-----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, U3XME1iAUtfGx2kQkwbuyOu2C12+BwoB/Nq5Swii+2BkpcYfGlif1rP4SW8e5lZI 6hh0fSCVey0AeWZJ3skWzg== 0001047469-99-012749.txt : 19990402 0001047469-99-012749.hdr.sgml : 19990402 ACCESSION NUMBER: 0001047469-99-012749 CONFORMED SUBMISSION TYPE: 10KSB40 PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19981231 FILED AS OF DATE: 19990331 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 SEC ACT: SEC FILE NUMBER: 001-14745 FILM NUMBER: 99581027 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 1 10KSB40 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ------------------------ FORM 10-KSB ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998 COMMISSION FILE NUMBER 0-21702 ------------------------ MIDDLE BAY OIL COMPANY, INC. (Exact Name of Registrant as Specified in Its Charter) ALABAMA 63-1081013 (State or Other Jurisdiction of (I.R.S. Employer Identification Incorporation or Organization) No.) 1221 LAMAR STREET, SUITE 1020, 77010 HOUSTON, TEXAS (Zip Code) (Address of Principal Executive Offices) Registrant's telephone number, including area code: (713) 759-6808 Securities registered pursuant to Section 12(b) of the Act:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED - -------------------------------------------------------- -------------------------------------------------------- None N/A
Securities registered pursuant to Section 12(g) of the Act: Common Stock, $.02 Par Value Securities registered pursuant to Securities Act of 1933: Series C Convertible Redeemable Preferred Stock, $.02 Par Value ------------------------ Check whether the Registrant (1) filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes /X/ No / / Check if disclosure of delinquent filers in response to Item 405 of Regulation S-B is not contained in this form, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-KSB or any amendment to this Form 10-KSB. /X/ Revenues of Registrant for fiscal year ended December 31, 1998 are $17,702,578. The aggregate market value as of March 19, 1999 of voting stock held by nonaffiliates of the Registrant was $3,777,828. - -------------------------------------------------------------------------------- Indicate the number of shares outstanding of each of the Registrant's classes of common equity, as of the latest practicable date (applicable only to corporate Registrants). 8,530,589 Shares of Common Stock, $.02 Par Value, as of March 19, 1999 - -------------------------------------------------------------------------------- Item 13(a) includes the Index of Exhibits to be filed with the Securities and Exchange Commission relative to this Report. - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- GLOSSARY OF TERMS The following are definitions of certain technical terms used in this Form 10-KSB in connection with the oil and gas exploration and development business of the Company: "BBL"--One stock tank barrel or 42 U.S. Gallons liquid volume, usually used herein in reference to crude oil or other liquid hydrocarbons. "BCF"--One billion cubic feet; expressed, where gas sales contracts are in effect, in terms of contractual temperature and pressure basis and, where contracts are nonexistent, at 60 degrees Fahrenheit and 14.65 pounds per square inch absolute. "BOE"--Equivalent barrels of oil and, with reference to natural gas, natural gas equivalents are determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. "DEVELOPED ACREAGE"--The number of acres which are allocated or assignable to producing wells or wells capable of production. "DEVELOPMENT WELL"--A well drilled as an additional well to the same reservoir as other producing wells on a Lease, or drilled on an offset Lease not more than one location away from a well producing from the same reservoir. "EXPLORATORY WELL"--A well drilled in search of a new undiscovered pool of oil or gas, or to extend the known limits of a field under development. "GROSS ACRES OR WELLS"--The total acres or wells, as the case may be, in which an entity has an interest, either directly or through an affiliate. "LEASE"--Full or partial interests in an oil and gas lease, oil and gas mineral rights, fee rights or other rights, authorizing the owner thereof to drill for, reduce to possession and produce oil and gas upon payment of rentals, bonuses and/or royalties. Oil and gas leases are generally acquired from private landowners and federal and state governments. "MCF"--One thousand cubic feet; expressed, where gas sales contracts are in effect, in terms of contractual temperature and pressure bases and, where contracts are nonexistent, at 60 degrees Fahrenheit and 14.65 pounds per square inch absolute. "MINERAL SERVITUDE"--A right that grants use of another's property for the purpose of extracting the minerals. "NET ACRES OR WELLS"--A party's interest in acres or wells calculated by multiplying the number of Gross Acres or Gross Wells in which such party has an interest by the fractional interest of such party in each such acre or well. "OPERATING COSTS"--The expenses of producing oil or gas from a formation, consisting of the costs incurred to operate and maintain wells and related equipment and facilities, including labor costs, repair and maintenance, supplies, insurance, production, severance and other production excise taxes. "PRODUCING PROPERTY"--A property (or interest therein) producing oil and gas in commercial quantities or that is shut-in but capable of producing oil and gas in commercial quantities, to which Producing Reserves have been assigned by an independent petroleum engineer. Interests in a property may include Working Interests, production payments, Royalty Interests and other non-Working Interests. "PROSPECT"--An area in which a party owns or intends to acquire one or more oil and gas interests which is geographically defined on the basis of geological data and which is reasonably anticipated to contain at least one reservoir of oil, gas or other hydrocarbons. "PROVED DEVELOPED RESERVES"--Proved Reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. i "PROVED RESERVES"--The estimated quantities of crude oil, natural gas and other hydrocarbons which, based upon geological and engineering data, are expected to be produced from known oil and gas reservoirs under existing economic and operating conditions, and the estimated present value thereof based upon the prices and costs on the date that the estimate is made and any price changes provided for by existing conditions. "PROVED UNDEVELOPED RESERVES"--Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. "PV 10%"--The discounted future net cash flows for proved oil and gas reserves computed using prices and costs, at the dates indicated, before income taxes and a discount rate of 10%. "ROYALTY INTEREST"--An interest in an oil and gas property entitling the owner to a share of oil and gas production free of the costs of production. "UNDEVELOPED ACREAGE"--Oil and gas acreage (including, in applicable instances, rights in one or more horizons which may be penetrated by existing well bores, but which have not been tested) to which Proved Reserves have not been assigned by independent petroleum engineers. "WORKING INTEREST"--The operating interest under a Lease which gives the owner the right to drill, produce and conduct operating activities on the property and a share of production, subject to all Royalty Interests, and other burdens and to all costs of exploration, development and operations and all risks in connection therewith. ii PART I ITEM 1. DESCRIPTION OF BUSINESS (a) COMPANY OVERVIEW Middle Bay Oil Company, Inc. (the "Company" or "Middle Bay") is an independent oil and gas company engaged in the exploration, development and production of oil and gas in the contiguous United States. The Company's strategy focuses on increasing its reserves of crude oil and natural gas by the acquisition and development of proved oil and gas properties primarily in the Gulf Coast and Mid-Continent regions. Middle Bay believes the current period reflects historically low market prices for oil and natural gas and is focusing its efforts on increasing reserves and production so that it will be well positioned to benefit in the event of any future increases in demand for natural gas and oil. Consistent with these efforts, the Company is participating on a limited basis in exploration drilling in the Gulf Coast and Mid-Continent regions of the contiguous United States. In November 1997, Middle Bay relocated its principal executive offices from Mobile, Alabama to 1221 Lamar Street, Suite 1020, Houston, Texas 77010. The Company's mailing address is P.O. Box 53448, Houston, Texas 77052-3448. Its telephone number is (713) 759-6808. The Company was incorporated under the Alabama Business Corporation Code on November 30, 1992. Effective December 31, 1992, all of the assets and liabilities of Bay City Consolidated Partners, L.P., an Alabama limited partnership (the "Predecessor Partnership"), were transferred to the Company in exchange for common stock of Middle Bay. The Predecessor Partnership was then dissolved under the Alabama Uniform Limited Partnership Act. The shares of common stock of Middle Bay then owned by the limited partnership were distributed to the general partner and the limited partners prorata in accordance with their respective interests in the limited partnership. References to the Company include, as the context requires, the Predecessor Partnership. This document includes "forward-looking statements" within the meaning of various provisions of the Securities Act and Securities Exchange Act of 1934, as amended (the "Exchange Act"). The words "expect," "estimate," "anticipate," "predict," "believe," and similar expressions and variations thereof are intended to identify forward-looking statements. All statements, other than statements of historical facts, included in this document that address activities, events, or developments that the Company expects or anticipates will or may occur in the future, including such things as estimated future net revenues from oil and natural gas reserves and the present value thereof, future capital expenditures (including the amount and nature thereof), business strategy and measures to implement strategy, competitive strengths, goals, expansion, and growth of Middle Bay's business and operations, plans, references to future success, references to intentions as to future matters and other such matters are forward-looking statements and include statements regarding interest, belief or current expectations of the Company, its directors, or its officers regarding such matters. These statements are based on certain assumptions and analyses made by Middle Bay in light of its experience and its perception of historical trends, current conditions and expected future developments as well as other factors it believes are appropriate under the circumstances. However, whether actual results and developments will conform with the Company's expectations and predictions is subject to a number of risks and uncertainties, including the risk factors discussed in this document, general economic, market or business conditions, the opportunities (or lack thereof) that may be presented to and pursued by Middle Bay, competitive actions by other oil and gas companies, changes in laws or regulations, and other factors, many of which are beyond the control of the Company. Consequently, all of the forward-looking statements made in this document are qualified by these cautionary statements and there can be no assurance that the actual results or developments anticipated by Middle Bay will be realized or, even if substantially realized, that they will have the expected consequences to or effects on the Company or its business or operations. (b) BUSINESS OF THE COMPANY The Company's oil and gas reserves are principally in long-lived fields with well-established production histories. Middle Bay's net Proved Reserves, estimated as of December 31, 1998 by applying S.E.C I-1 assumptions, consisted of approximately 43,483 million cubic feet of gas and 3,342 thousand barrels of oil and natural gas liquids, with an aggregate present value before income taxes, at a 10% discount, of $38,894,000. Approximately 79% of the reserves are classified as proved developed producing, 8% are proved developed non-producing and 13% are proved undeveloped. On an equivalent barrel basis, the proved reserves are 68% gas. Recoverable volumes of gas increased 136% and recoverable volumes of oil increased 14% over 1997 volumes. The PV 10% of the oil and gas reserves increased 29% over the 1997 amount of $30,179,000. The reserves are located primarily in Alabama, Kansas, Louisiana, Oklahoma and Texas. A substantial portion of Middle Bay's natural gas production and Proved Reserves consist of high BTU gas which, because of its rich liquid content and its proximity to processing and transmission facilities, is generally sold at a premium to Gulf Coast and Mid-Continent spot market prices. Substantially all of the Company's oil production is sold at market responsive prices. All of Middle Bay's gas production, except for the gas sold in the Spivey Field, is sold at market responsive prices. BUSINESS STRATEGY. The Company's present business strategy is to concentrate on expanding its asset base and cash flow primarily through emphasis on the following activities: - Increasing production, cash flow and asset value by acquiring Producing Properties with stable production rates, long reserve lives and potential for exploitation and development; - Building on Middle Bay's existing base of operations by concentrating its development activities in its primary operating areas in the Gulf Coast and the Mid-Continent Regions; - Acquiring additional properties with potential for development drilling and to maintain an inventory of undeveloped Prospects to enhance the Company's foundation for future growth; - Serving as operator of its wells to ensure technical performance and reduce costs; - Expanding its relationships with major and large independent oil and gas companies to access their undeveloped properties, seismic data and financial resources; - Managing financial risk and mitigating technical risk by: - drilling in known productive trends with multi-horizon geologic potential; - diversifying investment over a large number of wells in the Company's primary operating areas; - developing properties that provide a balance between short and long reserve lives; and - keeping a balanced reserve profile between oil and gas; and - Maintaining low general and administrative expenses and increasing economies of scale to reduce per unit operating, administrative and reserve acquisition costs. ACQUISITION POLICY. Middle Bay continues to actively pursue a program of acquiring producing oil and gas properties in either asset purchase or corporate merger transactions, with the goal of increasing cash flow, reserves and value for the long-term benefit of its stockholders. The Company utilizes an acquisition screening approach with its experienced management and technical staff that reviews potential acquisition properties against multiple criteria, both quantitative and subjective. Middle Bay generally seeks Producing Properties with established production histories. The Company may operate the property acquired; however, Middle Bay also considers non-operated property acquisitions. In evaluating Producing Properties for potential acquisition, production history, reservoir characteristics and available geologic data and interpretations are analyzed to determine estimates of proved and other reserves and cash flows expected to be recovered. Also evaluated are specific risks and economic considerations associated with the property, including environmental liabilities, risks of curtailment, condition of equipment and potential for additional development opportunities. Sales contracts, operating agreements and other contractual commitments, including take-or-pay clauses, market-out clauses, gas I-2 balancing agreements, transportation agreements and reversionary interests that may affect the cash flows from the property are also reviewed. DRILLING ACTIVITIES. Middle Bay has participated in drilling operations primarily in Texas, Louisiana and Kansas. The Company's drilling activity increased significantly in 1996 when the Company entered into the Brigham Agreement, described below. Middle Bay's drilling is funded principally from cash flow and is highly dependent on the price of oil and gas. If the price of oil continues to remain at or near the December 1998 levels, the amount of funds available for drilling could be reduced. During the year ended December 31, 1998, Middle Bay drilled 23 gross wells; 14 Development Wells and 9 Exploratory Wells. Twelve of the Development Wells and one of the Exploratory Wells were successful. The Company's drilling was concentrated in Texas and Louisiana, where 13 and 5 wells were drilled, respectively. In Texas, Middle Bay's drilling was concentrated in the Lake Tramel West and Carthage fields. There were four wells drilled on the Company's South Louisiana mineral acreage, three were unsuccessful Exploratory Wells and one Development Well which was completed as a producer, the Shore Oil Company #1 in St. Mary Parish. One successful Exploratory Well was drilled on the Sherburne Prospect, Point Coupee Parish, Louisiana. After evaluation of additional seismic data, no further drilling is expected on the Sherburne Prospect. The Quarry #1, an Exploratory Well being drilled as of December 31, 1998, was plugged and abandoned in February 1999. This Exploratory Well was drilled on the Quarry Prospect, Lea County, New Mexico. Middle Bay had prepaid approximately $125,000 in drilling costs as of December 31, 1998 and expensed the costs in the fourth quarter when it was determined the well was unsuccessful. For the twelve months ended December 31, 1997, Middle Bay drilled 42 gross wells; 23 Development Wells and 19 Exploratory Wells. Seventeen of the Development Wells and 8 of the Exploratory Wells were successful. The Company's drilling was concentrated in Kansas, Louisiana and Texas, where 14, 12 and 7 wells were drilled, respectively. The majority of the Kansas wells were Development Wells drilled in the Spivey Field (the "Spivey Field"). Two unsuccessful Exploratory Wells were drilled in the Reflection Ridge Prospect in Stanton County, Kansas. No further exploration is anticipated on the Reflection Ridge Prospect. For the three months ended March 31, 1997, Middle Bay participated in the drilling of 12 Exploratory Wells through the Brigham Agreement. The Brigham Agreement ended March 31, 1997. The Shore Oil Company #1, an Exploratory Well being drilled as of December 31, 1997, was found to be unsuccessful in February, 1998. This Exploratory Well was drilled on the Raceland Prospect in Lafourche Parish, Louisiana which is located on the fee mineral acreage acquired in the Shore Merger. The Company had prepaid approximately $311,000 in drilling costs as of December 31, 1997 and expensed the costs in the fourth quarter when it was determined that the well was abandoned. Drilling activities during 1998 added 104 thousand barrels of oil and 290 million cubic feet of gas with estimated future net revenues, discounted at 10%, of $732,000. Drilling activities during 1997 added 22 thousand barrels of oil and 705 million cubic feet of gas with estimated future net revenues, discounted at 10%, of $851,000. For the years 1997 and 1998, oil and gas reserves discovered through current year drilling accounted for 3% and 2%, respectively, of the year-end reserve value. In July 1997, the Company executed an exploration agreement with Brigham Exploration Company ("Brigham") for a 3-D seismic exploration project on the Hawkins Ranch (the "Ranch") in Matagorda County, Texas. The Ranch was lease optioned for a 3-D seismic survey with Brigham serving as the operator. Middle Bay purchased a 25% working interest through the lease selection phase of the project for $225,000 and in July 1998 purchased an additional 2.5% carried working interest for $251,250. This project involves approximately 142 square miles of 3-D seismic data. A total of 94 square miles of new data was shot during 1998 and merged into 60 square miles of existing 3-D data acquired in early 1998 that covers acreage adjacent to the Ranch. Final processing of the data was completed in November 1998 and interpretation is ongoing. Nine prospects have been identified to date in the Miocene, Discorbis "B" and Tex Miss Frio formations at depths between 6,000' and 15,000'. A total of approximately 4,000 gross acres I-3 are currently under lease on and near the Ranch. At December 31, 1998, the Company had incurred approximately $1,316,000 on the Hawkins Ranch project for land, seismic and other costs. During December 1998, the Company and Brigham sold a portion of their interest in the Ranch project to Adams Resources Exploration Corporation for a total of $2,000,000. In January 1999, Middle Bay received $500,000 of the proceeds and currently owns a 20% working interest in the Ranch project. The first well on the Hawkins Ranch project, the Ling Prospect, is expected to spud in early March 1999. Two additional wells, on the Marlin and Amberjack prospects, are expected to be drilled in the second quarter of 1999. The proceeds from the sale of interest will fund the majority of Middle Bay's portion of the drilling costs on the first three wells. The Company purchased a 12.5% working interest in the Sherburne Prospect in Point Coupee Parish, Louisiana, in October 1997 (the "Sherburne Prospect"). The Sherburne Prospect consists of approximately 10,000 acres that are prospective in the Frio, Cockfield, Sparta and Wilcox formations. The acreage is located in Southwest Point Coupee Parish between Krotz Springs Field and the Fordoche Field. Production is at depths from 6,500' to 15,500'. Swift Energy Company has a 62.5% working interest and is the operator. A private company holds the remaining 25%. The first well, the PMMI #1, was drilled and successfully completed in the Sparta formation in June 1998. After evaluation of additional seismic data shot in the third quarter of 1998, no further drilling is expected on the Sherburne Prospect. On April 3, 1996, the Company entered into a Joint Expense and Participation Agreement (the "Brigham Agreement") with Brigham. The Brigham Agreement allowed Middle Bay to participate in all of the wells that Brigham drilled over the 12-month period beginning April 1, 1996. The Company advanced Brigham a total of $1,945,000 to drill 61 wells, of which 43 (70%) were successfully completed. In the foreseeable future, the Company's primary drilling focus will be its participation in the Ranch Prospect and the development of the Spivey Field. Middle Bay expects to drill several Development Wells in the Spivey Field in Kansas in 1999, depending on oil prices. The Company also expects several wells to be drilled on the Shore mineral acreage in South Louisiana in 1999. In addition, Middle Bay is continually evaluating Prospects originated by its staff, other independent geologists or other oil and gas companies. If review of a certain Prospect indicates that it may be geologically and economically attractive, then the Company will attempt to obtain a Lease on the applicable acreage or commit to a Working Interest in the drilling Prospect. When Middle Bay does participate in a Prospect, it will typically acquire a fractional Working Interest in the Prospect, which may range from small percentage interests in more expensive exploratory Prospects to a majority interest in a lower cost or development Prospect. The Company believes that such participation, which is common practice in the oil and gas industry, allows for further diversification and reduction of risk. ACQUISITIONS AND MERGERS. Since its formation, the Company has grown primarily through acquisitions of proved oil and gas reserves. For the years 1996 through 1998, acquisitions of reserves accounted for 27%, 67% and 59% of the year-end before tax discounted reserve value, respectively. The Company has financed its acquisitions primarily by utilizing its credit facility with the Bank and issuing common and preferred stock. (See "Company Financing," below.) On December 17, 1996, Middle Bay entered into an Agreement and Plan of Merger (the "NPC Merger") with NPC Energy Corporation ("NPC"), whereby NPC would be merged into the Company in exchange for Middle Bay common stock and cash. The NPC Merger was approved by NPC's shareholders and closed on December 31, 1996. NPC was a privately owned domestic exploration and production company with assets located in Kansas, Michigan, Oklahoma, Texas and Wyoming. Pursuant to the NPC Merger, Middle Bay issued 562,000 shares of its common stock and paid $1,226,400 to NPC in exchange for all of the stock of NPC. The cash funding for the NPC Merger was financed through the issuance of 166,667 shares of Series A for $1.0 million. The NPC Merger added approximately 503 thousand barrels of oil and 3,139 million cubic feet of gas, for a total proved reserve value of $6.0 million (PV 10%) as of December 31, 1996, using December 31, 1996 prices. In addition, NPC had approximately $.8 million in working capital and $.4 million in bank debt. I-4 On February 10, 1997, the Company entered into an Agreement and Plan of Merger (the "Bison Merger") with Bison Energy Corporation ("Bison"), whereby Bison was merged with a wholly-owned subsidiary of Middle Bay in exchange for Company common stock and cash. The Bison Merger was approved by Bison's sole shareholder and closed on February 28, 1997. Bison was a privately held, domestic exploration and production company with assets located in Kansas and Oklahoma. Pursuant to the Bison Merger, the Company issued 1,167,556 shares of its common stock and paid cash consideration of $6,654,000 to Bison in exchange for all of the stock of Bison. 562,000 shares of Middle Bay common stock owned by Bison (as a result of the NPC Merger) were canceled at closing. The cash portion of the Bison Merger was financed through the issuance of 1,000,000 shares of Series A for $6.0 million. The Bison Merger added approximately 951 thousand barrels of oil and 7,791 million cubic feet of gas, for a total proved reserve value of $8.94 million (PV 10%) as of February 28, 1997, using December 31, 1997 prices. In addition, Bison had approximately $.7 million in working capital. On June 20, 1997, Middle Bay entered into an Agreement and Plan of Merger (the "Shore Merger") with Shore Oil Company ("Shore"), whereby Shore was merged with a wholly-owned subsidiary of the Company in exchange for Middle Bay common stock, Series B preferred stock (the "Series B"), cash and the assumption of Shore debt. The Shore Merger was approved by Shore's shareholders and closed on June 30, 1997. Shore was a privately held, domestic exploration and production company with oil and gas properties located primarily in Alabama, Louisiana, Mississippi and Texas, as well as approximately 40,000 net mineral acres in Lafourche, Terrebonne and St. Mary Parishes, Louisiana. Pursuant to the Shore Merger, the Company issued 1,883,333 shares of its common stock, paid Shore's indebtedness to its shareholders of $2,333,303 and assumed bank debt of $2,105,000. In addition, Middle Bay paid $200,000 in cash and issued 266,667 shares of Series B which are convertible into as many as 1,333,333 shares of common stock over the next five years, contingent upon the results of drilling and leasing activity on Shore's South Louisiana mineral acreage. The cash funding for the Shore Merger was financed through the issuance of 500,000 shares of Series A for $3.0 million. The Shore Merger added approximately 965 thousand barrels of oil and 1,364 million cubic feet of gas, for a total proved reserve value of $6.0 million (PV 10%) as of July 1, 1997, using December 31, 1997 prices. In addition, Shore had approximately $2.3 million in working capital. The Shore Merger also added approximately 40,000 net acres of fee minerals situated in Lafourche, Terrebonne and St. Mary Parishes in Louisiana that were valued by an independent oil and gas engineering firm at approximately $3.6 million at June 30, 1997. In August 1997, the Company acquired a 5.74% working interest in proved reserves with a January 1, 1997 effective date in the Riceville Field in Vermilion Parish, Louisiana for approximately $3.5 million (the "Riceville Acquisition"). The acquisition was financed with $3 million in loan proceeds and the remainder from cash on hand. The Riceville Acquisition added approximately 63 thousand barrels of oil and 2,955 million cubic feet of gas to the Company's proved reserves. Using December 31, 1997 prices, the Riceville Acquisition had a PV 10% of approximately $5.3 million. On March 27, 1998, pursuant to a cash tender offer that commenced February 19, 1998, the Company acquired 1,064,432 common shares (79.2%) of Enex Resources Corporation ("Enex") at $15.00 per share for $15,966,480 (the "Enex Acquisition"). Middle Bay later acquired 9,747 additional shares of Enex in open market transactions for $68,194 that increased its ownership in Enex to 80.0% at December 31, 1998. Enex is a publicly traded (OTC Bulletin Board symbol: ENEX), independent oil and gas development and production company with properties located primarily in Texas. In addition, Enex is the general partner of Enex Consolidated Partners, L. P., (the "Enex Partnership), a publicly held New Jersey limited partnership whose primary business is oil and gas development and production. Enex owns a 4.1% general partner interest and a 56.24% limited partner interest in the Enex Partnership. The Enex Acquisition added approximately 955 thousand barrels of oil and 18,950 million cubic feet of gas, for a total proved reserve value of $15.9 million (PV 10%) as of March 31, 1998, using December 31, 1998 prices. The proved reserve information related to the Enex Acquisition is on a consolidated basis and includes 100% of the proved reserves of Enex and the Enex Partnership. In addition, Enex had approximately $5.6 million in working capital and no long-term debt. I-5 As part of the Enex Acquisition, the Company entered into a consulting agreement, effective April 15, 1998, with the former President of Enex that provides for monthly payments of $20,000 until the agreement expires on May 18, 2002. The monthly payments serve as consideration for consulting services, a covenant not to compete and a preferential right to purchase certain oil and gas acquisitions which the former president controls or proposes to acquire during the term of the agreement. Middle Bay's total obligation under the consulting agreement is $960,000. On April 16, 1998, Middle Bay acquired substantially all of the oil and gas assets of Service Drilling Co., LLC and certain affiliates ("Service Drilling") in exchange for 666,000 shares of Company common stock and $6,500,000 cash for a total acquisition cost of $10,054,775. Service Drilling is a privately held, domestic exploration and production company with oil and gas properties located primarily in Oklahoma and the Texas Panhandle. The Service Drilling acquisition added approximately 299 thousand barrels of oil and 12,047 million cubic feet of gas, for a total reserve value of $7.2 million (PV 10%) as of the effective date of March 1, 1998, using December 31, 1998 prices. On December 30, 1998, the Company closed on an exchange offer (the "Exchange Offer") that began November 27, 1998 for limited partnership units of the Enex Partnership. The $11.9 million transaction involved the issuance of 2,177,481 shares of Middle Bay's Series C preferred stock (the "Series C") and payment of approximately $539,000 cash in exchange for the outstanding limited partnership interests of the Enex Partnership, the transfer of the Enex Partnership's assets and liabilities to Middle Bay, and the dissolution of the Enex Partnership. Pursuant to the Exchange Offer, each partnership unit was valued at $10.43 and the unitholders had the option of exchanging their units for the Series C (at a conversion ratio of 2.086 Series C shares for each of the total 1,102,631 partnership units) or exercising dissenters' rights and receiving a cash payment for their interests. The Company paid approximately $516,000 to unitholders who exercised dissenters' rights, which was financed with bank debt, and approximately $23,000 to unitholders in lieu of issuing fractional shares. In addition, Middle Bay incurred approximately $431,000 in transaction costs related to the Exchange Offer. Enex was general partner of the Enex Partnership and owned 56.24% of the total outstanding limited partnership units. The intent of the Exchange Offer was to acquire the 43.76% limited partnership units of the Enex Partnership that the Company (through Enex) did not currently own. Subsequent to the Exchange Offer, Enex owns 1,293,522 Series C shares, equal to 59.4% of the total outstanding Series C preferred stock. The total number of Series C shares not held by the Company is 1,142,663, consisting of the 883,959 shares issued to holders of the 43.76% of limited partnership units not held by Enex and 258,704 shares attributable to the 20% minority interest shareholders of Enex. The Series C pays cumulative cash dividends at the rate of 10% per year (payable semi-annually on March 31 and September 30), has a $5.00 per share liquidation preference and each Series C share is convertible at any time into one share of Middle Bay common stock. After January 1, 2000, the Company may, at its option, redeem the Series C for the liquidation value plus accrued dividends. Middle Bay has applied to list the Series C on the NASDAQ Small Cap Market. The Enex Partnership acquisition added approximately 628 thousand barrels of oil and 8,638 million cubic feet of gas, for a total proved reserve value of $9.7 million (PV 10%) as of the effective date of October 1, 1998, using December 31, 1998 prices. The proved reserve information related to the Enex Partnership acquisition is on a consolidated basis and includes 100% of the proved reserves of the Enex Partnership. In addition, the Enex Partnership had approximately $1.0 million in working capital and no long-term debt. The Enex Partnership properties are located primarily in Texas. Middle Bay is currently in the process of evaluating various corporate acquisitions and potential mergers in exchange for common and/or preferred stock in the Company. Management believes that corporate acquisitions and mergers are the fastest way to achieve Middle Bay's growth goals. In addition to achieving what management perceives to be a proper critical mass, potential corporate acquisitions or mergers are also considered as opportunities to build a more diverse oil and gas property base for further development and exploration. I-6 The price of oil has declined significantly since December 31, 1997 and, in December 1998, reached the lowest level in over ten years. The posted price of WTI crude declined from approximately $15.00 per barrel on December 31, 1997 to approximately $9.50 per barrel on December 31, 1998. If oil prices remain at or near these levels, the funds available for acquisitions could be reduced. COMPANY FINANCING. The Company has financed its acquisitions with debt proceeds from the Banks, issuance of convertible preferred stock and issuance of common stock. Middle Bay's drilling activities have been financed primarily through the Company's cash flow. On September 4, 1996, Middle Bay entered into a stock purchase agreement (the "Preferred Stock Agreement") with Kaiser-Francis Oil Company ("Kaiser-Francis") whereby Kaiser-Francis agreed to purchase 1,666,667 shares of Series A Preferred Stock (the "Series A") at $6.00 per share, for a total investment of $10,000,000. On January 31, 1998, Kaiser-Francis converted 100% of the Series A shares into 3,333,334 common shares of Middle Bay. At December 31, 1998, Kaiser-Francis owned 39.1% of the Company's outstanding common stock. Prior to their conversion to common stock, the Series A shares were nonvoting and accrued dividends at 8% per annum, payable quarterly in cash, and were convertible at any time into two shares of common stock for each Series A share held prior to January 1, 1998. The conversion rate decreased thereafter at 8% per annum. Kaiser-Francis is a privately held company based in Tulsa, Oklahoma whose majority shareholder is George B. Kaiser. During 1997, the Company issued $9.0 million in Series A Preferred Stock through its $10.0 million Preferred Stock Agreement to finance portions of the Bison and Shore mergers. In 1997, Middle Bay issued $3.627 million of Series B Preferred Stock to finance a portion of the Shore Merger. In 1998, the Company issued 2,177,481 shares of Series C preferred stock with a liquidation value of approximately $10.9 million in connection with the Enex Partnership acquisition. Middle Bay also issued its common stock in connection with the NPC, Bison and Shore mergers as well as the Service Drilling acquisition. In connection with the Enex Acquisition, effective March 27, 1998, the Company entered into a new reducing revolving credit facility (the "$100 million Revolver") with Compass Bank, N.A., as agent and lender, and Bank of Oklahoma, N. A., as a participant lender, (collectively, the "Banks"). The $100 million Revolver provided for an initial borrowing base of $29.0 million. The initial borrowing base was reduced to $27.5 million ten days after the effective date and further reduced by $275,000 per month, beginning May 1, 1998 and ending October 1, 1998. In conjunction with the closing of the Service Drilling acquisition on April 16, 1998, the borrowing base was increased to $32.6 million and the monthly borrowing base reduction was increased to $330,000. Effective October 1, 1998, the semi-annual borrowing base redetermination date, the borrowing base was calculated to be $28.9 million with monthly borrowing base reductions of $250,000 beginning November 1, 1998. Effective January 1, 1999, upon the closing of the Enex Partnership acquisition, the borrowing base determined at October 1, 1998 was adjusted to $33.1 million and the monthly borrowing base reduction was increased to $290,000. The borrowing base at December 31, 1998 was $32.5 million and the next semi-annual borrowing base redetermination date is April 1, 1999. The principal is due at maturity, April 1, 2001. Monthly principal payments are made as required in order that the outstanding principal balance does not exceed the borrowing base. Interest is payable monthly and is calculated at the prime rate. The Company may also elect to calculate interest under the LIBOR rate option, as defined in the agreement. Under the LIBOR rate option, interest is calculated at the LIBOR rate plus (a) 2.00% if the outstanding loan balance and letters of credit are equal to or greater than 75% of the borrowing base, (b) 1.75% if the outstanding loan balance and letters of credit are equal to or less than 75% or greater than 50% of the borrowing base, (c) 1.50% if the outstanding loan balance and letters of credit are equal to or less than 50% of the borrowing base. LIBOR interest is payable at maturity of the LIBOR loan which cannot be less than thirty days. At December 31, 1998, the loan balance was $27,454,567 and there was approximately $1,163,647 of outstanding letters of credit. As of December 31, 1998, the Company was paying LIBOR plus 2.00% on a sixty day LIBOR loan for $25,469,605 and prime on $1,984,962. The amount available under the borrowing base on the $100 million Revolver was $3.9 million at December 31, 1998. I-7 As of December 31, 1998, the amount available under the borrowing base on the $100 million Revolver was approximately $3.9 million. Assuming no other changes, the amount available to be borrowed under the borrowing base at April 1, 1999 will be approximately $3.0 million. Middle Bay expects that the Banks will complete the April 1, 1999 borrowing base redetermination by May 1, 1999. The Company also expects that the borrowing base will be less than the amount determined at the October 1, 1998 redetermination, adjusted for the monthly borrowing base reductions. The decrease is expected to be caused primarily by normal production declines and lower oil and gas pricing scenarios used by the Banks to value oil and gas reserves for loan purposes. Pursuant to the terms of the $100 million Revolver, if the borrowing base is less than the outstanding principal balance plus outstanding letters of credit, Middle Bay has sixty days, after receipt of written notice from the Banks, to cure the excess by prepayment, providing additional collateral or a combination of both. The Company is unable to predict the April 1, 1999 borrowing base. At the completion of the April 1, 1999 redetermination, Middle Bay does not expect to be required to make any prepayments or provide any additional collateral that would be material to the financial condition of the Company. The Company paid a facility fee equal to 3/8% of the initial borrowing base and is required to pay 3/8% on any future increase in the borrowing base within five days of written notice. Middle Bay is required to pay a quarterly commitment fee on the unused portion of the borrowing base of 1/2% if the outstanding loan balance plus letters of credit are greater than 50% of the borrowing base or 3/8% if the outstanding loan balance plus letters of credit are less than or equal to 50% of the borrowing base. The Company is required to pay a letter of credit fee on the date of issuance or renewal of each letter of credit equal to the greater of $500 or 1 1/2% of the face amount of the letter of credit. Middle Bay has granted to the Banks liens on substantially all of the Company's oil and gas properties, whether currently owned or hereafter acquired, and a negative pledge on all other oil and gas properties. The $100 million Revolver requires, among other things, a cash flow coverage ratio of 1.25 to 1.00 and a current ratio, excluding current maturities under the $100 million Revolver, of 0.9 to 1.00, determined on a quarterly basis. Under the terms of the $100 million Revolver, when mortgaged properties are sold the borrowing base shall be reduced, and if necessary, proceeds from the sales of properties shall be applied to the debt outstanding in an amount equal to the loan value attributable to such properties sold. Of the total net proceeds received from oil and gas property sales in 1998 of approximately $4,784,000, $2,145,000 was used to repay principal on the $100 million Revolver. In connection with the Shore Merger, effective August 25, 1997, the Bank of Oklahoma, National Association converted the Company's then $15 million convertible credit facility into a $50 million convertible credit facility. As of December 31, 1997, the principal balance of the loan was $10,956,298. Concurrent with the closing of the Enex Acquisition on March 27, 1998, the loan balance was paid in full and refinanced as part of the $100 million Revolver. Subject to availability of bank financing, Middle Bay will continue to consider asset purchase transactions that meet the Company's acquisition criteria. The Company currently has approximately $28.0 million borrowed on the $100 million Revolver. Middle Bay intends to finance corporate mergers and acquisitions by issuing common stock and/or preferred stock when possible. COMPETITION, MARKETS AND REGULATION. Competition in the exploration and property acquisition markets is intense. In seeking to obtain desirable Leases and exploration Prospects, the Company faces competition from both major and independent oil and gas companies, as well as from numerous individuals. Many of these competitors have substantial financial resources available to them, which makes for increased competition. The ability of Middle Bay to market oil and gas from its wells will depend upon numerous factors beyond its control, including, but not limited to, the extent of domestic production and imports of oil and gas, the proximity of the Company's production to existing pipelines, the availability of capacity in such pipelines and state and federal regulation of oil and gas production. There is no assurance that Middle Bay I-8 will be able to market all of the oil or gas produced by it or that favorable prices can be obtained for the oil and gas it produces. In view of the uncertainties affecting the supply and demand of oil and gas, the Company is unable to accurately predict future oil and gas prices and demand, or the overall effect they will have on Middle Bay. Numerous federal and state laws and regulations affect the Company's operations. In particular, oil and gas production operations are affected by tax and other laws relating to the petroleum industry and any changes in such laws and regulations. Some of the rules and regulations carry substantial penalties for failing to comply. The regulatory burden on the oil and gas industry increases Middle Bay's cost of doing business. The Company's activities are also subject to numerous federal, state and local environmental laws and regulations governing the discharge of materials. In most cases, the applicable regulatory requirements relate to water and air pollution control or solid waste management measures. Middle Bay believes the recent trend toward stricter standards in environmental legislation, regulation and enforcement will continue. To date, these laws have not had a significant impact on the Company but no assurance can be given as to the effect of these laws on Middle Bay in the future. EMPLOYEES. As of December 31, 1998, the Company employed 27 full-time persons. Middle Bay employs 16 full-time persons in its Houston, Texas office, including four executive officers, whose functions are associated with management, engineering, geology, land and legal, accounting, financial planning and administration. The Company employs five full-time persons in its Wichita, Kansas office, including one executive officer, a geologist, an engineer and two administrative assistants. Middle Bay also employs one full-time supervisor for well operations in Oklahoma and one full-time accountant in Mobile, Alabama. ITEM 2. DESCRIPTION OF PROPERTY (a) REAL ESTATE PROPERTIES Middle Bay owned a historic home in Mobile, Alabama, which previously served as its corporate office before the Company's relocation to Houston, Texas in November 1997. Middle Bay sold the property in December 1998 for $190,500. The Company retired a $127,809 mortgage on the property, paid $11,241 in closing costs and added the remaining proceeds of $51,450 to working capital. (b) OIL AND GAS PROPERTIES More than 95% of the Company's oil and gas properties, reserves and activities are located onshore in the continental United States, primarily in Alabama, Kansas, Louisiana, Oklahoma and Texas. Estimates of total proved net oil or gas reserves have not been filed with or included in reports to any federal authority or agency. There are no quantities of oil or gas subject to long-term supply or similar agreements with foreign governmental authorities. The Company's largest oil and gas property, in terms of reserve volumes and dollar value, is the Spivey Field acquired in the Bison Merger. The Spivey Field, located in Kingman and Harper Counties, South Central Kansas, was discovered in 1949. Development of oil and gas reserves from the Mississippian Chert Formation, at an average drilling depth of 4,250 feet, has been continual since discovery. Currently, approximately 585 active wells produce in the field. Great lateral extent, thick pay sections, and long-lived production characterize the reservoir. The Spivey Field has cumulative gas production of over 75,000 million cubic feet. Gas is marketed to the spot markets and to the Spivey Gas Plant (the "Plant"). Over 95% of Company gas is sold to the Plant under a life of the lease casinghead tailgate gas contract. Middle Bay owns approximately 11.5% ownership in the Plant and related gathering system. Warren Petroleum Company, L.P., and Dynegy, Inc. (formerly NGC Corporation) jointly operate the Plant. Ownership in the Plant is redetermined annually, based on each owner's throughput relative to total throughput. Plant liquids (propane, butane and natural gasoline) are marketed from the Plant to Murphy Energy. Residue gas is sold to KGE (f/k/a Kansas Power and Light) for a tailgate price of $2.91 per Mcf. The tailgate contract calls for an annual escalation of $0.02 per Mcf. The Btu factor for the residue gas is 1.042. Plant owners also receive the benefit of buying, stripping and reselling "non-owner" field gas. I-9 The Spivey Field has cumulative oil production of over 66.6 million barrels of oil. Lease oil is marketed to Koch Oil Company, via truck, and a bonus above posted prices is received. Middle Bay operates 74 wells in the Spivey Field from a field office in Attica, Kansas, staffed by one foreman and two Company pumpers. All oilfield services are present in the field. Exploration, engineering and land functions are directed from the division office located in Wichita, Kansas. The Company is continually evaluating and developing its acreage position of approximately 8,800 gross acres. As of December 31, 1998, Middle Bay has identified and independent engineers have evaluated 12 proved undeveloped locations in the Spivey Field with a PV 10% value of approximately $.9 million. At December 31, 1998, the Plant was valued by independent engineers at a $3.0 million PV 10%. The following table shows proved oil and gas reserves by major field for the Company's largest producing fields at December 31, 1998. The values represent the present value of estimated future net cash flows before income taxes, discounted at 10%, assuming unescalated expenses and prices of $9.50/Bbl and $2.10/Mcf attributable to proved reserves at December 31, 1998, as determined by Lee Keeling & Associates, Inc. and H. J. Gruy and Associates, Inc., independent reserve engineers.
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 $ 7,459 19.2% 1,117 7,172 Harper/Kingman, KS Riceville ..................................... Murphy 4,626 11.9% 57 2,555 Vermillion, LA Segundo ....................................... Company 2,781 7.2% 0 8,133 Webb, TX West Stigler .................................. Company 2,472 6.4% 0 5,282 Haskell, OK East Seven Sisters ............................ Vastar 1,804 4.6% 0 2,108 Duval, TX Stratton ...................................... Union Pacific 1,543 4.0% 81 1,494 Nueces/Kleberg, TX Sawyer ........................................ Louis Dreyfus 1,383 3.4% 4 1,148 Sutton, TX Hatter's Pond ................................. Texaco 787 2.0% 64 575 Mobile, AL Lockhart Crossing ............................. Amoco 770 2.0% 17 747 Livingston, LA Brooken ....................................... Company 704 1.8% 0 1,659 Haskell, OK Others ........................................ Various 14,565 37.5% 2,002 12,610 ----------- ----- ----- ----------- Total.......................................... $ 38,894 100.0% 3,342 43,483 ----------- ----- ----- ----------- ----------- ----- ----- -----------
As of December 31, 1998, the Banks have a first mortgage on all of the fields listed in the above table. The Banks also have a first mortgage on numerous additional fields not individually listed above. Middle Bay is obligated, within five days of request by the Banks, to grant the Banks a first and prior mortgage on any oil and gas properties owned or acquired by the Company. I-10 (c) LOUISIANA FEE MINERAL ACREAGE In the Shore Merger, Middle Bay acquired approximately 40,342 net mineral acres, situated in Terrebonne, Lafourche and St. Mary Parishes in South Louisiana. Of the total acreage, 37,194 acres are non-producing, 2,528 acres are held by production under existing leases and 620 acres prescribed in October 1997. The non-producing acreage is located in the following parishes: 18,704 in Terrebonne (Montegut and Houma areas), 12,630 acres in Lafourche (Raceland and Valentine areas) and 8,388 acres in St. Mary Parish (Charenton area). A total of 8,973 acres of the non-producing acreage are currently under lease and/or option agreements with expiration dates as follows: 4,267 acres in 1999, 4,570 acres in 2000 and 136 acres in 2001. As of December 31, 1998, 28,221 acres were not under lease. Royalty interest in the leases covering the non-producing minerals ranges from 20% to 25%. The mineral servitude prescription dates are estimated by the Company to be as follows: 6,226 acres in 1999, 5,286 acres in 2002, 4,145 acres in 2004, 1,189 acres in 2005, 1,145 acres held in perpetuity and the remaining 21,730 acres has prescription interrupted by production. Effective April 1, 1992 Shore Oil Company sold the production rights under tracts producing at that time and does not receive royalty income from the sale of oil or gas on those tracts. Over 85% of the non-producing minerals have been covered by 3-D seismic shot by third parties and provided to the Company at no cost. For the period July 1, 1997 through December 31, 1997 and during 1998, the Company received approximately $975,000 and $217,000, respectively, in lease bonus, delay rental and seismic option income on the acreage. An independent oil and gas engineering firm valued the acreage as of June 30, 1997 at $3,627,000. One unsuccessful Exploratory Well in Lafourche Parish, the Shore Oil Company #1, was drilled on the fee mineral acreage in 1997 and abandoned in February 1998. In Terrebonne Parish, two Exploratory Wells, the Middle Bay Oil Co. #1 and the Shore Oil Co. #1, were drilled and abandoned in March and May 1998, respectively. A successful Development Well in St. Mary Parish, the Shore Oil Company #1, was completed and began production during November 1998. One unsuccessful Exploratory Well in St. Mary Parish, the Middle Bay Oil Company #1, was drilled and abandoned in December 1998. (d) PRODUCTIVE WELLS AND ACREAGE The following table depicts the number of gross and net producing wells and related Developed and Undeveloped Acreage in which Middle Bay owned an interest for the period ended December 31, 1998. The Company operated approximately 275 wells at December 31, 1998. Undeveloped Acreage is oil and gas acreage (including, in certain instances, rights in one or more horizons which may be penetrated by existing well bores, but which have not been tested) to which Proved Reserves have not been assigned by independent petroleum engineers. Middle Bay's net Developed Acreage is located primarily in Oklahoma, Texas, Alabama, Louisiana, and Kansas. The Company's net Undeveloped Acreage is located primarily in Kansas.
ACREAGE ------------------------- DEVELOPED UNDEVELOPED ----------- ------------ Gross Acres......................................................... 248,670 11,282 Net Acres........................................................... 40,548 8,454 PRODUCTIVE WELLS ------------------------- OIL GAS ----------- ------------ Gross Wells......................................................... 276.00 212.00 Net Wells........................................................... 78.78 49.93
Excluded from the acreage data are approximately 41,441 net mineral acres owned by the Company, all of which are considered to have potential for oil and gas exploration. I-11 (e) PRODUCTION, PRICES AND COSTS Below is a summary of the net production of oil and gas, average sales prices and average production costs during each of the last three fiscal years. Middle Bay is not obligated to provide a fixed and determined quantity of oil and gas in the future under existing contracts or agreements. During the last three fiscal years, the Company has not had, nor does it now have, any long-term supply or similar agreements with governments or authorities.
FISCAL YEARS ENDED DECEMBER 31, -------------------------------------- 1996 1997 1998 ---------- ------------ ------------ Crude Oil and Natural Gas Production: Oil (Bbls).................................................... 108,626 283,849 581,457 Gas (Mcf)..................................................... 982,709 1,929,298 3,846,679 Average Sales Prices: Oil (per Bbl)................................................. $ 20.26 $ 18.06 $ 11.52 Gas (per Mcf)................................................. $ 2.28 $ 2.39 $ 2.00 Average Production Costs Per BOE(1)............................. $ 5.36 $ 6.71 $ 6.38
- ------------------------ (1) The components of production costs may vary substantially among wells, depending on the methods of recovery employed and other factors, but generally include severance taxes, administrative overhead, maintenance and repair, labor and utilities. (f) DRILLING ACTIVITIES During the periods indicated, Middle Bay drilled or participated in the drilling of the following productive and nonproductive Exploratory and Development Wells. All of the Company's drilling and production activities are conducted with independent contractors.
YEAR ENDED DECEMBER 31, ------------------------------- 1996 1997 1998 --------- --------- --------- Exploratory Wells: Productive Gross.............................................................. 31 8 1 Net................................................................ 0.987 0.452 0.125 Dry Gross.............................................................. 18 11 8 Net................................................................ 0.675 1.280 0.793 Development Wells: Productive Gross.............................................................. 4 17 12 Net................................................................ 0.866 5.627 1.508 Dry Gross.............................................................. 1 6 2 Net................................................................ 0.250 4.150 1.100 Total Wells: Productive Gross.............................................................. 35 25 13 Net................................................................ 1.853 6.079 1.633 Dry Gross.............................................................. 19 17 10 Net................................................................ 0.925 5.430 1.893
I-12 As of March 23, 1999, Middle Bay was drilling one Exploratory Well on the Ranch Prospect. (g) RESERVES Note 11 to the Company's financial statements presents, among other disclosures prepared pursuant to Statement of Financial Accounting Standards No. 69, the estimated net quantities of Middle Bay's proved oil and gas reserves and the standardized measure of discounted future net cash flows attributable to such reserves as of December 31, 1998. At December 31, 1998, the Company's net Proved Reserves consisted of 3,342 thousand barrels of oil and 43,483 million cubic feet of gas, and net Proved Developed Reserves consisted of 3,118 thousand barrels of oil and 36,731 million cubic feet of gas. At December 31, 1998, the present value discounted at 10% for Middle Bay's Proved oil and gas reserves, before income taxes, was approximately $38,894,000. (See Note 11 to the Company's financial statements for additional detail on Middle Bay's oil and gas reserves.) Management of the Company, however, cautions against using this data to determine the fair value of Middle Bay's oil and gas properties or for any other purpose because the price of oil and gas can be volatile. The present value was computed using December 31, 1998 base oil prices of $9.50 per Bbl and base gas prices of $2.10 per Mcf. Base prices were adjusted for certain properties that either received a price above or below the base price. There were no estimates or reserve reports of the Company's proved oil and gas reserves filed with any governmental authority or agency during the year ended December 31, 1998. The following table sets forth the standardized measure (in thousands of dollars) of future net cash flows of Proved Reserves and total recoverable volumes of oil and gas from Proved Reserves attributable to the Company's interest in oil and gas wells for the years ended December 31, 1996 through 1998:
RECOVERABLE VOLUMES ---------------------- STANDARDIZED OIL GAS YEAR ENDED MEASURE (MBBLS) (MMCF) - ---------------------------------------------------------------------- ------------ ----------- --------- December 31, 1998..................................................... $ 38,893 3,342 43,483 December 31, 1997..................................................... $ 24,493 2,933 18,419 December 31, 1996..................................................... $ 17,863 1,389 8,964
The increases in the standardized measure from 1996 to 1997 and 1997 to 1998 are due primarily to the Bison Merger, Shore Merger and Riceville Acquisition in 1997 and the Enex Acquisition and Service Drilling transactions in 1998. For a detail of changes in oil and gas reserves for the year, refer to Note 11 to the Company's financial statements. The reserve data set forth in this Form 10-KSB represents only estimates. Reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and adjustment. As a result, estimates of different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of crude oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas reserves and of future net revenues are based upon a number of variables and assumptions, including future prices of oil and gas, all of which may vary considerably from actual results. The reliability of such estimates is highly dependent upon the accuracy of the assumptions from which they were based. ITEM 3. LEGAL PROCEEDINGS The Company is a defendant in various legal proceedings which are considered routine litigation incidental to Middle Bay's business, the disposition of which management believes will not have a material effect on the financial position or result of operations of the Company. I-13 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS There were no matters submitted to a vote of security holders of Middle Bay during the fourth quarter of the fiscal year ended December 31, 1998. I-14 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 - ------------------------------------------------------------------------- ----------- ----------- 1997 First Quarter.......................................................... $ 9.25 $ 5.50 Second Quarter......................................................... 12.50 7.75 Third Quarter.......................................................... 11.50 8.75 Fourth Quarter......................................................... 11.13 9.00 1998 First Quarter.......................................................... $ 10.00 $ 5.75 Second Quarter......................................................... 8.00 5.13 Third Quarter.......................................................... 5.13 3.00 Fourth Quarter......................................................... 3.50 1.88
On March 12, 1999, the closing price of the common stock was $2.00 bid and $2.25 asked. (b) HOLDERS As of March 12, 1999, the Company had 686 holders of record of its common stock, which does not include an unknown number of additional holders whose stock is held in "street name." (c) DIVIDENDS; DIVIDEND POLICY The Company has never paid any dividends on its common stock. The terms of the Company's credit facility with Compass Bank prohibit the Company from making distributions of any kind, type or nature, cash or otherwise on its common stock. In any event, the Company expects to retain all available earnings generated by its operations for the development and growth of its business and does not anticipate paying any cash dividends on its common stock in the foreseeable future. Any future determination as to the payment of common stock dividends will be made at the discretion of the Board of Directors and will depend on a number of factors, including the future earnings, capital requirements, financial condition and future Prospects of the Company, restrictions in the Company's current or future financing agreements and any other factors as the Board of Directors may deem relevant. The Company is obligated to pay dividends on its Series C Preferred Stock in the amount of $571,332 per year. The Company has received a waiver from Compass Bank for the payment of dividends on the Series C Preferred Stock as long as no default or event of default exists or would exist as a result of the payment of the Series C Preferred Stock dividends. ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS The following discussion should be read in conjunction with the Company's financial statements and notes thereto set forth in Item 7. II-1 (a) RESULTS OF OPERATIONS The factors that most significantly affect the Company's results of operations are (i) the sales price of crude oil and natural gas, (ii) the level of production volumes, (iii) the level of lease operating expenses, (iv) the level of interest rates and (v) the level of general and administrative expenses. Sales of production and level of borrowing capacity are significantly impacted by the Company's ability to maintain or increase its production from existing oil and gas properties or through its exploration and development activities. Sales prices received by the Company for oil and gas have fluctuated significantly from period to period. The fluctuations in oil prices during these periods reflect market uncertainty regarding the inability of OPEC to control the production of its member countries, production from Iraq, as well as concerns related to the global supply and demand for crude oil. Gas prices received by the Company fluctuate generally with changes in the spot market price for gas. Relatively modest changes in either oil or gas prices significantly impact the Company's results of operations and cash flow and could significantly impact the Company's borrowing capacity. The table below details the increase (decrease) in oil and gas revenues, excluding plant and other revenues, caused by price and volume changes for the years ending December 31, 1998, 1997 and 1996.
1998 1997 1996 ------------- ------------ ---------- Oil Revenues Change due to volume........................................ $ 5,375,279 $ 3,549,922 $ 32,436 Change due to price......................................... (3,801,075) (644,906) 437,285 Total change................................................ 1,574,204 2,905,016 469,721 Gas Revenues Change due to volume........................................ $ 4,578,268 $ 2,161,383 $ 149,921 Change due to price......................................... (1,507,115) 201,483 708,386 Total change................................................ 3,071,153 2,362,866 858,307
(b) FISCAL 1998 For the current period, the revenues and expenses attributable to the Enex Acquisition and the Enex Partnership Acquisition are included for the period April through December and those attributable to the Service Acquisition are included for the months of May through December. For the comparable period, the revenues and expenses attributable to the Bison Merger are included for the period March through December, the Shore Merger for the period July through December and the Riceville Acquisition for the period August through December. Total revenues for the current period, of $17,703,000, were $6,270,000 higher than the comparable period. The increase in total revenues was due primarily to higher oil and gas revenues of $4,798,000 and higher gain on the sale of properties. During the current period lease bonus and rental income on the mineral acreage acquired in the Shore Merger decreased $758,000 and other revenues increased $282,000. Oil and gas revenues of $15,011,000 increased $4,798,000, consisting of a $1,574,000 increase in oil revenues, a $3,071,000 increase in gas revenues and a $153,000 increase in other revenues. The increase in oil and gas revenues was the result of higher oil and gas production. Production of oil increased 105% and production of gas increased 99%, over the comparable period. The oil production increase of 297,000 barrels and the gas production increase of 1,918,000 Mcf, were due primarily to the Riceville Acquisition which closed in 1997, and the Enex and Service Acquisitions which closed in 1998. During the current period, the Company sold 581,000 barrels of oil and 3,847,000 Mcf of gas, as compared to 284,000 barrels and 1,929,000 Mcf for the comparable period. The average price received on the gas sold in the current period of $2.00 per Mcf was 16% lower than the $2.39 per Mcf received in the comparable period. The average price received on the oil sold in 1998 of $11.52 per barrel was 36% lower than the $18.06 per barrel received in the comparable period. For the comparable period, production of oil was increased 30,000 barrels and oil revenues were increased $441,000 due to a reclassification. II-2 The Company received $217,000 in lease bonus and delay rental income on the fee mineral acreage acquired in the Shore Merger in the current period versus $975,000 in the comparable period. The decrease in leasing activity is the primary reason for the decline in income. The Company did not have any acreage revert to the surface owners in the current period. The gain on the sale of properties of $1,953,000 in the current period was primarily the result of sales of non-strategic properties and was $1,946,000 higher than the comparable period. Also included in the current period gain is a $365,000 gain on the sale of 20% of the Company's 25% interest in the Hawkins Ranch Prospect. Other income in the current period of $520,000 increased $284,000 over the comparable period. Other income consisted principally of a lawsuit settlement and an accounts payable settlement. Total expenses for the current period of $27,106,000 were $7,351,000 lower than the comparable period. The principal reason for the expense decrease was a decrease in the impairment charge of $16,984,000 to $4,164,000 versus $21,148,000 in the comparable period. The lower impairment charge was partially offset by a $3,953,000 increase in lease operating expenses, a $2,549,000 increase in depreciation, depletion and amortization and a $1,906,000 increase in general and administrative expenses. In the current period, the Company charged to impairment expense $4,164,000 versus $21,148,000 in the comparable period. The impairment expense was computed applying the guidelines of SFAS No. 121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of." The impairment expense in the current period of $4,164,000 was primarily attributable to oil and gas impairments of $4,092,000 on four fields--Wellman, Murphy Lake, Abbeville and Magnolia. The Wellman, Murphy Lake and Abbeville Fields were acquired in the Shore Merger in 1997 and the Magnolia Field was acquired in 1995. The Wellman, Murphy Lake and Magnolia Fields are oil fields whose value declined due to the decrease in oil prices. The impairment on the Abbeville Field was due to an unsuccessful recompletion attempt on the Goldberg #2 well. The reserves had been classified as proved behind pipe. The remaining oil and gas impairment expense of approximately $1,300,000 is attributable to several fields. The principal reasons for the impairment on these fields are the decrease in oil prices and the decrease or cessation of oil and gas production. The non-oil and gas impairment of approximately $72,000 is a $39,000 impairment of transaction costs in the postponed Enex Merger and a $33,000 impairment on oilfield equipment. Lease operating expenses of $7,801,000 increased by $3,953,000. The increase was due primarily to expenses associated with the properties acquired in the Enex and Service Acquisitions. Geological and geophysical expenses of $878,000 increased by $655,000. The primary geological and geophysical expenses in the current period include approximately $716,000 on Hawkins Ranch Prospect and $135,000 on Sherburne Prospect. Depletion, depreciation and amortization expense of $7,116,000 increased by $2,549,000. Depletion increased primarily due to the depletion associated with the properties acquired in the Enex and Service Acquisitions. Dry-hole expense of $503,000 decreased by $615,000 due to less drilling activity in the current period. The dryhole costs in the current period is due primarily to abandonment costs on two unsuccessful Exploratory Wells, the Dishman #1 well in the South Highbaugh Prospect in Texas and the Quarry #1 well in the Quarry Prospect in New Mexico, with dryhole costs of $197,000 and $125,000, respectively. Additional dryhole expense of $118,000 was for two wells in the Reflection Ridge Prospect in Kansas. The remaining dryhole expense of $63,000 was attributable to several additional wells. Interest expense of $1,972,000 increased by $1,301,000 due to a higher loan balance. The loan balance increased as a result of the funds borrowed to finance the Enex Acquisition in March and to partially finance the Service Acquisition in April. II-3 Stock compensation of $266,000 increased by $64,000. The increase was due to the granting of a warrant to purchase 75,000 shares of Company common stock to a consultant. The warrant fully vested on January 1, 1999 and was expensed in the current period. General and administrative expense of $4,267,000 increased by $1,906,000, due primarily to higher salary expense of $752,000, higher professional fees of $310,000 and higher office expenses of $195,000. The increase in salary expense was due to increases in salaries of existing employees, salaries of new employees and salaries associated with employees added in the Enex Acquisition. At December 31, 1998, the Company had twenty-seven full-time executive and clerical employees and five Enex employees. The increase in professional fees was due to higher accounting and engineering expenses related to a change in auditors and increased reserve report needs. The Company also experienced an increase in rent due to the Company previously owning its office in Mobile, Alabama versus renting office space since the Company's move to Houston in November 1997. The remaining increase in general and administrative expenses are over several categories and were due to the increase in the overall activity of the Company's business. Other expenses of $139,000 decreased $179,000 over the comparable period The Company reported an operating loss before minority interest of $9,404,000 for the current period, compared to an operating loss of $23,024,000 in the comparable period. Due to the Enex Acquisition, the Company records a minority interest on its income statement to remove the net income or loss attributable to the minority interest owners of Enex. For the six-month period ending September 30, the minority interest accounted for the income or loss for Enex and the Enex Partnership. For the three-month period ending December 31, the minority interest accounted only for the Enex operations since the Enex Partnership was merged into the Company effective October 1. In the current period the minority interest increased the operating loss by $15,089. The Company did not have a minority interest in the comparable period. The Company reported a deferred tax benefit of $2,830,000 for the current period versus a deferred tax benefit of $7,451,000 in the comparable period. The primary reason for the deferred tax benefit in the current period was the oil and gas reserve impairment, depletion expense and intangible drilling costs. The Company reported a net loss of $6,589,000 versus a net loss of $15,579,000 for the comparable period. The Company paid preferred dividends of $68,000 in the current period and $605,000 in the comparable period and reported a net loss to common stockholders of $6,657,000 in the current period versus a net loss to common stockholders of $16,184,000 in the comparable period. (c) FISCAL 1997 For the current period, the revenues and expenses attributable to the Bison Merger are included for the period March through December, the Shore Merger for the period July through December and the Riceville Acquisition for the period August through December. Total revenues for the current period of $11,433,000, were $6,546,000 higher than the comparable period. The increase in total revenues was due primarily to higher oil and gas revenues of $5,738,000. Revenue from lease bonus and delay rental income received on the fee mineral acreage in Louisiana increased $975,000. Gain on the sale of properties decreased by $31,000 and other income decreased by $136,000. Oil and gas revenues of $10,213,000 increased $5,738,000, consisting of a $2,905,000 increase in oil revenues, a $2,363,000 increase in gas revenues and a $470,000 increase in other oil and gas revenues. The increase in oil and gas revenues was primarily the result of increases in production which resulted from the Bison and Shore Mergers. Production of oil and gas for the current period, increased 160% and 96%, respectively, over the comparable period. During the current period, the Company sold 284,000 barrels of oil and 1,929,000 Mcf of gas, as compared to 109,000 barrels of oil and 983,000 Mcf of gas for the comparable period. Oil production for the current period was 175,000 barrels higher due primarily to production attributable to the Bison and Shore Mergers. Gas production in the current period was 946,000 Mcf higher due primarily to production attributable to Bison and Shore Mergers and the Riceville II-4 Acquisition. The price received on the gas sold in the current period of $2.39 per Mcf was slightly higher than the $2.28 per Mcf received in the comparable period. Oil prices in the current period of $18.06 per barrel were 11% lower than the $20.26 per barrel received in the comparable period. For the current period, production of oil was increased 30,000 barrels and oil revenues were increased $441,000 due to a reclassification. The gain on sale of properties in the current period of $7,000 decreased $31,000. Only a small number of oil and gas properties were sold in the current and comparable period. The Company received approximately $975,000 in lease bonus and delay rental income on the fee mineral acreage acquired in the Shore Merger in the current period. The Company had no lease bonus or delay rental income in the comparable period. Other income of $237,000 decreased $136,000 over the comparable period. Other income in the current period and comparable period consisted of various items related to the general business activity of the Company. Total expenses of $34,457,000 increased $29,851,000 over the comparable period. The principal reasons for the increase in the overall level of expenses were increased oil and gas property impairment charge by $20,870,000, increased lease operating expenses by $2,333,000, increased depletion expenses by $3,382,000 and increased general and administrative expenses by $1,699,000. In the fourth quarter of the current period, the Company charged to impairment expense $21,148,000 versus $278,000 in the comparable period. The impairment expense was computed applying the guidelines of SFAS No. 121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of." The impairment expense in the current period of $21,148,000 was primarily attributable to impairments on three fields--the Esther, Spivey and Wellman. The Esther and Wellman Fields were acquired in the Shore Merger, and the Spivey Field was acquired in the Bison Merger. The impairment on the Esther Field in Vermilion Parish, Louisiana was due primarily to a change in the category of reserves from Proved Undeveloped to Probable Undeveloped and changes in the economics of the development of the reserves. The category of the reserves was changed due to an abandoned sidetrack attempt in February, 1998 by the operator on the Proved Undeveloped Reserves. The impairment on the Spivey Field was due primarily to a decrease in the level of oil prices and changes in the economics of the Proved Undeveloped Reserves due to information obtained from the wells drilled in 1997. The impairment on the Wellman Field in Terry County, Texas was due primarily to decreases in oil prices. Since July 1, 1997, the posted price of WTI crude oil fell from approximately $18.00 per barrel to $15.00 per barrel at December 31, 1997 or 17%. The total oil equivalent reserves of the Wellman Field are 95% oil. The remaining impairment expense of approximately $4,400,000 is attributable to several fields. The principal reasons for the impairment on these fields are the decrease in oil prices and the decrease or cessation of oil and gas production. Lease operating expenses of $3,849,000 increased by $2,333,000. The increase was due primarily to the expenses associated with the properties acquired in the Bison and Shore Mergers. Depletion expense of $4,567,000 increased by $3,382,000. Depletion increased primarily due to the depletion associated with the properties acquired in the Bison and Shore Mergers. Interest expense of $671,000 increased by $166,000 due to a higher loan balance. The loan balance increased as a result of the funds borrowed to finance the Riceville Acquisition. Dry-hole expense of $1,119,000 increased by $690,000 due primarily to abandonment costs on three unsuccessful Exploratory Wells drilled in Louisiana--the Shore Oil Company #1, the Sabine #1 and the Middle Bay Oil Company #1--with dry-hole costs of $311,000, $177,000 and $168,000, respectively. Dryhole costs of $463,000 was attributable to several additional wells. II-5 General and administrative expense of $2,361,000 increased by $1,699,000, due primarily to higher salary expense of $724,000, higher professional fees of $347,000 and higher office expenses of $128,000. The remaining increase in general and administrative expenses was over several expense categories and was due primarily to an increase in the overall level of activity at the Company as a result of the Bison and Shore Mergers. The increase in salary expense is due to increases in salaries of existing employees and salaries associated with employees added in the Bison and Shore Mergers. At the time of the Bison Merger, seven employees occupied the Wichita, Kansas office. Effective August 1, 1997, only four employees occupied the Wichita, Kansas office--the President of Bison, an engineer, geologist and secretary. The President of Shore, an engineer and a secretary were added in the Shore Merger. In addition, the Company hired a land manager in July 1997 to manage the Company's land and mineral records and an accounting supervisor in October 1997 to assist with the increased accounting workload. Stock compensation expense of $202,000 increased by $202,000 due to the vesting of 50% of the restricted stock granted to certain Company employees in February, 1997. The remaining 50% will fully vest on June 30, 1998. Other expenses of $317,000 increased $285,000 over the comparable period. The primary reason for the increase was expenses associated with the Bison and Shore Mergers. The Company reported an operating loss of $23,024,000 for the current period as compared to an operating profit of $280,000 in the comparable period. The Company reported a deferred tax benefit of $7,451,000 for the current period versus deferred tax expense of $70,000 in the comparable period. The primary reason for the deferred tax benefit in 1997 was the oil and gas reserve impairment on the properties acquired in the Bison and Shore Mergers in 1997 and the NPC Merger in 1996. The Company reported a net loss of $15,579,000 versus net income of $205,500 for the comparable period. The Company paid preferred dividends of $605,000 in the current period and reported a net loss to common stockholders of $16,184,000 versus net income available to common stockholders of $205,000 for the comparable period. No preferred dividends were paid in 1996. (d) EFFECTS OF OIL AND GAS PRICE FLUCTUATIONS Fluctuations in the price of crude oil and natural gas significantly affect the Company's operations and the value of its assets. As a result of the instability and volatility of crude oil and natural gas prices, financial institutions have become more selective in the energy lending area and have reduced the percentage of existing reserves that may qualify for the borrowing base to support energy loans. The Company's principal source of cash flow is the production and sale of its crude oil and natural gas reserves which are depleting assets. Cash flow from oil and gas production sales depends upon the quantity of production and the price obtained for that production. An increase in prices permits the Company to finance its operations to a greater extent with internally-generated funds, allows the Company to obtain equity financing more easily and lessens the difficulty of attracting financing alternatives available to the Company from industry partners and nonindustry investors. However, price increases heighten the competition for Leases and Prospects, increase the costs of exploration and development activities and increase the risks associated with the purchase of Producing Properties. A decline in oil and gas prices (i) reduces the cash flow internally generated by the Company, which in turn reduces the funds available for servicing debt and exploring for and replacing oil and gas reserves, (ii) increases the difficulty of obtaining equity financing, (iii) reduces the number of Leases and Prospects available to the Company on reasonable economic terms and (iv) increases the difficulty of attracting financing alternatives available to the Company from industry partners and nonindustry investors. However, price declines reduce the competition for Leases and Prospects and correspondingly reduce the prices paid for Leases and Prospects. Furthermore, exploration and production costs generally decline, although the decline may not be at the same rate of decline of oil and gas prices. II-6 Since October, 1997, the price of oil has declined dramatically. The posted price of WTI crude oil has declined from a high of approximately $20.00 per barrel in October 1997 to lows in December 1998 of approximately $8.00 per barrel. Oil prices in March 1999 had recovered to approximately $12.50 per barrel. Gas prices peaked in November 1997, and on average, have declined slightly during the current period. (e) SEASONALITY The results of operations of the Company are somewhat seasonal due to seasonal fluctuations in the price for natural gas. Generally, natural gas prices are higher in the first and fourth quarter of the year due to colder winter weather and resulting higher demand for natural gas during these months. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of results on an annual basis. (f) INFLATION AND CHANGING PRICES Inflation principally affects the costs required to drill, complete and operate oil and gas wells. In recent years, inflation has had a minimal effect on the operations of the Company. Costs have generally declined recently due to the decrease in drilling activity in the United States. Unless increasing oil and gas prices spur large increases in industry activities, management believes costs will remain relatively stable over the next year. (g) CAPITAL RESOURCES AND LIQUIDITY--FISCAL 1998 AND FISCAL 1997 Cash flow from operating activities for the current period of $2,068,000 decreased $1,633,000 over the comparable period. The decrease in cash flow was due primarily to higher geological and geophysical, interest and general and administrative expenses, offset by increases in cash flow from oil and gas properties (oil and gas revenue less lease operating and production taxes) and working capital changes. Cash flow from oil and gas properties increased $846,000 over the comparable period. Oil and gas prices decreased 36% and 16%, respectively, while oil and gas production increased 105% and 99%, respectively. The change in working capital increased cash flow by $1,698,000 over the comparable period. The change in working capital was caused principally by timing differences in the payment of expenses and receipt of revenues. Cash additions to oil and gas properties were lower than the comparable period due primarily to the $3.5 million Riceville Acquisition in August 1997. The cash spent on acquisitions is higher due to the Enex Acquisition that closed March 27, 1998 and the Service Acquisition that closed April 16, 1998. The Company acquired approximately 79.2% of Enex common stock for cash in a tender offer and substantially all of the oil and gas assets of Service Drilling for cash and common stock. The increase in the amount of cash used for debt payments was due primarily to the replacing of the $50 million Convertible Loan, with a principal balance of $10,956,000, with the $100 million Revolver and principal payments of $5,015,000 on the $100 million Revolver. No monthly principal payments were required over the period April 1, 1997 to March 31, 1998 on the Company's $6 million, $15 million and $50 million Convertible Loans. The increase in the proceeds from debt issued was due to proceeds from the $100 million Revolver which were used to replace the $50 million Convertible Loan, to finance the Enex Acquisition and to partially finance the Service Acquisition. No preferred stock was issued for cash in the current period versus the $9 million issued under the Preferred Stock Agreement with Kaiser-Francis in the comparable period. Kaiser-Francis converted all of the Series A Preferred Stock on January 31, 1998. The Company's operating activities provided net cash of $2,068,000 for the current period. During this period, net cash from operations, cash from property sales and cash on hand was used principally for acquisitions and exploratory and developmental drilling. Approximately $925,000 was spent on exploratory drilling and approximately $2,690,000 was spent on developmental drilling. The principal exploratory wells in the current period were the S. Highbaugh Prospect ($197,000), the Quarry Prospect ($125,000) and the Sherburne Prospect ($421,000). The principal developmental wells drilled in the current period were the Kuehling #1 sidetrack ($548,000) in the Esther Field, several wells in the Lake Trammel Field ($207,000), a recompletion on a well in the Abbeville Field ($248,000), a recompletion on the Baker well in the Riceville Field ($222,000) and recompletions and drilling in the Spivey ($179,000) and Wellman ($124,000) II-7 Fields. The remaining $485,000 of capital expenditures on oil and gas was attributable to leasehold and proved property acquisitions. The Company spent approximately $15,960,000 on the Enex Acquisition which was financed entirely with debt proceeds from the $100 million Revolver. The Company spent approximately $6,500,000, excluding post-closing adjustments, on the cash portion of the Service Acquisition, $1,000,000 from cash on hand and the remainder with proceeds from the $100 million Revolver. Amounts spent on debt retirement consisted principally of the replacement of the $50 million convertible loan and principal payments on the $100 million Revolver. The Company paid approximately $1,348,000 in cash distributions to the minority interest partners in the Enex Partnership for the six-month period ending September 30. The Company spent approximately $431,000 on registration costs related to the registration of the Series C issued in the Enex Partnership Acquisition. Cash spent on other assets consisted principally of costs related to the deal costs on the postponed Enex Merger, computer equipment and software. The Company had current assets of $4,939,000 and current liabilities of $4,800,000, which resulted in working capital of $139,000 as of December 31, 1998. This was a decrease of $1,206,000 from the working capital of $1,344,000 as of December 31, 1997. Working capital decreased primarily due to the higher trade payables and amounts payable to dissenters and fractional shareholders in the Enex Partnership Acquisition. Accounts payable increased because of the increased number of properties and increased drilling activity. On August 13, 1998 the Oil and Gas Asset Clearinghouse auctioned several hundred oil and gas properties owned by the Company. The auctioned properties included properties acquired in the Enex and Service Acquisitions. Certain non-strategic properties were subject to minimum bid. The majority of the properties were sold by auction with no minimum bids. The Company received net proceeds of $2,635,000 from the sale of properties at the auction. During the current period, the Company also sold certain other non-strategic oil and gas properties in private sales for gross proceeds of $2,149,000. The remaining $28,000 of property sales proceeds was attributable to miscellaneous sales. Under the terms of the $100 million Revolver, when mortgaged properties are sold the borrowing base shall be reduced, and if necessary, proceeds from the sales of properties shall be applied to the debt outstanding in an amount equal to the loan value attributable to such properties sold. Of the total proceeds received from property sales, $2,145,000 was used to repay principal on the $100 million Revolver. On December 31, 1998 the Company sold 20% of its 25% interest in the Hawkins Ranch Prospect for $500,000. The proceeds from the sale were collected in January 1999 and are expected to be used to fund the drilling of the first three wells at Hawkins Ranch. $100 MILLION LINE OF CREDIT In conjunction with the Enex Acquisition on March 27, 1998 the Company entered into a new debt agreement with Compass Bank and Bank of Oklahoma (the "Banks"). The new debt agreement is a $100 million reducing, revolving line of credit (the "$100 million Revolver") with current borrowings under a term note maturing April 1, 2001. The entire principal balance of the Company's $50 million Convertible Loan at the Bank of Oklahoma was replaced with the $100 million Revolver. The Bank of Oklahoma is a participating lender with Compass Bank. The amount the Company can borrow is based upon the borrowing base. The borrowing base and the monthly borrowing base reduction amounts are redetermined semi-annually by unanimous consent of the lenders. The principal is due at maturity, April 1, 2001. Monthly principal payments are made as required in order that the outstanding principal balance plus outstanding letters of credit does not exceed the borrowing base. Interest is payable monthly and is calculated at the prime rate. The Company may elect to calculate interest under the Libor rate, as defined in the agreement. The Libor rate increases by (a) 2.00% if the outstanding loan balance and letters of credit are equal to or greater than 75% of the borrowing II-8 base, (b) 1.75% if the outstanding loan balance and letters of credit are less than 75% or greater than 50% of the borrowing base or (c) 1.50% if the outstanding loan balance and letters of credit are equal to or less than 50% of the borrowing base. The $100 million Revolver provided for an initial borrowing base of $29 million. The initial borrowing base was reduced to $27.5 million within ten days after the effective date and further reduced by $275,000 per month, beginning May 1, 1998 and ending October 1, 1998. In conjunction with the Service Acquisition, the borrowing base was increased to $32.6 million and the monthly borrowing base reductions were increased to $330,000. Effective October 1, 1998, the semi-annual borrowing base redetermination date, the borrowing base was calculated to be approximately $28.9 million with monthly borrowing base reductions of $250,000 beginning November 1, 1998. Effective January 1, 1999, due to the closing of the Enex Partnership Acquisition, the borrowing base determined at October 1, 1998 was adjusted to $33.1 million with monthly borrowing base reductions of $290,000 beginning November 1, 1998. The borrowing base at December 31, 1998 was $32.5 million and the next semi-annual borrowing base redetermination date is April 1, 1999. At December 31, 1998 the Company had borrowed $27,454,000 and had $1,164,000 of outstanding letters of credit. In the current period, the Company made $1,370,000 of required principal payments, $2,145,000 in payments from property sales proceeds and a $1,500,000 bridge payment ten days after the close of the Enex Acquisition. The Company is currently paying Libor plus 2.00% on a sixty day Libor loan for $25,470,000 and prime on $1,985,000. At December 31, 1998, the amount available under the borrowing base on the $100 million revolver was approximately $3.9 million. Assuming no other changes, the amount available to be borrowed at April 1 will be approximately $3.0 million. The Company expects that the Banks will complete the April 1 borrowing base redetermination by May 1, 1999. The Company also expects that the borrowing base will be less than the amount determined at the October 1, 1998 redetermination, adjusted for the monthly borrowing base reductions. The decline is expected to be caused primarily by normal production declines and lower oil and gas pricing scenarios used by the Banks to value the oil and gas reserves for loan purposes. Pursuant to the terms of the $100 million Revolver, if the borrowing base is less than the outstanding principal balance plus outstanding letters of credit the Company has sixty days, after receipt of notice from the Banks, to cure the excess by prepayment, providing additional collateral or a combination of both. The Company is unable to predict the April 1 borrowing base. While there can be no assurance, at the completion of the April 1 redetermination, the Company does not expect to be required to make any prepayments or provide any additional collateral that would be material to the financial condition of the Company. The Company paid a facility fee equal to 3/8% of the initial borrowing base and is required to pay 3/8% on any future increase in the borrowing base within five days of written notice. The Company is required to pay a quarterly commitment fee on the unused portion of the borrowing base of 1/2 % if the outstanding loan balance plus letters of credit are greater than 50% of the borrowing base or 3/8% if the outstanding loan balance plus letters of credit are less than or equal to 50% of the borrowing base. The Company is required to pay a letter of credit fee on the date of issuance or renewal of each letter of credit equal to the greater of $500 or 1 1/2 % of the face amount of the letter of credit. The Company has granted to the Banks liens on substantially all of the Company's oil and natural gas properties, whether currently owned or hereafter acquired, and a negative pledge on all other oil and gas properties. The $100 million Revolver requires, among other things, a cash flow coverage ratio of 1.25 to 1.00 and a current ratio, excluding the current maturity of the $100 million Revolver, of 0.9 to 1.00, determined on a quarterly basis. As of December 31, 1998 the Company was in compliance with the cash flow and current ratio covenants. Because the borrowing base was increased at the October 1 redetermination, no debt payments were required in the current quarter. The only debt payments made in the current quarter were the mortgage payments on the Company's former office in Mobile, Alabama. II-9 Under the terms of the $100 million Revolver, when mortgaged properties are sold the borrowing base shall be reduced, and if necessary, proceeds from the sales of properties shall be applied to the debt outstanding in an amount equal to the loan value attributable to such properties sold. The $100 million Revolver includes other covenants prohibiting cash dividends, distributions, loans, advances to third parties in excess of $100,000, or sales of assets greater than 10% of the aggregate net present value of the oil and gas properties in the borrowing base. Compass Bank has granted the Company a waiver allowing the Company to pay the dividends to holders of Series C as long as no default or event of default exists or would exist as a result of any Series C dividend payment. SERIES C PREFERRED STOCK In connection with the Enex Partnership Merger, on December 29, 1998, the Company issued 2,177,481 shares of Series C Preferred Stock ("Series C") in exchange for 100% of the Enex Partnership units. The holders of Series C are entitled to receive cumulative cash dividends in an amount per share of $0.50 per year (10% annual rate), payable semi-annually on March 31 and September 30 of each year. These dividends are payable in preference to and prior to the payment of any dividend or distribution to any holder of Company common stock or other junior security. The Series C dividends begin to accrue on December 30, 1998. The Series C has a liquidation preference of $5.00 per share plus an amount equal to all accumulated, accrued and unpaid dividends. The liquidation preference of Series C ranks on parity with the Series B Preferred Stock. Each share of Series C is convertible into one share of Company common stock. On or after January 1, 2000, the Company may redeem all or a portion of the Series C, at its option, at a purchase price of $5.00 per share, plus an amount equal to all accumulated, accrued and unpaid dividends. The Series C is generally nonvoting; however, holders of Series C are entitled to vote on any amendment, alteration or appeal of any provision of the Company's Articles of Incorporation which would adversely affect any holder's rights and preferences. As a result of its limited partnership interest in the Enex Partnership, Enex owns 1,293,522 shares of the Series C. Through its eighty percent ownership of Enex, 80% (or 1,034,818) of the shares are attributable to the Company. SERIES B PREFERRED STOCK In connection with the Shore Merger, effective June 30, 1997, the Company issued 266,667 shares of Series B Preferred Stock ("Series B"). The Series B is nonvoting and pays no dividends. The Series B has a liquidation value of $7.50 per share and is junior to the Company's Series A Preferred Stock. Until December 31, 2002, any holder of the Series B may convert all or any portion of Series B shares into Company Common Stock ("Common") at the greater ratio of (i) one share of Common for each share of Series B or (ii) at a ratio based upon the "Alternative Conversion Factor." The Alternative Conversion Factor is determined by dividing the net increase in value of approximately 40,000 net mineral acres owned by the Company in South Louisiana by $8,000,000 and multiplying the product by 1,066,000 to arrive at the potential number of total Common shares all holders would receive upon conversion. In no event shall the aggregate total number of shares of Common into which the Series B are converted be less than 266,667 shares or exceed 1,333,333 shares, unless further increased for any anti-dilution provisions. Upon expiration of the conversion period, unless the Company has given notice to redeem the Series B, all of the shares of the Series B shall be automatically converted. Since the merger date of June 30, 1997 the value of the fee minerals has not increased to a level where the alternative conversion rate is more beneficial than the initial conversion rate of one to one. As of December 31, 1998, no additional shares of Series B have been issued. II-10 SERIES A PREFERRED STOCK On September 4, 1996, the Company signed a stock purchase agreement with Kaiser Francis Oil Company ("the Agreement"). The Agreement provided for the purchase of 1,666,667 shares of Series A Preferred Stock ("Series A") at $6.00 per share, over a five-year period beginning September 4, 1996 with minimum incremental investments of $500,000 each. Each issuance of Series A was subject to approval by Kaiser-Francis of the use of proceeds. The Series A was nonvoting and accrued dividends at 8% per annum, payable quarterly in cash. The Series A was convertible at any time after issuance into shares of common stock at the rate of two shares of common stock for each share of Preferred before January 1, 1998. At December 31, 1997, all of the Series A had been issued and on January 31, 1998, all of the Series A was converted into 3,333,334 shares of Company common stock. THE ENEX ACQUISITION On March 27, 1998, the Company acquired 1,064,432 shares of the common stock of Enex, for $15 cash per share pursuant to the Company's tender offer that began February 19, 1998. The Enex shares acquired by the Company represent 79.2% of the total outstanding Enex common stock. The Company applied the purchase method of accounting to the Enex Acquisition. The purchase price of $15,966,000 was financed with proceeds from the Company's $100 million Revolver. The Company also incurred approximately $60,934 in legal, accounting and printing expenses and issued 33,825 shares of Company common stock for finders fees to unrelated third parties. Over a three-week period ending December 23, 1998, the Company acquired an additional 0.80% of Enex common stock for approximately $68,000. As part of the Enex Acquisition, the Company entered into a consulting agreement, effective April 15, 1998, with the former president of Enex that provides for monthly payments of $20,000 until expiration of the agreement on May 18, 2002. The present value of the agreement, applying a 10% discount rate, is approximately $788,000 and is included in Other Liabilities (current and long term). The monthly payments serve as consideration for consulting, a covenant not to compete and a preferential right to purchase certain oil and gas acquisitions which the former president controls or proposes to acquire during the term of the agreement. The Company will reimburse the former president each month for reasonable and necessary business expenses incurred in connection with the performance of consulting services. The agreement survives the former president and his spouse and is nonassignable. Enex, a Delaware corporation, is an independent oil and gas production and development company headquartered in Kingwood, Texas with operations primarily in Texas. Enex engages primarily in managing and acquiring producing oil and gas properties, and does not engage in significant drilling activities. Enex operates over 100 wells in South Texas. Before the tender offer, the Enex shares traded on the NASDAQ Stock Market National Market System under the symbol ENEX. The Enex shares are currently traded on the OTC Bulletin Board. Concurrent with the closing of the Enex Acquisition, the Enex Board of Directors resigned and were replaced by the persons who constitute the Company's Board of Directors. Enex is presently being operated as a majority-owned subsidiary of the Company. In addition to managing and acquiring direct interests in producing oil and gas properties, Enex served as general partner of the Enex Partnership until its sale to the Company, effective October 1, 1998. See the discussion below concerning the sale of the Enex Partnership to the Company. Approximately 73% of Enex's estimated future net revenues from proved reserves at December 31, 1997 is attributable to its interests in the Enex Partnership and approximately 27% is attributable to the properties owned directly by the Enex, after deducting the minority interest share of the Enex Partnership. As general partner, Enex had a 4.1% interest in the net revenues and gains generated by properties owned by the Enex Partnership. In addition to the general partner interest, Enex owned a 56.2% limited partner interest in the Enex Partnership. Based on the Company's 80% ownership of Enex, the Company had an effective limited partner ownership of the Enex Partnership of 44.9%. II-11 Because the Company's ownership of Enex is greater than 50%, the Company's consolidated financial statements at December 31, 1998 include 100% of the accounts of Enex subsequent to the acquisition date. Until the sale of the Enex Partnership, effective October 1, 1998, Enex consolidated 100% of the Enex Partnership on its books for financial reporting purposes because its ownership in the Enex Partnership was greater than 50%. The minority interest on the Company's balance sheet reflects the equity interest of the minority owners in Enex (20%). The operations of Enex for the six-month period ending September 30, which included the operations of the Enex Partnership until its sale effective October 1, 1998, were included in the financial statements of the Company. The operations of Enex for the three-month period ending December 31, which excluded the operations of the Enex Partnership, were also included in the financial statements of the Company. On October 31, 1998 the office lease in Kingwood where Enex and the Enex Partnership were headquartered expired. The Company has moved the majority of the current files and records for Enex and the Enex Partnership to the Houston office and has rented a small office in Kingwood where the accounting staff of Enex and the Enex Partnership will continue to operate until the end of the first quarter of 1999. THE ENEX MERGER On July 17, 1998, the Securities and Exchange Commission declared effective a registration statement filed under the Securities Act of 1933 for the merger of Enex into the Company (the "Enex Merger"). A special meeting of the stockholders of Enex was held on August 20, 1998 to approve the Enex Merger. Due to market conditions, the Company voted against the Enex Merger. Due to the postponement of the Enex Merger, the Company impaired deal costs related to the Enex Merger by approximately $38,000. THE ENEX PARTNERSHIP MERGER The Enex Partnership is a New Jersey limited partnership that was formed on June 30, 1997 from the combination of thirty-four Enex Oil and Gas Limited Partnerships. The Enex Partnership, headquartered in Kingwood, Texas, is engaged in the oil and gas business through the ownership of various interests in oil and gas properties. At October 1, 1998, Enex owned 56.24% of the outstanding limited partner units and the remaining 43.76% was owned by several thousand limited partners. On December 29, 1998 the Company closed an exchange of 2.086 shares of Series C Preferred stock for each Enex Partnership unit (the "Exchange Offer"). In connection with the Exchange Offer, the Company submitted a proposal to investors in the Enex Partnership to amend the partnership agreement to provide for the transfer of all of the assets and liabilities of the Enex Partnership to the Company as of October 1, 1998 and dissolve the Enex Partnership. The Company issued 2,177,481 Series C shares for 100% of the outstanding limited partner units. Enex was issued 1,293,522 Series C shares for its 56.24% ownership of the Enex Partnership. The remaining 883,959 Series C shares were issued to the limited partners that elected to take Series C shares in lieu of cash. Certain dissenting limited partners and fractional shares will be paid cash in January 1999. Because of the dissenting limited partners, Enex owns 59.4% of the Series C shares. The operations of the Enex Partnership for the nine-month period ending December 31 were included in the financial statements of the Company due to the Company's acquisition of Enex on March 27, 1998. Subsequent to October 1, 1998, no minority interest was recorded related to the operations of the Enex Partnership as it was dissolved. II-12 FUTURE CAPITAL REQUIREMENTS The Company has made and will continue to make, substantial capital expenditures for acquisition, development and exploration of oil and natural gas reserves. In fact, because the Company's principal natural gas and oil reserves are depleted by production, its success is dependent upon the results of its acquisition, development and exploration activities. The Company expects to incur a minimum of approximately $500,000 in capital expenditures over the next twelve months. The Company expects that available cash, cash flows from operations and cash proceeds from asset sales of certain non-core properties will be sufficient to fund the planned capital expenditures through 1999 in addition to funding interest and principal requirements on the $100 million Revolver. However, the Company may require additional borrowings under the $100 million Revolver or additional equity funding to raise additional capital to fund any acquisitions. Because future cash flows and the availability of financing are subject to a number of variables, such as the level of production and prices received for gas and oil, there can be no assurance that the Company's capital resources will be sufficient to maintain planned levels of capital expenditures and accordingly, oil and natural gas revenues and operating results may be adversely affected. At December 31, 1998, the amount available under the borrowing base on the $100 million revolver was approximately $3.9 million. Assuming no other changes, the amount available to be borrowed at April 1 will be approximately $3.0 million. The Company expects that the Banks will complete the April 1 borrowing base redetermination by May 1, 1999. The Company also expects that the borrowing base will be less than the amount determined at the October 1, 1998 redetermination, adjusted for the monthly borrowing base reductions. The decline is expected to be caused primarily by normal production declines and lower oil and gas pricing scenarios used by the Banks to value the oil and gas reserves for loan purposes. If the borrowing base is less than the outstanding principal balance plus outstanding letters of credit the Company has sixty days, after receipt of notice from the Banks, to cure the excess by prepayment, providing additional collateral or a combination of both. The Company is unable to predict the April 1 borrowing base. While there can be no assurance, at the completion of the April 1 redetermination, the Company does not expect to be required to make any prepayments or provide any additional collateral that would be material to the financial condition of the Company. However, depending on the amount of prepayment, if any is required, the Company may have to raise additional cash to meet this commitment. Amounts spent on debt retirement due to reductions in the borrowing base, reduce the cash available to spend on acquisition, development and exploration activities and, accordingly, oil and natural gas revenues and operating results may be adversely affected. By the end of the first quarter of 1999, the Company expects to have the operations of Enex and the Enex Partnership fully consolidated into its operations at the Company's headquarters in Houston. It is expected that the Company will realize certain cost savings in the consolidation of these operations. YEAR 2000 COMPLIANCE Readers are cautioned that the forward-looking statements contained in the following Year 2000 discussion should be read in conjunction with the Company's disclosures under the heading "Forward-Looking Statements." The disclosures also constitute a "Year 2000 Readiness Disclosure" and "Year 2000 Statement" within the meaning of the Year 2000 Information and Readiness Disclosure Act of 1998. STATEMENT OF READINESS The Company has undertaken various initiatives to ensure that its hardware, software and equipment will function properly with respect to dates before and after January 1, 2000. For this purpose, the phrase "hardware, software and equipment" includes systems that are commonly thought of as Information Technology systems ("IT"), as well as those Non-Information Technology systems ("Non-IT") and equipment which include embedded technology. IT systems include computer hardware and software and other II-13 related systems. Non-IT systems include certain oil and gas production and field equipment, gathering systems, office equipment, telephone systems, security systems and other miscellaneous systems. The Non-IT systems present the greatest readiness challenge since identification of embedded technology is difficult and because the Company is, to a great extent, reliant on third parties for Non-IT compliance. The Company has formed a Year 2000 ("Y2K") Project team, which is chaired by its Chief Financial Officer, Frank C. Turner, II. The team includes corporate staff and representatives from the Company's business units. In response to the possible risks posed to the Company, the team has developed a Y2K Plan (the "Plan") which includes guidelines for inventory, assessment, remediation, testing and contingency planning. The following categories represent the mission-critical operational systems of the Company. A "mission-critical system" is a system that is vital to the successful continuation of a core business activity. An application may be mission critical if it interfaces with a designated mission-critical system. Each system has been evaluated by the Company as to (a) the risks to the Company in the event of the most reasonably likely worst case scenario (the "Worst Case Scenario"); (b) the status of the Company's remediation plan, if any ("Status"); and (c) the Company's contingency plans, if any ("Contingency Plans"). ACCOUNTING SOFTWARE SYSTEMS. The Company relies solely on the software accounting packages ("Accounting Packages") to provide management with various reports that allow managers to determine the cash flow and profitability of individual properties and of the Company as a whole. Management also relies on the Accounting Packages to provide financial information necessary to prepare quarterly and annual financial reports that are sent to the Securities and Exchange Commission, NASDAQ Stock Market, banks and stockholders. In addition, the Company relies on the Accounting Packages to process and print checks to be sent to working and royalty interest owners for their share of the monthly oil and gas sales, to process and print checks for payment to vendors and to process and print monthly joint-interest statements to be sent to working interest owners in Company-operated oil and gas properties. Under a Worst Case Scenario, all accounting functions would have to be completed manually, significantly hindering the Company's ability to complete the above-described mission-critical systems. Status: The Company has updated its accounting systems. Testing is scheduled to be completed by April 30, 1999. Contingency Plans: The Company is currently considering contingency plans for processing its accounting data. Depending on the results of the testing phase, contingency plans will be developed.
CONTROL SYSTEMS AND IMBEDDED TECHNOLOGY. These systems include the equipment used to produce, monitor, control, sell and record hydrocarbon production, including all artificial lift equipment, storage, measurement and control facilities and third-party systems and technology interrelated to the Company's business. Under a Worst Case Scenario, multiple fields of oil and gas would lose the ability to account for the amount of hydrocarbon production, temporarily shutting down the field(s) until the malfunctioning part(s) could be repaired or replaced. This is not expected to materially adversely effect the Company. Status: The only mission-critical field operated by the Company is the Spivey Field, whose production operations are not affected by Y2K issues. The Spivey Field is affected by a third-party operated gas plant that processes the field's natural gas and may be subject to Y2K issues. Refer to "Third Party Systems-Gas Plant" for a discussion of the gas plant at the Spivey Field. The operations of the remaining fields were not materially affected by Y2K issues. Contingency Plans: The Company will continue to monitor the operations at its field locations and develop contingency planning if an exposure becomes apparent.
THIRD-PARTY SYSTEMS--OIL AND GAS PURCHASERS. The Company utilizes third-party purchasers to sell the oil and gas produced from the wells in which it has a working or royalty interest. The Company also II-14 depends on third-party purchasers to remit to the Company its share of the proceeds from the sales of oil and gas. The Company does not directly sell any oil and gas produced from the wells in which it has a working or royalty interest and does not take any oil or gas in kind as an alternative to cash payment. Under a Worst Case Scenario, multiple major purchasers would be temporarily shut down due to Y2K issues, materially adversely effecting the Company's revenues. Status: Based upon the diversity of purchasers, the Company believes that no single purchaser is a mission-critical purchaser. The Y2K team does not anticipate that a problem with any single purchaser for a reasonable period of time beyond 2000 will force the Company to curtail or shut down its operations. Although no single purchaser is a mission-critical purchaser, the loss of a major purchaser or multiple minor purchasers due to Y2K problems would affect the Company. The Company has obtained information about the top ten purchasers and their Y2K readiness. All but two of the top ten purchasers have formal Y2K Plans and are working to upgrade any mission-critical systems that are affected by Y2K. The other two purchasers acknowledge that certain systems will be affected by Y2K and have been undertaking plans to upgrade these systems. Contingency Plans: The Company continues to monitor the Y2K status of its major purchasers. Should a purchaser not become Y2K compliant, the Company will identify alternative purchasers for its production and, if necessary, temporarily shut-in production.
THIRD-PARTY SYSTEMS--GAS PLANT. Over 95% of the gas produced in the Spivey Field, a mission-critical system, is sold to a gas plant under a life of the lease casinghead tailgate gas contract. The Company owns approximately 11.5% of the gas plant and related gathering system. Colt Resources Corporation operates the plant. Under a Worst Case Scenario, the gas plant could be shut down which could materially adversely effect the Company. Status: The Company has received a letter from the operator of the Spivey plant stating that the Spivey plant's control systems and embedded technology are not Y2K affected and that its accounting and processing systems are Y2K compliant. Contingency Plans: A short-term interruption of gas sales would not materially affect the Company's operations. If the Spivey plant experiences problems with an expected duration in excess of one month, the Company has identified alternative gas markets it could utilize.
THIRD-PARTY SYSTEMS--BANKING. The Company relies on its banks to deposit checks payable to the Company and credit the checks to the appropriate accounts. The Company also relies on its banks to credit third-party accounts for payment. A Worst Case Scenario would occur if the Company's principal bank is unable to provide certain services for an extended period of time due to Y2K, causing the Company to be materially adversely affected. Status: The Company's principal bank currently has a formal Y2K Plan in effect and anticipates that all non-compliant, in-house mission-critical systems will be substantially remediated by December 31, 1998 and substantially completed by March 31, 1999 for vendor-supported systems. The Company's principal bank expects to have all of its non-compliant, mission-critical systems Y2K compliant by June 30, 1999. Contingency Plans: The Company intends to have cash on hand sufficient to cover short-term emergency payments and payroll. The Company also plans to open accounts with other institutions in the event its principal bank is unable to rectify its problems in a timely manner. The Company has no long-term contingency plans in the event of a system-wide failure of banking institutions.
II-15 THIRD-PARTY SYSTEMS--SUPPORT FUNCTIONS. The primary material support functions provided by third parties are electrical service, communication service and office space. Under a Worst Case Scenario, all primary support functions would be hindered in the short term. Status: All vendors of these services have reported that formal Y2K remediation plans are in effect and will be substantially complete by September 30, 1999. Contingency Plans: Short-term (less than two weeks) interruptions of services will not materially adversely effect the Company. The Company will be able to conduct business on a reduced scale using alternative business methods. Longer-term interruptions may materially adversely effect the Company. The Company has no plans sufficient to fully offset the effect of long-term interruptions.
COMPUTER OPERATING SYSTEMS AND APPLICATION SOFTWARE SYSTEMS. The Company relies solely on its personal computer systems to access the accounting software package through the Company's computer network. In addition, certain schedules and databases that are used for critical functions rely on spreadsheet and work-processing applications that are run on the Company's personal computer systems. Status: All systems appear to be Y2K ready. Contingency Plans: Operations could be performed manually until non-functioning equipment or software is repaired or replaced
COSTS OF Y2K COMPLIANCE The costs incurred by the Company to implement the Plan were not material to the Company's financial condition or results of operations. The Company does not expect any future costs related to the Plan to be material to the Company's financial condition or results of operations. THE RISKS OF Y2K ISSUES The Company presently believes that Y2K issues will not pose significant operational problems. However, if all significant Y2K issues are not properly identified or assessed, remediation and testing are not effected timely, the Y2K issues, either individually or in combination, may materially and adversely impact the Company's results of operations, liquidity and financial condition or materially and adversely affect its relationships with its business partners. Additionally, the misrepresentation of compliance by other entities or the persistent, universal failure of financial, transportation or other economic systems will likely have a material and adverse impact on the Company's operations or financial condition for which it cannot adequately prepare. ITEM 7. FINANCIAL STATEMENTS The Company's financial statements for the years ended December 31, 1998 and 1997 and the independent auditors' reports thereon are included in this Item 7. [The remainder of this page has been intentionally left blank] II-16 INDEX TO FINANCIAL STATEMENTS
PAGE ----- Reports of Independent Auditors............................................................................ F-2 Consolidated Balance Sheets as of December 31, 1998 and 1997............................................... F-4 Consolidated Statements of Operations for the years ended December 31, 1998 and 1997....................... F-5 Consolidated Statements of Cash Flows for the years ended December 31, 1998 and 1997....................... F-6 Consolidated Statements of Stockholders' Equity for the years ended December 31, 1998 and 1997............. F-7 Notes to Consolidated Financial Statements................................................................. F-8
F-1 REPORT OF INDEPENDENT AUDITORS The Board of Directors and Stockholders Middle Bay Oil Company, Inc. We have audited the accompanying consolidated balance sheet of Middle Bay Oil Company, Inc. and subsidiaries as of December 31, 1998, and the related consolidated statements of operations, changes in stockholders' equity and cash flows for the year then ended. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit. We conducted our audit in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Middle Bay Oil Company, Inc. and subsidiaries as of December 31, 1998, and the results of their operations and their cash flows for the year then ended in conformity with generally accepted accounting principles. KPMG LLP Houston, Texas March 26, 1999 F-2 REPORT OF INDEPENDENT AUDITORS The Board of Directors and Stockholders Middle Bay Oil Company, Inc. We have audited the accompanying consolidated balance sheet of Middle Bay Oil Company, Inc. and subsidiaries as of December 31, 1997, and the related statements of operations, changes in stockholders' equity and cash flows for the year then ended. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit. We have conducted our audit in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Middle Bay Oil Company, Inc. and subsidiaries as of December 31, 1997, and the results of their operations and their cash flows for the year then ended in conformity with generally accepted accounting principles. SCHULTZ, WATKINS & COMPANY Jackson, Mississippi February 27, 1998 F-3 MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS DECEMBER 31 ASSETS
1998 1997 ------------ ------------ CURRENT ASSETS........................................................................... Cash and cash equivalents.............................................................. $ 1,040,096 $ 1,587,184 Accounts receivable.................................................................... 3,309,043 2,352,679 Accounts receivable--Insurance Claim................................................... 448,083 -- Other current assets................................................................... 141,364 89,021 Assets held for resale................................................................. -- 206,464 ------------ ------------ Total current assets................................................................. 4,938,586 4,235,348 NON-CURRENT ASSETS Accounts receivable--stockholder....................................................... 173,115 166,165 PROPERTY (at cost) Oil and gas (successful efforts method) 90,849,439 62,654,328 Other.................................................................................. 795,323 822,806 ------------ ------------ 91,644,762 63,477,134 Less accumulated depletion, depreciation and amortization.............................. (39,073,584) (30,636,202) ------------ ------------ 52,571,178 32,840,932 OTHER ASSETS............................................................................. 257,938 10,127 ------------ ------------ TOTAL ASSETS............................................................................. $ 57,940,817 $ 37,252,572 ------------ ------------ ------------ ------------ LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES Current maturities of long term debt................................................... $ -- $ 1,375,537 Accounts payable--Trade................................................................ 3,643,241 1,176,680 Accounts payable--Enex, LP Dissenters and Fractional Shares............................ 538,750 -- Accounts payable--Revenue.............................................................. 342,931 308,981 Other current liabilities.............................................................. 275,010 29,737 ------------ ------------ Total current liabilities............................................................ 4,799,932 2,890,935 LONG TERM DEBT........................................................................... 27,454,567 9,714,713 DEFERRED INCOME TAXES.................................................................... 1,733,167 4,780,528 OTHER LIABILITIES........................................................................ 437,949 -- MINORITY INTEREST........................................................................ 957,369 -- STOCKHOLDERS' EQUITY..................................................................... -- -- Preferred stock, $.02 par, 5,000,000 shares authorized with 266,667 shares designated Series B and 2,177,481 designated Series C, none other issued........................ -- -- Cumulative convertible Series A 8% preferred stock, $6 stated value, No shares outstanding at 12/31/98 and 1,666,667 shares issued and outstanding at 12/31/97, $10,000,000 aggregate liquidation preference......................................... -- 10,000,000 Convertible preferred stock Series B, $7.50 stated value, 266,667 shares issued and outstanding at 12/31/98 and 12/31/97. $2,000,000 aggregate liquidation preference.... 3,627,000 3,627,000 Convertible preferred stock Series C, $5.00 stated value, 1,142,663 shares issued and outstanding at 12/31/98. $5,713,317 aggregate liquidation preference................. 5,281,937 -- Common stock, $.02 par value, 10,000,000 authorized, 8,552,365 and 4,519,206 shares issued and outstanding at 12/31/98 and 12/31/97, respectively........................ 171,055 90,392 Additional paid-in capital............................................................. 36,947,588 23,029,299 Unearned stock compensation............................................................ -- (67,500) Accumulated deficit.................................................................... (23,401,707) (16,744,755) Treasury stock; 21,773 shares at 12/31/98 and 12/31/97................................. (68,040) (68,040) ------------ ------------ Total stockholders' equity........................................................... 22,557,833 19,866,396 ------------ ------------ COMMITMENTS AND CONTINGENCIES TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY............................................... $ 57,940,817 $ 37,252,572 ------------ ------------ ------------ ------------
See accompanying notes to consolidated financial statements. F-4 MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIAIRES CONSOLIDATED STATEMENTS OF OPERATIONS YEARS ENDED DECEMBER 31
1998 1997 ------------- -------------- REVENUES Oil and gas sales and plant income.............................................. $ 15,011,354 $ 10,213,047 Gain on sale of properties...................................................... 1,953,362 7,018 Delay rental and lease bonus income............................................. 217,404 975,347 Other........................................................................... 520,458 237,583 ------------- -------------- Total revenues................................................................ 17,702,578 11,432,995 COSTS AND EXPENSES Lease operating, production taxes and plant costs............................... 7,801,249 3,848,627 Geological and geophysical...................................................... 877,643 222,608 Dryhole......................................................................... 503,444 1,118,838 Impairments..................................................................... 4,164,184 21,147,823 Depletion, depreciation and amortiziation....................................... 7,116,116 4,567,063 Interest........................................................................ 1,971,595 671,081 Stock compensation.............................................................. 266,445 202,500 General and administrative...................................................... 4,266,727 2,361,124 Other........................................................................... 138,855 317,469 ------------- -------------- Total costs and expenses...................................................... 27,106,258 34,457,133 LOSS BEFORE INCOME TAX BENEFIT AND MINORITY INTEREST.............................. (9,403,680) (23,024,138) INCOME TAX EXPENSE (BENEFIT) Current......................................................................... -- 6,451 Deferred........................................................................ (2,829,762) (7,451,249) ------------- -------------- (2,829,762) (7,444,798) MINORITY INTEREST................................................................. 15,089 -- ------------- -------------- NET LOSS.......................................................................... $ (6,589,007) $ (15,579,340) Dividends to preferred stockholders............................................... (67,945) (604,712) ------------- -------------- NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS...................................... $ (6,656,952) $ (16,184,052) ------------- -------------- ------------- -------------- NET LOSS PER SHARE Basic........................................................................... $ (0.83) $ (4.76) ------------- -------------- ------------- -------------- Diluted......................................................................... $ (0.83) $ (4.76) ------------- -------------- ------------- -------------- WEIGHTED AVERAGE COMMON SHARES OUTSTANDING Basic........................................................................... 8,050,108 3,397,117 ------------- -------------- ------------- -------------- Diluted......................................................................... 8,050,108 3,397,117 ------------- -------------- ------------- --------------
See accompanying notes to consolidated financial statements. F-5 MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS YEARS ENDED DECEMBER 31
1998 1997 ----------- ----------- CASH FLOWS FROM OPERATING ACTIVITIES Net loss............................................................................ $(6,589,007) $(15,579,340) Adjustments to reconcile net loss to net cash provided by operating activities: Depletion, depreciation and amortization.......................................... 7,070,916 4,567,063 Impairments....................................................................... 4,164,184 21,147,823 Deferred income tax benefit....................................................... (2,829,762) (7,451,249) Bad debt expense.................................................................. 20,000 45,000 Abandonment expense............................................................... 45,200 -- Dryhole costs..................................................................... 503,444 1,118,838 Stock compensation................................................................ 266,445 202,500 Gain on sale of assets............................................................ (1,953,362) (7,018) Minority interest................................................................. 15,089 -- Changes in operating assets and liabilities, net of acquisition effects: (Increase) Decrease in receivables................................................ (108,892) 243,779 Increase (Decrease) in payables................................................... 1,541,025 (438,355) (Increase) Decrease in other assets............................................... (76,995) (147,928) ----------- ----------- Net cash provided by operating activities........................................... 2,068,285 3,701,113 CASH FLOWS FROM INVESTING ACTIVITIES Payment for acquisition of Bison Energy Corp., net of cash acquired of $994,367... -- (7,139,914) Payment for acquisition of Shore Oil Company net of cash acquired of $2,057,467... -- (514,299) Payment for acquisition of 80% of Enex Resources Corp., net of cash acquired of $4,698,211....................................................................... (11,403,189) -- Payment for acquisition of assets of Service Drilling Co., LLC.................... (6,328,208) -- Capital expenditures: Oil and gas properties.......................................................... (4,100,252) (8,175,051) Other assets.................................................................... (322,816) (246,735) Proceeds from sale of: Oil and gas properties.......................................................... 4,812,326 103,872 Other assets.................................................................... 390,927 1,445,890 Advances to stockholder........................................................... (6,950) (6,950) ----------- ----------- Net cash used in investing activities......................................... (16,958,162) (14,533,187) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds of bank loans.............................................................. 32,469,604 5,769,705 Principal payments on loans......................................................... (16,105,287) (2,497,533) Proceeds from issuance of preferred stock........................................... -- 9,000,000 Preferred stock dividends........................................................... (67,945) (604,712) Partnership distributions........................................................... (1,348,098) -- Proceeds from common stock.......................................................... -- 195,772 Registration costs of Series C preferred stock...................................... (431,380) -- Other............................................................................... (174,105) -- ----------- ----------- Net cash provided by financing activities..................................... 14,342,789 11,863,232 NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS FOR THE YEAR..................... (547,088) 1,031,158 Cash and cash equivalents--Beginning of year........................................ 1,587,184 556,026 ----------- ----------- Cash and cash equivalents--End of year.............................................. $ 1,040,096 $ 1,587,184 ----------- ----------- ----------- ----------- SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION CASH PAID DURING THE YEAR FOR: Interest.......................................................................... $ 1,657,362 $ 601,582 ----------- ----------- ----------- ----------- Income Taxes...................................................................... -- $ 6,451 ----------- ----------- ----------- ----------- NON-CASH INVESTING AND FINANCING ACTIVITIES: Common stock issued as finders' fee in Enex Resources Corp. tender offer............ $ 245,232 $ -- ----------- ----------- ----------- ----------- Present value of consulting agreement of former president of Enex Resources Corp.... $ 788,563 $ -- ----------- ----------- ----------- ----------- Common stock issued in asset acquisition from Service Drilling Corp. LLC............ $ 3,554,774 $ -- ----------- ----------- ----------- ----------- Preferred stock issued in acquisition of Enex Consolidated Partners, LP............. $ 5,713,317 $ -- ----------- ----------- ----------- ----------- Conversion of redeemable common stock to common stock (net of treasury shares acquired)......................................................................... $ -- $ 421,179 ----------- ----------- ----------- ----------- Common stock issued in acquisition of Bison Energy Corp............................. $ -- $ 3,330,558 ----------- ----------- ----------- ----------- Common stock issued in acquisition of Shore Oil Company............................. $ -- $12,976,165 ----------- ----------- ----------- ----------- Preferred stock Series B issued in acquisition of Shore Oil Company................. $ -- $ 3,627,000 ----------- ----------- ----------- ----------- Debt assumed in acquisition of Shore Oil Company.................................... $ -- $ 2,105,000 ----------- ----------- ----------- ----------- Common stock issued in property acquisition......................................... $ -- $ 260,130 ----------- ----------- ----------- -----------
See accompanying notes to consolidated financial statements F-6 MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY YEARS ENDED DECEMBER 31, 1998 AND 1997
PREFERRED STOCK ---------------------------------------------------------------------- SERIES A SERIES B SERIES C COMMON STOCK ------------------------ --------------------- --------------------- -------------------- SHARES AMOUNT SHARES AMOUNT SHARES AMOUNT SHARES AMOUNT ---------- ------------ --------- ---------- --------- ---------- --------- --------- BALANCE--1/1/97............... 166,667 $ 1,000,000 -- $ -- -- $ -- 1,880,917 $ 37,618 Common stock issued in acquisition of NPC Energy Corporation................. -- -- -- -- -- -- 33,463 677 Preferred Series A issued..... 1,500,000 9,000,000 -- -- -- -- -- -- Common stock issued in acquisition of Bison Energy Corporation................. -- -- -- -- -- -- 605,556 12,111 Common stock issued in acquisition of Shore Oil Company..................... -- -- -- -- -- -- 1,883,333 37,667 Preferred Series B issued in acquisition of Shore Oil Company..................... -- -- 266,667 3,627,000 -- -- -- -- Conversion of redeemable common stock to common stock....................... -- -- -- -- -- -- -- -- Restricted stock awards....... -- -- -- -- -- -- 49,091 982 Stock options exercised....... -- -- -- -- -- -- 40,833 817 Purchase of oil and gas working interests........... -- -- -- -- -- -- 26,013 520 Unearned stock compensation... -- -- -- -- -- -- -- -- Net loss...................... -- -- -- -- -- -- -- -- 8% Preferred stock Series A dividends................... -- -- -- -- -- -- -- -- ---------- ------------ --------- ---------- --------- ---------- --------- --------- BALANCE--12/31/97............. 1,666,667 10,000,000 266,667 3,627,000 -- -- 4,519,206 90,392 Preferred A Conversion........ (1,666,667) (10,000,000) -- -- -- -- 3,333,334 66,667 Shares issued as finders fee in Enex Tender Offer........ -- -- -- -- -- -- 33,825 676 Service Drilling Co. Acquisition................. -- -- -- -- -- -- 666,000 13,320 Restricted stock awards earned...................... -- -- -- -- -- -- -- -- Enex Consolidated Partners Acquisition................. -- -- -- -- 1,142,663 5,713,317 -- -- Preferred Stock Registration Costs....................... -- -- -- -- -- (431,380) -- -- Warrants issued as compensation................ -- -- -- -- -- -- -- -- Net loss...................... -- -- -- -- -- -- -- -- 8% Preferred stock Series A dividend.................... -- -- -- -- -- -- -- -- ---------- ------------ --------- ---------- --------- ---------- --------- --------- ENDING BALANCE-- 12/31/98..... -- $ -- 266,667 $3,627,000 1,142,663 $5,281,937 8,552,365 $ 171,055 ---------- ------------ --------- ---------- --------- ---------- --------- --------- ---------- ------------ --------- ---------- --------- ---------- --------- --------- ADDITIONAL REDEEMABLE PAID-IN COMMON UNEARNED STOCK ACCUMULATED TREASURY CAPITAL STOCK COMPENSATION DEFICIT STOCK TOTAL ----------- ----------- -------------- ------------ ----------- ------------ BALANCE--1/1/97............... $ 6,049,442 $(421,179) $ -- $ (560,703) $ (68,040) $ 6,037,138 Common stock issued in acquisition of NPC Energy Corporation................. 93,018 -- -- -- -- 93,695 Preferred Series A issued..... -- -- -- -- -- 9,000,000 Common stock issued in acquisition of Bison Energy Corporation................. 3,318,447 -- -- -- -- 3,330,558 Common stock issued in acquisition of Shore Oil Company..................... 12,938,498 -- -- -- -- 12,976,165 Preferred Series B issued in acquisition of Shore Oil Company..................... -- -- -- -- -- 3,627,000 Conversion of redeemable common stock to common stock....................... -- 421,179 -- -- -- 421,179 Restricted stock awards....... 269,018 -- -- -- -- 270,000 Stock options exercised....... 101,266 -- -- -- -- 102,083 Purchase of oil and gas working interests........... 259,610 -- -- -- -- 260,130 Unearned stock compensation... -- -- (67,500) -- -- (67,500) Net loss...................... -- -- -- (15,579,340) -- (15,579,340) 8% Preferred stock Series A dividends................... -- -- -- (604,712) -- (604,712) ----------- ----------- -------------- ------------ ----------- ------------ BALANCE--12/31/97............. 23,029,299 -- (67,500) (16,744,755) (68,040) 19,866,396 Preferred A Conversion........ 9,933,333 -- -- -- -- -- Shares issued as finders fee in Enex Tender Offer........ 244,556 -- -- -- -- 245,232 Service Drilling Co. Acquisition................. 3,541,454 -- -- -- -- 3,554,774 Restricted stock awards earned...................... -- -- 67,500 -- -- 67,500 Enex Consolidated Partners Acquisition................. -- -- -- -- -- 5,713,317 Preferred Stock Registration Costs....................... -- -- -- -- -- (431,380) Warrants issued as compensation................ 198,946 -- -- -- -- 198,946 Net loss...................... -- -- -- (6,589,007) -- (6,589,007) 8% Preferred stock Series A dividend.................... -- -- -- (67,945) -- (67,945) ----------- ----------- -------------- ------------ ----------- ------------ ENDING BALANCE-- 12/31/98..... $36,947,588 $ -- $ -- ($23,401,707) $ (68,040) $ 22,557,833 ----------- ----------- -------------- ------------ ----------- ------------ ----------- ----------- -------------- ------------ ----------- ------------
See accompanying notes to consolidated financial statements. F-7 MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES Notes to Consolidated Financial Statements December 31, 1998 and 1997 (1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES ORGANIZATION Middle Bay Oil Company, Inc. (the Company) was incorporated under the laws of the state of Alabama on November 20, 1992. Effective March 27, 1998, the Company acquired 79.2% of Enex Resources Corporation ("Enex") and effective April 16, 1998, the Company acquired the assets of Service Drilling Co., LLC ("Service Drilling"). Effective October 1, 1998, the Company acquired 100% of Enex Consolidated Partners, L.P. ("Enex Partnership"), a limited partnership of which Enex owned greater than a 50% interest. In 1997, the Company acquired Bison Energy Corporation and Shore Oil Company. The Company is engaged in the acquisition, development and production of oil and natural gas in the contiguous United States. The Company considers its business to be a single operating segment. SIGNIFICANT ACCOUNTING POLICIES The Company's accounting policies reflect industry standards and conform to generally accepted accounting principles. The more significant of such policies are described below. PRINCIPLES OF CONSOLIDATION The consolidated financial statements include the accounts of the Company, its wholly-owned subsidiary and Enex, an 80% owned subsidiary. The equity of minority interest in Enex is shown in the consolidated statements as "minority interest". All significant intercompany balances and transactions have been eliminated in consolidation. CASH AND CASH EQUIVALENTS For purposes of the statements of cash flows, the Company classifies all cash investments with original maturities of three months or less as cash. OIL AND GAS PROPERTY The Company follows the successful efforts method of accounting for oil and gas properties, and accordingly, capitalizes all direct costs incurred in connection with the acquisition, drilling and development of productive oil and gas properties. Costs associated with unsuccessful exploration are charged to expense currently. Geological and geophysical costs and costs of carrying and retaining unevaluated properties are charged to expense. Depletion, depreciation and amortization of capitalized costs are computed separately for each property based on the unit of production method using only proved oil and gas reserves. In arriving at such rates, commercially recoverable reserves have been estimated by independent petroleum engineering firms. The Company reviews its undeveloped properties continually and charges them to expense on a property by property basis when it is determined that they have been condemned by dry holes, or will not be retained, sold or drilled upon. Gains and losses are recorded on sales of entire interests in proved or unproved properties. For the years ended December 31, 1998 and 1997, the Company realized gains on sales of properties of $1,953,000 and $7,000, respectively. The Company reviews long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such an asset may not be recoverable. This review consists of a comparison of the carrying value of the asset to the asset's expected future undiscounted cash flows without interest costs. Estimates of expected future cash flows represent management's best estimate based on reasonable and supportable assumptions and projections. If the expected future cash flows, assuming escalated prices, are F-8 MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES Notes to Consolidated Financial Statements December 31, 1998 and 1997 (1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) less than the carrying value of the asset, an impairment exists and is measured as the excess of the carrying value over the estimated fair value of the asset. The Company estimates discounted future net cash flows to determine fair value. Any impairment provisions recognized are permanent and may not be restored in the future. For the years 1998 and 1997, the Company's proved properties were assessed for impairment on an individual field basis and the Company recorded impairment provisions of $4,092,000 and $21,148,000 respectively, attributable to certain producing properties. SITE RESTORATION, DISMANTLEMENT AND ABANDONMENT COSTS Site restoration, dismantlement and abandonment costs (P&A costs) are common in the oil and gas industry in which the Company conducts operations. P&A costs are costs associated with removing the facilities and equipment required to operate a well and restoring the well site to specified conditions. P&A costs are incurred when the oil and gas reserves of a well or wells are depleted or when production drops to the point that it is no longer economically feasible to produce. P&A costs are governed by federal and state regulations and contractual obligations. The Company, in conjunction with its independent engineers and the operators of the wells, continually reviews its working interests with respect to potential P&A costs. Estimated P&A costs (net of salvage value) are amortized through depletion using the units-of-production method. As of December 31, 1998, the Company's estimated P&A were approximately $495,000, of which approximately $26,200 was amortized as of December 31, 1998. The Company's estimated P&A costs at December 31, 1997 were immaterial. OTHER PROPERTY AND EQUIPMENT Other property and equipment are stated at cost and depreciation is computed on the accelerated method over appropriate lives ranging from five to seven years. Additions and betterments which provide benefits to several periods are capitalized. ENVIRONMENTAL LIABILITIES Environmental expenditures that relate to current or future revenues are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. Generally, the timing of these accruals coincides with the Company's commitment to a formal plan of action. REVENUE Oil and gas revenues are recorded using the sales method, whereby the Company recognizes revenues based on the amount of oil and gas sold to purchasers on its behalf. INCOME TAXES The Company uses the asset and liability method of accounting for income taxes under which deferred tax assets and liabilities are determined by applying enacted statutory tax rates applicable to future years to the difference between the financial statement and tax basis of assets and liabilities. The effect on deferred F-9 MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES Notes to Consolidated Financial Statements December 31, 1998 and 1997 (1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) tax assets and liabilities of a change in tax rates is recognized as part of the provision for income taxes in the period that includes the enactment date. STOCK BASED COMPENSATION The Financial Accounting Standards Board ("FASB") issued SFAS No. 123, "Accounting for Stock Based Compensation", which establishes financial accounting and reporting standards for stock based compensation plans. The statement provides the option to continue under the accounting provisions of APB Opinion No. 25, while requiring proforma footnote disclosures of the effects of net income and earnings per share, calculated as if the new method had been implemented. The Company adopted the financial reporting provisions of SFAS No. 123, but continues under the accounting provisions of APB Opinion No. 25. EARNINGS PER SHARE Basic earnings per share is based on the weighted average shares outstanding without any dilutive effects considered. Diluted earnings per share reflects dilution from all potential common shares, including options, warrants and convertible preferred stock. CONCENTRATIONS OF MARKET RISK The future results of the Company will be affected by the market prices of oil and natural gas. The availability of a ready market for natural gas and oil in the future will depend on numerous factors beyond the control of the Company, including weather, production of other natural gas and crude oil, imports, marketing of competitive fuels, proximity and capacity of oil and gas pipelines and other transportation facilities, any oversupply or undersupply of gas and oil, the regulatory environment, and other regional and political events, none of which can be predicted with certainty. CONCENTRATIONS OF CREDIT RISK Financial instruments which subject the Company to concentrations of credit risk consist primarily of cash and accounts receivable. The Company places its cash investments with high credit qualified financial institutions. Risk with respect to receivables is concentrated primarily in the current production revenue receivable from multiple oil and gas producers, both major and independent, and is typical in the industry. No single customer accounted for greater than 10% of the Company's total oil and gas sales for the year ended December 31, 1998. The Company sold oil and gas representing approximately 14% of its total oil and gas sales to one customer, Warren Petroleum Company, L.P., for the year ended December 31, 1997. ACCOUNTING PRONOUNCEMENTS In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities". SFAS No. 133 standardizes the accounting for and disclosures of derivative instruments, including certain derivative instruments embedded in other contracts. The statement is effective for the Company beginning after January 1, 2000. As the Company historically has not entered into derivative instruments for non-trading (hedging) purposes or for trading purposes, the Company does not expect this statement to have a material impact on its financial condition or results of operations upon implementation. F-10 MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES Notes to Consolidated Financial Statements December 31, 1998 and 1997 (1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued) USE OF ESTIMATES Management of the Company has made a number of estimates and assumptions relating to the reporting of assets and liabilities to prepare the financial statements in conformity with generally accepted accounting principles. Actual results could differ from those estimates. RECLASSIFICATIONS Certain reclassifications of prior period amounts have been made to conform to the current presentation. (2) ACQUISITIONS On February 28, 1997, the Company completed the acquisition of Bison Energy Corporation ("BEC"). The transaction consisted of a merger (the "Bison Merger") of BEC into Bison Energy Corporation-Alabama, a wholly-owned subsidiary of the Company. On February 28, 1997, Bison Energy Corporation-Alabama merged into BEC and its separate corporate existence ceased. BEC was merged into the Company in January, 1998. The cost of acquiring BEC was approximately $10 million, consisting of the following (in thousands): Estimated fair value of 605,556 shares of Company common stock issued........................................................... $ 3,330 Cash consideration................................................. 6,654 Legal and accounting expenses...................................... 35 --------- Total.............................................................. $ 10,019 --------- ---------
The fair value of the securities issued in connection with the merger was calculated using the price of the Company's common stock at the time the Bison Merger was announced to the public of $5.50 per share. The Company's purchase price was allocated to the consolidated assets and liabilities of BEC based on estimates of the fair values with the remaining purchase price allocated to proved oil and gas properties. The allocation of the purchase price is summarized as follows: (in thousands) Working capital.................................................... $ 714 Oil and gas properties (proved).................................... 13,268 Yard equipment..................................................... 465 Deferred income taxes.............................................. (4,428) --------- Total.............................................................. $ 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. On June 30, 1997, the Company completed the acquisition of Shore Oil Company ("Shore"). The transaction consisted of a merger (the "Shore Merger") of Shore into Shore Acquisition Company Inc., a wholly-owned subsidiary of the Company. On June 30, 1997, Shore Acquisition Company merged into Shore F-11 MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES Notes to Consolidated Financial Statements December 31, 1998 and 1997 (2) ACQUISITIONS (Continued) and its separate corporate existence ceased. Shore continued as a wholly-owned subsidiary of the Company until it was merged into the Company in January 1998. The cost of acquiring Shore was approximately $19 million, consisting of the following (in thousands): Estimated fair value of 1,883,333 shares of Company common stock issued........................................................... $ 12,976 Estimated fair value of 266,667 shares of Company Series B preferred stock.................................................. 3,627 Cash consideration................................................. 2,533 Legal and accounting expenses...................................... 38 --------- Total.............................................................. $ 19,174 --------- ---------
The fair value of the securities issued in connection with the merger was calculated using the average price of the Company's common stock at the time the Shore Merger was announced to the public and further adjusted for tradability restrictions. An independent valuation firm determined the tradability discount for the Company's common stock. The Company's purchase price was allocated to the consolidated assets and liabilities of Shore based on estimates of the fair values with the remaining purchase price allocated to proved and unproved oil and gas properties. The allocation of the purchase price is summarized as follows: (in thousands) Working capital.................................................... $ 2,288 Oil and gas properties (proved and unproved)....................... 20,688 Fee minerals....................................................... 5,495 Debt assumed....................................................... (2,105) Deferred income taxes.............................................. (7,192) --------- Total.............................................................. $ 19,174 --------- ---------
On March 27, 1998, the Company acquired 1,064,432 common shares, approximately 79.2%, of Enex for $15,966,480. The Company purchased the common shares of Enex through a cash tender offer that commenced February 19, 1998 (the "Enex Acquisition"). The Company also incurred approximately $60,934 in legal, accounting and printing expenses and issued 33,825 shares of Company common stock for finders fees to unrelated third parties. At the time, Enex was general partner of Enex Consolidated Partners, L.P., (the "Enex Partnership"), a New Jersey limited partnership whose principal business is oil and gas exploration and production. Enex's general partner interest was 4.1%. Enex also owned an approximate 56.2% limited partner interest in Enex Partnership. As part of the Enex Acquisition, the Company entered into a consulting agreement, effective April 15, 1998, with the former president of Enex that provides for monthly payments of $20,000 until expiration of the agreement on May 18, 2002. The monthly payments serve as consideration for consulting, a covenant not to compete and a preferential right to purchase certain oil and gas acquisitions which the former president controls or proposes to acquire during the term of the agreement. The Company will reimburse the former president each month for reasonable and necessary business expenses incurred in connection with the performance of consulting services. The agreement survives the former president and his spouse and is nonassignable. At December 31, 1998, the present value of the agreement, applying a 10% discount, is F-12 MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES Notes to Consolidated Financial Statements December 31, 1998 and 1997 (2) ACQUISITIONS (Continued) approximately $677,949. The long-term portion of the agreement is classified as other liabilities in the financial statements. The cost of acquiring 79.2% of Enex was allocated using the purchase method of accounting to the consolidated assets and liabilities of Enex based on estimates of the fair values with the remaining purchase price allocated to proved oil and gas properties. The allocation of the purchase price is summarized as follows: (in thousands) Working capital.................................................... $ 5,640 Oil and gas properties (proved and unproved)....................... 19,090 Minority interest.................................................. (7,669) --------- Total.............................................................. $ 17,061 --------- ---------
Over the three-week period ended December 23, 1998, the Company acquired an additional 0.80% (9,747 common shares) of Enex common stock for approximately $68,000. On April 16, 1998, the Company acquired substantially all of the oil and gas assets of Service Drilling Co., LLC and certain affiliates ("Service Drilling"), in exchange for 666,000 shares of Company common stock and $6,500,000 in cash for a total acquisition cost of $10,054,774, before post-closing adjustments (the "Service Acquisition"). The fair value of the securities issued in connection with the Service Acquisition was calculated using the price of the Company's common stock at the time the Service Acquisition was announced to the public and further adjusted for tradability restrictions. An independent valuation firm determined the tradability discount for the Company's common stock. The effective date of the acquisition was March 1, 1998 and the cost was allocated using the purchase method of accounting. On December 29, 1998, the Company completed the acquisition of the Enex Partnership (the "Enex Partnership Acquisition"). The transaction consisted of an exchange offer whereby the Company offered to exchange 2.086 shares of Series C Preferred stock ("Series C") for each Enex Partnership unit (the "Exchange Offer"). In connection with the Exchange Offer, the Company submitted a proposal to investors in the Enex Partnership to amend the partnership agreement to provide for the transfer of all of the assets and liabilities of the Enex Partnership to the Company as of October 1, 1998 and dissolve the Enex Partnership. The Exchange Offer was approved on December 29, 1998 and the Company issued 2,177,481 Series C shares for 100% of the outstanding limited partner units. At the close of the Exchange Offer, the Enex Partnership had 1,102,631 units outstanding. Enex was issued 1,293,522 Series C shares for its 56.2% ownership of the Enex Partnership. The remaining 883,959 Series C shares were issued to the limited partners that elected to take Series C shares in lieu of cash. Certain dissenting limited partners and fractional shareholders were paid $538,750 in January 1999. Because of the dissenting limited partners, Enex owns 59.4% of the Series C shares, of which 20% relating to the minority interest (258,704 shares) are considered outstanding and held by third parties in the consolidated financial statements at December 31, 1998. The intent of the Exchange Offer was to acquire the 43.8% of the outstanding limited partner units that the Company did not currently own. The tables below present the consideration paid for 100% of the Enex Partnership and for the 43.8% of the Enex Partnership not owned by Enex. F-13 MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES Notes to Consolidated Financial Statements December 31, 1998 and 1997 (2) ACQUISITIONS (Continued) The cost of acquiring 100% of the outstanding limited partner units was approximately $11.9 million, consisting of the following (in thousands): Estimated fair value of 2,177,481 shares of Company Series C preferred stock.................................................. 10,887 Cash consideration................................................. 539 Legal, accounting and other expenses............................... 431 --------- Total.............................................................. $ 11,857 --------- ---------
As Enex is consolidated into the Company's financial statements, the number of shares outstanding and the value of the shares outstanding attributable to the 43.8% of the Enex Partnership not owned by Enex and the minority interest owners of Enex (20%) is 1,142,663 and $5,713,317, respectively. The cost of acquiring the outstanding limited partner units that were not owned by Enex was approximately $6.7 million, consisting of the following (in thousands): Estimated fair value of 1,142,663 shares of Company Series C preferred stock.................................................. 5,713 Cash consideration................................................. 539 Legal, accounting and other expenses............................... 431 --------- Total.............................................................. $ 6,683 --------- ---------
The Company's purchase price was allocated to the assets and liabilities of the Enex Partnership based on estimates of the fair values with the remaining purchase price allocated to proved oil and gas properties. The registration costs of approximately $431,000 reduced the value of the Series C shares issued. Because the Enex Partnership was consolidated in the financial statements of the Company as of the effective date of October 1, 1998, the preliminary purchase price allocation below shows the effect of the acquisition on the consolidated financial statements (in thousands): Working capital.................................................... (539) Oil and gas properties............................................. (23) Minority interest.................................................. 5,844 --------- Series C Preferred Stock........................................... $ 5,282 --------- ---------
F-14 MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES Notes to Consolidated Financial Statements December 31, 1998 and 1997 (2) ACQUISITIONS (Continued) The following pro forma data presents the results of the Company for the twelve months ended December 31, 1998 and 1997, as if the acquisitions of BEC, Shore, Service, Enex and the Enex Partnership had occurred on January 1, 1997. The pro forma results are presented for comparative purposes only and are not necessarily indicative of the results which would have been obtained had the acquisitions been consummated as presented. The following data reflect pro forma adjustments for oil and gas revenues, production costs, depreciation and depletion related to the properties and businesses acquired, preferred stock dividends on preferred stock issued, and the related income tax effects (in thousands, except per share amounts):
PROFORMA --------------------- 1998 1997 --------- ---------- (UNAUDITED) Total revenues......................................................... $ 21,232 $ 32,341 Net loss available to stockholders..................................... (7,413) (14,607) Net loss per share available to stockholders........................... (0.87) (2.84)
(3) RELATED PARTY TRANSACTIONS The Company has a note receivable from Bay City Energy Group, Inc., a shareholder of the Company, as of December 31, 1998 and 1997 in the amount of $173,115 and $166,165 respectively. The principal balance of the note accrues interest at 5% annually and is due January 1, 2001. The note is secured by 75,000 shares of Company common stock. Interest of $34,110 was accrued on the note as of December 31, 1998. The Company rents office space from C.J. Lett III, a shareholder, officer and director of the Company. The rent is $3,000 per month for three years through February, 2000. Mr. Lett has common stock ownership in two oil service companies that provide services to the Company. The Company paid approximately $148,000 and $88,000 to these companies for the years ended 1998 and 1997, respectively. The Company loaned Frank C. Turner II, Vice-President and Chief Financial Officer, $14,400 in September 1998 to pay income taxes associated with the exercise of incentive options. The balance at December 31, 1998 was $14,400. Gary R. Christopher, a shareholder and director of the Company, is employed by Kaiser-Francis Oil Co., which owns approximately 39% of the common stock of the Company. (4) ACCOUNTS RECEIVABLE-INSURANCE CLAIM The Company owns a 100% working interest in the Louis Mayard #1 (the "Well") well located in the Esther Field in Vermillion Parish, Louisiana. Due to a failed recompletion attempt and the inability of the Company to shut in the Well using normal operating methods, the Company incurred approximately $1,856,000 to gain control of the Well using special crews. On November 4, 1998, the insurance company made a partial payment to the Company under its well control insurance policy of approximately $1,408,000. At December 31, 1998, the Company had recorded the estimated remaining amount due from the insurance company in current assets as Accounts Receivable-Insurance Claim. F-15 MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES Notes to Consolidated Financial Statements December 31, 1998 and 1997 (5) LONG-TERM DEBT Long-term debt at December 31, 1998 and 1997, consisted of the following:
1998 1997 ------------- ------------- Reducing revolving line of credit up to $100,000,000 due April 1, 2001, secured by oil and gas properties, monthly borrowing base reductions of $290,000 effective November 1, 1998 and monthly payments of interest at LIBOR plus 2.00% and prime. At December 31, 1998 the LIBOR rate and the prime rate were 5.07% and 7.75%, respectively.......................... $ 27,454,567 -- Convertible Loan for $50,000,000 due September 30, 1998, secured by oil and gas properties, monthly payments of interest only at LIBOR plus 1.75%, convertible into a 72 month term note on September 30, 1998..... -- $ 10,956,298 Note, due 1/1/99, secured by office building, repayable in monthly installments of $1,511 including interest at 7 3/4%.................... -- 133,952 ------------- ------------- Total.................................................................... 27,454,567 11,090,250 Less current maturities.................................................. -- (1,375,537) ------------- ------------- Long tem debt excluding current maturities............................... $ 27,454,567 $ 9,714,713 ------------- ------------- ------------- -------------
Effective March 27, 1998 the Company entered into a new reducing revolving line of credit agreement (the "$100 million Revolver") with Compass Bank, as agent and lender, and Bank of Oklahoma, as a participant lender, (collectively, the "Banks"). The $100 million Revolver provided for an initial borrowing base of $29 million. The initial borrowing base was reduced to $27.5 million ten days after the effective date and further reduced by $275,000 per month, beginning May 1, 1998 and ending October 1, 1998. In conjunction with the Service Acquisition, the borrowing base was increased to $32.6 million and the monthly borrowing base reductions were increased to $330,000. Effective October 1, 1998, the semi-annual borrowing base redetermination date, the borrowing base was calculated to be approximately $28.9 million with monthly borrowing base reductions of $250,000 beginning November 1, 1998. Effective January 1, 1999, due to the closing of the Enex Partnership Acquisition, the borrowing base determined at October 1, 1998 was adjusted to $33.1 million with monthly borrowing base reductions of $290,000 beginning November 1, 1998. The borrowing base at December 31, 1998 was $32.5 million and the next semi-annual borrowing base redetermination date is April 1, 1999. The principal is due at maturity, April 1, 2001. Monthly principal payments are made as required in order that the outstanding principal balance plus outstanding letters of credit does not exceed the borrowing base. Interest is payable monthly and is calculated at the prime rate. The Company may also elect to calculate interest under the Libor rate, as defined in the agreement. The Libor rate increases by (a) 2.00% if the outstanding loan balance and letters of credit are equal to or greater than 75% of the borrowing base, (b) 1.75% if the outstanding loan balance and letters of credit are less than 75% or greater than 50% of the borrowing base or (c) 1.50% if the outstanding loan balance and letters of credit are equal to or less than 50% of the borrowing base. Libor interest is payable at maturity of the Libor loan which cannot be less than thirty days. F-16 MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES Notes to Consolidated Financial Statements December 31, 1998 and 1997 (5) LONG-TERM DEBT (Continued) At December 31, 1998 the Company had borrowed $27,454,567 and had $1,163,647 of outstanding letters of credit. As of December 31, 1998, the Company is paying Libor plus 2.00% on a sixty day Libor loan for $25,469,605 and prime on $1,984,962. At December 31, 1998, the amount available under the borrowing base on the $100 million revolver was approximately $3.9 million. Assuming no other changes, the amount available to be borrowed at April 1 will be approximately $3.0 million. The Company expects that the Banks will complete the April 1 borrowing base redetermination by May 1, 1999. The Company also expects that the borrowing base will be less than the amount determined at the October 1, 1998 redetermination, adjusted for the monthly borrowing base reductions. The decline is expected to be caused primarily by normal production declines and lower oil and gas pricing scenarios used by the Banks to value the oil and gas reserves for loan purposes. Pursuant to the terms of the $100 million Revolver, if the borrowing base is less than the outstanding principal balance plus outstanding letters of credit the Company has sixty days, after receipt of notice from the Banks, to cure the excess by prepayment, providing additional collateral or a combination of both. The Company is unable to predict the April 1 borrowing base. While there can be no assurance, at the completion of the April 1 redetermination, the Company does not expect to be required to make any prepayments or provide any additional collateral that would be material to the financial condition of the Company. Amounts spent on debt retirement due to reductions in the borrowing base reduce the cash available to spend on acquisition, development and exploration activities, and accordingly, oil and natural gas revenues and operating results may be adversely affected. The Company paid a facility fee equal to 3/8% of the initial borrowing base and is required to pay 3/8% on any future increase in the borrowing base within five days of written notice. The Company is required to pay a quarterly commitment fee on the unused portion of the borrowing base of 1/2% if the outstanding loan balance plus letters of credit are greater than 50% of the borrowing base or 3/8% if the outstanding loan balance plus letters of credit are less than or equal to 50% of the borrowing base. The Company is required to pay a letter of credit fee on the date of issuance or renewal of each letter of credit equal to the greater of $500 or 1 1/2% of the face amount of the letter of credit. The Company has granted to the Banks liens on substantially all of the Company's oil and natural gas properties, whether currently owned or hereafter acquired, and a negative pledge on all other oil and gas properties. The $100 million Revolver requires, among other things, a cash flow coverage ratio of 1.25 to 1.00 and a current ratio, excluding current maturities of the $100 million Revolver, of 0.9 to 1.00, determined on a quarterly basis. F-17 MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES Notes to Consolidated Financial Statements December 31, 1998 and 1997 (5) LONG-TERM DEBT (Continued) Aggregate amounts of expected required repayments of long term debt at December 31, 1998 are as follows: 1999........................................................... -- 2000........................................................... 3,058,214 2001........................................................... 24,396,353 2002........................................................... -- 2003........................................................... -- Thereafter..................................................... -- ---------- $27,454,567 ---------- ----------
(6) INCOME TAXES Income tax (benefit) expense for the years ended December 31 consisted of the following:
1998 1997 ------------- ------------- Current......................................................... $ -- $ 6,451 Deferred........................................................ (2,829,762) (7,451,249) ------------- ------------- Total......................................................... $ (2,829,762) $ (7,444,798) ------------- ------------- ------------- -------------
The reconciliation of income tax computed at the U.S. federal statutory tax rates to the provision for income taxes is as follows:
1998 1997 ------------- ------------- Income tax benefit at statutory rate............................ $ (3,197,251) $ (7,828,207) Increase in valuation allowance................................. 352,363 -- Increase due to state taxes and other........................... 15,126 383,409 ------------- ------------- Income tax benefit.............................................. $ (2,829,762) $ (7,444,798) ------------- ------------- ------------- -------------
The Company's net deferred tax liability at December 31, 1998 and 1997 is as follows:
1998 1997 ------------- ------------- Deferred tax liability Oil and Gas Properties........................................ $ 4,087,073 $ 5,906,070 ------------- ------------- Deferred tax asset NOL carryforward.............................................. (4,056,660) (1,083,324) AMT tax credit carryforward................................... (36,482) (36,482) Other......................................................... (394,570) (5,736) ------------- ------------- (4,487,712) (1,125,542) ------------- ------------- Valuation allowance............................................. 2,133,806 ------------- ------------- Net deferred tax liability...................................... $ 1,733,167 $ 4,780,528 ------------- ------------- ------------- -------------
F-18 MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES Notes to Consolidated Financial Statements December 31, 1998 and 1997 (6) INCOME TAXES (Continued) In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax asset will not be realized. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based upon projections for future taxable income over the periods which the deferred tax assets are deductible and the Section 382 limitation discussed below, management believes it is more likely than not that the Company will realize the benefits of these deductible differences, net of the existing valuation allowances at December 31, 1998. The valuation allowance increased $2,133,806 during 1998. No valuation allowance was recorded in 1997. In March 1998, the Company acquired Enex which had a net operating loss carryforward of approximately $5,200,000. These net opertaing losses expire in varying amounts through 2012, and their utilization is limited due to an ownership change pursuant to Section 382 triggered by the Company's acquisition of Enex. The 1998 increase in valuation allowance includes amounts attributable to the Enex Acquisition. (7) RETIREMENT PLAN All of the employees of the Company participate in a defined contribution plan that provides for a maximum discretionary Company contribution of 15% of total wages paid to employees for the year. The Company contributed $51,500 to the plan for the year ended December 31, 1997. No contributions were made to the plan for the year ending December 31, 1998. F-19 MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES Notes to Consolidated Financial Statements December 31, 1998 and 1997 (8) STOCK OPTION AND STOCK APPRECIATION RIGHTS PLAN At December 31, 1998, the Company had one fixed stock option plan, the 1995 Stock Option and Stock Appreciation Rights Plan (the "1995 Plan"). The Company applies the intrinsic value method for accounting for stock based compensation in accordance with APB Opinion No. 25, "Accounting for Stock Issued to Employees" and related interpretations; accordingly, no compensation cost has been recognized, as the exercise price of each option equals the market price of the Company's Common Stock on the date of grant. Had compensation cost for the Company's 1995 Plan been determined based on the fair value at the grant date for stock options granted during 1998 and 1997, the Company's net loss and loss per share would have been increased to the pro forma amounts listed below:
1998 1997 ------------- -------------- Net loss...................................... As Reported $ (6,656,952) $ (16,184,052) Pro Forma (7,145,580) (16,463,666) Basic loss.................................... As Reported $ (0.83) $ (4.76) Pro Forma (0.89) (4.85) Diluted loss.................................. As Reported $ (0.83) $ (4.76) Pro Forma (0.89) (4.85)
The weighted average fair value of stock options granted during 1998 and 1997 was $2.97 and $2.77 per share, respectively. The fair value of each option is estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions used for the grants in 1998 and 1997; no dividend yield; expected volatility of 77 percent and 60 percent, respectively; weighted average risk-free interest rate of 4.93% and 6.07%, respectively; and expected life of 3 years. At December 31, 1998, the range of exercise prices and weighted average remaining contractual life of options outstanding was $2.50 to $7.75 and 5.57 years, respectively. At December 31, 1998 there were 633,000 shares of common stock available for grant under the 1995 Plan. All of the options granted under the 1995 Plan have an exercise price equal to the fair market value of the Company's common stock at the date of the grant and expire ten (10) years from the date of grant if not exercised. All of the options granted under the 1995 Plan are 100% vested. The 1995 Plan is administered by the Compensation Committee of the Board of Directors. Information relating to stock options is summarized below:
AVERAGE EXERCISE PRICE SHARES PER SHARE --------- --------------- Options and warrants outstanding at January 1, 1997........................... 125,000 $ 2.50 Granted....................................................................... 520,000 $ 6.07 Exercised..................................................................... (40,833) $ 2.50 --------- Options and warrants outstanding at December 31, 1997......................... 604,167 $ 5.57 Granted....................................................................... 307,000 $ 5.57 --------- Options and warrants outstanding at December 31, 1998......................... 911,167 $ 5.57 --------- --------- Options and warrants exercisable at December 31, 1998......................... 911,167 $ 5.57 --------- ---------
F-20 MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES Notes to Consolidated Financial Statements December 31, 1998 and 1997 (8) STOCK OPTION AND STOCK APPRECIATION RIGHTS PLAN (Continued) Options to acquire 225,000 shares of the Company common stock at an exercise price of $5.50 were granted outside of the 1995 Plan on February 13, 1997 to certain officers of the Company. Warrants to acquire 75,000 shares of the Company common stock at an exercise price of $5.00 were granted outside of the 1995 Plan on September 15, 1998 to a consultant (See Note 9). Both grants are included in the table above. (9) STOCKHOLDERS' EQUITY PREFERRED STOCK-SERIES A On September 4, 1996, the Company signed a stock purchase agreement with Kaiser Francis Oil Company ("Kaiser-Francis"). Kaiser-Francis agreed to purchase 1,666,667 shares of Series A Preferred Stock ("Series A") at $6.00 per share, for a total investment of $10,000,000. The parties agreed to a five-year purchase period, effective September 4, 1996, with minimum incremental investments of $500,000 each. Each issuance of Series A was subject to approval by Kaiser-Francis of the use of proceeds. The Series A was nonvoting and accrued dividends at 8% per annum, payable quarterly in cash. The Series A was convertible at any time after issuance into shares of common stock at the rate of two shares of common stock for each share of Series A before January 1, 1998. The conversion rate decreases for every full year (excluding partial years) thereafter at 8% per annum. As of December 31, 1997, 1,666,667 shares of the Series A had been issued. On January 31, 1998 Kaiser-Francis converted 100% of the Series A into 3,333,334 common shares of the Company. PREFERRED STOCK-SERIES B In connection with the Shore Merger, effective June 30, 1997, the Company issued 266,667 shares of Series B Preferred Stock ("Series B"). The Series B is nonvoting and pays no dividends. The Series B has a liquidation value of $7.50 per share and is junior to the Company's Series A Preferred Stock. Until December 31, 2002, any holder of the Series B may convert all or any portion of Series B shares into Company Common Stock ("Common") at the greater ratio of (i) one share of Common for each share of Series B or (ii) at a ratio based upon the "Alternative Conversion Factor." The Alternative Conversion Factor is determined by dividing the net increase in value of approximately 40,000 net mineral acres owned by the Company in South Louisiana by $8,000,000 and multiplying the product by 1,066,000 to arrive at the potential number of total Common shares all holders would receive upon conversion. In no event shall the aggregate total number of shares of Common into which the Series B are converted be less than 266,667 shares or exceed 1,333,333 shares, unless further increased for any anti-dilution provisions. Upon expiration of the conversion period, unless the Company has given notice to redeem the Series B, all of the shares of the Series B shall be automatically converted. Since the merger date of June 30, 1997 the value of the fee minerals has not increased to a level where the alternative conversion rate is more beneficial than the initial conversion rate of one to one. As of December 31, 1998, no additional shares of Series B have been issued. PREFERRED STOCK-SERIES C In connection with the Enex Partnership Merger, on December 29, 1998, the Company issued 2,177,481 shares of Series C Preferred Stock ("Series C") in exchange for 100% of the Enex Partnership units. The holders of Series C are entitled to receive cumulative cash dividends in an amount per share of $0.50 per year (10% annual rate), payable semi-annually on March 31 and September 30 of each year. F-21 MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES Notes to Consolidated Financial Statements December 31, 1998 and 1997 PREFERRED STOCK-SERIES C (CONTINUED) These dividends are payable in preference to and prior to the payment of any dividend or distribution to any holder of Company common stock or other junior security. The Series C dividends begin to accrue on December 30, 1998. Compass Bank has granted the Company a waiver allowing the Company to pay the dividends on the Series C as long as no default or event of default exists or would exist as a result of any Series C dividend payment. The Series C has a liquidation preference of $5.00 per share plus an amount equal to all accumulated, accrued and unpaid dividends. The liquidation preference of Series C ranks on parity with the Series B. Each share of Series C is convertible into one share of Company common stock. On or after January 1, 2000, the Company may redeem all or a portion of the Series C, at its option, at a purchase price of $5.00 per share, plus an amount equal to all accumulated, accrued and unpaid dividends. The Series C is generally nonvoting; however, holders of Series C are entitled to vote on any amendment, alteration or appeal of any provision of the Company's Articles of Incorporation which would adversely affect any holder's rights and preferences. As a result of its limited partnership interest in the Enex Partnership, Enex owns 1,293,522 shares of the Series C of which the Company owns 80%, or 1,034,818 shares through its 80% ownership of Enex. COMMON STOCK On February 13, 1997, the Company awarded to the President, Vice-President Chief Financial Officer and Vice-President Engineering, 25,909, 11,591 and 11,591 shares of restricted stock of the Company, respectively. The restricted stock awards were contingent on the performance of services to the Company in the future with 50% of the restricted shares being earned over the six month period July 1, 1997 to December 31, 1997 and 50% over the six month period January 1, 1998 to June 30, 1998. As of December 31, 1998, all restricted shares were earned. WARRANTS On September 15, 1998 the Company entered into a consulting agreement with Edward K. Andrew ("Andrew") for a term of five years beginning January 1, 1999. As compensation, the Company granted to Andrew a warrant to purchase 75,000 shares of Company common stock at a price of $5.00. The warrants vested over the period September 15, 1998 to January 1, 1999. The estimated fair value of the warrants of $198,946 was determined at the date of grant and charged to stock compensation expense over the vesting period. F-22 MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES Notes to Consolidated Financial Statements December 31, 1998 and 1997 (9) STOCKHOLDERS' EQUITY (Continued) EARNINGS PER SHARE The following table provides a reconciliation between basic and diluted earnings (loss) per share:
WEIGHT AVERAGE COMMON SHARES PER SHARE NET LOSS OUTSTANDING AMOUNT -------------- --------------- ----------- Year Ended December 31, 1998: Basic earnings per share........................................... $ (6,656,952) 8,050,108 $ (0.83) Effect of dilutive stock options................................... -- -- -- Diluted earnings per share......................................... $ (6,656,952) 8,050,108 $ (0.83) Year Ended December 31, 1997: Basic earnings per share........................................... $ (16,184,052) 3,397,117 $ (4.76) Effect of dilutive stock options................................... -- -- -- Diluted earnings per share......................................... $ (16,184,052) 3,397,117 $ (4.76)
At December 31, 1998 and 1997, the Company had a weighted average of 849,890 and 542,249, combined stock options and warrants outstanding, respectively, which were not included in the computation of diluted earnings per share, because the effect of the assumed exercise of these stock options would have an antidilutive effect on the computation of diluted loss per share. At December 31, 1998 and 1997, the Company had shares of convertible preferred stock outstanding that were convertible into 1,409,330 and 3,600,001 shares of common stock, respectively, and dividends of $67,945 and $604,712, respectively, which were not included in the computation of diluted earnings per share, because the effect of the assumed conversion of these preferred shares would have an antidilutive effect on the computation of diluted loss per share. (10) COMMITMENTS AND CONTINGENCIES The Company is obligated under the terms of certain operating leases for office space that expire over the next two and one-half years. Total rent expense was $268,477 and $97,588 for the years ended December 31, 1998 and 1997, respectively. Future minimum rental payments under the Company's leases total $119,366, $75,720, and $34,860 for 1999, 2000, and 2001, respectively. As of December 31, 1998, the Company had $1,163,647 of irrevocable standby letters of credit outstanding. The Company is a defendant in various legal proceedings which are considered routine litigation incidental to the Company's business, the disposition of which management believes will not have a material effect on the financial position or results of operations of the Company. F-23 MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES Notes to Consolidated Financial Statements December 31, 1998 and 1997 (11) SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) CAPITALIZED COSTS AND COSTS INCURRED The following tables present the capitalized costs related to oil and gas producing activities and the related depreciation, depletion, amortization and impairment and costs incurred in oil and gas property acquisition, exploration and development activities (in thousands).
1998 1997 ---------- ---------- CAPITALIZED COSTS Proved properties......................................................................... $ 84,325 $ 56,536 Nonproducing leasehold.................................................................... 6,524 6,118 Accumulated depreciation, depletion, amortization and impairment.......................... (38,810) (30,456) ---------- ---------- Net capitalized costs................................................................... $ 52,039 $ 32,198 ---------- ---------- ---------- ---------- COSTS INCURRED Proved properties......................................................................... $ 28,878 $ 38,099 Unproved properties....................................................................... 337 6,195 Exploration costs......................................................................... 1,802 1,912 Development costs......................................................................... 3,041 1,862 ---------- ---------- Total................................................................................... $ 34,058 $ 48,068 ---------- ---------- ---------- ---------- Depletion, depreciation, amortization and impairment...................................... $ 11,013 $ 25,651 ---------- ---------- ---------- ----------
ESTIMATED QUANTITIES OF RESERVES The Company has interests in oil and gas properties that are located principally in Alabama, Louisiana, Kansas, Oklahoma and Texas. The Company does not own or lease any oil and gas properties outside the United States. There are no quantities of oil and gas subject to long-term supply or similar agreements with any governmental agencies. The Company retains independent engineering firms to provide year-end estimates of the Company's future net recoverable oil, gas and natural gas liquids reserves. In 1998, such estimates were prepared by Lee Keeling and Associates, Inc. and H.J. Gruy & Associates, Inc. In 1997, such estimates were prepared by Lee Keeling and Associates, Inc., Cawley, Gillespie and Associates, Inc., Ryder Scott Company, Huddleston & Company, Inc., and DeGoyler & MacNaughton. The reserve information was prepared in accordance with guidelines established by the Securities and Exchange Commission. Estimated proved net recoverable reserves as shown below include only those quantities that can be expected to be commercially recoverable at prices and costs in effect at the balance sheet dates under existing regulatory practices and with conventional equipment and operating methods. Proved developed reserves represent only those reserves expected to be recovered through existing wells. Proved undeveloped reserves include those reserves expected to be recovered from new wells or on undrilled acreage or from existing wells on which a relatively major expenditure is required for recompletion. F-24 MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES Notes to Consolidated Financial Statements December 31, 1998 and 1997 (11) SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (Continued) Net quantities of proved developed and undeveloped reserves of natural gas and crude oil, including condensate and natural gas liquids, are summarized as follows:
YEARS ENDED DECEMBER 31 -------------------------------------------------- 1998 1997 ------------------------ ------------------------ OIL OIL PROVED RESERVES (BARRELS) GAS (MCF) (BARRELS) GAS (MCF) - ------------------------------------------------------------ ---------- ------------ ---------- ------------ Beginning of year........................................... 2,933,000 18,419,000 1,389,945 8,964,238 Revisions of previous estimates............................. (277,291) (82,742) (205,733) (1,431,708) Extensions and discoveries.................................. 103,506 290,347 22,520 705,020 Purchases of reserves in place.............................. 1,254,663 30,997,247 1,980,117 12,110,748 Sale of reserves in place................................... (90,373) (2,294,193) -- -- Production for the year..................................... (581,457) (3,846,679) (253,849) (1,929,298) ---------- ------------ ---------- ------------ End of year................................................. 3,342,048 43,482,980 2,933,000 18,419,000 ---------- ------------ ---------- ------------ ---------- ------------ ---------- ------------ PROVED DEVELOPED RESERVES - ------------------------------------------------------------ Beginning of year........................................... 2,580,000 14,251,000 1,266,421 8,142,820 End of year................................................. 3,117,839 36,731,365 2,580,000 14,251,000
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED RESERVES The following is a summary of the standardized measure of discounted future net cash flows related to the Company's proved oil and gas reserves. For these calculations, estimated future cash flows from estimated future production of proved reserves are computed using oil and gas prices as of the end of each period presented. Future development and production costs attributable to the proved reserves were estimated assuming that existing conditions would continue over the economic lives of the individual leases and costs were not escalated for the future. Estimated future income taxes were calculated by applying statutory tax rates (based on current law adjusted for permanent differences and tax credits) to the estimated future pre-tax net cash flows related to proved oil and gas reserves, less the tax basis of the properties involved. The Company cautions against using this data to determine the value of its oil and gas properties. To obtain the best estimate of the fair value of the oil and gas properties, forecasts of future economic conditions, varying discount rates, and consideration of other than proved reserves would have to be incorporated into the calculation. In addition, there are significant uncertainties inherent in estimating quantities of proved reserves and in projecting rates of production that impair the usefulness of the data. F-25 MIDDLE BAY OIL COMPANY, INC. AND SUBSIDIARIES Notes to Consolidated Financial Statements December 31, 1998 and 1997 (11) SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (Continued) The standardized measure of discounted future net cash flows relating to proved oil and gas reserves are summarized as follows (in thousands):
YEARS ENDED DECEMBER 31 ---------------------- 1998 1997 ---------- ---------- Future cash inflows................................................................. $ 133,549 $ 101,482 Future production costs and development costs....................................... (62,085) (54,358) Future income tax expenses.......................................................... -- (11,853) ---------- ---------- Future net cash flows............................................................... 71,464 35,271 10% discount to reflect timing of cash flows........................................ (32,570) (10,778) ---------- ---------- Standardized measure of discounted future net cash flows............................ $ 38,894 $ 24,493 ---------- ---------- ---------- ----------
The following are the principal sources of changes in the standardized measure of discounted future net cash flows (in thousands):
YEARS ENDED DECEMBER 31 --------------------- 1998 1997 --------- ---------- Sales of oil and gas, net of production cost............................................ $ (7,210) $ (6,364) Net changes in price and production cost................................................ (5,459) (11,108) Extensions and discoveries.............................................................. 732 851 Purchase of reserves.................................................................... 23,092 20,293 Sale of reserves........................................................................ (1,528) -- Revisions of previous quantity estimates................................................ (1,573) 1,794 Net change in income taxes.............................................................. 2,712 (1,082) Accretion of discount................................................................... 3,635 2,246 Changes in production rates (timing) and other.......................................... -- -- --------- ---------- End of year............................................................................. $ 14,401 $ 6,630 --------- ---------- --------- ----------
During recent years, there have been significant fluctuations in the prices paid for crude oil in the world markets. The situation has had a destabilizing effect on the crude oil posted prices in the United States, including the posted prices paid by purchasers of the Company's crude oil. The year end prices of oil and gas at December 31, 1998 and 1997, used in the above table were $9.50 and $16.18 per barrel of oil and $2.10 and $2.54 per thousand cubic feet of gas, respectively. F-26 PART III ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS; COMPLIANCE WITH SECTION 16(A) OF THE EXCHANGE ACT (a) EXECUTIVE OFFICERS AND DIRECTORS The following table sets forth the executive officers and directors of Middle Bay as of December 31, 1998. All directors serve for a one-year term or until the next Annual Meeting of Shareholders of the Company. The Board of Directors held four meetings during the fiscal year ended December 31, 1998. Each director attended all meetings of the Board. Executive officers serve at the pleasure of the Board of Directors.
DIRECTOR NAME AGE POSITION(S) HELD SINCE - ---------------------------------------- --- ---------------------------------------------- ----------- John J. Bassett 40 Chairman, President and Chief Executive 1992 Officer C. J. Lett, III 41 Executive Vice President 1997 Frank C. Turner, II(1)(2) 38 Vice President and Chief Financial Officer N/A Stephen W. Herod(2) 39 Vice President 1997 Robert W. Hammons 45 Vice President N/A Lynn M. Davis 50 Secretary and Treasurer N/A Edward P. Turner, Jr.(1) 69 Director 1989 Frank E. Bolling, Jr. 39 Director 1992 Alvin V. Shoemaker(3) 60 Director 1997 Gary R. Christopher 49 Director 1997
- ------------------------ (1) Edward P. Turner, Jr. and Frank C. Turner, II, are father and son. (2) Mr. Herod replaced Frank C. Turner, II effective July 3, 1997. (3) Mr. Shoemaker replaced C. Noell Rather effective July 28, 1997. JOHN J. BASSETT has served as President, Chief Executive Officer and a director of the Company since 1992 and was elected Chairman of the Board of Directors in 1992. He served as President of the general partner of the Predecessor Partnership from 1987 to 1992. Mr. Bassett was a director and President of Bay City Energy Group, Inc., a principal shareholder of the Company, from 1987 to 1998. STEPHEN W. HEROD has served as Vice President--Corporate Development and a director of the Company since July 1, 1997. Mr. Herod served as President and a director of Shore Oil Company from April 1992 until the merger of Shore and the Company on June 30, 1997. He joined Shore's predecessor as Controller in February 1991. In addition, Mr. Herod was employed by Conquest Exploration Company from 1984 until 1991 in various financial management positions, including Operations Accounting Manager. From 1981 to 1984, Superior Oil Company employed Mr. Herod as a financial analyst. FRANK C. TURNER, II has served as Vice President and Chief Financial Officer for the Company since its organization as a corporation in 1992. He had previously served as Vice President of Finance for the general partner of the Predecessor Partnership since 1990. From 1987 to 1990, Mr. Turner was employed by Sonat, Inc. as a financial analyst. He also serves as a director and Vice President of Bay City Energy Group, Inc. ROBERT W. HAMMONS was hired by the Company in April, 1992 as a reservoir engineer. Mr. Hammons was appointed Vice President of Engineering of Middle Bay in 1993. Prior to his employment with the III-1 Company, he had worked with Bay City Minerals, Inc. as an independent petroleum engineering consultant since 1987. Prior to 1987, Mr. Hammons was employed as manager of reservoir engineering for Marion Corporation. LYNN M. DAVIS has been Secretary and Treasurer for Middle Bay since 1992. She served as Secretary-Treasurer of the general partner of the Predecessor Partnership from 1984 to 1992 and was a director from 1988 to 1992. Ms. Davis also serves as a director and Secretary-Treasurer for Bay City Energy Group, Inc. EDWARD P. TURNER, JR. served as President of Bay City Minerals, Inc. from 1975 to 1987. He is a member of the Alabama State Bar and a managing partner of the law firm of Turner, Onderdonk, Kimbrough & Howell, P.A., in Chatom, Alabama. A substantial amount of his practice is devoted to oil and gas law. Mr. Turner also serves as a director of Bay City Energy Group, Inc. FRANK E. BOLLING, JR. has been employed by Midstream Fuel Services, Inc. as Vice President of Retail Operations since February, 1995. Prior to his employment with Midstream, Mr. Bolling served as Vice President and General Manager of Dantzler Bulk Plant, Inc., a distributor for Chevron U.S.A., Inc. with annual sales in excess of $25 million. Mr. Bolling served as sales manager for Dantzler from 1987 to 1989. Prior to 1987, Mr. Bolling was employed by Bay City Minerals, Inc. ALVIN V. SHOEMAKER is a former Chairman of the Board of First Boston Corporation and former President of Blyth Eastman Paine Webber. He has also worked for the U.S. Treasury. He has been Chairman of the Board of Trustees of the University of Pennsylvania, Vice Chairman of the Securities Industry Association and a director of Harcourt Brace Jovanovich, Royal Insurance of America, Hanover Compressor Company, the Council on Foreign Relations and the Wharton School of Finance Board. GARY R. CHRISTOPHER is Acquisitions Coordinator of Kaiser-Francis Oil Company, a position he has held since February 1996. From 1991 to 1996, Mr. Christopher served as Senior Vice President and Manager of Energy Lending for the Bank of Oklahoma. He continues to serve as a consultant to the Bank of Oklahoma. Kaiser-Francis Oil Company owns 3,333,334 shares of the Company's common stock. C. J. LETT, III has served as Executive Vice President and a director for Middle Bay since the merger of the Company and Bison Energy Corporation on February 28, 1997. Mr. Lett was President and a director of Bison Energy Corporation from 1981 to 1997. (b) COMPLIANCE WITH SECTION 16(A) OF THE EXCHANGE ACT Section 16(a) of the Securities Exchange Act of 1934 requires the Company's directors and executive officers and any persons who own more than 10% of Middle Bay's common stock to file with the Securities and Exchange Commission reports of ownership and changes in ownership of such securities. Based on representations from such persons, the Company believes that there was no failure to file or delinquent filings under Section 16(a) of the Securities Exchange Act of 1934 by any officer, director or beneficial owner of 10% or more of Middle Bay's common stock during 1998. (c) AUDIT AND COMPENSATION COMMITTEES The members of the Audit Committee are Gary R. Christopher, Frank E. Bolling, Jr. and Alvin V. Shoemaker. The functions of the Audit Committee include recommending to the Board of Directors the independent auditors; reviewing and approving the planned scope of the annual audit; proposing fee arrangements; reviewing the results of the annual audit; reviewing the adequacy of the accounting and financial controls; reviewing the independence of the independent auditors; approving all assignments to be performed by the independent auditors; and instructing the independent auditors, as deemed appropriate, to undertake special assignments. During 1998, the Audit Committee met one time. Each member attended the committee meeting. The members of the Compensation Committee are John J. Bassett, Edward P. Turner, Jr. and Frank E. Bolling, Jr. The functions of the Compensation Committee are to approve or recommend for approval to the Board of Directors, the compensation and remuneration arrangements for directors and III-2 senior management. During 1998, the Compensation Committee met two times. Each member attended all meetings of the committee. ITEM 10. EXECUTIVE COMPENSATION (a) SUMMARY COMPENSATION TABLE The following table sets forth the aggregate cash compensation earned by and paid to the Company's executive officers for the periods ended December 31, 1996 through December 31, 1998:
LONG-TERM COMPENSATION -------------------------- AWARDS ANNUAL COMPENSATION ----------- - --------------------------------------------------------------------------------------------------- SECURITIES PAYOUTS RESTR. UNDERLYING ------------- OTHER ANNUAL STOCK OPTIONS/ LTIP NAME AND PRINCIPAL POSITION YEAR SALARY($) BONUS($) COMPENSATION AWARDS($) SARS(#) PAYOUTS($) - ------------------------------ --------- ----------- ----------- ----------------- ----------- ----------- ------------- John J. Bassett 1998 111,667 37,121 -- -- 35,000 -- President & 1997 95,521 6,001 -- 129,545 132,000 -- Chief Executive Officer 1996 58,075 -- -- -- 20,000 -- Steve W. Herod 1998 100,000 24,375 -- -- 35,000 -- Vice President-- 1997 50,000 -- -- -- -- -- Corp. Development 1996 -- -- -- -- -- -- Robert W. Hammons 1998 91,250 25,625 -- -- 22,000 -- Vice President-- 1997 85,729 6,000 -- 57,960 94,500 -- Engineering 1996 58,075 -- -- -- 20,000 -- Frank C. Turner, II 1998 89,167 25,521 -- -- 22,000 -- Vice President & 1997 85,729 6,000 -- 57,960 94,500 -- CFO 1996 54,458 -- -- -- 20,000 -- - ------------------------------ ALL OTHER NAME AND PRINCIPAL POSITION COMPENSATION($) - ------------------------------ ----------------- John J. Bassett -- President & 13,032 Chief Executive Officer 2,271 Steve W. Herod -- Vice President-- -- Corp. Development -- Robert W. Hammons -- Vice President-- 12,500 Engineering 2,271 Frank C. Turner, II Vice President & 16,250 CFO 2,174
(b) OPTION GRANTS IN LAST FISCAL YEAR The 1995 Stock Option and Stock Appreciation Rights Plan (the "Plan") is administered by the Compensation Committee (the "Committee") of the Board of Directors. At least two members of the Committee must be disinterested nonemployee directors. The Committee is authorized to determine the employees, including officers, to whom options or rights are granted. Each option or right granted shall be on such terms and conditions consistent with the Plan as the Committee may determine, but the duration of any option or right shall be not greater than ten years or less than five years from the date of grant. Options or rights grants shall be made under the Plan only to persons who are officers or salaried employees of Middle Bay or are nonemployee directors. The aggregate number of shares of common stock of the Company, which could be subject to options or rights under the Plan during 1998, was 1,500,000. During the fiscal year ended December 31, 1998, options covering 232,000 shares were issued under the Plan. As of December 31, 1998, options for a total of 836,167 shares had been granted and were outstanding; 611,167 under the Plan and 225,000 outside of the Plan. In February 1999, options for a total of 200,000 shares were issued under the Plan. The option price of shares covered by options granted under the Plan may not be less than the fair market value at the time the option is granted. The option price must be paid in full in cash or cash equivalent at the time of purchase or prior to delivery of the shares in accordance with cash payment arrangements acceptable to the Committee. If the Committee so determines, the option price may also be paid in shares of the Company's common stock already owned by the optionee. The Committee has discretion to determine the time or times when options become exercisable, within the limits set forth in the Plan. All options and rights granted under the Plan will, however, become fully exercisable if there is a change in control (as defined in the Plan) of the Company. III-3 The following table provides certain information with respect to all options granted during the fiscal year ended December 31, 1998 to any executive officer or director of Middle Bay; 232,000 options were granted under the Plan and none were granted outside of the Plan: INDIVIDUAL GRANTS
NUMBER OF SECURITIES UNDERLYING % OF TOTAL OPTIONS/ OPTIONS/SARS SARS GRANTED IN EXERCISE OR BASE EXPIRATION NAME GRANTED(#) FISCAL YEAR PRICE($/SH) DATE - ------------------------------------------------------- ----------- ------------- ------------------- ----------- John J. Bassett........................................ 35,000 15.1% 5.75 1/13/2008 Steve W. Herod......................................... 35,000 15.1% 5.75 1/13/2008 Frank C. Turner, II.................................... 22,000 9.5% 5.75 1/13/2008 Robert W. Hammons...................................... 22,000 9.5% 5.75 1/13/2008 C. J. Lett, III........................................ 22,000 9.5% 5.75 1/13/2008 Edward P. Turner, Jr.*................................. 10,000 4.3% 5.75 1/13/2008 Frank E. Bolling, Jr.*................................. 10,000 4.3% 5.75 1/13/2008 Alvin V. Shoemaker*.................................... 10,000 4.3% 5.75 1/13/2008 Gary R. Christopher*................................... 10,000 4.3% 5.75 1/13/2008
- ------------------------ * Nonemployee director (c) AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR AND OPTION VALUE TABLE AS OF DECEMBER 31, 1998 The following table sets forth certain information concerning each exercise of stock options during the year ended December 31, 1998, by each of the named executive officers and directors and the aggregated fiscal year-end value of the unexercised options of each such named executive officer and director: INDIVIDUAL GRANTS
NUMBER OF SECURITIES UNDERLYING VALUE OF UNEXERCISED UNEXERCISED IN-THE-MONEY OPTIONS/SARS AT FY OPTIONS/ SARS AT FY END(#) END($) SHARES ACQUIRED VALUE -------------------- -------------------- NAME ON EXERCISE(#) REALIZED($) EXER. UNEXER. EXER. UNEXER. - ------------------------------- ----------------- --------------- --------- --------- --------- --------- John J. Bassett................ -- -- -- 187,000 -- 5,000 Frank C. Turner, II............ -- -- 20,000 116,500 5,000 -- Robert W. Hammons.............. -- -- -- 136,500 -- 5,000 C. J. Lett, III................ -- -- -- 37,000 -- -- Steve W. Herod................. -- -- -- 35,000 -- -- Edward P. Turner, Jr.*......... -- -- -- 44,734 -- 5,000 Frank E. Bolling, Jr.*......... -- -- -- 44,533 -- 5,000 Alvin V. Shoemaker*............ -- -- -- 10,000 -- -- Gary R. Christopher*........... -- -- -- 10,000 -- --
- ------------------------ * Nonemployee director (d) OTHER COMPENSATION UNDER PLANS Middle Bay established a SEP/IRA retirement plan (the "SEP Plan") in 1993 which allows for a maximum discretionary Company contribution of 15% of total wages paid to employees for the year. For the years ended December 31, 1998, 1997 and 1996, Middle Bay contributed a total of $0, $51,500 and $5,000 to the SEP Plan, respectively, including $0, $32,064 and $3,068, respectively, for all executive officers as a group. III-4 Middle Bay established a 401-K Plan in October 1997, which allows for voluntary contributions by the employees and the employer. No Company contributions were made in 1997 or 1998. The Company has no other retirement, pension/profit sharing or other deferred compensation plan for its employees. (e) LONG-TERM INCENTIVE PLAN ("LTIP") AWARDS TABLE In March 1995, the Board of Directors adopted an employee incentive compensation plan whereby the proceeds equivalent to a 1% net profits interest (as defined) in all oil and gas properties, drilling prospects and divestitures acquired or made after January 1, 1994 are paid into a fund for incentive compensation awards to employees. For the year ended December 31, 1996, the Company paid $6,916 to employees through the employee incentive plan, including $4,897 for all executive officers as a group. No amount was paid into the plan in 1997 or 1998. (f) DIRECTORS' FEES Directors of Middle Bay receive a fee of $500 per meeting and are reimbursed for documented travel expenses. Certain nonemployee directors have received stock options for their services as directors (see "Option Grants in Last Fiscal Year," above). (g) EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT AND CHANGE-IN-CONTROL ARRANGEMENTS Mr. Bassett and Mr. Hammons in January 1997, signed employment agreements with the Company which extend through January 31, 2002 and January 31, 2000, respectively, with automatic one-year extensions upon each anniversary date of the employment agreement thereafter unless either party gives at least 30 days' notice of termination. Each employment agreement is terminable by Middle Bay before expiration of the term if such termination is for cause (as specified in the employment agreement). The executive employment agreements provide for an annual salary of not less than the base salaries of $95,000 and $85,000, respectively, which amounts may be adjusted from time to time by the Board of Directors upon the recommendation of the Compensation Committee. They also provide for fringe benefits in accordance with the Company's policies adopted from time to time for salaried executive employees holding comparable positions. Mr. Herod executed an employment agreement with the Company with an effective date of July 1, 1997 and extending through June 30, 1999, with automatic one-year extensions upon each anniversary date of the employment agreement thereafter unless either party gives at least 30 days' notice of termination. The employment agreement is terminable by Middle Bay before expiration of the term if such termination is for cause (as specified in the employment agreement). The executive employment agreement provides for an annual salary of not less than the base salary of $100,000, which amount may be adjusted from time to time by the Board of Directors upon the recommendation of the Compensation Committee. It also provides for fringe benefits in accordance with the Company's policies adopted from time to time for salaried executive employees holding comparable positions. III-5 ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT (a) SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS The following table sets forth the shares of Middle Bay's common and preferred stock beneficially owned by those persons known by the Company to be the beneficial owner of more than five percent of Middle Bay's issued and outstanding common and preferred stock as of December 31, 1998:
TITLE OF AMOUNT AND NATURE OF PERCENT OF CLASS(6) NAME AND ADDRESS OF BENEFICIAL OWNER BENEFICIAL OWNERSHIP CLASS - ----------- ---------------------------------------- -------------------- ----------- Common Kaiser-Francis Oil Company(1)(2) 3,333,334 39.1% 6733 South Yale Tulsa, OK 74136 Common C. J. Lett, III(1) 1,187,556 13.9% 9320 East Central Wichita, KS 67206 Common Weskids, L.P.(3) 843,687 9.9% 310 South Street Morristown, NJ 07960 Common Weskids, Inc. 843,687 9.9% 310 South Street Morristown, NJ 07960 Common Alvin V. Shoemaker(1)(4) 682,222 8.0% 8800 First Avenue Stone Harbor, NJ 08247 Common SerDrilco, Inc.(1)(5) 666,000 7.8% 15 West 6th Street, Suite 1800 Tulsa, OK 74192 Preferred Weskids, L.P.(3) 117,467 44.1% Series B 310 South Street Morristown, NJ 07960 Preferred Weskids, Inc. 117,467 44.1% Series B 310 South Street Morristown, NJ 07960 Preferred Alvin V. Shoemaker(1)(4) 117,466 44.1% Series B 8800 First Avenue Stone Harbor, NJ 08247 Preferred Stephen W. Herod(1) 15,867 5.9% Series B 1110 Briar Ridge Drive Houston, TX 77057 Preferred W. Tim Sexton(1) 15,867 5.9% Series B 12010 Winwood Houston, TX 77024
- ------------------------ (1) The nature of the beneficial ownership is sole voting and investment. (2) George B. Kaiser is the majority shareholder of Kaiser-Francis Oil Company. (3) Weskids, L.P. is presently the beneficial owner and has sole voting and disposition power of 843,687 shares of common stock and 117,467 shares of Series B preferred stock. Weskids, Inc. is the general partner of Weskids, L.P. and effectively controls Weskids, L.P. The officers and directors of Weskids, III-6 Inc. are as follows: J. Peter Simon, director; Michael B. Lenard, President; Mark J. Butler, Vice President/Treasurer; and Christine W. Jenkins, Secretary. (4) Alvin V. Shoemaker individually owns 313,421 shares of common stock and 117,466 shares of Series B preferred stock. In addition, 361,800 shares of common stock are held by the Shoemaker 1998 Descendants Trust and Mr. Shoemaker disclaims beneficial ownership of these shares. An additional 7,000 common shares are held by affiliated family partnerships that Mr. Shoemaker controls. (5) SerDrilco, Inc. is the parent company of Service Drilling Co., LLC. Sherman E. Smith is the majority shareholder of SerDrilco, Inc. (6) Series B preferred stock is convertible into common stock at a variable ratio of not less than one-to-one as determined by the terms of the June 20, 1997 merger agreement between Middle Bay and Shore Oil Company. III-7 (b) SECURITY OWNERSHIP OF MANAGEMENT The following table sets forth the shares of the Company's common stock beneficially owned by each director and executive officer and all directors and executive officers as a group, all as of March 1, 1999:
CONV. AMOUNT AND NATURE OF PREFERRED & NAME AND ADDRESS OF BENEFICIAL PERCENT OF OPTIONS STOCK BENEFICIAL OWNER OWNERSHIP(6) CLASS - -------------- ---------- ------------------------------ ---------------------- ----------- 222,000 25,211 John J. Bassett 247,211 2.5% 4326 Noble Oak Trail Houston, TX 77059 136,500 14,296 Frank C. Turner, II 150,796 1.5% 1406 Tallow Court Seabrook, TX 77586 156,500 6,996 Robert W. Hammons 163,496 1.7% 915 Kentbury Court Katy, TX 77450 13,500 -- Lynn M. Davis 13,500 -- 121 Donna Circle Daphne, AL 36526 49,734 376,241 Edward P. Turner, Jr.(1) 425,975 4.3% 100 Central Avenue Chatom, AL 36518 47,000 1,187,556 C. J. Lett, III(2) 1,234,556 12.6% 9320 East Central Wichita, KS 67206 49,533 -- Frank E. Bolling, Jr. 49,533 0.5% 3830 Kendale Drive Gautier, MS 39553 15,000 13,000 Gary R Christopher(3) 28,000 0.3% 6733 South Yale Tulsa, OK 74136 132,466 684,222 Alvin V. Shoemaker(4) 816,688 8.3% 8800 First Avenue Stone Harbor, NJ 08247 70,867 109,816 Stephen W. Herod(5) 180,683 1.8% 1110 Briar Ridge Drive Houston, TX 77057 All executive officers and 3,310,438 33.7% directors as a group (10 persons)
- ------------------------ (1) Includes 362,803 shares owned by Bay City Energy Group, Inc. in which Mr. Turner has indirect voting control but not a direct beneficial interest, and 13,438 shares over which Mr. Turner has sole voting and dispositive power. (2) Mr. Lett was named Executive Vice President and a director of the Company on February 28, 1997 in connection with the Bison Merger. (3) Mr. Christopher is an officer of Kaiser-Francis Oil Company, which is the beneficial owner of 3,333,334 of the Company's common shares. III-8 (4) Mr. Shoemaker was named a director of Middle Bay in July 1997 in connection with the Shore Oil Company merger. Consists of 117,466 shares of Series B preferred stock convertible into 117,466 common shares of the Company. (5) Mr. Herod was named Vice President--Corporate Development and a director of Middle Bay in July 1997 in connection with the Shore Oil Company merger. Consists of 15,867 shares of Series B preferred stock convertible into 15,867 common shares of the Company. (6) The nature of beneficial ownership for all shares is sole voting and investment power. (c) CHANGES IN CONTROL There are no arrangements known to management, which may result in a change in control of the Company. ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Edward P. Turner, Jr., a director of Middle Bay, is managing partner of the law firm of Turner, Onderdonk, Kimbrough & Howell, P.A., the Company's counsel for certain corporate and oil and gas matters. For the years ended December 31, 1996 through 1998, Middle Bay paid legal fees to Mr. Turner's firm of $1,560, $2,874 and $915, respectively, for legal services. Mr. Turner's firm charges the Company for its services on the same basis as it charges other business clients for similar services rendered. Middle Bay intends to continue to use Mr. Turner's firm as its primary local counsel in Alabama and will pay reasonable fees for such future services. Bay City Energy Group, Inc. is presently indebted to Middle Bay in the amount of $173,115 ($139,005 of principal and $34,110 of accrued interest). The note payable was renegotiated on December 31, 1995 and is due in full on January 1, 2001, plus interest at an annual fixed rate of 5%. The note payable is secured by 75,000 shares of the Company's common stock. Edward P. Turner, Jr., a director of Middle Bay, has indirect voting control but not a beneficial interest in Bay City Energy Group, Inc. On December 31, 1996, NPC Energy Corp., then a company indirectly controlled by C. J. Lett, III through Bison Energy Corporation ("Bison"), merged with the Company in exchange for 562,000 shares of common stock of Middle Bay and $1,226,400 cash. Subsequently, in February 1997, the Company acquired Bison as a wholly-owned subsidiary pursuant to an Agreement and Plan of Merger whereby Mr. Lett received net cash consideration of $5.9 million plus 1,167,556 shares of Middle Bay's common stock, and the 562,000 shares held by Bison (as a result of the NPC Merger) were canceled. The Company rents office space for its division office in Wichita, KS from Mr. Lett at the rate of $3,000 per month through February 2000. The Company loaned Frank C. Turner, II, Vice President and Chief Financial Officer, $14,400 in September 1998 to pay income taxes associated with the exercise of incentive stock options. Gary R. Christopher, a director of Middle Bay, is employed by Kaiser-Francis Oil Company, which directly owns 3,333,334 common shares or 39.1% of the Company. [The remainder of this page has been intentionally left blank.] III-9 PART IV I. ITEM 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 N/A Corporation, and C.J. Lett(6) 2.2 Agreement and Plan of Merger dated June 20, 1997 among the Company, Shore Oil Company, N/A and its Shareholders(5) 3.1 Articles of Incorporation(1) N/A 3.2 Articles of Amendment to Articles of Incorporation reflecting reverse split(2) N/A 3.3 Articles of Amendment to Articles of Incorporation designating preferences and rights of N/A Series A Preferred Stock(4) 3.4 Articles of Amendment to Articles of Incorporation designating preferences and rights of N/A Series B Preferred Stock(5) 3.5 Articles of Amendment to Articles of Incorporation increasing authorized capital stock(7) N/A 3.6 Articles of Amendment to Articles of Incorporation increasing authorized capital stock(8) N/A 3.7 Articles of Amendment to Articles of Incorporation designating preferences and rights of N/A Series C Preferred Stock(9) 3.8 Bylaws(1) N/A 10.1 Executive Employment Agreement for John J. Bassett dated January 30, 1997(14) N/A 10.2 Executive Employment Agreement for Robert W. Hammons dated January 30, 1997(14) N/A 10.3 Executive Employment Agreement for Steve W. Herod dated July 1, 1997(14) N/A 10.4 1995 Stock Option and Stock Appreciation Rights Plan(3) N/A 10.5 Amended and Restated 1995 Stock Option and Stock Appreciation Rights Plan(7) N/A 10.6 Amendment No. 1 to Amended and Restated 1995 Stock Option and Stock Appreciation Rights N/A Plan(8) 10.7 Credit Agreement between the Company and Enex Resources Corporation, as borrower, and N/A Compass Bank, as agent and lender, Bank of Oklahoma, N.A., as a lender, and the other lenders signatory thereto, dated March 27, 1998(10) 10.8 Asset Purchase Agreement among the Company, Service Drilling Co., L.L.C. and Diamond S N/A Gas Systems, L.L.C. dated April 16, 1998(11) 10.9 Consulting Agreement between Gerald B. Eckley and the Company dated April 15, 1998(12) N/A 16.1 Letter from Schultz, Watkins & Company regarding change in certifying public accountants N/A dates October 9, 1998(13) 21.1 Subsidiaries of the Company N/A 23.3 Consent of Deloitte & Touche, L.L.P., independent accountants(9) N/A
IV-1 (a) REPORTS ON FORM 8-K None. - ------------------------ (1) Incorporated by reference to Exhibits to Registration Statement on Form S-4 filed October 4, 1993. (2) Incorporated by reference to Exhibits to definitive Proxy Statement filed February 15, 1995. (3) Incorporated by reference to Exhibits to definitive Proxy Statement filed May 11, 1995. (4) Incorporated by reference to Exhibits to Form 8-K filed September 19, 1996. (5) Incorporated by reference to Exhibits to Form 8-K filed July 3, 1997. (6) Incorporated by reference to Exhibits to Form 8-K filed February 25, 1997. (7) Incorporated by reference to Exhibits to definitive Proxy Statement filed May 5, 1997. (8) Incorporated by reference to Exhibits to definitive Proxy Statement filed May 15, 1998. (9) Incorporated by reference to Exhibits to Amendment No. 1 to Form S-4 filed October 19, 1998. (10) Incorporated by reference to Exhibits to Amendment No. 3 and Final Amendment to Schedule 14D-1 filed April 13, 1998. (11) Incorporated by reference to Exhibits to Form 8-K filed May 6, 1998. (12) Incorporated by reference to Exhibits to Registration Statement on Form S-4 filed July 31, 1998. (13) Incorporated by reference to Form 8-K filed October 13, 1998. (14) Incorporated by reference to Form 10-KSB filed March 31, 1998. IV-2 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed by the undersigned, thereunto duly authorized. MIDDLE BAY OIL COMPANY, INC. (Registrant) By: /s/ JOHN J. BASSETT ----------------------------------------- John J. Bassett PRESIDENT
March 30, 1999 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated: March 30, 1999 /s/ JOHN J. BASSETT - ------------------------------------------- -------------------------------------------- Date John J. Bassett Director, President, Chief Executive and Operating Officer March 30, 1999 /s/ C. J. LETT III - ------------------------------------------- -------------------------------------------- Date C. J. Lett, III Executive Vice President and Director March 30, 1999 /s/ STEPHEN W. HEROD - ------------------------------------------- -------------------------------------------- Date Stephen W. Herod Vice President and Director March 30, 1999 /s/ EDWARD P. TURNER, JR. - ------------------------------------------- -------------------------------------------- Date Edward P. Turner, Jr. Director March 30, 1999 /s/ FRANK E. BOLLING, JR. - ------------------------------------------- -------------------------------------------- Date Frank E. Bolling, Jr. Director March 30, 1999 /s/ GARY R. CHRISTOPHER - ------------------------------------------- -------------------------------------------- Date Gary R. Christopher Director March 30, 1999 /s/ ALVIN V. SHOEMAKER - ------------------------------------------- -------------------------------------------- Date Alvin V. Shoemaker Director
EX-21.1 2 EXHIBIT 21.1 EXHIBIT 21.1 MIDDLE BAY OIL COMPANY, INC. LIST OF SUBSIDIARIES AS OF DECEMBER 31, 1998 Middle Bay Production Company (INCORPORATED IN KANSAS) ENEX RESOURCES CORPORATION (INCORPORATED IN DELAWARE) EX-27 3 EXHIBIT 27
5 YEAR DEC-31-1998 JAN-01-1998 DEC-31-1998 1,040,096 0 3,898,490 0 0 4,938,586 91,644,762 39,073,584 57,940,817 4,799,932 27,454,567 0 8,908,937 37,118,643 (23,469,747) 57,940,817 15,011,354 17,702,578 7,801,249 27,106,258 0 0 1,971,595 (9,403,680) (2,829,762) (6,589,007) 0 0 0 (6,589,007) (0.83) (0.83)
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