-----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, SMF2X5N5hiixyvkaXKT+4Pmtcr23TNg8StQGRqg5TdjrjTTZQW1OllyR7pVhE4mO WGvTcIIAncRrHYD2aojdCw== 0001047469-99-017515.txt : 19990503 0001047469-99-017515.hdr.sgml : 19990503 ACCESSION NUMBER: 0001047469-99-017515 CONFORMED SUBMISSION TYPE: 10KSB40/A PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 19981231 FILED AS OF DATE: 19990430 FILER: COMPANY DATA: COMPANY CONFORMED NAME: ESENJAY EXPLORATION INC CENTRAL INDEX KEY: 0000901611 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 731421000 STATE OF INCORPORATION: OK FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10KSB40/A SEC ACT: SEC FILE NUMBER: 001-12530 FILM NUMBER: 99607912 BUSINESS ADDRESS: STREET 1: 500 N WATER STREET STREET 2: SUITE 1100 CITY: CORPUS CHRISTI STATE: TX ZIP: 78471 BUSINESS PHONE: 5128837464 MAIL ADDRESS: STREET 1: 500 DALLAS STREET STREET 2: SUITE 2920 CITY: HOUSTON STATE: TX ZIP: 77002 FORMER COMPANY: FORMER CONFORMED NAME: FRONTIER NATURAL GAS CORP DATE OF NAME CHANGE: 19931006 10KSB40/A 1 10KSB40/A - -------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-KSB/A [X] ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1998 [ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ______ to ______ Commission file number: 0-22782 ESENJAY EXPLORATION, INC. (Exact name of small business issuer in its charter) DELAWARE 73-1421000 (State of incorporation) (I.R.S. Employer Identification Number) 500 N. WATER STREET, SUITE 1100 CORPUS CHRISTI, TEXAS 78471 (Address of registrant's principal executive offices, including zip code) Registrant's telephone number, including area code: (512) 883-7464 Securities registered under Section 12(b) of the Exchange Act: NAME OF EACH EXCHANGE TITLE OF EACH CLASS ON WHICH REGISTERED ------------------- --------------------- None None Securities registered under Section 12(g) of the Exchange Act: COMMON STOCK SERIES B COMMON STOCK PURCHASE WARRANTS Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 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 [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-B is not contained herein, 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] State issuer's revenues for its most recent fiscal year: $1,716,473 The aggregate market value of the voting stock held by non-affiliates of the registrant (treating all executive officers and directors of the registrant, for this purpose, as if they may be affiliates of the registrant) was approximately $19,731,042 on March 26, 1999 (based on the last sales price of $1.25 per share as reported on the NASDAQ Stock Market). 15,784,834 shares as the registrant's common stock were outstanding as of March 26, 1999. DOCUMENTS INCORPORATED BY REFERENCE Registrant's Proxy Statement for its 1998 Annual Meeting of Stockholders is incorporated by reference into Part III. - -------------------------------------------------------------------------------- ESENJAY EXPLORATION, INC. FOR YEAR ENDED DECEMBER 31, 1998 TABLE OF CONTENTS FORM 10-KSB/A PART I
ITEM PAGE - ---- ---- 1. Description of Business............................................... 3 2. Description of Property............................................... 20 3. Legal Proceedings..................................................... 22 4. Submission of Matters to a Vote of Security Holders................... 22 PART II 5. Market for Common Equity and Related Stockholder Matters.............. 23 6. Management's Discussion and Analysis or Plan of Operation............. 23 6A. Quantitative and Qualitative Disclosures about Market Risks........... 31 7. Financial Statements.................................................. 32 8. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure................................. 52 PART III 9. Directors, Executive Officers, Promoters and Control Persons; Compliance with Section 16(a) of the Exchange Act................... 53 10. Executive Compensation................................................ 55 11. Security Ownership of Certain Beneficial Owners and Management...................................................... 56 12. Certain Relationships and Related Transactions........................ 58 PART IV 13. Exhibits and Reports on Form 8-K...................................... 60 Signatures............................................................ 62
2 PART I This Form 10-KSB/A contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. The Company's actual results could differ materially from those set forth in the forward-looking statements. Certain factors that might cause such a difference are discussed in the introductory paragraph to Management's Discussion and Analysis beginning on page 23 of this Form 10-KSB. ITEM 1. DESCRIPTION OF BUSINESS GENERAL THE COMPANY Esenjay Exploration, Inc. (the "Company") is an independent energy company engaged in the exploration for and development of natural gas and oil. The Company has assembled an inventory of 39 technology enhanced natural gas and oil exploration projects along the Texas and Louisiana Gulf Coast (the "Exploration Projects"). These Exploration Projects include substantial interests in 28 projects the Company acquired on May 14, 1998 (the "Acquisitions") from Esenjay Petroleum Corporation ("EPC") and Aspect Resources LLC ("Aspect") pursuant to an Acquisition Agreement and Plan of Exchange (as amended, the "Acquisition Agreement"). The Exploration Projects also include the Company's interests in projects acquired both before and after consummation of the Acquisitions. The Company, EPC and Aspect have spent several years identifying and evaluating many of the Exploration Projects. Each of the Exploration Projects differs in scope and character and consists of one or more types of assets, such as 3-D seismic data, leasehold positions, lease options, working interests in leases, royalty interests or other mineral rights. In connection with the Acquisitions, an affiliate of Enron Corp. exercised an option to exchange $3.8 million of debt Aspect owed to such Enron affiliate for 675,000 shares of the Company's Common Stock that would otherwise have been issued to Aspect in the Acquisitions, at an effective conversion rate of $5.63 per share. As a result of the Acquisitions and this exchange and the underwritten offering described below, EPC, Aspect and the Enron affiliate own approximately 32.8%, 27.7% and 4.3%, respectively, of the Company's outstanding Common Stock. On July 21, 1998 the Company closed an underwritten offering of 4,000,000 shares of its common stock at a price of $4.00 per share. The net proceeds to the Company were approximately $14,880,000. After the offering the Company had 15,762,723 shares outstanding. OVERVIEW OF CURRENT ACTIVITIES AND RECENT EVENTS. The Exploration Projects encompass a relatively large number of properties which the Company intends to drill and/or otherwise exploit on a property by property basis over a period of time based upon various factors including terms and locations of leases, updated current drilling results, and the overall Company exploration strategy. The Company utilizes the successful efforts method of accounting. Under this method it expenses its dry hole costs and the field acquisition costs of 3-D seismic data as incurred. The undeveloped properties which were acquired pursuant to the Acquisitions, and which were comprised primarily of interests in unproven 3-D seismic based projects, recorded in May of 1998 at an independently estimated fair market value of $54.2 million as determined by Cornerstone Ventures, L.P., a Houston, Texas based investment banking firm. Pursuant to the successful efforts method of accounting, the Company is amortizing such initial costs as periodic impairments of unproved properties on a straight-line basis over a period not to exceed forty-eight months, as well as recognizing property specific impairments. These non-cash charges effect all such costs which are not, in the accounting period they are to be impaired, supported by proven oil and gas reserves. Hence significant non-cash charges will likely depress reported earnings of the Company over the next several years, but will not effect cash flows provided by operating activities nor the ultimate realizable value of the Company's natural gas and oil properties. Most of the Exploration Projects have been enhanced with 3-D seismic data in conjunction with computer aided exploration ("CAEX") technologies. The 3-D seismic data acquired to date covers approximately 1,700 square miles. A significant number of the Exploration Projects have reached the drilling stage, and the Company has budgeted approximately $16.5 million, in addition to funds already spent, to fund its drilling budget in 1999. It has 3 also budgeted approximately $7.5 million for additional land and geophysical costs for a total 1999 capital expenditure budget of approximately $24.0 million. The budget is projected to fund the Company's net cost in over 40 wells. The Company does not currently have capital resources to fund the complete 1999 budget but believes such resources or other optional means of exploration funding will be available. (See Management's Discussion and Analysis - Liquidity and Capital Resources). The Company believes that the Exploration Projects represent a diverse array of technology enhanced, 3-D seismic evaluated, ready to drill natural gas exploration projects. The Company entered 1999 having gone from nominal second quarter 1998 gas and oil revenues of approximately $35,000 per month and large operating cash flow deficits to a company with over $360,000 per month in oil and gas revenues in the fourth quarter of 1998. This number is expected to exceed $700,000 per month as first quarter 1999 exploration discoveries come on line and continue to increase as additional wells are drilled. This should allow it to achieve positive operating cash flow in 1999 and beyond. In addition, since December 31, 1998, the Company has closed a long term financing commitment for $9,000,000 with Duke Energy Field Services, Inc., it has closed a sale of project interests to industry partners for a total of $3,768,500, and has entered into two preliminary agreements to sell additional project interests, which it expects to close in April 1999, for a total of approximately $3,900,000. The closed financing, combined with the closed project sales, as well as those expected to close, will result in an aggregate availability of over $16,600,000 in available cash resources, which is expected to enhance working capital and contribute to the Company's early 1999 capital expenditure plan. (See "See Management's Discussion and Analysis - Liquidity and Capital Resources"). STRATEGY The Company's strategy is to expand its reserves, production and cash flow through the implementation of an exploration program that focuses on (i) obtaining dominant positions in core areas of exploration; (ii) enhancing the value of the Exploration Projects and reducing exploration risks through the use of 3-D seismic and CAEX technologies; (iii) maintaining an experienced technical staff with the expertise necessary to take advantage of the Company's proprietary 3-D seismic and CAEX seismic data; (iv) reducing exploration risks by focusing on the identification of potential moderate-depth gas reservoirs, which the Company believes are conducive to hydrocarbon detection technologies; and (v) retaining operational control over critical exploration decisions. OBTAIN DOMINANT POSITION IN CORE AREAS. The Company has identified core areas for exploration along the Texas and Louisiana Gulf Coasts that have geological trends with demonstrated histories of prolific natural gas production from reservoir rocks high in porosity and permeability with profiles suitable for seismic evaluation. Unlike the Gulf of Mexico, where 3-D seismic data typically is owned and licensed by many companies that compete intensely for leases, the private right of ownership of onshore mineral rights enables individual exploration companies to proprietarily control the seismic data within focused core areas. The Company believes that by obtaining substantial amounts of proprietary 3-D seismic data and significant acreage positions within its core areas, it will be able to achieve a dominant position in focused portions of those areas. With such a dominant position, the Company believes it can better control the core areas' exploration opportunities and future production, and can attempt to minimize costs through economies of scale and other efficiencies inherent in its focused approach. Such cost savings and efficiencies include the ability to use the Company's proprietary data to reduce exploration risks and lower its leasehold acquisition costs by identifying and purchasing leasehold interests only in those focused areas in which the Company believes exploratory drilling is most likely to be successful. USE OF 3-D SEISMIC AND CAEX TECHNOLOGIES. The Company attempts to enhance the value of its Exploratory Projects through the use of 3-D seismic and CAEX technologies, with an emphasis on direct hydrocarbon detection technologies. These technologies create computer generated 3-dimensional displays of subsurface geological formations that enable the Company's explorationists to detect seismic anomalies in structural features that are not apparent in 2-D seismic surveys. The Company believes that 3-D seismic technology, if properly used, will reduce drilling risks and costs by reducing the number of dry holes, optimizing well locations and reducing the number of wells required to exploit a discovery. The Company believes that 3-D seismic surveys are particularly suited to its Exploration Projects along the Texas and Louisiana Gulf Coasts. 4 EXPERIENCED TECHNOLOGICAL TEAM. The Company maintains an experienced technical staff, including engineers, geologists, geophysicists, landmen and other technical personnel. After the Acquisitions, the Company hired most of EPC's technical personnel, who, in some instances, have worked together for over 15 years. In addition, the Company has contracts with various geotechnical services consultants who provide the Company geophysical expertise in managing the design, acquisition, processing and interpretation of 3-D seismic data in conjunction with CAEX data. FOCUSED DRILLING OBJECTIVES. In addition to using 3-D seismic and CAEX technologies, the Company seeks to reduce exploration risks by primarily exploring at moderate depths that are deep enough to discover sizeable gas accumulations (generally 8,000 to 12,500 feet) and that also are conducive to direct hydrocarbon detection, but not so deep as to be highly exposed to the greater mechanical risks and drilling costs incurred in the deep plays in the region. In conjunction with interpreting the 3-D seismic and CAEX data relating to the Company's moderate depth wells, the Company anticipates it will identify potential prospects in deep gas provinces that the Company may elect to pursue. CONTROL OF EXPLORATION AND OPERATIONAL FUNCTIONS. The Company believes that having control of the most critical functions in the exploration process will enhance its ability to successfully develop its Exploration Projects. The Company has a majority interest in many of the Exploration Projects, including proprietary interests in most of the 3-D seismic data relating to those projects. Although the Company has partners in the Exploration Projects in which it does not own a majority interest, in many cases, the Company owns a greater interest than any of its project partners. As a result, the Company will often be able to influence the areas to explore, manage the land permitting and option process, determine seismic survey areas, oversee data acquisition and processing, prepare, integrate and interpret the data and identify each prospect drillsite. In addition, the Company will likely be the operator of most of the wells drilled within the Exploration Projects. EXPLORATION PROJECTS Most of the Exploration Projects are concentrated within the Downdip Frio, Wilcox and Texas Hackberry core project areas. The Downdip Frio core area generally is in the middle Texas Gulf Coast where the Company believes Frio targets exist at moderate depths. The Wilcox core area generally is in the middle Texas Gulf Coast in an area the Company believes to have prospects for Wilcox sand exploration. The Texas Hackberry core area is located in Jefferson and Orange Counties, Texas, in an area which the Company believes offers drilling opportunities in the Hackberry formations, as well as Miocene and deeper Vicksburg sands. Other Exploration Projects consist of the Starboard Project, as well as other projects in Louisiana and Mississippi that either are in early stage exploration areas that may develop into new core project areas, or non-core area projects, which are projects that are not presently expected to be further expanded. Each of the Exploration Projects differs in scope and character and consists of one or more types of assets, such as 3-D seismic data, leasehold positions, lease options, working interests in leases, royalty interests or other mineral rights. The Company's percentage interest in each Exploration Project (a "Project Interest") represents the portion of the interest in the Exploration Project it shares with its other project partners. Therefore, the Company's Project Interest in an Exploration Project should not be confused with the working interest that the Company will own when a given well is drilled. The Company's working interest in the wells on each Exploration Project may be higher or lower than its Project Interest. The following table sets forth certain information about each of the Exploration Projects: 5 EXPLORATION PROJECTS
ACRES LEASED OR UNDER OPTION AT MARCH 26, SQUARE MILES OF 1999(1) 3-D SEISMIC DATA -------------------------- RELATING TO PROJECT AREAS GROSS NET PROJECT AREA PROJECT INTEREST(2) - ------------- ------- ------ ---------------- ------------------ SOUTH TEXAS DOWNDIP FRIO CORE AREA Allen Dome......................... 833 136 -- 50.0% Gillock............................ 23,804 3,404 82 22.5% Blessing........................... 1,414 278 22 24.0% Tidehaven.......................... 3,842 1,254 28 40.5% El Maton........................... 4,893 1,793 28 46.5% Midfield........................... 3,267 1,059 21 37.5% Markham............................ 2,584 1,480 -- 60.0% Buckeye............................ 20,279 7,667 50 45.0% Duncan Slough..................... 5,608 1,601 60 40.9% Southwest Pheasant................. 3,033 1,781 10 75.0% Geronimo........................... 7,140 1,382 76 20.0% Houston Endowment.................. 3,000 810 50 27.0% Wolf Point......................... 960 437 8 45.5% Sheriff Field...................... 4,943 2,755 -- 75.0% Bauer Ranch........................ 22,000 4,803 56 33.3% La Rosa............................ 5,537 443 25 8.0% Piledriver......................... 640 400 2 62.5% Archie ............................ 903 207 14 25.0% ------- ------ --- Downdip Frio Sub-Total 114,680 31,690 532 WILCOX CORE AREA Gila Bend.......................... 1,179 147 16 12.5% Hall Ranch......................... 7,894 3,266 57 41.5% Hordes Creek....................... 4,730 1,943 25 41.5% Mikeska............................ 7,898 2,850 32 38.0% Duval/McMullen..................... 1,980 1,782 12 90.0% Verdad............................. 50,994 6,930 57 25.0% Orangedale......................... 2,353 2,086 3 90.0% Riverdale.......................... 5,601 1,400 23 25.0% ------- ------ --- Wilcox Sub-Total 82,629 20,404 225 TEXAS HACKBERRY CORE AREA Lox B.............................. 9,281 1,440 62 25.0% West Port Acres.................... 881 86 21 12.5% Big Hill/Stowell................... 7,100 1,960 56 33.3% Lovells Lake....................... 18,213 4,262 65 33.3% West Beaumont...................... 1,721 78 23 7.9% ------- ------ --- Texas Hackberry Sub-Total 37,196 7,826 227 LOUISIANA Lapeyrouse......................... 4,576 943 35 25.0% Average Crab Lake.......................... 1,130 322 12 75.0% S. L. Eocene(3).................... 5,516 5,416 -- 100.0% ------- ------ --- Louisiana Sub-Total 11,222 6,681 47 6 ACRES LEASED OR UNDER OPTION AT MARCH 26, SQUARE MILES OF 1999(1) 3-D SEISMIC DATA -------------------------- RELATING TO PROJECT AREAS GROSS NET PROJECT AREA PROJECT INTEREST(2) - ------------- ------- ------ ---------------- ------------------ OTHER TEXAS Raymondville....................... 27,406 16,210 62 60.4% Caney Creek........................ 19,759 2,334 33 12.5% East Texas Pinnacle Reef (4)....... -- -- 400 -- Papalote (3)....................... 25,316 21,685 -- 87.5% Average ------- ------ --- Other Texas Sub-Total 72,481 40,229 495 MISSISSIPPI Thompson Creek..................... 1,877 1,562 12 93.5% Lipsmacker......................... 2,892 452 64 22.0% ------- ------ --- Mississippi Sub-Total 4,769 2,014 76 ------- ------ --- TOTAL ALL PROJECTS 322,977 108,844 1,602 ------- ------ --- ------- ------ ---
- ----------- (1) Gross acres refers to the number of acres leased or under option in which the Company owns an undivided interest. Net acres were determined by multiplying the gross acres leased or under option times the Company's working interest therein. (2) Each of the Exploration Projects differs in scope and character and consists of one or more types of assets, such as 3-D seismic data, leasehold positions, lease options, working interests in leases, royalty interests or other mineral rights. The Company's percentage interest in each Exploration Project (a "Project Interest") represents the portion of the interest in the Exploration Project it shares with its other project partners. Therefore, the Company's Project Interest in an Exploration Project should not be confused with the working interest that the Company will own when a given well is drilled. The Company's working interest in the wells on each Exploration Project may be higher or lower than its Project Interest. (3) Proprietary 3-D seismic data is planned to be shot over these areas in the near future. (4) Consists of 400 square miles of 3-D seismic data to which Aspect has rights pursuant to a license agreement, and to which the Company may acquire an interest pursuant to a geophysical technical services agreement with Aspect. EXPLORATION PROJECT DESCRIPTIONS. Set forth below is a description of the Exploration Projects. The amounts specified for the interests in the Exploration Projects and gross and net acreage of each Exploration Project and the project description were determined as of March 26, 1999. Estimates of drilling and completion costs are gross amounts and are not necessarily net to the Company's interests in the related Exploration Projects. In addition, predictions of well costs are estimates only, and actual costs may vary based on, among other factors, down hole conditions and costs for drilling rigs at the time of drilling. In prospects where 3-D seismic surveys are not yet shot, processed and interpreted, such data may, when available, enhance or condemn previously identified prospects or leads. DOWNDIP FRIO CORE AREA PROJECTS ALLEN DOME. The Allen Dome Project consists of leases and options of approximately 833 gross acres with 271 net acres in Brazoria County, Texas. The Company has a 50% Project Interest with 136 net acres to its interest. The acreage targets the Frio "A" Sands and is updip from a show in the Frio "A" Sand. Miocene potential exists in radial fault traps surrounding the dome. A spec shoot is in the planning stage, and the Company is attempting to tie onto the larger Speculative shoot in the area. A minimal amount of data will be needed to image the trap. Estimated drilling and completion costs for the deep Frio test is $1.2 million. 7 GILLOCK. The Gillock Project consists of leases and options covering approximately 23,804 gross acres with 15,129 net acres in Galveston County, Texas, which also includes HBP leasehold. The Company has a 22.5% Project Interest in this 3-D seismic project with 3,404 net acres to its interest. The primary geological targets the Company has identified, for potential drilling, are the Frio and Vicksburg Sands. A 70 square mile 3-D survey was completed in July 1998, has been processed, and is currently being interpreted. Preliminary interpretations have yielded several low risk prospects in the project area. The estimated cost to drill and complete a shallow well is approximately $900,000, with deeper wells costing over $3.5 million. BLESSING. The Blessing Project consists of leases and options covering approximately 1,414 gross acres with 1,157 net acres under 22 square miles of 3-D seismic coverage in Matagorda County, Texas. The Company has a non-operated 24.0% Project Interest with 278 net acres to its interest. A 3-D seismic survey was conducted in conjunction with the Tidehaven 3-D shoot (see "Tidehaven Project"). The Operator has drilled two (2) Upper Frio Sand wells. One well produced 277 MMCF per day and 4,267 BC per day in 1998, and has been recompleted in another pay zone, which is currently producing 1400 MCF per day and 20 BC per day; the other well was a dry hole. The Company's Working Interest in the well is 33.935%, although the Company's Project Interest in the remaining portion of the project is 24.0%. No wells are planned for 1999. The estimated cost of drilling and completing a shallow well in this project area is approximately $550,000. TIDEHAVEN. The Tidehaven Project consists of leases and options covering over 3,842 gross acres with 3,097 net acres in Matagorda County, Texas. The Company has a 40.5% Project Interest with 1,254 net acres to its interest. These leases overlay a series of known field pays and multiple fault blocks, which made this structure a 3-D seismic candidate. Initial interpretation of the 28 square mile 3-D seismic data set is complete. The Company has drilled and completed two wells in the lower Frio. The first is currently producing 1.1 MMCF per day and 7 BC per day, and the other was a dry hole. The estimated cost to drill and complete a well ranges from approximately $550,000 to $1.5 million, depending upon depth. There are several additional Mid Frio and Lower Frio prospects. EL MATON. The El Maton Project consists of leases and options covering approximately 4,893 gross acres with 3,856 net acres in Matagorda County, Texas. The Company has a 46.5% Project Interest with 1,793 net acres to its interest. A 29 square mile 3-D seismic survey was started in May 1997, as an extension of the Tidehaven shoot. This seismic survey has been completed and the interpretation is essentially complete. The geologic setting and target zones are the same as for Tidehaven. The Company has merged the 3-D data sets in the El Maton, Tidehaven, Blessing, and Midfield projects. The Company has identified several Mid Frio and Lower Frio prospect leads. The estimated cost to drill and complete a well ranges from approximately $550,000 to $1.5 million, depending upon depth. MIDFIELD. The Midfield Project consists of leases and options covering approximately 3,267 gross acres with 2,825 net acres in Matagorda County, Texas. The Company has a 37.5% Project Interest with 1,059 net acres to its interest. The project is an extension of the Tidehaven, Blessing and El Maton 3-D seismic shoots. All four of these 3-D seismic surveys have been merged. The Midfield Project is adjacent to and up basin from, the Tidehaven Project. The geologic setting and target zones are similar to Tidehaven. Initial data interpretation on a 21 square mile 3-D seismic survey over this acreage is complete, and the data has revealed two (2) low risk shallow drilling locations. The estimated cost to drill and complete a shallow well is approximately $550,000. MARKHAM. The Markham Project consists of leases and options covering approximately 2,584 gross acres with 2,466 net acres in Matagorda County, Texas. The Company has a 60% project interest with 1,048 net acres to its interest. The 3-D has been completed, and the Company is interpreting the data. Initial review of the seismic is encouraging and several prospects have been identified. The estimated costs to drill and complete a shallow well is approximately $550,000, with deeper well costing approximately $1.3 million. BUCKEYE RANCH. The Buckeye Ranch Project consists of approximately 20,279 gross acres with 17,037 net acres of lease options in Matagorda County, Texas. The Company has a 45% Project Interest with 7,667 net acres to its interest. A 3-D seismic survey has been completed, and the Company is currently interpreting the data. The estimated cost to drill and complete a shallow well is approximately $550,000, with deeper wells costing approximately $1.3 million. Initial review of the seismic data is encouraging and numerous prospects have been delineated. 8 DUNCAN SLOUGH. The Duncan Slough Project consists of leases and options covering approximately 5,608 gross acres with 3,906 net acres in Matagorda County, Texas. The Company has a 40.99% Project Interest with 1,601 net acres to its interest. The 3D survey has been completed, and the Company is interpreting the data. Initial review of the seismic is encouraging and numerous prospects have been delineated. The estimated cost to drill and complete a shallow well is approximately $550,000, with deeper wells costing approximately $1.3 million. The Company is planning to merge the Markham-Buckeye-Duncan Slough 3-D data with the adjacent surveys. SOUTHWEST PHEASANT. The Southwest Pheasant Project consists of leases and options covering approximately 3,033 gross acres with 2,375 net acres in Matagorda County, Texas. The Company has a 75.0% Project Interest with 1,781 net acres to its interest. The primary geological objectives are the middle and lower Frio sands. A portion of the project area is covered by an old Mobil 3-D seismic that has been reprocessed and reinterpreted. The Company has identified several shallow prospects. The estimated cost to drill and complete a shallow well is approximately $550,000, with deeper wells costing approximately $1.3 million. GERONIMO. The Geronimo Project consists of leases and options covering approximately 7,140 gross acres with 6,911 net acres in San Patricio County, Texas. The Company has a 20% Project Interest with 1,382 net acres to its interest. A 76 square mile 3-D seismic survey has been shot, and the Company has identified several prospective drillsites. One well has been drilled and is producing 50 BO per day and 142 MCF per day. A deep Vicksburg test and an Anderson Sand test well are currently being marketed. The estimated cost to drill and complete a well is approximately $600,000 for a shallow well, $1.2 million for an intermediate depth well, and $4.0 million for a Vicksburg well. HOUSTON ENDOWMENT. The Houston Endowment Project consists of leases and options covering approximately 3,000 gross acres with 3,000 net acres in San Patricio and Aransas Counties, Texas. The Company has a 27.0% Project Interest with 810 net acres to its interest. A 50 square mile 3-D seismic survey has been acquired. Esenjay Petroleum Corporation drilled one dry hole within the project area before execution of the Acquisition Agreement. The Company drilled an additional Deep Frio test, which was not successful. The estimated cost to drill and complete a shallow well is approximately $700,000 with deeper wells costing approximately $1.3 million. WOLF POINT. The Wolf Point Project consists of state leases covering approximately 960 gross acres with 960 net acres in Calhoun County, Texas. The Company has a 45.5% Project Interest with 437 net acres to its interest. Esenjay Petroleum Corporation drilled and completed two (2) successful wells within the 3-D seismic survey area before the Effective Date of the Acquisitions (November 1, 1997). Known field pays from this area are the 7,200-foot Frio, 7,500-foot Frio, 7,700 foot Frio, Broughton, Oats, Upper, Middle and Lower Melbourne sands. The Company drilled one successful well which is currently producing approximately 1.3 MMCF per day and 13 BC per day. The Company has also drilled one dry hole. The estimated cost to drill and complete a well is approximately $900,000. SHERIFF FIELD. The Sheriff Project consists of approximately 4,943 gross acres with 3,674 net acres of lease options in Calhoun County, Texas. The Company has a 75.0% Project Interest with 2,755 net acres to its interest. The Company has written off most of the book value of this project and does not expect it to play a significant part in its near term exploration activities. BAUER RANCH. The Bauer Ranch Project contains approximately 22,000 gross acres with 14,411 net acres of lease options in Jefferson County, Texas. The Company has a 33.33% Project Interest with 4,803 net acres to its interest. Numerous prospect leads have been generated within the area via log shows, detailed structural mapping, and 2-D seismic data. Deep exploration zones also are targeted. The Company recently completed shooting a 56 square mile 3-D seismic survey and is currently interpreting the data. The estimated cost to drill and complete a shallow well is approximately $650,000, with deeper wells costing approximately $1.6 million. 9 LA ROSA. The La Rosa Project consists of approximately 5,537 gross acres with 5,537 net acres of leases and options in Refugio County, Texas. The Company has non-operating Project Interest of between 8.0% and 13% with between 443 and 719 net acres to its interest. A 25 square mile 3-D seismic shoot has been acquired and interpreted. Four wells have been drilled since the Effective Date of the Acquisition for the Company's account. Three wells were dry holes. The most recent well is currently producing 440 MCF per day. The Company has a 13% interest in this well. The estimated cost to drill and complete a Frio formation well is approximately $450,000. PILEDRIVER. The Piledriver Project consists of 640 gross acres and 640 net acres of state leases located in Chambers County, Texas. The Company has a 62.5% Project Interest with 400 net acres to its interest. The objectives are two Frio age sands. One of these target sands has what the Company believes to be a significant gas test at the top of the sand in a well that it believes is down dip to the Company's acreage. A 3D seismic survey was recently conducted by Western Geophysical. The Company has acquired the data and is interpreting it at this time before making any drilling decisions. The estimated cost to drill and complete a well is approximately $1.85 million. ARCHIE. The Archie Project consists of leases covering 903 gross acres and 826 net acres located in Chambers County, Texas. The Company owns a 25% project interest with 207 net acres to its interest. Interpretations of the 13.4 square mile 3-D are complete and the location on the first of three low risk prospects is being built. The target zones are the lower Frio Textularia Mississippiensis sands. Estimated dry hole costs are $800,000. WILCOX CORE AREA PROJECTS GILA BEND. The Gila Bend Project consists of a continuous acreage block of 1,179 gross acres with 1,179 net acres under a 16 square mile 3-D in Karnes County, Texas. The Company has a 12.5% interest with 147 net acres to its interest. The project is adjacent to the Company's Hall Ranch and Verdad projects. The 3-D interpretation is complete, and a deviated well is scheduled in the second quarter of 1999, to test multiple Wilcox Sands. The estimated cost to drill and complete a deviated well, in the deep Wilcox, is approximately $3.0 million. HALL RANCH. The Hall Ranch Project consists of leases and options covering approximately 7,894 gross acres with 7,869 net acres under a 57 square mile 3-D seismic survey in Karnes County, Texas. The Company has a 41.5% Project Interest with 3,266 net acres to its interest. The Company believes the Hall Ranch area is on an under-explored ridge on trend with several producing fields. Multiple potential pay zones in four expanded fault blocks have been delineated in the Wilcox sands from approximately 8,000 to 17,000 feet. Known field pays are from Wilcox reservoirs in the Migura, Roeder, Bunger, Hackney, Middle Wilcox L series sands, and the Upper Wilcox. The Company has delineated several potential drill sites. The Company has drilled and run production casing on its first well on this project. The well is currently producing 5 MMCF per day without any production decline over the last 6 months. This well was drilled at a location in which the Company owns a 20.75% non-operated Working Interest. The Company will own and operate 41.5% Working Interest in offset locations. The estimated cost to drill and complete a well ranges from approximately $270,000 to $600,000 for shallow wells, while wells completed in the deep zones (to 12,500 feet) cost approximately $2.0 million. HORDES CREEK. The Hordes Creek Project contains leases and options on approximately 4,730 gross acres with 4,683 net acres located in Goliad County, Texas. The Company has a 41.5% Project Interest with 1,943 net acres to its interest. The Company believes Hordes Creek has potential in the Miocene, Frio, Yegua, and the Upper, Middle, and Lower Wilcox Sands. Preliminary migrated 3-D seismic data covering 25 square miles has been interpreted. The Company has drilled two shallow Wilcox wells in the project, both of which were dry holes. A deep Wilcox (15,000 ft.) test is currently being marketed. A shallow Yegua well is in the planning stage. The estimated cost to drill and complete a shallow Yegua well is approximately $355,000.00. The estimated cost to drill and complete a deep Wilcox test is $2.9 million. MIKESKA. The Mikeska Project consists of leases covering approximately 7,898 gross acres with 7,500 net acres located in Live Oak County, Texas. The Company has a 38.0% Project Interest with 2,850 net acres to its interest. Multiple pay potential exists from 8,500 feet to at least 16,000 feet. This portion of the Wilcox trend contains known pays from the Hockley, four Queen City sands, four Slick sands, six Luling sands, three Tom Lyne sands and three to five House sands. A 32 square mile 3-D seismic survey has been shot and the data has been 10 recently reprocessed and is being reinterpreted. One well has been drilled and completed as a low volume oil well and is not an impact well. A second well has been completed and tested 9 MMCF per day plus water, and is awaiting pipeline connection. The Company has identified several drill sites updip to the discovery well. The estimated cost to drill and complete a shallow well is approximately $800,000, with deeper wells costing approximately $1.4 million. DUVAL/MCMULLEN. The Duval/McMullen Project consists of approximately 1,980 gross acres with 1,980 net acres of options in Duval and McMullen Counties, Texas. The Company has a 90.0% Project Interest with 1,782 net acres to its interest. The Company is negotiating with Western Geophysical to acquire a one-year-old proprietary 3-D seismic survey. The Company plans to interpret the 3-D seismic data before drilling. The estimated cost to drill and complete a shallow well is approximately $800,000, with deeper wells costing approximately $1.2 million. These leases have not been available prior to the 3D seismic data being acquired and released. Vastar Resources has recently enjoyed significant drilling success adjacent to Esenjay's acreage. VERDAD. The Verdad Project consists of leases and options covering approximately 50,994 gross acres with 27,721 net acres under a 40 square mile 3-D seismic survey in Karnes County, Texas. The Company owns a non-operated 25% interest in this project with 6,930 net acres to its interest. Verdad has potential pays in the shallow Frio, Yegua, and Upper Wilcox, as well as the upside potential in the numerous Middle and Lower Wilcox reservoirs. This project is adjacent to the Company's Hall Ranch Project. The Company expects to begin interpreting data in mid April 1999. Estimated drilling and completed well costs in the project area range from approximately $270,000 to $600,000 for shallow wells, while wells completed in the deep zones cost approximately $1.8 million. ORANGEDALE. The Orangedale Project consists of approximately 2,353 gross acres with 2,318 net acres of leases in Bee County, Texas. The Company has a 90% interest with 2,086 net acres to its interest. The prospect was originally a subsurface idea backed up by 2-D data and then was recently shot as a large spec 3-D shoot by a third party. Esenjay has rights to and has interpreted three square miles of the 3-D data. Seitel has recently shot another 3-D survey, which will overlap the survey shot by Edge in 1997, and will also cover additional Esenjay leases not previously shot. Multiple pay potential exists from 8,800' to 15,000' in the expanded Upper and Middle Wilcox Sands. Wells required to test the several proposed traps from a depth of 10,150' (non-pipe) to 15,000', cost from $450,000 to $1,500,000, respectively. RIVERDALE. The Riverdale Project consists of a continuous acreage block of 5,601 gross acres with 5,601 net acres in a complexly faulted area ten miles west of Goliad, Texas. The Company has a 25% non-operated interest with 1,400 net acres to its interest. The Frio, Vicksburg, Hockley, Yegua, Cook Mountain and Upper Wilcox sands from depths of 1700' to 9500' have all produced in the immediate area and are considered to be prospective. Large untested fault blocks have been mapped in the area using approximately 100 miles of 2-D seismic in conjunction with the available well control. Recently Western Geophysical has acquired 3-D data across this project and the Company is interpreting the data. This area is adjacent to and will be merged with the Company's Hordes Creek project. The estimated cost to drill and complete a 9500' test is approximately $800,000. TEXAS HACKBERRY CORE AREA PROJECTS LOX B. The Lox B Project consists of 9,281 gross acres with 5,759 net acres of leases and options in Jefferson County, Texas. The Company has a 25.0% non-operated Project Interest with 1,440 net acres to its interest. The primary objectives of this project are the Hackberry and Vicksburg formations. The acreage has been evaluated with 71 square miles of 3-D seismic data. The Company has identified numerous potential prospects through the use of seismically detected hydrocarbon indicators. The 3-D seismic survey has been merged with the West Port Acres data, and ultimately will be merged with the Big Hill/Stowell and Lovells Lake 3-D seismic surveys described below. The initial well was dry and the second well appears to be a significant discovery. The operator, H.S. Resources, Inc. anticipates flowing the well at 15 MMCF per day and 750 BC per day. The estimated cost to drill and complete a Hackberry well is approximately $1.3 million, and Vicksburg wells cost approximately $1.8 million to drill and complete. 11 WEST PORT ACRES. The West Port Acres Project consists of 881 gross acres with 686 net acres of leases in Jefferson County, Texas, which have been acquired and a 21 square mile 3-D seismic survey has been conducted. The Company has a 12.5% non-operated Project Interest with 86 net acres. The Company has identified several Hackberry prospects. The estimated cost to drill and complete a Hackberry well is approximately $1.5 million. BIG HILL/STOWELL. The Big Hill/Stowell Project consists of over 7,100 gross acres with 5,882 net acres of leases and options in Jefferson County, Texas. The Company has a 33.33% Project Interest with 1,960 net acres to its interest. The Company has entered an agreement to sell all of its undeveloped property interests in the Big Hill/Stowell area to Helmerich & Payne, Inc. LOVELLS LAKE. The Lovells Lake Project consists of 18,213 gross acres with 12,788 net acres of leases and options in Jefferson County, Texas. The Company has a 33.33% Project Interest with 4,262 net acres to its interest. The Company has completed a 65 square mile 3-D seismic survey, which has been interpreted, yielding numerous Hackberry prospects. The Company has drilled and logged 58 feet of net gas pay in the first well and is awaiting completion. A second well is currently being drilled. The Company anticipates drilling four additional wells in 1999. The estimated cost to drill and complete a Hackberry well ranges from approximately $1.0 million to $1.5 million. WEST BEAUMONT. The West Beaumont Project consists of 1,721 gross acres with 990 net acres of leases and options in Jefferson County, Texas. The Company has a 7.9% non-operated Project Interest with 80 net acres to its interest. A 22.5 square mile 3-D seismic survey has been interpreted by the Company. Several Frio and Hackberry age prospects have been identified. Two wells have been drilled by the operator. The first well tested at 1.1 MMCF per day and 403 BO per day. The second well has been drilled and pipe has been set awaiting completion. The estimated cost to drill and complete a Hackberry well is approximately $750,000. The Company has entered a contract to sell its undeveloped property interests in this project. LOUISIANA PROJECTS LAPEYROUSE. The Company has non-operated working interests in the leases over this project ranging from 12.0% to 46.875%, depending upon the target formation depths. The project consists of approximately 4,576 gross and 3,772 net acres of leases in the Lapeyrouse Field in Terrebonne Parish, Louisiana. The 3-D seismic data has been shot, processed and interpreted. After seismic interpretation, two exploratory initial wells have been identified. Both wells will expose the Company to significant reserve potential in a trend area where numerous giant oil and gas fields are located. Drilling is expected to commence in the fourth quarter of 1999. The estimated cost to drill and complete a well is approximately $3.2 million to $5.5 million depending upon depth. CRAB LAKE. The Company has retained a 75% project interest, which consists of 1,130 gross and 429 net acres of leases in Cameron Parish, Louisiana. The primary target objectives are in the Miocene series of sands. The Company has interpreted a 12 square mile 3-D seismic shoot, part of a 52 square mile 3-D. The first well is scheduled to be drilled in third quarter 1999, as a development well to extend the field. The well will test multiple objectives, and if successful, will require further development drilling. The estimated cost to drill and complete a well is approximately $1.1 million. S. L. EOCENE. The S. L. Eocene Project contains approximately 5,516 gross acres with 5,416 net acres of lease options in Beauregard Parish, Louisiana. The Company has a 100.00% Project Interest with 5,416 net acres. Numerous project leads have been generated within the area via log shows, detailed facies mapping, and 2-D seismic data. The main target horizon for this project is the Cockfield Formation. The shallower frio and deeper Wilcox zones may also be targeted. The Company is currently marketing the project to potential partners. The estimated cost to drill a Cockfield well is $275,000, with a completed well cost estimated at $450,000. OTHER TEXAS PROJECTS RAYMONDVILLE. The Raymondville Project consists of approximately 27,406 gross acres with 26,849 net acres of leases and options in Willacy County, Texas. The Company has a 60.37500% Project Interest with 16,210 net acres to its interest. This project includes separate geologic structures known by four different field names. The pre 3-D seismic geologic study of this area has identified several possible drilling locations. These locations were 12 selected based on subsurface well correlation and production analysis. A 62 square mile 3-D seismic survey has been acquired and currently is in processing. The Company anticipates to begin interpreting the data in May 1999. Two of the locations, which were identified by subsurface mapping prior to 3D seismic, have been drilled. Both have logged multiple pay zones and both have been completed as dual gas producers. The combined initial flow rate for the wells exceeded 10 MMCF per day, and they are currently producing 6 MMCF per day. The Company has recently sold an 18.5% working interest for $3.76 million. The estimated cost to drill and complete a well is approximately $550,000. CANEY CREEK. The Caney Creek Project consists of options and leases covering 19,759 gross acres with 18,670 net acres in Matagorda and Wharton Counties, Texas. The Company has a 12.5% Project Interest with 2,334 net acres to its interest. The project targets the Frio and Yegua reservoirs. A 32 square mile 3-D seismic survey has been conducted, and the interpretation of the data has been completed. Several leads have been identified. The Company entered a contract to sell its undeveloped interests in this area. EAST TEXAS PINNACLE REEF TREND. Aspect and certain of its affiliates have licenses covering approximately 400 square miles of 3-D seismic data pertaining to the East Texas Cotton Valley Reef Trend. This seismic data is recently acquired and most of it is proprietary. Currently, there is no acreage position or defined drilling opportunity associated with this project. The Company intends to enter into a joint venture with Aspect or its affiliates to attempt to generate drillable prospects. The joint venture will, if consummated, be subject to the terms of any licensing or other agreements currently in effect. PAPALOTE. The Papalote Project consists of leases and options of approximately 25,316 gross acres with 24,783 net acres in San Patricio and Bee Counties, Texas. The Company has ownership of between 75% and 100% in the Project at various stages in the development of the property. A +100 square mile 3-D is planned for 1999. The project will target the Frio sands with the Vicksburg Sands as a secondary target, and the Yegua formation as the primary exploratory target. Several Yegua leads have been identified with subsurface and 2-D seismic. A Frio/Vicks well will cost $250,000 to drill and complete and a Yegua well will cost approximately $1.0 million. MISSISSIPPI PROJECTS THOMPSON CREEK. The Thompson Creek Project consists of approximately 1,877 gross acres with 1,671 net acres of leases and options in Wayne County, Mississippi. The Company has a 93.5% Project Interest with 1,562 net acres to its interest. Approximately 12 miles of 3D have been interpreted along the salt ridge. The Company has written off most of the book value of this project and does not expect it to play a significant part in its near term exploration activities. LIPSMACKER. The Lipsmacker Project consists of approximately 2,892 gross acres with 2,056 net acres of leases and options in Choctaw, Alabama and Clarke Counties, Mississippi. The Company has a 22.0% Project Interest with 452 net acres to its interest. Esenjay Petroleum Corporation completed a 64 square mile 3-D seismic survey in the fall of 1996, and while several drilling locations were tested, the results generally were disappointing. The Company believes there is one additional well to be drilled. The Company is currently marketing this prospect. The estimated cost to drill and complete a well is approximately $1.2 million. CAEX TECHNOLOGY AND 3-D SEISMIC The Company, either directly or through its partners, uses CAEX technology to collect and analyze geological, geophysical, engineering, production and other data obtained about potential gas or oil prospects. The Company uses this technology to correlate density and sonic characteristics of subsurface formations obtained from 2-D seismic surveys with like data from similar properties, and uses computer programs and modeling techniques to determine the likely geological composition of a prospect and potential locations of hydrocarbons. Once all available data has been analyzed to determine the areas with the highest potential within a prospect area, the Company may conduct 3-D seismic surveys to enhance and verify the geological interpretation of the structure, including its location and potential size. The 3-D seismic process produces a three-dimensional image based upon seismic data obtained from multiple horizontal and vertical points within a geological formation. The 13 calculations needed to process such data are made possible by computer programs and advanced computer hardware. While large oil companies have used 3-D seismic and CAEX technologies for approximately 20 years, these methods were not affordable by smaller, independent gas and oil companies until more recently, when improved data acquisition equipment and techniques and computer technology became available at reduced costs. The Company began using 3-D seismic and CAEX technologies in 1992 and is using these technologies on a continuing basis. The Company believes its use of CAEX and 3-D seismic technology may provide it with certain advantages in the exploration process over those companies that do not use this technology. These advantages include better delineation of the subsurface, which can reduce exploration risks and help optimize well locations in productive reservoirs. The Company believes these advantages can be readily validated based upon general industry experience as well as the experiences of Aspect and EPC. Because computer modeling generally provides clearer and more accurate projected images of geological formations, the Company believes it is better able to identify potential locations of hydrocarbon accumulations and the desirable locations for wellbores. However, the Company has not used the technology extensively enough to arrive at any conclusion regarding the Company's ability to interpret and use the information developed from the technology. EXPLORATION AND DEVELOPMENT The Company considers the Gulf Coast to be the premier area in the United States to explore for significant new reserves. This conclusion is based on several characteristics including (i) a large number of productive intervals throughout a significant sedimentary section, (ii) numerous wells with which to calibrate 3-D seismic data and (iii) complicated geological formations that the Company believes 3-D seismic technology is particularly well suited to interpretation. In 1994, the Company began devoting more of its energy to the Gulf Coast region. The Company initially entered this area by evaluating the onshore shallow Frio/Miocene Trend. Its emphasis expanded to include larger exploration targets represented by large geological features such as those present in the Starboard Project. Upon completion of the Acquisitions, the Company spread its focus over an array of exploration projects along the Gulf Coast and intends to expand its project inventory in these areas. The Company's Exploration Project inventory is along the Gulf Coast of Texas, Louisiana, Alabama and Mississippi. The focus is on natural gas exploration prospects with a numerical concentration along the Texas Gulf Coast, many of which were delineated by seismic hydrocarbon indicators. Additional 2-D and 3-D seismic surveys may be required to evaluate these areas more fully, and when determined appropriate, the Company intends to acquire acreage and drill wells as indicated by the evaluations. The Company intends to drill prospects where the formations being tested are known to be productive in the general area and where it believes 3-D seismic can be used to increase resolution and thereby reduce risk. The extent to which the Company will pursue its activities in the onshore Gulf Coast region will be determined by the availability of the Company's resources and the availability of joint venture partners. ACQUISITIONS AND DIVESTMENTS The Company has periodically acquired producing natural gas and oil properties. In connection with each acquisition, the Company considers (i) current and historic production levels and reserve estimates, (ii) additional exploration and exploitation potential via technology enhancements; (iii) capital requirements; (iv) proximity of product markets; (v) regulatory compliance; (vi) acreage potential; and (vii) existing production transportation capabilities. The Company also considers the historic financial operating results and cash flow potential of each acquisition opportunity. Evaluation of the merits of a particular acquisition is based, to the extent relevant, on all of the above factors as well as other factors deemed relevant by the Company's management. The Company has currently de-emphasized its producing property acquisition activities. The Company intends to limit its near term producing property acquisitions to opportunities that facilitate its exploration activities. The Company may readdress this approach if it identifies an opportunity it believes to be of exceptional benefit to its shareholders. 14 HEDGING ACTIVITIES AND MARKETING The Company markets its natural gas through monthly spot sales. Because sales made under spot sales contracts result in fluctuating revenues to the Company depending upon the market price of gas, the Company may enter into various hedging agreements to minimize the fluctuations and the effect of price declines or swings. During January 1999, the Company completed performance on a 1996 swap agreement on approximately 1,040 MMBtu's per day of Mid-Continent natural gas production for $1.566 per MMBtu for the period beginning April 1, 1996 and ending January 31, 1999. In October of 1998, the Company entered into two swap agreements, one for 4,000 MMBtu's per day of its Gulf Coast natural gas production for $2.14 per MMBtu for the period beginning November 1998 and ending in October 1999, and the second one for 700 MMBtu's per day of its Gulf Coast natural gas production for $2.13 per MMBtu for the period beginning November 1998 and ending in October 1999. Both of these swap agreements were supplemented in December 1998 when the Company entered into additional swap agreements, one of which was for 4,000 MMBtu's per day of its Gulf Coast natural gas production for $2.07 per MMBtu for the period beginning November 1999 and ending in October 2000, and the second one was for 700 MMBtu's per day of its Gulf Coast natural gas production for $2.07 per MMBtu for the period beginning November 1999 and ending in October 2000. As a result of the foregoing transactions, the Company has 4,700 MMBtu's per day of its Gulf Coast natural gas production hedged through October 2000. The Company expects that its daily production will continue to increase rapidly and it will periodically consider additional hedge transactions consistent with its ongoing policy. Its policy is to periodically review its projected natural gas production from proved developed properties in light of then current market conditions. Its objective is to seek to prudently stabilize its future cash flows from proven producing properties. It believes that as it continues to expand its drilling budget this methodology allows it to have more control over its short-term cash flow while not giving up the upside potential in its future revenues, a substantial portion of which it projects to be from properties within its project inventory which are yet to be drilled. All of the Company's oil production is now sold under market-sensitive or spot price contracts. The Company's revenues from oil sales fluctuate depending upon the market price of oil. No purchaser accounted for more than 10% of the Company's total revenue in 1997 or 1998. The Company does not believe the loss of any existing purchaser would have a material adverse effect on the Company. The Company has a credit facility with Duke Energy Field Services, Inc., which allows the lender the right to gather, process, transport and market, at competitive market rates, natural gas produced from a majority of the Exploration Projects through December 31, 2005. OPERATING HAZARDS AND INSURANCE The gas and oil business involves a variety of operating risks, including the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations, and environmental hazards such as oil spills, gas leaks, ruptures or discharges of toxic gases, the occurrence of any of which could result in substantial losses to the Company due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, cleanup responsibilities, regulatory investigation and penalties and suspension of operations. The Company maintains a gas and oil lease operator insurance policy that insures the Company against certain sudden and accidental risks associated with drilling, completing and operating its wells. There can be no assurance that this insurance will be adequate to cover any losses or exposure to liability. The Company also carries comprehensive general liability policies and an umbrella policy. The Company and its subsidiaries carry workers' compensation insurance in all states in which they operate. The Company maintains various bonds as required by state and federal regulatory authorities. Although the Company believes these policies are customary in the industry, they do not provide complete coverage against all operating risks. An uninsured or partially insured claim, if successful and of sufficient magnitude, could have a material adverse effect on the Company and its financial condition. If the Company experiences significant claims or losses, the Company's insurance premiums could be increased which may adversely affect the Company and its financial condition or limit the ability of the Company to 15 obtain coverage. Any difficulty in obtaining coverage may impair the Company's ability to engage in its business activities. REGULATION GENERAL. The gas and oil industry is extensively regulated by federal, state and local authorities. In particular, gas and oil production operations and economics are affected by price controls, environmental protection statutes, tax statutes and other laws and regulations relating to the petroleum industry, as well as changes in such laws, changing administrative regulations and the interpretations and application of such laws, rules and regulations. Gas and oil industry legislation and agency regulation are under constant review for amendment and expansion for a variety of political, economic and other reasons. Numerous regulatory authorities, federal, and state and local governments issue rules and regulations binding on the gas and oil industry, some of which carry substantial penalties for failure to comply. The regulatory burden on the gas and oil industry increases the Company's cost of doing business and, consequently, affects its profitability. The Company believes it is in compliance with all federal, state and local laws, regulations and orders applicable to the Company and its properties and operations, the violation of which would have a material adverse effect on the Company or its financial condition. SEISMIC PERMITS. Current law in the State of Louisiana requires permits from owners of at least an undivided 80% interest in each tract over which the Company intends to conduct seismic surveys. As a result, the Company may not be able to conduct seismic surveys covering its entire area of interest. Moreover, 3-D seismic surveys typically are conducted from various locations both inside and outside the area of interest to obtain the most detailed data of the geological features within the area. To the extent that the Company is unable to obtain permits to access locations to conduct the seismic surveys, the data obtained may not be as detailed as might otherwise be available. EXPLORATION AND PRODUCTION. The Company's operations are subject to various regulations at the federal, state and local levels. Such regulations include (i) requiring permits for the drilling of wells; (ii) maintaining bonding requirements to drill or operate wells; and (iii) regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells and the disposal of fluids used in connection with well operations. The Company's operations also are subject to various conservation regulations. These include the regulation of the size of drilling and spacing units, the density of wells that may be drilled, and the unitization or pooling of gas and oil properties. In addition, state conservation laws establish maximum rates of production from gas and oil wells, generally prohibiting the venting or flaring of gas, and impose certain requirements regarding the ratability of production. The effect of these regulations is to limit the amount of gas and oil the Company can produce from its wells and to limit the number of wells or the locations at which the Company can drill. Recently enacted legislation and regulatory action in Texas and Oklahoma is intended to reduce the total production of natural gas in those states. Although such restrictions have not had a material impact on the Company's operations to date, the extent of any future impact therefrom cannot be predicted. NATURAL GAS MARKETING, GATHERING AND TRANSPORTATION. Federal legislation and regulatory controls in the United States have historically affected the price of the natural gas produced by the Company and the manner in which such production is marketed. The transportation and sale for resale of natural gas in interstate commerce are regulated by the Federal Energy Regulatory Commission ("FERC") pursuant to the Natural Gas Act and the Natural Gas Policy Act of 1978 ("NGPA"). The maximum selling prices of natural gas were formerly established pursuant to regulation. However, on July 26, 1989, the Natural Gas Wellhead Decontrol Act of 1989 ("Decontrol Act") was enacted, which terminated wellhead price controls on all domestic natural gas on January 1, 1993 and amended the NGPA to remove completely by January 1, 1993 price and nonprice controls for all "first sales" of natural gas, which will include all sales by the Company of its own production. Consequently, sales of the Company's natural gas currently may be made at market prices, subject to applicable contract provisions. The FERC's jurisdiction over natural gas transportation was unaffected by the Decontrol Act. The FERC also regulates interstate natural gas transportation rates and service conditions, which affect the marketing of natural gas produced by the Company, as well as the revenues received by the Company for sales of such natural gas. Since the latter part of 1985, the FERC has endeavored to make interstate natural gas transportation more accessible to gas buyers and sellers on an open and nondiscriminatory basis. The FERC's efforts have 16 significantly altered the marketing and transportation of natural gas. Commencing in April 1992, the FERC issued Order Nos. 636, 636-A, 636-B and 636-C (collectively, "Order No. 636"), which, among other things, require interstate pipelines to "restructure" their services to provide transportation separate or "unbundled" from the pipelines' sales of gas. Also, Order No. 636 requires interstate pipelines to provide open-access transportation on a nondiscriminatory basis that is equal for all natural gas shippers. Order No. 636 has been implemented through decisions and negotiated settlements in individual pipeline services restructuring proceedings. In many instances, the result of Order No. 636 and related initiatives has been to substantially reduce or eliminate the interstate pipelines' traditional role as wholesalers of natural gas, and has substantially increased competition and volatility in natural gas markets. The FERC has issued final orders in virtually all Order No. 636 pipeline restructuring proceedings. In July 1996, the United States Court of Appeals for the District of Columbia Circuit largely upheld Order No. 636 and remanded certain issues for further explanation or clarification. Numerous petitions for review of the individual pipeline restructuring orders are currently pending in that court. The issues remanded for further action do not appear to materially affect the Company. Proceedings on the remanded issues are currently ongoing before the FERC following its issuance of Order No. 636-C in February 1997. Although it is difficult to predict when all appeals of pipeline restructuring orders will be completed or their impact on the Company, the Company does not believe that it will be affected by the restructuring rule and orders any differently than other natural gas producers and marketers with which it competes. Although Order No. 636 does not regulate natural gas production operations, the FERC has stated that Order No. 636 is intended to foster increased competition within all phases of the natural gas industry. It is unclear what impact, if any, increased competition within the natural gas industry under Order No. 636 will have on the Company and its natural gas marketing efforts. Although Order No. 636 could provide the Company with additional market access and more fairly applied transportation service rates, terms and conditions, it could also subject the Company to more restrictive pipeline imbalance tolerances and greater penalties for violation of those tolerances. The Company does not believe, however, that it will be affected by any action taken with respect to Order No. 636 materially differently than other natural gas producers and marketers with which it competes. The FERC has recently announced its intention to reexamine certain of its transportation-related policies, including the appropriate manner for setting rates for new interstate pipeline construction, the manner in which interstate pipeline shippers may release interstate pipeline capacity under Order No. 636 for resale in the secondary market, the price that shippers can charge for their released capacity, and the use of negotiated and market-based rates and terms and conditions for interstate gas transmission. Several pipelines have obtained FERC authorization to charge negotiated rates as an alternative to traditional cost-of-service rate making methodology. In February 1997, the FERC announced a broad inquiry into issues facing the natural gas industry to assist the FERC in establishing regulatory goals and priorities in the post-Order No. 636 environment. In December 1997, the FERC requested comments on the financial outlook of the natural gas pipeline industry, including among other matters, whether the FERC's current rate making policies are suitable in the current industry environment. In April 1998, the FERC issued a new rule to further standardize pipeline transaction tariffs that, as the result of newly standardized provisions regarding firm intra day transportation nominations, could adversely affect the reliability of scheduled interruptible transportation service on some pipelines. While any resulting FERC action would affect the Company only indirectly, any new rules and policy statements may have the effect of enhancing competition in natural gas markets. Additional proposals and proceedings that might affect the natural gas industry are considered from time to time by Congress, the FERC, state regulatory bodies and the courts. The Company cannot predict when or if any such proposals might become effective, or their effect, if any, on the operations of the Company. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue indefinitely into the future. The regulatory burden on the oil and natural gas industry increases the Company's cost of doing business and, consequently, affects its profitability and cash flow. In as much as such laws and regulations are frequently expanded, amended or reinterpreted, the Company is unable to predict the future cost or impact of complying with such regulations. LOUISIANA LEGISLATION. The Louisiana legislature passed Act 404 in 1993, which permits a party transferring an oil field site to establish a site-specific trust account for such oil field. If the site-specific trust account is established in accordance with the requirements of the statute, the party transferring the oil field site shall 17 not thereafter be held liable by the state for any site restoration costs or actions associated with the transferred oil field site. The parties to a transfer may elect not to establish a site-specific trust account, however, in the absence of such an account, the transferring party will continue to have liability for the costs of restoration of the site. If the parties to a transfer elect to establish a site-specific trust account pursuant to the statute, the Louisiana Department of Natural Resources ("DNR") requires an oil field site restoration assessment to be made at the time of the transfer or within one year thereafter, to determine the site restoration requirements existing at the time of transfer. Based upon the site restoration assessment, the parties to the transfer must propose to the DNR a funding schedule for the site-specific trust account, providing for some contribution to the account at the time of transfer and at least quarterly payment thereafter. If the DNR approves the establishment and funding of the site-specific trust account, the purchaser will thereafter be the responsible party to the state, except that the failure of a transferring party to make a good faith disclosure of all oil field site conditions existing at the time of the transfer will render that party liable for the costs of restoration of such undisclosed conditions in excess of the balance of the site-specific trust fund. OIL SALES AND TRANSPORTATION RATES. The FERC also regulates rates and service conditions for interstate transportation of crude oil, liquids and condensate, which can affect the amount the Company receives from the sale of these products. Rates for such transportation are generally subject to an indexing system under which rates may be increased as long as they do not exceed an index rate that is tied to inflation. Over time, this indexing system could have the effect of increasing the cost of transporting crude oil, liquids and condensate by pipeline. Sales of crude oil, condensate and gas liquids by the Company are not regulated and are made at market prices. The price the Company receives from the sale of these products is affected by the cost of transporting the products to market. ENVIRONMENTAL MATTERS. The Company's oil and natural gas exploration, development and production operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the U.S. Environmental Protection Agency ("EPA"), issue regulations to implement and enforce such laws, which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties or may result in injunctive relief for failure to comply. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require remedial action to prevent pollution from former operations, such as plugging abandoned wells, or closing pits, and impose substantial liabilities for pollution resulting from the Company's operations. In addition, these laws and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist. The regulatory burden on the oil and gas industry increases the cost of doing business and consequently affects its profitability. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal or cleanup requirements could have a material adverse effect on the Company's operations and financial position, as well as those of the oil and gas industry in general. While management believes that the Company is in substantial compliance with current applicable environmental laws and regulations and the Company has neither experienced any material adverse effect nor experts any significant capital expenditures from compliance with these environmental requirements, there is no assurance that this trend will continue in the future. The Comprehensive Environmental Response, Compensation and Liability Act, as amended ("CERCLA"), also known as "Superfund," and comparable state laws imposes liability without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a "hazardous substance" into the environment. These persons include (i) the current owner and operator of a facility from which hazardous substances are released, (ii) owners and operators of the facility at the time the disposal of hazardous substances took place, (iii) generators of hazardous substances who arranged for the disposal or treatment at or transportation to such facility of hazardous substances and (iv) transporters of hazardous substances to disposal or treatment facilities selected by them. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants into the environment. Furthermore, although petroleum, including crude oil and natural gas, is exempt from CERCLA, at least two courts have ruled that certain wastes associated with the 18 production of crude oil may be classified as "hazardous substances" under CERCLA, and thus such wastes may become subject to liability and regulation under CERCLA. Regulatory programs aimed at remediation of environmental releases could have a similar impact on the Company. The Resource Conservation and Recovery Act, as amended ("RCRA"), generally does not regulate most wastes generated by the exploration and production of oil and gas. RCRA specifically excludes from the definition of hazardous waste "drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy." However, these wastes may be regulated by EPA or state agencies as solid waste. Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils, may be regulated as hazardous waste. Pipelines used to transfer oil and gas may also generate some hazardous wastes. Although the costs of managing solid and hazardous waste may be significant, the Company does not expect to experience more burdensome costs than similarly situated companies involved in oil and gas exploration and production. The Company currently owns or leases, and has in the past owned or leased, numerous properties that for many years have been used for the exploration and production of oil and gas. Although the Company has used operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under the Company's control. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, the Company could be required to remove or remediate previously disposed wastes (including waste disposal of or released by prior owners or operators), or property contamination (including groundwater contamination by prior owners or operators), or to perform remedial plugging or pit closure operations to prevent future contamination. The Federal Water Pollution Control Act of 1972 as amended ("FWPCA"), also known as the Clean Water Act ("CWA") and analogous state laws, impose restrictions and strict controls regarding the discharge of pollutants including produced waters and other oil and gas wastes, into state waters or waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accord with the terms of a permit issued by EPA or the state. These proscriptions also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers. Sanctions for unauthorized discharges include administrative, civil and criminal penalties, as well as injunctive relief. The Oil Pollution Act of 1990, as amended ("OPA"), pertains to the prevention of and response to spills or discharges of hazardous substances or oil into navigable waters of the United States. Under OPA, a person owning or operating a facility or equipment (including land drilling equipment) from which there is a discharge or threat of a discharge of oil into or upon navigable waters or adjoining shorelines is liable, regardless of fault, as a "responsible party" for removal costs and damages. Federal law imposes strict, joint and several liability on facility owners for containment and clean-up costs and certain other damages, including natural resource damages, arising from a spill. The OPA establishes a liability limit for onshore facilities of $350 million; however, a party cannot take advantage of this liability limit if the spill is caused by gross negligence or willful misconduct or resulted from a violation of a federal safety, construction, or operating regulation. If a party fails to report a spill or cooperate in the cleanup, the liability limits otherwise do not apply. Federal regulations under the OPA and FWPCA also require certain owners and operators of facilities that store or otherwise handle oil, such as the Company, to prepare and implement spill prevention, control and countermeasure plans and spill response plans relating to possible discharge of oil into surface waters. The Company believes that it is in substantial compliance with the requirements of the OPA and FWPCA and that any non-compliance would not have a material adverse effect on the Company. COMPETITION The gas and oil industry is highly competitive in all of its phases. The Company encounters strong competition from other gas and oil companies in all areas of its operations, including the acquisition of exploratory and producing properties, the permitting and conducting of seismic surveys and the marketing of gas and oil. Many of these competitors possess greater financial, technical and other resources than the Company. Competition for the acquisition of producing properties is affected by the amount of funds available to the Company, information about 19 producing properties available to the Company and any standards the Company establishes from time to time for the minimum projected return on investment. Competition also may be presented by alternative fuel sources, including heating oil and other fossil fuels. There has been increased competition for lower risk development opportunities and for available sources of financing. In addition, the marketing and sale of natural gas and processed gas are competitive. Because the primary markets for natural gas liquids are refineries, petrochemical plants and fuel distributors, prices generally are set by or in competition with the prices for refined products in the petrochemical, fuel and motor gasoline markets. FACILITIES The Company leases approximately 7,600 square feet of office space in Houston, Texas, at an annual rent of $117,068. The lease expires in September 2001. The Company leases approximately 13,279 square feet of office space in Corpus Christi, Texas. The annual rent is $135,446, and the Lease expires on June 30, 2003. The Company currently has more office space than it needs in Houston, and has sublet a portion of its office space. EMPLOYEES The Company has eight (8) full-time employees in its Houston, Texas office, and 31 employees in its Corpus Christi, Texas office. Their functions include management, production, engineering, geology, geophysics, land, legal, gas marketing, accounting, financial planning and administration. Certain operations of the Company's field activities are accomplished through independent contractors who are supervised by the Company. The Company believes its relations with its employees and contractors are good. No employees of the Company are represented by a union. ITEM 2. DESCRIPTION OF PROPERTY PRINCIPAL AREAS OF OPERATIONS The Company owns and operates producing properties located in four states with proved reserves located primarily in Louisiana, Oklahoma and Texas. Daily production from both operated and non-operated wells net to the Company's interest averaged 1,794 Mcf per day and 24 Bbls of oil per day for the year ended December 31, 1998 and 5,526 Mcf per day and 41 Bbls of oil per day for the quarter ended December 31, 1998. These properties have provided most of the Company's revenues to date. DRILLING ACTIVITY In 1997, the Company participated in eight wells, drilled one sidetrack operation in an existing wellbore, which operations have resulted in two successful completions, six dry holes, and one unsuccessful sidetrack operation due to mechanical difficulties. These results were all prior to the Acquisitions in May 1998, at which time the exploration functions of the Company changed dramatically with new projects, new management and a new focus. Since November 1, 1997 (the effective date of the Acquisitions) through December 31, 1998, 24 wells have been drilled for the Company's account, of which twelve have been completed, eleven were dry holes and one was drilling. In the first quarter of 1999, the Company participated in the drilling of six additional wells, of which one had been completed, two are awaiting completion, one was a dry hole and two were drilling. PRODUCTIVE WELL SUMMARY The following table sets forth certain information regarding the Company's ownership as of December 31, 1998 of productive gas and oil wells in the areas indicated. 20
Gas Oil ---------------- ---------------- Gross Net Gross Net ------ ------- ----- ------ Texas ................................................ 12 2.73 4 0.75 Oklahoma ............................................. 3 0.01 5 0.08 Louisiana ............................................ 1 0.08 0 0.00 Kansas ............................................... 1 0.10 0 0.00 ------ ------- ----- ------ Total ............................................ 17 2.92 9 0.83 ------ ------- ----- ------ ------ ------- ----- ------
VOLUMES, PRICES AND PRODUCTION COSTS The following table sets forth certain information regarding the production volumes, average prices received (net of transportation) and average production costs associated with the Company's sale of gas and oil for the periods indicated.
Year Ended December 31, -------------------------------------- 1998 1997 --------------- ----------------- Net Production: Oil (Bbl) ........................................................ 8,878 7,286 Gas (Mcf)......................................................... 653,325(1) 121,304 Gas equivalent (Mcfe)............................................. 706,593(1) 165,020 Average sales price: Oil ($ per Bbl)................................................... $ 10.92 $ 20.28 Gas ($ per Mcf)................................................... $ 1.95 $ 2.06 Average production expenses and taxes ($ per Mcfe)........................ $ 0.52 $ 2.13(2)
(1) The majority of the net production is attributable to the fourth quarter of 1998, during which time additional exploration discoveries commenced production. (2) This computation includes $164,792 in costs associated with the fulfillment of contractual transportation obligations on the Company's Mobile Bay Properties. If this amount were not included, the average production expenses and taxes per Mcfe would have been $1.13. LEASEHOLD ACREAGE The following table sets forth as of December 31, 1998, the gross and net acres of proved developed and proved undeveloped gas and oil leases which the Company holds or has the right to acquire. It does not include unproven acreage, which constitutes the majority of the Company's leasehold position.
PROVED DEVELOPED PROVED UNDEVELOPED -------------------- -------------------- STATE GROSS NET GROSS NET ----- -------- ------- -------- ---------- Arkansas ................................................. 0.0 0.0 6,360.0 2,544.0 Kansas ................................................... 640.0 30.6 0.0 0.0 Louisiana ................................................ 225.0 225.0 9,215.0 3,910.5 Oklahoma ................................................. 2,117.0 50.4 12,908.5 3,727.2 Texas .................................................... 3,016.0 1,390.2 6,980.5 1,339.0 ------- ------- -------- -------- Total ............................................ 5,998.0 1,696.2 35,464.0 11,520.7 ------- ------- -------- -------- ------- ------- -------- --------
21 TITLE TO PROPERTIES Title to properties is subject to royalty, overriding royalty, carried working, net profits, working and other similar interests and contractual arrangements customary in the gas and oil industry, liens for current taxes not yet due and other encumbrances. As is customary in the industry in the case of undeveloped properties, little investigation of record title is made at the time of acquisition (other than a preliminary review of local records). Investigations including a title opinion of local counsel generally are made before commencement of drilling operations. The Company has granted to an affiliate of a major public utility a mortgage on its interest in the Starboard Project to secure repayment of the funding provided by the affiliate and relating to the prospect, and has granted to Bank of America NT&SA ("B of A") a mortgage on virtually all remaining gas and oil properties to secure repayment of its credit facility with the bank and with Duke Energy Field Services, Inc. ("Duke"). B of A serves as collateral agent for both B of A and Duke pursuant to an intercreditor agreement between each of them and the Company. ITEM 3. LEGAL PROCEEDINGS EPC was a defendant in a lawsuit regarding injuries to a oil field worker not employed by the Company that resulted in a judgment against EPC of approximately $17,700,000. The judgment was settled by EPC's insurers, who agreed to make cash payments to the plaintiff, and by EPC who agreed to implement a mutually agreeable work safety plan in exchange for approximately $6.0 million in punitive damages that otherwise would have been payable to the plaintiff. The settlement was entered into and approved by the court entering an agreed judgment on December 3, 1997. On approximately April 16, 1998, the plaintiff filed an action against both EPC and the Company alleging, in part, that EPC has failed and refused to implement an appropriate safety plan and entered into negotiations with the Company to convey material assets to it which, if consummated, would negate plaintiffs benefits to be obtained by EPC's safety plan, thereby fraudulently inducing plaintiff to settle the judgment against EPC. The Company believes the claims are not supported by the facts and are without merit. The Company has in fact implemented a safety plan as part of its business strategy which it believes equals or exceeds the one EPC agreed to implement. It took this action as part of its business activities and not due to any obligation it believes exists to the Plaintiff. The Company and EPC have been advised by counsel for the plaintiff that the litigation will be dismissed subject to agreement on a procedure for verification of the Company's ongoing safety plan. Charles J. Smith and Michael E. Johnson, shareholders of 100% of the common stock of EPC, have indemnified the Company in the event that any damages were to be assessed against the Company. In the event it is not timely dismissed, the Company and EPC will vigorously defend the claims and the Company does not believe it will sustain any material loss. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS On December 3, 1998 the Company held its Annual Meeting of Shareholders. At said meeting Mr. Hobart Smith and Mr. William D. Dodge III were re-elected as directors with their new terms expiring at the Annual Stockholders Meeting in 2001. The vote totals were as follows:
Number of Number of Shares Number of Shares Voted Shares Voted Shares For: Against: Abstained William D. Dodge III 14,431,500 233 19,046 Hobart A. Smith 14,431,566 167 29,213
There was no further business submitted to the shareholders for a vote. 22 PART II ITEM 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS On November 12, 1993, the Company's predecessor, Frontier Natural Gas Corporation's common stock, its Convertible Preferred Stock and its Series A Warrants were all admitted to trading on the NASDAQ Small Cap Market under the symbols "FNGC" for its common stock, "FNGCP" for its Convertible Preferred Stock, and "FNGCW" for its Series A Warrants. All of the issued and outstanding Convertible Preferred Stock was redeemed in June of 1998. The Series A Warrants expired in November of 1998. On August 9, 1996, Frontier Natural Gas Corporation's Series B Warrants were admitted to trading on the NASDAQ Small Cap Market under the symbol "FNGCZ". In May of 1998 the Company reincorporated in the State of Delaware and changed its name to Esenjay Exploration, Inc. Its common stock trading symbol changed to "ESNJ" and its Series B Warrant symbol to "ESNJZ". The Series B Warrants ceased to be listed on the NASDAQ Small Cap Market in February of 1999 due to insufficient market makers and are not currently listed on any national market. The Company's common stock trades on the NASDAQ Small Cap Market under the symbol "ESNJ". The Company estimates there are approximately 95 common shareholders of record and 2,355 beneficial owners of the common stock.
Convertible Series A Series B Common Preferred Warrants(1) Warrants -------------------- ------------------ ----------------- -------------------- Quarter Ended High Low High Low High Low High Low - ------------- --------- -------- ------- ------ ------- ------- --------- --------- December 31, 1998 $ 3 3/16 $ 1 1/2 -- -- 5/32 1/32 September 30, 1998 4 3/8 1 13/16 -- -- 7/32 1/32 June 30, 1998 6 3/8 4 10 1/2 10 1/2 3/16 1/16 March 31, 1998 7 1/8 4 1/8 10 7/8 7 1/8 1/4 1/16 December 31, 1997 $12 $ 4 1/8 8 1/2 7 1/8 3/8 1/64 7/16 3/32 September 30, 1997 12 3 3/4 9 7 1/4 3/16 1/16 3/4 1/8 June 30, 1997 14 1/4 10 1/8 10 9 5/16 3/16 15/16 1/2 March 31, 1997 21 3/8 12 3/8 10 5/8 9 1/2 5/32 1 11/16 11/16
(1) The Series A Warrants expired in November 1998. There were no 1998 trades recorded prior to their expiration. ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION The following discussion and analysis reviews Esenjay Exploration, Inc.'s and/or its predecessor Frontier Natural Gas Corporation's operations for the twelve month periods ended December 31, 1998 and 1997 and should be read in conjunction with the consolidated financial statements and notes related thereto. Certain statements contained herein that set forth management's intentions, plans, beliefs, expectations or predictions of the future are forward-looking statements. It is important to note that actual results could differ materially from those projected in such forward-looking statements. The risks and uncertainties include but are not limited to potential unfavorable or uncertain results of 3-D seismic surveys not yet completed, drilling costs and operational uncertainties, risks associated with quantities of total reserves and rates of production from existing gas and oil reserves and pricing assumptions of said reserves, potential delays in the timing of planned operations, competition and other risks associated with permitting seismic surveys and with leasing gas and oil properties, potential cost overruns, potential dry holes and regulatory uncertainties and the availability of capital to fund planned expenditures as well as general industry and market conditions. OVERVIEW OVERVIEW OF HISTORICAL DEVELOPMENTS - INCEPTION THROUGH MAY 1998. In mid-1996, the Company refocused its activities from acquiring gas reserves principally in the Mid-Continent region of the United States to concentrate on exploration and related development drilling projects in Southern Louisiana and along the Gulf Coast 23 region of Alabama, Mississippi and Texas. During 1996 and 1997, the Company's drilling activities, which were based primarily on 2-D seismic data, were largely unsuccessful. This fact, along with an unexpected drop in production from the Company's Mobile Bay area wells, greatly reduced the Company's cash and capital resources. To address the Company's capital needs, the Board of Directors, at its meeting on August 12, 1997, directed management to look for potential assets to acquire in exchange for the Company's Common Stock, to identify and review potential business consolidation opportunities, identify potential partners to help fund the Company's proposed drilling activities, and to consider any other avenues to strengthen the Company's capital resources and diversify its exploration opportunities. The Board also directed management to reduce overhead wherever prudently possible and the Company retained an investment advisor to aid in achieving these objectives. The Company explored a series of such transactions and the Board, after receipt of the advice of management and its investment advisor, and receipt of due diligence reports and other materials, unanimously agreed that a transaction with Aspect and EPC was the best option for the Company's shareholders. This process led to the Company entering into the Acquisition Agreement among the Company, EPC, and Aspect. This Acquisition Agreement, and certain provisions of it, required approval of the shareholders of the Company. At a special meeting of shareholders held on May 14, 1998 the shareholders approved the Acquisition Agreement, a recapitalization of the Company pursuant to which each outstanding share of common stock would convert into one-sixth (1/6) of a share of new common stock (the "Reverse Split"), a plan and agreement of merger pursuant to which the Company would reincorporate in the state of Delaware and would change its name to Esenjay Exploration, Inc. (the "Reincorporation"), and the election of seven directors. On May 14, 1998 after a Special Meeting of Shareholders, the Company closed the transactions provided for in the Acquisition Agreement, implemented the Reverse Split, and completed the Reincorporation. All references in the accompanying financial statements to the number of common shares have been restated to reflect the foregoing. In addition, as required by the Acquisition Agreement, the Company called for redemption, all of its issued and outstanding cumulative convertible preferred stock and did redeem said preferred stock. The result of the foregoing is that the Company conveyed a substantial majority of its Common Stock to acquire an array of significant technology enhanced natural gas oriented exploration projects. The Company believed the Acquisitions would facilitate expanded access to capital markets due to the value and diversity of its exploration project portfolio. The Company also believes the members of EPC's management that joined the Company after consummation of the acquisitions significantly enhanced the Company's management team. In connection with the Acquisitions, an affiliate of Enron Corp. exercised an option to exchange $3.8 million of debt Aspect owed to such Enron affiliate for 675,000 shares of the Company's Common Stock that would otherwise have been issued to Aspect in the Acquisitions, at an effective conversion rate of $5.63 per share. As a result of the Acquisitions and this exchange and the secondary public offering effective in July of 1998, EPC, Aspect and the Enron affiliate own approximately 32.8%, 27.7% and 4.3%, respectively, of the Company's Common Stock. On July 21, 1998 the Company closed an underwritten offering of 4,000,000 shares of its common stock at a price of $4.00 per share. The net proceeds to the Company were approximately $14,880,000. After the offering the Company had 15,762,723 shares outstanding. OVERVIEW OF CURRENT ACTIVITIES - SINCE MAY 1998. As a result of the above-described acquisitions, restructuring, and the underwritten offering, the Company believes it is positioned for a period of significant exploration activity on its technology enhanced projects. Many of the projects have reached the drilling stage. In many instances the requisite process of geological and/or engineering analysis, followed by acreage acquisition of leasehold rights and seismic permitting, and 3-D seismic field data acquisition, then processing of the data and finally its interpretation, took several years of time and the investment of significant capital. Management believes the acquisition of projects at this advanced stage has not only reduced the drilling risk, but should allow the Company to consistently drill on a broad array of exploration prospects in 1999 and subsequent years. On Exploration Projects acquired pursuant to the Acquisitions, the Company has participated in the drilling of twenty-four wells through December 31, 1998 with working interests which range from 8% to 79%. Out of the twenty-four wells drilled, twelve wells have been completed, eleven were dry holes, and one is being drilled. Several of the successful wells went into production late in the third quarter of 1998, and in the fourth quarter of 1998. In addition, in the first quarter of 1999, the Company participated in six additional wells of which one was completed, two are awaiting completion, two were 24 drilling, and one was dry. As a result, management believes net daily oil and gas production, which currently approximates 5,300 Mcfe per day, will increase to approximately 13,500 Mcfe per day as production from the new discoveries comes on line. The Company entered 1999 having gone from nominal second quarter 1998 gas and oil revenues of approximately $35,000 per month and large operating cash flow deficits to a company with over $360,000 per month in oil and gas revenues in the fourth quarter of 1998. This number is expected to exceed $700,000 per month as first quarter 1999 exploration discoveries come on line and continue to increase as additional wells are drilled. This should allow it to achieve positive operating cash flow in 1999 and beyond. In addition, since December 31, 1998, the Company has closed a long term financing commitment for $9,000,000 with Duke Energy Field Services, Inc., it has closed a sale of project interests to industry partners for a total of $3,768,500, and has entered into two agreements to sell additional project interests for a total of approximately $3,900,000. The closed financing, combined with the closed project sales, as well as those expected to close, will result in an aggregate availability of over $16,600,000 in available cash resources, which is expected to enhance working capital and contribute to the Company's early 1999 capital expenditure plan. (See "Liquidity and Capital Resources"). The Company will look to a variety of sources to fund its continuing capital expenditures budget, including it's new credit facilities and sales of promoted project interests to industry partners, as it seeks to maximize its interests and manage its risks while aggressively pursuing its exploration projects. (see "Liquidity and Capital Resources") SUCCESSFUL EFFORTS ACCOUNTING AND RELATED MATTERS. The Company utilizes the successful efforts method of accounting. Under this method it expenses its dry hole costs and the field acquisition costs of 3-D seismic data as incurred. The undeveloped properties which were acquired pursuant to the Acquisitions, and which were comprised primarily of interests in unproven 3-D seismic based projects, recorded in May of 1998 at an independently estimated fair market value of $54.2 million as determined by Cornerstone Ventures, L.P., a Houston, Texas based investment banking firm. Pursuant to the successful efforts method of accounting, the Company is amortizing such initial costs as periodic impairments of unproved properties on a straight-line basis over a period not to exceed forty-eight months, as well as recognizing property specific impairments. These non-cash charges effect all such costs which are not, in the accounting period they are to be impaired, supported by proven oil and gas reserves. Hence significant non-cash charges will likely depress reported earnings of the Company over the next several years, but will not effect cash flows provided by operating activities nor the ultimate realized value of the Company's natural gas and oil properties. As a result of the tax rules applicable to the Acquisitions, the Company will likely not be able to fully use its existing net operating loss carry forward in the future. YEAR 2000 The Company is exposed to the risk that the Year 2000 issue could cause system failures or miscalculations causing disruptions of operations, including, among other things, a temporary inability to process transactions, send joint interest billings, or engage in similar normal business activities. During 1998, the Company undertook a corporate-wide initiative designed to assess the impact of the Year 2000 issue on software and hardware utilized in the Company's operations. The Company's initiative is to be conducted in these phases: assessment, implementation and testing. During the assessment phase, the Company completed a comprehensive inventory of all "mission critical" systems and equipment. Many of the Company's systems include hardware and packaged software purchased from large vendors who have represented that these systems are already Year 2000 compliant. The Company relies on other producers and transmission companies to conduct its basic operations. Should any third party with which the Company has a material relationship fail, the impact could impair the Company's ability to perform its basic operation. Examples of such changes are an inability to transport production to market or an inability to continue drilling activities. As part of the Company's assessment phase, the Company will address the most reasonably likely worst-case scenarios and potential costs. The majority of the Company's technical applications are not date sensitive. Of those applications that are 25 date sensitive, most have recently been, or are currently being, upgraded. The Company intends to complete the testing of Year 2000 modifications during the third quarter of 1999. The Company has not established a contingency plan but intends to formulate one to address unavoidable risks, including those discussed above. The Company expects to have the contingency plan formulated by the third quarter of 1999. The Company's efforts with respect to the Year 2000 issue have been handled internally by management and other Company personnel. Costs of developing and carrying out this initiative are being funded from the Company's operations and have not represented a material expense to the Company. The Company has not completed its assessment but currently believes that the costs of addressing the Year 2000 issue should not be significant and should not have a material adverse impact on the Company's financial condition. COMPARISON OF 1998 TO 1997. All comparative discussions should be considered in the context of the Acquisitions closed on May 14, 1998, which, together with related changes significantly modified the scope, focus and the method of doing business of the Company. As a result, the comparisons are of more limited value when analyzing relevant trends. REVENUE. Total revenues increased 88.9% from $908,609 for the year ended December 31, 1997 to $1,716,473 for the year ended December 31, 1998. Total gas and oil revenues increased 106.6% from $664,126 to $1,372,002. The increase in gas and oil revenue was attributed mainly to revenues from wells placed into production during the third and fourth quarters of 1998. There was a decrease in gain on the sale of assets of $446,445 from $452,020 reported for 1997 to $5,375 reported for 1998. As a result of the increase in operations stemming from both exploratory and developmental drilling, operating fees increased 412.6% from $55,021 for 1997 to $282,020 for 1998. The Company realized a loss from various commodity transactions totaling $113,911 for 1998 as compared to $375,410 for 1997. These losses were attributed to various transactions in which the Company hedged its future gas delivery obligations as a requirement of its bank loan facility. In addition to the realized losses from commodity transactions, the Company recorded $128,936 in unrealized gain for 1998 as compared to an unrealized loss of $128,936 for 1997. This was due to the fact that by year end 1998 the Company's average production volumes exceeded the hedged volumes, and it was able to fulfill its hedge commitments. In addition to the foregoing, the Company had other revenues of $42,051 for 1998 as compared to $241,788 for 1997. COSTS AND EXPENSES. Total costs and expenses of the Company increased 429.4% from $5,862,412 for 1997 compared to $31,037,820 for 1998. The increases primarily relate to the changes in scope, focus and method of doing business which occurred upon closing of the Acquisitions. As a result, staffing and activity volume increased dramatically. Also foundational was the increase in 3-D seismic and other geological and geophysical work intended to lead to increased, risk-controlled drilling and ultimately increased gas and oil reserves and production. Increasing during the year were amortization of gas and oil properties, exploration costs-geological and geophysical, exploration costs-dry hole, general and administrative costs, depletion, depreciation, and amortization, interest expense and production taxes. Partially offsetting the foregoing increases were decreases in lease operating expenses, transportation and gathering costs, and delay rentals. AMORTIZATION OF UNPROVED PROPERTIES FOR IMPAIRMENT was $6,937,300 in 1998 (none in 1997). The Company will amortize the undeveloped and unevaluated value of the properties acquired pursuant to the Acquisitions over a period not to exceed forty-eight months. (See "Successful Efforts Accounting and Related Matters.") IMPAIRMENT OF GAS AND OIL PROPERTIES increased from $349,384 in 1997 to $5,832,024 in 1998. This non-cash impairment in 1998 is primarily the result of the expanded property base acquired pursuant to the Acquisitions. Management's periodic review of each individual Exploration Project resulted in the decision to expense the book value of certain projects based upon the belief that they no longer have a realistic potential to realize the book value from such projects in the future. The impairment charges incurred were primarily attributable to the Sheriff, Thompson Creek, and Vicksburg Phase II Exploration Projects. In addition, $1,560,990 of impairment was taken on producing properties for which the book value exceeded estimated future cash flow. 26 EXPLORATION COSTS - GEOLOGICAL AND GEOPHYSICAL increased 1,110.5% from $485,956 for 1997 to $5,882,307 for 1998. These exploration costs reflect the costs of topographical, geological and geophysical studies and include the expenses of geologists, geophysical crews and other costs of acquiring and analyzing 3-D seismic data. The Company's exploration technology enhanced exploration program on the Exploration Projects has required the acquisition and interpretation of substantial quantities of such data and these costs have greatly increased for 1998 as compared with 1997. The Company considers 3-D seismic data a valuable asset; however, its successful efforts accounting method requires such costs to be expensed for accounting purposes. EXPLORATION COSTS - DRY HOLE increased 194.1% from $1,772,746 for 1997 to $5,213,930 for 1998 as a result of increased drilling activity in 1998. During the year, the Company participated in the drilling of twenty-four wells of which eleven were dry holes that were expensed. GENERAL AND ADMINISTRATIVE EXPENSES increased 117.4% from $2,070,812 for 1997 as compared to $4,501,656 for 1998. This was primarily attributable to increases in operational expenses incurred after May 14, 1998, the effective date of the Acquisition Agreement with Aspect and EPC, and costs associated with the Acquisitions, after which time the scope of the Company's activities increased significantly. The primary components of general and administrative expenses were payroll and payroll taxes, which increased 125% from $936,304 in 1997 to $2,104,818 in 1998, legal, accounting and other professional services which increased 37% from $385,384 in 1997 to $528,705 in 1998. DEPLETION, DEPRECIATION AND AMORTIZATION ("DD&A") increased 382.1% from $315,880 for 1997 to $1,522,771 for 1998. The increase to DD&A was primarily attributable to wells placed in production in the third and fourth quarters of 1998. INTEREST EXPENSE increased 917.6% from $60,942 for 1997 to $620,121 for 1998. The increase in interest expense was primarily attributed to a credit facility with Duke Energy Financial Services, Inc. closed in February 1998 which was paid off in July, 1998 and an increase in borrowings pursuant to its credit facility with Bank of America NT & SA in October, 1998. The Company capitalized a large portion of its interest associated with its on-going projects, of which capitalized amounts totaled $456,901 for 1998 and $235,977 for 1997. PRODUCTION TAXES increased 290.8% from $24,497 for 1997 to $95,728 for 1998. The increase in production taxes was attributed to revenues of wells placed in production during the third and fourth quarters of 1998, which increase was partially offset by a production tax refund from the State of Oklahoma for a production enhancement project completed in 1994. LEASE OPERATING EXPENSE decreased 36.6% from $427,240 for 1997 to $270,881 for 1998. The reduction in lease operating expense relates back to ceased operational costs for the Company's Mobile Bay wells in 1997. Lease operating costs associated with the Mobile Bay wells for 1997 included $110,000 accrued for plugging and abandonment costs. During 1998, the Company reversed $68,739 of the accrual associated with these wells. These factors combined with lease operating expense increases during the third and fourth quarters of 1998 because of wells placed in production during those periods. Lease operating costs would have increased from $317,240 in 1997 to $339,620 were the Mobile Bay wells, which are plugged and abandoned, not included. The increases would be attributable to increased production activities in late 1998. TRANSPORTATION AND GATHERING COSTS decreased 98.8% from $143,265 for 1997 to $1,719 for 1998. The decrease in transportation and gathering cost was almost entirely attributable to the ceased production of the Mobile Bay Wells. DELAY RENTAL EXPENSE decreased 24.7% from $211,690 for 1997 to $159,383 for 1998. These rental payments were primarily associated with the Company's Starboard Prospect and various other prospects. The decrease was based upon the Company's decision to release certain leases not deemed significant after seismic evaluation. NET LOSS PER COMMON SHARE decreased from a net loss of $3.07 per share for 1997 to a net loss of $2.97 per share for 1998. There was an increase in net loss applicable to common stockholders of $24,312,527 from 1997 as compared to 1998, but it was more than offset by the increased number of weighted average common equivalent 27 shares at December 31, 1998, resulting from the Acquisitions which closed May 14, 1998, and the underwritten common stock offering closed July 21, 1998. Approximately 9,882,000 weighted average common equivalent shares were outstanding at December 31, 1998 as compared to approximately 1,646,000 at December 31, 1997. KNOWN AND ANTICIPATED TRENDS, CONTINGENCIES AND DEVELOPMENTS IMPACTING FUTURE OPERATING RESULTS. The Company's future operating results will be substantially dependent upon the success of the Company's efforts to develop the projects acquired in the Acquisitions, as well as its other prospects. While management believes that said projects represent the most promising prospects in the Company's history, and the wells drilled on projects acquired pursuant to the Acquisitions in 1998 substantially increased the Company's revenues, the capital expenditures planned in 1999 will continue to require substantial outlays of capital to explore, develop and produce. 1998 drilling results have in fact resulted in substantial revenue increases which were evidenced in the fourth quarter. Wells drilled in the fourth quarter of 1998 and first quarter of 1999 are expected to contribute to continued rapid increases in the Company monthly gas and oil revenues as they come on line in the first and second quarters of 1999. However, because of the Company's expanded 1999 drilling budget capital from sources other than cash flow from operations will continue to be required for funding planned exploration activities. LIQUIDITY AND CAPITAL RESOURCES The Company has budgeted approximately $24,000,000 to fund its 1999 capital budget which includes the drilling and/or completion of its interest in over 40 wells on the Exploration Projects in 1999. The Company's sources of financing include borrowing capacity under its existing credit facilities and other potential credit facilities, the sale of promoted interests in the Exploration Projects to industry partners and cash provided from operations. The Company entered 1999 having gone from nominal second quarter 1998 gas and oil production of approximately $35,000 per month and large operating cash flow deficits to a company which averaged over $360,000 per month in oil and gas revenues in the fourth quarter of 1998, most of which is attributable to wells which commenced production in September and throughout the fourth quarter of 1998. This number is expected to continue to increase. The Company believes it will exceed $700,000 per month as exploratory discoveries from the first quarter of 1999 come on line. Additional drilling success in 1999 is expected to continue the trend of rapid increases. This should allow it to achieve steadily increasing operating cash flow throughout the year (prior to capital expenditures and new 3-D seismic data acquisition costs, which costs the successful efforts accounting method utilized by the Company mandate to be expensed rather than capitalized). In addition, since December 31, 1998, the Company has closed long term financings for $9,000,000, closed the sale of project interests for $3,768,500, and has entered preliminary agreements to sell certain project interests to two industry partners for a total of approximately $3,900,000. The resultant aggregate availability of approximately $16,600,000 in cash is expected to enhance working capital and fund the Company's exploration plan into the second quarter of 1999. The two transactions include a sale to Helmerich & Payne, Inc. ("H&P") and a sale to Aspect Resources LLC ("Aspect"), an affiliate. The Company has entered an agreement to sell to H&P all of its undeveloped property interests in the Big Hill/Stowell project area and any interests in a project area called Gill East for $1,300,000. Closing is to occur in May 1999. It has also entered into an agreement to sell to Aspect a 12.5% (of 100%) interest in the Caney Creek Project, a 12% (of 100%) interest in the Gillock Project, and all of the Company's undeveloped property interests in the West Beaumont project area for $2,610,000. Closing is scheduled for April 1999. Proceeds from the sale will be used to settle amounts due Aspect. In that Aspect is a related party, closing is subject to receipt of an independent fairness opinion which management believes will be timely obtained. On October 23, 1998, the Company amended and restated its credit agreement dated January 3, 1996 with B of A. The amended agreement is in a total amount of $20,000,000 and provided for an immediate borrowing base of up to $9,000,000. The Company had drawn $7,500,000 pursuant to the B of A loan facility as of December 31, 1998, and March 26, 1999. The loan is in two tranches. Tranche A is a revolving facility with no required principal payments for two years after which it converts into a thirty-six month term loan. Tranche B is payable in interest only 28 until maturity in eighteen months. Both loans are at a varied interest rate utilizing either the B of A's Alternate Reference Rate (Alternate Reference Rate is the greater of (i) B of A's Reference Rate and (ii) the Federal Funds effective rate plus 0.50%) or the London Interbank rate plus 2% for Tranche A and 4% for Tranche B. The remaining funds will be available for future drilling activities of the Company, subject to the approval of the bank. The Tranche A loan is secured by a mortgage on most proven properties currently owned by the Company. In addition, certain mortgages on the Company's exploration project inventory secure Tranche B of the credit facility with B of A as well as the entire credit facility with Duke discussed below. All such shared collateral is governed by an intercreditor agreement between B of A and Duke in which B of A serves as the collateral agent. In addition to the foregoing, B of A received a 2.0% overriding royalty interest, proportionately reduced to the Company's net interest, in the properties classified as proven as of the date of closing and received a five year warrant to purchase 95,000 shares of common stock at a price equal to the average daily closing price of the Company's common stock for the thirty days prior to closing of the credit agreement. The credit agreement does not provide for any additional overriding interests in favor of B of A. Proceeds of the loan primarily supplement working capital and exploration costs. On January 28, 1999, the Company closed a credit facility with Duke. This facility provides for Duke to loan up to $9,000,000 to the Company for eighteen months. The commitment reduces by $930,000 per quarter for five quarters and reduces to zero on August 1, 2000. Principal outstanding cannot exceed the commitment amount at any time. Duke is paid interest at a rate of prime plus 4%. It also received a right to gather and process, at fair market value, gas and condensate from a designated area of interest, and a net revenue interest in certain of the Company's future drilling activities not to exceed 0.49% of the Company's net interest. Proceeds primarily supplement exploration costs. On January 28, 1999, the Company, B of A, and Duke entered into an intercreditor agreement which governs the collateral which is used to secure the credit facility with B of A and the credit facility with Duke. Tranche A of the B of A credit facility is secured by a first mortgage on most of the Company's proven properties. Collateral securing amounts outstanding under both the Duke credit facility and Tranche B of the B of A facility is primarily comprised of mortgages taken on a significant proportion of the Exploration Projects of the Company which have not been developed. At such time as drilling is conducted on the Exploration Projects and proven reserves are discovered, the Company has a right to seek increases in the available amount to be drawn under Tranche A of its credit facility with B of A. In the event B of A agrees to increase the amounts available pursuant to Tranche A, then, subject to Duke's consent, security interests in proven reserves would be used as additional primary collateral on Tranche A loans from B of A supporting the borrowing availability increases. The Company will require additional sources of capital to fund its exploration budget over the next 12 months. It anticipates substantial growth of its credit facility with B of A as proven reserves of gas and oil are added by its exploration program. It also plans to continue to sell promoted interests in certain of its Exploration Projects to fund its exploration program over the next 12 months. In the second quarter of 1999, its capital expenditures budget will be significantly dependent upon sales of additional interests in the Exploration Projects. Delays in such new sales would delay the drilling of certain wells. The Company historically has addressed its long-term liquidity needs through the issuance of debt and equity securities, through bank credit and other credit facilities and with cash provided by operating activities. Its major obligations at March 26, 1999, consisted principally of (i) servicing loans under the credit facilities with B of A and with Duke and other loans, (ii) funding of the Company's exploration activities, and (iii) funding of the day-to-day operating costs. Many of the factors that may affect the Company's future operating performance and long-term liquidity are beyond the Company's control, including, but not limited to, oil and natural gas prices, governmental actions and taxes, the availability and attractiveness of financing and its operational results. The Company continues to examine alternative sources of long-term capital, the acquisition of a company with producing properties for common stock or other equity securities, including bank borrowings, the issuance of debt instruments, the sale of common stock or other equity securities, the issuance of net profits interests, sales of promoted interests in its Exploration Projects, and various forms of joint venture financing. In addition, the prices the Company receives for its future oil and natural gas production and the level of the Company's production will have a significant impact on future operating cash flows. 29 In order to minimize the pricing risk associated with oil and gas sales, the Company entered into hedging transactions aggregating a twenty-four month period with Bank of America's Financial Engineering and Risk Management Group. The hedging instruments called for the delivery of 4,700 MMBtu per day at prices which range from $2.07 to $2.14 per MMBtu for the period November 1, 1998 through October 31, 2000. WORKING CAPITAL. At December 31, 1998, the Company had a cash balance of $646,200 and a working capital deficit of $10,956,500. The working capital deficit was primarily attributable to substantial exploratory costs, including the substantial costs of 3-D seismic data acquisition and analysis, incurred in 1998, and deficit cash flow from operations before changes in working capital incurred in 1998. It was also effected by the fact that the Company received approximately $9,000,000 less in net proceeds then planned from the sale of common stock of the Company in the third quarter. In regard to said sale, the Company sold fewer shares for less money per share than planned in its July underwriting primarily due to market conditions beyond its control. Gas and oil revenues from wells which went into production in 1998 are anticipated to generate revenues which will equal or exceed ongoing costs of operations (prior to capital expenditures and the cost of new 3-D seismic data acquisitions) in the first half of 1999 and beyond. Since the end of 1998, the Company has closed the above-described credit facility with Duke, closed the sale of project interests to Xplor Energy, Inc. for approximately $3,768,500 and entered into two previously referenced agreements to sell additional project interests for approximately $3,900,000, which, if all closed, will have generated to the Company's account over $16,600,000 million in available cash resources subsequent to December 31, 1998. Such cash resources serve to substantially improve working capital and have served to provide significant funds for capital expenditures. Due to limited working capital as described above, the Company had slowed its exploration budget in the second half of 1998. Upon the closing of the credit facilities with B of A, the sale of certain promoted interests and exploration projects, and receipt of the Duke credit commitment, the Company increased its exploration activities in the first quarter of 1999. It plans to continue this more rapid pace of exploratory drilling activities. In order to fully implement its 1999 exploration budget while maintaining adequate working capital, the Company will rely upon additional sales of promoted project interests through the summer of 1999. In this regard, it has budgeted sales to industry partners netting approximately $10 million in net proceeds to the Company by the summer of 1999. Delays in projected sales would delay certain planned drilling. In the second half of the year, it projects certain increases in its Tranche A facility with B of A. It also expects continued rapid increases in monthly oil and gas revenues due to its exploration successes in the first quarter of 1999. Increased revenues are anticipated to generate significantly increasing cash flow as the year progresses, which cash flow will also further supplement the Company's working capital. SUMMARY. The Company believes it is positioned for a period of significant exploration activity on its technology enhanced projects. Many of the projects have reached the drilling stage. In many instances the requisite process of geological and/or engineering analysis, followed by acreage acquisition of leasehold rights and seismic permitting, and 3-D seismic field data acquisition, then processing of the data and finally its interpretation took several years of time and the investment of significant capital. Management believes the acquisition of projects at this advanced stage has not only reduced the drilling risk, but should allow the Company to consistently drill on a broad array of exploration prospects throughout 1999. As evidence of this activity the Company has participated in the drilling of twenty-two wells from March through December 31, 1998, with working interests which range from 8% to 79%. Out of the twenty-two wells drilled, ten wells were completed, eleven were dry holes and one was being drilled. In the first quarter of 1999 through March 31, 1999, the Company participated in the drilling of six wells, of which one was completed, two are awaiting completion, two were drilling, and one was a dry hole. The Company's recent drilling results have served to increase its confidence in its anticipated 1999 drilling on the technology enhanced Exploration Projects. The Company believes its monthly oil and gas revenues will exceed $700,000 per month (at current natural gas one year futures prices) when the recently drilled wells are all on line late in the second quarter. In that overhead is stable, operating cash flow should steadily and substantially increase throughout 1999. Additional exploration success would continue this positive trend. In that the Company will not fund most of its 1999 capital expenditure budget from cash flow, the Company will continue to look to a variety of sources to fund its continuing capital expenditures budget including credit facilities and sales of promoted project interests to industry partners, as it seeks to maximize its interests and manage its risks while aggressively pursuing its exploration projects. This process will be limited more by capital 30 availability than by its inventory of drillable prospects. Timing of funding its exploration budget will determine the pace of drilling and, to the extent drilling is successful, the growth of future oil and gas revenues. Management believes expanded credit facilities will be available to it in 1999 if it achieves meaningful exploratory and developmental drilling success, and that strategic sales of prospect interests will be contracted and closed which will allow it to continue its planned exploration activities throughout the year. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS. In 1997, the Financial Accounting Standards Board ("FASB") issued SFAS No. 128, "Earnings per Share" and SFAS No. 129, "Disclosure Information about Capital Structure," which have been reflected in the Company's year-end 1997 and 1998 financial statements. In 1997, FASB also issued SFAS No. 130, "Reporting Comprehensive Income", SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information", and SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities". SFAS Nos. 130 and 131 were adopted effective January 1, 1997. The adoption of those standards has had no impact on the Company's financial statement presentation or disclosures as the Company had no items of other comprehensive income and operates primarily in one segment. The Company is still evaluating the impact of the application of SFAS No. 133, which when adopted, could have a material effect on its financial position, liquidity or results of operations. ITEM 6A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS. Market risk generally represents the risk that losses may occur in the value of financial instruments as a result of movements in interest rates, foreign currency exchange rates and commodity prices. The Company has entered into interest-rate swap agreements to eliminate any movement in interest rate. The energy markets have historically been very volatile, and there can be no assurance that oil and gas prices will not be subject to wide fluctuations in the future. In an effort to reduce the pricing risks associated with oil and gas sales, the Company entered into hedging transactions aggregating a twenty-four month period with B of A's Financial Engineering and Risk Management Group. The hedging instruments called for the delivery of 4,700 MMBtu per day at prices which range from $2.07 to $2.14 per MMBtu for the period November 1, 1998 through October 31, 2000. While the use of these hedging arrangements limit the downside risk of adverse price movements, it also limits future gains from favorable movements to the extent of the hedged volumes. 31 ITEM 7. FINANCIAL STATEMENTS INDEPENDENT AUDITORS' REPORT To the Board of Directors Esenjay Exploration, Inc. We have audited the accompanying consolidated balance sheets of Esenjay Exploration, Inc. (formerly Frontier Natural Gas Corporation) and subsidiaries (the "Company") as of December 31, 1998 and 1997 and the related consolidated statements of operations, stockholders' equity and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 1998 and 1997, and the results of their operations and their cash flows for the years then ended in conformity with generally accepted accounting principles. Deloitte & Touche LLP Houston, Texas April 14, 1999 32 ESENJAY EXPLORATION, INC. CONSOLIDATED BALANCE SHEETS ASSETS
DECEMBER 31, DECEMBER 31, 1998 1997 --------------- -------------- Current assets: Cash and cash equivalents .............................. $ 646,200 $ 690,576 Accounts receivable, net of allowance for doubtful accounts of $348,984 at December 31, 1998 and $15,488 at December 31, 1997 ......................... 3,209,633 221,864 Prepaid expenses and other .............................. 122,422 249,328 Receivables from affiliates ............................. 963,700 105,171 --------------- -------------- Total current assets ........................... 4,941,955 1,266,939 Property and equipment ....................................... 70,044,882 4,404,975 Less accumulated depletion, depreciation and amortization ........................................ (15,517,656) (1,260,605) --------------- -------------- 54,527,226 3,144,370 Other assets ................................................. 447,091 164,699 --------------- -------------- Total assets ................................... $ 59,916,272 $ 4,576,008 --------------- -------------- --------------- --------------
33 ESENJAY EXPLORATION, INC. CONSOLIDATED BALANCE SHEETS LIABILITIES AND STOCKHOLDERS' EQUITY
DECEMBER 31, DECEMBER 31, 1998 1997 ------------ ------------ Current liabilities: Accounts payable .............................................................. $ 8,993,859 $ 911,396 Accounts payable to affiliate, net ............................................ 4,322,548 --- Revenue distribution payable .................................................. 1,996,091 68,131 Current portion of long-term debt ............................................. 101,236 401,085 Accrued and other liabilities ................................................. 484,756 299,704 ------------ ------------ Total current liabilities ............................................ 15,898,490 1,680,316 Long-term debt ..................................................................... 7,500,000 22,680 Non-recourse debt .................................................................. 864,000 864,000 Accrued interest on non-recourse debt .............................................. 331,194 194,274 Other long-term liabilities ........................................................ --- 9,918 ------------ ------------ Total liabilities .................................................... 24,593,684 2,771,188 Stockholders' equity: Cumulative convertible preferred stock $.01 par value; 5,000,000 shares authorized; 85,961 shares issued and outstanding at December 31, 1997 ($859,610 aggregate redemption and liquidation preference) ................. --- 860 Common stock: Class A common stock, $.01 par value; 40,000,000 shares authorized; 15,784,834 and 1,655,984 outstanding at December 31, 1998 and 1997, respectively (1) ............................ 157,849 16,560 Unamortized value of warrants issued .......................................... --- (27,163) Additional paid-in capital (1) ................................................ 77,651,602 14,751,425 Accumulated deficit ........................................................... (42,486,863) (12,936,862) ------------ ------------ Total stockholders' equity ........................................... 35,322,588 1,804,820 ------------ ------------ Total liabilities and stockholders' equity ........................... $ 59,916,272 $ 4,576,008 ------------ ------------ ------------ ------------
(1) As a result of the 1:6 reverse stock split effected on May 14, 1998, all numbers of shares and per share amounts have been restated for all periods presented. The accompanying notes are an integral part of these financial statements. 34 ESENJAY EXPLORATION, INC. CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31, ----------------------------------- 1998 1997 ------------- ------------ Revenues: Gas and oil revenues.................................................... $1,372,002 $ 664,126 Realized loss on commodity transactions................................. (113,911) (375,410) Unrealized gain (loss) on commodity transactions........................ 128,936 (128,936) Gain on sale of assets.................................................. 5,375 452,020 Operating fees.......................................................... 282,020 55,021 Other revenues.......................................................... 42,051 241,788 ------------- ------------ Total revenues................................................. 1,716,473 908,609 ------------- ------------ Costs and expenses: Lease operating expense................................................. 270,881 427,240 Production taxes........................................................ 95,728 24,497 Transportation and gathering costs...................................... 1,719 143,265 Depletion, depreciation and amortization................................ 1,522,771 315,880 Amortization of unproved properties..................................... 6,937,300 --- Impairment of oil and gas properties.................................... 5,832,024 349,384 Exploration costs-geological & geophysical.............................. 5,882,307 485,956 Exploration costs-dry hole.............................................. 5,213,930 1,772,746 Interest expense........................................................ 620,121 60,942 Delay rentals........................................................... 159,383 211,690 General and administrative 4,501,656 2,070,812 ------------- ------------ Total costs and expenses....................................... 31,037,820 5,862,412 ------------- ------------ Loss before provision for income taxes....................................... (29,321,347) (4,953,803) Benefit (provision) for income taxes......................................... --- --- Net loss .................................................................... (29,321,347) (4,953,803) Cumulative preferred stock dividend.......................................... 48,136 103,153 ------------- ------------ Net loss applicable to common stockholders................................... $(29,369,483) $(5,056,956) ------------- ------------ ------------- ------------ Net loss per common share (1)................................................ $ (2.97) $ (3.07) ------------- ------------ ------------- ------------ Weighted average number of common shares outstanding (1)..................... 9,882,227 1,646,311 ------------- ------------ ------------- ------------
(1) As a result of the 1:6 reverse stock split effected on May 14, 1998, all numbers of shares and per share amounts have been restated for all periods presented. The accompanying notes are an integral part of these financial statements. 35 ESENJAY EXPLORATION, INC. CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
Preferred Class A Unamortized Stock Common Shares Value of Additional ------------------------------------------- Warrants Paid-in Accumulated Shares Amount Shares(1) Amount(1) Issued Capital(1) Deficit ------- ------ ---------- --------- ------------ ----------- ------------ Balance, December 31, 1996..... 85,961 $ 860 1,644,317 $ 16,443 $(54,325) $14,681,542 $ (7,905,694) Issuance of common stock................. -- -- 11,667 117 -- 69,883 -- Cumulative preferred stock dividend.............. -- -- -- -- -- -- (77,365) Amortization of warrants.............. -- -- -- -- 27,162 -- -- Net loss................ -- -- -- -- -- -- (4,953,803) ------- ----- ---------- -------- -------- ----------- ------------ Balance, December 31, 1997 .... 85,961 860 1,655,984 16,560 (27,163) 14,751,425 (12,936,862) Issuance of common stock for Acquisitions, net..... -- -- 10,106,700 101,067 -- 49,360,831 -- Redemption of preferred stock (85,961) (860) -- -- -- (858,750) (228,654) Amortization of warrants.............. -- -- -- -- 27,163 -- -- Secondary common stock offering, net................... 4,000,000 40,000 14,364,980 -- Issuance of common stock................. 22,150 222 33,116 -- Net loss................ (29,321,347) ------- ----- ---------- -------- -------- ----------- ------------ Balance, December 31, 1998..... -- $ -- 15,784,834 $157,849 $ -- $77,651,602 $(42,486,863) ------- ----- ---------- -------- -------- ----------- ------------ ------- ----- ---------- -------- -------- ----------- ------------
(1) As a result of the 1:6 reverse stock split effected on May 14, 1998, all numbers of shares and per share amounts have been restated for all periods presented. The accompanying notes are an integral part of these financial statements. 36 ESENJAY EXPLORATION, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31, ------------------------------------ 1998 1997 ------------ ----------- Cash flows from operating activities: Net loss .......................................................... $(29,321,347) $(4,953,803) Adjustments to reconcile net loss to net cash provided by (used in) operating activities: Depletion, depreciation and amortization ..................... 1,522,771 315,880 Amortization of unproven property............................. 6,937,300 -- Impairment of oil and gas properties.......................... 5,832,024 349,384 Exploration costs............................................. 11,096,237 2,258,702 Gain on sale of assets........................................ (5,375) (452,020) Gain on settlement of deferred compensation agreement......... -- (25,794) Amortization of financing costs and warrants.................. 136,677 46,128 Unrealized (gain) loss on commodity transitions............... (128,936) 128,936 Changes in operating assets and liabilities: Trade and affiliate receivables............................... (3,846,298) 191,882 Prepaid expenses.............................................. 126,906 198,418 Other assets.................................................. (372,941) 272,679 Trade and affiliate payables.................................. 11,405,011 186,174 Revenue distribution payable.................................. 1,927,960 (292,032) Accrued and other............................................. 440,990 (118,936) ------------ ----------- Net cash provided by (used in) operating activities........... 5,750,979 (1,894,402) ------------ ----------- Cash flows from investing activities: Capital expenditures - gas and oil properties...................... (29,818,845) (3,023,253) Capital expenditures - other property and equipment................ (300,724) (159,679) Proceeds from sale of assets....................................... 5,191,847 1,002,540 ------------ ----------- Net cash used in investing activities........................... (24,927,722) (2,180,392) ------------ ----------- Cash flows from financing activities: Proceeds from issuance of debt..................................... 15,800,000 182,382 Repayments of long-term debt....................................... (8,641,494) (296,303) Preferred stock redeemed........................................... (859,610) -- Preferred stock dividends paid..................................... (228,654) (77,365) Net proceeds from issuance of common stock......................... 14,438,318 -- Cost of issuing stock.............................................. (1,376,193) -- ------------ ----------- Net cash provided by (used in) financing activities............. 19,132,367 (191,286) ------------ ----------- Net decrease in cash and cash equivalents.......................... (44,376) (4,266,080) Cash and cash equivalents at beginning of year.......................... 690,576 4,956,656 ------------ ----------- Cash and cash equivalents at end of year................................ $ 646,200 $ 690,576 ------------ ----------- ------------ ----------- Supplemental disclosure of cash flow information: Cash paid for interest............................................. $ 835,186 $ 141,356 37 Supplemental disclosure of non-cash investing and financing activities: Acquisition of oil and gas properties........................... $54,218,750 -- Assumption of exploration and other costs....................... 2,380,659 -- Assumption of related liabilities............................... 1,000,000 -- Issuance of 10,106,722 shares of common stock................... 50,838,091 --
The accompanying notes are an integral part of these financial statements. 38 ESENJAY EXPLORATION, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: BASIS OF PRESENTATION - Esenjay Exploration, Inc.'s (the "Company") primary business activities include gas and oil exploration, production and sales, primarily along the Texas and Louisiana Gulf Coast areas of the United States. The accompanying consolidated financial statements include the accounts of the Company, and its subsidiaries. All significant intercompany accounts and transactions have been eliminated upon consolidation. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates. Certain amounts from previous years have been reclassified to conform to current presentation. CASH EQUIVALENTS - The Company considers all investments with a maturity of three months or less when purchased to be cash equivalents. GAS AND OIL PROPERTIES - The Company uses the successful efforts method of accounting for gas and oil exploration and development costs. All costs of acquired wells, productive exploratory wells, and development wells are capitalized and depleted by the unit of production method based upon estimated proved developed reserves. Exploratory dry hole costs, geological and geophysical costs, and lease rentals on non-producing leases are expensed as incurred. Gas and oil leasehold acquisition costs are capitalized. Costs of unproved properties are transferred to proved properties when reserves are proved. Gains or losses on sale of leases and equipment are recorded in income as incurred and depleted by the unit of production method based upon estimated proved reserves. Valuation allowances are provided if the net capitalized costs of gas and oil properties at the field level exceed their realizable values based on expected future cash flows. This analysis resulted in $1,560,990 of impairment charges during 1998. Unproved properties are periodically assessed for impairment and, if necessary, a loss is recognized. Impairments of $4,271,034 and $349,384 were recognized in 1998 and 1997, respectively. In addition, the $54,200,000 fair market value assigned to unproven gas and oil exploration projects contributed by Esenjay Petroleum Corporation ("EPC") and Aspect Resources LLC ("Aspect") pursuant to certain acquisitions of undeveloped exploration projects (the "Acquisitions") which closed on May 14, 1998 is, until such time as the book value of each such project is either drilled and transferred to producing properties or is otherwise evaluated as impaired, are being amortized on a straight-line basis over a period not to exceed forty-eight months. For the year ended December 31, 1998, such amortization was $6,937,300. The costs of multiple producing properties acquired in a single transaction are allocated to individual producing properties based on estimates of gas and oil reserves and future cash flows. OTHER PROPERTY AND EQUIPMENT - Other property and equipment is carried at cost. The Company provides for depreciation of other property and equipment using the straight-line method over the estimated useful lives of the assets, which range from three to ten years. Upon sale or retirement of an asset, the cost of the asset disposed of and the related accumulated depreciation are removed from the accounts, and the resulting gain or loss is reflected in income. INCOME TAXES - The Company accounts for income taxes on an asset and liability method which requires, among other things, the recognition of deferred tax liabilities and assets for the tax effects of temporary differences between the financial and tax bases of assets and liabilities, operating loss carryforwards, and tax credit carryforwards. 39 COMMODITY TRANSACTIONS - The Company attempts to minimize the price risk of a portion of its future oil and gas production with commodity futures contracts. Gains and losses on these contracts are recognized in the period in which revenue from the related gas and oil production is recorded or when the contracts are closed. To the extent that the quantities hedged under the commodity transaction exceed current production, the Company recognizes gains or losses on the overhedged amount. CAPITALIZED INTEREST - The Company capitalizes interest costs incurred on exploration projects. Interest capitalized for the years ended December 31, 1998 and 1997 was approximately $456,901 and $235,977, respectively. GAS BALANCING - The Company records gas revenue based on the entitlement method. Under this method, recognition of revenue is based on the Company's pro-rata share of each well's production. During such time as the Company's sales of gas exceed its pro-rata ownership in a well, a liability is recorded, and conversely a receivable is recorded for wells in which the Company's sales of gas are less than its pro-rata share. The Company's gas balancing position at December 31, 1998 and 1997 was approximately 31,298 MCF and 29,244 MCF overproduced, respectively. EXPLORATION COSTS - The Company expenses exploratory dry hole costs, geological and geophysical costs, and impairment of unproved properties. In 1998 and 1997, the Company expensed $5,882,307 and $485,956 in geological and geophysical costs respectively and $5,213,930 and $1,772,746 in dry hole costs respectively. FAIR VALUE OF FINANCIAL INSTRUMENTS - Statement of Financial Accounting Standards No. 107. "Disclosures about Fair Value of Financial Instruments" requires disclosure regarding the fair value of financial instruments for which it is practical to estimate that value. The carrying amount of cash and cash equivalents, accounts receivable and accounts payable, approximates fair market value because of the short maturity of those instruments. The fair value of the Company's long-term debt is estimated to approximate carrying value based on the borrowing rates currently available to the Company for bank loans with similar terms and average maturities. The Company has interest rate and gas swap agreements that subject it to off-balance sheet risk. The unrealized losses on these contracts, as disclosed in the following footnotes, are based on market quotes. These unrealized losses are not recorded in the consolidated financial statements to the extent the swaps qualify for hedge accounting. EARNINGS PER SHARE - Basic earnings per share has been computed by dividing net income to common shareholders by the weighted average number of common shares outstanding. Diluted earnings per share is calculated by dividing net income to common shareholders by the weighted average number of common shares outstanding plus dilutive potential common shares. For the years ended December 31, 1998 and 1997 all potentially diluted securities are anti-dilutive and therefore are not included in the earnings per share calculation. The following table presents information necessary to calculate basic and diluted earnings per share for the periods indicated:
1998 1997 ------------ ----------- BASIC AND DILUTED EARNINGS PER SHARE Weighted average common shares outstanding ............... 9,882,227 1,646,311 Basic and diluted loss per share.......................... $ (2.97) $ (3.07) ------------ ----------- EARNINGS FOR BASIC AND DILUTED COMPUTATION Net loss.................................................. $(29,321,347) $(4,953,803) Preferred share dividends................................. (48,136) (103,153) ------------ ----------- Net loss to common shareholders (basic and diluted loss per share computation)............................. $(29,369,483) $(5,056,956) ------------ ----------- ------------ -----------
40 2. RECENT EVENTS On January 28, 1999, the Company closed a credit facility with Duke Energy Financial Services, Inc. ("Duke"). This facility provides for Duke to loan up to $9,000,000 to the Company for eighteen months. The commitment reduces by $930,000 per quarter for five quarters and reduces to zero on August 1, 2000. Principal outstanding cannot exceed the commitment amount at any time. Duke is paid interest at a rate of prime plus 4%. Duke also received a right to gather and process, at fair market value, gas and condensate from a designated area of interest, and a net revenue interest in certain of the Company's future drilling activities not to exceed 0.49% of the Company's net interest. Proceeds from the credit facility will primarily supplement exploration costs. On January 28, 1999, the Company, Bank of America NT&SA ("B of A"), and Duke entered into an intercreditor agreement which governs the collateral which is used to secure the credit facility with B of A and the credit facility with Duke. Tranche A of the B of A credit facility is secured by a first mortgage on most of the Company's proven properties at a given point in time. Collateral securing amounts outstanding under both the Duke credit facility and Tranche B of the B of A facility is primarily comprised of mortgages taken on a significant proportion of the exploration projects of the Company which have not been developed. At such time as drilling is conducted on the exploration projects and proven reserves are discovered, the Company has a right to seek increases in the available amount to be drawn under Tranche A of its credit facility with B of A. In the event B of A agrees to increase the amounts available pursuant to Tranche A, then, subject to Duke's consent, security interests in proven reserves would be used as additional primary collateral on Tranche A loans from B of A supporting the borrowing availability increases. In January 13, 1999, the Company closed the sale of approximately 23.45% of its interest in its Willacy County Project to a third party for $3,768,500 plus potential future additional payments based upon future drilling activity. On March 22, 1999, the Company entered into an agreement with Aspect to sell a 12.5% (of 100%) interest in the Caney Creek Project, a 12% (of 100%) interest in the Gillock Project, and all of the Company's undeveloped property interests in the West Beaumont project area for $2,610,000. Closing is scheduled for April 1999. In that Aspect is a related party, closing is subject to receipt of an independent fairness opinion which management believes will be timely obtained. Proceeds will be utilized to reduce net accounts payable of $4,322,548 at December 31, 1998 from the Company to Aspect. In addition, on March 31, 1999 the Company entered into an agreement with Helmerich & Payne, Inc. to sell all of its undeveloped property interests in the Big Hill/Stowell project area and an area called East Gill for $1,300,000. Closing is expected in April 1999. 3. STOCKHOLDERS' EQUITY: As a result of the Company's 1:6 reverse stock split effected May 14, 1998, all numbers of common shares and per share amounts have been restated for all periods. At December 31, 1996, the Company had 1,644,317 outstanding shares of $0.01 par value common stock and 85,961 shares of cumulative convertible preferred stock. In 1998 and 1997 the Company issued 14,128,850 and 11,667 additional shares of common stock, respectively. On May 14, 1998, the shareholders approved the January 19, 1998 Acquisition Agreement with EPC and Aspect. This agreement called for the Company to issue up to 5,165,260 shares of Common Stock, after giving effect to the reverse split, to EPC in exchange for undeveloped oil and gas prospects and to issue up to 4,941,440 shares of Common Stock, after giving effect to the reverse split, to Aspect in exchange for undeveloped oil and gas prospects. The combined assets of Aspect and EPC had a historical full cost basis of $19,900,000 and a fair value of $54,200,000 as determined by an independent assessment by Cornerstone Ventures L.P.. In addition, after November 1, 1997 (the effective date) and prior to the date of closing, EPC incurred approximately $3,800,000 in exploration and development costs and $300,000 in overhead costs associated with the prospects and Aspect incurred approximately $3,955,000 in such costs, all of which incurred costs were for the account of the Company. CUMULATIVE CONVERTIBLE PREFERRED STOCK - During 1998 and 1997, $48,136 and $77,365 was declared and paid in cumulative preferred stock dividends. In addition, during 1998 the Company paid dividends in arrears of 41 $180,518 ($1.50 per share) on its cumulative preferred stock for the period from May 1, 1995 to December 31, 1998. All shares of the cumulative convertible preferred stock were redeemed in May of 1998. WARRANTS - As of December 31, 1996, there were 263,013 Series A Warrants outstanding. All of the Series A Warrants expired on November 13, 1998. Since December 31, 1996, the Company has had Series B Warrants, which entitles the holder to purchase one-sixth (1/6) share of common stock for $12.15 commencing August 8, 1997, and ending August 8, 2001. Each Series B Warrant is redeemable by the Company with the prior consent of the underwriter at a price of $0.06 per Series B Warrant, at any time after the Series B Warrants become exercisable, upon not less than 30 days notice, if the last sale price of the common stock has been at least 200% of the then exercise price of the Series B Warrants for the 20 consecutive trading days ending on the third day prior to the date on which the notice of redemption is given. The Company had also issued a common stock warrant to purchase 4,167 shares of common stock at $24.00 per share in connection with a loan agreement. This warrant expired on November 13, 1998. The loan was paid in full in 1993. The Company and Hi-Chicago Trust agreed to a settlement in December 1995 whereby the Company issued 12,500 shares of common stock and a stock purchase warrant to purchase up to 50,000 shares of common stock at an exercise price of $18.00 per share to settle a claim asserted by Hi-Chicago Trust. The warrant is exercisable through the earlier of 60 months from the settlement date or for a period of 30 days after the closing bid price of the Company's stock equals or exceeds $36.00 per share for sixty consecutive trading days. The issued shares are unregistered. In 1996, the Company issued to a bank providing financing, a warrant to purchase up to 41,667 shares of common stock for a period of five years beginning January 3, 1996, at an exercise price of the highest average of the daily closing bid prices for thirty (30) consecutive trading days between January 1, 1996, and June 30, 1996. The Company has recorded the warrants at a value of approximately $82,500 as unamortized value of warrants issued. The warrants were amortized using the interest method and were fully amortized during 1998. The Company has also issued a warrant to purchase 41,667 shares of the Company's common stock at $12.00 per share to a financial advisor. The warrant has a five year term commencing on January 12, 1996 and provides for anti- dilution protection, registration rights, and permits partial exercise at the election of the holder by exchanging the warrants with appreciated value equal to each exercise price in lieu of cash. The Company has recorded the warrants at their fair value of approximately $33,000. On January 15, 1997, the Board of Directors authorized the Company to enter into an agreement with a company to perform investor relations services for the Company on a fee basis through January 15, 1999, and month to month thereafter, which fee may be paid either in cash or common stock at the election of the Company. The Company elected to compensate the investor relations firm partially in cash and partially in stock, therefore the investor relations firm was issued 11,667 shares of common stock during 1997 and 12,500 shares in 1998. In the first quarter of 1998, the Company, in connection with a financing arrangement, issued warrants to purchase 25,000 shares of common stock at an exercise price of $3.00 per share. On October 13, 1998, the Company entered into an amended credit agreement with B of A part of which called for the Company to issue warrants to purchase 95,000 shares of common stock at a price per share equal to the average daily closing price of the Company's common stock during the 30 calendar days prior to closing. The warrants have a five year term and provide for usual and customary anti-dilution protection, registration rights, and put and call provisions (including a call on the warrants if the stock price exceeds five times the strike price). EMPLOYEE OPTION PLAN-1997 - The plan authorizes the issuance of up to 115,892 options to purchase one share of common stock. Options to purchase 94,001 shares of common stock at prices ranging from $3.78 to $7.68 are currently outstanding. 42 Under the plan, the Board may grant options to officers and other employees. Each option shall consist of an option to purchase one share of common stock at an exercise price that shall be at least the fair market value of the Common stock on the date of the grant of the option. However, the Board may authorize vesting options as it deems necessary; such is the case of certain officers reissued options under this plan during 1997. Unless otherwise so designated, the options shall be exercisable at a rate of 33 1/3% on January 1, the year following the effective date of the grant, and 33 1/3% each January 1 thereafter. The Option holder's right is cumulative. Unless otherwise designated by the Board, if the employment of the Option holder is terminated for any reason, all unexercised Options shall terminate, be forfeited and shall lapse within three months thereafter. The options have a maximum life of ten years from the date of issuance. MANAGEMENT INCENTIVE STOCK PLAN - The Plan initially authorized the issuance of up to 40,000 units. Each unit consisted of (i) an option to purchase one share of Common Stock and (ii) a cash payment ("Stock Appreciation Right" or "SAR") to be made by the Company when the option is exercised. The value of the SAR was equal to twice the amount by which the fair market value of the Common Stock on the date of the exercise of the option exceeds the exercise price. Currently all units have expired or have been canceled by the Board of Directors and the plan is not effective. The following table summarizes activity under the Company's stock option plans for the years ended December 31, 1998 and 1997.
INCENTIVE MANAGEMENT STOCK INCENTIVE EMPLOYEE OPTION STOCK OPTION PLAN INCENTIVE STOCK PLAN OPTION PLAN 1997 PLAN 1997 ----------------- -------------------- ---------------- ----------------- 1998 1997 1998 1997 1998 1997 1998 1997 ---- ---- ---- ---- ---- ---- ---- ---- Shares available for grant.. --- --- --- --- --- 1,333 115,892 115,892 Shares under option at end of period................ --- --- --- 8,000 --- 20,333 94,001 100,167 Option price per share...... --- --- --- $12.00-21.00 --- $8.82-12.75 $3.78-7.68 $3.78-11.28 Shares exercisable at end of period................ --- --- --- 8,000 --- 6,778 90,667 90,667 Sales canceled.............. --- 30,000 --- 10,667 --- 36,667 --- --- Weighted option price....... --- --- --- $18.12 --- $10.02 $3.92 $4.20 Weighted average fair value of options granted during the year at market price --- $3.30
STOCK OPTION PLANS - The Company has one active fixed option plan which reserves shares of common stock for issuance to executives, key employees and directors. The Company has adopted the disclosure-only provisions of Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation". Accordingly, no compensation cost has been recognized for the stock option plans. Had compensation cost for the Company's stock option plans been determined based on fair value at the grant date for awards in 1998 and 1997 consistent with the provisions of SFAS No. 123, the Company's pro forma net loss applicable to common stockholders and net loss per common and common equivalent share would have been as indicated below:
1998 1997 ------------ ----------- Net loss applicable to common stockholders-as reported........... $(29,369,483) $(5,056,956) Net loss applicable to common stockholders-pro forma............. $(29,370,094) $(5,679,620) Net loss per common share-as reported............................ $(2.97) $(3.07) Net loss per common share-pro forma.............................. $(2.97) $(3.42)
The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions: no dividends; expected volatility of 60%; risk-free interest rate of 5.71% in 1998 and 1997; and expected lives of five (5) years. 43 OPTION REPRICINGS - In the last quarter of 1997, the Company determined to attempt to consummate a significant corporate transaction in order to satisfy the Company's need for additional capital resources. In connection with pursuing such a transaction, Mr. Berry and Mr. Christofferson entered into Incentive Agreements and Contract Settlement Agreements with the Company pursuant to which each of Mr. Berry and Mr. Christofferson were entitled to receive certain Incentive Payments and Contract Settlement Payments upon the consummation of such a transaction. The Acquisitions were such a transaction. Their employment agreements terminated upon the consummation of the Acquisitions. In negotiating the terms of the Incentive Agreements and Contract Settlement Agreements, Mr. Berry and Mr. Christofferson determined that their existing stock options would expire 90 days after their termination of employment. The Compensation Committee of the Board of Directors which was comprised of Messrs. Sweeny and Elliott, each of whom was an outside director, recognized that the expiration of those options would result in a disincentive for Mr. Berry and Mr. Christofferson to help the Company pursue a significant corporate transaction. Therefore, the Compensation Committee determined that Mr. Berry's and Mr. Christofferson's existing stock options should be canceled and replaced with new stock options that would terminate not sooner than the date their old options would have expired if their employment with the Company was not terminated. As an added incentive, the Compensation Committee determined to reprice Mr. Berry's and Mr. Christofferson's options so they could more readily benefit from any upturn in the Company's Common Stock trading price upon the consummation of a significant corporate transaction. When determining the price at which Mr. Berry's and Mr. Christofferson's new options would be exercisable, the Compensation Committee took the average closing price of the Company's Common Stock on the NASDAQ Small-Cap Market over the 20 day trading period immediately preceding the option reprice date, and multiplied such average trading price by 65%. The Compensation Committee believed that the discount to the average trading price was appropriate because the shares of Common Stock issuable upon exercise of the repriced options would not be freely tradable and the discount was appropriate to reflect the actual fair market value of the liquid shares that would be received upon the exercise of the new options. The following table sets forth certain information with respect to replacement stock options granted to Mr. Berry and Mr. Christofferson during the year ended December 31, 1997, which are also reported above under "Option Grants." There were no replacement stock options issued in 1998.
LENGTH OF NUMBER OF ORIGINAL OPTION SECURITIES OF TERM REMAINING UNDERLYING MARKET PRICE OF EXERCISE PRICE AT DATE OF OPTIONS/SARS STOCK AT TIME OF AT TIME OF NEW REPRICING OR REPRICED OR REPRICING OR REPRICING OR EXERCISE AMENDMENT NAME DATE AMENDED AMENDMENT AMENDMENT PRICE (MONTHS) ---- ------- ------------- ---------------- -------------- -------- ---------------- David W. Berry............ 12/3/97 20,000 $5.82 $ 9.72 $3.78 102 President and 12/3/97 4,000 $5.82 $18.60 $3.78 69 Chief Executive Officer David B. Christofferson... 12/3/97 30,000 $5.82 $10.08 $3.78 62 Executive Vice 12/3/97 4,000 $5.82 $18.60 $3.78 69 President, General 12/3/97 16,667 $5.82 $ 8.82 $3.78 102 Counsel and Secretary
4. SALE OF GAS AND OIL ASSETS AND SEISMIC DATA: The Company sold various properties in a number of different transactions during 1998 and 1997. These sales resulted in an aggregate gain of approximately $485,813 for 1997. No gain or loss was recorded on the sale of gas and oil assets in 1998 as these were the sale of partial interests in several unproved properties and the proceeds were treated as a recovery of costs. 44 5. LONG-TERM DEBT: Long-term debt consists of the following:
DECEMBER 31, -------------------------- 1998 1997 ---------- ------------ Note payable repaid in 1998....................................................... $ $274,922 Non-recourse loan, payable out of an 8% ORRI on the Starboard Prospect, interest accrued at 15%................................................................. 864,000 864,000 Note payable to bank, interest at 7.49% to 12.5%, payable in monthly installments, collateralized by other property and equipment................... 1,236 48,843 Note payable, interest at 12%, payable monthly, is currently due.................. 100,000 100,000 Loan with B of A, in two Tranches: Tranche A is a revolving credit facility which terminates October 13, 2000, thereafter converting the unpaid balance into a five year term loan requiring quarterly principle and interest payments; Tranche B is payable in interest only until maturity on April 13, 2000, at which time payment in full is required. Both loans are at a varied interest rate utilizing either the B of A's Alternative Reference Rate (Alternative Reference Rate is the greater of (i) B of A's Reference Rate and (ii) the Federal Funds effective rate plus 0.50%) or the Interbank rate plus 2% for Tranche A and 4% for Tranche B. The loan is secured by a mortgage on all properties currently owned by the Company 7,500,000 -- ---------- ------------ 8,465,236 1,287,765 Less current portion.............................................................. 101,236 401,085 ---------- ------------ $8,364,000 $886,680 ---------- ------------ ---------- ------------
Maturities of long-term debt (excluding non-recourse debt, which is solely dependent upon the successful development and future production, if any, of the Starboard Prospect) are as follows:
YEAR AT DECEMBER 31, --------------- 1998 --------------- 1999.................................................................... $ 101,236 2000.................................................................... 4,412,500 2001.................................................................... 650,000 2002.................................................................... 650,000 2003.................................................................... 650,000
The remaining balance of $1,137,500 will be paid in 2004 and 2005. 45 On October 13, 1998, the Company amended and restated the credit agreement dated January 3, 1996 with B of A to an amount equal to the lesser of the Collateral Value, or $20,000,000. The amended agreement provided for an immediate borrowing base of up to $9,000,000 ($8,250,000 if the Company did a third party financing in which the third party lender would share in certain collateral of B of A). The $9,000,000 base represents the Collateral Value until the initial Collateral Value Redetermination is made. The Company has drawn $7,500,000 pursuant to the B of A facility. The loan is in two tranches. Tranche A is a revolving facility which terminates on October 13, 2000 thereafter converting the unpaid balance into a five year term loan requiring quarterly principle and interest payments. Tranche B is payable in interest only until maturity on April, 13, 2000 at which time payment in full is required. In conjunction with this financing, B of A received a 2% overriding royalty interest, proportionately reduced to the Company's net interest, in the properties classified proven as of the date of closing and received a five year warrant to purchase 95,000 shares of common stock at a price equal to the average daily closing price of the Company's common stock for the thirty days prior to closing of the credit agreement. Proceeds of the loan primarily supplement working capital. As part of the credit agreement, the Company is subject to certain covenants and restrictions, among which are the limitations on additional borrowing, and sales of significant properties, working capital, cash, and net worth maintenance requirements and a minimum debt to net worth ratio. The covenants regarding financial condition of Company are as follows: Tangible Net Worth............................ $45,000,000 + 50% of Consolidated Net Income + 100% of net proceeds received from sale of any Non-Redeemable Stock Current Ratio................................. 1.1:1.0 Debt to Capitalization........................ 0.5:1.0 Interest Coverage Ratio ...................... 1.0:1.0 - 4th quarter 1998 and 1st quarter 1999, 3.0:1.0 2nd qtr 1999 and any consecutive quarters after June 30, 1999
At December 31, 1998 the Company's tangible net worth as calculated pursuant to the Credit Agreement was $35,322,586. B of A has waived noncompliance with this covenant at December 31, 1998 and March 31, 1999. The Company and B of A have been in discussions, both recognizing that the covenant as initially established did not give adequate consideration to the effects of the Company's successful efforts method of accounting on the future book value of its properties, in particular the accounting treatment that the Company has adopted which requires the amortization over a period not to exceed forty-eight months of a substantial portion of the property values recorded pursuant to the Acquisitions. As such, B of A has agreed with the Company in concept to reduce the tangible net worth requirement to an amount not in excess of $25,000,000, subject to approval of B of A's credit committee anticipated in the second quarter of 1999. In the event the credit committee does not approve the modification of the covenant, the Company would be in noncompliance of this provision and will seek alternative financing arrangements. Further, as of December 31, 1998, the Company's current ratio was 0.3128:1 and the Company's interest coverage ratio was (2.1368) to 1, both of which were, therefore, in noncompliance. B of A has waived said noncompliance at December 31, 1998. The Company believes it has improved its current ratio and its interest coverage ratio since December 31, 1998 significantly; however, it does not believe it is likely that it will be in compliance with either of said covenants as of March 31, 1999. B of A has indicated that, in the event the Company is in noncompliance, it will likely waive any such covenants through April 1, 1999. Although the Company believes it can be in compliance with both of these covenants throughout the remainder of 1999, there can be no assurance that it will be in compliance. As a result it is possible that additional waivers may be needed in the future. In the event B of A did not grant such waivers, if needed, the Company would be in noncompliance of the covenants and would seek alternative financing arrangements. In addition, the Company has entered into an interest rate swap guaranteeing a fixed interest rate of 8.28% on the loan, and the Company will pay fees of one-eighth of 1% (.0125%) on the unused portion of the commitment amount. The unrealized loss on the interest rate swap agreement was $21,910 and $1,275 at December 31, 1997 and 1998, respectively. 46 On March 12, 1996, the Company completed a financial package with a group funded by a public utility to evaluate and develop a project in Terrebonne Parish, Louisiana. This group will participate in 48% of all costs of evaluation and development of the project area and provided a non-recourse loan to fund the Company's 48% share of the leasehold and seismic evaluation costs of the project. The loan is secured by a mortgage on the Company's interest in the project. As of December 31, 1998 and 1997, the Company has received advances aggregating $864,000 on the non-recourse loan. The non-recourse loan will be paid solely by the assignment on an 8% overriding royalty interest in the future revenues of the financed project. Future funding will be provided as costs are incurred. 6. INCOME TAXES: Deferred tax assets and liabilities are as follows: AT DECEMBER 31, --------------------------------- 1998 1997 --------------- -------------- Net operating tax loss carryforward.................................. $ 11,633,159 $ 4,332,710 Property and equipment............................................... (435,246) (2,936,284) Valuation allowance.................................................. (11,197,913) (1,396,426) --------------- -------------- Net deferred tax asset (liability)................................ $ --- $ --- --------------- --------------
The Company has recorded a deferred tax valuation allowance since, based on an assessment of all available historical evidence, it is more likely than not that future taxable income will not be sufficient to realize the tax benefit. The Company and its subsidiaries have net operating loss carryforwards ("NOLs") at December 31, 1998, of approximately $33,200,000 which may be used to offset future taxable income. The operating loss carryforwards expire in the tax years 2006 through 2013. The ability of the Company to utilize NOLs and tax credit carryforwards to reduce future federal income taxes of the Company may be subject to various limitations under the Internal Revenue Code of 1986, as amended (the "Code"). One such limitation is contained in Section 382 of the Code which imposes an annual limitation on the amount of a corporation's taxable income that can be offset by those carryforwards in the event of a substantial change in ownership as defined in Section 382 ("Ownership Change"). In general, Ownership Change occurs if during a specified three-year period there are capital stock transactions, which result in an aggregate change of more than 50% in the beneficial ownership of the stock of the Company. In connection with the Acquisition Agreement, the Company has incurred such an Ownership Change. 7. RELATED PARTY TRANSACTIONS: The Company's outstanding advances to employees and affiliates of the Company at December 31, 1998 and 1997 was $963,700 and $105,171, respectively. The December 31, 1998 and 1997 receivables include approximately $47,787 from an affiliated partnership for which the Company serves as the managing general partner. In addition, the December 31, 1998 balance includes a $915,342 receivable from Esenjay Petroleum (EPC) primarily related to joint interest billings to EPC. In addition, amounts payable of $134,400 and $112,000 were due to David W. Berry and David B Christofferson, respectively, in conjunction with the settlement of their prior employment contracts. In addition, at December 31, 1998 the Company had a net account payable to Aspect in the amount of $4,322,548. (See Note 9) 8. COMMITMENTS AND CONTINGENCIES: The Company leases office space under lease agreements, which are classified as operating leases. Lease expense under these agreements was $193,515 in 1998 and $112,432 in 1997. A summary of future minimum rentals on these non-cancelable operating leases is as follows: 47
AT DECEMBER 31, YEAR 1998 - ---- --------------- 1999.................................................................... $252,514 2000.................................................................... $252,514 2001.................................................................... $213,491 2002.................................................................... $135,446 2003.................................................................... $67,723
The Company is party to various lawsuits arising in the normal course of business. Management believes the ultimate outcome of these matters will not have a material effect on the Company's consolidated financial position, results of operation, and net cash flows. The Company markets its natural gas through monthly spot sales. Because sales made under spot sales contracts result in fluctuating revenues to the Company depending upon the market price of gas, the Company may enter into various hedging agreements to minimize the fluctuations and the effect of price declines or swings. During January 1999, the Company completed performance on a 1996 swap agreement on approximately 1,040 MMBtu's per day of Mid-Continent natural gas production for $1.566 per MMBtu for the period beginning April 1, 1996 and ending January 31, 1999. In October of 1998, the Company entered into two swap agreements, one on 4,000 MMBtu's per day of its Gulf Coast natural gas production for $2.14 per MMBtu for the period beginning November 1998 and ending in October 1999, and the second one on 700 MMBtu's per day of its Gulf Coast natural gas production for $2.13 per MMBtu for the period beginning November 1998 and ending in October 1999. Both of these swap agreements were supplemented in December 1998 when the Company entered into additional swap agreements, one of which was for 4,000 MMBtu's per day of its Gulf Coast natural gas production for $2.07 per MMBtu for the period beginning November 1999 and ending in October 2000, and the second one was on 700 MMBtu's per day of its Gulf Coast natural gas production for $2.07 per MMBtu for the period beginning November 1999 and ending in October 2000. As a result of the foregoing transactions, the Company has 4,700 MMBtu's per day of its Gulf Coast natural gas production hedged through October 2000. 9. ACQUISITIONS: On May 14, 1998, the Company acquired substantial interests in 28 exploration projects from EPC and Aspect in exchange for 10,106,700 shares of the Company's common stock. The estimated fair value on the date of acquisition was approximately $60 million, which consists of the fair market value of $54.2 million, as determined by an independent third party, plus project costs from the effective date of November 1, 1997 up to the closing of the Acquisition Agreement. The acquired projects are primarily technology enhanced natural gas exploration projects along the Texas and Louisiana Gulf Coast. The Acquisitions have been recorded at their fair value and have been included in the Company's consolidated financial statements from the date of their acquisition. The following unaudited pro forma information presents a summary of condensed consolidated results of operations as if the Acquisitions had occurred on January 1, 1997: 48
YEAR ENDED DECEMBER 31, ----------------------------------- 1998 1997 ------------ ------------ Revenues ................................ $ 1,716,473 $ 908,609 Total costs and expenses ................ (33,325,677) (12,865,085) ------------ ------------ Net loss ................................ $(31,609,204) $(11,956,476) ------------ ------------ ------------ ------------ Basic and diluted loss per share ........ $ (2.33) $ (1.02) ------------ ------------ ------------ ------------
10. PROPERTY AND EQUIPMENT
YEAR ENDED DECEMBER 31, ----------------------------------- 1998 1998 ------------ ----------- Gas and oil properties, at cost, successful efforts method of accounting: Proved ..................................... $ 14,006,224 $ 1,181,811 Unproved, subject to amortization .......... 43,800,198 -- Unproved, not subject to amortization ...... 10,835,056 2,054,037 ------------ ----------- Total gas and oil properties ............ 68,641,498 3,235,848 1,403,384 1,169,127 ------------ ----------- Other property and equipment ........................ 70,044,882 4,404,975 Less accumulated depletion, depreciation and amortization ............................... (15,517,656) (1,260,605) ------------ ----------- $ 54,527,226 $ 3,144,370 ------------ ----------- ------------ -----------
11. SUPPLEMENTAL GAS AND OIL INFORMATION (UNAUDITED): The Company's proved gas and oil reserves are located in the United States. Proved reserves are those quantities of natural gas and crude oil which, upon analysis of geological and engineering data, demonstrate with reasonable certainty to be recoverable in the future from known gas and oil reservoirs under existing economic and operating conditions (i.e. price and costs as of the date the estimate is made). Proved developed (producing and non-producing) reserves are those proved reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped gas and oil reserves are 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. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. FINANCIAL DATA The Company's gas and oil producing activities represent substantially all of the business activities of the Company. The following costs include all such costs incurred during each period, except for depreciation and amortization of costs capitalized: 49 COSTS INCURRED IN GAS AND OIL EXPLORATION AND PRODUCTION ACTIVITIES:
YEAR ENDED DECEMBER 31, --------------------------- 1998 1997 ----------- ---------- Acquisition of properties: Proved......................................................................... $ --- $ 765,678 Unproved....................................................................... 63,511,000 242,205 Exploration costs................................................................. 13,412,133 1,861,432 Development costs................................................................. 7,114,820 153,938 ----------- ---------- Total costs incurred........................................................ $84,037,952 $3,023,253 ----------- ---------- ----------- ----------
CAPITALIZED COSTS:
AT DECEMBER 31, ---------------------------- 1998 1997 ------------ ---------- Proved............................................................................ $ 14,006,244 $1,181,811 Unproved properties, subject to amortization...................................... 43,800,198 -- Unproved properties, not subject to amortization.................................. 10,835,056 2,054,037 Less accumulated amortization..................................................... (14,584,784) (438,044) ------------ ---------- Net capitalized costs....................................................... $ 54,056,714 $2,797,804 ------------ ---------- ------------ ----------
ESTIMATED QUANTITIES OF PROVED GAS AND OIL RESERVES: The estimates of proved producing reserves were estimated. Proved reserves cannot be measured exactly because the estimation of reserves involves numerous judgmental and arbitrary determinations. Accordingly, reserve estimates must be continually revised as a result of new information obtained from drilling and production history or as a result of changes in economic conditions.
CRUDE OIL, CONDENSATE AND NATURAL GAS LIQUIDS NATURAL GAS (MCF) (BARRELS) ---------------------------- ------------------------ YEARS ENDED DECEMBER 31, YEARS ENDED DECEMBER 31, ---------------------------- ------------------------ 1998 1997 1998 1997 ---------- ---------- --------- --------- Proved developed and undeveloped reserves: Beginning of period............................. 5,500,363 8,901,555 114,399 183,735 Purchases of minerals-in-place.................. --- --- --- --- Sales of minerals-in-place...................... --- (159,528) --- (3,857) Revisions of previous estimates................. (5,284,456) (3,129,076) (97,420) (59,121) Extensions, discoveries and other additions..... 12,367,076 8,716 92,094 928 Production...................................... (653,316) (121,304) (8,878) (7,286) ---------- ---------- ------- ------- End of period................................... 11,929,667 5,500,363 100,195 114,399 ---------- ---------- ------- ------- ---------- ---------- ------- ------- Proved developed reserves: Beginning of period............................. 521,345 985,524 24,358 46,420 End of period................................... 6,864,564 521,345 59,085 24,358
Reserves of wells, which have performance history, were estimated through analysis of production trends and other appropriate performance relationships. Where production and reservoir data were limited, the volumetric method was used and it is more susceptible to subsequent revisions. 50 STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS: The standardized measure of discounted future net cash flows is based on criteria established by Financial Accounting Standards Board Statement No. 69, "Accounting for Oil and Gas Producing Activities" and is not intended to be a "best estimate" of the fair value of the Company's oil and gas properties. For this to be the case, forecasts of future economic conditions, varying price and cost estimates, varying discount rates and consideration of other than proved reserves (i.e., probable reserves) would have to be incorporated into the valuations. Future net cash inflows are based on the future production of proved reserves of natural gas, natural gas liquids, crude oil and condensate as estimated by petroleum engineers by applying current prices of gas and oil (with consideration of price changes only to the extent fixed and determinable and with consideration of the timing of gas sales under existing contracts or spot market sales) to estimated future production of proved reserves. Average year end prices used in determining future cash inflows for natural gas and oil for the periods ended December 31, 1998 and 1997 were as follows: 1998 - $2.01 per MCF-Gas, $9.03 per barrel-Oil; 1997 - $2.46 per MCF-Gas, $15.70 per barrel-Oil, respectively. Future net cash flows are then calculated by reducing such estimated cash inflows by the estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves and by the estimated future income taxes. Estimated future income taxes are computed by applying the appropriate year-end tax rate to the future pretax net cash flows relating to the Company's estimated proved oil and gas reserves. The estimated future income taxes give effect to permanent differences and tax credits and allowances. The following table sets forth the Company's estimated standardized measure of discounted future net cash flows:
YEAR ENDED DECEMBER 31, ---------------------------- 1998 1997 ----------- ----------- Future cash inflows............................................................ $25,241,119 $15,752,040 Future development and production costs........................................ (8,478,613) (7,468,887) Future income tax expenses..................................................... -- (365,224) ----------- ----------- Future net cash flows.......................................................... 16,762,506 7,917,929 Discount....................................................................... (4,242,485) (4,019,429) ----------- ----------- Standardized measure of discounted future net cash flows....................... $12,520,021 $3,898,500 ----------- ----------- ----------- -----------
The following table sets forth changes in the standardized measure of discounted future net cash flows:
YEAR ENDED DECEMBER 31, ---------------------------- 1998 1997 ----------- ------------ Standardized measure of discounted future cash flows-beginning of period....... $ 3,898,500 $ 16,758,544 Sales of oil and gas produced, net of operating expenses....................... (1,021,830) (312,198) Net changes in sales prices and production costs............................... (4,459,331) (10,601,580) Extensions, discoveries and improved recovery, less related costs.............. 13,358,762 30,952 Change in future development costs............................................. 5,135,315 (433,314) Previously estimated development costs incurred during the year................ 2,515 162,610 Revisions of previous quantity estimates....................................... (1,957,356) (4,973,603) Accretion of discount.......................................................... 402,566 2,169,632 Net change of income taxes..................................................... 127,157 4,810,619 Sales of minerals-in-place..................................................... - (371,728) Changes in production rates (timing) and other................................. (2,966,277) (3,341,614) ----------- ------------ Standardized measure of discounted future cash flows-end of period............. $12,520,021 $ 3,898,500 ----------- ------------ ----------- ------------
51 ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Not Applicable. 52 PART III ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS; COMPLIANCE WITH SECTION 16(a) OF THE EXCHANGE ACT The following table sets forth certain information regarding the Company's directors and executive officers.
NAME AGE POSITION - ---- --- --------- David W. Berry(1)(4)................................. 49 Chairman of the Board Alex M. Cranberg(1)(2)(5)............................ 44 Vice Chairman of the Board Michael E. Johnson(1)(5)............................. 50 Director, President and Chief Executive Officer Charles J. Smith(1)(4)............................... 72 Director Alex B. Campbell(3)(4)............................... 41 Director William D. Dodge, III(2)(6).......................... 46 Director Jack P. Randall(2)(3)(5)............................. 49 Director Hobart A. Smith(3)(6)................................ 62 Director David B. Christofferson.............................. 50 Senior Vice President, Secretary and General Counsel
- ----------- (1) Member of the Executive Committee. (2) Member of the Audit Committee. (3) Member of the Compensation Committee. (4) Director whose term expires in 1999. (5) Director whose term expires in 2000 (6) Director whose term expires in 2001 DAVID W. BERRY has served as President of the Company since the incorporation of its predecessor in August 1988 and until May 14, 1998, and has served as Chairman of the Board of Directors since 1991. In 1978, he formed Berry Petroleum Corporation, which was a regional natural gas and oil exploration company. In 1976 he co-founded Vulcan Energy Corporation, a Tulsa, Oklahoma based exploration and production company. Mr. Berry has served as the State Finance Chairman of the Oklahoma State Republican Party, as a Trustee for the Oklahoma Museum of Art and on the United States Senatorial Trust Committee. Mr. Berry is a member of the Texas Independent Producers and Royalty Owners Association. ALEX M. CRANBERG has been a director of the Company since May 14, 1998. He has been President of Aspect Management Corporation, the manager of Aspect, since its inception in 1993. He joined Houston Oil and Minerals Corp. in 1977 where he served in various engineering and financial roles. He has managed the oil and gas portfolio of General Atlantic Partners, a private investment firm, since 1981. He is on the Board of Directors of Brigham Exploration, Inc., a public company, and Westport Oil and Gas, Inc., a private exploration and production company active in the Rocky Mountain and Gulf Coast Regions. He received a BS in petroleum engineering from the University of Texas and an MBA from Stanford University. MICHAEL E. JOHNSON has been a director, President and Chief Executive Officer of the Company since May 14, 1998. He was President of EPC from 1978 until joining the Company. Mr. Johnson was an operations engineer for Atlantic Richfield Co. from 1971 to 1976 and worked for Tana Oil and Gas before co-founding EPC, where he has managed all exploration activities, coordinated outside technical support and raised capital from industry partners. He received a BS degree in mechanical engineering from the University of Southwestern Louisiana. CHARLES J. SMITH has been a director of the Company since May 14, 1998. He has served as Chairman and Chief Executive Officer of EPC since its formation in 1978. Mr. Smith acts as EPC's senior land and administrative officer. He was a practicing attorney specializing in oil and gas law from 1963 to 1987. Before 1963, he was a petroleum landman 53 for Humble Oil and Refining Company. Mr. Smith received a BBA in industrial management from the University of Texas and was admitted to practice law in Texas in 1959 after attending South Texas School of Law and the completion of off-campus studies. ALEX B. CAMPBELL has been a director of the Company since May 14, 1998. He has been Vice President of Aspect Management Corporation since August 1996 and is responsible for land and corporate development and legal issues. He served as landman for Grynberg Petroleum and TXO Production Corp. from 1980 to 1984, focusing on the Rocky Mountain Region, then as division landman for Lario Oil & Gas Company from 1984 to 1996, where he was responsible for administration, prospect marketing, contract lease negotiation, exploration permitting, surface owner negotiations and property acquisition negotiation and due diligence. He has a BA in business/pre-law from Colorado State University, and an MBA from Colorado State University. WILLIAM D. DODGE, III has been a director of the Company since May 14, 1998. He has been Regional President of Pacific Southwest Bank, Corpus Christi, Texas since 1995. He has been active in banking since 1977, including serving as President of The Bank of Robstown, Texas from 1982 until 1995. He also serves in a number of civic roles, including as Chairman of the Port of Corpus Christi Authority, and serving on the Board of Directors of Columbia Northwest Hospital. Mr. Dodge is a member of the Editorial Review Board SAM Advanced Management Journal at the Texas A&M University-Corpus Christi College of Business. He received a BA degree from the University of Texas at Austin and attended the Southwestern Graduate School of Banking, Southern Methodist University. JACK P. RANDALL has been a director of the Company since May 14, 1998. He founded Randall & Dewey, Inc. in 1989 and has served as its President since that time. Randall & Dewey is a Houston, Texas, based transaction advisory firm focusing on oil and gas mergers, acquisitions, divestments, trades and alliances. Before founding Randall & Dewey, he was with Amoco Production Company from 1975 to 1989, where his service included acting as Manager of Acquisitions and Investments. Mr. Randall is a member of the Board of Directors of Crosstimbers Oil Company, the chairman of the Petroleum Engineering Visiting Committee at the University of Texas at Austin, and a member of the Implementation Advisory Committee for the Oil Recovery Center of Excellence at the University of Texas at Austin. He also is a member of the Society for Petroleum Engineers, the American Petroleum Institute and the Independent Petroleum Association of America. He received BS and MS degrees in engineering from the University of Texas. HOBART A. SMITH has been a director of the Company since May 14, 1998. He has served as a director of Harken Energy Corporation since 1997 and a consultant to Smith International, Inc. since 1991. From 1987 to 1991, Mr. Smith was Vice President of Customer Relations for Smith International, Inc. From 1965 to 1987, he held numerous positions, including many executive offices with Smith Tool, Inc., a subsidiary of Smith International, Inc. Mr. Smith has more than 30 years of experience in the oil services industry. Mr. Smith received a BA from Claremont McKenna College. DAVID B. CHRISTOFFERSON joined the Company in 1989 and served as a director until May 14, 1998. Mr. Christofferson currently is Senior Vice President, Secretary and General Counsel of the Company. He also serves as its Principal Financial Officer. Mr. Christofferson has been active in the natural gas and oil industry for over 20 years. He also served as General Counsel to two independent natural gas and oil companies and to a natural gas marketing company. Mr. Christofferson is a member of the Texas Independent Producers and Royalty Owners Association. He received a BBA in finance and a Juris Doctor from the University of Oklahoma. He also received a Masters of Divinity degree from Phillips University. He is admitted to practice law in Oklahoma. KEY OFFICERS In addition to the directors and executive officers listed above, the following former EPC employees have significant responsibilities with the Company. HOWARD E. WILLIAMS, 56, is Vice President and Treasurer. Mr. Williams joined EPC in 1981 and became the Company's Principal Accounting Officer on May 14, 1998. He is responsible for supervising and coordinating all of the Company's accounting activities. Before joining EPC, Mr. Williams practiced public accounting for 17 years with "Big 8," regional and local accounting firms. Mr. Williams is a graduate of Texas A&I University with a BBA in Accounting. LINDA D. SCHIBI, 42, is Vice President-Land. Mrs. Schibi joined EPC in 1978 and became the Company's Land 54 Manager in charge of the day-to-day land operations on May 14, 1998. She coordinates the activities of outside landmen and supervises in-house land department operations. Mrs. Schibi also functions as oil and gas marketing manager with responsibility for the marketing of the Company's operated oil and gas production. She is a Certified Petroleum Landman. She attended Del Mar College. DALE W. ALEXANDER, 43, is Vice President-Exploitation. He served EPC as a consultant in the area of reservoir and exploitation engineering from 1991 until May 14, 1998, when he became the Company's Vice President--Exploitation. Mr. Alexander is responsible for determining pre-drill economics, risk weighting drilling projects and coordination of reserve reports. From 1988 to 1991, he was with Kamlock Oil & Gas Company. He was an exploitation/reservoir engineer for EPC from 1983 to 1988. He also has worked for Champlin Petroleum Company, and Union Oil of California. Mr. Alexander has a BS in Petroleum Engineering from the University of Texas. MICHAEL E. MOORE, 41, is Vice President-Exploration. Mr. Moore joined EPC in 1982 as a staff geologist and became the Company's Exploration Manager on May 14, 1998. Mr. Moore is responsible for reviewing all outside geological projects as well as supervising the activities of in-house and retainer geological staff. He previously was employed as a field geologist with J.R. Weber, Inc., a consulting firm in Denver, Colorado. He received a BS in Geology from the University of Texas. WILLIAM L. JACKSON, 43, is Senior Vice President-Operations. Mr. Jackson joined EPC in 1982 and, on May 14, 1998, became the Company's Chief Engineering Officer responsible for all oil and gas drilling, completion, workover, and production operations. He previously served with Acock Engineering and Mueller Engineering as an on-site petroleum engineering consultant on drilling and workovers for oil and gas wells in the South Texas area. He received a BS in Petroleum Engineering and an MBA from the University of Texas. COMPLIANCE WITH SECTION 16(a) OF THE EXCHANGE ACT Section 16(a) of the Exchange Act requires the Company's directors, executive officers and persons who own more than 10% of a registered class of the Company's equity securities, to file reports of ownership on Form 3 and changes in ownership on Form 4 or 5 with the Commission. Such officers, directors and 10% shareholders also are required by Commission rules to furnish the Company with copies of all Section 16(a) reports they file. Based solely on its review of the copies of such forms received by it, or written representations from certain reporting persons that they were not required to file a Form 5, the Company believes that, during the fiscal year ended December 31, 1998, its officers, directors and 10% shareholders complied with all Section 16(a) filing requirements applicable to such individuals. ITEM 10. EXECUTIVE COMPENSATION SUMMARY COMPENSATION TABLE The following table sets forth the total remuneration paid during 1998, 1997 and 1996 to the individuals who served as Chief Executive Officer of the Company during 1998 and the Company's other most highly compensated officers who received compensation in excess of $100,000 during 1998.
LONG-TERM COMPENSATION ---------------------- ANNUAL COMPENSATION(1) AWARDS PAYOUTS ---------------------------- ---------------------- AWARDS OF LTIP ALL OTHER NAME AND PRINCIPAL POSITION YEAR SALARY BONUS OPTIONS (2) PAYOUTS COMPENSATION - ------------------------------------------------------------- ---------------------- ------------ Michael E. Johnson(3)........ 1998 $125,000 ------ ------ ------ ------ President and Chief Executive Officer David W. Berry(4)............... 1998 $147,079 ------ ------ ------ $264,000(5) Chairman of the Board 1997 134,400 ------ 32,000(6) $44,965(7) ------ 1996 124,000 ------ 20,000(6) 20,145(7) ------ David B Christofferson.......... 1998 121.606 ------ ------ ------ $224,000(5) Senior Vice President 1997 112,000 ------ 58,667(6) $47,888(8) ------ Principal Financial Officer 1996 103,000 ------ 16,667(6) 22,469(8) ------
55 - ---------------------------- (1) Does not include perquisites and other personal benefits which are less than either $50,000 or 10% of the total of annual salary and bonus. (2) Represents the number of shares of Common Stock issuable pursuant to vested and non-vested stock options. (3) Mr. Johnson became the Chief Executive Officer of the Company on May 14, 1998. (4) Mr. Berry served as Chief Executive Officer through May 14, 1998. (5) Upon the closing of the Acquisitions, previously existing incentive agreements and contract settlement agreements with both Mr. Berry and Mr. Christofferson required total payments of $264,000 to Mr. Berry and $224,000 to Mr. Christofferson. These amounts were paid 50% in cash and 50% pursuant to promissory notes due in January of 1999 to each individual. See "Certain Transactions". (6) In 1997, all stock options previously granted to Mr. Berry and Mr. Christofferson were canceled and new stock options were granted to them pursuant to the Employee Option Plan - 1997 (the "1997 Plan"). Amounts stated for 1997 include regrants of such canceled options. (7) In 1997, the Company settled its deferred compensation liability to Mr. Berry for a payment of $80,537. Of this amount, a total of $56,063 had been reported as earned compensation in the years 1993-96, and the balance of $24,474 is reported as earned in 1997. (8) In 1997, the Company settled its deferred compensation liability to Mr. Christofferson for a payment of $95,170. Of this amount, a total of $72,694 had been reported as earned compensation in the years 1993-96, and the balance of $22,476 is reported as earned in 1997. OPTION GRANTS OR REPRICINGS There were no option grants or repricings made in 1998 to the individuals named in the Summary Compensation Table above. OPTION EXERCISE AND YEAR-END VALUES The following table sets forth certain information as of December 31, 1998 with respect to the unexercised options to purchase Common Stock to the individuals named in the Summary Compensation Table above. None of such individuals exercised any stock options during 1998.
VALUE OF UNEXERCISED NUMBER OF UNEXERCISED IN-THE MONEY-OPTIONS AT OPTIONS AT DECEMBER 31, 1998 DECEMBER 31, 1998 (1) ----------------------------------------------------------------------------- NAME EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE - ---- ----------- -------------- ----------- -------------- David W. Berry...................... 32,000 ------ ----- ------ David B Christofferson............. 58,667 ------ ----- ------
- -------------- (1) Based on the last sale price of the Common Stock on the Nasdaq Small-Cap Market on December 31, 1998 of $1.875. OPTION PLANS Employee Option Plan-1997. The 1997 Plan authorizes the issuance of up to 115,892 options to purchase one share of Common Stock. Options to purchase 94,001 shares are currently outstanding at exercise prices ranging from $3.78 per share to $7.68 per share. There are no other option plans currently in effect. DIRECTORS' COMPENSATION No directors' compensation was paid in 1998. A directors' compensation plan is to be finalized in the second quarter of 1999 which is anticipated to include certain compensation for 1998 services. ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The following table sets forth certain information, as of March 26, 1999, with respect to the Common Stock owned by (i) each person known by management to own beneficially more than 5% of the Company's outstanding Common Stock; (ii) each of the Company's Directors and each executive officers who received compensation in 1998 in excess of $100,000; and (iii) all Directors and executive officers of the Company as a group. Unless otherwise noted, the persons named below have sole voting and investment power with respect to such shares. 56
Number of Percent of Name of Beneficial Owner Shares (1) Class (2) (3) ------------------------ ---------- ------------- Esenjay Petroleum Corporation(4).............. 5,177,761(5) 32.78% Aspect Resources LLC(6)....................... 4,386,856(7) 27.76% David W. Berry(13)............................ 162,155(8) 1.03% Alex M. Cranberg(6)........................... 4,398,756(9) 27.83% Michael E. Johnson(4)......................... 5,260,261(10) 33.30% Charles J. Smith(4)........................... 5,263,761(10) 33.32% Alex B. Campbell(6)........................... ------ * William D. Dodge, III(13)..................... ------ * Jack P. Randall(13)........................... ------ * Hobart A. Smith(13)........................... 1,667 * David B Christofferson(13).................... 68,000(11) * All executive officers and Directors as a group (9 persons)......................... 412,222(12) 2.60%
- ---------------------- * Less than 1% (1) Includes all shares of Common Stock with respect to which each person, executive officer or Director who directly, through any contract, arrangement, understanding, relationship or otherwise, has or shares the power to vote or to direct voting of such shares or to dispose or to direct the disposition of such shares. Includes shares that may be purchased under stock options exercisable within 60 days. (2) Based on 15,784,834 shares of Common Stock outstanding at March 26, 1999, plus, for each beneficial owner, those number of shares underlying exercisable options held by each executive officer or Director. (3) Percent of class for any Stockholder listed is calculated without regard to shares of Common Stock issuable to others upon exercise of outstanding stock options. Any shares a Stockholder is deemed to own by having the right to acquire by exercise of a stock option or warrant are considered to be outstanding solely for the purpose of calculating that Stockholder's ownership percentage. (4) Address: c/o Esenjay Exploration, Inc., North 500 Water Street, Suite 1100 South, Corpus Christi, Texas 78471. (5) Includes 12,500 shares of Common Stock issuable upon the exercise of warrants. (6) Address: 511 16th Street, Suite 300, Denver, Colorado 80202. (7) Includes 18,750 shares of Common Stock issuable upon the exercise of warrants. (8) Includes 32,000 shares of Common Stock issuable upon the exercise of stock options that are currently exercisable. (9) Includes (i) 11,900 shares of Common Stock owned and (ii) 4,386,856 shares of Common Stock owned by Aspect, which includes 18,750 shares issuable upon the exercise of warrants, as to which Mr. Cranberg disclaims beneficial ownership. (10) Includes (i) 82,500 shares owned and (ii) 5,165,261 shares of Common Stock owned by EPC, and 12,500 shares of Common Stock issuable upon exercise of currently exercisable warrants held by EPC, as to which Messrs. Johnson and Smith disclaim beneficial ownership. (11) Includes 58,667 shares of Common Stock issuable upon the exercise of stock options that are currently exercisable. (12) Includes 90,667 shares issuable pursuant to stock options held by executive officers and Directors that are currently exercisable. Does not include any shares of Common Stock as to which beneficial ownership is disclaimed. (13) Address: c/o Esenjay Exploration, Inc., 500 Dallas, Suite 2920, Houston, Texas 77002. COMPLIANCE WITH SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING REQUIREMENTS Section 16(a) of the Securities and Exchange Act of 1934 requires that Company's Directors, executive officers and any persons who own more than 10% of a registered class of the Company's equity securities to file with the Securities and Exchange Commission (the "SEC") reports of ownership and changes in ownership of Common Stock and other equity securities of the Company. Officers, Directors and greater than 10% stockholders are required by SEC regulation to furnish the Company with copies of all Section 16(a) forms they file. 57 Based solely on review of the copies of such reports furnished to the Company or written representations that no other reports were required, the Company believes that, during the 1998 fiscal year, all filing requirements applicable to its executive officers, Directors and greater than 10% stockholders were compiled on a timely basis. ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The Company and Aspect Management Corporation, the manager of Aspect ("Aspect Management"), have entered into a Geotechnical Services Consulting Agreement on May 14, 1998, pursuant to which Aspect Management performs geotechnical services for the Company. The Company and Aspect Management also entered into a Land Service Consulting Agreement on May 14, 1998, pursuant to which Aspect Management provides certain land related services to the Company in connection with certain oil and gas properties to which both parties share an ownership interest. To the extent that Aspect Management pays or advances costs or expenses associated with certain assets on behalf of the Company, and to the extent Aspect Management hires independent contractors, such costs and expenses will be billed to the Company. Under the Geotechnical Consulting Agreement, Aspect Management must obtain the Company's approval to enter into any related contract or agreement that has a cost exceeding $50,000 net to the Company. The Company must pay Aspect Management for services rendered in an amount equal to Aspect's employee costs, overhead costs and general and administrative costs associated with the services rendered thereunder. The agreements terminate on May 14, 2002, unless terminated by either party with 90 days' written notice to the other party. Aspect received warrants to purchase 9,375 shares of Common Stock at an exercise price of $3.00 per share in connection with providing financing under a credit facility, and received warrants to purchase an additional 9,375 shares of Common Stock at an exercise price of $3.00 per share in connection with guaranteeing a portion of the indebtedness under another credit facility. In addition, EPC received warrants to purchase an aggregate of 12,500 shares of Common Stock at an exercise price of $3.00 per share in connection with guaranteeing a portion of the indebtedness under the above referenced credit facilities. Each of Messrs. Berry and Christofferson (each an "Employee") entered into an Incentive Agreement and a Contract Settlement Agreement, and their employment agreements with the Company were terminated upon the closing of the Acquisitions. Pursuant to the Incentive Agreements and Contract Settlement Agreements, the Company agreed that if the Company closed a significant corporate transaction, and the Employee did not resign as an executive officer before that time, the Company would pay an Incentive Payment of $134,000 to Mr. Berry and $112,000 to Mr. Christofferson, as well as a Contract Settlement Payment of $134,000 to Mr. Berry and $112,000 to Mr. Christofferson, at which time Mr. Berry and Mr. Christofferson would be released from all further obligations to the Company other than contractual confidentiality obligations. Each of the Incentive Payments and the Contract Settlement Payments were in the form of promissory notes bearing interest at the rate of 10% per year payable by the Company to the Employees, with the principal amount being paid at a minimum of $5,000 per month, beginning the first day of the third month after the closing of the significant corporate transaction, and all principal and accrued interest being due and payable upon the earlier of September 30, 1998, or the completion of a public sale of any equity or debt securities of the Company, whichever is earlier. Each of the employees, at their discretion, may defer payment of up to 50% of the principal amount due until January 15, 1999. The Contract Settlement Payments were intended to satisfy the Employees employment contracts. Incentive Payments were intended to compensate the Employees for their services in soliciting, negotiating and closing a significant corporate transaction and not in satisfaction of any prior obligations to the Company. The Incentive Payments were in addition to any other obligations or payments due to the Employees, including the settlement of their previously existing employment contracts. In addition, as an inducement to the Employees to continue to solicit and close a change of control transaction, and regardless of whether such a transaction occurred, all of the stock options previously granted to the employees by the Company were canceled, and the Company issued to each of the employees new stock options pursuant to the Employee Option Plan. The Acquisitions constituted a significant corporate transaction pursuant to which the Incentive Payments and Contract Settlement Payments were payable to Mr. Berry and Mr. Christofferson. Pursuant to the Incentive Agreements and Contract Settlement Agreements the Company has paid Mr. Berry and Mr. Christofferson the above described note payments. Mr. Berry and Mr. Christofferson have no further contractual obligations to the Company 58 other than confidentiality obligations and any contractual arrangements they may negotiate with the Company in the future. The Company's outstanding advances to employees and affiliates of the Company at December 31, 1998 and 1997 was $963,700 and $105,171, respectively. The December 31, 1998 and 1997 receivables include approximately $47,787 from an affiliated partnership for which the Company serves as the managing general partner. In addition, the December 31, 1998 balance includes a $915,342 receivable from EPC primarily related to joint interest billings to EPC. In addition, amounts payable of $134,400 and $112,000 were due to David W. Berry and David B Christofferson, respectively, in conjunction with the settlement of their prior employment contracts, which amounts were paid in January 1999. In addition, at December 31, 1998 the Company had a net account payable to Aspect Resources LLC in the amount of $4,322,548. It has also entered into an agreement to sell to Aspect a 12.5% (of 100%) interest in the Caney Creek Project, a 12% (of 100%) interest in the Gillock Project, and all of the Company's undeveloped property interests in the West Beaumont project area for $2,610,000. Closing is scheduled for the second quarter of 1999. Proceeds from the sale will be used to settle amounts due Aspect. In that Aspect is a related party, closing is subject to receipt of an independent fairness opinion which management believes will be timely obtained. Any future transaction between the Company and any of its Directors, officers or owners of five percent or more of the Company's then outstanding Common Stock will be on terms no less favorable than would reasonably be expected from an independent third party, and will be approved by a majority of the Directors who do not have an interest in the proposed transaction and who have had access to the Company's outside legal counsel with respect to such transaction. 59 PART IV ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K
Exhibit Name of Exhibit - ------- --------------- 2(a) Acquisition Agreement and Plan of Exchange dated as of January 19, 1998, by and among Frontier Natural Gas Corporation, Esenjay Petroleum Corporation, and Aspect Resources LLC as incorporated by reference to the Company's Annual Report on Form 10-KSB for the fiscal year ended December 31, 1997 dated April 6, 1998, wherein the same appears as Exhibit 2. 2(b) First Amendment to Acquisition Agreement and Plan of Exchange dated as of April 20, 1998, by and among Frontier Natural Gas Corporation, Esenjay Petroleum Corporation, and Aspect Resources LLC as incorporated by reference to the Company's Registration Statement number 333-53581 dated May 21, 1998 wherein the same appeared as Exhibit 10(x). 2(c) Second Amendment to Acquisition Agreement and Plan of Exchange dated as of May 13, 1998, by and among Frontier Natural Gas Corporation, Esenjay Petroleum Corporation, and Aspect Resources LLC as incorporated by reference to the Company's Registration Statement number 333-53581 dated May 21, 1998 wherein the same appeared as Exhibit 10(y). 2(d) Plan and Agreement of Merger dated as of May 14, 1998, by and between Esenjay Exploration, Inc., a Delaware corporation, and Frontier Natural Gas Corporation as incorporated by reference to the Company's Proxy Statement filed with the Securities and Exchange Commission on April 24, 1998, wherein the same appeared as Appendix F. 3(a) Certificate of Incorporation of the Company as incorporated by reference to the Company's Registration Statement number 333-53581 dated May 21, 1998 wherein the same appeared as Exhibit 3(a). 3(b) By-Laws of the Company as incorporated by reference to the Company's Registration Statement number 333-53581 dated May 21, 1998 wherein the same appeared as Exhibit 3(c). 4 See Articles V, VI and X of the Company's Certificate of Incorporation and Articles I, II, V and VI of the Company's By-Laws as provided at Exhibits 3(a) and 3(b) above. 10(a) Contract Settlement Agreement between Frontier Natural Gas Corporation and David W. Berry dated effective January 1, 1998, as incorporated by reference to the Company's Annual Report on Form 10-KSB for the fiscal year ended December 31, 1997 dated April 6, 1998, wherein the same appears as Exhibit 10(b). 10(b) Contract Settlement Agreement between Frontier Natural Gas Corporation and David B Christofferson dated effective January 1, 1998, as incorporated by reference to the Company's Annual Report on Form 10-KSB for the fiscal year ended December 31, 1997 dated April 6, 1998, wherein the same appears as Exhibit 10(d). 10(c) $20,000,000 Amended and Restated Credit Agreement dated as of October 13, 1998, between Esenjay Exploration, Inc. as the borrower and Bank of America NT&SA as the lender, as incorporated by reference to the Company's Annual Report on Form 10-KSB for the fiscal year ended December 31, 1998 dated April 14, 1999, wherein the same appears as Exhibit 10(c). 10(d) Credit Agreement by and between Esenjay Exploration, Inc. and Duke Energy Financial Services, Inc. dated as of January 28, 1999, as currently in effect, as incorporated by reference to the Company's Annual Report on Form 10-KSB for the fiscal year ended December 31, 1998 dated April 14, 1999, wherein the same appears as Exhibit 10(d). 60 10(e) Loan Agreement by and between Frontier Natural Gas Corporation and 420 Energy Investments, Inc. dated March 1, 1996, as currently in effect as incorporated by reference to the Company's Annual Report on Form 10-KSB for the fiscal year ended December 31, 1995 dated March 29, 1996, wherein the same appears as Exhibit 10(r). 10(f) Employee Option Plan-1997 as currently in effect as incorporated by reference to the Company's Annual Report on Form 10-KSB for the fiscal year ended December 31, 1997 dated April 6, 1998, wherein the same appears as Exhibit 10(o). 10(g) Warrant Agreement between Frontier Natural Gas Corporation and Gaines, Berland Energy Fund, L.P. dated January 14, 1998, as incorporated by reference to the Company's Registration Statement number 333-53581 dated May 21, 1998 wherein the same appeared as Exhibit 10(q). 10(h) Warrant Agreement between Frontier Natural Gas Corporation and Esenjay Petroleum Corporation dated January 14, 1998, as incorporated by reference to the Company's Registration Statement number 333-53581 dated May 21, 1998 wherein the same appeared as Exhibit 10(r). 10(i) Warrant Agreement between Frontier Natural Gas Corporation and Aspect Resources LLC dated January 14, 1998, as incorporated by reference to the Company's Registration Statement number 333-53581 dated May 21, 1998 wherein the same appeared as Exhibit 10(s). 10(j) Warrant Agreement between Frontier Natural Gas Corporation and Gaines, Berland Energy Fund, L.P. dated January 23, 1998, as incorporated by reference to the Company's Registration Statement number 333-53581 dated May 21, 1998 wherein the same appeared as Exhibit 10(t). 10(k) Warrant Agreement between Frontier Natural Gas Corporation and Esenjay Petroleum Corporation dated January 23, 1998, as incorporated by reference to the Company's Registration Statement number 333-53581 dated May 21, 1998 wherein the same appeared as Exhibit 10(u). 10(l) Warrant Agreement between Frontier Natural Gas Corporation and Aspect Resources LLC dated January 23, 1998, as incorporated by reference to the Company's Registration Statement number 333-53581 dated May 21, 1998 wherein the same appeared as Exhibit 10(v). 11* Statement of Earnings per Share 21* Subsidiaries of Registrant. 27* Financial Data Schedule. (b) Reports on Form 8-K. None
- ------------------- *Filed herewith 61 SIGNATURES Pursuant to the requirements of Section 13, or 15(d) of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. ESENJAY EXPLORATION, INC. Date: April 30, 1999 By: /s/ Michael E. Johnson ------------------------------------ Michael E. Johnson, President, Chief Executive Officer and Director Pursuant to the requirements of Section 13, or 15(d) of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. Date: April 30, 1999 /s/ David B Christofferson ---------------------------------------- David B Christofferson, Senior Vice President General Counsel and Chief Financial Officer Date: April 30, 1999 /s/ Howard E. Williams ---------------------------------------- Howard E. Williams, Vice President and Principal Accounting Officer Date: April 30, 1999 /s/ David W. Berry ---------------------------------------- David W. Berry, Chairman and Director Date: April 30, 1999 /s/ Charles J. Smith ---------------------------------------- Charles J. Smith, Director Date: April 30, 1999 /s/ Alex M. Cranberg ---------------------------------------- Alex M. Cranberg, Director Date: April 30, 1999 /s/ Alex B. Campbell ---------------------------------------- Alex B. Campbell, Director 62 EX-11 2 EXHIBIT 11 EXHIBIT 11 TO FORM 10-KSB COMPUTATION OF EARNINGS PER COMMON SHARE AND COMMON SHARE EQUIVALENTS
Year Ended December 31, ---------------------------------- 1998 1997 ------------ ----------- BASIC EARNINGS PER SHARE Weighted average common shares outstanding 9,882,227 1,646,311 ------------ ----------- ------------ ----------- Basic loss per share $ (2.97) $ (3.07) ------------ ----------- ------------ ----------- DILUTED EARNINGS PER SHARE Weighted average common shares outstanding 9,882,227 1,646,311 Share issuable from assumed conversion of common share options and warrants - 1,338 ------------ ----------- Weighted average common shares outstanding, as adjusted 9,882,227 1,647,649 ------------ ----------- ------------ ----------- Diluted loss per share $ (2.97) $ (3.07) ------------ ----------- ------------ ----------- EARNINGS FOR BASIC AND DILUTED COMPUTATION Net income $(29,321,347) $(4,953,803) Preferred shares dividend (48,138) (103,153) ------------ ----------- Net income to common shareholders (basic and diluted earnings per share computation) $(29,369,485) $(5,056,956) ------------ ----------- ------------ -----------
This calculation is submitted in accordance with Regulation S-K; although it is contrary to paragraphs 13 through 16 of the Financial Accounting Standards Board's Statement of Financial Standard No. 128, because it produces an antidilutive result. 63 EX-21 3 EXHIBIT 21 EXHIBIT 21 TO FORM 10-KSB The subsidiaries of the Registrant are:
Name State of Incorporation - ---- ---------------------- Frontier Acquisition Corp. Oklahoma
64 EX-27 4 EXHIBIT 27
5 YEAR DEC-31-1998 JAN-01-1998 DEC-31-1998 646,200 0 3,558,617 (348,984) 0 4,941,955 70,044,882 (15,517,656) 59,916,272 15,898,490 7,500,000 0 0 157,849 35,164,739 59,916,272 1,372,002 1,716,473 0 30,417,699 0 0 620,121 (29,321,347) 0 (29,321,347) 0 0 0 (29,321,347) (2.97) (2.97)
-----END PRIVACY-ENHANCED MESSAGE-----