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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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, 1996 Commission file number 0-21702
MIDDLE BAY OIL COMPANY, INC.
(Exact Name of Registrant as Specified in Its Charter)
ALABAMA 63-1081013
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification No.)
115 SOUTH DEARBORN STREET
MOBILE, ALABAMA 36602
(Address of Principal Executive Offices) (Zip Code)
Registrant's telephone number, including area code: (334) 432-7540
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange on
Title of Each Class Which Registered
--------------------- ------------------------
None N/A
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, $.02 Par Value
Check whether the Registrant (1) filed all reports required to be filed by
Section 13 or 15(d) of the Exchange Act during the past 12 months (or for
such shorter period that the Registrant was required to file such reports),
and (2) has been subject to such filing requirements for the past 90 days.
[X]
Check if disclosure of delinquent filers in response to Item 405 of
Regulation S-B is not contained in this form, and will not be contained, to
the best of Registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-KSB or any
amendment to this Form 10-KSB. [X]
Revenues of Registrant for fiscal year ended December 31, 1996 are
$4,886,421.
The aggregate market value as of March 15, 1997 of voting stock held by
nonaffiliates of the Registrant was $6,915,983.
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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).
2,497,775 Shares of Common Stock, $.02 Par Value, as of March 15, 1997
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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.
"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.
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"Operating Costs" - The expenses of producing oil or gas from
a formation, consisting of the costs incurred to operate and maintain wells and
related equipment and facilities, including labor costs, repair and maintenance,
supplies, insurance, production, severance and other production excise taxes.
"Producing Property" - A property (or interest therein)
producing oil and gas in commercial quantities or that is shut-in but capable of
producing oil and gas in commercial quantities, to which Producing Reserves have
been assigned by an independent petroleum engineer. Interests in a property may
include Working Interests, production payments, Royalty Interests and other
non-Working Interests.
"Prospect" - An area in which a party owns or intends to
acquire one or more oil and gas interests which is geographically defined on the
basis of geological data and which is reasonably anticipated to contain at least
one reservoir of oil, gas or other hydrocarbons.
"Proved Developed Reserves" - Proved Reserves which can be
expected to be recovered through existing wells with existing equipment and
operating methods.
"Proved Reserves" - The estimated quantities of crude oil,
natural gas and other hydrocarbons which, based upon geological and engineering
data, are expected to be produced from known oil and gas reservoirs under
existing economic and operating conditions, and the estimated present value
thereof based upon the prices and costs on the date that the estimate is made
and any price changes provided for by existing conditions.
"Royalty Interest" - An interest in an oil and gas property
entitling the owner to a share of oil and gas production free of the costs of
production.
"Undeveloped Acreage" - Oil and gas acreage (including, in
applicable instances, rights in one or more horizons which may be penetrated by
existing well bores, but which have not been tested) to which Proved Reserves
have not been assigned by independent petroleum engineers.
"Working Interest" - The operating interest under a Lease
which gives the owner the right to drill, produce and conduct operating
activities on the property and a share of production, subject to all Royalty
Interests, and other burdens and to all costs of exploration, development and
operations and all risks in connection therewith.
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PART I
ITEM 1. DESCRIPTION OF BUSINESS
(a) Business Development
Middle Bay Oil Company, Inc. (the "Company") is an independent
oil and gas company engaged in the exploration, development and production of
oil and gas in the contiguous United States. The Company's strategy focuses on
increasing its reserves of crude oil and natural gas by the acquisition and
development of proved oil and gas properties primarily in the Mid-continent and
Gulf Coast Basin. By focusing its efforts on increasing reserves during the
current period which the Company believes reflects historically low market
prices for oil and gas, the Company believes that it will be well positioned to
benefit in the event of any future increases in demand for natural gas and oil.
Consistent with its efforts to increase reserve levels, the Company also
participates on a limited basis in drilling and development activities in other
geographic regions of the contiguous United States. The principal executive
offices of the Company are located at 115 South Dearborn Street, Mobile, Alabama
36602, and the Company's mailing address is P.O. Box 390, Mobile, Alabama 36601.
Its telephone number is (334) 432-7540.
The Company was incorporated under the Alabama Business
Corporation Code on November 30, 1992. Effective December 31, 1992, all of the
assets of Bay City Consolidated Partners, L.P., an Alabama limited partnership
(the "Predecessor Partnership"), were transferred to the Company in exchange for
common stock of the Company. The Predecessor Partnership was then dissolved
under the Alabama Uniform Limited Partnership Act. The shares of common stock of
the Company then owned by the limited partnership were distributed to the
general partner and the limited partners prorata in accordance with their
respective interests in the limited partnership. On October 6, 1994,
shareholders of the Company ratified the conversion of the Company into
corporate form. References to the Company include, as the context requires, the
Predecessor Partnership.
On February 23, 1995, the Company completed the acquisition of
proved producing properties from Parker & Parsley Development LP (the "P&P
Acquisition"). The acquisition included interest in 142 oil wells and 23 gas
wells in 37 fields located in Alabama, Arkansas, Louisiana, Mississippi and New
Mexico for a purchase price, subject to certain adjustments, of $3,885,000 in
cash, effective March 1, 1994. The entire purchase price was financed by a term
loan from the Bank of Oklahoma (the "Bank"). The value is highly concentrated in
four fields: Magnolia Lime Unit, Columbia, AR; Wild Fork Creek, Escambia, AL;
Lea North, Lea, NM; and Little Comite Creek, East Feliciano Parish, LA. The P&P
Acquisition included estimated proved producing reserves of 415 MBbls of oil and
2.3 Bcf of gas, as of January 1, 1995. Current monthly net production from the
properties is estimated at 5 MBbls of oil and 40 MMcf of gas.
On April 3, 1996, the Company entered into a Joint Expense and
Participation Agreement with Brigham Oil and Gas, L.P. (the "Brigham Agreement")
which allows the Company to participate in all of the wells that Brigham drills
over the 12-month period beginning April 1, 1996. The Company is committed to
funding $1,500,000 in drilling costs over this 12-month period. As of December
31, 1996, the Company had advanced $1,452,980 in drilling and completion costs
to Brigham Oil and Gas, L.P. Of the total advance,
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$1,142,090 was spent on successful and unsuccessful wells and $310,890 was spent
on wells in process at December 31, 1996. As of December 31, 1996, the Company
had participated in the drilling of 49 wells, of which 31 were successfully
completed, and discovered 76.5 thousand barrels of oil and 92.3 million cubic
feet of natural gas, for a total value of $1.9 million (PV 10%).
The Company effected a one-for-two reverse split of its common
stock on March 21, 1995, and on May 9, 1995, the Company's common stock began
trading on the OTC Bulletin Board. On September 29, 1995 the Company's stock
began trading on the NASDAQ Small Cap Market tier of the NASDAQ Stock Market
under the symbol "MBOC".
On September 4, 1996, the Company signed a stock purchase
agreement with Kaiser Francis Oil Company ("the Preferred Stock Agreement").
Kaiser-Francis agreed to purchase 1,666,667 shares of Series A Preferred Stock
("Preferred") 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 Preferred is
subject to approval by Kaiser-Francis of the use of proceeds. The Preferred is
nonvoting and accrues dividends at 8% per annum, payable quarterly in cash. The
Preferred is convertible at any time after issuance into shares of common stock
at the rate of two shares of common stock for each share of Preferred before
January 1, 1998. The conversion rate decreases thereafter at 8% per annum. The
Company will pay the costs of registration of the Preferred or the underlying
common stock under the Securities Act of 1933 upon request of Kaiser-Francis.
The Company may redeem the Preferred, in whole or in part, at any time after
January 1, 2007 at a price of $6.00 per share. As of December 31, 1996, 166,667
shares of the Preferred had been issued. Management expects to use the preferred
stock to acquire direct interests in producing properties with exploitation
potential or as financing for mergers with exploration and production companies.
On December 17, 1996, the Company entered into an Agreement
and Plan of Merger (the "NPC Merger") with NPC Energy Corporation ("NPC"),
whereby NPC would be merged into the Company in exchange for Company common
stock and cash. The Merger was approved by NPC's shareholders 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
Merger, the Company issued 562,000 shares of its common stock and paid
$1,226,400 to NPC in exchange for all of the stock of NPC. Preferred stock in
the amount of $1.0 million under the Preferred Stock Agreement was sold to
finance the cash portion of the purchase price. The NPC Merger added
approximately 503 thousand barrels of oil and 3,139 million cubic feet of gas,
for a total reserve value of $6.0 million (PV 10%). Approximately 137 thousand
barrels of oil and 910 million cubic feet of gas and $1.8 million of the NPC
reserve value (PV 10%) consists of proved behind pipe and proved undeveloped
reserves.
In connection with the Brigham Agreement, effective April 1,
1996, the Bank converted the Company's term loan into a $6.0 million, one-year
revolving line-of-credit (the "Revolver). The Revolver requires monthly payments
of interest only at prime plus 1.5% and converts again into a term note on
September 30, 1997. The term note matures September 30, 2003 and is payable in
72 equal monthly principal and interest payments at prime plus 1.5%.
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The Revolver is secured by a first mortgage on a portion of
the Company's existing properties selected by the Bank as collateral from time
to time, and the Bank has an option to collateralize 100% of the Company's
proved reserves. In the event that a mortgaged property is sold, upon prior
written consent of the Bank, the greater of 65% of the gross sales price or 65%
of the discounted present worth of the mortgaged property will be applied to the
outstanding principal balance of the term loan in the inverse order of the due
date of scheduled monthly installments.
The Revolver contains various restrictive covenants similar to
those contained in the prior $5.6 million term loan. The significant financial
covenants contained in the Revolver include a requirement that the Company
maintain a balance sheet current ratio of at least 0.9 to 1.0. The current ratio
computation excludes all accounts receivable from certain affiliates and current
maturities of long-term debt. The Revolver requires the prior written consent of
the Bank before the Company can, among other things, (a) create or assume any
debt, with specified exceptions, (b) create or permit to exist any liens on the
mortgaged properties, with certain exceptions, (c) sell or dispose of any
property if such sale or disposition exceeds $50,000 per transaction, or (d)
merge into or consolidate into any other entity.
The borrowing base for the Revolver will be redetermined on
March 31, 1997 by the Bank's engineers or any other independent engineer using
the Bank's pricing and discount factors and the future net revenue expected to
be produced from the Company's oil and gas reserves. If at any time during the
period of the Revolver (and the period subsequent to the conversion to the term
note) the collateral borrowing base, as determined by the Bank, should be less
than the aggregate unpaid principal balance of the note, the collateral
deficiency shall be cured by making a cash prepayment on the note in the amount
of the deficiency or by increasing the monthly principal payments for the next
six months to reduce the principal balance to the projected borrowing base as of
the next semiannual redetermination date. As of December 31, 1996, the principal
balance of the Revolver was $5,186,596.
Recent Transaction. On February 10, 1997, the Company entered
into an Agreement and Plan of Merger (the "Bison Merger") with Bison Energy
Corporation ("Bison"), whereby Bison was merged with a wholly-owned subsidiary
of the Company in exchange for Company common stock and cash. The Bison Merger
was approved by Bison's sole shareholder and closed on February 28, 1997. Bison
is a domestic exploration and production company with assets located in Kansas
and Oklahoma. Pursuant to the Bison Merger, the Company issued 1,167,556 shares
of its common stock and net cash consideration of $5,900,000 to Bison in
exchange for all of the stock of Bison. 562,000 shares of Company common stock
owned by Bison (as a result of the NPC Merger) were canceled at closing. The
cash portion of the Bison Merger was financed through the issuance of 1,000,000
shares of preferred stock under the Preferred Stock Agreement for $6.0 million.
(b) Business of the Company
The Company's oil and gas reserves are principally in
long-lived fields with well established production histories. The Company's net
Proved Reserves, estimated as of December 31, 1996 by applying S.E.C.
assumptions (PV 10%), consisted of approximately 8,964,200 Mcf of gas and
1,389,900 Bbls of oil, with an aggregate present value before income taxes, at a
10% discount, of $22,465,000. Recoverable volumes of gas increased 40.7% and
recoverable volumes of oil increased 78.7%, respectively, over 1995 volumes. The
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discounted present value of oil and gas reserves increased 115.8% over the 1995
amount of $10,410,553. Approximately 92% of the Company's discounted present
value of oil and gas reserves are located in Oklahoma (26%), Texas (14%),
Alabama (13%), New Mexico (12%), Kansas (11%), Arkansas (6%), Louisiana (5%) and
Mississippi (5%). A substantial portion of the Company's natural gas production
and Proved Reserves consist of high BTU gas which, because of its rich liquid
content and its proximity to processing and transmission facilities, is
generally sold at a premium to Gulf Coast and Mid-Continent spot market prices.
Substantially all of the Company's oil and gas production is sold at market
responsive prices.
Business Strategy. The Company's present business strategy is
to concentrate on expanding its asset base and cash flow primarily through
emphasis on the following activities:
- Increasing production, cash flow and asset value by
acquiring Producing Properties with stable production
rates, long reserve lives and potential for
exploitation and development;
- Building on the Company's existing base of operations
by concentrating its development activities in its
primary operating areas in the Gulf Coast Basin and
the Mid-continent;
- Acquiring additional properties with potential for
developmental drilling to maintain a significant
inventory of undeveloped Prospects and to enhance the
Company's foundation for future growth;
- Serving as operator of its wells to ensure technical
performance and reduce costs;
- Expanding its relationships with major and large
independent oil and gas companies to access their
undeveloped properties, seismic data and financial
resources;
- Managing financial risk and mitigating technical risk
by:
- drilling in known productive trends with
multi-horizon geologic potential;
- diversifying investment over a large number
of wells in the Company's primary operating
areas;
- developing properties that provide a balance
between short and long reserve lives; and
- keeping a balanced reserve profile between
oil and gas; and
- Maintaining low general and administrative expenses
and increasing economies of scale to reduce per unit
operating costs and reserve acquisition costs.
Acquisition Policy. The Company continues to pursue a program
of actively acquiring producing oil and gas properties, with the goal of
increasing cash flow, reserves and value for the long-term benefit of its
stockholders.
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The Company utilizes an acquisitions' screening approach with
its experienced management and technical staff which reviews potential property
against multiple criteria, both quantitative and subjective. The Company
generally seeks Producing Properties with established production histories. The
Company may operate the property acquired; however, the Company also considers
nonoperated property acquisitions.
In evaluating Producing Properties for potential acquisition,
production history, reservoir characteristics and available geologic data and
interpretations are analyzed to determine estimates of proved and other reserves
and cash flows expected to be recovered. Also evaluated are specific risks and
economic considerations associated with the property, including environmental
liabilities, risks of curtailment, condition of equipment and potential for
additional development opportunities. Sales contracts, operating agreements and
other contractual commitments, including take-or-pay clauses, market-out
clauses, gas balancing agreements, transportation agreements and reversionary
interests that may affect the cash flows from the property are also reviewed.
Drilling Activities. The Company has participated in drilling
operations in Texas, Mississippi, Louisiana, Oklahoma, New Mexico and Kansas.
For the nine months ended December 31, 1996, the Company participated in the
drilling of 49 Exploratory Wells through the Brigham Agreement. Forty wells were
drilled in Texas, seven in Oklahoma, one in Kansas and one in New Mexico. The
Company also participated in the drilling of four Developmental Well in the
Frymire Waterflood Unit in Nolan County, Texas, three were successful and one
was a dry hole. One successful developmental was drilled in the Campbell Field
in Major County, Oklahoma. In total, 35 wells were successfully drilled in 1996.
In 1995, the Company participated in the drilling of one Development Well in New
Mexico and one in Louisiana, both were unsuccessful. In 1994, the Company
participated in one Exploratory Well in Mississippi which was unsuccessful..
Drilling activities during 1996 added 76,492 Bbls of oil and 392,275 Mcf of
natural gas, respectively, with estimated future net revenues, discounted at
10%, of $1,966,000. In 1996, the finding cost was $10.16 per BOE. The Company
believes that there exists great potential for further acquisitions and
development opportunities in Kansas, Texas and other parts of the Gulf Coast;
and, with the Company's expertise in operations, it will be able to develop the
reserves to their ultimate potential.
The Company has a 65% working interest in the LL&E No. 1 well
in the Lake Decade Field, Terrebone Parish, Louisiana, which ceased producing
gas in December, 1996 and is expected to be plugged and abandoned in the first
quarter of 1997. The Company had successfully recompleted the well in 1995.
In 1995, the Company entered into a joint development
agreement with Chesapeake Operating, Inc. (COI). The agreement covers a 600 acre
block of leases in Lea County, New Mexico assembled by the Company and COI. The
prospect is believed to be a large Strawn algal mound that was initially
identified through 2-D seismic. The Company and COI will use 3-D seismic
technology to provide a more accurate and comprehensive interpretation of the
structure. COI has earned a 25% working interest in the Prospect. The Company is
continuing to evaluate the prospect and expects to begin drilling in the last
half of 1997.
In the foreseeable future, the Company's primary focus will be
its activities in Kansas. The Company expects to drill eight developmental wells
in the Spivey Field in Kansas in 1997. The Company also expects to drill a
Prospect in Tyler County, Texas in the first half of 1997, and expects to
participate in a 3-D seismic and drilling prospect in Kansas in 1997. In
addition, the Company is continually evaluating Prospects
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originated by its staff, other independent geologists or other oil and gas
companies. If review of a certain Prospect indicates that it may be geologically
and economically attractive, then the Company will attempt to obtain a Lease on
the applicable acreage or commit to a Working Interest in the drilling Prospect.
When the Company does participate in a Prospect, it will typically acquire a
fractional Working Interest in the Prospect, which may range from a small
percentage interest in more expensive exploratory Prospects to a majority
interest in certain lower cost or development Prospects. 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 1992 through 1996, acquisitions of reserves accounted for 47%, 64%, 5% ,
35% and 34% of the year-end discounted reserve value, respectively.
During fiscal years 1992 through 1996, the Company acquired
2,419,573, 3,661,789, 233,670, 2,340,487 and 3,139,299 Mcf of natural gas and
77,384, 492,552, 23,464, 397,855 and 503,156 Bbls of oil for $1,470,998,
$3,146,414, $280,000, $2,798,685 and $3,402,100, respectively. For the fiscal
years ended 1992 through 1996, proved property acquisitions amounted to 480,646,
1,102,850, 62,409, 787,936 and 1,026,373 BOE, respectively, at a cost of $3.06,
$2.85, $4.48, $3.55 and $3.31 per BOE, respectively. The Company has financed
its acquisitions primarily by utilizing its credit facility with the Bank of
Oklahoma and issuing common and preferred stock. (See "Company Financing,"
below.)
The Bison Merger in February, 1997 added approximately 607
thousand barrels of oil and 2,580 million cubic feet of gas to the Company's
proved reserves. A portion of the reserves consists of proved behind pipe and
proved undeveloped reserves. The Bison Merger has a discounted value of
approximately $10.0 million, according to the Company's evaluation.
The Company is currently in the process of evaluating various
corporate acquisitions and potential mergers in exchange for common stock of the
Company. Management believes that corporate acquisitions and mergers are the
fastest way to achieve the Company's growth goals. In addition to achieving what
management perceives to be a proper critical mass, potential corporate
acquisitions or mergers are also considered as opportunities to acquire a more
diverse oil and gas interest. There are no agreements, preliminary or otherwise,
pending or presently expected between the Company and any acquisition or merger
candidate.
Company Financing. The Company has financed its prior
acquisitions primarily through the Bank of Oklahoma and currently has
approximately $5.2 million borrowed on the $6.0 million revolving line of credit
described under "Business Development," above. In 1996, the Company used $1.0
million in preferred stock through its $10.0 million Preferred Stock Agreement
to finance a portion of the NPC Merger.
The Company also used its common stock to finance a significant portion of the
NPC merger in 1996 and for an asset acquisition in 1993. The Company's drilling
activities have been financed primarily through the Company's cash flow.
The Bank has stated that it will continue to consider
debt-financed acquisitions presented to it by the Company. The Company intends
to finance acquisitions by issuing common stock and preferred stock when
possible.
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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 fierce competition.
The ability of the Company to market oil and gas from its
wells will depend upon numerous factors beyond its control, including, but not
limited to, the extent of domestic production and imports of oil and gas, the
proximity of the Company's production to existing pipelines, the availability of
capacity in such pipelines and state and federal regulation of oil and gas
production. There is no assurance that the Company will be able to market all of
the oil or gas produced by it or that favorable prices can be obtained for the
oil and gas it produces. In view of the uncertainties affecting the supply and
demand of oil and gas, the Company is unable to accurately predict the future
oil and gas prices and demand or the overall effect they will have on the
Company.
The Company's operations are affected by numerous federal and
state laws and regulations. In particular, oil and gas production operations are
affected by tax and other laws relating to the petroleum industry and changes in
such laws and regulations. Some of the rules and regulations carry substantial
penalties for failure to comply. The regulatory burden on the oil and gas
industry increases the Company's cost of doing business. The Company's
activities are also subject to numerous federal, state and local environmental
laws and regulations governing the discharge of materials. In most cases, the
applicable regulatory requirements relate to water and air pollution control or
solid waste management measures. The Company believes the recent trend toward
stricter standards in environmental legislation, regulation and enforcement will
continue. To date, these laws have not had a significant impact on the Company
but no assurance can be given as to the effect of these laws on the Company in
the future.
Employees. At December 31, 1996, the Company employed eight
full-time people in its Mobile, Alabama office, including four executive
officers, whose functions were associated with management, engineering, geology,
land and legal, accounting, financial planning and administration. The Company
also employs one full-time supervisor for well operations in Oklahoma.
As a result of the Bison Merger, C.J. Lett, III, former
president and sole shareholder of Bison, has agreed to continue as President and
a director of Bison. Mr. Lett will also serve as Executive Vice President of the
Company and will be nominated for election as a director of the Company at the
next Annual Meeting. The Company will maintain Bison's headquarters in Wichita,
Kansas and its field offices in Cushing, Oklahoma and Attica, Kansas, and will
employ two professional personnel, in addition to Mr. Lett, at Bison's
headquarters.
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ITEM 2. DESCRIPTION OF PROPERTY
(a) Real Estate Properties
The Company owns an historic home in Mobile, Alabama which
serves as its corporate office. In April, 1994, the Company sold for $125,000
the undeveloped real estate in McIntosh purchased in 1993. In June, 1996, the
Company sold for $75,000 the Bayou Coden property purchased in May, 1994.
(b) Oil and Gas Properties
All of the Company's oil and gas properties, reserves and
activities are located onshore in the continental United States, primarily in
Oklahoma, Texas, Alabama, New Mexico and Kansas. 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 following table shows proved oil and gas reserves by major
field for the Company's largest producing fields at December 31, 1996. The
values represent the present value of estimated future net cash flows before
income taxes, discounted at 10%, assuming unescalated expenses and prices of
$24.50/Bbl and $3.70/MMBtu attributable to proved reserves at December 31, 1996,
as determined by Lee Keeling & Associates and Cawley, Gillespie & Associates.
<TABLE>
<CAPTION>
Discounted Percentage Oil Gas
Field Name/ Primary Present of Total Reserves Reserves
City/State Operator Value Reserves (Bbls) (Mcf)
---------- -------- ----- -------- ------ -----
(Dollars/quantities in thousands)
<S> <C> <C> <C> <C> <C>
Spivey Bison $ 2,379 10.6% 218 1,757
Harper/Kingman, KS
Hatters Pond Texaco 1,610 7.2% 82 217
Mobile, AL
Magnolia Lime Arco 1,302 5.8% 189 263
Columbia, AR
Orlando Berry & Co. 890 3.9% 49 234
Noble, OK
Okeene NW Tidewest 801 3.5% 18 626
Major, OK Ricks Expl.
Lake Trammel W. Northland 756 3.4% 69 11
Noland, TX
</TABLE>
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<TABLE>
<S> <C> <C> <C> <C> <C>
Chunchula Unocal 691 3.1% 38 275
Mobile, AL
Polo Lu-Ray Ptrl. 665 2.9% 129 5
Noble, OK
Powell Kerr-McGee 620 2.7% 10 340
Converse, WY
Bismarck "26" ANR 509 2.2% - 146
Presque Isle, MI
Custer City N. Toklan 499 2.2% - 348
Custer, OK
Convis "8-A" Lomak 467 2.1% 36 5
Custer, OK
Pistol Ridge Company 463 2.1% 1 209
Pearl River, MS
Wildfork Creek Desoto 444 1.9% 56 -
Escambia, AL
Foster "248" #1 Louis Dreyfus 440 1.9% - 152
Canadian, OK
Lake Pagie Company 429 1.9% - 144
Terrebone, LA
Wright Hilcorp 421 1.9% 63 55
Vermillion, LA
Laguna Valley R&S 389 1.7% - 262
Lea, NM
Tulk Coastal 381 1.7% 39 183
Lea, NM
Logan S. Devon Energy 379 1.7% 24 135
Beaver, OK
Cherokee SW Bison 345 1.5% - 300
Alfalfa, OK
N.E. Lovington Amerind Oil, 325 1.4% 23 78
Lea, NM Apache
</TABLE>
I - 9
<PAGE> 13
<TABLE>
<S> <C> <C> <C> <C> <C>
Campbell Petro Energy 255 1.1% 2 170
Major, OK
Oakdale Bison 239 1.1% - 273
Woods, OK
Other 6,765 30.7% 343 2,776
-------- ----- ----- -----
Total $ 22,464 100.0% 1,389 8,964
======== ===== ===== =====
</TABLE>
The Bank of Oklahoma has a first mortgage on all of the fields listed in the
above table, except for Pistol Ridge and Foster "248". The Bank also has a first
mortgage on numerous additional fields not individually listed above which in
total gives the Bank a first mortgage on approximately 75% of the Company's
total reserves (PV10%) of $22,464,000 before income tax. The Company is
obligated, within five days of request by the Bank, to grant the Bank a first
and prior mortgage on any oil and gas properties owned or acquired by the
Company.
(c) Productive Wells and Acreage
The following table depicts the number of gross and net
producing wells and related Developed and Undeveloped Acreage in which the
Company owned an interest for the period ended December 31, 1996. 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.
The Company's net Developed Acreage is located primarily in
Oklahoma, Texas, Alabama, New Mexico and Kansas. The Company's net Undeveloped
Acreage is located in Kansas.
<TABLE>
<CAPTION>
Acreage
----------------------------
Developed Undeveloped
--------- -----------
<S> <C> <C>
Gross Acres 198,545 320
Net Acres 11,552 240
<CAPTION>
Productive Wells
----------------------------
Oil Gas
--- ---
<S> <C> <C>
Gross Wells 721.00 76.00
Net Wells 145.70 35.44
</TABLE>
Excluded from the acreage data are approximately 1,720 net (18,543 gross)
mineral acres owned by the Company, all of which are considered to have
potential for oil and gas exploration.
I - 10
<PAGE> 14
(d) Production, Prices and Costs
Below is a summary of the net production of oil and gas,
average sales prices and average production costs during each of the last three
fiscal years. The Company is not obligated to provide a fixed and determined
quantity of oil and gas in the future under existing contracts or agreements.
During the last three fiscal years, the Company has not had, nor does it now
have, any long-term supply or similar agreements with governments or
authorities.
<TABLE>
<CAPTION>
Fiscal Years Ended December 31,
1994 1995 1996
---- ---- ----
<S> <C> <C> <C>
Crude Oil and Natural Gas Production:
Oil (Bbls) 71,350 107,025 108,626
Gas (Mcf) 733,010 916,954 982,709
Average Sales Prices:
Oil (per Bbl) 14.74 16.17 20.26
Gas (per Mcf) 1.76 1.51 2.28
Average Production Costs Per BOE(1) $ 4.31 $ 5.25 $ 5.36
</TABLE>
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.
(e) Drilling Activities
During the periods indicated, the Company drilled or
participated in the drilling of the following productive and nonproductive
Exploratory and Development Wells. All of the Company's drilling and production
activities are conducted with independent contractors.
<TABLE>
<CAPTION>
Year Ended December 31,
Exploratory Wells: 1994 1995 1996
--------- --------- ---------
<S> <C> <C> <C>
Productive
Gross 0 0 31
Net 0 0 0.987
Dry
Gross 1 0 18
Net 0.1544 0 0.675
Development Wells:
Productive
Gross 0 0 4
Net 0 0 0.866
Dry
Gross 0 2 1
Net 0 0.418 0.250
</TABLE>
I - 11
<PAGE> 15
<TABLE>
<CAPTION>
<S> <C> <C> <C>
Total Wells:
Productive
Gross 0 0 35
Net 0 0 1.853
Dry
Gross 1 2 19
Net 0.154 0.418 0.925
</TABLE>
As of March 15, 1997, the Company is drilling three exploratory wells and one
developmental well.
(f) Reserves
Note 11 to the Company's financial statements presents, among
other disclosures prepared pursuant to Statement of Financial Accounting
Standards No. 69, the estimated net quantities of the Company's proved oil and
gas reserves and the standardized measure of discounted future net cash flows
attributable to such reserves as of December 31, 1996. At December 31, 1996, the
Company's net Proved Reserves consisted of 1,389,900 Bbls of oil and 8,964,200
Mcf of gas and net Proved Developed Reserves consisted of 1,266,400 Bbls of oil
and 8,142,800 Mcf of gas. At December 31, 1996, the present value discounted at
10% for the Company's Proved oil and gas reserves, before income taxes, was
approximately $22,464,000. (See Note 11 to the Company's financial statements
for additional detail on the Company's oil and gas reserves.) Management of the
Company, however, cautions against using this data to determine the fair value
of the Company's oil and gas properties or for any other purpose because the
price of oil and gas can be volatile. The present value was computed using
December 31, 1996 base oil prices of $24.50 per Bbl and base gas prices of $3.70
per MMBtu. Base prices were adjusted for certain properties that either received
a price above or below the base price. There were no estimates or reserve
reports of the Company's proved oil and gas reserves filed with any governmental
authority or agency during the year ended December 31, 1996.
The following table sets forth the standardized measure (in
thousands of dollars) of future net cash flows, before income taxes, of Proved
and Probable Reserves and total recoverable volumes of oil and gas attributable
to the Company's interest in oil and gas wells for the years ended December 31,
1996 through 1994:
<TABLE>
<CAPTION>
Recoverable Volumes
-------------------
Standardized Oil Gas
Year Ended Measure (MBbls) (MMcf)
---------- ------- ------- ------
<S> <C> <C> <C>
December 31, 1996 $22,464 1,389 8,964
December 31, 1995 $10,411 778 6,371
December 31, 1994 $6,635 571 4,772
</TABLE>
The increases in the standardized measure from 1994 to 1995 and 1995 to 1996 are
due primarily to the P&P Acquisition and the NPC Merger, respectively. The only
Probable Reserves are in 1994 and amounted to
I - 12
<PAGE> 16
$221,000 and 29 MBbls. For a detail of changes in oil and gas reserves for the
year, refer to Note 11 to the Company's financial statements.
ITEM 3. LEGAL PROCEEDINGS
The Company is a defendant in various legal proceedings which are
considered routine litigation incidental to the Company's business, the
disposition of which management believes will not have a material effect on the
financial position or result of operations of the Company.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders of the
Company during the fourth quarter of the fiscal year ended December 31, 1996.
[The remainder of this page has been intentionally left blank]
I - 13
<PAGE> 17
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 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>
1995
Third Quarter $3.63 $3.63
Fourth Quarter 3.75 2.75
1996
First Quarter $3.38 $2.75
Second Quarter 3.38 2.75
Third Quarter 3.25 2.50
Fourth Quarter 6.00 3.00
</TABLE>
On March 15, 1997, the closing price of the common stock was $7.50 bid and $8.00
asked.
There are 125,000 outstanding options issued to officers and
directors to purchase shares of the Company's common stock at a price of $2.50.
222,296 and 562,000 of the Company's outstanding shares of common stock are
considered "restricted shares," as that term is defined under Rule 144 of the
Securities Act. Of these total shares, 222,296 were eligible for resale under
Rule 144 under the Securities Act after December 31, 1996, and 562,000 will be
eligible after December 31, 1998.
In general, Rule 144 allows a shareholder who has beneficially
owned shares for at least two years (or an affiliate of the Company who owns
unrestricted shares of common stock, no matter when acquired) to sell within any
three-month period a number of shares that does not exceed the greater of one
percent of the then-outstanding shares of the Company's common stock
(approximately 18,591 shares) or the average weekly trading volume in the
over-the-counter market during the four calendar weeks preceding the date on
which notice of the sale is filed with the Securities and Exchange Commission.
Sales under Rule 144 are also subject to certain manner of sale provisions and
notice requirements and to the availability of current public information about
the Company. A shareholder who is deemed not to have been an "affiliate" of the
Company for at least 90 days and who has beneficially owned his restricted
shares for at least three years would be entitled to sell such shares under Rule
144(k) without regard to the other requirements described above.
II - 1
<PAGE> 18
(b) Holders
As of February 28, 1997, the Company had 789 holders of record
of its common stock which does not include an unknown number of additional
holders whose stock is held in "street name".
(c) Dividends; Dividend Policy
The Company has never paid any dividends on its common stock.
The terms of the Company's credit facility with the Bank of
Oklahoma prohibit the Company from making distributions of any kind, type or
nature, cash or otherwise on its common stock. In any event, the Company expects
to retain all available earnings generated by its operations for the development
and growth of its business and does not anticipate paying any cash dividends in
the foreseeable future. Any future determination as to the payment of dividends
will be made at the discretion of the Board of Directors and will depend on a
number of factors, including the future earnings, capital requirements,
financial condition and future Prospects of the Company, restrictions in the
Company's current or future financing agreements (such as the Revolver) and any
other factors as the Board of Directors may deem relevant.
ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS
The following discussion should be read in conjunction with the
Company's financial statements and notes thereto set forth in Item 7.
(a) Results of Operations
The factors that most significantly affect the Company's
results of operations are (i) the sales price of crude oil and natural gas, (ii)
the level of production sales, (iii) the level of lease operating expenses, and
(iv) the level of interest rates. Sales of production and level of borrowing are
significantly impacted by the Company's ability to maintain or increase its
production from existing oil and gas properties or through its exploration and
development activities. Sales prices received by the Company for oil and gas
have fluctuated significantly from period to period. The fluctuations in oil
prices during these periods reflect market uncertainty regarding the inability
of OPEC to control the production of its member countries, the timing of Iraq's
reentry into OPEC, 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. Gas prices have generally increased in
recent years due to increased demand; and in January 1996 and January 1997, gas
prices reached recent highs. However, in late 1994, gas prices reached recent
lows. Relatively modest changes in either oil or gas prices significantly impact
the Company's results of operations and cash flow and could significantly impact
the Company's borrowing capacity.
The table below details the changes in oil and gas revenues
caused by price and volume changes for the years ending December 31, 1994, 1995
and 1996.
II - 2
<PAGE> 19
<TABLE>
<CAPTION>
1996 1995 1994
---- ---- ----
<S> <C> <C> <C>
Oil Revenues
Change due to volume $ 32,436 $576,865 $352,875
Change due to price 437,285 102,558 ( 27,433)
Total change 469,721 679,423 325,442
Gas Revenues
Change due to volume $149,921 $277,755 $275,563
Change due to price 708,386 (182,391) (265,018)
Total change 858,307 95,364 10,545
</TABLE>
(b) Fiscal 1996
Total revenues for the twelve months ended December 31, 1996,
of $4,886,421, were $1,347,775 higher than the same period in 1995. The increase
in total revenues was due primarily to higher oil and gas revenues of
$1,236,506, consisting primarily of a $469,721 increase in oil revenues and a
$858,307 increase in gas revenues. Total revenues also increased due to higher
other income of $199,004, due primarily to a gas contract settlement of
$263,000. The increase in oil and gas revenues from 1996 to 1995 was primarily
the result of higher oil and gas prices. Production of oil and gas for the
twelve months ended December 31, 1996, increased 1% and 7%, respectively, over
the comparable 1995 period. During the twelve-month period ended December 31,
1996, the Company sold 108,626 barrels of oil and 982,709 Mcf of gas, as
compared to 107,025 barrels of oil and 916,954 Mcf of gas for the comparable
1995 period. Oil production for 1996 was 1,601 barrels higher due to a 4,273
barrel increase from the successful wells in the Brigham Agreement, a 533 barrel
increase in existing properties, and a decrease of 3,205 barrels from properties
sold in 1996. Gas production in 1996 was 65,755 Mcf higher due to a 24,487 Mcf
increase from the successful wells in the Brigham Agreement and a 77,952 Mcf
increase in existing properties offset by a decrease of 36,684 Mcf from
properties sold in 1996. The price received on the gas sold in 1996 of $2.28 per
Mcf was higher than the $1.51 per Mcf received in the comparable 1995 period.
Oil prices in 1996 of $20.26 per barrel were higher than the $16.17 per barrel
received in 1995.
The increase in total revenues of $1,347,775 was more than the
increase in total expenses of $646,198. Increases in dry-hole costs and
depreciation and depletion expense accounted for approximately 91% of the total
expense increase.
Lease operating expenses of $1,516,011 increased by $79,142 as
a result of higher expenses on existing properties of $137,987 and expenses on
successful wells in the Brigham Agreement of $4,342 offset by reductions due to
properties sold in 1996 of $63,186. Interest expense of $504,945 decreased by
$15,474 due to lower interest rates and payments on principal in 1996. Dry-hole
expense increased by $345,490 due primarily to abandonment costs of $421,003
associated with the unsuccessful wells drilled in the Brigham Agreement.
Depletion expense of $1,397,015 increased by $255,815. Regular depletion of
$1,119,532 increased by $134,403 due primarily to higher depletion on existing
properties. Write-offs of proven properties in accordance with SFAS #121 of
$277,483 increased by $121,412. Of the total writedown, 75% is from three single
well fields in Louisiana. One of the fields was the Lake Decade field which was
a major property in 1995. It contributed $91,000 to cash flow in 1996 before it
ceased producing in December 1996, resulting in
II - 3
<PAGE> 20
an impairment expense of $59,000. The other two fields, which produced very
little in 1996, were minor properties contributing less than $20,000 to cash
flow in 1995, and producing impairment losses of $95,000 and $55,000. The
remaining impairment expense resulted from several properties, none of which
were significant properties in terms of discounted present value and were
primarily mature, small properties that did not contribute significantly to the
Company's cash flow in 1996 and 1995. Depreciation expense of $59,788 decreased
$14,882 due to lower depreciation on lease and well equipment and corporate
office furniture and fixtures which are depreciated on an accelerated method
which declines over the useful life of the asset. General and administrative
expenses decreased by $3,894, due primarily to the Company's lower 1996 SEP/IRA
and 1% NPI contributions of $11,916 compared to the $60,000 in contributions in
1995, and to lower accounting expenses of $14,000 and lower miscellaneous
expenses of $18,000 which were partially offset by higher travel and
entertainment expenses of $47,000 and higher legal expenses of $12,000.
The Company reported an operating profit of $280,371 for the
twelve month period ended December 31, 1996 as compared to an operating loss of
$421,206 in 1995. If the 1996 nonrecurring credits of $303,000 consisting of the
gas contract settlement of $263,00 and lease operating expense credit of
$40,000, were offset against the 1995 nonrecurring expenses of $62,000, the
operating loss would have decreased by $336,577.
The Company reported net income of $205,500 for the year ended
December 31, 1996, versus a net loss of $331,053 for the comparable 1995 period.
(c) Fiscal 1995
Total revenues for the twelve months ended December 31, 1995,
of $3,538,646 were $911,686 higher than the same period in 1994. The increase in
total revenues was due primarily to higher oil and gas revenues of $844,498,
consisting primarily of a $679,423 increase in oil revenues and a $95,364
increase in gas revenues. Total revenues also increased due to higher gain on
sale of properties of $113,417 as a result of property sales in June and
December of 1995. The increase in oil and gas revenues from 1995 to 1994 was
primarily the result of the Company's increased oil and gas asset base and
consequent increase in production. Production of oil and gas for the twelve
months ended December 31, 1995, increased 50% and 25%, respectively, over the
comparable 1994 period. The asset base increased as a result of the P&P
Acquisition. It closed February 23, 1995, with an effective date of March 1,
1994, and resulted in increased oil revenues of $748,476 and increased gas
revenues of $428,932 over the comparable 1994 period. During the twelve-month
period ended December 31, 1995, the Company sold 107,025 barrels of oil and
916,954 Mcf of gas, as compared to 71,350 barrels and 733,010 Mcf for the
comparable 1994 period. Sales of gas in the second and third quarters were
approximately 17,100 Mcf and $35,000 lower than normal due to curtailed
production in the Bismarck field, a major gas property of the Company. The
production was back to normal in the fourth quarter. Sales of oil in the third
quarter were approximately 2,000 barrels and $30,700 lower than normal due to
the shut-in from repairs of a major oil property acquired in the P&P
Acquisition. The production was back to normal in the last half of the fourth
quarter. Oil production for 1995 was 35,675 barrels higher due to a 45,650
barrel increase from the P&P Acquisition made in 1995, offset by a decrease of
916 barrels from existing production and a decrease of 9,059 barrels from
properties sold in 1995. Gas production in 1995 was 183,944 Mcf higher due to a
287,547 Mcf increase from the P&P Acquisition made in 1995, offset by a decrease
in production on existing properties of 1,223 Mcf, and a decrease of 102,380 Mcf
from properties
II - 4
<PAGE> 21
sold in 1995. The price received on the gas sold in 1995 of $1.51 per Mcf was
lower than the $1.76 per Mcf received in the comparable 1994 period. Oil prices
in 1995, of $16.17 per barrel, were higher than the $14.74 per barrel received
in 1994.
The increase in total revenues of $911,686 was more than the
increase in total expenses of $842,472. Increases in lease operating expenses
and interest expense accounted for approximately 89% of the total expense
increase.
Lease operating expenses of $1,436,869 increased by $522,844
as a result of expenses on acquired properties of approximately $656,003, higher
expenses on existing properties of $44,511 and reductions due to properties sold
in 1995 of $177,670. Lease operating expenses on acquired properties included a
$16,000 charge for an oil spill and related clean-up. Interest expense of
$520,419 increased by $223,557 in 1995 due to additional advances on the term
note used to acquire proven properties, and due to higher interest rates in
1995. The prime rate increased 2.50% from January 1994 to January 1995, but fell
by 0.50% in the second half of 1995. Dry-hole expense of $83,107 increased by
$64,582 due to a dry-hole drilled in December, 1995, in Louisiana. Depletion
expense of $1,141,200 increased by $72,628. Regular depletion of $985,129
increased by $165,252 due to additional depletion on the acquired properties.
Write-offs of proven properties in accordance with SFAS #121 of $156,071
decreased by $92,624. Of the properties that received writedowns in 1995, none
were significant properties in terms of discounted present value and were
primarily mature, small properties that had not contributed significantly to the
Company's cash flow in 1995 and 1994. Depreciation expense of $74,670 decreased
$11,530 due to lower depreciation on lease and well equipment and corporate
office furniture and fixtures which are depreciated on an accelerated method
which declines over the useful life of the asset. General and administrative
expenses increased by $24,509, due primarily to the Company's SEP/IRA
contribution of $30,000 made in April, and the 1% NPI Bonus Plan payment of
$30,000 in December, offset partially by lower legal and accounting expenses of
$53,000 and lower land work expenses of $20,000.
The Company reported an operating loss of $421,206 for the
twelve month period ended December 31, 1995, which was a decrease of $69,214 in
the operating loss of $490,420 in 1994. Excluding the gain on sale of properties
of $125,550 in 1995 and $12,133 in 1994, the operating loss for the year ended
December 31, 1995 would have increased $44,203 over the comparable period in
1994. The 1995 non-recurring expenses totaling $62,000 were principally offset
by the lawsuit settlement expense of $54,119 in 1994.
The Company reported a net loss of $331,053 for the year ended
December 31, 1995 versus a net loss of $457,434 for the comparable 1994 period.
(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.
II - 5
<PAGE> 22
The Company's principal source of cash flow is the production
and sale of its crude oil and natural gas reserves which are depleting assets.
Cash flow from oil and gas production sales depends upon the quantity of
production and the price obtained for that production. An increase in prices
permits the Company to finance its operations to a greater extent with
internally-generated funds, allow the Company to obtain equity financing more
easily and lessens the difficulty of attracting financing alternatives available
to the Company from industry partners and nonindustry investors. However, price
increases heighten the competition for Leases and Prospects, increase the costs
of exploration and development activities and increase the risks associated with
the purchase of Producing Properties.
A decline in oil and gas prices (i) reduces the cash flow
internally generated by the Company, which in turn reduces the funds available
for servicing debt and exploring for and replacing oil and gas reserves, (ii)
increases the difficulty of obtaining equity financing, (iii) reduces the number
of Leases and Prospects available to the Company on reasonable economic terms
and (iv) increases the difficulty of attracting financing alternatives available
to the Company from industry partners and nonindustry investors. However, price
declines reduce the competition for Leases and Prospects and correspondingly
reduce the prices paid for Leases and Prospects. Furthermore, exploration and
production costs generally decline, although the decline may not be at the same
rate of decline of oil and gas prices.
(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
over the near future due to the decrease in drilling activity in the United
States. Unless increasing oil and gas prices spur large increases in industry
activities, management believes costs will remain relatively stable over the
next year.
(g) Capital Resources and Liquidity -- Fiscal 1996 and Fiscal 1995
Cash flow from operations before working capital changes of
$1,699,672 increased $1,025,165 over the comparable 1995 period. This increase
was due a to $1,158,000 increase in oil and gas cash flow, an increase of
$199,000 in other income and decreases in interest expense of $15,000 and
general and administrative expenses of $3,000, offset by a $345,000 increase in
dry-hole costs and a $5,000 increase in current income taxes.. Increased oil and
gas operations cash flow before working capital was principally the result of
increases in oil and gas prices. The other income increase was due to the
receipt of $263,000 from settlement of a gas contract
II - 6
<PAGE> 23
Cash flow from operating activities for the twelve months
ending December 31, 1996, of $1,389,376 increased $951,798 over the comparable
1995 period. Changes in working capital reduced cash flow by $73,367 over the
comparable 1995 period. Differences in the amount and timing of accrual and
payment of payables and the accrual and receipt of revenues account for the
changes in working capital.
Additions to oil and gas properties and equipment purchases
were lower than the comparable period in 1995 due to less amounts of cash being
spent on acquisitions in 1996. The decrease in proceeds from debt issued was due
only to an advance for drilling in 1996 as compared to the refinancing of the
$3.8 million term note and the financing of the P&P Acquisition in the prior
year. The decrease in the amount of cash used for debt payments was due
principally to the interest only payments on the Revolver since April 1, 1996,
compared to the payoff of the remaining principal balance of $2.5 million on the
$3.8 million Term Note in the prior year.
The Company's operating activities provided net cash of
$1,389,376 for the twelve-month period ending December 31, 1996. Sales of minor
oil and gas properties in March and June provided cash of $40,000 and sale of
real estate in June provided cash of $75,000. During this period, cash from
operations, cash from property sales and cash on hand were used to acquire
$24,000 of proved properties; $241,000 was spent on workovers, $1,332,000 was
spent on exploratory and developmental drilling and $651,000 was spent on the
NPC Merger. Of the $1,332,000 spent on drilling, $1,032,000 was through the
Brigham Agreement and included completed wells and wells in process. The Company
incurred an additional $421,000 in dry-hole costs attributable to wells drilled
through the Brigham Agreement. The majority of the remaining drilling funds was
spent on developmental wells in the Lake Trammel Field, recompletion of wells in
the Lea Field, Lake Pagie Field and Pistol Ridge Field, and a developmental well
drilled in the Campbell Field. Of the $241,000 spent on workovers, the majority
was spent on work in the Tulk Field, Bismarck Field, Wild Fork Creek Field and
Pistol Ridge Field. In the NPC Merger the total acquisition price was
$3,251,728. Common stock valued at $1,967,000 and cash of $1,284,728 was used to
finance the merger. The Company acquired $633,712 of cash in the NPC Merger, so
the net cash paid was $651,016. Also included in the purchase price was the
assumption of $385,089 in debt of NPC.
Amounts spent on debt retirement represent three months of
principal payments on the $5.6 million Term Note. The principal payments on the
$5.6 million Term Note were suspended when the Company converted the Term Note
to the Revolver on April 1, 1996.
The Company had current assets of $1,743,580 and current
liabilities of $957,397, which resulted in working capital of $786,183 at
December 31, 1996. This was an increase of $1,206,897 from the working capital
deficit of $420,714 at December 31, 1995. Working capital increased primarily
due to increased cash flow from oil and gas production, cash proceeds from
preferred stock sales, a gas contract settlement and no monthly principal
payments on the Revolver, offset partially by increased amounts spent on
exploratory and developmental drilling. The current maturity of long-term debt
in 1996 was lower than in 1995, due mainly to the Revolver requiring only
interest payments through September 30, 1997. The Company's current ratio of
4.25, calculated under the terms of the Revolver which excludes stockholder
receivables and debt due under the Revolver, is in excess of the 0.90 to 1.00
required.
II - 7
<PAGE> 24
In general, because natural gas and oil reserves are depleted
by production, the Company's success is dependent upon the results of its
acquisition, development and exploration activities. The Company's strategy is
to acquire and develop proved producing and proved undeveloped properties,
enhance and exploit its existing properties for reserves and to invest in a
limited amount of exploratory and developmental drilling projects. The Company
expects to incur a minimum of $1,200,000 in capital expenditures over the next
twelve months to drill eight developmental wells in the Spivey Field in Kansas
and a minimum of an additional $500,000 to invest in other exploratory and
developmental projects. The Company expects to fund its proved property
acquisitions through the sale of Common Stock and Convertible Preferred Stock
and also through debt-financing with the Bank of Oklahoma. The developmental and
exploratory drilling projects will be funded by internally-generated cash flows.
In connection with the issuance of 142,107 shares of common
stock in the Janex Acquisition, the Company has a contingent obligation to
repurchase the shares, upon written notice delivered to the Company, beginning
five years after the closing date and continuing for thirty days thereafter, at
a price of $6.00 per share. This contingent obligation shall terminate if the
Company's stock trades at an ask price of $8.00 or greater for 20 consecutive
days during the 36 month period immediately preceding the first day of the fifth
year after the closing date (such prices being adjusted for the one-for-two
reverse split). The closing date of the Janex Acquisition was November 1, 1993.
If the trading market for the Company's stock does not meet the trading limits
stated above over the three-year period beginning November 1, 1995 through
October 31, 1998, the Company would have to redeem the shares of stock from the
original owners upon written request at $6.00 per share beginning November 1,
1998 and ending November 30, 1998. As of December 31, 1996, the Company's Common
Stock had not met the trading limits. However, during the year, 71,910 shares of
Company Common Stock subject to the repurchase obligation were sold. The Company
is unable to determine at this time if it will have to redeem the remaining
shares. Depending on the number of shares the Company may have to redeem, the
redemption will be financed through internal cash flow or by debt financing. The
redemption, if any, is not expected to have a material adverse effect on the
operations of the Company. If the Company has to redeem the entire amount
through internal cash flow, the redemption could have an adverse effect on the
financial position of the Company.
In conjunction with the Brigham Agreement, effective April 1,
1996, the Bank converted the existing term loan into the $6.0 million, one-year,
revolving line-of-credit described under "Business Development." The Revolver
requires monthly payments of interest only at prime plus 1.5% and converts into
a term note on March 31, 1997. The term note matures on March 31, 2003 and is
payable in 72 equal monthly principal and interest payments at prime plus 1.5%.
On October 8, 1996, the Revolver was amended to change the maturity date and
conversion date to September 30, 1997. The term note under the amendment matures
September 30, 2003 and is payable in 72 equal monthly principal and interest
payments at prime plus 1.5%.
The principal balance of the Revolver at December 31, 1996 was $5,186,596.
On September 4, 1996, the Company signed a Preferred Stock
Agreement with Kaiser-Francis Oil Co. The Preferred Stock Agreement provides for
the purchase of 1,666,667 shares of Preferred by Kaiser- Francis over a
five-year period, beginning September 4, 1996, with minimum incremental
investments of $500,000 each. Each issuance is subject to approval by
Kaiser-Francis of the use of proceeds. The Preferred is nonvoting and accrues
dividends at 8% per annum, payable quarterly in cash. On December 31, 1996,
II - 8
<PAGE> 25
166,667 shares of Preferred was issued under the Preferred Stock Agreement to
fund a portion of the NPC Energy Corp. acquisition. No other Preferred stock was
issued in 1996.
The estimated drilling budget for the period January 1, 1997
to March 31, 1997 under the Brigham Agreement is $899,440. The actual advances
to Brigham for the three-month period ended March 31, 1997 amounted to $230,520.
The Company drilled a successful developmental well in Harper
County, Kansas, in the Spivey Field, in January, 1997, for an estimated cost to
the Company of $83,000. The Company successfully recompleted the A.J. Danner
well in March, 1997, at an estimated total cost to the Company of $85,000. As of
March 15, 1997, the Company had approved expenditures for developmental work in
the Lake Trammel Field, one developmental well in the Spivey Field and an
exploratory well Prospect in Tyler County, Texas for estimated total costs to
the Company of $110,000, $80,000 and $41,000, respectively.
The Company's liquidity position and current and anticipated
cash flows from operations remain adequate for its general requirements.
However, because future cash flows and the availability of financing are subject
to a number of variables, such as the level of production and prices received
for gas and oil, there can be no assurance that the Company's capital resources
will be sufficient to maintain planned levels of capital expenditures.
(h) Capital Expenditures -- Fiscal 1996 and Fiscal 1995
Total capital expenditures for oil and gas properties in
fiscal 1996 and 1995 were $4,214,982 and $3,266,267, respectively. The majority
of the expenditures was for proved property acquisitions.
On December 31, 1996 the Company closed the NPC Merger. The
total acquisition price was $3,251,728, which was financed by $1,967,000 in
common stock and the remainder in cash.
On February 23, 1995, the Company closed the P&P Acquisition.
The acquisition price was $3,885,000, subject to certain adjustments, with an
effective date of March 1, 1994. The Company received approximately $1,300,00 of
net oil and gas revenues from March 1, 1994 to closing and incurred other costs
related to the acquisition, resulting in a net cost for the P&P Acquisition of
$2,798,000. The acquisition was financed entirely through the Company's credit
facility with the Bank of Oklahoma.
During 1996, the Company advanced $1,452,980 in drilling and
completion costs through the Brigham Agreement. Of the total advanced,
$1,142,090 was spent on successful and unsuccessful wells and $310,890 was spent
on wells in process at December 31, 1996.
Excluding the commitments through the Brigham Agreement, the
timing of most of the Company's capital expenditures is discretionary because
the Company has no material long-term commitments. The Company's funding
obligations through the Brigham Agreement will terminate on March 31, 1997. The
level of the Company's capital expenditures will vary in future periods,
depending on energy market conditions and other related economic factors. The
Company anticipates that its cash flow from operations will be adequate to fund
the drilling of eight developmental wells in the Spivey Field in Kansas
estimated at $1,200,000
II - 9
<PAGE> 26
and a minimum of $500,000 in additional expenditures for exploratory and
developmental drilling. As of March 15, 1997, the Company has $3,000,000
available through its Convertible Preferred Stock Purchase Agreement with
Kaiser-Francis and $800,000 available through its $6.0 million Revolver. The
Company expects to use the funds available from the Preferred Stock and Revolver
to finance proved property acquisitions. Whenever possible, the Company will use
funds from the sale of Common Stock to finance acquisitions and drilling
projects.
The Company's liquidity position and current and anticipated
cash flows from operations are expected to remain adequate for its general
requirements over the next twelve months.
ITEM 7. FINANCIAL STATEMENTS
The Company's financial statements for the years ended December 31,
1996 and 1995 and the report of Schultz, Watkins & Company, independent
accountants, thereon are included in this Item 7.
[The remainder of this page has been intentionally left blank]
II - 10
<PAGE> 27
MIDDLE BAY OIL COMPANY, INC.
AUDITED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1996 AND 1995
SCHULTZ, WATKINS & COMPANY
CERTIFIED PUBLIC ACCOUNTANTS
JACKSON, MISSISSIPPI
<PAGE> 28
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
No.
----
<S> <C>
Independent Auditor's Report. . . . . . . . . . . . . . . . . . . . 1
Balance Sheets. . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Statements of Operations. . . . . . . . . . . . . . . . . . . . . . 3
Statements of Changes in Stockholders' Equity . . . . . . . . . . . 4
Statements of Cash Flows. . . . . . . . . . . . . . . . . . . . . . 5
Notes to Financial Statements. . . . . . . . . . . . . . . . . . . 6
</TABLE>
<PAGE> 29
[SCHULTZ, WATKINS & COMPANY LETTERHEAD]
Independent Auditor's Report
Board of Directors and Stockholders
Middle Bay Oil Company, Inc.
We have audited the accompanying balance sheets of Middle Bay Oil
Company, Inc. as of December 31, 1996 and 1995, and the related statements of
operations, changes in stockholders' equity and cash flows for the years then
ended. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We have conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of Middle Bay Oil
Company, Inc. at December 31, 1996 and 1995, and the results of its operations
and its cash flows for the years then ended in conformity with generally
accepted accounting principles.
/s/ Schultz, Watkins & Company
Jackson, Mississippi
February 14, 1997
-1-
<PAGE> 30
MIDDLE BAY OIL COMPANY, INC.
Balance Sheets
December 31
ASSETS
<TABLE>
<CAPTION>
1996 1995
----------- -----------
<S> <C> <C>
CURRENT ASSETS
Cash $ 556,026 $ 80,791
Accounts receivable - trade 1,129,417 880,715
Other current assets 58,137 52,785
----------- -----------
Total current assets 1,743,580 1,014,291
NON-CURRENT ASSETS
Accounts receivable-stockholder (Note 3) 159,215 132,547
PROPERTY (At Cost)(Substantially Pledged)(Notes 1 & 4)
Oil and gas (successful efforts method) 16,252,576 11,400,288
Land - 54,414
Office building and other 354,603 350,676
----------- -----------
16,607,179 11,805,378
Less accumulated depletion and depreciation 5,332,517 3,976,923
----------- -----------
11,274,662 7,828,455
OTHER ASSETS 7,523 9,459
----------- -----------
$13,184,980 $ 8,984,752
=========== ===========
<CAPTION>
LIABILITIES AND STOCKHOLDERS' EQUITY
<S> <C> <C>
CURRENT LIABILITIES
Current maturity of long-term debt (Note 4) $ 554,601 $ 810,861
Accounts payable and accrued expenses 402,796 624,144
----------- -----------
Total current liabilities 957,397 1,435,005
LONG-TERM DEBT (Note 4) 5,158,477 4,195,391
DEFERRED INCOME TAXES (Notes 1 & 5) 610,785 495
REDEEMABLE COMMON STOCK (Note 8) 421,179 852,642
STOCKHOLDERS' EQUITY
Preferred stock, $.02 par, 2,500,000 shares authorized
with 1,666,667 shares designated as Series A, none
other issued - -
Cumulative convertible Series A 8% preferred stock, $6
stated value, 1,666,667 designated, 166,667 shares
issued and outstanding in 1996 ($1,000,000 aggregate
liquidation preference at 12/31/96) (Note 8) 1,000,000 -
Common stock, $.02 par, 5,000,000 shares
authorized, 1,880,917 issued and outstanding
in 1996 and 1,318,917 in 1995 (Note 8) 37,618 26,378
Additional paid-in capital 6,049,442 4,093,682
Less redeemable common stock (Note 8) (421,179) (852,642)
Deficit (560,699) (766,199)
Less cost of treasury stock (21,773 shares) (68,040) -
----------- -----------
6,037,142 2,501,219
----------- -----------
COMMITMENTS AND CONTINGENCIES (Note 9)
$13,184,980 $ 8,984,752
=========== ===========
</TABLE>
See accompanying notes to financial statements.
-2-
<PAGE> 31
MIDDLE BAY OIL COMPANY, INC.
Statements of Operations
Years Ended December 31
<TABLE>
<CAPTION>
1996 1995
----------- -----------
<S> <C> <C>
REVENUE
Oil and gas sales $ 4,474,786 $ 3,238,280
Gain on sale of oil and gas properties 37,815 125,550
Other 373,820 174,816
----------- -----------
4,886,421 3,538,646
COSTS AND EXPENSES
Operating expenses, including production taxes 1,516,011 1,436,869
Abandonment costs 428,598 83,107
Depletion, depreciation and amortization 1,462,196 1,221,263
Interest 504,945 520,419
General and administrative 694,300 698,194
----------- -----------
4,606,050 3,959,852
----------- -----------
INCOME (LOSS) BEFORE INCOME TAX EXPENSE (BENEFIT) 280,371 (421,206)
INCOME TAX EXPENSE (BENEFIT) (Note 5)
Current 5,079 -
Deferred 69,792 (90,153)
----------- -----------
74,871 (90,153)
----------- -----------
NET INCOME (LOSS) $ 205,500 $ (331,053)
=========== ===========
NET INCOME (LOSS) PER SHARE
On a common and common equivalent share $ .15 $ (.25)
=========== ===========
On a fully diluted basis $ .15 $ (.25)
=========== ===========
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Primary 1,332,141 1,318,917
=========== ===========
Fully Diluted 1,358,662 -
=========== ===========
</TABLE>
See accompanying notes to financial statements.
-3-
<PAGE> 32
MIDDLE BAY OIL COMPANY, INC.
Statements of Changes in Stockholders' Equity
Years Ended December 31, 1996 and 1995
<TABLE>
<CAPTION>
Preferred Common Additional
Stock Stock Paid-in
Shares Amount Shares Amount Capital Deficit Total
---------- ---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
BALANCE - 1/01/95 - - 1,318,917 26,372 $4,093,682 $ (435,146) $3,684,908
Less redeemable common
stock (Note 8) - - - - (852,642) - (852,642)
Share consolidation - - - 6 - - 6
Net loss - - - - - (331,053) (331,053)
---------- ---------- ---------- ---------- ---------- ---------- ----------
BALANCE - 12/31/95 - - 1,318,917 26,378 3,241,040 (766,199) 2,501,219
Common stock issued
in acquisition of
NPC Energy Corp. - - 562,000 11,240 1,955,760 - 1,967,000
Preferred stock
issued 166,667 1,000,000 - - - - 1,000,000
Conversion of
redeemable common
stock to common
stock - - - - 431,463 - 431,463
Net income - - - - - 205,500 205,500
---------- ---------- ---------- ---------- ---------- ---------- ----------
BALANCE - 12/31/96 166,667 1,000,000 1,880,917 37,618 $5,628,263 $ (560,699) 6,105,182
========== ========== ========== ========== ========== ========== ==========
Less cost of treasury
stock acquired in
1996 (21,773 shares) (68,040)
----------
$6,037,142
</TABLE>
See accompanying notes to financial statements.
-4-
<PAGE> 33
MIDDLE BAY OIL COMPANY, INC.
Statements of Cash Flows
Years Ended December 31
<TABLE>
<CAPTION>
1996 1995
----------- -----------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income(loss) $ 205,500 $ (331,053)
Depletion, depreciation and amortization 1,462,194 1,221,263
Gain on sale of assets (37,814) (125,550)
Other 7,648 (31,242)
Increase (Decrease) in deferred taxes 69,792 (90,153)
Increase in receivables (14,487) (443,817)
(Decrease) Increase in payables (303,457) 238,130
----------- -----------
Net cash provided by operating activities 1,389,376 437,578
CASH FLOWS FROM INVESTING ACTIVITIES
Payment for purchase of NPC Energy Corp.,
net of cash acquired (651,016) -
Capital expenditures:
Oil and gas properties (1,596,966) (3,266,267)
Office building and other (8,188) (9,873)
Proceeds from sales of:
Oil and gas properties 40,000 523,196
Timberland 75,000 -
Advances to stockholder-net (26,668) (68,148)
----------- -----------
Net cash (used in) investing activities (2,167,838) (2,821,092)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds of bank loans 529,596 5,628,000
Principal payments on loans (207,859) (3,347,211)
Proceeds from issuance of preferred stock 1,000,000 -
Purchases of treasury stock (68,040) -
----------- -----------
Net cash provided by financing
activities 1,253,697 2,280,789
----------- -----------
NET INCREASE (DECREASE) IN CASH FOR THE YEAR 475,235 (102,725)
CASH - Beginning of year 80,791 183,516
----------- -----------
CASH - End of year $ 556,026 $ 80,791
=========== ===========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Cash paid during the year for:
Interest $ 504,945 $ 520,419
=========== ===========
Income taxes $ 5,079 $ -
=========== ===========
Non-cash investing and financing activities:
Common stock issued in acquisition
of NPC Energy Corp. $ 1,967,000 $ -
=========== ===========
Conversion of redeemable common stock to
common stock (net of treasury shares
acquired) $ 363,423 $ -
=========== ===========
</TABLE>
See accompanying notes to financial statements.
-5-
<PAGE> 34
MIDDLE BAY OIL COMPANY, INC.
Notes to Financial Statements
December 31, 1996 and 1995
(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 30, 1992. The Company is engaged in the
acquisition, development and production of oil and natural gas in the contiguous
United States.
Significant Accounting Policies
The Company's accounting policies reflect industry standards and
conform to generally accepted accounting principles. The more significant of
such policies are described below.
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 and development
are charged to expense currently. Geological and geophysical costs and costs of
carrying and retaining unevaluated properties are charged to expense. Depletion,
depreciation and amortization of capitalized costs are computed separately for
each property based on the unit-of-production method using only proved oil and
gas reserves. In arriving at such rates, commercially recoverable reserves have
been estimated by independent petroleum engineering firms. The Company reviews
its undeveloped properties continually and charges them to expense on a property
by property basis when it is determined that they have been condemned by dry
holes, or will not be retained, sold or drilled upon.
Site Restoration, Dismantlement & Abandonment Costs
Site restoration, dismantlement and abandonment costs (P&A costs) are
common in the oil and gas industry in which the Company conducts operations. P&A
costs are costs associated with removing the facilities and equipment required
to operate a well and restoring the well site to specified conditions. P&A
procedures are governed by federal and state regulations and contractual
obligations. P&A costs are incurred when the oil and gas reserves of a well or
wells are depleted or when production drops to the point that it is no longer
economically feasible to produce.
The Company, in conjunction with its independent engineers and the
operators of wells, continually reviews its working interests with respect to
potential P&A costs. When conditions require that a well be abandoned, the
appropriate accounting procedures are followed. When a well or the last well of
a group of proved properties ceases to produce or is no longer economically
feasible to produce, the entire cost related to the well or group of wells,
which includes estimated future dismantlement and abandonment cost, is written
off and gain or loss is recognized. Any additional liabilities arising from P&A
costs, net of salvage value of the equipment, are accrued in the financial
statements and charged to expense in the current period.
<PAGE> 35
MIDDLE BAY OIL COMPANY, INC.
Notes to Financial Statements
December 31, 1996 and 1995
(Continued)
(1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Site Restoration, Dismantlement & Abandonment Costs (continued)
P&A costs are considered in the proved oil and gas reserve estimates as
disclosed in Note 11 - Supplemental Oil and Gas Reserve Information; and, if
material, the present value of the reserves is reduced accordingly.
As of December 31, 1996 and 1995, the P&A costs accrued were
immaterial.
Impairment of Long-Lived Assets
Statement of Financial Accounting Standards No. 121 "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of"
(SFAS #121) was issued in March 1995. This statement requires that long-lived
assets be reviewed for impairment when events or changes in circumstances
indicate that the carrying value of such assets may not be recoverable. This
review consists of a comparison of the carrying value of the asset with the
asset's expected future undiscounted cash flows without interest costs.
Estimates of expected future cash flows are to represent management's
best estimate based on reasonable and supportable assumptions and projections.
If the expected future cash flows exceed the carrying value of the asset, no
impairment is recognized. If the carrying value of the asset exceeds the
expected future cash flows, an impairment exists and is measured by the excess
of the carrying value over the estimated fair value of the asset. Any impairment
provisions recognized in accordance with SFAS #121 are permanent and may not be
restored in the future.
In the fourth quarter of 1996 and 1995, the Company's proved properties
were assessed for impairment on an individual field basis and the Company
recorded an impairment provision of $277,483 and $156,071, respectively,
attributable to certain producing properties.
Prior to the adoption of SFAS #121, the Company assessed its proved oil
and gas properties on an individual field basis using management's best estimate
of the expected future cash flows from the producing properties.
Other Property and Equipment
Property and equipment are stated at cost and depreciation is computed
on the accelerated method over the appropriate life for the property. Additions
and betterments which provide benefits to several periods are capitalized.
Income Taxes
The Company uses the asset and liability method of accounting for
income taxes required by Statement of Financial Accounting Standards No. 109.
Under the asset and liability method, deferred tax assets and liabilities are
determined by applying enacted statutory tax rates applicable to future years to
the difference between the financial statement and tax bases of assets and
liabilities.
<PAGE> 36
MIDDLE BAY OIL COMPANY, INC.
Notes to Financial Statements
December 31, 1996 and 1995
(Continued)
(1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Concluded)
Stock-based Compensation
In October 1995, the Financial Accounting Standards issued SFAS No.
123, "Accounting for Stock-Based Compensation", which establishes financial
accounting and reporting standards for stock-based compensation plans. Effective
for fiscal years beginning after December 31, 1995, the statement provides the
option to continue under the accounting provisions of APB Opinion 25, while
requiring pro forma footnote disclosures of the effects on net income and
earnings per share, calculated as if the new method had been implemented. The
Company has adopted the financial reporting provisions of SFAS No. 123 for 1996,
but will continue under the accounting provisions of APB Opinion 25.
Use of Estimates
Management of the Company has made a number of estimates and
assumptions relating to the reporting of assets and liabilities, revenue and
expenses, and the disclosure of contingent assets and liabilities to prepare the
financial statements in conformity with generally accepted accounting
principles. Actual results could differ from those estimates.
Earnings (Loss) Per Share
Primary earnings (loss) per common and common stock equivalent share
data is computing by dividing net income (loss) of $205,500 and $(331,053) by
the weighted average number of common shares outstanding during each period.
Shares issuable upon exercise of options are included in the computation of
earnings per common and common equivalent share to the extent they are dilutive.
Fully diluted earnings (loss) per common share also assumes the exercise of the
convertible preferred stock if such conversion has a dilutive effect.
For the year ended December 31, 1996, the exercise of the stock options
had a dilutive effect. Accordingly, the income per share calculation is based on
the weighted average common shares outstanding plus the dilutive effect of the
common stock equivalents. The effect of the convertible preferred stock was not
significant because it was outstanding for only one day of the year ended
December 31, 1996. No common stock equivalents were outstanding for the year
ended December 31, 1995.
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 current production
revenue receivable from multiple oil and gas producers, both major and
independent, and is typical in the Industry.
<PAGE> 37
MIDDLE BAY OIL COMPANY, INC.
Notes to Financial Statements
December 31, 1996 and 1995
(Continued)
(2) ACQUISITIONS
On December 31, 1996, NPC Energy Corporation (NPC), an Oklahoma
corporation, merged into the Company in accordance with the Agreement and Plan
of Merger (Merger) dated December 17, 1996. NPC is a privately-owned domestic
exploration and production company with assets located primarily in Kansas and
Oklahoma. Pursuant to the Merger, the Company issued 562,000 shares of its
common stock valued at $3.50 per share and paid $1,226,400 in cash in exchange
for all of the stock of NPC, resulting in total consideration paid of
$3,193,400. The Company used the proceeds from the sale of 166,667 shares of
convertible preferred stock to finance a portion of the acquisition price. The
NPC Merger added approximately 503 thousand barrels of oil and 3.1 billion cubic
feet of gas to the Company's proved reserves. The Merger was accounted for as a
purchase.
The following information represents unaudited pro-forma results of
operations of the Company for the years ended December 31, 1996 and 1995, as if
the acquisition had occurred at the beginning of 1995. The information is
presented for comparative purposes only and is not necessarily indicative of the
results that would have been obtained had this acquisition been consummated as
presented. The following reflects pro forma adjustments for the crude oil and
natural gas sales, costs and expenses, depletion, depreciation and amortization,
and preferred stock dividends:
<TABLE>
<CAPTION>
Pro Forma (Unaudited)
(In Thousands
except per share data)
1996 1995
------- --------
<S> <C> <C>
Revenues $6,476 $5,719
Net Loss 294 (100)
Net Loss per share $ 0.22 $(0.05)
</TABLE>
On February 23, 1995, the Company completed the acquisition of producing
oil and gas properties, principally working interest, from Parker & Parsley
Development, LP, a Texas limited partnership. The acquisition added
approximately 415 thousand barrels of oil and 2.3 billion cubic feet of natural
gas to the Company's proved reserves.
The cost of $2,798,685, net after various post-closing adjustments, was
paid in cash financed by an increase in the Company's term loan. The acquisition
was accounted for as a purchase.
The following information represents unaudited pro-forma results of
operations of the Company for the years ended December 31, 1995 and 1994, as if
the acquisition had occurred at the beginning of 1994. The information is
presented for comparative purposes only and is not necessarily indicative of the
results that would have been obtained had this acquisition been consummated as
presented. The following reflects pro forma adjustments for the crude oil and
natural gas sales, costs and expenses, depletion, depreciation and amortization,
and interest expense on additional borrowed funds:
<TABLE>
<CAPTION>
Pro Forma (Unaudited)
(In Thousands
except per share data)
1995 1994
------- --------
<S> <C> <C>
Revenues $3,944 $4,439
Net Loss (338) (344)
Net Loss per share $(0.26) $(0.31)
</TABLE>
<PAGE> 38
MIDDLE BAY OIL COMPANY, INC.
Notes to Financial Statements
December 31, 1996 and 1995
(Continued)
(3) RELATED PARTY TRANSACTIONS
The Company had a note receivable from Bay City Energy Group, Inc.
(successor entity to Bay City Minerals, Inc., effective September 26, 1995) a
significant stockholder, as of December 31, 1996 and 1995 in the amount of
$159,215 and $132,547, respectively. The principal balance of the note accrues
interest at 5% annually and is due January 1, 2001. The note is secured by
75,000 shares of Company common stock. Bay City Energy Group, Inc. made cash
payments to the Company of $0 and $17,928 and was advanced $26,668 and $86,076
during the years ended December 31, 1996 and 1995, respectively. Interest of
$20,210 was accrued on the note as of December 31, 1996.
(4) LONG - TERM DEBT
<TABLE>
<CAPTION>
1996 1995
---------- ----------
<S> <C> <C>
Convertible loan for $6,000,000 due September 30, 1997, secured by oil and
gas properties, monthly payments of interest only at 1.5% over prime,
convertible into a 72 month
term note on September 30, 1997 $5,186,596 $ -
Term note due August 31, 1998, secured by
oil and gas properties, repayable in
monthly installments of $27,590 plus
interest at 9.5% 385,089 -
Term note for $5,628,000, due February 1, 2002, secured by oil and gas
properties, repayable in monthly installments of of $67,000 plus
interest at 1.5% over
prime - 4,858,000
Note due January 1, 1999, secured by office
building, repayable in monthly installments
of $1,511, including interest at 7 3/4% 141,393 148,252
---------- ----------
Total 5,713,078 5,006,252
Less current maturities 554,601 810,861
---------- ----------
Long-term debt excluding current maturities $5,158,477 $4,195,391
========== ==========
</TABLE>
The $6,000,000 convertible loan and the $385,089 note payable, contain
certain restrictive provisions, the most significant of which restricts
additional borrowings, either directly or indirectly, and payment of dividends.
At December 31, 1996, the Company was in compliance with all covenants specified
in the agreements.
Aggregate amounts of expected required repayments of long-term debt at
December 31, 1996 are as follows:
<TABLE>
<S> <C>
1997 $ 554,601
1998 926,448
1999 864,432
2001 864,432
2002 864,432
Thereafter 1,638,733
----------
$ 5,713,078
==========
</TABLE>
<PAGE> 39
MIDDLE BAY OIL COMPANY, INC.
Notes to Financial Statements
December 31, 1996 and 1995
(Continued)
(5) INCOME TAXES
Income tax expense (benefit) for the years ended December 31 consisted
of the following:
<TABLE>
<CAPTION>
1996 1995
--------- ---------
<S> <C> <C>
Current $ 5,079 $ -
Deferred 69,792 (90,153)
--------- ---------
Total $ 74,871 $ (90,153)
========= =========
</TABLE>
The reconciliation of income taxes computed at the U.S. federal
statutory tax rates to the provision for income taxes is as follows:
<TABLE>
<CAPTION>
1996 1995
--------- ---------
<S> <C> <C>
Income tax expense (benefit) at statutory rate $ 92,595 $(143,210)
Decrease due to NOL carryforward (79,500) (85,072)
Increase due to NOL not yet recognized 151,762 143,483
Decrease due to AMT credit carryforward - (26,106)
Decrease due to effect of graduated tax rates (96,740) (115)
Increase due to state taxes and other 6,754 20,867
--------- ---------
Income tax expense (benefit) $ 74,871 $ (90,153)
========= =========
</TABLE>
The Company's net deferred tax liability at December 31, 1996 and 1995
is as follows:
<TABLE>
<CAPTION>
1996 1995
--------- ---------
<S> <C> <C>
Deferred tax liability
Oil and gas properties $ 817,079 $ 144,453
Deferred tax asset
NOL Carryforward (164,076) (85,072)
AMT tax credit carryforward (36,482) (36,482)
Other (5,736) (22,403)
Valuation allowance - -
--------- ---------
Net deferred tax liability $ 610,785 $ 496
========= =========
</TABLE>
As of December 31, 1996, the Company had net operating loss
carryforwards of $836,665 expiring in the years, 2009 and 2010, and minimum tax
credit carryforwards of $36,482.
<PAGE> 40
MIDDLE BAY OIL COMPANY, INC.
Notes to Financial Statements
December 31, 1996 and 1995
(Continued)
(6) RETIREMENT PLAN AND OTHER EMPLOYEE BENEFITS
All employees of the Company participate in a defined contribution
profit-sharing plan which provides for a maximum discretionary Company
contribution of 15% of total wages paid to employees for the year. The Company
contributed $5,000 and $30,000 to the plan for the years ended December 31, 1996
and 1995, respectively.
In 1995, the Company adopted an employee incentive award plan which
provides for a 1% net profit interest in all oil and gas property acquisitions
and divestitures and in drilling prospects acquired or made after January 1,
1994. Awards to employees are determined by the Compensation Committee of the
Board of Directors. The Company paid $6,916 and $30,000, into the plan for the
years ended December 31, 1996 and 1995, respectively.
(7) STOCK OPTION AND STOCK APPRECIATION RIGHTS PLAN
At December 31, 1996, the Company has one fixed stock option plan, the
1995 Stock Option and Stock Appreciation Rights Plan (1995 Plan). The Company
applies APB Opinion 25, "Accounting for Stock Issued to Employees", and related
Interpretations in accounting for the plan; and accordingly, no compensation
cost has been recognized. Had compensation cost for the Company's 1995 Plan been
determined based on the fair value at the grant date for awards under the 1995
Plan consistent with the method of FASB Statement 123, "Accounting for
Stock-Based Compensation", the Company's net income and earnings per share would
have been reduced to the pro forma amounts indicated below:
<TABLE>
<CAPTION>
1996
--------
<S> <C> <C>
Net income As reported $205,500
Pro forma 88,034
Primary earnings per share As reported $ 0.15
Pro forma 0.07
Fully diluted earnings per share As reported $ 0.15
Pro forma 0.07
The 1995 Plan
</TABLE>
On May 31, 1996, the Board of Directors granted options to acquire
125,000 shares of Company common stock under the 1995 Plan to key employees and
non-employee directors. All of the options vested on the grant date of May 31,
1996 with an exercise price of $2.50 per share, which was equal to the fair
market value of common stock on the date of grant. The options expire ten years
from the date of grant if not exercised. The 1995 Plan is administered by the
Compensation Committee of the Board of Directors.
Information regarding the 1995 Plan is summarized below:
<TABLE>
<CAPTION>
Year ended
December 31, 1996
-----------------
<S> <C>
Options outstanding at beginning of period........ -
Granted........................................... 125,000
Exercised......................................... -
Surrendered or forfeited.......................... -
--------
Options outstanding at end of period.............. 125,000
========
</TABLE>
The fair value of each option grant is estimated on the date of grant
using the Black-Scholes option-pricing model with the following assumptions used
for the grants in 1996: no dividend yield; expected volatility of 50.41 percent;
risk-free interest rate of 6.38 percent; and expected life of 3 years.
<PAGE> 41
MIDDLE BAY OIL COMPANY, INC.
Notes to Financial Statements
December 31, 1996 and 1995
(Continued)
(8) STOCKHOLDERS' EQUITY
On September 4, 1996, the Company executed a stock purchase agreement
(the Agreement) with Kaiser-Francis Oil Company. Kaiser-Francis has agreed to
purchase 1,666,667 shares of Series A Preferred Stock (the Preferred) at $6.00
per share, for a total investment of $10,000,000. The parties have agreed to a
five-year purchase period, effective September 4, 1996, with minimum incremental
investments of $500,000 each. Each issuance of the Preferred is subject to
approval by Kaiser-Francis of the use of the proceeds. The Preferred is
nonvoting and accrues dividends at 8% per annum, payable quarterly in cash and
is convertible at any time, after issuance and until January 1, 1998, into
shares of common stock at the rate of two shares of common stock for each share
of Preferred. After January 1, 1998, the conversion rate decreases at 8% per
annum. The Company will pay the costs of registration of the Preferred or the
underlying common stock under the Securities Act of 1933 upon request of Kaiser-
Francis. The Company may redeem the Preferred in whole or in part, at any time
after January 1, 2007 at a price of $6.00 per share. As of December 31, 1996,
166,667 shares of the Preferred had been issued.
On April 1, 1996, the Board of Directors authorized the repurchase of
up to $100,000 of Company common stock at a per share price not to exceed $3.25,
excluding brokerage costs. As of December 31, 1996, the Company had purchased
21,773 shares of common stock at a cost of $68,040.
On March 21, 1995 the Company effected a one-for-two reverse stock
split (share consolidation) of its capital stock, thereby changing authorized
common stock from 10,000,000 shares of $.01 par value to 5,000,000 shares of
$.02 par value. The issued and outstanding shares of common stock were thus
reduced from 2,637,257 to 1,318,629 shares. The Company's authorized preferred
was reduced from 5,000,000 shares of $.01 par value to 2,500,000 shares of $.02
par value.
The Company has a contingent obligation to repurchase the 142,107
common shares issued in the Janex Acquisition, upon written notice delivered to
the Company, beginning five years after the closing date November 1, 1993, and
continuing for thirty days thereafter, at a price of $6.00 per share. This
obligation shall terminate if the Company's stock trades at a share price of
$8.00 or greater for twenty consecutive days during the thirty-six month period
ending November 1, 1998. As of December 31, 1996, the price of the Company's
common stock had not met the trading limits. As of December 31, 1996, 71,910
shares subject to the repurchase obligation had been sold, thus leaving 70,197
shares subject to redemption. The value of the remaining shares at the $6.00
redemption price per share is carried in the balance sheet as Redeemable Common
Stock.
<PAGE> 42
MIDDLE BAY OIL COMPANY, INC.
Notes to Financial Statements
December 31, 1996 and 1995
(Continued)
(9) COMMITMENTS AND CONTINGENCIES
The Company is obligated under the terms of certain operating leases
for office equipment through December, 1997, with future minimum rental payments
of $8,076.
On April 3, 1996, the Company entered into a Joint Expense and
Participation Agreement with Brigham Oil and Gas, L.P. (Brigham), through which
the Company is participating in the drilling of approximately eighty-seven
onshore wells over the twelve month period beginning April 1, 1996. The Company
is committed to fund $1,500,000 in drilling costs over this period. As of
December 31, 1996, the Company had advanced $1,271,914 in drilling costs to
Brigham. The amount required to be deposited into the escrow account at January
1, 1997 to cover the drilling and completion costs for the three month period
ending March 31, 1997 was $899,440.
The Company is a defendant in various other legal proceedings which are
considered routine litigation incidental to the Company's business, the
disposition of which management believes will not have a material effect on the
financial position or result of operations of the Company.
(10) SUBSEQUENT EVENTS
On February 10, 1997, the Company executed a definitive merger
agreement with Bison Energy Corporation (Bison), whereby Bison will be acquired
as a wholly owned subsidiary. The Merger will add reserves of approximately 607
million barrels of oil and natural gas liquids, and approximately 2.58 billion
cubic feet of natural gas located primarily in the Spivey-Grabs Field, Kingman
and Harper Counties, Kansas. Bison has 120 operated wells in Kansas through its
wholly owned subsidiary, Bison Production Company. In addition, the Company will
acquire approximately 9,000 acres of undeveloped leases, an interest in the
Spivey-Grabs gas processing plant,and operating facilities in Attica, Kansas and
Cushing, Oklahoma.
Pursuant to the terms of the agreement, the Company will issue
1,167,556 shares of its common stock and cancel 562,000 shares of its common
stock presently held by Bison for a net increase of 605,556 shares. The balance
of the purchase price will consist of cash of $5,900,000 to be funded by
Kaiser-Francis Oil Company through its Preferred Stock Agreement with the
Company. The transaction is expected to be closed no later than February 28,
1997.
<PAGE> 43
MIDDLE BAY OIL COMPANY, INC.
Notes to Financial Statements
December 31, 1996 and 1995
(Continued)
(11) SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
CAPITALIZED COSTS AND COSTS INCURRED (UNAUDITED)
The following tables present the (1) capitalized costs related to oil
and gas producing activities and the related depreciation, depletion and
amortization and (2) costs incurred in oil and gas property acquisition and
exploration and development activities (in thousands).
<TABLE>
<CAPTION>
1996 1995
--------- ---------
<S> <C> <C>
Capitalized Costs
-----------------
Proved properties $ 15,561 $ 10,709
Nonproducing leasehold 376 378
Support equipment & facilities 315 313
Accumulated depreciation, depletion & amortization (5,237) (3,905)
--------- ---------
Net $ 11,015 $ 7,495
========= =========
Costs Incurred
--------------
Proved properties $ 3,402 $ 2,811
Unproved properties - 38
Exploration costs 1,453 -
Development costs 540 500
--------- ---------
Total $ 5,395 $ 3,349
========= =========
Depreciation, depletion and amortization $ 1,433 $ 1,187
========= =========
</TABLE>
ESTIMATED QUANTITIES OF RESERVES (UNAUDITED)
The Company has interests in oil and gas properties that are
principally located in Alabama, Louisiana, Kansas, New Mexico, Oklahoma and
Texas. The Company does not own or lease any oil and gas properties outside the
United States. There are no quantities of oil or gas subject to long-term supply
or similar agreements with any governmental agencies.
The Company retains independent engineering firms to provide annual
year-end estimates of the Company's future net recoverable oil, gas and natural
gas liquids reserves. The information for 1996 and 1995 is based upon estimates
prepared by Lee Keeling and Associates, Inc., and Cawley, Gillespie &
Associates, Inc., which were engaged to perform an evaluation of the Company's
oil and gas reserves. The reserve information was prepared in accordance with
Statement of Financial Accounting Standards No. 69. 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 on
undrilled acreage or from existing wells on which a relatively major expenditure
is required for recompletion.
<PAGE> 44
MIDDLE BAY OIL COMPANY, INC.
Notes to Financial Statements
December 31, 1996 and 1995
(Continued)
(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:
ESTIMATED QUANTITIES OF RESERVES (UNAUDITED)
<TABLE>
<CAPTION>
Years Ended
December 31
--------------------------------------------
1996 1995
---------------------- --------------------
Oil Gas Oil Gas
Proved Reserves (Barrels) (Mcf) (Barrels) (Mcf)
- --------------- ---------- ---------- --------- ----------
<S> <C> <C> <C> <C>
Beginning of year 777,550 6,370,830 541,556 4,772,579
Revisions of previous estimates 157,099 44,543 (84) 604,718
Extensions and discoveries 76,492 392,275 - -
Purchases of reserves in place 503,156 3,139,299 397,855 2,340,487
Sale of reserves in place (15,726) - (54,752) (430,000)
Production for the year (108,626) (982,709) (107,025) (916,954)
---------- ---------- --------- ----------
End of year 1,389,945 8,964,238 777,550 6,370,830
========= ========== ========= =========
Proved Developed Reserves
Beginning of year 770,334 6,306,604 541,556 4,772,579
========== ========== ========= =========
End of year 1,266,421 8,142,820 770,334 6,306,604
========== ========== ========= =========
</TABLE>
STANDARDIZED MEASURE OF FUTURE NET CASH FLOWS FROM PROVED RESERVES
(UNAUDITED)
The following is a summary of the standardized measure of discounted
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 pretax 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.
<PAGE> 45
MIDDLE BAY OIL COMPANY, INC.
Notes to Financial Statements
December 31, 1996 and 1995
(Concluded)
(11) SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (Concluded)
STANDARDIZED MEASURE OF FUTURE NET CASH FLOWS FROM PROVED RESERVES
(UNAUDITED)
The standardized measure of discounted future net cash flows relating
to proved oil and gas reserves are summarized as follows (in thousands):
<TABLE>
<CAPTION>
December 31
----------------------
1996 1995
--------- ---------
<S> <C> <C>
Future cash inflows $ 61,813 $ 26,192
Future production costs and development costs (25,873) (10,860)
Future income tax expenses (7,361) (1,709)
--------- ---------
Future net cash flows 28,579 13,623
10% discount to reflect timing of cash flows (10,716) (4,373)
--------- ---------
Standardized measure of discounted
future net cash flows $ 17,863 $ 9,250
========= =========
</TABLE>
The following are the principal sources of change in the standardized
measure of discounted future net cash flows (in thousands):
<TABLE>
<CAPTION>
Years Ended
December 31
----------------------
1996 1995
--------- ---------
<S> <C> <C>
Beginning of year $ 9,250 $ 5,785
Sales of oil and gas, net of production cost (2,959) (1,801)
Net changes in prices and production cost 8,521 1,612
Extension and discoveries 1,966 -
Purchase of reserves 6,006 3,202
Sale of reserves (29) (478)
Revisions of quantity estimates (2,551) 822
Net change in income taxes (3,382) (533)
Accretion of discount 1,041 641
--------- ---------
End of year $ 17,863 $ 9,250
========= =========
</TABLE>
During recent years, there have been significant fluctuations in the
prices paid for crude oil in the world markets. This 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, 1996 and 1995, used in the above
table were $24.50 and $17.50 per barrel of oil, respectively, and $3.70 and
$2.03 per thousand cubic feet of gas, respectively.
<PAGE> 46
PART III
ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS;
COMPLIANCE WITH SECTION 16(A) OF THE EXCHANGE ACT
(a) Executive Officers and Directors
The following table sets forth the executive officers and
directors of the Company as of December 31, 1996. All directors serve for a
one-year term or until the next Annual Meeting of Shareholders of the Company.
The Board of Directors held five meetings during the fiscal year ended December
31, 1996. Each director attended all meetings of the Board. Executive officers
serve at the pleasure of the Board of Directors. There were no employment
contracts between the Company and any executive officer as of December 31, 1996.
<TABLE>
<CAPTION>
Director
Name Age Position(s) Held Since(1)
---- --- ---------------- --------
<S> <C> <C> <C>
John J. Bassett 38 Chairman, President and 1989
Chief Executive Officer
Frank C. Turner, II(2) 36 Vice President, Chief Financial 1989
Officer and Director
Robert W. Hammons 43 Vice President N/A
Lynn M. Davis 48 Secretary and Treasurer N/A
Edward P. Turner, Jr.(2) 67 Director 1989
Frank E. Bolling, Jr. 37 Director 1992
C. Noell Rather 61 Director 1995
</TABLE>
(1) All directors, except Mr. Rather, were elected upon the organization of
Middle Bay Oil Company as a corporation in December, 1992. Each
director, except for Mr. Bolling. and Mr. Rather, had served as a
director of Bay City Minerals, Inc., the general partner of the
Predecessor Partnership, since prior to the formation of the
Predecessor Partnership in May, 1989.
(2) Edward P. Turner, Jr. and Frank C. Turner, II, are father and son.
John J. Bassett has served as President and a director of the
Company since 1992 and was elected Chairman of the Board of Directors in 1996.
He served as President of the general partner of the Predecessor Partnership
from 1987 to 1992. He also serves as a director and President of Bay City Energy
Group, Inc., a principal shareholder of the Company.
III - 1
<PAGE> 47
Frank C. Turner, II has served as Vice President and Chief
Financial Officer for the Company since its organization as a corporation in
1992. He had previously served as Vice President of Finance for the general
partner of the Predecessor Partnership since 1990. From 1987 to 1990, Mr. Turner
was employed by Sonat, Inc. as a financial analyst. He also serves as a director
and Vice President of Bay City Energy Group, Inc.
Robert W. Hammons was hired by the Company in April, 1992 as
a reservoir engineer. Mr. Hammons was appointed Vice President of Engineering
of the Company in 1993. Prior to his employment with the Company, he had worked
with Bay City Minerals, Inc. as an independent petroleum engineering consultant
since 1987. Prior to 1987, Mr. Hammons was employed as manager of reservoir
engineering for Marion Corporation.
Lynn M. Davis has been Secretary and Treasurer for the Company
since 1992. She has served as Secretary-Treasurer of the general partner of the
Predecessor Partnership since 1984 and as a director since 1988. Ms. Davis also
serves as a director and Secretary-Treasurer for Bay City Energy Group, Inc.
Edward P. Turner, Jr. served as President of Bay City
Minerals, Inc. from 1975 to 1987. He is a member of the Alabama State Bar and a
managing partner of the law firm of Turner, Onderdonk, Kimbrough & Howell, P.A.,
in Chatom, Alabama. A substantial amount of his practice is devoted to oil and
gas law. Mr. Turner also serves as a director of Bay City Energy Group, Inc.
Frank E. Bolling, Jr. has been employed by Midstream Fuel
Services, Inc. as Vice President of Retail Operations since February, 1995.
Prior to his employment with Midstream, Mr. Bolling served as Vice President and
General Manager of Dantzler Bulk Plant, Inc., a distributor for Chevron U.S.A.,
Inc. with annual sales in excess of $25 million. Mr. Bolling served as sales
manager for Dantzler from 1987 to 1989. Prior to 1987, Mr. Bolling was employed
by Bay City Minerals, Inc.
C. Noell Rather has been President of Janex Oil Co., Inc. and
Enexco, Inc since 1981. Both are independent oil companies based in Texas.
(b) Compliance with Section 16(a) of the Exchange Act
Section 16(a) of the Securities Exchange Act of 1934 requires
the Company's directors and executive officers and any persons who own more than
10% of the Company's common stock to file with the Securities and Exchange
Commission reports of ownership and changes in ownership of such securities.
Based on representations from such persons, the Company believes that there was
no failure to file or delinquent filings under Section 16(a) of the Securities
Exchange Act of 1934 by any officer, director or beneficial owner of 10% or more
of the Company's common stock during 1996.
(c) Audit and Compensation Committees
The members of the Audit Committee are Frank C. Turner, II,
Frank E. Bolling, Jr. and C. Noell Rather. 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
III - 2
<PAGE> 48
arrangements; reviewing the results of the annual audit; reviewing the adequacy
of the accounting and financial controls; reviewing the independence of the
independent auditors; approving all assignments to be performed by the
independent auditors; and instructing the independent auditors, as deemed
appropriate, to undertake special assignments.
The members of the Compensation Committee are John J. Bassett,
Edward P. Turner, Jr. and Frank E. Bolling, Jr. The functions of the
Compensation Committee are to approve or recommend for approval to the Board of
Directors, the compensation and remuneration arrangements for directors and
senior management.
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, 1994 through December 31, 1996:
<TABLE>
<CAPTION>
Annual Compensation Long-Term Compensation
------------------- ----------------------
Awards Payouts
(g)
Securities
Underlying (i)
(a) (e) Options/ (h) All Other
Name and (b) (c) (d) Other Annual SARs LTIP Compensation
Principal Position Year Salary ($) Bonus ($) Compensation (#) Payouts ($) ($)
------------------ ---- ---------- --------- ------------ --- ----------- ---
<S> <C> <C> <C> <C> <C> <C> <C>
John J. Bassett 1996 $ 58,075 -- -- 20,000 -- $ 2,271
President & Chief 1995 56,250 -- -- -- -- 11,371
Executive Officer 1994 54,000 $200 -- -- -- --
Frank C. Turner, II 1996 54,458 -- -- 20,000 -- 2,174
Vice President & 1995 50,083 -- -- -- -- 10,775
CFO 1994 48,000 200 -- -- -- --
Robert W. Hammons 1996 58,075 -- -- 20,000 -- 2,271
Vice President - 1995 56,250 -- -- -- -- 11,360
Engineering 1994 54,000 200 -- -- -- --
Lynn M. Davis 1996 32,733 -- -- 5,000 -- 1,249
Secretary/Treasurer 1995 31,667 -- -- -- -- 6,238
1994 30,000 200 -- -- -- --
</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
III - 3
<PAGE> 49
such terms and conditions consistent with the Plan as the Committee may
determine, but the duration of any option or right shall be not greater than ten
years or less than five years from the date of grant.
Options or rights grants shall be made under the Plan only to
persons who are officers or salaried employees of the Company or are nonemployee
directors. The aggregate number of shares of common stock of the Company which
could be subject to options or rights under the Plan during 1996 was 125,000.
During the fiscal year ended December 31, 1996, options covering 125,000 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.
The following table provides certain information with respect
to all options granted during the fiscal year ended December 31, 1996 to any
executive officer or director of the Company; all of the options were granted
under the Plan:
<TABLE>
<CAPTION>
INDIVIDUAL GRANTS
(a) (b) (c) (d) (e)
Number of
Securities % of Total
Underlying Options/SARs
Options/ Granted to
SARS Employees in Exercise or Base Expiration
Name Granted (#) Fiscal Year Price ($/Sh) Date
---- ----------- ----------- ------------ ----
<S> <C> <C> <C> <C>
John J. Bassett 20,000 16.0% 2.50 5/31/2006
Frank C. Turner, II 20,000 16.0% 2.50 5/31/2006
Robert W. Hammons 20,000 16.0% 2.50 5/31/2006
Lynn M. Davis 5,000 4.0% 2.50 5/31/2006
Edward P. Turner, Jr.* 13,334 10.7% 2.50 5/31/2006
Frank E. Bolling, Jr.* 13,333 10.7% 2.50 5/31/2006
C. Noell Rather* 13,333 10.7% 2.50 5/31/2006
</TABLE>
*Nonemployee director
III - 4
<PAGE> 50
(c) Aggregated Option Exercises in Last Fiscal Year and Option
Value Table as of December 31, 1996
The following table sets forth certain information concerning
each exercise of stock options during the year ended December 31, 1996 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:
<TABLE>
<CAPTION>
INDIVIDUAL GRANTS
(a) (b) (c) (d) (e)
Number of Securities Value of Unexercised
Underlying Unexercised In-the-Money
Shares Options/SARs at Options/SARs at
Acquired Value FY End (#) FY End ($)
Name on Exercise (#) Realized ($) Exer. Unexer. Exer. Unexer.
---- --------------- ------------ ----- ------- ----- -------
<S> <C> <C> <C> <C> <C> <C>
John J. Bassett -- -- -- 20,000 -- 70,000
Frank C. Turner, II -- -- -- 20,000 -- 70,000
Robert W. Hammons -- -- -- 20,000 -- 70,000
Lynn M. Davis -- -- -- 5,000 -- 17,500
Edward P. Turner, Jr.* -- -- -- 13,334 -- 46,669
Frank E. Bolling, Jr.* -- -- -- 13,333 -- 46,666
C. Noell Rather* -- -- -- 13,333 -- 46,666
*Nonemployee director
</TABLE>
(d) Other Compensation Under Plans
The Company established a SEP/IRA retirement plan (the "Plan")
in 1993 which allows for a maximum discretionary Company contribution of 15% of
total wages paid to employees for the year. No contribution was made to the Plan
in 1994. For the years ended December 31, 1996 and 1995, the Company contributed
a total of $5,000 and $30,000 to the Plan, respectively, including $3,068 and
$18,505, respectively, for all executive officers as a group.
In March, 1995, the Board of Directors adopted an employee
incentive compensation plan whereby the proceeds equivalent to 1% net profits
interest (the "net profits interest") in all oil and gas properties, drilling
prospects and divestitures acquired or made after January 1, 1994 are paid into
a fund for incentive compensation awards to employees. For the year ended
December 31, 1996 and 1995, the Company paid $6,916 and $30,000, respectively,
to employees through the employee incentive plan, including $4,897 and $21,245
for all executive officers as a group.
III - 5
<PAGE> 51
The Company has no other retirement, pension/profit sharing or
other deferred compensation plan for its employees. The Company has granted
125,000 stock options to its employees and directors.
(e) Directors' Fees
Directors of the Company receive a fee of $500 per meeting and
are reimbursed for documented travel expenses. Certain nonemployee directors
have received stock options for their services as directors (see "Option Grants
in Last Fiscal Year," above).
ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
(a) Security Ownership of Certain Beneficial Owners
The following table sets forth the shares of the Company's
common and preferred stock beneficially owned by those persons known by the
Company to be the beneficial owner of more than five percent of the Company's
issued and outstanding common and preferred stock as of February 28, 1997:
<TABLE>
<CAPTION>
Title of Name and Address of Amount and Nature of Percent of
Class Beneficial Owner(1) Beneficial Ownership Class
----- ------------------- -------------------- -----
<S> <C> <C> <C>
Common Bay City Energy Group, Inc. 374,203 15.00%
115 S. Dearborn Street
Mobile, Alabama 36602
Common C. J. Lett, III(2) 1,167,556 46.90%
9320 East Central
Wichita, Kansas 67206
Series A Kaiser-Francis Oil Company 1,166,667 100.00%
Preferred(3) 6733 South Yale
Tulsa, Oklahoma 74136
</TABLE>
(1) Bay City Energy Group, Inc. is indirectly controlled by Edward P.
Turner, Jr., a director of the Company.
(2) Mr. Lett has agreed that, for a period of one year from February 28,
1997, his voting power will be restricted to not more than votes
representing 20% of the total number of shares of the Company's common
stock issued and outstanding and eligible to vote at the time in
connection with any vote taken or consent, waiver or ratification given
in connection with the election or removal of directors of the Company.
(3) The Series A preferred stock is nonvoting. Each Series A preferred
share is convertible, subject to certain adjustments, into two shares
of common stock.
III - 6
<PAGE> 52
(b) Security Ownership of Management
The following table sets forth the shares of the Company's
common stock beneficially owned by each director and executive officer and all
directors and executive officers as a group, all as of February 28, 1997:
<TABLE>
<CAPTION>
Title of Name and Address of Amount and Nature of Percent of
Class Beneficial Owner Beneficial Ownership Class
----- ---------------- -------------------- -----
<S> <C> <C> <C>
Common John J. Bassett 30,756 1.2%
3400 Peyton Court
Mobile, AL 36609
Common Frank C. Turner, II 21,500 0.9%
6201 Laurelwood Drive
Satsuma, AL 36572
Common Robert W. Hammons 21,200 0.8%
1013 Fribourg
Mobile, AL 36608
Common Lynn M. Davis 5,000 0.2%
121 Donna Circle
Daphne, AL 36526
Common Edward P. Turner, Jr. 402,575(1) 16.1%
100 Central Avenue
Chatom, AL 36518
Common C. J. Lett, III 1,167,556(2) 46.7%
9320 East Central
Wichita, KS 67206
Common Frank E. Bolling, Jr. 13,333 0.5%
3830 Kendale Drive
Gautier, MS 39553
Common C. Noell Rather 19,924 0.8%
3500 Oaklawn, Suite 380
Dallas, TX 75219
Common All executive officers and
directors as a group
(8 persons) 1,681,844(3) 67.3%
</TABLE>
III - 7
<PAGE> 53
(1) Includes 374,203 shares owned by Bay City Energy Group, Inc. in which
Mr. Turner has indirect voting control but not a direct beneficial
interest, and 15,038 shares over which Mr. Turner has sole voting and
dispositive power.
(2) Mr. Lett was named Executive Vice President of the Company on February
28, 1997 in connection with the Bison Merger (see "Business
Development--Recent Transaction"). Mr. Lett's voting rights are
restricted until February 28, 1998 (see Item 11(a) above).
(3) Includes presently exercisable options held by officers and directors
as follows: John J. Bassett - 20,000; Frank C. Turner, II - 20,000;
Robert W. Hammons - 20,000; Lynn M. Davis - 5,000; Edward P. Turner,
Jr. - 13,334; Frank E. Bolling, Jr. - 13,333; and C. Noell Rather -
13,333.
(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, parent and promoter of the Company,
is managing partner of the law firm of Turner, Onderdonk, Kimbrough & Howell,
P.A., the Company's general counsel for certain corporate and oil and gas
matters. For the years ended December 31, 1994 through 1996, the Company paid
legal fees to Mr. Turner's firm of $1,454, $787 and $1,560, respectively, for
legal services. Mr. Turner's firm charges the Company for its services on the
same basis as it charges other business clients for similar services rendered.
The Company intends to continue to use Mr. Turner's firm as its primary local
counsel and will pay reasonable fees for such future services.
Bay City Energy Group, Inc., is presently indebted to the Company in
the amount of $159,215 ($139,005 of principal and $20,210 of accrued interest).
The note payable was renegotiated on December 31, 1995 and is due in full on
January 1, 2001, plus interest at an annual fixed rate of 5%. The note payable
is secured by 75,000 shares of Company common stock.
On December 31, 1994, Bay City Minerals, Inc. contributed oil and gas
reserves valued at $186,938 to the Company as partial payment on the amount
owed. The value of the reserves was calculated by the Company's petroleum
engineer on a basis similar to the method used by Lee Keeling & Associates, Inc.
on the evaluation of the Company's reserves at year-end.
Bay City Minerals, Inc., acted as operator on behalf of the Company on
four oil and gas wells until April 1, 1994, when such operating rights were
transferred to the Company. The operating agreements and terms were
substantially similar to and at least as favorable as operating agreements
between the Company and unaffiliated operators. The amount paid to Bay City
Minerals, Inc. in 1994, for its services under the operating agreements was
$5,985.
III - 8
<PAGE> 54
On December 31, 1996, NPC Energy Corp., then a company indirectly
controlled by C. J. Lett, III through Bison Energy Corporation ("Bison"), merged
with the Company in exchange for 562,000 shares of common stock of the Company
and $1,226,400 cash. Subsequently, in February, 1997, the Company acquired Bison
as a wholly-owned subsidiary pursuant to an Agreement and Plan of Merger whereby
Mr. Lett received net cash consideration of $5.9 million plus 1,167,556 shares
of the Company's common stock, and the 562,000 shares held by Bison (as a result
of the NPC Merger) were canceled (see "Business Development").
[The remainder of this page has been intentionally left blank.]
III - 9
<PAGE> 55
PART IV
ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
<TABLE>
<CAPTION>
Sequential
Exhibit No. Description of Exhibit Page No.
----------- ---------------------- --------
<S> <C> <C>
2.1 Plan of Recapitalization for Reverse Split
effective March 21, 1995(2) N/A
3.1 Articles of Incorporation(1) N/A
3.2 Articles of Amendment to Articles of
Incorporation reflecting reverse split(2) N/A
3.3 Articles of Amendment to Articles of
Incorporation designating preferences
and rights of Series A Preferred Stock(4) N/A
3.4 Bylaws(1) N/A
10.1 1995 Stock Option and Stock Appreciation
Rights Plan(3) N/A
10.2 Stock Purchase Agreement dated September 4,
1996 between Kaiser-Francis Oil Company
and the Company(4) N/A
10.3 Agreement and Plan of Merger between the
Company and NPC Energy Corporation
dated December 17, 1996(5) N/A
11.1 Statement of Computation of Per-Share
Earnings
27 Financial Data Schedule (for SEC use only)
</TABLE>
(b) Reports on Form 8-K
A Current Report on Form 8-K was filed by the Company on
December 31, 1996 reporting the Agreement and Plan of Merger between NPC Energy
Corporation and the Company.
(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 December 31,
1996.
IV - 1
<PAGE> 56
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed by
the undersigned, thereunto duly authorized.
MIDDLE BAY OIL COMPANY, INC.
(Registrant)
By: /s/ John J. Bassett
------------------------------------
John J. Bassett, President
March 26, 1997
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated:
March 26, 1997 /s/ John J. Bassett
- --------------------- ------------------------------------------------
Date John J. Bassett
Director, President, Chief Executive and
Operating Officer
March 26, 1997 /s/ Frank C. Turner, II
- --------------------- ------------------------------------------------
Date Frank C. Turner, II
Director, Vice President, Chief Financial and
Accounting Officer
March 26, 1997 /s/ Edward P. Turner, Jr.
- --------------------- ------------------------------------------------
Date Edward P. Turner, Jr.
Director
March 26, 1997 /s/ Frank E. Bolling, Jr.
- --------------------- ------------------------------------------------
Date Frank E. Bolling, Jr.
Director
March 26, 1997 C. Noell Rather
- --------------------- ------------------------------------------------
Date C. Noell Rather
Director
<PAGE> 1
Exhibit 11.1
MIDDLE BAY OIL COMPANY, INC.
Statement of Computation of Per-Share Earnings
For the Year Ended December 31, 1996
<TABLE>
<CAPTION>
Fully
Primary Diluted
---------- ----------
<S> <C> <C>
Net Income $ 205,500 $ 205,500
---------- ----------
Adjusted Net Income $ 205,500 $ 205,500
========== ==========
Divided By:
Weighted Average Shares 1,304,464 1,304,464
Plus: Common Stock Equivalents
Stock Options 27,677 54,198
---------- ----------
Adjusted Weighted Average
Shares 1,332,141 1,358,662
---------- ----------
Earnings Per Share $ 0.154 $ 0.151
========== ==========
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE AUDITED
FINANCIAL STATEMENTS - BALANCE SHEETS FOR THE YEAR ENDED DECEMBER 31, 1996 AND
THE AUDITED STATEMENTS OF OPEERATIONS FOR THE YEAR ENDED DECEMBER 31, 1996 AND
IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> DEC-31-1996
<CASH> 556,026
<SECURITIES> 0
<RECEIVABLES> 1,129,417
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 1,743,580
<PP&E> 16,607,179
<DEPRECIATION> 5,332,517
<TOTAL-ASSETS> 13,184,980
<CURRENT-LIABILITIES> 957,397
<BONDS> 5,158,477
1,000,000
0
<COMMON> 37,618
<OTHER-SE> 4,999,524
<TOTAL-LIABILITY-AND-EQUITY> 13,184,980
<SALES> 4,474,786
<TOTAL-REVENUES> 4,886,421
<CGS> 1,516,011
<TOTAL-COSTS> 1,516,011
<OTHER-EXPENSES> 1,890,794
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 504,945
<INCOME-PRETAX> 280,371
<INCOME-TAX> 74,871
<INCOME-CONTINUING> 205,500
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 205,500
<EPS-PRIMARY> .15
<EPS-DILUTED> .15
</TABLE>
