-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, IW1fV32XsVPhaI9itBoIihXJ/ravt1a4q0E+cdkY8wyyITt1xdYJPDi2cZIXdxLe lDJtIVgJY2i/DgYfMEZPxA== 0000950144-98-011550.txt : 19981019 0000950144-98-011550.hdr.sgml : 19981019 ACCESSION NUMBER: 0000950144-98-011550 CONFORMED SUBMISSION TYPE: 10KSB40/A PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 19971231 FILED AS OF DATE: 19981016 SROS: NONE FILER: COMPANY DATA: COMPANY CONFORMED NAME: MIDDLE BAY OIL CO INC CENTRAL INDEX KEY: 0000903267 STANDARD INDUSTRIAL CLASSIFICATION: OIL AND GAS FIELD EXPLORATION SERVICES [1382] IRS NUMBER: 631081013 STATE OF INCORPORATION: AL FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10KSB40/A SEC ACT: SEC FILE NUMBER: 000-21702 FILM NUMBER: 98727192 BUSINESS ADDRESS: STREET 1: 1221 LAMAR ST STREET 2: SUITE 1020 CITY: HOUSTON STATE: TX ZIP: 77010 BUSINESS PHONE: 7137596808 MAIL ADDRESS: STREET 1: PO BOX 390 CITY: MOBILE STATE: AL ZIP: 36602 10KSB40/A 1 MIDDLE BAY OIL CO INC 1 ================================================================================ SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-KSB/A AMENDMENT NO. 2 TO ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year Commission file number 0-21702 ended December 31, 1997 MIDDLE BAY OIL COMPANY, INC. (Exact Name of Registrant as Specified in Its Charter) ALABAMA 63-1081013 (State or Other Jurisdiction of (I.R.S. Employer Incorporation or Organization) Identification No.) 1221 LAMAR STREET, SUITE 1020 HOUSTON, TEXAS 77010 (Address of Principal Executive Offices) (Zip Code) Registrant's telephone number, including area code: (713) 759-6808 Securities registered pursuant to Section 12(b) of the Act: Name of Each Exchange on Title of Each Class Which Registered - ------------------------ --------------------------- None N/A Securities registered pursuant to Section 12(g) of the Act: Common Stock, $.02 Par Value Check whether the Registrant (1) filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. [X] Check if disclosure of delinquent filers in response to Item 405 of Regulation S-B is not contained in this form, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-KSB or any amendment to this Form 10-KSB. [X] Revenues of Registrant for fiscal year ended December 31, 1997 are $11,432,995. The aggregate market value as of March 16, 1998 of voting stock held by nonaffiliates of the Registrant was $6,409,463. - -------------------------------------------------------------------------------- Indicate the number of shares outstanding of each of the Registrant's classes of common equity, as of the latest practicable date (applicable only to corporate Registrants). 7,830,766 Shares of Common Stock, $.02 Par Value, as of March 16, 1998 - -------------------------------------------------------------------------------- Item 13(a) includes the Index of Exhibits to be filed with the Securities and Exchange Commission relative to this Report. ================================================================================ This Amendment No. 2 on form 10-KSB/A contains expanded disclosure relating to the prior issuance and conversion of Series "A" Preferred Stock. No other information in the Report has been amended. 2 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. -i- 3 "Net Acres or Wells" - A party's interest in acres or wells calculated by multiplying the number of Gross Acres or Gross Wells in which such party has an interest by the fractional interest of such party in each such acre or well. "Operating Costs" - The expenses of producing oil or gas from a formation, consisting of the costs incurred to operate and maintain wells and related equipment and facilities, including labor costs, repair and maintenance, supplies, insurance, production, severance and other production excise taxes. "Producing Property" - A property (or interest therein) producing oil and gas in commercial quantities or that is shut-in but capable of producing oil and gas in commercial quantities, to which Producing Reserves have been assigned by an independent petroleum engineer. Interests in a property may include Working Interests, production payments, Royalty Interests and other non-Working Interests. "Prospect" - An area in which a party owns or intends to acquire one or more oil and gas interests which is geographically defined on the basis of geological data and which is reasonably anticipated to contain at least one reservoir of oil, gas or other hydrocarbons. "Proved Developed Reserves" - Proved Reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. "Proved Reserves" - The estimated quantities of crude oil, natural gas and other hydrocarbons which, based upon geological and engineering data, are expected to be produced from known oil and gas reservoirs under existing economic and operating conditions, and the estimated present value thereof based upon the prices and costs on the date that the estimate is made and any price changes provided for by existing conditions. "PV 10%" - The discounted future net cash flows for proved oil and gas reserves computed using prices and costs, at the dates indicated, before income taxes and a discount rate of 10%. "Royalty Interest" - An interest in an oil and gas property entitling the owner to a share of oil and gas production free of the costs of production. "Undeveloped Acreage" - Oil and gas acreage (including, in applicable instances, rights in one or more horizons which may be penetrated by existing well bores, but which have not been tested) to which Proved Reserves have not been assigned by independent petroleum engineers. "Working Interest" - The operating interest under a Lease which gives the owner the right to drill, produce and conduct operating activities on the property and a share of production, subject to all Royalty Interests, and other burdens and to all costs of exploration, development and operations and all risks in connection therewith. -ii- 4 PART I ITEM 1. DESCRIPTION OF BUSINESS (a) Business Development Middle Bay Oil Company, Inc. (the "Company") is an independent oil and gas company engaged in the exploration, development and production of oil and gas in the contiguous United States. The Company's strategy focuses on increasing its reserves of crude oil and natural gas by the acquisition and development of proved oil and gas properties primarily in the Mid-Continent and Gulf Coast regions. The Company believes the current period reflects historically low market prices for oil and gas and is focusing its efforts on increasing reserves so that it will be well positioned to benefit in the event of any future increases in demand for natural gas and oil. Consistent with these efforts, the Company is participating on a limited basis in drilling and development activities in other geographic regions of the contiguous United States. In November, 1997, the Company relocated its principal executive offices to 1221 Lamar Street, Suite 1020, Houston, Texas 77010. The Company's mailing address is P.O. Box 53448, Houston, Texas 77052-3448. Its telephone number is (713) 759-6808. The Company was incorporated under the Alabama Business Corporation Code on November 30, 1992. Effective December 31, 1992, all of the assets of Bay City Consolidated Partners, L.P., an Alabama limited partnership (the "Predecessor Partnership"), were transferred to the Company in exchange for common stock of the Company. The Predecessor Partnership was then dissolved under the Alabama Uniform Limited Partnership Act. The shares of common stock of the Company then owned by the limited partnership were distributed to the general partner and the limited partners prorata in accordance with their respective interests in the limited partnership. References to the Company include, as the context requires, the Predecessor Partnership. On April 3, 1996, the Company entered into a Joint Expense and Participation Agreement (the "Brigham Agreement") with Brigham Oil and Gas, L.P., now Brigham Exploration Company ("Brigham"). The Brigham Agreement allowed the Company to participate in all of the wells that Brigham drilled over the 12-month period beginning April 1, 1996. The Company advanced Brigham a total of $1,945,000 to drill 61 wells, of which 43 were successfully completed. On September 4, 1996, the Company entered into a stock purchase agreement ("the Preferred Stock Agreement") with Kaiser Francis Oil Company ("Kaiser-Francis") whereby Kaiser-Francis agreed to purchase 1,666,667 shares of Series A Preferred Stock (the "Series A") at $6.00 per share, for a total investment of $10,000,000. On January 31, 1998, Kaiser-Francis converted 100% of the Series A shares into 3,333,334 common shares of the Company. Prior to their conversion to common stock, the Series A were nonvoting and accrued dividends at 8% per annum, payable quarterly in cash, and were convertible at any time into two shares of common stock for each Series A share held prior to January 1, 1998. The conversion rate decreased thereafter at 8% per annum. Kaiser-Francis is a privately-held company whose majority shareholder is George B. Kaiser. I-1 5 On December 17, 1996, the Company entered into an Agreement and Plan of Merger (the "NPC Merger") with NPC Energy Corporation ("NPC"), whereby NPC would be merged into the Company in exchange for Company common stock and cash. The NPC Merger was approved by NPC's shareholders and closed on December 31, 1996. NPC was a privately-owned domestic exploration and production company with assets located in Kansas, Michigan, Oklahoma, Texas and Wyoming. Pursuant to the NPC Merger, the Company issued 562,000 shares of its common stock and paid $1,226,400 to NPC in exchange for all of the stock of NPC. The cash funding for the NPC Merger was financed through the issuance of 166,667 shares of Series A for $1.0 million. The NPC Merger added approximately 503 thousand barrels of oil and 3,139 million cubic feet of gas, for a total proved reserve value of $6.0 million (PV 10%) as of December 31, 1996, using December 31, 1996 prices. On February 10, 1997, the Company entered into an Agreement and Plan of Merger (the "Bison Merger") with Bison Energy Corporation ("Bison"), whereby Bison was merged with a wholly-owned subsidiary of the Company in exchange for Company common stock and cash. The Bison Merger was approved by Bison's sole shareholder and closed on February 28, 1997. Bison was a privately-held, domestic exploration and production company with assets located in Kansas and Oklahoma. Pursuant to the Bison Merger, the Company issued 1,167,556 shares of its common stock and net cash consideration of $5,900,000 to Bison in exchange for all of the stock of Bison. 562,000 shares of Company common stock owned by Bison (as a result of the NPC Merger) were canceled at closing. The cash portion of the Bison Merger was financed through the issuance of 1,000,000 shares of Series A for $6.0 million. The Bison Merger added approximately 951 thousand barrels of oil and 7,791 million cubic feet of gas, for a total proved reserve value of $8.94 million (PV 10%) as of February 28, 1997, using December 31, 1997 prices. On June 20, 1997, the Company entered into an Agreement and Plan of Merger (the "Shore Merger") with Shore Oil Company ("Shore"), whereby Shore was merged with a wholly-owned subsidiary of the Company in exchange for Company common stock, Series B preferred stock (the "Series B"), cash and the assumption of Shore debt. The Shore Merger was approved by Shore's shareholders and closed on June 30, 1997. Shore was a privately-held, domestic exploration and production company with oil and gas properties located primarily in Alabama, Louisiana, Mississippi and Texas, as well as approximately 42,000 net mineral acres in LaFourche, Terrebonne and St. Mary Parishes, Louisiana. Pursuant to the Shore Merger, the Company issued 1,883,333 shares of its common stock, paid Shore's indebtedness to its shareholders of $2,333,303 and assumed bank debt of $2,105,000. In addition, the Company paid $200,000 in cash and issued 266,667 shares of Series B which are convertible into as many as 1,333,333 shares of common stock over the next five years, contingent upon the results of drilling and leasing activity on Shore's Louisiana mineral acreage. The cash funding for the Shore Merger was financed through the issuance of 500,000 shares of Series A for $3.0 million. The Shore Merger added approximately 965 thousand barrels of oil and 1,364 million cubic feet of gas, for a total proved reserve value of $6.0 million (PV 10%) as of July 1, 1997, using December 31, 1997 prices. The Shore Merger also added approximately 42,000 net acres of fee minerals situated in Lafourche, Terrebonne and St. Mary Parishes in Louisiana that were valued at approximately $3.6 million at June 30, 1997. In connection with the Shore Merger, effective August 25, 1997, the Bank of Oklahoma, National Association (the "Bank") converted the Company's $15 million convertible credit facility into a $50 million convertible credit facility. The credit facility requires monthly payments of interest only I-2 6 at a fixed rate of Libor plus 1.75% as long as the principal amount borrowed is less than 75% of the current borrowing base of $15 million. If the principal amount of the loan is greater than or equal to 75% of the borrowing base the rate increases to Libor plus 2.00%. The Company has the option of switching to a floating prime rate. The credit facility converts into a term note on March 31, 1998 payable in seventy-one consecutive equal monthly principal and interest payments, with the remaining principal and interest payment due on March 31, 2004. The credit facility is secured by a first mortgage on a portion of the Company's existing properties selected by the Bank as collateral from time to time, and the Bank has an option to collateralize 100% of the Company's proved reserves. In the event that a mortgaged property is sold, upon prior written consent of the Bank, the greater of 65% of the gross sales price or 65% of the discounted present worth of the mortgaged property will be applied to the outstanding principal balance of the loan in the inverse order of the due date of scheduled monthly installments. The significant financial covenants contained in the Convertible Loan Agreement include a requirement that the Company maintain a balance sheet current ratio of at least 0.9 to 1.0. The current ratio computation excludes all accounts receivable from certain affiliates and current maturities of long-term debt. The Convertible Loan requires the prior written consent of the Bank before the Company can, among other things, (a) create or assume any debt, with specified exceptions, (b) create or permit to exist any liens on the mortgaged properties, with certain exceptions, (c) sell or dispose of any property if such sale or disposition exceeds $150,000 per transaction, or (d) merge into or consolidate into any other entity. The initial borrowing base at closing of the $50 million Convertible Loan on August 25, 1997, was $15 million. The borrowing base is redetermined on March 31 and September 30, commencing September 30, 1997, by the Bank's engineers or any other independent engineer using the Bank's pricing and discount factors and the future net revenue expected to be produced from the Company's oil and gas reserves. If at any time during the period of the loan (and the period subsequent to the conversion to the term note) the collateral borrowing base, as determined by the Bank, should be less than the aggregate unpaid principal balance of the note, the collateral deficiency shall be cured by making a cash prepayment on the note in the amount of the deficiency or by increasing the monthly principal payments for the next six months to reduce the principal balance to the projected borrowing base as of the next semiannual redetermination date. As of December 31, 1997, the principal balance of the loan was $10,956,298. I-3 7 (b) Business of the Company The Company's oil and gas reserves are principally in long-lived fields with well-established production histories. The Company's net Proved Reserves, estimated as of December 31, 1997 by applying S.E.C. assumptions, consisted of approximately 18,419 million cubic feet of gas and 2,933 thousand barrels of oil, with an aggregate present value before income taxes, at a 10% discount, of $30,179,000. Approximately 80% of the reserves are classified as proved developed producing, 7% are proved developed non-producing and 13% are proved undeveloped. On an equivalent barrel basis, the proved reserves are 55% gas. Recoverable volumes of gas increased 105% and recoverable volumes of oil increased 111% over 1996 volumes. The PV10% of the oil and gas reserves increased 34% over the 1996 amount of $22,465,000. The reserves are located primarily in Alabama, Kansas, Louisiana, Oklahoma and Texas. A substantial portion of the Company's natural gas production and Proved Reserves consist of high BTU gas which, because of its rich liquid content and its proximity to processing and transmission facilities, is generally sold at a premium to Gulf Coast and Mid-Continent spot market prices. Substantially all of the Company's oil production is sold at market responsive prices. All of the Company's gas production, except for the gas sold in the Spivey Field, is sold at market responsive prices. Business Strategy. The Company's present business strategy is to concentrate on expanding its asset base and cash flow primarily through emphasis on the following activities: - Increasing production, cash flow and asset value by acquiring Producing Properties with stable production rates, long reserve lives and potential for exploitation and development; - Building on the Company's existing base of operations by concentrating its development activities in its primary operating areas in the Gulf Coast and the Mid-continent Regions; - Acquiring additional properties with potential for developmental drilling to maintain a significant inventory of undeveloped Prospects and to enhance the Company's foundation for future growth; - Serving as operator of its wells to ensure technical performance and reduce costs; - Expanding its relationships with major and large independent oil and gas companies to access their undeveloped properties, seismic data and financial resources; I-4 8 - Managing financial risk and mitigating technical risk by: - drilling in known productive trends with multi-horizon geologic potential; - diversifying investment over a large number of wells in the Company's primary operating areas; - developing properties that provide a balance between short and long reserve lives; and - keeping a balanced reserve profile between oil and gas; and - Maintaining low general and administrative expenses and increasing economies of scale to reduce per unit operating costs and reserve acquisition costs. Acquisition Policy. The Company continues to pursue a program of actively acquiring producing oil and gas properties, with the goal of increasing cash flow, reserves and value for the long-term benefit of its stockholders. The Company utilizes an acquisitions' screening approach with its experienced management and technical staff which reviews potential property against multiple criteria, both quantitative and subjective. The Company generally seeks Producing Properties with established production histories. The Company may operate the property acquired; however, the Company also considers nonoperated property acquisitions. In evaluating Producing Properties for potential acquisition, production history, reservoir characteristics and available geologic data and interpretations are analyzed to determine estimates of proved and other reserves and cash flows expected to be recovered. Also evaluated are specific risks and economic considerations associated with the property, including environmental liabilities, risks of curtailment, condition of equipment and potential for additional development opportunities. Sales contracts, operating agreements and other contractual commitments, including take-or-pay clauses, market-out clauses, gas balancing agreements, transportation agreements and reversionary interests that may affect the cash flows from the property are also reviewed. Drilling Activities. The Company has participated in drilling operations primarily in Texas, Louisiana and Kansas. The Company's drilling activity increased significantly in 1996 when the Company executed the Brigham Agreement. The Company's drilling is funded principally from cash flow and is highly dependent on the price of oil and gas. If the price of oil continues to remain at or near the March 1998 levels, the amount of funds available for drilling could be reduced. For the twelve months ended December 31, 1997, the Company drilled 42 gross wells; 23 Development Wells and 19 Exploratory Wells. Seventeen of the Development Wells and 8 of the Exploratory Wells were successful. The Company's drilling was concentrated in Kansas, Louisiana and Texas, where 14, 12 and 7 wells were drilled, respectively. The majority of the Kansas wells were Development Wells drilled in the Spivey Field (the "Spivey Field"). Two unsuccessful Exploratory Wells were drilled in the Reflection Ridge Prospect in Stanton County, Kansas. No further exploration is anticipated on the Reflection Ridge Prospect. For the three months ended March 31, 1997, the Company participated in the drilling of 12 Exploratory Wells through the Brigham Agreement. The Brigham Agreement ended March 31, 1997. I-5 9 Shore Oil Company #1, an Exploratory Well being drilled as of December 31, 1997, was found to be unsuccessful in February, 1998. This Exploratory Well was drilled on the Raceland Prospect in Lafourche Parish, Louisiana which is located on the fee mineral acreage acquired in the Shore Merger. The Company had prepaid approximately $300,000 in drilling cost as of December 31, 1997 and expensed the costs in the fourth quarter when it was determined that the well was abandoned. For the twelve months ended December 31, 1996, the Company drilled 54 wells, 5 Developmental Wells and 49 Exploratory Wells. Four of the Developmental Wells and 31 of the Exploratory Wells were successful. For the nine months ended December 31, 1996, the Company participated in the drilling of 49 Exploratory Wells through the Brigham Agreement. Forty wells were drilled in Texas, seven in Oklahoma, one in Kansas and one in New Mexico. The Company also participated in the drilling of four Developmental Wells in the Frymire Waterflood Unit in Nolan County, Texas, three of which were successful and one of which was a dry hole. One successful Developmental Well was drilled in the Campbell Field in Major County, Oklahoma. Drilling activities during 1997 added 22 thousand barrels of oil and 705 million cubic feet of gas with estimated future net revenues, discounted at 10%, of $851,000. Drilling activities during 1996 added 76 thousand barrels of oil and 392 million cubic feet of gas with estimated future net revenues, discounted at 10%, of $1,966,000. For the years 1996 and 1997, oil and gas reserves discovered through current year drilling accounted for 11% and 3%, respectively, of the year-end reserve value. In 1995, the Company entered into a joint development agreement, the Quarry Prospect, with Chesapeake Operating, Inc. ("COI"). The agreement covers a 600-acre block of leases in Lea County, New Mexico assembled by the Company and COI. The Quarry Prospect is believed to be a large strawn algal mound that was initially identified through 2-D seismic and further defined using 3-D seismic testing. In 1997, the Company acquired additional leases in the prospect and sold 50% of the Quarry Prospect. The Company and COI together retained 50% of the Quarry Prospect. If COI elects not to participate, the Company's interest will be increased to 50%. The first well on the Quarry Prospect is expected to spud in the second quarter of 1998 and will cost the Company approximately $141,000 to drill and $66,000 to complete (assuming a 25% working interest). In July 1997, the Company executed an exploration agreement with Brigham Exploration Company ("Brigham") for a 3-D seismic exploration project on the Hawkins Ranch (the "Ranch") in Matagorda County, Texas. The Ranch has been lease optioned for a 54 square mile 3-D seismic survey. The Company purchased a 25% working interest through the lease selection phase of the project for $225,000. I-6 10 The Company purchased a 12.5% working interest in the Sherburne Prospect in Point Coupee Parish, Louisiana, in October, 1997 (the "Sherburne Prospect"). The Sherburne Prospect consists of approximately 10,000 acres that are prospective in the Frio, Cockfield, Sparta and Wilcox formations. The acreage is located in Southwest Point Coupee Parish between Krotz Springs Field and the Fordoche Field. Production is at depths from 6,500' to 15,500'. Swift Energy Company has a 62.5% working interest and will be the operator. A private company holds the remaining 25%. The first well was spud on March 11, 1998 with an estimated dry hole cost to the Company of approximately $300,000. In the foreseeable future, the Company's primary drilling focus will be its participation in the Sherburne Prospect, the Ranch Prospect, the Quarry Prospect and the development of the Spivey Field. The Company expects to drill several Development Wells in the Spivey Field in Kansas in 1998. The Company also expects several wells to be drilled on the Shore mineral acreage in South Louisiana in 1998. In addition, the Company is continually evaluating Prospects originated by its staff, other independent geologists or other oil and gas companies. If review of a certain Prospect indicates that it may be geologically and economically attractive, then the Company will attempt to obtain a Lease on the applicable acreage or commit to a Working Interest in the drilling Prospect. When the Company does participate in a Prospect, it will typically acquire a fractional Working Interest in the Prospect, which may range from small percentage interests in more expensive exploratory Prospects to a majority interest in a lower cost or development Prospect. The Company believes that such participation, which is common practice in the oil and gas industry, allows for further diversification and reduction of risk. Acquisitions and Mergers. Since its formation, the Company has grown primarily through acquisitions of proven oil and gas reserves. For the years 1993 through 1997, acquisitions of reserves accounted for 64%, 5%, 35%, 34% and 80% of the year-end discounted reserve value, respectively. The Company has financed its acquisitions primarily by utilizing its credit facility with the Bank and issuing common and preferred stock. (See "Company Financing," below.) In August 1997, the Company acquired a 5.74% working interest in proved reserves in the Riceville Field in Vermilion Parish, Louisiana for approximately $3.5 million. The acquisition was financed with $3 million in loan proceeds and the remainder from cash on hand. The Riceville Acquisition added approximately 63 thousand barrels of oil and 2,955 million cubic feet of gas to the Company's proved reserves. A portion of the reserves is proved undeveloped. The Riceville Acquisition had a PV10% of approximately $5.3 million, using December 31, 1997 prices. The Shore Merger in June 1997 added approximately 965 thousand barrels of oil and 1,364 million cubic feet of gas to the Company's proved reserves. A portion of the reserves consists of proven behind pipe and proven undeveloped reserves. The Shore Merger had a PV 10% of approximately $6.0 million, using December 31, 1997 prices. The Shore Merger also added approximately 42,000 net acres of minerals located in South Louisiana, which were valued at $3.6 million at June 30, 1997. I-7 11 The Bison Merger in February, 1997 added approximately 951 thousand barrels of oil and 7,791 million cubic feet of gas to the Company's proved reserves. A portion of the reserves consists of proven behind pipe and proven undeveloped reserves. The Bison Merger had a PV 10% of approximately $8.9 million, using December 31, 1997 prices. The NPC Merger in December, 1996 added approximately 503 thousand barrels of oil and 3,139 million cubic feet of gas to the Company's proved reserves. A portion of the reserves consists of proven behind pipe and proven undeveloped reserves. The NPC Merger had a PV 10% of approximately $6.0 million, using December 31, 1996 prices. The Company is currently in the process of evaluating various corporate acquisitions and potential mergers in exchange for common stock of the Company. Management believes that corporate acquisitions and mergers are the fastest way to achieve the Company's growth goals. In addition to achieving what management perceives to be a proper critical mass, potential corporate acquisitions or mergers are also considered as opportunities to build a more diverse oil and gas property base for further development and exploration. The price of oil has declined significantly since December 31, 1997 and, in March, 1998, reached the lowest level in ten years. The posted price of WTI crude declined from approximately $15 per barrel on December 31, 1997 to approximately $13 per barrel on March 16, 1998. If oil prices remain at or near these levels, the funds available for acquisitions could be reduced. Company Financing. The Company has financed its acquisitions with debt proceeds from the Bank, issuance of convertible preferred stock and issuance of common stock. The Company currently has approximately $11 million borrowed on the $50.0 million Convertible Loan with the Bank of Oklahoma described under "Business Development," above. In 1997, the Company issued the remaining $9.0 million in Series A Preferred Stock through its $10.0 million Preferred Stock Agreement to finance portions of the Bison and Shore mergers. This completed the funding of the $10.0 million Preferred Stock Agreement with Kaiser-Francis, which was signed in September, 1996. In 1997, the Company issued $3.627 million of Series B Preferred Stock to finance a portion of the Shore Merger. The Company also issued its common stock in connection with the Bison and Shore mergers. The Company's drilling activities have been financed primarily through the Company's cash flow. Subject to availability of bank financing, the Company will continue to consider debt-financed acquisitions presented to it by the Company. The Company intends to finance acquisitions by issuing common stock and/or preferred stock when possible. Competition, Markets and Regulation. Competition in the exploration and property acquisition markets is intense. In seeking to obtain desirable Leases and exploration Prospects, the Company faces competition from both major and independent oil and gas companies, as well as from numerous individuals. Many of these competitors have substantial financial resources available to them, which makes for increased competition. I-8 12 The ability of the Company to market oil and gas from its wells will depend upon numerous factors beyond its control, including, but not limited to, the extent of domestic production and imports of oil and gas, the proximity of the Company's production to existing pipelines, the availability of capacity in such pipelines and state and federal regulation of oil and gas production. There is no assurance that the Company will be able to market all of the oil or gas produced by it or that favorable prices can be obtained for the oil and gas it produces. In view of the uncertainties affecting the supply and demand of oil and gas, the Company is unable to accurately predict future oil and gas prices and demand, or the overall effect they will have on the Company. Numerous federal and state laws and regulations affect the Company's operations. In particular, oil and gas production operations are affected by tax and other laws relating to the petroleum industry and any changes in such laws and regulations. Some of the rules and regulations carry substantial penalties for failing to comply. The regulatory burden on the oil and gas industry increases the Company's cost of doing business. The Company's activities are also subject to numerous federal, state and local environmental laws and regulations governing the discharge of materials. In most cases, the applicable regulatory requirements relate to water and air pollution control or solid waste management measures. The Company believes the recent trend toward stricter standards in environmental legislation, regulation and enforcement will continue. To date, these laws have not had a significant impact on the Company but no assurance can be given as to the effect of these laws on the Company in the future. Employees. As of December 31, 1997, the Company employs seventeen full-time persons. The Company employs eleven full-time persons in its Houston, Texas office, including four executive officers, whose functions are associated with management, engineering, geology, land and legal, accounting, financial planning and administration. The Company employs four full-time persons in its Wichita, Kansas office, including one executive officer, a geologist, an engineer and an administrative assistant. The Company also employs one full-time supervisor for well operations in Oklahoma and one full-time accountant in Mobile, Alabama. ITEM 2. DESCRIPTION OF PROPERTY (a) Real Estate Properties The Company owns a historic home in Mobile, Alabama which previously served as its corporate office before the Company's relocation to Houston, Texas in November 1997. The Company has listed the property for sale. (b) Oil and Gas Properties More than 95% of the Company's oil and gas properties, reserves and activities are located onshore in the continental United States, primarily in Alabama, Kansas, Louisiana, Oklahoma and Texas. Estimates of total proved net oil or gas reserves have not been filed with or included in reports to any federal authority or agency. There are no quantities of oil or gas subject to long-term supply or similar agreements with foreign governmental authorities. I-9 13 The Company's largest oil and gas property, in terms of dollar value, is the Spivey Field acquired in the Bison Merger. The Spivey Field, located in Kingman and Harper Counties, South Central Kansas, was discovered in 1949. Development of oil and gas reserves from the Mississippian Chert Formation, at an average drilling depth of 4,250 feet, has been continual since discovery. Currently, approximately 585 active wells produce in the field. Great lateral extent, thick pay sections, and long-lived production characterize the reservoir. The Spivey Field has cumulative gas production of over 75,000 million cubic feet. Gas is marketed to the spot markets and to the Spivey Gas Plant (the "Plant"). Over 95% of Company gas is sold to the Plant under a life of the lease casinghead tailgate gas contract. The Company owns approximately 11.5% ownership in the Plant and related gathering system. Warren Petroleum Company, L.P., and NGC Corporation jointly operate the Plant. Ownership in the Plant is redetermined annually, based on owner's throughput relative to total throughput. Plant liquids (propane, butane and natural gas) are marketed from the Plant to Murphy Energy. Residue gas is sold to KGE (fka Kansas Power and Light) for a tailgate price of $2.91 per Mcf. The tailgate contract calls for an annual escalation of $0.02 per Mcf. The Btu factor for the residue gas is 1.042. Plant owners also receive the benefit of buying, stripping and reselling "Non-Owner" field gas. The Spivey Field has cumulative oil production of over 66.6 million barrels of oil. Lease oil is marketed to Koch Oil Company, via truck, and a bonus above posted prices is received. The Company operates approximately 80 wells in the Spivey Field from a field office in Attica, Kansas, staffed by one foreman and two Company pumpers. All oilfield services are present in the field. Exploration, engineering and land functions are directed from the division office located in Wichita, Kansas. The Company is continually developing its acreage position of approximately 8,500 gross acres. As of December 31, 1997, the Company has identified and independent engineers have evaluated twenty-two proven undeveloped locations in the Spivey Field with a PV 10% value of approximately $2.4 million. At December 31, 1997, the Plant was valued by independent engineers at $2.9 million PV 10%. I-10 14 The following table shows proved oil and gas reserves by major field for the Company's largest producing fields at December 31, 1997. The values represent the present value of estimated future net cash flows before income taxes, discounted at 10%, assuming unescalated expenses and prices of $16.18/Bbl and $2.54/MMBtu attributable to proved reserves at December 31, 1997, as determined by several independent reserve engineers.
Discounted Percentage Oil Gas Field Name/ Primary Present of Total Reserves Reserves County/State Operator Value Present Value (Bbls) (Mcf) ------------ -------- ----- ------------- ------ ----- (Dollars/quantities in thousands) Spivey Company $9,329 30.9% 993 11,415 Harper/Kingman, KS Riceville Field Murphy 4,958 16.4% 50 2,244 Vermillion, LA Hatters Pond Texaco 1,019 3.4% 71 187 Mobile, AL Wright Field Hilcorp 735 2.4% 96 150 Vermilion, LA Murphy Lake Amerada Hess 587 1.9% 99 -- St. Martin, LA Lockhart Crossing Amoco 488 1.6% 10 270 Livingston, LA Polo Field Lu-Ray 481 1.6% 141 5 Noble, OK Abbeville Company 473 1.6% 3 279 Vermilion, LA Okeene N.W. Ricks Expl. 443 1.5% 11 507 Major,OK N. Frisco City Torch Energy 443 1.5% 33 32 Monroe, AL Others Various 11,223 37.2% 1,426 3,330 -------- ----- ----- ------ Total $ 30,179 100.0% 2,933 18,419 ======== ===== ===== ======
As of December 31, 1997, the Bank has a first mortgage on all of the fields listed in the above table. The Bank also has a first mortgage on numerous additional fields not individually listed above which I-11 15 in total gives the Bank a first mortgage on approximately 75% of the Company's total reserves (PV 10%) of $30,179,000 before income tax. The Company is obligated, within five days of request by the Bank, to grant the Bank a first and prior mortgage on any oil and gas properties owned or acquired by the Company. (c) Louisiana Fee Mineral Acreage In the Shore Merger, the Company acquired approximately 42,321 net mineral acres, situated in Terrebonne, Lafourche and St. Mary Parishes in Louisiana. Of the total acreage, 39,769 acres are non-producing and the remainder is held by production under existing leases. The non-producing acreage is located in the following parishes: 20,587 in Terrebonne (Montegut and Houma areas), 11,128 acres in Lafourche (Raceland and Valentine areas) and 8,054 acres in St. Mary Parish (Charenton area). The non-producing acreage currently under lease and/or option has expiration dates as follows: 17,835 acres in 1998 and 5,722 acres in 2000. As of December 31, 1997, 16,212 acres were not under lease. Royalty interest in the leases covering the non-producing minerals ranges from 20% to 25%. The mineral servitude prescription dates are estimated by the Company to be as follows: 620 acres prescribed in 1997, 6,226 acres in 1999, 5,286 acres in 2002, 4,145 acres in 2004, 1,121 acres in 2005, 1,145 acres held in perpetuity and the remaining acreage has prescription interrupted by production. Effective April 1, 1992 Shore Oil Company sold the production rights under tracts producing at that time and does not receive royalty income from the sale of oil or gas on those tracts. Over 80% of the non-producing minerals have been covered by 3-D seismic shot by third parties and provided to the Company at no cost. During the period July 1, 1997 through December 31, 1997, the Company received approximately $975,000 in lease bonus, delay rental and seismic option income on the acreage. An independent oil and gas engineering firm valued the acreage as of June 30, 1997 at $3,627,000. One unsuccessful Exploratory Well in Lafourche Parish, the Shore Oil Company #1, was drilled on the fee mineral acreage in 1997 and abandoned in February 1998. (d) Productive Wells and Acreage The following table depicts the number of gross and net producing wells and related Developed and Undeveloped Acreage in which the Company owned an interest for the period ended December 31, 1997 Undeveloped Acreage is oil and gas acreage (including, in certain instances, rights in one or more horizons which may be penetrated by existing well bores, but which have not been tested) to which Proved Reserves have not been assigned by independent petroleum engineers. I-12 16 The Company's net Developed Acreage is located primarily in Oklahoma, Texas, Alabama, New Mexico and Kansas. The Company's net Undeveloped Acreage is located in Kansas.
Acreage ------------------------------------ Developed Undeveloped --------- ----------- Gross Acres 239,646 9,758 Net Acres 20,337 8,643 Productive Wells ------------------------------------ Oil Gas --- --- Gross Wells 797.00 184.00 Net Wells 68.67 30.13
Excluded from the acreage data are approximately 44,041 net mineral acres owned by the Company, all of which are considered to have potential for oil and gas exploration. (e) Production, Prices and Costs Below is a summary of the net production of oil and gas, average sales prices and average production costs during each of the last three fiscal years. The Company is not obligated to provide a fixed and determined quantity of oil and gas in the future under existing contracts or agreements. During the last three fiscal years, the Company has not had, nor does it now have, any long-term supply or similar agreements with governments or authorities.
Fiscal Years Ended December 31, ------------------------------------------- 1995 1996 1997 ---- ---- ---- Crude Oil and Natural Gas Production: Oil (Bbls) 107,025 108,626 253,849 Gas (Mcf) 916,954 982,709 1,929,298 Average Sales Prices: Oil (per Bbl) $16.17 $20.26 $18.38 Gas (per Mcf) $1.52 $2.28 $2.39 Average Production Costs Per BOE(1) $5.25 $5.36 $6.69
(1) The components of production costs may vary substantially among wells, depending on the methods of recovery employed and other factors, but generally include severance taxes, administrative overhead, maintenance and repair, labor and utilities. I-13 17 (f) Drilling Activities During the periods indicated, the Company drilled or participated in the drilling of the following productive and nonproductive Exploratory and Development Wells. All of the Company's drilling and production activities are conducted with independent contractors.
Year Ended December 31, --------------------------------------- Exploratory Wells: 1995 1996 1997 ----- ------ ------ Productive Gross 0 31 8 Net 0 0.987 0.452 Dry Gross 0 18 11 Net 0 0.675 1.280 Development Wells: Productive Gross 0 4 17 Net 0 0.866 5.627 Dry Gross 2 1 6 Net 0.418 0.250 4.150 Total Wells: Productive Gross 0 35 25 Net 0 1.853 6.079 Dry Gross 2 19 17 Net 0.418 0.925 5.430
As of March 16, 1998, the Company was drilling one Exploratory Well on the Sherburne Prospect. (g) Reserves Note 11 to the Company's financial statements presents, among other disclosures prepared pursuant to Statement of Financial Accounting Standards No. 69, the estimated net quantities of the Company's proved oil and gas reserves and the standardized measure of discounted future net cash flows attributable to such reserves as of December 31, 1997. At December 31, 1997, the Company's net Proved Reserves consisted of 2,933 thousand barrels of oil and 18,419 million cubic feet of gas, and net Proved Developed Reserves consisted of 2,580 thousand barrels of oil and 14,251 million cubic feet of gas. At December 31, 1997, the present value discounted at 10% for the Company's Proved oil and gas reserves, before income taxes, was approximately $30,179,000. (See Note 11 to the Company's financial statements for additional detail on the Company's oil and gas reserves.) Management of the Company, however, cautions against using this data to determine the fair value of the Company's oil and gas properties or for any other purpose because the price of oil and gas can be volatile. The present value was computed using December 31, 1997 base oil prices of I-14 18 $16.18 per Bbl and base gas prices of $2.54 per MMBtu. Base prices were adjusted for certain properties that either received a price above or below the base price. There were no estimates or reserve reports of the Company's proved oil and gas reserves filed with any governmental authority or agency during the year ended December 31, 1997. The following table sets forth the standardized measure (in thousands of dollars) of future net cash flows of Proved Reserves and total recoverable volumes of oil and gas from Proved Reserves attributable to the Company's interest in oil and gas wells for the years ended December 31, 1997 through 1995:
Recoverable Volumes ------------------- Standardized Oil Gas Year Ended Measure (MBbls) (MMcf) ---------- ------- ------- ------ December 31, 1997 $24,493 2,933 18,419 December 31, 1996 $17,863 1,389 8,964 December 31, 1995 $9,250 778 6,371
The increases in the standardized measure from 1995 to 1996 and 1996 to 1997 are due primarily to the NPC Merger in 1996 and the Bison and Shore Mergers and Riceville Acquisition in 1997. For a detail of changes in oil and gas reserves for the year, refer to Note 11 to the Company's financial statements. The reserve data set forth in this Form 10-KSB represents only estimates. Reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and adjustment. As a result, estimates of different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of crude oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas reserves and of future net revenues are based upon a number of variables and assumptions, including future prices of oil and gas, all of which may vary considerably from actual results. The reliability of such estimates is highly dependent upon the accuracy of the assumptions from which they were based. ITEM 3. LEGAL PROCEEDINGS The Company is a defendant in various legal proceedings which are considered routine litigation incidental to the Company's business, the disposition of which management believes will not have a material effect on the financial position or result of operations of the Company. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS There were no matters submitted to a vote of security holders of the Company during the fourth quarter of the fiscal year ended December 31, 1997. I-15 19 PART II ITEM 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS (a) Market Information The Company Common Stock is quoted on the NASDAQ Small Cap Market tier of the NASDAQ Stock Market under the symbol "MBOC". The Common Stock began trading on NASDAQ Small Cap Market on September 29, 1995. At present, the stock does not have any retail brokerage coverage. The following quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission, and may not represent actual transactions:
Period High Bid Low Bid ------ -------- ------- 1996 First Quarter $3.38 $2.75 Second Quarter 3.38 2.75 Third Quarter 3.25 2.50 Fourth Quarter 6.00 3.00 1997 First Quarter $9.25 $5.50 Second Quarter 12.50 7.75 Third Quarter 11.50 8.75 Fourth Quarter 11.13 9.00
On March 16, 1998, the closing price of the common stock was $5.13 bid and $6.50 asked. (b) Holders As of March 16, 1998, the Company had 738 holders of record of its common stock, which does not include an unknown number of additional holders whose stock is held in "street name." (c) Dividends; Dividend Policy The Company has never paid any dividends on its common stock. The terms of the Company's credit facility with the Bank of Oklahoma prohibit the Company from making distributions of any kind, type or nature, cash or otherwise on its common stock. In any event, the Company expects to retain all available earnings generated by its operations for the development and growth of its business and does not anticipate paying any cash dividends in the foreseeable future. Any future II - 1 20 determination as to the payment of dividends will be made at the discretion of the Board of Directors and will depend on a number of factors, including the future earnings, capital requirements, financial condition and future Prospects of the Company, restrictions in the Company's current or future financing agreements (such as the Convertible Loan) and any other factors as the Board of Directors may deem relevant. ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS The following discussion should be read in conjunction with the Company's financial statements and notes thereto set forth in Item 7. (a) Results of Operations The factors that most significantly affect the Company's results of operations are (i) the sales price of crude oil and natural gas, (ii) the level of production volumes, (iii) the level of lease operating expenses, and (iv) the level of interest rates. Sales of production and level of borrowing are significantly impacted by the Company's ability to maintain or increase its production from existing oil and gas properties or through its exploration and development activities. Sales prices received by the Company for oil and gas have fluctuated significantly from period to period. The fluctuations in oil prices during these periods reflect market uncertainty regarding the inability of OPEC to control the production of its member countries, production from Iraq, as well as concerns related to the global supply and demand for crude oil. Gas prices received by the Company fluctuate generally with changes in the spot market price for gas. Relatively modest changes in either oil or gas prices significantly impact the Company's results of operations and cash flow and could significantly impact the Company's borrowing capacity. The table below details the changes in oil and gas revenues, excluding plant and other revenues, caused by price and volume changes for the years ending December 31, 1997, 1996 and 1995.
1997 1996 1995 ---------- -------- --------- Oil Revenues Change due to volume $2,942,138 $ 32,436 $ 576,865 Change due to price (478,122) 437,285 102,558 Total change 2,464,016 469,271 679,423 Gas Revenues Change due to volume $2,161,383 $149,921 $ 277,755 Change due to price 201,483 708,386 (182,391) Total change 2,362,866 858,307 95,364
(b) Fiscal 1997 Total revenues for the twelve months ended December 31, 1997, of $11,433,000, were $6,546,000 higher than the same period in 1996. The increase in total revenues was due primarily to higher II - 2 21 oil and gas revenues of $4,827,000, consisting primarily of a $2,464,000 increase in oil revenues and a $2,363,000 increase in gas revenues. Also contributing to the revenue increase was $920,000 in revenue from gas processing at the gas plant located at the Spivey Field and $975,000 in lease bonus and delay rental income on the fee mineral acreage in Louisiana. The gas processing plant was acquired in the February 28, 1997 Bison Merger. The increase in oil and gas revenues from 1996 to 1997 was primarily the result of increases in production which resulted from the Bison and Shore Mergers. Production from the Bison and Shore Mergers is included from March 1 and July 1, 1997, respectively. Production of oil and gas for the twelve months ended December 31, 1997, increased 133% and 96%, respectively, over the comparable period. During the twelve-month period ended December 31, 1997, the Company sold 254,000 barrels of oil and 1,929,000 Mcf of gas, as compared to 109,000 barrels of oil and 983,000 Mcf of gas for the comparable period. Oil production for 1997 was 145,000 barrels higher due primarily to a 58,000 barrel increase from the Bison Merger and a 76,000 barrel increase from the Shore Merger. Gas production in 1997 was 946,000 Mcf higher due primarily to a 521,000 Mcf increase from the Bison Merger, a 335,000 Mcf increase from the Shore Merger and a 188,000 Mcf increase from the Riceville Acquisition. The price received on the gas sold in 1997 of $2.39 per Mcf was slightly higher than the $2.28 per Mcf received in the comparable period. Oil prices in 1997 of $18.38 per barrel were 9% lower than the $20.26 per barrel received in the comparable period. The Company received approximately $975,000 in lease bonus and delay rental income on the fee mineral acreage acquired in the Shore Merger over the six-month period ending December 31, 1997. The increase in total revenues of $6,546,000 was less than the increase in total expenses, before income taxes, of $29,851,000. The principal reasons for the increase in the overall level of expenses are (1) increased oil and gas property impairment charge of $20,870,000; (2) increased lease operating and depletion expenses of $5,715,000 from properties acquired in the Bison and Shore Mergers which are included with the Company's expenses from March 1 and July 1, respectively; and (3) increased G&A expenses of $1,699,000 due to increased number of employees from the Bison and Shore Mergers and higher overall administrative expenses due to the increased level of activity. In the fourth quarter of 1997, the Company charged to impairment expense $21,148,000 versus $278,000 in the comparable period. The impairment expense was computed applying the guidelines of FAS #121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of." This statement requires that long-lived assets be reviewed for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. This review consists of a comparison of the carrying value of the asset with the asset's expected future undiscounted cash flows without interest costs. Expected undiscounted future cash flow is defined as "the future cash inflows expected to be generated by an asset less the future cash outflows expected to be necessary to obtain those inflows (undiscounted and without interest charges)." Independent oil and gas engineers determine the expected future undiscounted cash flows. To determine the expected future undiscounted cash flows of each property, the engineers estimated each property's oil and gas reserves, relied on certain information supplied by the Company regarding the oil and gas reserves, applied certain assumptions regarding price and cost escalations, and applied certain discount factors for risk, location, type of ownership interest, category of reserves, operational characteristics and other factors. Estimates of expected future undiscounted cash flows are to represent II - 3 22 management's best estimate based on reasonable and supportable assumptions and projections. If the expected future undiscounted cash flows exceed the carrying value of the asset, no impairment is recognized. If the carrying value of the asset exceeds the expected future undiscounted cash flows, impairment exists and is measured by the excess of the carrying value over the estimated fair value of the asset. Fair value is defined in the statement as the "amount at which the asset could be bought or sold in a current transaction between willing parties." The impairment expense in the current period of $21,148,000 was primarily attributable to impairments on three fields--the Esther Field, Spivey Field and Wellman Field--amounting to $8,394,000, $6,127,000 and $2,257,000, respectively. The Esther and Wellman Fields were acquired in the Shore Merger, and the Spivey Field was acquired in the Bison Merger. The impairment on the Esther Field in Vermilion Parish, Louisiana was due primarily to a change in the category of reserves from Proved Undeveloped to Probable Undeveloped and changes in the economics of the development of the reserves. The category of the reserves was changed due to an abandoned sidetrack attempt in February, 1998 by the operator on the Proved Undeveloped Reserves. The impairment on the Spivey Field was due primarily to a decrease in the level of oil prices and changes in the economics of the Proved Undeveloped Reserves due to information obtained from the wells drilled in 1997. The impairment on the Wellman Field in Terry County, Texas was due primarily to decreases in oil prices. Since July 1, 1997, the posted price of WTI crude oil has fallen from approximately $18.00 per barrel to $15.00 per barrel at December 31, 1997or 17%. The total oil equivalent reserves of the Wellman Field are 95% oil. The remaining impairment expense of approximately $4,370,000 is attributable to several fields. The principal reasons for the impairment on these fields are the decrease in oil prices and the decrease or cessation of oil and gas production. Lease operating expenses of $3,849,000 increased by $2,333,000. The increase was due primarily to the Bison and Shore Mergers which increased lease operating expenses $1,067,000 and $915,000, respectively. Depletion expense of $4,567,000 increased by $3,382,000. Depletion increased primarily due to the Bison and Shore Mergers which increased depletion by $1,279,000 and $1,270,000, respectively. Interest expense of $671,000 increased by $166,000 due to a higher loan balance. Dry-hole expense of $1,119,000 increased by $690,000 due primarily to abandonment costs on three unsuccessful Exploratory Wells drilled in Louisiana--the Shore Oil Company #1, the Sabine #1 and the Middle Bay Oil Company #1--with dry-hole costs of $311,000, $177,000 and $168,000, respectively. General and administrative expense of $2,361,000 increased by $1,699,000, due primarily to higher salary expense of $724,000, higher professional fees of $347,000, higher office expenses of $128,000, and higher IRA/SEP/Other Bonus expenses of $123,000. The remaining increase in general and administrative expenses was over several expense categories and was due primarily to an increase in the overall level of activity at the Company as a result of the Bison and Shore Mergers. The increase in salary expense is due to increases in salaries of existing employees and salaries associated with employees added in the Bison and Shore Mergers. At the time of the Bison Merger, seven employees occupied the Wichita, Kansas office. Effective August 1, 1997, only four employees will be occupying the Wichita, Kansas office--the President of Bison, an engineer, geologist and secretary. The President of Shore, an engineer and a secretary were added in the Shore Merger. In addition, the Company hired a land manager in July to manage the Company's land and mineral records and an accounting supervisor in October to assist with the increased accounting workload. Stock compensation II - 4 23 expense of $202,000 increased by $202,000 due to the vesting of 50% of the restricted stock granted to certain Company employees in February, 1997. The remaining 50% will fully vest on June 30, 1998. Other expenses of $317,000 increased $285,000 over the comparable period. The primary reason for the increase was expenses associated with the Bison and Shore Mergers. The Company reported an operating loss of $23,024,000 for the year ended December 31, 1997, as compared to an operating profit of $280,000 in the comparable period. The Company reported a deferred tax benefit of $7,451,000 for the year ended 1997 versus a deferred tax expense of $70,000 in the comparable period. The primary reason for the deferred tax benefit in 1997 was the oil and gas reserve impairment on the properties acquired in the Bison and Shore Mergers in 1997 and the NPC Merger in 1996. These three mergers were tax-free mergers, and the tax basis of the oil and gas properties acquired were carried over on the Company's books at the merger dates. For accounting purposes, the three mergers were purchases and the oil and gas properties were recorded on the Company's books at fair market value on the merger dates. The fair market value was much higher than the carryover tax basis and a deferred tax liability at the prevailing tax rate was recorded for the difference. The total deferred tax liability that was recorded on the Company's books for the Bison, Shore and NPC Mergers was approximately $12 million. When the impairment reduced the carrying amount of the oil and gas properties for accounting purposes but not for tax purposes, the difference between the accounting and tax basis of the properties was reduced and the deferred tax liability was reduced accordingly, resulting in a deferred tax benefit. The Company reported a net loss of $15,579,000 versus net income of $205,500 for the comparable period. The Company paid preferred dividends of $605,000 in the current period and reported a net loss to common stockholders of $16,184,000 versus net income available to common stockholders of $205,000 for the comparable period. No preferred dividends were paid in 1996. (c) Fiscal 1996 Total revenues for the twelve months ended December 31, 1996, of $4,886,000, were $1,348,000 higher than the comparable period. The increase in total revenues was due primarily to higher oil and gas revenues of $1,236,000, consisting primarily of a $469,000 increase in oil revenues and a $858,000 increase in gas revenues. Total revenues also increased due to higher other income of $199,000, due primarily to a gas contract settlement of $263,000. The increase in oil and gas revenues from 1996 to 1995 was primarily the result of higher oil and gas prices. Production of oil and gas for the twelve months ended December 31, 1996, increased 1% and 7%, respectively, over the comparable period. During the twelve-month period ended December 31, 1996, the Company sold 109,000 barrels of oil and 983,000 Mcf of gas, as compared to 107,000 barrels of oil and 917,000 Mcf of gas for the comparable period. Oil production for 1996 was 1,600 barrels higher due to a 4,300 barrel increase from the successful wells in the Brigham Agreement, a 500 barrel increase in existing properties, and a decrease of 3,200 barrels from properties sold in 1996. Gas production in 1996 was 66,000 Mcf higher due to a 25,000 Mcf increase from the successful wells in the Brigham Agreement and a 78,000 Mcf increase in existing properties offset by a decrease of II - 5 24 37,000 Mcf from properties sold in 1996. The price received on the gas sold in 1996 of $2.28 per Mcf was higher than the $1.51 per Mcf received in the comparable period. Oil prices in 1996 of $20.26 per barrel were 25% higher than the $16.17 per barrel received in the comparable period. The increase in total revenues of $1,348,000 was more than the increase in total expenses of $646,000. Increases in dry-hole costs and depreciation and depletion expense accounted for approximately 91% of the total expense increase. Lease operating expenses of $1,516,000 increased by $79,000 as a result of higher expenses on existing properties of $138,000 and expenses on successful wells in the Brigham Agreement of $4,300 offset by reductions due to properties sold in 1996 of $63,000. Interest expense of $505,000 decreased by $15,000 due to lower interest rates and payments on principal in 1996. Dry-hole expense increased by $346,000 due primarily to abandonment costs of $421,000 associated with the unsuccessful wells drilled in the Brigham Agreement. Depletion expense of $1,397,000 increased by $256,000. Regular depletion of $1,119,000 increased by $134,000 due primarily to higher depletion on existing properties. Write-offs of proven properties in accordance with SFAS #121 of $277,000 increased by $121,000. Of the total writedown, 75% is from three single well fields in Louisiana. One of the fields was the Lake Decade Field which was a major property in 1995. It contributed $91,000 to cash flow in 1996 before it ceased producing in December 1996, resulting in an impairment expense of $59,000. The other two fields, which produced very little in 1996, were minor properties contributing less than $20,000 to cash flow in 1995, and producing impairment losses of $95,000 and $55,000. The remaining impairment expense resulted from several properties, none of which were significant properties in terms of discounted present value and were primarily mature, small properties that did not contribute significantly to the Company's cash flow in 1996 and 1995. Depreciation expense of $60,000 decreased $15,000 due to lower depreciation on lease and well equipment and corporate office furniture and fixtures which are depreciated on an accelerated method which declines over the useful life of the asset. General and administrative expenses decreased by $3,900, due primarily to the Company's lower 1996 SEP/IRA and 1% NPI contributions of $12,000 compared to the $60,000 in contributions in 1995, lower accounting expenses of $14,000 and lower miscellaneous expenses of $18,000 which were partially offset by higher travel and entertainment expenses of $47,000 and higher legal expenses of $12,000. The Company reported an operating profit of $280,000 for the year ended December 31, 1996 as compared to an operating loss of $421,000 in 1995. If the 1996 nonrecurring credits of $303,000 consisting of the gas contract settlement of $263,00 and lease operating expense credit of $40,000, were offset against the 1995 nonrecurring expenses of $62,000, the operating loss would have decreased by $336,000. The Company reported net income of $205,000 for the year ended December 31, 1996, versus a net loss of $331,000 for the comparable period. II - 6 25 (d) Effects of Oil and Gas Price Fluctuations Fluctuations in the price of crude oil and natural gas significantly affect the Company's operations and the value of its assets. As a result of the instability and volatility of crude oil and natural gas prices, financial institutions have become more selective in the energy lending area and have reduced the percentage of existing reserves that may qualify for the borrowing base to support energy loans. The Company's principal source of cash flow is the production and sale of its crude oil and natural gas reserves which are depleting assets. Cash flow from oil and gas production sales depends upon the quantity of production and the price obtained for that production. An increase in prices permits the Company to finance its operations to a greater extent with internally-generated funds, allow the Company to obtain equity financing more easily and lessens the difficulty of attracting financing alternatives available to the Company from industry partners and nonindustry investors. However, price increases heighten the competition for Leases and Prospects, increase the costs of exploration and development activities and increase the risks associated with the purchase of Producing Properties. A decline in oil and gas prices (i) reduces the cash flow internally generated by the Company, which in turn reduces the funds available for servicing debt and exploring for and replacing oil and gas reserves, (ii) increases the difficulty of obtaining equity financing, (iii) reduces the number of Leases and Prospects available to the Company on reasonable economic terms and (iv) increases the difficulty of attracting financing alternatives available to the Company from industry partners and nonindustry investors. However, price declines reduce the competition for Leases and Prospects and correspondingly reduce the prices paid for Leases and Prospects. Furthermore, exploration and production costs generally decline, although the decline may not be at the same rate of decline of oil and gas prices. Since September, 1997, the price of oil has declined dramatically. The posted price of WTI crude oil has declined from a high of approximately $20.00 per barrel in October 1997 to lows in March 1998 of approximately $13.00 per barrel. The average posted price of WTI crude oil for the year 1997 was approximately $18 per barrel. Approximately 55% of the Company's proved developed producing oil and gas reserves, on a BOE basis, are oil. If oil prices remain at or near the March 1998 levels, the Company's revenue and cash flow will decrease relative to the year ended 1997. Gas prices peaked in November 1997, but decreased and have not changed significantly since December 1997. (e) Seasonality The results of operations of the Company are somewhat seasonal due to seasonal fluctuations in the price for natural gas. Generally, natural gas prices are higher in the first and fourth quarter of the year due to colder winter weather and resulting higher demand for natural gas during these months. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of results on an annual basis. II - 7 26 (f) Inflation and Changing Prices Inflation principally affects the costs required to drill, complete and operate oil and gas wells. In recent years, inflation has had a minimal effect on the operations of the Company. Costs have generally declined over the near future due to the decrease in drilling activity in the United States. Unless increasing oil and gas prices spur large increases in industry activities, management believes costs will remain relatively stable over the next year. (g) Capital Resources and Liquidity -- Fiscal 1997 and Fiscal 1996 Cash flow from operations before working capital changes of $2,925,000 increased $1,225,000 over the comparable period. This increase was due a to $3,184,000 increase in oil and gas cash flow, an increase of $554,000 in other income offset by increases in general and administrative costs of $1,654,000, dry-hole costs of $691,000, interest expense of $166,000 and $1,000 in current income taxes. Increased oil and gas operations cash flow before working capital changes was principally the result of increases in oil and gas production. The other income increase was due primarily to lease bonus and delay rental income on the minerals acquired in the Shore Merger. Cash flow from operating activities for the year ending December 31, 1997, of $2,582,000 increased $1,193,000 over the comparable period. Changes in working capital reduced cash flow by $32,000 over the comparable period. Differences in the amount and timing of accrual and payment of payables and the accrual and receipt of revenues account for the changes in working capital. Additions to oil and gas properties were higher than the comparable period due to the Bison and Shore Mergers and increased acquisitions and drilling in the current period. The increase in the amount of cash used for debt payments was due primarily to the $2,105,000 refinancing of the term note assumed in the Shore Merger and the $385,000 of payments and refinancing on the note assumed in the NPC Merger. No principal payments have been required over the period April 1, 1996 to December 31, 1997 on the Company's $6 million, $15 million and $50 million convertible loans. The increase in the proceeds from debt issued was due to the refinancing of the notes assumed in the Shore and NPC Mergers, $3,000,000 issued in the Riceville Acquisition and the financing of the leasehold and seismic costs in the amount of $385,000 associated with the Reflection Ridge Prospect. The increase in proceeds from issuance of preferred stock was due to the preferred stock issued to finance portions of the Bison and Shore Mergers. The Company's operating activities provided net cash of $2,582,000 for the year ending December 31, 1997. During this period, net cash from operations and cash on hand was used principally for exploratory and developmental drilling of $2,004,000, workovers of $431,000, exploration prospects of $415,000 and proved property acquisitions of $921,000. Debt proceeds were used to finance $3,000,000 of proved property acquisition and $285,000 of prospects. Common stock was issued for $260,000 of proved property acquisitions, excluding mergers. Of the $2,004,000 spent on exploratory and developmental drilling, approximately $420,000 was spent in the Brigham Agreement, $880,000 in the Spivey Field in Kansas, $100,000 in the Wellman Unit in Texas, and the remainder was spent on several wells in Louisiana, Mississippi and Oklahoma. Of the $431,000 spent on workovers, approximately $80,000 was spent at Wild Fork Creek II - 8 27 Field in Alabama, $44,000 at the Wright Field in Louisiana, $30,000 at Magnolia in Arkansas and $25,000 at Lake Trammel Field in Texas. The remaining amount was spent on several different properties. The $700,000 total amount spent on prospects consisted primarily of $286,000 on Reflection Ridge in Kansas, $232,000 on Hawkins Ranch in Texas, $67,000 on the Sherburne Prospect in Louisiana, $31,000 on the Quarry Prospect in New Mexico and $55,000 on S. Highbaugh in Texas. The Company spent $7,140,000 on the Bison Merger. This includes the $1,446,000 in non-oil and gas assets, which were subsequently sold for the amount paid. The Company spent $514,000 on the Shore Merger. Amounts spent on debt retirement consisted principally of the payment in full of the note assumed in the Shore Merger of $2,105,000, monthly principal payments on the $385,000 term note assumed in the NPC Merger and the refinancing of the NPC term note of $274,000. The principal payments on the $6 million convertible loan were suspended when the Company converted the $5.6 million term note to a $6 million convertible loan on April 3, 1996. The Company incurred $1,119,000 in dry hole costs consisting principally of three wells drilled in Louisiana and one well drilled in Oklahoma. The Louisiana wells were the Shore Oil Company #1, the Sabine #1 and the Middle Bay Oil Company #1 with dry-hole costs of $311,000, $177,000 and $168,000, respectively. The Oklahoma well was the Hannah #1 with a dry hole cost of $301,000. The Company incurred $223,000 in geological and geophysical costs ("G&G Costs") which consisted primarily of $130,000 in G&G costs on the Reflection Ridge Prospect and $62,000 on the Hawkins Ranch Prospect. The above discussion of capital costs does not include amounts expensed as dry hole and G&G costs. The Company had current assets of $4,223,000 and current liabilities of $2,891,000, which resulted in working capital of $1,332,000 at December 31, 1997. This was an increase of $546,000 from working capital of $786,000 at December 31, 1996. Working capital increased primarily due to increased cash flow from operations, cash proceeds from stock option exercises, and no monthly principal payments on the Convertible Loan, offset partially by increased amounts spent on exploratory and developmental drilling and working capital changes. The current maturity of long-term debt was higher in 1997 because of the larger principal balance requiring payment in the following year. In 1997, the $50 million Convertible Loan requires principal payments beginning April 1, 1998 versus the $6 million Convertible Loan requiring principal payments beginning October 1, 1997 in the comparable period. The Company's current ratio of 2.78, calculated under the terms of the Convertible Loan which excludes stockholder receivables and debt due under the $50 million Convertible Loan, is in excess of the 0.90 to 1.00 required. In general, because natural gas and oil reserves are depleted by production, the Company's success is dependent upon the results of its acquisition, development and exploration activities. The Company's strategy is to acquire and develop proved producing and proved undeveloped properties, enhance and exploit its existing properties for reserves and to invest in a limited amount of exploratory and developmental drilling projects. The Company expects to incur a minimum of $2,300,000 in capital expenditures over the next twelve months for exploratory and developmental activities. The capital expenditures for drilling are expected to be allocated to recomplete a well in the Esther Field for $400,000, drill a well on the Sherburne Prospect for $288,000, on the S. Highbaugh Prospect for $150,000, on the Quarry Prospect for $140,000 and shoot, II - 9 28 process and interpret seismic and acquire leases on the Hawkins Ranch Prospect for $1,300,000. The developmental and exploratory drilling activities will be funded by internally generated cash flows. Capital expenditures above $2.3 million will be contingent on a number of factors including current and expected prices of oil and gas, timing of completion of 3-D seismic data acquisition on the Hawkins Ranch Prospect, results of exploration and development drilling and potential additional mergers and acquisitions the Company is currently evaluating. As of March 16, 1998, the Company had funded the sidetracking of the Kuehling #1 well in the Esther Field for $400,000 and a well in the S. Highbaugh Prospect in Tyler County, Texas for $150,000. The operator abandoned the recompletion attempt after encountering a split casing, and the well in S. Highbaugh was a dry hole. In addition, the Company purchased additional interest and seismic on the Hawkins Ranch Prospect for approximately $250,000. Under the terms of the Janex Acquisition, the Company has a contingent obligation to repurchase 142,107 common shares issued in the Janex Acquisition, upon written notice delivered to the Company, beginning five years after the closing date and continuing for thirty days thereafter, at a price of $6.00 per share. This obligation shall terminate if the Company's stock trades at a share price of $8.00 or greater for twenty consecutive trading days during the thirty-six month period ending November 1, 1998. At the close of trading on April 7, 1997, the Company's common stock had traded at an ask price that was equal to, or exceeded, $8.00 per share for twenty consecutive trading days. Therefore, the contingent obligation represented by the redeemable common stock balance on the Company's balance sheet in the amount of $421,179 was reclassified to additional paid-in capital effective April 7, 1997. On April 3, 1996, the Bank converted its $5.6 million term note into a $6.0 million, one-year, revolving line-of-credit (the "$6 million Convertible Loan"), effective April 1, 1996. The $6 million Convertible Loan required monthly payments of interest only at prime plus 1.5% and converted into a term note payable in seventy-one consecutive equal monthly principal and interest payments at prime plus 1.5%, with the remaining principal and interest payment due on March 31, 2003. Effective, March 31, 1997, the Company refinanced the $6 million Convertible Loan at its current principal balance of $5,186,596 with a $15 million Convertible Loan. The $15 million Convertible Loan required monthly payments of interest only at prime for one year and converts into a term note payable in seventy-one consecutive equal monthly principal and interest payments at prime, with the remaining principal and interest payment due on March 31, 2004. The $15 million Convertible Loan also required payment of a commitment fee equal to an annual rate of three-eighths percent of the excess of the borrowing base over the principal balance of the convertible note. Effective September 1, 1997, the Company refinanced the $15 million Convertible Loan at its current principal balance of $5,851,298 with a $50 million Convertible Loan. The $50 million Convertible Loan requires monthly payments of interest only at a fixed rate of Libor plus 1.75% as long as the principal amount of the loan is less than 75% of the current borrowing base of $15 million. If the principal amount of the loan is greater than or equal to 75% of the borrowing base, the rate increases to Libor plus 2.75%. The Company has the option of switching to a floating prime rate. The $50 million Convertible Loan converts into a term note payable in seventy-one consecutive equal monthly principal and interest payments at prime, with the remaining principal and interest payment due on March 31, 2004. The $50 million Convertible Loan also requires payment of a commitment II - 10 29 fee equal to an annual rate of three-eighths percent of the excess of the borrowing base over the principal balance of the convertible note. The principal balance of the $50 million Convertible Loan at December 31, 1997 was $10,956,298. On September 4, 1996, the Company signed a Preferred Stock Agreement with Kaiser-Francis. The Preferred Stock Agreement provides for the purchase of 1,666,667 shares of Series A by Kaiser-Francis over a five-year period, beginning September 4, 1996, with minimum incremental investments of $500,000 each. Each issuance is subject to approval by Kaiser-Francis of the use of proceeds. The Series A is nonvoting and accrues dividends at 8% per annum, payable quarterly in cash. At December 31, 1997, 100% of the Series A had been issued to partially finance the NPC, Bison and Shore Mergers. In connection with the Shore Merger effective June 30, 1997, the Company issued 266,667 shares of Series B Preferred Stock ("Series B"). The Series B is nonvoting and pays no dividends. The Series B has a liquidation value of $7.50 per share and is junior to the Series A Preferred. For a period of sixty-six months subsequent to June 30, 1997, any holder of the Series B may convert all or any portion of Series B shares into Company common stock ("Common") at a ratio of one share of Common for each Series B share, or at any time on or after January 1, 1998, the holders may convert pursuant to the Alternative Conversion Method based on Cumulative Value. The Cumulative Value (as defined in the Shore Merger Agreement) means the value attributable to the approximately 42,000 net mineral acres located in South Louisiana. The Cumulative Value shall initially be equal to $2 million, shall not exceed $10 million and shall be recomputed on an incremental basis as of December 31 of each year following the merger date. The Cumulative Value consists primarily of income from lease bonuses and delay rentals and the present value of proved reserves discovered on the acreage. Upon expiration of the conversion period, unless the Company has given notice to redeem the Series B, all of the shares of Series B shall be automatically converted. In no event shall the aggregate total number of shares of Common into which the Series B are converted be less than 266,667 shares or exceed 1,333,333 shares, unless further increased for any anti-dilution provisions. The Alternative Conversion Method shall be computed as of December 31 of each year following the merger date of June 30, 1997, by determining the incremental amounts by which the Cumulative Value increases over the prior year's computation. Each incremental increase in the Cumulative Value, when computed, shall be divided by $8,000,000, with the resulting quotient (the "Alternative Conversion Factor") multiplied by 266,667 to determine the number of Series B shares which would be available to be converted. The number of Common shares into which the Series B would be converted shall be determined by multiplying 1,066,666 times the then applicable Alternative Conversion Factor. The procedure shall be repeated as of each December 31, with the applicable number of Series B shares converted into Common shares. If on December 31 of any year during the conversion period the aggregate Cumulative Value equals or exceeds $10,000,000, then the remaining Series B shares will be convertible into a number of Common shares equal to 1,333,333 shares less the aggregate number of Common shares previously issued upon conversion The Company's liquidity position and current and anticipated cash flows from operations remain adequate for its general requirements. However, because future cash flows and the availability of financing are subject to a number of variables, such as the level of production and prices received for gas and II - 11 30 oil, there can be no assurance that the Company's capital resources will be sufficient to maintain planned levels of capital expenditures. (h) Capital Expenditures -- Fiscal 1997 and Fiscal 1996 Total capital expenditures, excluding mergers, for oil and gas properties in fiscal 1997 and 1996 were $7,316,000 and $1,597,000, respectively. Total capital expenditures for mergers in 1997 and 1996 were $27,586,000 and $2,618,000, respectively. Total capital expenditures for dry holes and G&G in 1997 and 1996 were $1,341,000 and $429,000, respectively. Through March 16, 1998, the Company has spent approximately $1,000,000 and is committed to spend an additional $1,300,000 for the remainder of the year. Beyond these commitments, the Company's capital expenditures will vary, depending on energy market conditions and other related economic factors. The Company anticipates that its cash flow from operations will be adequate to fund the drilling of the wells in the Esther Field, Sherburne, S. Highbaugh and Quarry Prospects and to fund the seismic survey at Hawkins Ranch. As of March 16, 1998, the Company has approximately $4,000,000 of available credit through the $50.0 million Convertible Loan. The funds available under the $50 million Convertible Loan may be reduced at the next redetermination date on March 31, 1998, depending on the level of prices, rates of production and various other factors. The Company intends to use the $50 million Convertible Loan to finance proved property acquisitions. Whenever possible, the Company will use funds from the sale of preferred stock and/or common stock to finance acquisitions. The Company's liquidity position and current and anticipated cash flows from operations are expected to remain adequate for its general requirements over the next twelve months. ITEM 7. FINANCIAL STATEMENTS The Company's financial statements for the years ended December 31, 1997 and 1996 and the report of Schultz, Watkins & Company, independent accountants, thereon are included in this Item 7. [The remainder of this page has been intentionally left blank] II - 12 31 MIDDLE BAY OIL COMPANY, INC. AUDITED CONSOLIDATED FINANCIAL STATEMENTS YEARS ENDED DECEMBER 31, 1997 AND 1996 SCHULTZ, WATKINS & COMPANY CERTIFIED PUBLIC ACCOUNTANTS JACKSON, MISSISSIPPI 32 TABLE OF CONTENTS
Page No. ---- Independent Auditors' Report.............................................. 1 Consolidated Balance Sheets............................................... 2 Consolidated Statements of Operations..................................... 3 Consolidated Statements of Changes in Stockholders' Equity................ 4 Consolidated Statements of Cash Flows..................................... 5 Notes to Consolidated Financial Statements................................ 6
33 SCHULTZ, WATKINS & COMPANY ================================================================================ CERTIFIED PUBLIC ACCOUNTANTS 1437 Old Square Road Suite 106 Jackson, MS 39211 Phone: 601-362-3312 FAX: 601-362-1623 Independent Auditors' Report Board of Directors and Stockholders Middle Bay Oil Company, Inc. We have audited the accompanying consolidated balance sheets of Middle Bay Oil Company, Inc. and subsidiaries as of December 31, 1997 and 1996, and the related statements of operations, changes in stockholders' equity and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We have conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Middle Bay Oil Company, Inc. and subsidiaries at December 31, 1997 and 1996, and the results of their operations and their cash flows for the years then ended in conformity with generally accepted accounting principles. As discussed in Note 1 to the financial statements, the Company restated its consolidated financial statements to exclude a valuation allowance in presenting its net deferred income tax liability. /s/ Schultz, Watkins & Company Jackson, Mississippi February 27, 1998 -1- 34 MIDDLE BAY OIL COMPANY, INC. Consolidated Balance Sheets December 31 ASSETS
1997 1996 ------------ ------------ CURRENT ASSETS Cash and cash equivalents $ 1,587,184 $ 556,026 Accounts receivable 2,325,138 1,129,417 Other current assets 104,313 58,137 Assets held for resale 206,464 -- ------------ ------------ Total current assets 4,223,099 1,743,580 NON-CURRENT ASSETS Accounts receivable - stockholder (Note 3) 166,165 159,215 PROPERTY(at cost)(substantially pledged) (Notes 1&4) Oil and gas (successful efforts method) 62,654,347 16,252,576 Other 837,205 354,603 ------------ ------------ 63,491,552 16,607,179 Less accumulated depletion, depreciation and amortization (30,636,202) (5,332,517) ------------ ------------ 32,855,350 11,274,662 OTHER ASSETS 7,958 7,523 ------------ ------------ TOTAL ASSETS $ 37,252,572 $ 13,184,980 ============ =============
-2- 35 LIABILITIES AND STOCKHOLDERS' EQUITY
1997 1996 ------------ ---------- CURRENT LIABILITIES Current maturities of long term debt (Note 4) $ 1,375,537 $ 554,601 Accounts payable - trade 1,176,680 381,870 Royalties payable 212,622 4,720 Other current liabilities 126,092 16,206 ------------ ---------- Total current liabilities 2,890,931 957,397 LONG TERM DEBT (Note 4) 9,714,713 5,158,477 DEFERRED INCOME TAXES (Notes 1 & 5) 4,780,528 610,785 REDEMABLE COMMON STOCK (Note 8) -- 421,179 STOCKHOLDERS' EQUITY Preferred stock, $.02 par, 5,000,000 shares authorized with 1,666,667 shares designated Series A, none other issued -- -- Cumulative convertible Series A 8% preferred stock, $6 stated value, 1,666,667 designated, 1,666,667 and 166,667 shares issued and outstanding at 12/31/97 and 12/31/96, respectively, $10,000,000 aggregate liquidation preference 10,000,000 1,000,000 Convertible preferred stock Series B, $7.50 stated value, 266,667 shares issued and outstanding at 12/31/97. $2,000,000 aggregate liquidation preference 3,627,000 -- Common stock, $.02 par value, 10,000,000 authorized, 4,519,206 and 1,880,917 shares issued and outstanding at 12/31/97 and 12/31/96, respectively 90,392 37,618 Additional paid-in capital 23,029,299 6,049,442 Less redeemable common stock -- (421,179) Unearned stock compensation (67,500) -- Accumulated deficit (16,744,751) (560,699) Less cost of treasury stock; 21,773 shares at 12/31/97 and 12/31/96 (68,040) (68,040) ------------ ------------ Total stockholders' equity 19,866,400 6,037,142 ------------ ------------ COMMITMENTS AND CONTINGENCIES (Note 9) TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 37,252,572 $ 13,184,980 ============ ============
See accompanying notes to consolidated financial statements. 36 MIDDLE BAY OIL COMPANY, INC. Consolidated Statements of Operations Years Ended December 31
1997 1996 ------------ ------------ REVENUES Oil and gas sales $ 10,213,047 $ 4,474,786 Gain on sale of oil and gas properties 7,018 37,815 Delay rental and lease bonus income 975,347 -- Other 237,583 373,820 ------------ ------------ Total revenue 11,432,995 4,886,421 COSTS AND EXPENSES Operating expenses, including production taxes 3,848,627 1,516,011 Geological and geophysical costs 222,608 -- Abandonment costs 1,118,838 428,598 Impairments 21,147,823 277,483 Depletion, depreciation and amortization 4,567,063 1,184,713 Interest 671,081 504,945 Stock compensation expense 202,500 -- General and administrative 2,361,124 662,288 Other 317,469 32,012 ------------ ------------ Total expenses 34,457,133 4,606,050 (LOSS) INCOME BEFORE INCOME TAX (BENEFIT) EXPENSE (23,024,138) 280,371 INCOME TAX (BENEFIT)EXPENSE (Note 5) Current 6,451 5,079 Deferred (7,451,249) 69,792 ------------ ------------ (7,444,798) 74,871 ------------ ------------ NET (LOSS)INCOME $(15,579,340) $ 205,500 Dividends to preferred stockholders (604,712) -- ------------ ------------ NET (LOSS)INCOME AVAILABLE TO STOCKHOLDERS $(16,184,052) $ 205,500 ============ ============ NET (LOSS)INCOME PER SHARE Basic $ (4.76) $ 0.15 ============ ============ Diluted $ (4.76) $ 0.14 ============ ============ WEIGHTED AVERAGE COMMON SHARES OUTSTANDING Basic 3,397,117 1,332,141 ============ ============ Diluted 3,397,117 1,449,855 ============ ============
See accompanying notes to consolidated financial statements. -3- 37 MIDDLE BAY OIL COMPANY, INC. Consolidated Statements of Changes in Stockholders' Equity Years Ended December 31, 1997 and 1996
Preferred Stock --------------- ---------------- Common Series A Series B Stock ------- ------ ---- -------- -------- ------ Shares Amount Shares Amount Shares Amount --------- ----------- ------- ---------- --------- ------- BALANCE - 1/1/96 -- $ -- -- $ -- 1,318,917 $26,378 Common stock issued in acquisition of NPC Energy Corporation -- -- -- -- 562,000 11,240 Preferred stock issued 166,667 1,000,000 -- -- -- -- Conversion of redeemable common stock to common stock -- -- -- -- -- -- Net income -- -- -- -- -- -- Treasury stock acquired - 21,773 shares -- -- -- -- -- -- --------- ----------- ------- ---------- --------- ------- BALANCE - 12/31/96 166,667 1,000,000 -- -- 1,880,917 37,618 Common stock issued in acquisition of NPC Energy Corporation -- -- -- -- 33,463 677 Preferred Series A issued 1,500,000 9,000,000 -- -- -- -- Common stock issued in acquisition of Bison Energy Corporation -- -- -- -- 605,556 12,111 Common stock issued in acquisition of Shore Oil Company -- -- -- -- 1,883,333 37,667 Preferred Series B issued in acquisition of Shore Oil Company -- -- 266,667 3,627,000 -- -- Conversion of redeemable common stock to common stock -- -- -- -- -- -- Restricted stock awards -- -- -- -- 49,091 982 Stock options exercised -- -- -- -- 40,833 817 Purchase of oil and gas working interests -- -- -- -- 26,013 520 Unearned stock compensation -- -- -- -- -- -- Net loss -- -- -- -- -- -- 8% Preferred stock Series A dividends -- -- -- -- -- -- --------- ----------- ------- ---------- --------- ------- BALANCE - 12/31/97 1,666,667 $10,000,000 266,667 $3,627,000 4,519,206 $90,392 ========= =========== ======= ========== ========= =======
See accompanying notes to consolidated financial statements. -4- 38
Additional Redeemable Unearned Paid-in Common Stock Accumulated Treasury Capital Stock Compensation Deficit Stock Total ------- ----- ------------ ------- ----- ----- $ 4,093,682 $(852,642) $ -- $ (766,199) $ -- $ 2,501,219 1,955,760 -- -- -- -- 1,967,000 -- -- -- -- -- 1,000,000 -- 431,463 -- -- -- 431,463 -- -- -- 205,500 -- 205,500 -- -- -- -- (68,040) (68,040) - ----------- --------- -------- ------------ -------- ------------ 6,049,442 (421,179) -- (560,699) (68,040) 6,037,142 93,018 -- -- -- -- 93,695 -- -- -- -- -- 9,000,000 3,318,447 -- -- -- -- 3,330,558 12,938,498 -- -- -- -- 12,976,165 -- -- -- -- -- 3,627,000 -- 421,179 -- -- -- 421,179 269,018 -- -- -- -- 270,000 101,266 -- -- -- -- 102,083 259,610 -- -- -- -- 260,130 -- -- (67,500) -- -- (67,500) -- -- -- (15,579,340) -- (15,579,340) -- -- -- (604,712) -- (604,712) - ----------- --------- -------- ------------ -------- ------------ $23,029,299 $ -- $(67,500) $(16,744,751) $(68,040) $ 19,866,400 =========== ========= ======== ============ ======== ============
39 MIDDLE BAY OIL COMPANY, INC. Consolidated Statements of Cash Flows Years Ended December 31
1997 1996 -------- ------ CASH FLOWS FROM OPERATING ACTIVITIES Net(loss) income $(15,579,340) $ 205,500 Adjustments to reconcile net(loss) income to net cash provided by operating activities: Depletion, depreciation and amoritization 4,567,065 1,184,713 Impairments 21,147,823 277,483 Deferred income taxes (7,451,249) 69,792 Bad debt expense 45,000 -- Unearned stock compensation 202,500 -- Gain on sale of assets (7,018) (37,814) Changes in operating assets and liabilities: (Increase) Decrease in receivables 243,777 (14,487) Decrease in payables (438,355) (303,457) Other (147,928) 7,648 ------------ ------------ Net cash provided by operating activities 2,582,275 1,389,378 CASH FLOWS FROM INVESTING ACTIVITIES Payment for acquisition of NPC Energy Corp., net of cash acquired of $633,712 -- (651,016) Payment for acquisition of Bison Energy Corp., net of cash acquired of $994,367 (7,139,914) -- Payment for acquisition of Shore Oil Company net of cash acquired of $2,057,467 (514,299) -- Capital expenditures: Oil and gas properties (7,056,213) (1,596,966) Office building and other (246,735) (8,188) Proceeds from sales of: Oil and gas properties 103,872 40,000 Timberland -- 75,000 Other 1,445,890 -- Advances to stockholders - net (6,950) (26,668) ------------ ------------ Net cash used in investing activities (13,414,349) (2,167,838) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds of bank loans 5,769,705 529,596 Principal payments on loans (2,497,533) (207,859) Proceeds from issuance of preferred stock 9,000,000 1,000,000 Preferred stock dividends (604,712) -- Proceeds from common stock 195,772 -- Purchases of treasury stock -- (68,040) ------------ ------------ Net cash provided by financing activities 11,863,232 1,253,697
-5- (continued from opposite page) 40 (continued from opposite page)
1997 1996 ------------ ------------ NET INCREASE IN CASH AND CASH EQUIVALENTS FOR THE YEAR 1,031,158 475,235 Cash and cash equivalents - Beginning of year 556,026 80,791 ------------ ------------ Cash and cash equivalents - End of year $ 1,587,184 $ 556,026 ============ ============ SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION Cash paid during the year for: Interest $ 671,081 $ 504,945 ============ ============ Income Taxes $ 6,451 $ 5,079 ============ ============ Non-cash investing and financing activities: Common stock issued in acquisition of NPC Energy Corp. $ -- $ 1,967,000 ============ ============ Conversion of redeemable common stock to common stock (net of treasury shares acquired) $ 421,179 $ 363,423 ============ ============ Common stock issued in acquisition of Bison Energy Corp. $ 3,330,559 $ -- ============ ============ Common stock issued in acquisition of Shore Oil Company $ 12,976,165 $ -- ============ ============ Preferred stock Series B issued in acquisition of Shore Oil Company $ 3,627,000 $ -- ============ ============ Debt assumed in acquisition of Shore Oil Company $ 2,105,000 $ -- ============ ============ Common stock issued in property acquisition $ 260,130 $ -- ============ ============
See accompanying notes to consolidated financial statements. 41 MIDDLE BAY OIL COMPANY, INC. Notes to Consolidated Financial Statements December 31, 1997 and 1996 (1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Organization Middle Bay Oil Company, Inc. (the Company), was incorporated under the laws of the state of Alabama on November 20, 1992. On December 31, 1996, the Company acquired NPC Energy Corporation, and during 1997, the Company acquired Bison Energy Corporation and Shore Oil Company (See Note 2). The Company is engaged in the acquisition, development and production of oil and natural gas in the contiguous United States. Significant Accounting Policies The Company's accounting policies reflect industry standards and conform to generally accepted accounting principles. The more significant of such policies are described below. Principles of Consolidation The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation. Restatement of the 1997 Financial Statements In 1998, the Company restated its 1997 financial statements to correctly state deferred income taxes for improper inclusion of a valuation allowance for deferred income taxes. This restatement resulted in an adjustment decreasing the net loss and net loss available to stockholders by $1,125,542. The net loss per share decreased $.34 as a result of the restatement. Cash and Cash Equivalents For purposes of the statements of cash flows, the Company classifies all cash investments with original maturities of three months or less as cash. Oil and Gas Property The Company follows the successful efforts method of accounting for oil and gas properties, and accordingly, capitalizes all direct costs incurred in connection with the acquisition, drilling and development of productive oil and gas properties. Costs associated with unsuccessful exploration are charged to expense currently. Geological and geophysical costs and costs of carrying and retaining unevaluated properties are charged to expense. Depletion, depreciation and amortization of capitalized costs are computed separately for each property based on the unit of production method using only proved oil and gas reserves. In arriving at such rates, commercially recoverable reserves have been estimated by independent petroleum engineering firms. The Company reviews its undeveloped properties continually and charges them to expense on a property by property basis when it is determined that they have been condemned by dry holes, or will not be retained, sold or drilled upon. Site Restoration, Dismantlement and Abandonment Costs Site restoration, dismantlement and abandonment costs (P&A costs) are common in the oil and gas industry in which the Company conducts operations. P&A costs are costs associated with removing the facilities and equipment required to operate a well and restoring the well site to specified conditions. P&A procedures are governed by federal and state regulations and contractual obligations. P&A costs are incurred when the oil and gas reserves of a well or wells are depleted or when production drops to the point that it is no longer economically feasible to produce. -6- 42 MIDDLE BAY OIL COMPANY, INC. Notes to Consolidated Financial Statements December 31, 1997 and 1996 Continued (1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued) Site Restoration, Dismantlement and Abandonment Costs (continued) The Company, in conjunction with its independent engineers and the operators of the wells, continually reviews its working interests with respect to potential P&A costs. When conditions require that a well be plugged and abandoned, the appropriate accounting procedures are followed. When a well, or the last well of a group of proved properties ceases to produce or is no longer economically feasible to produce, the entire cost related to the well or group of wells, which includes estimated future dismantlement and abandonment cost, is written off and gain or loss is recognized. Any additional liabilities arising from P&A costs, net of salvage value of the equipment, are accrued in the financial statements and charged to expense in the current period. P&A costs are considered in the proved oil and gas reserve estimates as disclosed in Note 11 - Supplemental Oil and Gas Reserve Information; and, if material, the present value of the reserves is reduced accordingly. As of December 31, 1997 and 1996, the P&A costs accrued were immaterial. Impairment of Long Lived Assets Statement of Financial Accounting Standards No. 121 "Accounting for the Impairment of Long Lived Assets and for Long Lived Assets to be disposed of" (SFAS No.121) was issued in March 1995. This statement requires that long lived assets be reviewed for impairment when events or changes in circumstances indicate that the carrying value of such an asset may not be recoverable. This review consists of a comparison of the carrying value of the asset to the asset's expected future undiscounted cash flows without interest costs. Estimates of expected future cash flows represent management's best estimate based on reasonable and supportable assumptions and projections. If the expected future cash flows are less than the carrying value of the asset, an impairment exists and is measured as the excess of the carrying value over the estimated fair value of the asset. Any impairment provisions recognized in accordance with SFAS No. 121 are permanent and may not be restored in the future. In the fourth quarter of 1997 and 1996 the Company's proved properties were assessed for impairment on an individual field basis and the Company recorded impairment provisions of $21,147,823 and $277,483 respectively, attributable to certain producing properties. Prior to the adoption of SFAS No. 121, the Company assessed its proved oil and gas properties on an individual field basis using management's best estimate of the expected future cash flows from the producing properties. Other Property and Equipment Property and equipment are stated at cost and depreciation is computed on the accelerated method over appropriate lives ranging from five to seven years. Additions and betterments which provide benefits to several periods are capitalized. Environmental Liabilities Environmental expenditures that relate to current or future revenues are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and /or clean-ups are probable, and the costs can be reasonably estimated. Generally, the timing of these accruals coincides with the Company's commitment to a formal plan of action. 43 MIDDLE BAY OIL COMPANY, INC. Notes to Consolidated Financial Statements December 31, 1997 and 1996 Continued (1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued) Revenue Oil and gas revenues are recorded using the sales method, whereby the Company recognizes revenues based on the amount of oil and gas sold to purchasers on its behalf. Income Taxes The Company uses the asset and liability method of accounting for income taxes required by the Statement of Financial Accounting Standards No. 109. Under the asset and liability method, deferred tax assets and liabilities are determined by applying enacted statutory tax rates applicable to future years to the difference between the financial statement and tax basis of assets and liabilities. Stock Based Compensation In October 1995, The Financial Accounting Standards Board ("FASB") issued SFAS No. 123, "Accounting for Stock Based Compensation", which establishes financial accounting and reporting standards for stock based compensation plans. Effective for fiscal years beginning after December 31, 1995, the statement provides the option to continue under the accounting provisions of APB No. 25, while requiring proforma footnote disclosures of the effects of net income and earnings per share, calculated as if the new method had been implemented. The Company has adopted the financial reporting provisions of SFAS No. 123 for 1997, but will continue under the accounting provisions of APB Opinion 25. Use of Estimates Management of the Company has made a number of estimates and assumptions relating to the reporting of assets and liabilities to prepare the financial statements in conformity with generally accepted accounting principles. Actual results could differ from those estimates. Earnings Per Share Effective December 31, 1997, the Company adopted SFAS No. 128, "Earnings per Share." This statement establishes standards for computing and presenting earnings per share, and requires, among other things, dual presentation of basic and diluted earnings per share on the face of the statement of operations. In accordance with SFAS No. 128, earnings per share and weighted average shares outstanding have been restated to conform to this statement for all periods presented. Concentrations of Market Risk The future results of the Company will be affected by the market prices of oil and natural gas. The availability of a ready market for natural gas and oil in the future will depend on numerous factors beyond the control of the Company, including weather, production of other natural gas and crude oil, imports, marketing of competitive fuels, proximity and capacity of oil and gas pipelines and other transportation facilities, any oversupply or undersupply of gas and oil, the regulatory environment, and other regional and political events, none of which can be predicted with certainty. 44 MIDDLE BAY OIL COMPANY, INC. Notes to Consolidated Financial Statements December 31, 1997 and 1996 Continued (1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (concluded) Concentrations of Credit Risk Financial instruments which subject the Company to concentrations of credit risk consist primarily of cash and accounts receivable. The Company places its cash investments with high credit qualified financial institutions. Risk with respect to receivables is concentrated primarily in the current production revenue receivable from multiple oil and gas producers, both major and independent, and is typical in the industry. The Company sold oil and gas representing approximately 14% of its total production to one customer, Warren Petroleum, for the year ended December 31, 1997. Accounting Pronouncements In June 1997, the Financial Accounting Standards Board ("FASB") issued SFAS No. 130, "Reporting Comprehensive Income." This statement establishes standards for reporting and display of comprehensive income and its components in the Company's financial statements. Comprehensive income includes all changes in the Company's equity except investments by and distributions to owners and includes, among other things, foreign currency translation adjustments. In June 1997, the FASB also issued SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information." This statement establishes standards for reporting information about operating segments in annual financial statements and requires selected information about operating segments be included in interim reports issued to shareholders. Both of these statements are effective for financial statements for periods beginning after December 15, 1997. As both SFAS Nos. 130 and 131 establish standards for reporting and display, the Company does not expect the adoption of these statements to have a material impact on its financial condition or results of operations. (2) ACQUISITIONS On December 31, 1996, the Company completed the acquisition of NPC Energy Corporation ("NPC"). The transaction consisted of a merger (the "NPC Merger") of NPC into the Company and its separate corporate existence ceased. The cost of acquiring NPC was approximately $3.20 million, consisting of the following (in thousands): Estimated fair value of 562,000 shares of MBOC common stock issued.............................. $ 1,967 Cash consideration......................................... 1,226 Legal and accounting expenses.............................. 35 ------- $ 3,228 =======
The fair value of the securities issued in connection with the NPC Merger was calculated assuming the price of the Company's common stock was $3.50 per share. 45 MIDDLE BAY OIL COMPANY, INC. Notes to Consolidated Financial Statements December 31, 1997 and 1996 Continued (2) ACQUISITIONS (continued) The Company's purchase price was allocated to the assets and liabilities of NPC based on estimates of the fair values with the remaining purchase price allocated to proved oil and gas properties. No goodwill was recorded in this transaction. The allocation of the purchase price is summarized as follows: (in thousands) Working capital......................................... $ 775 Oil and gas properties (proved)......................... 3,378 Debt assumed............................................ (385) Deferred income taxes................................... (540) ------- $ 3,228 =======
On February 28, 1997, the Company completed the acquisition of Bison Energy Corporation ("BEC"). The transaction consisted of a merger (the "Bison Merger") of BEC into Bison Energy Corporation-Alabama, a wholly-owned subsidiary of the Company. On February 28, 1997, Bison Energy Corporation-Alabama merged into BEC and its separate corporate existence ceased. BEC continues as a wholly-owned subsidiary of the Company. The cost of acquiring BEC was approximately $10 million, consisting of the following (in thousands): Estimated fair value of 605,556 shares of MBOC common stock issued....................... $ 3,330 Cash consideration.................................. 6,654 Legal and accounting expenses....................... 35 ---------- $ 10,019 ==========
The fair value of the securities issued in connection with the merger was calculated using the price of the Company's common stock at the time the Bison Merger was announced to the public of $5.50 per share. The Company's purchase price was allocated to the consolidated assets and liabilities of BEC based on estimates of the fair values with the remaining purchase price allocated to proved oil and gas properties. No goodwill was recorded in this transaction. The allocation of the purchase price is summarized as follows: (in thousands) Working capital..................................... $ 714 Oil and gas properties (proved)..................... 13,268 Yard equipment...................................... 465 Deferred income taxes............................... (4,428) ----------- $ 10,019 ===========
The price paid for BEC and the allocation of the purchase price, both detailed above, excludes the $1,445,890 allocated to non-oil and gas assets that were purchased in the merger and sold on March 3, 1997 for $1,445,890. 46 MIDDLE BAY OIL COMPANY, INC. Notes to Consolidated Financial Statements December 31, 1997 and 1996 Continued (2) ACQUISITIONS (continued) On June 30, 1997, the Company completed the acquisition of Shore Oil Company ("Shore"). The transaction consisted of a merger (the "Shore Merger") of Shore into Shore Acquisition Company Inc., a wholly-owned subsidiary of the Company. On June 30, 1997, Shore Acquisition Company merged into Shore and its separate corporate existence ceased. Shore continues as a wholly-owned subsidiary of the Company. The cost of acquiring Shore was approximately $19 million, consisting of the following (in thousands): Estimated fair value of 1,883,333 shares of MBOC common stock issued...................... $ 12,976 Estimated fair value of 266,667 shares of MBOC Series B preferred stock................. 3,627 Cash consideration................................. 2,533 Legal and accounting expenses...................... 38 ---------- $ 19,174 ==========
The fair value of the securities issued in connection with the merger was calculated using the average price of the Company's common stock at the time the Shore Merger was announced to the public and further adjusted for tradability restrictions. An independent valuation firm determined the tradability discount for the Company's common stock. The Company's purchase price was allocated to the consolidated assets and liabilities of Shore based on estimates of the fair values with the remaining purchase price allocated to proved and unproved oil and gas properties. No goodwill was recorded in this transaction. The allocation of the purchase price is summarized as follows: (in thousands) Working capital.................................... $ 2,288 Oil and gas properties (proved and unproved)....... 20,688 Fee minerals....................................... 5,495 Debt assumed....................................... (2,105) Deferred income taxes.............................. (7,192) ----------- $ 19,174 ===========
47 MIDDLE BAY OIL COMPANY, INC. Notes to Consolidated Financial Statements December 31, 1997 and 1996 Continued (2) ACQUISITIONS (concluded) The following pro forma data presents the results of the Company for the twelve months ended December 31, 1997 and 1996, as if the acquisitions of NPC, BEC and Shore had occurred on January 1, 1996. The pro forma results are presented for comparative purposes only and are not necessarily indicative of the results which would have been obtained had the acquisitions been consummated as presented. The following data reflect pro forma adjustments for oil and gas revenues, production costs, depreciation and depletion related to the properties and businesses acquired, preferred stock dividends on preferred stock issued, and the related income tax effects (in thousands, except per share amounts).
Pro Forma (Unaudited) 1997 1996 --------- ----------- Total revenues.................................... $ 14,753 $ 15,068 Net loss.......................................... (22,466) (946) Loss per diluted share............................ (6.61) (0.65)
(3) RELATED PARTY TRANSACTIONS The Company had a note receivable from Bay City Energy Group, Inc. (successor entity to Bay City Minerals, Inc., effective September 26, 1995) a significant stockholder, as of December 31, 1997 and 1996 in the amount of $166,165 and $159,215 respectively. The principal balance of the note accrues interest at 5% annually and is due January 1, 2001. The note is secured by 75,000 shares of Company common stock. Bay City Energy Group, Inc. made no cash payments to the Company and was advanced $26,668 during the year ended December 31, 1996. Interest of $27,160 was accrued on the note as of December 31, 1997. The Company rents office space from C.J. Lett III, a shareholder, officer and director of the Company. The rent is $3,000 per month for three years through February, 2000. Gary R. Christopher, a shareholder and director of the Company, is employed by Kaiser-Francis Oil Co., which owns approximately 43% of the common stock of the Company. 48 MIDDLE BAY OIL COMPANY, INC. Notes to Consolidated Financial Statements December 31, 1997 and 1996 Continued (4) LONG-TERM DEBT Long-term debt at December 31, 1997 and 1996, consisted of the following:
1997 1996 ------------ ----------- Convertible Loan for $50,000,000 due March 31, 1998, secured by oil and gas properties, monthly payments of interest only at LIBOR plus 1.75%, convertible into a 72 month term note on March 31, 1998 $ 10,956,298 $ -- Convertible loan for $6,000,000 due September 30, 1997, Secured by oil and gas properties, monthly payments of interest only at 1.5% over prime, convertible into a 72 month term note on September 30, 1997 -- 5,186,596 Term note due August 31, 1998, secured by oil and gas properties, repayable in monthly installments of $27,590 plus interest at 9.5% -- 385,089 Note, due 1/1/99, secured by office building, repayable in monthly installments of $1,511 including interest at 73/4% 133,952 141,393 ------------ ----------- Total 11,090,250 5,713,078 Less current maturities (1,375,537) (554,601) ------------ ----------- Long term debt excluding current maturities $ 9,714,713 $ 5,158,477 ============ ===========
On April 3, 1996, the Bank converted its $5.6 million term note into a $6.0 million, one-year, revolving line-of-credit (the "6 million Convertible Loan"), effective April 1, 1996. The $6 million Convertible Loan required monthly payments of interest only at prime plus 1.5% and converted into a term note payable in seventy-one consecutive equal monthly principal and interest payments at prime plus 1.5%, with the remaining principal and interest payment due on March 31, 2003. Effective March 31, 1997, the Company refinanced the $6 million Convertible Loan at its current principal balance of $5,186,596 with a $15 million Convertible Loan. The $15 million Convertible Loan required monthly payments of interest only at prime for one year and converts into a term note payable in seventy-one consecutive equal monthly principal and interest payments at prime, with the remaining principal and interest payment due on March 31, 2004. The $15 million Convertible Loan also required payment of a commitment fee equal to an annual rate of three-eighths percent of the excess of the Borrowing Base over the principal balance of the convertible note. Effective August 25, 1997, the Company refinanced the $15 million Convertible Loan at its current principal balance of $5,851,298 with a $50 million Convertible Loan. The $50 million Convertible Loan requires monthly payments of interest only at a fixed rate of Libor plus 1.75% as long as the principal amount of the loan is less than 75% of the current borrowing base of $15 million. If the principal amount of the loan is greater than or equal to 75% of the borrowing base the rate increases to Libor plus 2.00%. The Company has the option of switching to a floating prime rate. The $50 million Convertible Loan converts into a term note 49 MIDDLE BAY OIL COMPANY, INC. Notes to Consolidated Financial Statements December 31, 1997 and 1996 Continued (4) LONG-TERM DEBT (concluded) payable in seventy-one consecutive equal monthly principal and interest payments at prime, with the remaining principal and interest payment due on March 31, 2004. The $50 million Convertible Loan also requires payment of a commitment fee equal to an annual rate of three-eighths percent of the excess of the Borrowing Base over the principal balance of the convertible note. The principal balance of the $50 million Convertible Loan at December 31, 1997 was $10,956,298. The initial borrowing base of the $50 million Convertible Loan at closing on August 25, 1997, was $15 million. The borrowing base will be redetermined on March 31 and September 30, commencing September 30, 1997, by the Bank's engineers or any other independent engineer using the Bank's pricing and discount factors and the future net revenue expected to be produced from the Company's oil and gas reserves. If at any time during the period of the Convertible Loan (and the period subsequent to the conversion to the term note) the collateral borrowing base, as determined by the Bank, should be less than the aggregate unpaid principal balance of the note, the collateral deficiency shall be cured by making a cash prepayment on the note in the amount of the deficiency or by increasing the monthly principal payments for the next six months to reduce the principal balance to the projected borrowing base as of the next semiannual redetermination date. The $50,000,000 convertible loan contains certain restrictive provisions the most significant of which restricts additional borrowings, either directly or indirectly, and payment of dividends. At December 31, 1997, the Company was in compliance with all covenants specified in the agreement. Aggregate amounts of expected required repayments of long term debt at December 31, 1997 are as follows: 1998 $ 1,375,537 1999 1,954,001 2000 1,826,050 2001 1,826,050 2002 1,826,050 Thereafter 2,282,562 ------------- $ 11,090,250
50 MIDDLE BAY OIL COMPANY, INC. Notes to Consolidated Financial Statements December 31, 1997 and 1996 Continued (5) INCOME TAXES Income tax (benefit)expense for the years ended December 31 consisted of the following:
1997 1996 ---- ---- Current $ 6,451 $ 5,079 Deferred (7,451,249) 69,792 ------------ ----------- Total $ (7,444,798) $ 74,871 ============ ===========
The reconciliation of income tax computed at the U.S. federal statutory tax rates to the provision for income taxes is as follows:
1997 1996 ---- ---- Income tax (benefit)expense at statutory rate $(7,828,207) $ 92,595 Increase(decrease) due to effect of graduated tax rates 96,853 (96,740) Increase due to state taxes and other 286,556 79,016 ----------- ----------- Income tax (benefit)expense $(7,444,798) $ 74,871 =========== ===========
The Company's net deferred tax liability at December 31, 1997 and 1996 is as follows:
1997 1996 ---- ---- Deferred tax liability Oil and Gas Properties $ 5,906,070 $ 817,079 Deferred tax asset NOL carryforward (1,083,324) (164,076) AMT tax credit carryforward (36,482) (36,482) Other (5,736) (5,736) ------------ ---------- (1,125,542) (206,294) Valuation allowance -- -- ------------ ---------- Net deferred tax liability $ 4,780,528 $ 610,785 ============ ==========
As of December 31, 1997, the Company had net operating loss carryforwards of $3,186,247 expiring in the years 2009 through 2011. 51 MIDDLE BAY OIL COMPANY, INC. Notes to Consolidated Financial Statements December 31, 1997 and 1996 Continued (6) RETIREMENT PLAN All of the employees of the Company participate in a defined contribution plan which provides for a maximum discretionary Company contribution of 15% of total wages paid to employees for the year. The Company contributed $51,560 and $5,000 to the plans for the years ended December 31, 1997 and 1996, respectively. (7) STOCK OPTION AND STOCK APPRECIATION RIGHTS PLAN At December 31, 1997, the Company had one fixed stock option plan, the 1995 Stock Option and Stock Appreciation Rights Plan (1995 Plan). The Company applies APB Opinion 25, "Accounting for Stock Issued to Employees" and related interpretations in accounting for the plan; accordingly, no compensation cost has been recognized. Had compensation cost for the Company's 1995 Plan been determined based on the fair value at the grant date for stock options granted during 1997 and 1996 consistent with the method of FASB Statement 123, "Accounting for Stock Based Compensation"' the Company's net income and earnings per share would have been reduce to the pro forma amounts listed below:
1997 1996 ------------- --------- Net (Loss)Income As Reported $ (16,184,052) $ 205,500 Pro Forma (16,463,666) 189,657 Basic (loss)earnings per share As Reported $ (4.76) $ 0.15 Pro Forma (4.85) 0.14 Diluted (loss)earnings per share As Reported $ (4.76) $ 0.14 Pro Forma (4.85) 0.13
The fair value of each option is estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions used for the grants in 1997 and 1996; no dividend yield; expected volatility of 60 percent and 50 percent, respectively; risk-free interest rate of 6.06% and 6.38%, respectively; and expected life of 3 years. At December 31, 1997, the range of exercise prices and weighted average remaining contractual life of options outstanding was $2.50 and $7.00 and 9.06 years, respectively. The 1995 Plan At December 31, 1997 there were 80,000 shares of common stock available for grant under the 1995 plan. All of the options granted under the 1995 Plan have an exercise price equal to the fair market value of the Company's common stock at the date of the grant and expire ten (10) years from the date of grant if not exercised. All of the options granted under the 1995 Plan are 100% vested. The 1995 Plan is administered by the Compensation Committee of the Board of Directors. 52 MIDDLE BAY OIL COMPANY, INC. Notes to Consolidated Financial Statements December 31, 1997 and 1996 Continued 7) STOCK OPTION AND STOCK APPRECIATION RIGHTS PLAN (concluded) Information relating to stock options is summarized below:
Exercise Price Shares Per Share ------ -------------- Options outstanding at January 1, 1996....................... -- -- Granted...................................................... 125,000 $ 2.50 --------- Options outstanding at December 31, 1996..................... 125,000 $ 2.50 Granted...................................................... 520,000 $ 6.07 Exercised.................................................... 40,833 $ 2.50 --------- Options outstanding at December 31, 1997..................... 604,167 $ 5.57 Options exercisable at December 31, 1997 604,167 $ 5.57
Options to acquire 225,000 shares of the Company common stock at an exercise price of $5.50 were granted outside of the 1995 Plan on February 13, 1997 to certain officers of the Company. (8) CAPITAL STOCK Preferred Stock In connection with the merger with Shore Oil Company, effective June 30, 1997, the Company issued 266,667 shares of Series B Preferred Stock ("Series B"). The Series B is nonvoting and pays no dividends. The Series B has a liquidation value of $7.50 per share and is junior to the Series A Preferred. For a period of sixty-six months subsequent to June 30, 1997 any holder of the Series B may convert all or any portion of Series B shares into Company Common Stock ("Common") at a ratio of one share of Common for each Series B share or at any time on or after January 1, 1998, the holders may convert their Series B Preferred shares based on a conversion method whereby the number of convertible Series B Preferred shares is calculated as the increase in value of approximately 40,000 acres of mineral interest owned by Shore at the end of the year divided by $8,000,000 and multiplied by 266,667 shares. Each of the convertible Series B Preferred shares is then multiplied by 1,066,000 to arrive at the potential converted number of common shares. Upon expiration of the conversion period, unless the Company has given notice to redeem the Series B, all of the shares of Series B shall be automatically converted. In no event shall the aggregate total number of shares of Common into which the Series B are converted be less than 266,667 shares or exceed 1,333,333 shares, unless further increased for any anti-dilution provisions. 53 MIDDLE BAY OIL COMPANY, INC. Notes to Consolidated Financial Statements December 31, 1997 and 1996 Continued (8) CAPITAL STOCK (continued) Preferred Stock (concluded) On September 4, 1996, the Company signed a stock purchase agreement with Kaiser Francis Oil Company ("the Agreement"). Kaiser-Francis has agreed to purchase 1,666,667 shares of Series A Preferred Stock ("Series A") at $6.00 per share, for a total investment of $10,000,000. The parties agreed to a five-year purchase period, effective September 4, 1996, with minimum incremental investments of $500,000 each. Each issuance of Series A is subject to approval by Kaiser-Francis of the use of proceeds. The Series A is nonvoting and accrues dividends at 8% per annum, payable quarterly in cash. The Series A is convertible at any time after issuance into shares of common stock at the rate of two shares of common stock for each share of Series A before January 1, 1998. The conversion rate decreases thereafter at 8% per annum. The Company will pay the costs of registration of the Series A or the underlying common stock upon request of Kaiser-Francis. The Company may redeem the Series A in whole or in part, at any time after January 1, 2007 at a price of $6.00 per share. As of December 31, 1997, 1,666,667 shares of the Series A had been issued. Common Stock On April 1, 1996, the Board of Directors authorized the repurchase of up to $100,000 of Company common stock at a price per share not to exceed $3.25, exclusive of brokerage costs. As of December 31, 1997 the Company had purchased 21,773 shares of common stock at a cost of $68,040. Under the terms of the Janex Acquisition in 1993, the Company had a contingent obligation to repurchase 142,107 common shares issued in the Janex Acquisition, upon written notice delivered to the Company, beginning five years after the closing date and continuing for thirty days thereafter, at a price of $6.00 per share. This obligation will terminate if the Company's stock trades at a share price of $8.00 or greater for twenty consecutive trading days during the thirty-six month period ending November 1, 1998. At the close of trading on April 7, 1997, the Company's common stock had traded at an ask price that was equal to, or exceeded, $8.00 per share for twenty consecutive trading days. Therefore, the contingent obligation represented by the redeemable common stock balance on the Company's balance sheet in the amount of $421,179 was reclassified to additional paid-in capital effective April 7, 1997. On February 13, 1997, the Company awarded the President, Vice-President/ Chief Financial Officer and Vice-President of Engineering stock options to acquire 100,000, 62,500 and 62,500 shares of common stock, respectively, at an exercise price of $5.50 per share. All of the options vested on the date of grant. The exercise price was equal to the fair market value of common stock on the date of grant. On the same date, the Company awarded to the President, Vice-President/ Chief Financial Officer and Vice-President of Engineering, 25,909, 11,591 and 11,591 shares of restricted stock of the Company, respectively. The restricted stock awards are contingent on the performance of services to the Company in the future with 50% of the restricted shares being earned over the six month period July, 1997 to December 31, 1997 and 50% over the six month period January 1, 1998 to June 30, 1998. As of December 31, 1997, 50% of the restricted stock awards had been earned. On May 30, 1997, the Board of Directors granted options to acquire 85,000 shares of Company common stock under the 1995 Stock Option and Stock Appreciation Rights Plan to certain key employees. All of the options vested on the grant date of May 30, 1997 with an exercise price of $7.75 per share, which was equal to the fair market value of common stock on the date of grant. The options expire ten years from the date of grant if not exercised. 54 MIDDLE BAY OIL COMPANY, INC. Notes to Consolidated Financial Statements December 31, 1997 and 1996 Continued (8) CAPITAL STOCK (concluded) Common Stock (concluded) On February 6, 1997, the Board of Directors granted options to acquire 210,000 shares of Company common stock under the 1995 Stock Option and Stock Appreciation Rights Plan to key employees and non-employee directors. All of the options vested on the grant date of February 6, 1997 with an exercise price of $6.00 per share, which was equal to the fair market value of common stock on the date of grant. The options expire ten years from the date of grant if not exercised. On May 31, 1996, the Board of Directors granted options to acquire 125,000 shares of Company common stock under the 1995 Stock Option and Stock Appreciation Rights Plan to key employees and non-employee directors. All of the options vested on the grant date of May 31, 1996 with an exercise price of $2.50 per share, which was equal to the fair market value of common stock on the date of grant. The options expire ten years from the date of grant if not exercised. Earnings Per Share The following table provides a reconciliation between basic and diluted earnings (loss) per share:
Weight Average Per Common Shares Share Net (Loss)Income Outstanding Amount ---------------- ------------- -------- Year Ended December 31, 1997: Basic earnings per share $(16,184,052) 3,397,117 $ (4.76) Effect of dilutive stock options -- -- -- ------------ --------- -------- Diluted earnings per share $(16,184,052) 3,397,117 $ (4.76) ============ ========= ======== Year Ended December 31, 1996 (restated): Basic earnings per share $ 205,500 1,332,141 $ .15 Effect of dilutive stock options -- 117,714 (.01) ------------ --------- -------- Diluted earnings per share $ 205,500 1,449,855 $ .14 ============ ========= ========
At December 31, 1997, the Company had 604,167 stock options outstanding with exercise prices ranging from $2.50 to $7.75 which were not included in the computation of diluted earnings per share, because the effect of the assumed exercise of these stock options would have an antidilutive effect on the computation of diluted loss per share. 55 MIDDLE BAY OIL COMPANY, INC. Notes to Financial Statements December 31, 1997 and 1996 Continued (9) COMMITMENTS AND CONTINGENCIES The Company is obligated under the terms of certain operating leases for office space that expire over the next three years. Total rent expense was $97,588 and $12,144 for the years ended December 31, 1997 and 1996, respectively. Future minimum rental payments under the Company's leases total $149,658, $114,912, and $6,000 for 1998, 1999, and 2000, respectively. On April 3, 1996, the Company entered into a Joint Expense and Participation Agreement with Brigham Oil & Gas, L.P. which allowed the Company to participate in the drilling of ninety-one (91) onshore wells in Texas and Oklahoma over the twelve month period beginning April 1, 1996. The Company committed to fund $1,500,000 in drilling costs over this twelve month period. As of December 31, 1997, the Company had advanced $1,944,499 in drilling and completion costs to Brigham Oil and Gas, L.P. The Company is no longer required to advance any additional money under the Agreement. As of December 31, 1997, the Company is committed to pay approximately $400,000 under various AFEs for work to be performed in 1998. The actual amounts due may be higher or lower than the amounts estimated in the AFEs. The Company is a defendant in various legal proceedings which are considered routine litigation incidental to the Company's business, the disposition of which management believes will not have a material effect on the financial position or results of operations of the Company. (10) SUBSEQUENT EVENTS Recent Transactions On January 31, 1998, Kaiser Francis Oil Company converted 100% of the shares of the Series A Preferred stock into 3,333,334 common shares of the Company. On February 19, 1998, the Company commenced a cash tender offer for the common shares of Enex Resources Corporation ("Enex") at a price of $15 per share. As of February 10, 1998, there were 1,343,352 common shares of Enex outstanding. On a diluted basis, there would be 1,486,352 shares outstanding. The purpose of the tender offer is to acquire common shares that will represent at least a majority of the outstanding common stock of Enex. The tender offer is intended to result in the acquisition of 100% of Enex's outstanding common stock. The tender offer is scheduled to expire on March 16, 1998, unless extended. Enex is an independent oil and gas production and development company, headquartered in Kingwood, Texas, with operations primarily in Texas. Enex common stock trades on the NASDAQ National Market System. 56 MIDDLE BAY OIL COMPANY, INC. Notes to Consolidated Financial Statements December 31, 1997 and 1996 Continued (11) SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) CAPITALIZED COSTS AND COSTS INCURRED (UNAUDITED) The following tables present the (1) capitalized costs related to oil and gas producing activities and the related depreciation, depletion, amortization and impairment and (2) costs incurred in oil and gas property acquisition, exploration and development activities (in thousands).
1997 1996 -------- -------- Capitalized Costs - ----------------- Proved properties $ 56,441 $ 15,561 Nonproducing leasehold 6,118 376 Support equipment & facilities 95 315 Accumulated depreciation, depletion, amortization and impairment (30,456) (5,237) -------- -------- Net capitalized costs $ 32,198 $ 11,015 ======== ======== Costs Incurred - -------------- Proved properties $ 38,099 $ 3,402 Unproved properties 6,195 -- Exploration costs 1,912 1,453 Development costs 1,862 540 -------- -------- Total $ 48,068 $ 5,395 ======== ======== Depletion, depreciation, amortization and impairment $ 25,651 $ 1,433 ======== ========
ESTIMATED QUANTITIES OF RESERVES (UNAUDITED) The Company has interests in oil and gas properties that are located principally in Alabama, Louisiana, Kansas, New Mexico, Oklahoma and Texas. The Company does not own or lease any oil and gas properties outside the United States. There are no quantities of oil and gas subject to long-term supply or similar agreements with any governmental agencies. The Company retains independent engineering firms to provide annual year end estimates of the Company's future net recoverable oil, gas and natural gas liquids reserves. The information for 1997 is based upon estimates prepared by Lee Keeling and Associates, Inc., Cawley, Gillespie and Associates, Inc., Ryder Scott Company, Huddleston & Company, Inc., and DeGoyler & MacNaughton, which were engaged to perform an evaluation of the Company's oil and gas reserves. The information for 1996 was prepared by Lee Keeling and Associates, Inc. and Cawley, Gillespie and Associates, Inc. The reserve information was prepared in accordance with guidelines established by the Securities and Exchange Commission. Estimated proved net recoverable reserves as shown below include only those quantities that can be expected to be commercially recoverable at prices and costs in effect at the balance sheet dates under existing regulatory practices and with conventional equipment and operating methods. Proved developed reserves represent only those reserves expected to be recovered through existing wells. Proved undeveloped reserves include those reserves expected to be recovered from new wells or on undrilled acreage or from existing wells on which a relatively major expenditure is required for recompletion. 57 MIDDLE BAY OIL COMPANY, INC. Notes to Consolidated Financial Statements December 31, 1997 and 1996 Continued (11) SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (continued) ESTIMATED QUANTITIES OF RESERVES (UNAUDITED) (continued) Net quantities of proved developed and undeveloped reserves of natural gas and crude oil, including condensate and natural gas liquids, are summarized as follows:
Years Ended December 31 --------------------- ------------------------ 1997 1996 ----------- ---------- ---------- ---------- Oil Gas Oil Gas Proved Reserves (Barrels) (Mcf) (Barrels) (Mcf) - --------------- ---------- ----------- ---------- ---------- Beginning of year 1,389,945 8,964,238 777,550 6,370,830 Revisions of previous estimates (205,733) (1,431,708) 157,099 44,543 Extensions and discoveries 22,520 705,020 76,492 392,275 Purchases of reserves in place 1,980,117 12,110,748 503,156 3,139,299 Sale of reserves in place -- -- (15,726) -- Production for the year (253,849) (1,929,298) (108,626) (982,709) ---------- ----------- ---------- ---------- End of year 2,933,000 18,419,000 1,389,945 8,964,238 ========== =========== ========== ========== Proved Developed Reserves - ------------------------- Beginning of year 1,266,421 8,142,820 770,334 6,306,604 ========== =========== ========== ========== End of year 2,580,000 14,251,000 1,266,421 8,142,820 ========== =========== ========== ==========
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED RESERVES (UNAUDITED) The following is a summary of the standardized measure of discounted future net cash flows related to the Company's proved oil and gas reserves. For these calculations, estimated future cash flows from estimated future production of proved reserves are computed using oil and gas prices as of the end of each period presented. Future development and production costs attributable to the proved reserves were estimated assuming that existing conditions would continue over the economic lives of the individual leases and costs were not escalated for the future. Estimated future income taxes were calculated by applying statutory tax rates (based on current law adjusted for permanent differences and tax credits) to the estimated future pre-tax net cash flows related to proved oil and gas reserves, less the tax basis of the properties involved. 58 MIDDLE BAY OIL COMPANY, INC. Notes to Consolidated Financial Statements December 31, 1997 and 1996 Continued (11) SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (continued) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED RESERVES (UNAUDITED) (continued) The Company cautions against using this data to determine the value of its oil and gas properties. To obtain the best estimate of the fair value of the oil and gas properties, forecasts of future economic conditions, varying discount rates, and consideration of other than proved reserves would have to be incorporated into the calculation. In addition, there are significant uncertainties inherent in estimating quantities of proved reserves and in projecting rates of production that impair the usefulness of the data. The standardized measure of discounted future net cash flows relating to proved oil and gas reserves are summarized as follows (in thousands):
Years Ended December 31 ----------- ---------- 1997 1996 ---------- ---------- Future cash inflows $ 101,482 $ 61,813 Future production costs and development costs (54,358) (25,873) Future income tax expenses (11,853) (7,361) --------- ---------- Future net cash flows 35,271 28,579 10% discount to reflect timing of cash flows (10,778) (10,716) --------- ---------- Standardized measure of discounted future net cash flows $ 24,493 $ 17,863 ========= ==========
The following are the principal sources of changes in the standardized measure of discounted future net cash flows (in thousands):
Years Ended December 31 1997 1996 --------- --------- Beginning of year $ 17,863 $ 9,250 Sales of oil and gas, net of production cost (6,364) (2,959) Net changes in price and production cost (11,108) 8,521 Extensions and discoveries 851 1,966 Purchase of reserves 20,293 6,006 Sale of reserves -- (29) Revisions of quantity estimates and other 1,794 (2,551) Net change in income taxes (1,082) (3,382) Accretion of discount 2,246 1,041 --------- -------- End of year $ 24,493 $ 17,863 ========= =========
59 MIDDLE BAY OIL COMPANY, INC. Notes to Consolidated Financial Statements December 31, 1997 and 1996 Concluded (11) SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (concluded) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED RESERVES (UNAUDITED) (concluded) During recent years, there have been significant fluctuations in the prices paid for crude oil in the world markets. The situation has had a destabilizing effect on the crude oil posted prices in the United States, including the posted prices paid by purchasers of the Company's crude oil. The year end prices of oil and gas at December 31, 1997 and 1996, used in the above table were $16.18 and $24.50 per barrel of oil and $2.54 and $3.70 per thousand cubic feet of gas, respectively. 60 ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Inapplicable. [The remainder of this page has been intentionally left blank] II - 42 61 PART III ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS; COMPLIANCE WITH SECTION 16(A) OF THE EXCHANGE ACT (a) Executive Officers and Directors The following table sets forth the executive officers and directors of the Company as of December 31, 1997. All directors serve for a one-year term or until the next Annual Meeting of Shareholders of the Company. The Board of Directors held three meetings during the fiscal year ended December 31, 1997. Each director attended all meetings of the Board. Executive officers serve at the pleasure of the Board of Directors.
Director Name Age Position(s) Held Since ---- --- ---------------- ----- John J. Bassett(1) 39 Chairman, President and 1989 Chief Executive Officer C. J. Lett, III 40 Executive Vice President 1997 Frank C. Turner, II(2)(3) 37 Vice President and Chief N/A Stephen W. Herod(3) 38 Vice President 1997 Financial Officer Robert W. Hammons 44 Vice President N/A Lynn M. Davis 49 Secretary and Treasurer N/A Edward P. Turner, Jr.(1)(2) 68 Director 1989 Frank E. Bolling, Jr. 38 Director 1992 Alvin V. Shoemaker(4) 59 Director 1997 Gary R. Christopher 48 Director 1997
(1) John J. Bassett and Edward P. Turner, Jr. were elected upon the organization of Middle Bay Oil Company as a corporation in November, 1992. Previously they served as directors of Bay City Minerals, Inc., the general partner of the Predecessor Partnership. (2) Edward P. Turner, Jr. and Frank C. Turner, II, are father and son. (3) Mr. Herod replaced Frank C. Turner, II effective July 3, 1997. III-1 62 (4) Mr. Shoemaker replaced C. Noell Rather effective July 28, 1997. John J. Bassett has served as President and a director of the Company since 1992 and was elected Chairman of the Board of Directors in 1992. He served as President of the general partner of the Predecessor Partnership from 1987 to 1992. He also serves as a director and President of Bay City Energy Group, Inc., a principal shareholder of the Company. Stephen W. Herod has served as Vice President - Corporate Development and a director of the Company since July 1, 1997. Mr. Herod served as President and a director of Shore Oil Company from April, 1992 until the merger of Shore and the Company on June 30, 1997. He joined Shore's predecessor as Controller in February, 1991. In addition, Mr. Herod was employed by Conquest Exploration Company from 1984 until 1991 in various financial management positions, including Operations Accounting Manager. From 1981 to 1984, Mr. Herod was employed by Superior Oil Company as a financial analyst. Frank C. Turner, II has served as Vice President and Chief Financial Officer for the Company since its organization as a corporation in 1992. He had previously served as Vice President of Finance for the general partner of the Predecessor Partnership since 1990. From 1987 to 1990, Mr. Turner was employed by Sonat, Inc. as a financial analyst. He also serves as a director and Vice President of Bay City Energy Group, Inc. Robert W. Hammons was hired by the Company in April, 1992 as a reservoir engineer. Mr. Hammons was appointed Vice President of Engineering of the Company in 1993. Prior to his employment with the Company, he had worked with Bay City Minerals, Inc. as an independent petroleum engineering consultant since 1987. Prior to 1987, Mr. Hammons was employed as manager of reservoir engineering for Marion Corporation. Lynn M. Davis has been Secretary and Treasurer for the Company since 1992. She has served as Secretary-Treasurer of the general partner of the Predecessor Partnership since 1984 and as a director since 1988. Ms. Davis also serves as a director and Secretary-Treasurer for Bay City Energy Group, Inc. Edward P. Turner, Jr. served as President of Bay City Minerals, Inc. from 1975 to 1987. He is a member of the Alabama State Bar and a managing partner of the law firm of Turner, Onderdonk, Kimbrough & Howell, P.A., in Chatom, Alabama. A substantial amount of his practice is devoted to oil and gas law. Mr. Turner also serves as a director of Bay City Energy Group, Inc. Frank E. Bolling, Jr. has been employed by Midstream Fuel Services, Inc. as Vice President of Retail Operations since February, 1995. Prior to his employment with Midstream, Mr. Bolling served as Vice President and General Manager of Dantzler Bulk Plant, Inc., a distributor for Chevron U.S.A., Inc. with annual sales in excess of $25 million. Mr. Bolling served as sales manager for Dantzler from 1987 to 1989. Prior to 1987, Mr. Bolling was employed by Bay City Minerals, Inc. Alvin V. Shoemaker is a former Chairman of the Board of First Boston Corporation and former President of Blyth Eastman Paine Webber. He has also worked for the U.S. Treasury. He has been Chairman of the Board of Trustees of the University of Pennsylvania, Vice Chairman of the Securities Industry III-2 63 Association and a director of Harcourt Brace Jovanovich, Royal Insurance of America, the Council on Foreign Relations and the Wharton School of Finance Board. Mr. Shoemaker is also a director of Hanover Compressor Company. Gary R. Christopher is Acquisitions Coordinator of Kaiser-Francis Oil Company, a position he has held since February, 1996. From 1991 to 1996, Mr. Christopher served as Senior Vice President and Manager of Energy Lending for the Bank of Oklahoma. He continues to serve as a consultant to the Bank of Oklahoma. Kaiser-Francis Oil Company owns 1,166,667 shares of the Company's Series A Preferred stock; each such preferred share is convertible into two shares of common stock. C. J. Lett, III has served as Executive Vice President for the Company since February 28, 1997. Mr. Lett is also President and a director of Bison Energy Corporation, a position he has held since 1981. (b) Compliance with Section 16(a) of the Exchange Act Section 16(a) of the Securities Exchange Act of 1934 requires the Company's directors and executive officers and any persons who own more than 10% of the Company's common stock to file with the Securities and Exchange Commission reports of ownership and changes in ownership of such securities. Based on representations from such persons, the Company believes that there was no failure to file or delinquent filings under Section 16(a) of the Securities Exchange Act of 1934 by any officer, director or beneficial owner of 10% or more of the Company's common stock during 1997. (c) Audit and Compensation Committees The members of the Audit Committee are Gary R. Christopher, Frank E. Bolling, Jr. and Alvin V. Shoemaker. The functions of the Audit Committee include recommending to the Board of Directors the independent auditors; reviewing and approving the planned scope of the annual audit; proposing fee arrangements; reviewing the results of the annual audit; reviewing the adequacy of the accounting and financial controls; reviewing the independence of the independent auditors; approving all assignments to be performed by the independent auditors; and instructing the independent auditors, as deemed appropriate, to undertake special assignments. The members of the Compensation Committee are John J. Bassett, Edward P. Turner, Jr. and Frank E. Bolling, Jr. The functions of the Compensation Committee are to approve or recommend for approval to the Board of Directors, the compensation and remuneration arrangements for directors and senior management. III-3 64 ITEM 10. EXECUTIVE COMPENSATION (a) Summary Compensation Table The following table sets forth the aggregate cash compensation earned by and paid to the Company's executive officers for the periods ended December 31, 1995 through December 31, 1997:
Annual Compensation Long-Term Compensation ------------------------------------- ----------------------- Awards Payouts ------ ------- Securities Underlying Restr. Options/ All Other Name and Other Annual Stock SARs LTIP Compensation Principal Position Year Salary ($) Bonus ($) Compensation Awards($) (#) Payouts ($) ($) ------------------ ---- ---------- --------- ------------ --------- --- ----------- --- John J. Bassett 1997 95,521 6,001 -- 129,545 132,000 -- 13,032 President & 1996 58,075 -- -- -- 20,000 -- 2,271 Chief Executive 1995 56,250 -- -- -- -- -- 11,371 Officer Frank C. Turner, II 1997 85,729 6,000 -- 57,960 94,500 -- 16,250 Vice President & 1996 54,458 -- -- -- 20,000 -- 2,174 CFO 1995 50,083 -- -- -- -- -- 10,775 Robert W. Hammons 1997 85,729 6,000 -- 57,960 94,500 -- 12,500 Vice President - 1996 58,075 -- -- -- 20,000 -- 2,271 Engineering 1995 56,250 -- -- -- -- -- 11,360
(b) Option Grants in Last Fiscal Year The 1995 Stock Option and Stock Appreciation Rights Plan (the "Plan") is administered by the Compensation Committee (the "Committee") of the Board of Directors. At least two members of the Committee must be disinterested nonemployee directors. The Committee is authorized to determine the employees, including officers, to whom options or rights are granted. Each option or right granted shall be on such terms and conditions consistent with the Plan as the Committee may determine, but the duration of any option or right shall be not greater than ten years or less than five years from the date of grant. Options or rights grants shall be made under the Plan only to persons who are officers or salaried employees of the Company or are nonemployee directors. The aggregate number of shares of common stock of the Company which could be subject to options or rights under the Plan during 1997 was 500,000. During the fiscal year ended December 31, 1997, options covering 295,000 shares were issued under the Plan. The option price of shares covered by options granted under the Plan may not be less than the fair market value at the time the option is granted. The option price must be paid in full in cash or cash equivalent at the time of purchase or prior to delivery of the shares in accordance with cash payment arrangements acceptable to the Committee. If the Committee so determines, the option price may also be paid in shares of the Company's common stock already owned by the optionee. The Committee has discretion to III-4 65 determine the time or times when options become exercisable, within the limits set forth in the Plan. All options and rights granted under the Plan will, however, become fully exercisable if there is a change in control (as defined in the Plan) of the Company. The following table provides certain information with respect to all options granted during the fiscal year ended December 31, 1997 to any executive officer or director of the Company; 295,000 options were granted under the Plan and 225,000 were granted outside of the Plan: INDIVIDUAL GRANTS
Number of Securities % of Total Underlying Options/SARs Options/ Granted to SARS Employees in Exercise or Base Expiration Name Granted (#) Fiscal Year Price ($/Sh) Date ---- ----------- ----------- ------------ ---- John J. Bassett 100,000 19.0% 5.50 2/13/2007 32,000 6.0% 6.00 2/6/2007 Frank C. Turner, II 62,500 12.0% 5.50 2/13/2007 32,000 6.0% 6.00 2/6/2007 Robert W. Hammons 62,500 12.0% 5.50 2/13/2007 32,000 6.0% 6.00 2/6/2007 Lynn M. Davis 8,000 2.0% 6.00 2/6/2007 Edward P. Turner, Jr.* 21,400 4.0% 6.00 2/6/2007 Frank E. Bolling, Jr.* 21,400 4.0% 6.00 2/6/2007 C. Noell Rather** 21,200 4.0% 6.00 2/6/2007
*Nonemployee director **Former nonemployee director III - 5 66 (c) Aggregated Option Exercises in Last Fiscal Year and Option Value Table as of December 31, 1997 The following table sets forth certain information concerning each exercise of stock options during the year ended December 31, 1997, by each of the named executive officers and directors and the aggregated fiscal year-end value of the unexercised options of each such named executive officer and director: INDIVIDUAL GRANTS
Number of Securities Value of Unexercised Underlying Unexercised In-the-Money Shares Options/SARs at Options/SARs at Acquired Value FY End (#) FY End ($) ----------------------- ------------------------ Name on Exercise (#) Realized ($) Exer. Unexer. Exer. Unexer. - ----------------------- --------------- ------------ ----------------------- ------------------------ John J. Bassett -- -- -- 152,000 -- 728,000 Frank C. Turner, II 20,000 115,000 20,000 94,500 150,000 409,250 Robert W. Hammons -- -- -- 114,500 -- 559,250 Lynn M. Davis 5,000 38,750 -- 8,000 37,500 32,000 Edward P. Turner, Jr.* -- -- -- 34,734 -- 185,600 Frank E. Bolling, Jr.* -- -- -- 34,733 -- 185,600
*Nonemployee director (d) Other Compensation Under Plans The Company established a SEP/IRA retirement plan (the "SEP Plan") in 1993 which allows for a maximum discretionary Company contribution of 15% of total wages paid to employees for the year. For the years ended December 31, 1997, 1996 and 1995, the Company contributed a total of $51,500, $5,000 and $30,000 to the SEP Plan, respectively, including $32,064, $3,068 and $18,505, respectively, for all executive officers as a group. The Company established a 401-K Plan in October, 1997 which allows for voluntary contributions by the employees and the employer. No Company contributions were made in 1997. The Company has no other retirement, pension/profit sharing or other deferred compensation plan for its employees. III-6 67 (e) Long-Term Incentive Plan ("LTIP") Awards Table In March, 1995, the Board of Directors adopted an employee incentive compensation plan whereby the proceeds equivalent to 1% net profits interest (the "net profits interest") in all oil and gas properties, drilling prospects and divestitures acquired or made after January 1, 1994 are paid into a fund for incentive compensation awards to employees. For the years ended December 31, 1996 and 1995, the Company paid $6,916 and $30,000, respectively, to employees through the employee incentive plan, including $4,897 and $21,245 for all executive officers as a group. No amount was paid into the plan in 1997. (f) Directors' Fees Directors of the Company receive a fee of $500 per meeting and are reimbursed for documented travel expenses. Certain nonemployee directors have received stock options for their services as directors (see "Option Grants in Last Fiscal Year," above). (g) Employee Contracts and Termination of Employment and Change-in-Control Arrangements Mr. Bassett and Mr. Hammons in January, 1997, signed employment agreements with the Company which extend through January 31, 2002 and January 31, 2000, respectively, with automatic one-year extensions upon each anniversary date of the employment agreement thereafter unless either party gives at least 30 days' notice of termination. Each employment agreement is terminable by the Company before expiration of the term if such termination is for cause (as specified in the employment agreement). The executive employment agreements provide for an annual salary of not less than the base salaries of $95,000 and $85,000, respectively, which amounts may be adjusted from time to time by the Board of Directors upon the recommendation of the Compensation Committee. They also provide for fringe benefits in accordance with the Company's policies adopted from time to time for salaried executive employees holding comparable positions. Mr. Herod executed an employment agreement with the Company with an effective date of July 1, 1997 and extending through June 30, 1999, with automatic one-year extensions upon each anniversary date of the employment agreement thereafter unless either party gives at least 30 days' notice of termination. The employment agreement is terminable by the Company before expiration of the term if such termination is for cause (as specified in the employment agreement). The executive employment agreement provides for an annual salary of not less than the base salary of $100,000, which amount may be adjusted from time to time by the Board of Directors upon the recommendation of the Compensation Committee. It also provides for fringe benefits in accordance with the Company's policies adopted from time to time for salaried executive employees holding comparable positions. III-7 68 ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT (a) Security Ownership of Certain Beneficial Owners The following table sets forth the shares of the Company's common and preferred stock beneficially owned by those persons known by the Company to be the beneficial owner of more than five percent of the Company's issued and outstanding common and preferred stock as of December 31, 1997:
Title of Name and Address of Amount and Nature of Percent of Class(6) Beneficial Owner Beneficial Ownership Class ----- ------------------- -------------------- ----- Common C. J. Lett, III(1)(4) 1,197,556 13.8% 9320 East Central Wichita, Kansas 67206 Common Kaiser-Francis Oil Company(4) 3,333,334 38.3% 6733 South Yale Tulsa, Oklahoma 74136 Common Weskids, L.P.(2)(5) 843,687 10.0% 310 South Street Morristown, NJ 07960 Common Weskids, Inc. 843,687 10.0% 310 South Street Morristown, NJ 07960 Common Alvin V. Shoemaker(3)(4) 661,222 8.9% 8800 First Avenue Stone Harbor, NJ 08247 Preferred Weskids, L.P.(5) 117,467 44.1% Series B 310 South Street Morristown, NJ 07960 Preferred Alvin V. Shoemaker(4) 117,466 44.1% Series B 8800 First Avenue Stone Harbor, NJ 08247 Preferred Stephen W. Herod(4) 15,867 5.9% Series B 1110 Briar Ridge Drive Houston, TX 77057
III-8 69 Preferred W. Tim Sexton(4) 15,867 5.9% Series B 12010 Winwood Houston, TX 77024
(1) Mr. Lett has agreed that, for a period of one year from February 28, 1997, his voting power will be restricted to not more than votes representing 20% of the total number of shares of the Company's common stock issued and outstanding and eligible to vote at the time in connection with any vote taken or consent, waiver or ratification given in connection with the election or removal of directors of the Company. (2) Weskids, L.P. has agreed that, for a period of one year from June 30, 1997, its voting power will be restricted to not more than votes representing 20% of the total number of shares of the Company's common stock issued and outstanding and eligible to vote at the time in connection with any vote taken or consent, waiver or ratification given in connection with the election or removal of directors of the Company. (3) Mr. Shoemaker has agreed that, for a period of one year from June 30, 1997, his voting power will be restricted to not more than votes representing 20% of the total number of shares of the Company's common stock issued and outstanding and eligible to vote at the time in connection with any vote taken or consent, waiver or ratification given in connection with the election or removal of directors of the Company. (4) The nature of the beneficial ownership is sole voting and investment power. (5) Weskids, L.P. is presently the beneficial owner and has sole voting and disposition power of 843,687 shares of common stock and 117,467 shares of Series B preferred stock immediately convertible into not less than 117,467 shares of the Company's common stock. The exact conversion ratio is determined by the terms of the merger. Weskids, Inc. is the general partner of Weskids, L.P. and effectively controls Weskids, L.P. The officers and directors of Weskids, Inc. are as follows: J. Peter Simon, director; William Edward Simon, Jr., director; Michael B. Lenard, President; Mark J. Butler, Vice President/Treasurer; and Christine W. Jenkins, Secretary. (6) Series B preferred stock is convertible into common stock at a variable ratio of not less than one-to-one. III-9 70 (b) Security Ownership of Management The following table sets forth the shares of the Company's common stock beneficially owned by each director and executive officer and all directors and executive officers as a group, all as of February 28, 1998:
CONV. PREFERRED NAME AND ADDRESS OF AMOUNT AND NATURE OF PERCENT OF & OPTIONS STOCK BENEFICIAL OWNER BENEFICIAL OWNERSHIP(6) CLASS --------- ----- ---------------- -------------------- ------ 152,000 24,711 John J. Bassett 176,711 2.0% 4326 Noble Oak Trail Houston, TX 77059 94,500 25,796 Frank C. Turner, II 120,296 1.4% 1406 Tallow Court Seabrook, TX 77586 114,500 6,996 Robert W. Hammons 121,496 1.4% 915 Kentbury Court Katy, TX 77450 8,000 5,000 Lynn M. Davis 13,000 0.1% 121 Donna Circle Daphne, AL 36526 34,734 376,241 Edward P. Turner, Jr.(1) 410,975 4.7% 100 Central Avenue Chatom AL 36518 15,000 1,182,556 C. J. Lett, III(2) 1,197,556 13.8% 9320 East Central Wichita, KS 67206 34,734 -- Frank E. Bolling, Jr. 34,734 0.4% 3830 Kendale Drive Gautier, MS 39553 -- 12,000 Gary R Christopher(3) 12,000 0.1% 6733 South Yale Tulsa, OK 74136 117,466 661,222 Alvin V. Shoemaker(4) 778,688 8.9% 8800 First Avenue Stone Harbor, NJ 08247
III-10 71 15,867 109,816 Stephen W. Herod(5) 125,683 1.4% 1110 Briar Ridge Drive Houston, TX 77057 All executive officers and directors as a group (10 persons) 2,991,139 34.3%
(1) Includes 362,803 shares owned by Bay City Energy Group, Inc. in which Mr. Turner has indirect voting control but not a direct beneficial interest, and 13,438 shares over which Mr. Turner has sole voting and dispositive power. (2) Mr. Lett was named Executive Vice President of the Company on February 28, 1997 in connection with the Bison Merger (see "Business Development"). Mr. Lett's voting rights are restricted until February 28, 1998 (see Item 11(a) above). (3) Mr. Christopher is an officer of Kaiser-Francis Oil Company which is the beneficial owner of 3,33,334 of the Company's common shares. (4) Consists of 117,466 shares of Series B preferred stock convertible into 117,466 common shares of the Company. Mr. Shoemaker's voting rights are restricted until June 30, 1998 (see Item 11(a) above). (5) Consists of 15,867 shares of Series B preferred stock convertible into 15,867 common shares of the Company. Mr. Herod's voting rights are restricted in the same manner as Weskids, L.P. and Mr. Shoemaker. (6) The nature of beneficial ownership for all shares is sole voting and investment power. (c) Changes in Control There are no arrangements known to management which may result in a change in control of the Company. ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Edward P. Turner, Jr., a director of the Company, is managing partner of the law firm of Turner, Onderdonk, Kimbrough & Howell, P.A., the Company's general counsel for certain corporate and oil and gas matters. For the years ended December 31, 1995 through 1997, the Company paid legal fees to Mr. Turner's firm of $787, $1,560 and $2,874, respectively, for legal services. Mr. Turner's firm charges the Company for its services on the same basis as it charges other business clients for similar services rendered. The Company intends to continue to use Mr. Turner's firm as its primary local counsel in Alabama and will pay reasonable fees for such future services. III-11 72 Bay City Energy Group, Inc., is presently indebted to the Company in the amount of $166,165 ($139,005 of principal and $27,160 of accrued interest). The note payable was renegotiated on December 31, 1995 and is due in full on January 1, 2001, plus interest at an annual fixed rate of 5%. The note payable is secured by 75,000 shares of Company common stock. Edward P. Turner, Jr., a director of the Company, has indirect voting control but not a beneficial interest in Bay City Energy Group, Inc. On December 31, 1996, NPC Energy Corp., then a company indirectly controlled by C. J. Lett, III through Bison Energy Corporation ("Bison"), merged with the Company in exchange for 562,000 shares of common stock of the Company and $1,226,400 cash. Subsequently, in February, 1997, the Company acquired Bison as a wholly-owned subsidiary pursuant to an Agreement and Plan of Merger whereby Mr. Lett received net cash consideration of $5.9 million plus 1,167,556 shares of the Company's common stock, and the 562,000 shares held by Bison (as a result of the NPC Merger) were canceled (see "Business Development"). Gary R. Christopher, a director of the Company, is employed by Kaiser-Francis Oil Company which directly owns 3,333,334 common shares or 42.57% of the Company. [The remainder of this page has been intentionally left blank.] III-12 73 PART IV ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits
Sequential Exhibit No. Description of Exhibit Page No. ----------- ---------------------- ---------- 2.1 Agreement and Plan of Merger dated February 10, 1997 among the Company, Bison Energy Corporation, and C.J. Lett(6) N/A 2.2 Agreement and Plan of Merger dated February 10, 1997 among the Company, Shore Oil Company, and its shareholders(5) N/A 3.1 Articles of Incorporation(1) N/A 3.2 Articles of Amendment to Articles of Incorporation reflecting reverse split(2) N/A 3.3 Articles of Amendment to Articles of Incorporation designating preferences and rights of Series A Preferred Stock(5) N/A 3.4 Articles of Amendment to Articles of Incorporation designating preferences and rights of Series B Preferred Stock(5) N/A 3.5 Bylaws(1) N/A 10.1 Executive Employment Agreement for John J. Bassett dated January 30, 1997.(7) N/A 10.2 Executive Employment Agreement for Robert W. Hammons dated January 30, 1997.(7) N/A 10.3 Executive Employment Agreement for Steve W. Herod dated July 1, 1997.(7) N/A 11.1 Statement of Computation of Per-Share Earnings(7) 21.1 Subsidiaries of the Company(7) N/A
IV-1 74 (b) Reports on Form 8-K None. (1) Incorporated by reference to Exhibits to Registration Statement on Form S-4 filed October 4, 1993. (2) Incorporated by reference to Exhibits to definitive Proxy Statement filed February 15, 1995. (3) Incorporated by reference to Exhibits to definitive Proxy Statement filed May 11, 1995. (4) Incorporated by reference to Exhibits to Form 8-K filed September 19, 1996. (5) Incorporated by reference to Exhibits to Form 8-K filed July 3, 1997. (6) Incorporated by reference to Exhibits to Form 8-K filed February 25, 1997. (7) Incorporated by reference to Exhibits to Form 10KSB/A filed May 15, 1998. IV-2 75 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed by the undersigned, thereunto duly authorized. MIDDLE BAY OIL COMPANY, INC. (Registrant) By: /s/ John J. Bassett --------------------------------------- John J. Bassett, President October 16, 1998 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated: October 16, 1998 /s/ John J. Bassett - ------------------------------------ ------------------------------------- Date John J. Bassett Director, President Chief Executive Operating Officer October 16, 1998 /s/ C. J. Lett, III - ------------------------------------ ------------------------------------- Date C. J. Lett, III Executive Vice President and Director October 16, 1998 /s/ Stephen W. Herod - ------------------------------------ ------------------------------------- Date Stephen W. Herod Vice President and Director October 16, 1998 /s/ Edward P. Turner, Jr. - ------------------------------------ ------------------------------------- Date Edward P. Turner, Jr. Director October 16, 1998 /s/ Frank E. Bolling, Jr. - ------------------------------------ ------------------------------------- Date Frank E. Bolling, Jr. Director October 16, 1998 /s/ Gary R. Christopher - ------------------------------------ ------------------------------------- Date Gary R. Christopher Director October 16, 1998 /s/ Alvin V. Shoemaker - ------------------------------------ ------------------------------------- Date Alvin V. Shoemaker Director
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