193) -- --
Production for the year..................................... (581,457) (3,846,679) (253,849) (1,929,298)
---------- ------------ ---------- ------------
End of year................................................. 3,342,048 43,482,980 2,933,000 18,419,000
---------- ------------ ---------- ------------
---------- ------------ ---------- ------------
<CAPTION>
PROVED DEVELOPED RESERVES
- ------------------------------------------------------------
<S> <C> <C> <C> <C>
Beginning of year........................................... 2,580,000 14,251,000 1,266,421 8,142,820
End of year................................................. 3,117,839 36,731,365 2,580,000 14,251,000
</TABLE>
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED RESERVES
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.
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.
F-25
<PAGE>
MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 1998 and 1997
(11) SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (Continued)
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
----------------------
1998 1997
---------- ----------
<S> <C> <C>
Future cash inflows................................................................. $ 133,549 $ 101,482
Future production costs and development costs....................................... (62,085) (54,358)
Future income tax expenses.......................................................... -- (11,853)
---------- ----------
Future net cash flows............................................................... 71,464 35,271
10% discount to reflect timing of cash flows........................................ (32,570) (10,778)
---------- ----------
Standardized measure of discounted future net cash flows............................ $ 38,894 $ 24,493
---------- ----------
---------- ----------
</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
---------------------
1998 1997
--------- ----------
<S> <C> <C>
Sales of oil and gas, net of production cost............................................ $ (7,210) $ (6,364)
Net changes in price and production cost................................................ (5,459) (11,108)
Extensions and discoveries.............................................................. 732 851
Purchase of reserves.................................................................... 23,092 20,293
Sale of reserves........................................................................ (1,528) --
Revisions of previous quantity estimates................................................ (1,573) 1,794
Net change in income taxes.............................................................. 2,712 (1,082)
Accretion of discount................................................................... 3,635 2,246
Changes in production rates (timing) and other.......................................... -- --
--------- ----------
End of year............................................................................. $ 14,401 $ 6,630
--------- ----------
--------- ----------
</TABLE>
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, 1998 and 1997, used in the above table were $9.50 and
$16.18 per barrel of oil and $2.10 and $2.54 per thousand cubic feet of gas,
respectively.
F-26
<PAGE>
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
Middle Bay as of December 31, 1998. All directors serve for a one-year term or
until the next Annual Meeting of Shareholders of the Company. The Board of
Directors held four meetings during the fiscal year ended December 31, 1998.
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 40 Chairman, President and Chief Executive 1992
Officer
C. J. Lett, III 41 Executive Vice President 1997
Frank C. Turner, II(1)(2) 38 Vice President and Chief Financial Officer N/A
Stephen W. Herod(2) 39 Vice President 1997
Robert W. Hammons 45 Vice President N/A
Lynn M. Davis 50 Secretary and Treasurer N/A
Edward P. Turner, Jr.(1) 69 Director 1989
Frank E. Bolling, Jr. 39 Director 1992
Alvin V. Shoemaker(3) 60 Director 1997
Gary R. Christopher 49 Director 1997
</TABLE>
- ------------------------
(1) Edward P. Turner, Jr. and Frank C. Turner, II, are father and son.
(2) Mr. Herod replaced Frank C. Turner, II effective July 3, 1997.
(3) Mr. Shoemaker replaced C. Noell Rather effective July 28, 1997.
JOHN J. BASSETT has served as President, Chief Executive Officer 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. Mr. Bassett was a director and
President of Bay City Energy Group, Inc., a principal shareholder of the
Company, from 1987 to 1998.
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, Superior Oil Company
employed Mr. Herod 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 Middle Bay
in 1993. Prior to his employment with the
III-1
<PAGE>
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 Middle Bay since 1992.
She served as Secretary-Treasurer of the general partner of the Predecessor
Partnership from 1984 to 1992 and was a director from 1988 to 1992. 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
Association and a director of Harcourt Brace Jovanovich, Royal Insurance of
America, Hanover Compressor Company, the Council on Foreign Relations and the
Wharton School of Finance Board.
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 3,333,334 shares of the Company's
common stock.
C. J. LETT, III has served as Executive Vice President and a director for
Middle Bay since the merger of the Company and Bison Energy Corporation on
February 28, 1997. Mr. Lett was President and a director of Bison Energy
Corporation from 1981 to 1997.
(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 Middle
Bay'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 Middle Bay's common stock during 1998.
(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. During 1998, the Audit Committee
met one time. Each member attended the committee meeting.
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
III-2
<PAGE>
senior management. During 1998, the Compensation Committee met two times. Each
member attended all meetings of the committee.
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, 1996
through December 31, 1998:
<TABLE>
<CAPTION>
LONG-TERM COMPENSATION
--------------------------
AWARDS
ANNUAL COMPENSATION -----------
- --------------------------------------------------------------------------------------------------- SECURITIES PAYOUTS
RESTR. UNDERLYING -------------
OTHER ANNUAL STOCK OPTIONS/ LTIP
NAME AND PRINCIPAL POSITION YEAR SALARY($) BONUS($) COMPENSATION AWARDS($) SARS(#) PAYOUTS($)
- ------------------------------ --------- ----------- ----------- ----------------- ----------- ----------- -------------
<S> <C> <C> <C> <C> <C> <C> <C>
John J. Bassett 1998 111,667 37,121 -- -- 35,000 --
President & 1997 95,521 6,001 -- 129,545 132,000 --
Chief Executive Officer 1996 58,075 -- -- -- 20,000 --
Steve W. Herod 1998 100,000 24,375 -- -- 35,000 --
Vice President-- 1997 50,000 -- -- -- -- --
Corp. Development 1996 -- -- -- -- -- --
Robert W. Hammons 1998 91,250 25,625 -- -- 22,000 --
Vice President-- 1997 85,729 6,000 -- 57,960 94,500 --
Engineering 1996 58,075 -- -- -- 20,000 --
Frank C. Turner, II 1998 89,167 25,521 -- -- 22,000 --
Vice President & 1997 85,729 6,000 -- 57,960 94,500 --
CFO 1996 54,458 -- -- -- 20,000 --
<CAPTION>
- ------------------------------
ALL OTHER
NAME AND PRINCIPAL POSITION COMPENSATION($)
- ------------------------------ -----------------
<S> <C>
John J. Bassett --
President & 13,032
Chief Executive Officer 2,271
Steve W. Herod --
Vice President-- --
Corp. Development --
Robert W. Hammons --
Vice President-- 12,500
Engineering 2,271
Frank C. Turner, II
Vice President & 16,250
CFO 2,174
</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 Middle Bay 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 1998, was 1,500,000. During
the fiscal year ended December 31, 1998, options covering 232,000 shares were
issued under the Plan. As of December 31, 1998, options for a total of 836,167
shares had been granted and were outstanding; 611,167 under the Plan and 225,000
outside of the Plan. In February 1999, options for a total of 200,000 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 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.
III-3
<PAGE>
The following table provides certain information with respect to all options
granted during the fiscal year ended December 31, 1998 to any executive officer
or director of Middle Bay; 232,000 options were granted under the Plan and none
were granted outside of the Plan:
INDIVIDUAL GRANTS
<TABLE>
<CAPTION>
NUMBER OF
SECURITIES
UNDERLYING % OF TOTAL
OPTIONS/ OPTIONS/SARS
SARS GRANTED IN EXERCISE OR BASE EXPIRATION
NAME GRANTED(#) FISCAL YEAR PRICE($/SH) DATE
- ------------------------------------------------------- ----------- ------------- ------------------- -----------
<S> <C> <C> <C> <C>
John J. Bassett........................................ 35,000 15.1% 5.75 1/13/2008
Steve W. Herod......................................... 35,000 15.1% 5.75 1/13/2008
Frank C. Turner, II.................................... 22,000 9.5% 5.75 1/13/2008
Robert W. Hammons...................................... 22,000 9.5% 5.75 1/13/2008
C. J. Lett, III........................................ 22,000 9.5% 5.75 1/13/2008
Edward P. Turner, Jr.*................................. 10,000 4.3% 5.75 1/13/2008
Frank E. Bolling, Jr.*................................. 10,000 4.3% 5.75 1/13/2008
Alvin V. Shoemaker*.................................... 10,000 4.3% 5.75 1/13/2008
Gary R. Christopher*................................... 10,000 4.3% 5.75 1/13/2008
</TABLE>
- ------------------------
* Nonemployee director
(c) AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR AND OPTION VALUE TABLE
AS OF DECEMBER 31, 1998
The following table sets forth certain information concerning each exercise
of stock options during the year ended December 31, 1998, by each of the named
executive officers and directors and the aggregated fiscal year-end value of the
unexercised options of each such named executive officer and director:
INDIVIDUAL GRANTS
<TABLE>
<CAPTION>
NUMBER OF SECURITIES
UNDERLYING VALUE OF UNEXERCISED
UNEXERCISED IN-THE-MONEY
OPTIONS/SARS AT FY OPTIONS/ SARS AT FY
END(#) END($)
SHARES ACQUIRED VALUE -------------------- --------------------
NAME ON EXERCISE(#) REALIZED($) EXER. UNEXER. EXER. UNEXER.
- ------------------------------- ----------------- --------------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
John J. Bassett................ -- -- -- 187,000 -- 5,000
Frank C. Turner, II............ -- -- 20,000 116,500 5,000 --
Robert W. Hammons.............. -- -- -- 136,500 -- 5,000
C. J. Lett, III................ -- -- -- 37,000 -- --
Steve W. Herod................. -- -- -- 35,000 -- --
Edward P. Turner, Jr.*......... -- -- -- 44,734 -- 5,000
Frank E. Bolling, Jr.*......... -- -- -- 44,533 -- 5,000
Alvin V. Shoemaker*............ -- -- -- 10,000 -- --
Gary R. Christopher*........... -- -- -- 10,000 -- --
</TABLE>
- ------------------------
* Nonemployee director
(d) OTHER COMPENSATION UNDER PLANS
Middle Bay 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, 1998,
1997 and 1996, Middle Bay contributed a total of $0, $51,500 and $5,000 to the
SEP Plan, respectively, including $0, $32,064 and $3,068, respectively, for all
executive officers as a group.
III-4
<PAGE>
Middle Bay 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 or 1998.
The Company has no other retirement, pension/profit sharing or other
deferred compensation plan for its employees.
(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 a 1% net profits interest
(as defined) 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 year ended December 31, 1996, the
Company paid $6,916 to employees through the employee incentive plan, including
$4,897 for all executive officers as a group. No amount was paid into the plan
in 1997 or 1998.
(f) DIRECTORS' FEES
Directors of Middle Bay 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) EMPLOYMENT 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 Middle Bay
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 Middle Bay 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-5
<PAGE>
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 Middle Bay'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 Middle Bay's issued and
outstanding common and preferred stock as of December 31, 1998:
<TABLE>
<CAPTION>
TITLE OF AMOUNT AND NATURE OF PERCENT OF
CLASS(6) NAME AND ADDRESS OF BENEFICIAL OWNER BENEFICIAL OWNERSHIP CLASS
- ----------- ---------------------------------------- -------------------- -----------
<S> <C> <C> <C>
Common Kaiser-Francis Oil Company(1)(2) 3,333,334 39.1%
6733 South Yale
Tulsa, OK 74136
Common C. J. Lett, III(1) 1,187,556 13.9%
9320 East Central
Wichita, KS 67206
Common Weskids, L.P.(3) 843,687 9.9%
310 South Street
Morristown, NJ 07960
Common Weskids, Inc. 843,687 9.9%
310 South Street
Morristown, NJ 07960
Common Alvin V. Shoemaker(1)(4) 682,222 8.0%
8800 First Avenue
Stone Harbor, NJ 08247
Common SerDrilco, Inc.(1)(5) 666,000 7.8%
15 West 6th Street, Suite 1800
Tulsa, OK 74192
Preferred Weskids, L.P.(3) 117,467 44.1%
Series B 310 South Street
Morristown, NJ 07960
Preferred Weskids, Inc. 117,467 44.1%
Series B 310 South Street
Morristown, NJ 07960
Preferred Alvin V. Shoemaker(1)(4) 117,466 44.1%
Series B 8800 First Avenue
Stone Harbor, NJ 08247
Preferred Stephen W. Herod(1) 15,867 5.9%
Series B 1110 Briar Ridge Drive
Houston, TX 77057
Preferred W. Tim Sexton(1) 15,867 5.9%
Series B 12010 Winwood
Houston, TX 77024
</TABLE>
- ------------------------
(1) The nature of the beneficial ownership is sole voting and investment.
(2) George B. Kaiser is the majority shareholder of Kaiser-Francis Oil Company.
(3) 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. Weskids, Inc. is the general partner of Weskids,
L.P. and effectively controls Weskids, L.P. The officers and directors of
Weskids,
III-6
<PAGE>
Inc. are as follows: J. Peter Simon, director; Michael B. Lenard, President;
Mark J. Butler, Vice President/Treasurer; and Christine W. Jenkins,
Secretary.
(4) Alvin V. Shoemaker individually owns 313,421 shares of common stock and
117,466 shares of Series B preferred stock. In addition, 361,800 shares of
common stock are held by the Shoemaker 1998 Descendants Trust and Mr.
Shoemaker disclaims beneficial ownership of these shares. An additional
7,000 common shares are held by affiliated family partnerships that Mr.
Shoemaker controls.
(5) SerDrilco, Inc. is the parent company of Service Drilling Co., LLC. Sherman
E. Smith is the majority shareholder of SerDrilco, Inc.
(6) Series B preferred stock is convertible into common stock at a variable
ratio of not less than one-to-one as determined by the terms of the June 20,
1997 merger agreement between Middle Bay and Shore Oil Company.
III-7
<PAGE>
(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 March 1, 1999:
<TABLE>
<CAPTION>
CONV. AMOUNT AND NATURE OF
PREFERRED & NAME AND ADDRESS OF BENEFICIAL PERCENT OF
OPTIONS STOCK BENEFICIAL OWNER OWNERSHIP(6) CLASS
- -------------- ---------- ------------------------------ ---------------------- -----------
<C> <C> <S> <C> <C>
222,000 25,211 John J. Bassett 247,211 2.5%
4326 Noble Oak Trail
Houston, TX 77059
136,500 14,296 Frank C. Turner, II 150,796 1.5%
1406 Tallow Court
Seabrook, TX 77586
156,500 6,996 Robert W. Hammons 163,496 1.7%
915 Kentbury Court
Katy, TX 77450
13,500 -- Lynn M. Davis 13,500 --
121 Donna Circle
Daphne, AL 36526
49,734 376,241 Edward P. Turner, Jr.(1) 425,975 4.3%
100 Central Avenue
Chatom, AL 36518
47,000 1,187,556 C. J. Lett, III(2) 1,234,556 12.6%
9320 East Central
Wichita, KS 67206
49,533 -- Frank E. Bolling, Jr. 49,533 0.5%
3830 Kendale Drive
Gautier, MS 39553
15,000 13,000 Gary R Christopher(3) 28,000 0.3%
6733 South Yale
Tulsa, OK 74136
132,466 684,222 Alvin V. Shoemaker(4) 816,688 8.3%
8800 First Avenue
Stone Harbor, NJ 08247
70,867 109,816 Stephen W. Herod(5) 180,683 1.8%
1110 Briar Ridge Drive
Houston, TX 77057
All executive officers and 3,310,438 33.7%
directors as a group (10
persons)
</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 and a director of the Company on
February 28, 1997 in connection with the Bison Merger.
(3) Mr. Christopher is an officer of Kaiser-Francis Oil Company, which is the
beneficial owner of 3,333,334 of the Company's common shares.
III-8
<PAGE>
(4) Mr. Shoemaker was named a director of Middle Bay in July 1997 in connection
with the Shore Oil Company merger. Consists of 117,466 shares of Series B
preferred stock convertible into 117,466 common shares of the Company.
(5) Mr. Herod was named Vice President--Corporate Development and a director of
Middle Bay in
July 1997 in connection with the Shore Oil Company merger. Consists of
15,867 shares of Series B preferred stock convertible into 15,867 common
shares of the Company.
(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 Middle Bay, is managing partner of the
law firm of Turner, Onderdonk, Kimbrough & Howell, P.A., the Company's counsel
for certain corporate and oil and gas matters. For the years ended December 31,
1996 through 1998, Middle Bay paid legal fees to Mr. Turner's firm of $1,560,
$2,874 and $915, 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. Middle Bay 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.
Bay City Energy Group, Inc. is presently indebted to Middle Bay in the
amount of $173,115 ($139,005 of principal and $34,110 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 the Company's common stock. Edward P. Turner, Jr., a
director of Middle Bay, 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 Middle Bay 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
Middle Bay's common stock, and the 562,000 shares held by Bison (as a result of
the NPC Merger) were canceled. The Company rents office space for its division
office in Wichita, KS from Mr. Lett at the rate of $3,000 per month through
February 2000.
The Company loaned Frank C. Turner, II, Vice President and Chief Financial
Officer, $14,400 in September 1998 to pay income taxes associated with the
exercise of incentive stock options.
Gary R. Christopher, a director of Middle Bay, is employed by Kaiser-Francis
Oil Company, which directly owns 3,333,334 common shares or 39.1% of the
Company.
[The remainder of this page has been intentionally left blank.]
III-9
<PAGE>
PART IV
I. ITEM EXHIBITS AND REPORTS ON FORM 8-K
(a) EXHIBITS
<TABLE>
<CAPTION>
SEQUENTIAL
EXHIBIT NO. DESCRIPTION OF EXHIBIT PAGE NO.
- ------------- ----------------------------------------------------------------------------------------- -------------
<C> <S> <C>
2.1 Agreement and Plan of Merger dated February 10, 1997 among the Company, Bison Energy N/A
Corporation, and C.J. Lett(6)
2.2 Agreement and Plan of Merger dated June 20, 1997 among the Company, Shore Oil Company, N/A
and its Shareholders(5)
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 N/A
Series A Preferred Stock(4)
3.4 Articles of Amendment to Articles of Incorporation designating preferences and rights of N/A
Series B Preferred Stock(5)
3.5 Articles of Amendment to Articles of Incorporation increasing authorized capital stock(7) N/A
3.6 Articles of Amendment to Articles of Incorporation increasing authorized capital stock(8) N/A
3.7 Articles of Amendment to Articles of Incorporation designating preferences and rights of N/A
Series C Preferred Stock(9)
3.8 Bylaws(1) N/A
10.1 Executive Employment Agreement for John J. Bassett dated January 30, 1997(14) N/A
10.2 Executive Employment Agreement for Robert W. Hammons dated January 30, 1997(14) N/A
10.3 Executive Employment Agreement for Steve W. Herod dated July 1, 1997(14) N/A
10.4 1995 Stock Option and Stock Appreciation Rights Plan(3) N/A
10.5 Amended and Restated 1995 Stock Option and Stock Appreciation Rights Plan(7) N/A
10.6 Amendment No. 1 to Amended and Restated 1995 Stock Option and Stock Appreciation Rights N/A
Plan(8)
10.7 Credit Agreement between the Company and Enex Resources Corporation, as borrower, and N/A
Compass Bank, as agent and lender, Bank of Oklahoma, N.A., as a lender, and the other
lenders signatory thereto, dated March 27, 1998(10)
10.8 Asset Purchase Agreement among the Company, Service Drilling Co., L.L.C. and Diamond S N/A
Gas Systems, L.L.C. dated April 16, 1998(11)
10.9 Consulting Agreement between Gerald B. Eckley and the Company dated April 15, 1998(12) N/A
16.1 Letter from Schultz, Watkins & Company regarding change in certifying public accountants N/A
dates October 9, 1998(13)
21.1 Subsidiaries of the Company N/A
23.3 Consent of Deloitte & Touche, L.L.P., independent accountants(9) N/A
</TABLE>
IV-1
<PAGE>
(a) 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 definitive Proxy Statement filed
May 5, 1997.
(8) Incorporated by reference to Exhibits to definitive Proxy Statement filed
May 15, 1998.
(9) Incorporated by reference to Exhibits to Amendment No. 1 to Form S-4 filed
October 19, 1998.
(10) Incorporated by reference to Exhibits to Amendment No. 3 and Final
Amendment to Schedule 14D-1 filed April 13, 1998.
(11) Incorporated by reference to Exhibits to Form 8-K filed May 6, 1998.
(12) Incorporated by reference to Exhibits to Registration Statement on Form
S-4 filed July 31, 1998.
(13) Incorporated by reference to Form 8-K filed October 13, 1998.
(14) Incorporated by reference to Form 10-KSB filed March 31, 1998.
IV-2
<PAGE>
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.
<TABLE>
<S> <C> <C>
MIDDLE BAY OIL COMPANY, INC.
(Registrant)
By: /s/ JOHN J. BASSETT
-----------------------------------------
John J. Bassett
PRESIDENT
</TABLE>
March 30, 1999
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>
March 30, 1999 /s/ JOHN J. BASSETT
- ------------------------------------------- --------------------------------------------
Date John J. Bassett
Director, President, Chief Executive
and Operating Officer
March 30, 1999 /s/ C. J. LETT III
- ------------------------------------------- --------------------------------------------
Date C. J. Lett, III
Executive Vice President and Director
March 30, 1999 /s/ STEPHEN W. HEROD
- ------------------------------------------- --------------------------------------------
Date Stephen W. Herod
Vice President and Director
March 30, 1999 /s/ EDWARD P. TURNER, JR.
- ------------------------------------------- --------------------------------------------
Date Edward P. Turner, Jr.
Director
March 30, 1999 /s/ FRANK E. BOLLING, JR.
- ------------------------------------------- --------------------------------------------
Date Frank E. Bolling, Jr.
Director
March 30, 1999 /s/ GARY R. CHRISTOPHER
- ------------------------------------------- --------------------------------------------
Date Gary R. Christopher
Director
March 30, 1999 /s/ ALVIN V. SHOEMAKER
- ------------------------------------------- --------------------------------------------
Date Alvin V. Shoemaker
Director
</TABLE>
<PAGE>
EXHIBIT 21.1
MIDDLE BAY OIL COMPANY, INC.
LIST OF SUBSIDIARIES AS OF DECEMBER 31, 1998
Middle Bay Production Company (INCORPORATED IN KANSAS)
ENEX RESOURCES CORPORATION (INCORPORATED IN DELAWARE)
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> DEC-31-1998
<CASH> 1,040,096
<SECURITIES> 0
<RECEIVABLES> 3,898,490
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 4,938,586
<PP&E> 91,644,762
<DEPRECIATION> 39,073,584
<TOTAL-ASSETS> 57,940,817
<CURRENT-LIABILITIES> 4,799,932
<BONDS> 27,454,567
0
8,908,937
<COMMON> 37,118,643
<OTHER-SE> (23,469,747)
<TOTAL-LIABILITY-AND-EQUITY> 57,940,817
<SALES> 15,011,354
<TOTAL-REVENUES> 17,702,578
<CGS> 7,801,249
<TOTAL-COSTS> 27,106,258
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 1,971,595
<INCOME-PRETAX> (9,403,680)
<INCOME-TAX> (2,829,762)
<INCOME-CONTINUING> (6,589,007)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (6,589,007)
<EPS-PRIMARY> (0.83)
<EPS-DILUTED> (0.83)
</TABLE>
