-----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, MmIOlSzJBOuQtWlYeuy/eK1kAOiaXm5jEYvO1dvesZYJqpV3+8gopL2vGz4Bxs3U e4hGu0PiF1f3WHzPDJurig== 0000912057-01-509180.txt : 20010418 0000912057-01-509180.hdr.sgml : 20010418 ACCESSION NUMBER: 0000912057-01-509180 CONFORMED SUBMISSION TYPE: 10KSB40 PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 20001231 FILED AS OF DATE: 20010417 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 SEC ACT: SEC FILE NUMBER: 001-12530 FILM NUMBER: 1604578 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 1 a2043667z10ksb40.txt 10KSB40 - -------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-KSB [X] ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2000 [ ] 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: (361) 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: $34,674,753 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 $44,641,018 on March 29, 2001 (based on the last sales price of $4.969 per share as reported on the NASDAQ Stock Market). 18,980,698 shares of the registrant's common stock were outstanding as of March 30, 2001. - -------------------------------------------------------------------------------- ESENJAY EXPLORATION, INC. FOR YEAR ENDED DECEMBER 31, 2000 TABLE OF CONTENTS FORM 10-KSB PART I
ITEM PAGE 1. Description of Business.................................................... 3 2. Description of Property.................................................... 17 3. Legal Proceedings.......................................................... 18 4. Submission of Matters to a Vote of Security Holders........................ 18 PART II 5. Market for Common Equity and Related Stockholder Matters................... 19 6. Management's Discussion and Analysis....................................... 19 7. Financial Statements....................................................... 29 8. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure...................................... 46 PART III 9. Directors, Executive Officers, Promoters and Control Persons; Compliance with Section 16(a) of the Exchange Act........................ 47 10. Executive Compensation..................................................... 49 11. Security Ownership of Certain Beneficial Owners and Management........................................................... 52 12. Certain Relationships and Related Transactions............................. 54 PART IV 13. Exhibits and Reports on Form 8-K........................................... 56 Signatures................................................................. 58
2 PART I This Form 10-KSB 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 20 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 a diverse inventory of technology enhanced natural gas and oil exploration projects located primarily along the Texas and Louisiana Gulf Coast (the "Exploration Projects"). It should be noted that the Company defines a "project" as a distinct 3-D seismic data set area that often comprises multiple exploratory "prospects". 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 that can expose the Company to major gas and oil reserve growth opportunities for several years to come. In May of 1998 the Company acquired an array of 28 exploration projects located along the Texas Gulf Coast from Esenjay Petroleum Corporation ("EPC") and Aspect Resources LLC ("Aspect") pursuant to an Acquisition Agreement and Plan of Exchange (as amended, the "Acquisition Agreement"). At that time the Company's gas and oil properties and projects included an inventory of unproven, undeveloped exploration projects independently valued at over $64 million, coupled with only nominal existing production. The Company's exploration plan is directed by a comprehensive technical staff and the Company is managed by a group experienced in geology, geophysics, engineering, land, finance and related areas. The Exploration Projects also include the Company's interests in projects acquired since consummation of the Acquisitions. It is an integral portion of the Company's business to continually add to its Exploration Project inventory new internally generated 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. Industry partners typically participate in the Exploration Projects by purchase of a promoted interest from the Company. In September of 1999 the Company acquired 3DX Technologies Inc., pursuant to which acquisition it expanded its ownership in certain of its Exploration Projects, added interests in other projects, and expanded its technical staff. From 1998 through 2000 the Company has significantly increased its gas and oil production and reserves while continuing to add to its project inventory. OVERVIEW OF CURRENT ACTIVITIES AND RECENT EVENTS. 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 2,200 square miles, with additional 3-D seismic surveys planned for 2001. A significant number of the Exploration Projects have reached the drilling stage, and the Company has budgeted approximately $26 million to fund its drilling, completion, land and seismic activities in 2001. The budget is projected to fund the Company's net cost in over 50 wells. Included in the 2001 budget is the Company's net cost in approximately six planned delineation and/or development wells to be drilled in conjunction with the two recent field discoveries. The discoveries were the Grand Slam Field discovered by the Company's Runnells #3 well and the Hordes Creek Field discovered by its Pereira Childrens Trust #2 well. The Pereira Childrens Trust #2 well has been renamed the Hamman & Anderson #2 well. The Company believes that delineation of both fields, which are operated by the Company, can add substantial new proven reserves to the Company's gas and oil reserve base in 2001. The Company, which utilizes the successful efforts method of accounting, entered 2001 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 $3,500,000 per month in oil and gas revenues in the fourth quarter of 2000. Its revenue began to grow rapidly in the second half of 1999 as wells drilled after closing of the transactions pursuant to the 3 Acquisition Agreement began to rapidly come on line. Gas and oil production is expected to continue to increase in 2001. Revenues in 2001 are expected to exceed those in 2000. In addition, since December 31, 2000, the Company has reset its long term credit facility with Deutsche Bank AG, New York Branch. The facility included $20,341,782 outstanding at December 31, 2000 of which $6,750,000 was classified as current portion of long term debt. The reset total credit availability has been increased to $29,000,000. A summary of the impact of the successful efforts accounting method as it relates to the Acquisitions and a survey of the Company's history are set forth below. SUCCESSFUL EFFORTS ACCOUNTING AND RELATED MATTERS. The Company utilizes the successful efforts method of accounting. Under this method it expenses its exploratory 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, were comprised primarily of interests in unproven 3-D seismic based projects, and were 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 of unproved properties on a straight-line basis over a period not to exceed forty-eight months, as well as recognizing property specific impairments. As of December 31, 2000 the unamortized balance was $5,334,700. In 2000 this amortization resulted in a $5,176,100 expense and impairments totaled an additional $4,771,272. Impairments were primarily related to unproved property costs on projects regarding which management believes have diminished value based upon 2000 exploration activities. Hence significant non-cash charges primarily related to the accounting treatment of the Company's unproven properties have depressed reported earnings of the Company and will likely continue to do so in 2001; however, the non-cash charges will not affect cash flows provided by operating activities nor the ultimate realized value of the Company's natural gas and oil properties. The amortization of properties acquired pursuant to the Acquisitions will conclude not later than May of 2002. As a result of the tax rules applicable to the Acquisitions, the Company will likely not be able to fully use that portion of its existing net operating loss carry forward attributable to periods prior to May of 1998 in the future. OVERVIEW OF HISTORICAL DEVELOPMENTS - INCEPTION THROUGH DECEMBER 31, 1998. Prior to May of 1998 the Company operated on a much smaller scale. A negotiation process led to the Company entering into the Acquisition Agreement among the Company, EPC and Aspect. This Acquisition Agreement 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. Immediately after the shareholders meeting, the Company closed the transactions provided for in the Acquisition Agreement, implemented the Reverse Split, and completed the Reincorporation. 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 transactions significantly enhanced the Company's management team. 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 1999 ACTIVITIES. As a result of the above-described acquisitions, restructuring, and the underwritten offering, the Company believed it was, and believes it continues to be, positioned for a period of significant exploration activity on its technology enhanced projects. Many of the projects had 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, required several years and the investment of significant capital. Management believes the acquisition of projects at this advanced stage has not only reduced the drilling risk, but also positioned the Company to consistently drill on a broad array of exploration prospects for years to come. The Company ended 1999 having gone from nominal third quarter 1998 gas and oil revenues of 4 approximately $35,000 per month and large operating cash flow deficits to a company which averaged $1,815,637 per month in net oil and gas revenues in the fourth quarter of 1999. The increasing revenue allowed the Company to achieve positive operating cash flow (before capital expenditures, and before the costs of acquisition of new 3-D seismic data, and changes in working capital) in the third quarter, which operating cash flow increased in the fourth quarter. On May 12, 1999, the Company announced that it had entered into a Plan and Agreement of Merger with 3DX Technologies, Inc. ("3DX") which provided for the merger of 3DX into the Company. The shareholders of both companies approved the transaction at their respective meetings on September 23, 1999 and the merger was consummated the same day. The terms of the merger provided for 3DX shareholders to receive, at their election, either (i) the issuance of one share of Esenjay common stock for 3.25 shares of 3DX common stock; or (ii) the issuance of a new Esenjay convertible preferred stock at a ratio of one share of Esenjay convertible preferred stock for each 2.75 shares of 3DX common stock. The preferred stock did not require payment of dividends. Approximately 91% of the 3DX common shares converted into Esenjay common stock and approximately 9% were converted into Esenjay convertible preferred stock. As a result, Esenjay issued approximately 2,906,800 new shares of common stock and 356,999 shares of convertible preferred stock. The convertible preferred stock was redeemable at Esenjay's sole option until September 23, 2000 at $1.925 per share. It was subsequently redeemed in September of 2000. OVERVIEW OF 2000 ACTIVITIES. In 2000 the Company utilized its increased cash resources to increase its capital expenditures to approximately $25 million. The increased available capital allowed the Company to focus drilling on higher risk, higher potential opportunities. This risk profile led to the drilling of the Company's Runnells #3 discovery well located in the Duncan Slough project area in the fourth quarter of 2000 and its Pereira Children's Trust #2 well located in the Hordes Creek project area that was logged and completed in the first quarter of 2001. The Pereira Childrens Trust #2 well has subsequently been renamed the Hamman & Anderson #2 well. Both discoveries will be the focus of significant capital investment in 2001 as field delineation wells are drilled. In 2000 the Company participated in a total of 52 new wells that reached total depth and were logged during the year. Of the total wells drilled and logged during 2000, 29 were completed as of March 31, 2001, two are scheduled to commence production upon completion and pipeline connections, and 21 were dry holes. The Company added 19.256 billion cubic feet equivalent ("BCFE") of new gas and oil reserves from its 2000 drilling activities. The added reserves do not reflect the full potential of the Grand Slam Field anticipated to be ascertained through the delineation wells to be drilled in 2001, nor does it reflect any reserves attributable to the Hordes Creek Field which was not discovered until the first quarter of 2001. Year end 2000 reserves were adversely affected by 6.241 BCFE of downward adjustments in prior discoveries primarily related to wells located in the Hackberry trend. The Hackberry wells were previously believed by Company engineers and by the Company's independent reservoir engineers to be primarily depletion drive reservoirs but actual results showed a stronger water drive component that shortened the wells' lives and led to the downward adjustments. These adjustments are incorporated in the December 31, 2000 gas and oil reserve studies. Year end totals were also affected by the sale of 3.398 BCFE pursuant to a transaction with an industry partner closed in early 2000. On September 23, 2000, the Company redeemed all of its previously outstanding preferred stock. The redemption was pursuant to a unilateral right to redeem in favor of the Company. A total of 356,999 shares of preferred stock were redeemed at the contractual redemption price of $1.925 per share. On October 12, 2000 the Company finalized and closed an agreement with 420 Energy Investments, Inc. ("420") pursuant to which $864,000 in non-recourse debt and $562,034 in interest on non-recourse debt was satisfied. Consideration paid to 420 was $300,000 in cash, plus an agreement to drill one well in the project area, plus an agreement to pay to 420 cash payments on the date drilling may commence on any future wells it may drill on one exploration project area located in Terrebonne Parish, Louisiana. Any such future payments would range from $20,000 per well to $100,000 per well, but would never exceed a total of $300,000. In addition, 420 retained its prior right to an overriding royalty equal to 2% of the Company's interest in any well drilled in the project area in Terrebonne Parish. As a result of the transaction, the Company recognized an extraordinary gain in the fourth quarter of 2000 of $1,126,034. The initial well in which the Company participated was drilled in the fourth quarter. It elected to not participate in completion of the well due to what the Company believed were marginal expected economics. The Company has no obligation or any current plans to drill any future wells on the project acreage. 5 On October 2, 2000 the Company announced it had retained Deutsche Bank Securities, Inc. to advise it concerning various strategic alternatives intended to better maximize shareholder value. It also retained the firm of Randall & Dewey, Inc. to initiate and manage a transaction to seek to better realize this value through various alternatives such as selling the Company for cash, merger, stock trade or acquisition. Since the Company's recent field discoveries, the Company has determined that it can better maximize shareholder value by drilling delineation wells near the discoveries and executing its overall exploratory drilling plan. Accordingly, it has announced that it does not plan to actively pursue new alternatives for a potential sale of the Company. OVERVIEW OF 2001 ACTIVITIES. The Company believes it entered 2001 in a position to continue to expand its production and reserves via exploration activities on its technology-enhanced projects. By utilizing the increased capital available to it from operating cash flow, financings and industry partner transactions, the Company intends to pursue an aggressive exploration budget in its major trends of activity. The Company's net daily production approximated 364 barrels of oil per day and 16,681 Mcf natural gas per day in March of 2001. Subsequent to December 31, 2000, the Company reset its credit facility with Deutsche Bank AG, New York Branch. Availability pursuant to the facility was increased to $29 million with a borrowing base adjustment scheduled for the end of the second quarter of 2001. The facility is divided into two tranches. Tranche A is a revolving credit facility with $20 million available of which $14.84 million was outstanding on March 29, 2001. No principal amortization is required on Tranche A in 2001. Tranche B is a $9 million loan that amortizes in four equal principal payments beginning April 30, 2001. As a result of its current operating cash flow combined with available credit and the proceeds of anticipated sales of select Exploration Project interests to industry partners, the Company believes it is positioned to fund its 2001 drilling and exploration activities, the results of which are intended to continue the upward trends of increasing cash flow and reserves. The Company will look to a variety of sources in addition to operating cash flow to further supplement its capital expenditures budget, including its credit facilities and sales of additional promoted project interests to industry partners, as it seeks to maximize its interests and manage its risks while aggressively pursuing its exploration projects. The Company has budgeted $26 million in drilling, completion, land and seismic expenditures on interests in over 50 wells in 2001. Through this exploration program, the Company believes it can continue its trends of growth in net production, net revenues, operating cash flow, and net gas and oil reserves throughout the year 2001 and beyond. Its 2001 drilling activity will primarily be divided between a continuation of exploratory drilling on high potential target features, which drilling will be coupled with the field delineation and development drilling associated with the Company's recent field discoveries. An array of lower risk prospects will also be drilled, the cost of which will be a modest portion of the capital budget. As of March 30, 2001, the Company has 18,980,698 total shares of common stock outstanding. It employs thirty-four full time employees, including five in its exploration and geophysical departments, seven in its operations department, two in its exploitation department, and seven in its land department. Its focus continues to be the implementation of its business strategy as set forth in this section. STRATEGY The Company's strategy is to expand its reserves, production and cash flow through the implementation of an exploration program that is oriented toward (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 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 reservoirs 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 6 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 more accurately map structural features to detect seismic anomalies 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. 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, had worked together for over 15 years. It further expanded its technical staff when it acquired 3DX in September of 1999. In addition, the Company has agreements 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 often seeks to reduce exploration risks by exploring at moderate depths that are deep enough to discover sizable 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 is also pursuing potential prospects in deep gas provinces in which 3-D seismic and CAEX technologies are used to identify a structural image of the subsurface. Generally, reservoirs at deeper depths are not conducive to direct hydrocarbon detection but have potential for the discovery of greater quantities of hydrocarbons. 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 controlling interest in many of the Exploration Projects, including proprietary interests in most of the 3-D seismic data relating to those projects. 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 a majority of the wells drilled within the Exploration Projects. EXPLORATION PROJECTS Most of the Exploration Projects are concentrated within the Frio, Wilcox, Texas Hackberry and Yegua core project areas. The Frio core area generally is in the middle Texas Gulf Coast where the Company believes Frio targets exist at moderate to deeper 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. The Yegua trend extends from San Patricio County in Texas through Beauregard and Calcasieu Parishes in Louisiana. The Company became active in two 7 portions of this trend in 1999. Other Exploration Projects include 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. Because each Exploration Project consists of a bundle of assets which may or may not include a working interest in the project, the Company's Project Interest simply represents the Company's proportional ownership in the bundle of assets that constitute the Exploration Project. 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. It is possible that while the Company may own a 50.0% Project Interest, it may only be entitled to 25.0% of the working interest involved in the Exploration Project. Each Exploration Project represents a negotiated transaction between the project partners. The Company's working interest may be higher or lower than its Project Interest. The following table sets forth certain information about each of the Exploration Projects:
EXPLORATION PROJECTS ACRES LEASED OR UNDER OPTION AT SQUARE MILES OF MARCH 27, 2001(1) 3-D SEISMIC DATA PROJECT PROJECT COMPANY RELATING TO PROJECT PROJECT AREAS GROSS NET NET PROJECT AREA INTEREST(2) - ------------------------------------- ------------ ------------- ------------ -------------------- -------------- SOUTH TEXAS FRIO CORE AREA Allen Dome................... 730.05 424.37 384.58 53 90.62% Lafite....................... 4,792.60 4,672.15 4,432.17 53 94.86% Gillock...................... 16,054.65 13,293.09 4,933.91 70 37.12% Blessing..................... 80.00 80.00 27.14 22 33.93% Tidehaven.................... 2,536.68 2,034.23 1,060.40 28 52.13% El Maton..................... 4,080.47 3,257.79 2,120.19 29 65.08% Midfield..................... 1,978.40 1,097.85 952.13 21 86.73% Markham...................... 2,126.24 2,126.24 718.37 5 33.79% Buckeye Ranch................ 2,898.74 1,861.73 837.65 40 44.99% Duncan Slough................ 4,902.54 3,643.61 1,638.08 25 44.96% SW Pheasant (Francitas)...... 1,102.95 732.99 549.72 10 75.00% La Rosa...................... 80.00 80.00 7.60 25 9.50% Vicksburg Area II Phase I.... 3,522.02 3,410.68 1,446.46 76 42.41% Vicksburg Area II Phase II... 1,126.63 1,126.63 473.18 50 42.00% Wolf Point................... 632.00 632.00 174.75 8 27.65% Archie....................... 489.40 489.40 88.71 14 18.13% Powerhorn/Matagorda Bay...... 480.00 480.00 72.00 30 15.00% Raymondville................. 12,412.19 12,345.04 6,920.30 62 56.06% Smith Point.................. --- --- --- 80 7.50% ------------ ------------- ------------ -------------------- Frio Sub-Total 60,025.56 51,787.80 26,837.34 701 WILCOX CORE AREA Gila Bend.................... 531.84 531.84 78.22 16 14.71% Hall Ranch................... 8,412.92 7,618.18 3,001.80 57 39.40% Hordes Creek................. 4,889.58 4,842.91 2,043.00 25 42.19% Mikeska W.................... 5,540.49 5,256.85 1,974.79 32 37.57% Hagist Ranch N E............. 1,979.59 1,979.60 1,781.62 10 90.00% Verdad....................... 4,918.53 4,671.85 1,191.10 40 25.50% Orangedale West.............. 2,314.33 2,207.81 1,980.24 10 89.69% Riverdale.................... 7,351.71 7,059.41 1,764.87 23 25.00% ------------ ------------- ------------ -------------------- Wilcox Sub-Total 35,938.99 34,168.45 13,815.64 213 TEXAS HACKBERRY CORE AREA Lox B 4,345.05 2,091.14 504.57 62 24.99% West Port Acres.............. 728.95 650.55 81.32 21 12.50% 8 EXPLORATION PROJECTS ACRES LEASED OR UNDER OPTION AT SQUARE MILES OF MARCH 27, 2001(1) 3-D SEISMIC DATA PROJECT PROJECT COMPANY RELATING TO PROJECT PROJECT AREAS GROSS NET NET PROJECT AREA INTEREST(2) - ------------------------------------- ------------ ------------- ------------ -------------------- -------------- Stowell/Big Hill............. 1,462.00 943.46 103.51 56 10.97% Cheek 11,367.85 8,305.05 1,116.90 48 13.45% Lovell Lake.................. 11,687.91 9,559.19 1,594.55 65 16.68% West Beaumont................ 1,071.91 850.80 62.73 23 7.37% ------------ ------------- ------------ -------------------- Texas Hackberry Sub-Total 30,663.67 22,400.19 3,463.58 275 YEGUA CORE AREA Papalote..................... 36,562.00 35,332.76 18,654.18 98 52.80% Inez......................... 202.51 199.26 68.20 10 34.23% West Inez.................... 56.67 56.67 56.67 10 100.00% Mathis....................... 924.55 924.55 508.51 40 55.00% TBC ........................ 44,695.00 37,214.00 14,888.00 90 40.00% South Louisiana Eocene....... 6,271.41 6,191.94 1,601.30 85 25.86% Howards Creek................ 33,409.93 33,362.26 7,292.82 85 21.86% ------------ ------------- ------------ -------------------- Yegua Sub-Total 122,122.07 113,281.44 43,069.68 418 OTHER LOUISIANA Four Isle Dome 80 7.50% Starboard Lapeyrouse......... 3,893.68 2,739.15 693.79 35 25.33% ------------ ------------- ------------ -------------------- Louisiana Sub-Total 3,893.68 2,739.15 693.79 115 OTHER TEXAS East Texas Pinnacle Reef(3).. TBD TBD TBD 400 TBD ------------ ------------- ------------ -------------------- Other Texas Sub-Total TBD TBD TBD 400 MISSISSIPPI Thompson Creek............... 798.15 696.73 657.05 12 94.30% Melvin....................... 275.16 255.18 58.80 64 23.04% ------------ ------------- ------------ -------------------- Mississippi Sub-Total 1,073.31 951.91 715.85 76 ------------ ------------- ------------ -------------------- TOTAL ALL PROJECTS 253,717.28 225,328.94 88,595.88 2,198 ============ ============= ============ ====================
- ------------ (1) Project Gross acres refers to the number of acres within a project. Project Net acres refers to leaseable acreage by tract. Company Net acres are either leased or under option in which the Company owns an undivided interest. Company Net acres were determined by multiplying the project net 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. Because each Exploration Project consists of a bundle of assets which may or may not include a working interest in the project, the Company's Project Interest simply represents the Company's proportional ownership in the bundle of assets that constitute the Exploration Project. 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. It is possible that while the Company may own a 50.0% Project Interest, it may only be entitled to 25.0% of the working interest involved in the Exploration Project. Each Exploration Project represents a negotiated transaction between the project partners. The Company's working interest may be higher or lower than its Project Interest. (3) Consists of approximately 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 AREA DESCRIPTIONS. The Company is focused on certain core project areas along the Texas and Louisiana Gulf Coast where it has pursued a trend strategy. Focusing on trends, as opposed to individual projects, allows the Company the opportunity to gain and exploit regional knowledge, develop competitive advantages and provide expansion room once concepts are proven. 9 The Company's four core trend areas are characterized by high reservoir quality, an extensive knowledge base due to technical staff experience and focus, and geophysical characteristics suitable to 3-D seismic imaging. The four core trend areas are further described below: FRIO CORE AREA. In the Frio Trend, the Company has interests in 19 3-D seismic surveys that cover approximately 700 square miles. It plans to drill and/or participate in approximately 40 wells in the Frio Trend in 2001. This trend extends across the Texas Gulf Coast from the Houston area to the border of Mexico. Esenjay has numerous projects and prospects scattered throughout this large trend and has significantly increased its planned capital expenditures in the trend as compared with 2000. WILCOX CORE AREA. In the Wilcox Trend, the Company has nine 3-D seismic surveys covering approximately 213 square miles. It plans to drill approximately 10 wells in the Wilcox Trend in 2001. This trend extends through Texas from Louisiana to Mexico. Production from the Wilcox ranges from the very shallow to over 16,000 feet in depth. The Company's focus is on certain of the portions of the Wilcox Trend generally located below 10,000 feet. These deeper portions have historically had less total drilling and allow the Company ample room to expand its activities should success in 2001 and beyond so warrant. It has significantly increased its 2001 capital budget (as compared to 2000) in this area which it believes to represent exceptional upside potential. TEXAS HACKBERRY CORE AREA. The Texas Hackberry Trend, sometimes referred to as the Hackberry Embayment, is an area in which the Company has interests in six 3-D seismic surveys covering approximately 275 square miles. It plans to drill at least seven wells in the Hackberry Trend in 2001. Based on its experience and the experience of certain of its affiliates, the Company believes that the portions of the Hackberry formation in geographical proximity to the Gulf of Mexico and the Texas/Louisiana border have proven to be an excellent area for the use of 3-D seismic data. Historical drilling in the Hackberry Sands had exhibited low historical success rates that have been greatly improved in the Company's experience in projects in which it has participated in the Hackberry through the use of 3-D seismic data. The Company has drilled 21 successful wells out of 29 attempts utilizing modern 3-D seismic data. Included in the seismic evaluation of the Texas Hackberry Trend has been significantly use of direct hydrocarbon detection technologies. YEGUA CORE AREA. In the Yegua Trend, the Company currently has interests in six 3-D seismic surveys. The Company will own interests in an aggregate of approximately 418 square miles of 3-D seismic data in the trend in 2001. The Company expects to drill approximately six wells in the Yegua Trend in 2001. This trend extends from Beauregard Parish, Louisiana, to San Patricio County, Texas, and is generally characterized by structural and stratigraphically trapped hydrocarbons that may appear on 3-D seismic data as seismic anomalies. The Company believes that the area is comprised of physical characteristic such that it will be well situated for direct hydrocarbon detection technologies. 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 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 over 20 years, these methods were not affordable by smaller, independent gas and oil companies until more recently, when improved data 10 acquisition equipment and techniques and computer technology became available at reduced costs. The Company 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 its own results in 1999 and 2000. 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. 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. 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 primarily along the Gulf Coast of Texas and Louisiana. 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 de-emphasized 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 or as changing market conditions may warrant. 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. In February of 2000, in conjunction with its financing with Deutsche Bank, the Company established natural gas hedges with an affiliate of Deutsche Bank. Pursuant to these hedges, the Company then had 9,381 MMBtu/day of net production hedged for the first quarter of 2000, 9,031 MMBtu/day hedged for the second quarter of 2000, 8,646 MMBtu/day for the third quarter of 2000, 8,278 MMBtu/day for the fourth quarter of 2000, 7,161 MMBtu/day for the first quarter of 2001, 6,880 MMBtu/day for the second quarter of 2001, 6,600 MMBtu/day for the third quarter of 2001, and 6,319 MMBtu/day for the fourth quarter of 2001. All hedges were at $2.45 per MMBtu. These hedges were restructured in January of 2001 for all periods beginning February 1, 2001, and any rights or obligations of the Company pursuant to the previously existing $2.45 hedges were cancelled. Pursuant to the restructured agreements, the Company has subjected volumes of its Gulf Coast natural gas production to a "collar" structure with a floor price of $3.25 per MMBtu and a ceiling or cap price of $4.00 per MMBtu. Volumes committed to this structure are 7,500 MMBtu per day in February and March of 2001, 7,900 MMBtu per day in the second quarter of 2001, and 8,000 MMBtu per day in the third and fourth quarter of 2001. In 2002, volumes committed are 8,500, 8,000, 7,500 and 7,000 MMBtu per day in the first through fourth quarters respectively. Finally, volumes committed to the collar structure include 4,500 MMBtu per day for calendar year 2003. 11 In the third quarter of 2000 the Company hedged an additional 5,000 MMBtu/day of natural gas. The hedge prices were at $4.70 per MMBtu for the months of September through December 2000, and at $4.01 per MMBtu for the months of January through December 2001. These hedges were not restructured and also remain in effect. In September of 1999, the Company entered into a "collar" hedge arrangement on certain of its oil production. It entered into an oil hedge for a quantity equal to 300 barrels of oil per day in the fourth quarter of 1999, 280 barrels of oil per day in the first quarter of 2000, 256 barrels of oil per day in the second quarter of 2000, and 237 barrels of oil per day in the third quarter of 2000, all of which transactions were structured with an $18.00 floor price and a $20.40 cap price. These positions were supplemented with oil hedges for 238 barrels of oil per day in the fourth quarter of 2000, and 175 barrels of oil per day, 168 barrels of oil per day, 161 barrels of oil per day and 154 barrels of oil per day for the first through fourth quarters of 2001, respectively, all of which supplemental hedges were at $21.03 per barrel. These hedges also remain in effect. As a result of the above-referenced transactions, the Company has hedged varying quantities of its natural gas through December of 2003 and varying quantities of its oil production through December of 2001. First quarter 2001 hedges are estimated to approximate 76.6% of the Company's natural gas production and 50.5% of its oil production for such quarter. Future percentages will vary. All of the Company's natural gas and oil production is now sold under market-sensitive or spot price contracts. The Company's revenues from natural gas and oil sales fluctuate depending upon the market price of natural gas or oil. In 1999, purchasers accounting for more than 10% of the Company's total revenue were Coral Energy Resources, L.P., Pan Energy Marketing Company, Duke Energy Trading & Marketing and Duke Energy Field Services, Inc. In 2000, purchasers accounting for more than 10% of the Company's total revenue were Duke Energy Transportation and Trading, Gulf Energy Marketing, LLC and PG&E Texas Industrial Energy. The Company does not believe the loss of any existing purchaser would have a material adverse effect on the Company. The Company previously had a credit facility with Duke Energy Financial Services, Inc. ("Duke"), pursuant to which an ongoing agreement was established which still allows affiliates of Duke 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. The Company expects that its daily production will continue to increase and it will periodically consider additional hedge transactions consistent with its ongoing policy. Its policy is to periodically review its projected natural gas and oil production from proved developed properties in light of then current market conditions. Its objective is to seek a balance pursuant to which it can prudently stabilize its future cash flows from proven producing properties while providing ongoing upside potential should product prices increase. 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. 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' 12 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 provide coverage in scope and in amounts 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 obtain coverage. Any difficulty in obtaining coverage may impair the Company's ability to engage in its business activities. REGULATION GENERAL. The oil and gas 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 regulations 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. 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 utilization 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. FEDERAL REGULATIONS SALES AND TRANSPORTATION OF NATURAL GAS. Historically, the transportation and sales for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938 ("NGA"), the Natural Gas Policy Act of 1978 ("NGPA") and Federal Energy Regulatory Commission ("FERC") regulations. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act deregulated price for all "first sales" of natural gas. Thus, all sales of gas by the Company may be made at market prices, subject to applicable contract provisions. Sales of natural gas are affected by the availability, terms and cost of pipeline transportation. Since 1985, the FERC has implemented regulations intended to make natural gas transportation more accessible to gas buyers and sellers on an open-access, non-discriminatory basis. Beginning in April 1992, the FERC issued Order No. 636 and a series of related orders, which required interstate pipelines to provide open-access transportation on a not unduly discriminatory basis for all natural gas shippers. The FERC has stated that it intends for Order No. 636 and its future restructuring activities to foster increased competition within all phases of the natural gas industry. Although Order No. 636 does not directly regulate our production and marketing activities, it does affect how buyers and sellers gain access to the necessary transportation facilities and how we and our competitors sell natural gas in the marketplace. The courts have largely affirmed the significant features of Order No. 636 and the numerous related orders pertaining to individual pipelines. However, some appeals remain pending and the FERC continues to review and modify its regulations regarding the transportation of natural gas. For example, the FERC issued Order No. 637 13 which: o lifts the cost-based cap on pipeline transportation rates in the capacity release market until September 30, 2002, for short-term releases of pipeline capacity of less than one year, o permits pipelines to file for authority to charge different maximum cost-based rates for peak and off-peak periods, o encourages, but does not mandate, auctions for pipeline capacity, o requires pipelines to implement imbalance management services, o restricts the ability of pipelines to impose penalties for imbalances, overruns and non-compliance with operational flow orders, and o implements a number of new pipeline reporting requirements. Order No. 637 also requires the FERC staff to analyze whether the FERC should implement additional fundamental policy changes. These include whether to pursue performance-based or other non-cost based ratemaking techniques and whether the FERC should mandate greater standardization in terms and conditions of service across the interstate pipeline grid. In April 1999 the FERC issued Order No. 603, which implemented new regulations governing the procedure for obtaining authorization to construct new pipeline facilities. In September 1999, the FERC issued a related policy statement establishing a presumption in favor of requiring owners of new pipeline facilities to charge rates for service on new pipeline facilities based solely on the costs associated with such new pipeline facilities. We cannot predict what further action the FERC will take on these matters, nor can we accurately predict whether the FERC's actions will achieve the goal of increasing competition in markets in which our natural gas is sold. However, we do not believe that any action taken will affect the Company in a way that materially differs from the way it affects other natural gas producers, gatherers and marketers. The Outer Continental Shelf Lands Act, which the FERC implements as to transportation and pipeline issues, requires that all pipelines operating on or across the Outer Continental Shelf provide open-access, non-discriminatory service. Historically, the FERC has opted not to impose regulatory requirements under its Outer Continental Shelf Lands Act authority on gatherers and other entities outside the reach of its NGA jurisdiction. However, the FERC recently issued Order No. 639, requiring that virtually all non-proprietary pipeline transporters of natural gas on the Outer Continental Shelf report information on their affiliations, rates and conditions of service. The reporting requirements established by the FERC in Order No. 639 may apply, in certain circumstances, to operators of production platforms and other facilities on the Outer Continental Shelf, with respect to gas movements across such facilities. Among the FERC's stated purposes in issuing such rules was the desire to increase transparency in the market, to provide producers and shippers on the Outer Continental Shelf with greater assurance of (a) open-access services on pipelines located on the Outer Continental Shelf and (b) non-discriminatory rates and conditions of service on such pipelines. The FERC retains authority under the Outer Continental Shelf Lands Act to exercise jurisdiction over gatherers and other entities outside the reach of its NGA jurisdiction if necessary to ensure non-discriminatory access to service on the Outer Continental Shelf. We do not believe that any FERC action taken under its Outer Continental Shelf Lands Act jurisdiction will affect us in a way that materially differs from the way it affects other natural gas producers, gatherers and marketers. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC and the courts. 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. 14 SALES AND TRANSPORTATION OF CRUDE OIL. Sales of crude oil, condensate and natural gas liquids by the Company are not currently regulated, and are subject to applicable contract provisions made at market prices. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to the FERC's jurisdiction under the Interstate Commerce Act. In other instances, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes. The regulation of pipelines that transport crude oil, condensate and natural gas liquids is generally more light-handed than the FERC's regulation of gas pipelines under the NGA. Regulated pipelines that transport crude oil, condensate, and natural gas liquids are subject to common carrier obligations that generally ensure non-discriminatory access. With respect to interstate pipeline transportation subject to regulation of the FERC under the Interstate Commerce Act, rates generally must be cost-based, although market-based rates or negotiated settlement rates are permitted in certain circumstances. Pursuant to FERC Order No. 561, pipeline rates are subject to an indexing methodology. Under this indexing methodology, pipeline rates are subject to changes in the Producer Price Index for Finished Goods, minus one percent. A pipeline can seek to increase its rates above index levels provided that the pipeline can establish that there is a substantial divergence between the actual costs experienced by the pipeline and the rate resulting from application of the index. A pipeline can seek to charge market-based rates if it establishes that it lacks significant market power. In addition, a pipeline can establish rates pursuant to settlement if agreed upon by all current shippers. A pipeline can seek to establish initial rates for new services through a cost-of-service proceeding, a market-based rate proceeding, or through an agreement between the pipeline and at least one shipper not affiliated with the pipeline. The FERC indicated in Order No. 561 that it will assess in 2000 how the rate-indexing method is operating. The FERC issued a Notice of Inquiry on July 27, 2000 seeking comment on whether to retain or to change the existing index. After consideration of all the initial and reply comments, the FERC concluded on December 14, 2000 that the PPI-1 index has reasonably approximated the actual cost changes in the oil pipeline industry during the preceding five year period, and that it should be continued for the subsequent five year period. FEDERAL LEASES. The Company maintains operations located on federal oil and gas leases, which are administered by the Minerals Management Service pursuant to the Outer Continental Shelf Lands Act. These leases are issued through competitive bidding and contain relatively standardized terms. These leases require compliance with detailed Minerals Management Service regulations and orders that are subject to interpretation and change by the Minerals Management Service. For offshore operations, lessees must obtain Minerals Management Service approval for exploration, development and production plans prior to the commencement of such operations. In addition to permits required from other agencies such as the Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency, lessees must obtain a permit from the Minerals Management Service prior to the commencement of drilling. The Minerals Management Service has promulgated regulations requiring offshore production facilities located on the Outer Continental Shelf to meet stringent engineering and construction specifications. The Minerals Management Service also has regulations restricting the flaring or venting of natural gas, and has proposed to amend such regulations to prohibit the flaring of liquid hydrocarbons and oil without prior authorization. Similarly, the Minerals Management Service has promulgated other regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all production facilities. To cover the various obligations of lessees on the Outer Continental Shelf, the Minerals Management Service generally requires that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be met. The cost of these bonds or assurances can be substantial, and there is no assurance that they can be obtained in all cases. Under some circumstances, the Minerals Management Service may require operations on federal leases to be suspended or terminated. The Minerals Management Service also administers the collection of royalties under the terms of the Outer Continental Shelf Lands Act and the oil and gas leases issued under the Act. The amount of royalties due is based upon the terms of the oil and gas leases as well as of the regulations promulgated by the Minerals Management Service. These regulations are amended from time to time, and the amendments can affect the amount of royalties that we are obligated to pay to the Minerals Management Service. However, we do not believe that these regulations or any future amendments will affect the Company in a way that materially differs from the way it affects other oil and gas producers, gathers and marketers. 15 STATE REGULATIONS Most states regulate the production and sale of oil and natural gas, including requirements for obtaining drilling permits, the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and gas resources. The rate of production may be regulated and the maximum daily production allowable from both oil and gas wells may be established on a market demand or conservation basis or both. The Company may enter into agreements relating to the construction or operation of a pipeline system for the transportation of natural gas. To the extent that such gas is produced, transported and consumed wholly within one state, such operations may, in certain instances, be subject to the jurisdiction of such state's administrative authority charged with the responsibility of regulating intrastate pipelines. In such event, the rates which the Company could charge for gas, the transportation of gas, and the construction and operation of such pipeline would be subject to the rules and regulations governing such matters, if any, of such administrative authority. LEGISLATIVE PROPOSALS In the past, Congress has been very active in the area of natural gas regulation. There are legislative proposals pending in the various state legislatures which, if enacted, could significantly affect the petroleum industry. At the present time it is impossible to predict what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on the Company's operations. 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 exploratory or producing properties is affected by the amount of funds available to the Company, information about 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 $124,548. The lease expires in September 2001. The Company leases approximately 13,300 square feet of office space in Corpus Christi, Texas. The annual rent is $168,137, and the Lease expires on June 30, 2003. The Company currently has more office space than it needs in Corpus Christi, and has sublet a portion of its office space. EMPLOYEES The Company has nine full-time employees in its Houston, Texas office, and twenty-five employees in its Corpus Christi, Texas office. Their functions include management, production, engineering, geology, geophysics, exploitation, 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. The Company believes its relationship with its employees is satisfactory. 16 ITEM 2. DESCRIPTION OF PROPERTY PRINCIPAL AREAS OF OPERATIONS The Company owns and operates producing properties located in five states with proved reserves located primarily in Louisiana and Texas. Daily production from both operated and non-operated wells net to the Company's interest averaged 9,290 Mcf per day and 276 Bbls of oil per day for the year ended December 31, 1999 and 16,055 Mcf per day and 449 Bbls of oil per day for the year ended December 31, 2000. These properties have provided most of the Company's revenues to date. DRILLING ACTIVITY From November 1, 1997 (the effective date of the Acquisitions) through December 31, 1998, 24 exploratory wells were drilled for the Company's account, of which 12 were completed and 11 were dry holes. In 1999, 23 exploratory and six developmental wells were drilled and logged for the Company's account of which 22 were completed and seven were dry holes. In 2000, 41 exploratory and 11 developmental wells were drilled and logged for the Company's account of which 29 were completed as of March 30, 2001, two were waiting on completion and/or pipelines, and 21 were dry holes. The following table sets forth certain information regarding the actual drilling results for each of the years 1999 and 2000 as to wells drilled in each such individual year.
EXPLORATORY DEVELOPMENT WELLS(1) WELLS(1) ------------------------ -------------------- GROSS NET GROSS NET ----- --- ----- --- 1999 Productive ........................ 16 2.41 6 1.46 Dry................................ 7 0.87 --- --- 2000 Productive......................... 25 5.994 6 1.559 Dry................................ 16 5.275 5 1.412
- -------------------- (1) Gross wells represent the total number of wells in which the Company owned an interest; net wells represent the total of the Company's net working interests owned in the wells. Through the first quarter of 2001, the Company participated in the drilling of 11 additional exploratory wells and four additional development wells, of which one had been completed, five are awaiting completion, two were dry holes and seven were drilling. PRODUCTIVE WELL SUMMARY The following table sets forth certain information regarding the Company's ownership as of December 31, 2000 of productive gas and oil wells in the areas indicated.
GAS OIL -------------------- -------------------- GROSS NET GROSS NET -------- -------- -------- -------- Alabama ...................................... -- -- 1 .17 Kansas ....................................... 1 .10 -- -- Louisiana .................................... 4 .18 -- -- Oklahoma...................................... 4 .13 1 .19 Texas......................................... 59 10.43 15 1.69 -------- -------- -------- -------- Total .................................... 68 10.84 17 2.05 ======== ======== ======== ========
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 17 indicated.
YEAR ENDED DECEMBER 31, ----------------------------------- 2000 1999 ---------------- --------------- Net Production: Oil (Bbl) ............................................ 163,892 100,559 Gas (Mcf)............................................. 5,860,195 3,381,592 Gas equivalent (Mcfe)................................. 6,843,547 3,984,946 Average sales price: Oil ($ per Bbl)............................................... $ 32.34(1) $ 18.01(1) Gas ($ per Mcf)....................................... $ 4.12(1) $ 2.35(1) Average production expenses and taxes ($ per Mcfe)............ $ 0.48 $ 0.35
----------- (1) Average sales prices do not include the Company's hedging instruments for oil and gas. Including the effect of hedging activities, average sales prices would have been $29.38 per Bbl and $3.38 per Mcf for the year ended December 31, 2000, and $19.01 per Bbl and $2.36 per Mcf for the year ended December 31, 1999. LEASEHOLD ACREAGE The following table sets forth as of December 31, 2000, the gross and net acres of proved developed and proved undeveloped and unproven gas and oil leases which the Company holds or has the right to acquire.
PROVED DEVELOPED PROVED UNDEVELOPED UNPROVEN ----------------- ------------------- ------------------ STATE GROSS NET GROSS NET GROSS NET ----- ------ ------ ------- ------- -------- ------- Alabama.................................... 82 19 --- --- 113 22 Arkansas .................................. --- --- --- --- 6,360 2,544 Kansas .................................... 640 31 --- --- --- --- Louisiana ................................. --- --- --- --- 17,859 3,057 Mississippi................................ 82 7 --- --- 795 443 Oklahoma .................................. 2,198 51 --- --- 12,909 3,727 Texas ..................................... 18,292 4,239 1,180 346 193,017 64,537 ------ ----- ----- --- ------- ------ Total ............................ 21,294 4,347 1,180 346 231,053 74,330 ====== ===== ===== === ======= ======
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 Deutsche Bank AG, New York Branch a mortgage or a right to file a mortgage on virtually all of its gas and oil properties to secure repayment of its credit facility with the bank. ITEM 3. LEGAL PROCEEDINGS The Company currently has no action filed against it other than ordinary routine litigation. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS There were no such matters submitted in the fourth quarter of 2001. 18 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 and its Series A Warrants were admitted to trading on the NASDAQ Small Cap Market under the symbols "FNGC" and "FNGCW", respectively. In November of 1998, the Series A Warrants expired. 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. There have been no reported trades of the Series B Warrants since that time. The Series B Warrants are exercisable for $12.15 per share of common stock of the Company, and expire on the earlier of August 8, 2001 or such time as the stock trades over $24.30 for twenty consecutive days. On September 23, 1999, the Company acquired 3DX Technologies Inc. via merger. The price of the acquisition was approximately $7.4 million, of which $6.7 million was in the form of Company's common stock and $0.7 million was in the form of Company preferred stock. As a result, Esenjay issued 356,999 shares of new convertible preferred stock that could be redeemed at Esenjay's sole option until September 23, 2000 at $1.925 per share. Said 356,999 shares of convertible preferred stock were redeemed by the Company on September 23, 2000. The convertible preferred stock was listed on the over-the-counter bulletin board under the symbol "ESNJP". There were no 1999 or 2000 trades reported in this series of preferred stock prior to its redemption. The Company's common stock trades on the NASDAQ Small Cap Market under the symbol "ESNJ". The Company estimates there are approximately 145 common shareholders of record and 2,977 beneficial owners of the common stock. The following table sets forth, for the periods indicated, the high and low sales prices of the Company's Common Stock as reported on the Nasdaq Small-Cap Market.
Quarter Ended High Low ------------------------- --------- ---------- December 31, 2000 $ 5 3/16 $ 3 1/8 September 30, 2000 4 3/4 2 15/32 June 30, 2000 4 1/8 1 5/8 March 31, 2000 2 3/4 1 9/16 December 31, 1999 $ 2 3/8 $ 1 7/16 September 30, 1999 2 5/8 1 3/4 June 30, 1999 2 11/16 1 1/8 March 31, 1999 2 7/8 1
To date, the Company has not paid any dividends on its Common Stock. The payment of dividends, if any, in the future is within the discretion of the Board of Directors and will depend upon the Company's earnings, its capital requirements and financial condition and other relevant factors. Payments of dividends are also restricted in certain situations by the Company's credit agreement with Deutsche Bank. The Company does not expect to declare or pay any dividends on its Common Stock in the foreseeable future. ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS The following discussion and analysis reviews Esenjay Exploration, Inc.'s operations for the twelve month periods ended December 31, 2000 and 1999 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 19 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 A summary of the impact of the successful efforts accounting method as it relates to the Acquisitions and a survey of the Company's history are as follows: SUCCESSFUL EFFORTS ACCOUNTING AND RELATED MATTERS. The Company utilizes the successful efforts method of accounting. Under this method it expenses its exploratory 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, were comprised primarily of interests in unproven 3-D seismic based projects, and were 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 of unproved properties on a straight-line basis over a period not to exceed forty-eight months, as well as recognizing property specific impairments. As of December 31, 2000 the unamortized balance was $5,334,700. In 2000 this amortization resulted in a $5,176,100 expense and impairments totaled an additional $4,771,272. Impairments were primarily related to unproved property costs on projects regarding which management believes have diminished value based upon 2000 exploratory activities. Hence significant non-cash charges primarily related to the accounting treatment of the Company's unproven properties have depressed reported earnings of the Company and will likely continue to do so in 2001; however, the non-cash charges will not affect cash flows provided by operating activities nor the ultimate realized value of the Company's natural gas and oil properties. The amortization of properties acquired pursuant to the Acquisitions will conclude not later than May of 2002. As a result of the tax rules applicable to the Acquisitions, the Company will likely not be able to fully use that portion of its existing net operating loss carry forward attributable to periods prior to May of 1998 in the future. OVERVIEW OF HISTORICAL DEVELOPMENTS - INCEPTION THROUGH DECEMBER 31, 1998. Prior to May of 1998 the Company operated on a much smaller scale. A negotiation process led to the Company entering into the Acquisition Agreement among the Company, EPC, and Aspect. This Acquisition Agreement 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. Immediately after the shareholders meeting, the Company closed the transactions provided for in the Acquisition Agreement, implemented the Reverse Split, and completed the Reincorporation. 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 transactions significantly enhanced the Company's management team. 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 1999 ACTIVITIES. As a result of the above-described acquisitions, restructuring, and the underwritten offering, the Company believed it was, and believes it continues to be, positioned for a period of significant exploration activity on its technology enhanced projects. Many of the projects had 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, required several years and the investment of significant capital. Management 20 believes the acquisition of projects at this advanced stage has not only reduced the drilling risk, but also positioned the Company to consistently drill on a broad array of exploration prospects for years to come. The Company ended 1999 having gone from nominal third quarter 1998 gas and oil revenues of approximately $35,000 per month and large operating cash flow deficits to a company which averaged $1,815,637 per month in net oil and gas revenues in the fourth quarter of 1999. The increasing revenue allowed the Company to achieve positive operating cash flow (before capital expenditures, and before the costs of acquisition of new 3-D seismic data, and changes in working capital) in the third quarter, which operating cash flow increased in the fourth quarter. On May 12, 1999, the Company announced that it had entered into a Plan and Agreement of Merger with 3DX Technologies, Inc. ("3DX") which provided for the merger of 3DX into the Company. The shareholders of both companies approved the transaction at their respective meetings on September 23, 1999 and the merger was consummated the same day. The terms of the merger provided for 3DX shareholders to receive, at their election, either (i) the issuance of one share of Esenjay common stock for 3.25 shares of 3DX common stock; or (ii) the issuance of a new Esenjay convertible preferred stock at a ratio of one share of Esenjay convertible preferred stock for each 2.75 shares of 3DX common stock. The preferred stock did not require payment of dividends. Approximately 91% of the 3DX common shares converted into Esenjay common stock and approximately 9% were converted into Esenjay convertible preferred stock. As a result, Esenjay issued approximately 2,906,800 new shares of common stock and 356,999 shares of convertible preferred stock. The convertible preferred stock was redeemable at Esenjay's sole option until September 23, 2000 at $1.925 per share. It was subsequently redeemed in September of 2000. OVERVIEW OF 2000 ACTIVITIES. In 2000 the Company utilized its increased cash resources to increase its capital expenditures to approximately $25 million. The increased available capital allowed the Company to focus drilling on higher risk, higher potential opportunities. This risk profile led to the drilling of the Company's Runnells #3 discovery well located in the Duncan Slough project area in the fourth quarter of 2000 and its Pereira Children's Trust #2 well located in the Hordes Creek project area that was logged and completed in the first quarter of 2001. The Pereira Childrens Trust #2 well has subsequently been renamed the Hamman & Anderson #2 well. Both discoveries will be the focus of significant capital investment in 2001 as field delineation wells are drilled. In 2000 the Company participated in a total of 52 new wells that reached total depth and were logged during the year. Of the total wells drilled and logged during 2000, 29 were completed as of March 31, 2001, two are scheduled to commence production upon completion and pipeline connections, and 21 were dry holes. The Company added 19.256 billion cubic feet equivalent ("BCFE") of new gas and oil reserves from its 2000 drilling activities. The added reserves do not reflect the full potential of the Grand Slam Field anticipated to be ascertained through the delineation wells to be drilled in 2001, nor does it reflect any reserves attributable to the Hordes Creek Field which was not discovered until the first quarter of 2001. Year end 2000 reserves were adversely affected by 6.241 BCFE of downward adjustments in prior discoveries primarily related to wells located in the Hackberry trend. The Hackberry wells were previously believed by Company engineers and by the Company's independent reservoir engineers to be primarily depletion drive reservoirs but actual results showed a stronger water drive component that shortened the wells' lives and led to the downward adjustments. These adjustments are incorporated in the December 31, 2000 gas and oil reserve studies. Year end totals were also affected by the sale of 3.398 BCFE pursuant to a transaction with an industry partner closed in early 2000. On September 23, 2000, the Company redeemed all of its previously outstanding preferred stock. The redemption was pursuant to a unilateral right to redeem in favor of the Company. A total of 356,999 shares of preferred stock were redeemed at the contractual redemption price of $1.925 per share. On October 12, 2000 the Company finalized and closed an agreement with 420 Energy Investments, Inc. ("420") pursuant to which $864,000 in non-recourse debt and $562,034 in interest on non-recourse debt was satisfied. Consideration paid to 420 was $300,000 in cash, plus an agreement to drill one well in the project area, plus an agreement to pay to 420 cash payments on the date drilling may commence on any future wells it may drill on one exploration project area located in Terrebonne Parish, Louisiana. Any such future payments would range from $20,000 per well to $100,000 per well, but would never exceed a total of $300,000. In addition, 420 retained 21 its prior right to an overriding royalty equal to 2% of the Company's interest in any well drilled in the project area in Terrebonne Parish. As a result of the transaction, the Company recognized an extraordinary gain in the fourth quarter of 2000 of $1,126,034. The initial well quarter in which the Company participated was drilled in the fourth. It elected to not participate in completion of the well due to what the Company believed were marginal expected economics. The Company has no obligation or any current plans to drill any future wells on the project acreage. On October 2, 2000 the Company announced it had retained Deutsche Bank Securities, Inc. to advise it concerning various strategic alternatives intended to better maximize shareholder value. It also retained the firm of Randall & Dewey, Inc. to initiate and manage a transaction to seek to better realize this value through various alternatives such as selling the Company for cash, merger, stock trade or acquisition. Since the Company's recent field discoveries, the Company has determined that it can better maximize shareholder value by drilling delineation wells near the discoveries and executing its overall exploratory drilling plan. Accordingly, it has announced that it does not plan to actively pursue new alternatives for a potential sale of the Company. OVERVIEW OF 2001 ACTIVITIES. The Company believes it entered 2001 in a position to continue to expand its production and reserves via exploration activities on its technology-enhanced projects. By utilizing the increased capital available to it from operating cash flow, financings and industry partner transactions, the Company intends to pursue an aggressive exploration budget in its major trends of activity. The Company's net daily production approximated 364 barrels of oil per day and 16,681 Mcf natural gas per day in March of 2001. Subsequent to December 31, 2000, the Company reset its credit facility with Deutsche Bank AG, New York Branch. Availability pursuant to the facility was increased to $29 million with a borrowing base adjustment scheduled for the end of the second quarter of 2001. The facility is divided into two tranches. Tranche A is a revolving credit facility with $20 million available of which $14.84 million was outstanding on March 29, 2001. No principal amortization is required on Tranche A in 2001. Tranche B is a $9 million loan that amortizes in four equal principal payments beginning April 30, 2001. As a result of its current operating cash flow combined with available credit and the proceeds of anticipated sales of select Exploration Project interests to industry partners, the Company believes it is positioned to fund its 2001 drilling and exploration activities, the results of which are intended to continue the upward trends of increasing cash flow and reserves. The Company will look to a variety of sources in addition to operating cash flow to further supplement its capital expenditures budget, including its credit facilities and sales of additional promoted project interests to industry partners, as it seeks to maximize its interests and manage its risks while aggressively pursuing its exploration projects. The Company has budgeted $26 million in drilling, completion, land and seismic expenditures on interests in over 50 wells in 2001. Through this exploration program, the Company believes it can continue its trends of growth in net production, net revenues, operating cash flow, and net gas and oil reserves throughout the year 2001 and beyond. Its 2001 drilling activity will primarily be divided between a continuation of exploratory drilling on high potential target features, which drilling will be coupled with the field delineation and development drilling associated with the Company's recent field discoveries. An array of lower risk prospects will also be drilled, the cost of which will be a modest portion of the capital budget. As of March 30, 2001, the Company has 18,980,698 total shares of common stock outstanding. It employs thirty-four full time employees, including five in its exploration and geophysical departments, seven in its operations department, two in its exploitation department, and seven in its land department. Its focus continues to be the implementation of its business strategy as set forth in this section. COMPARISON OF 2000 TO 1999. VOLUMES, PRICES AND PRODUCTION COSTS The following table sets forth certain information regarding the production volumes, average prices received (net of transportation) and average production costs associated with the Company's sale of gas and oil for the periods indicated. 22
YEAR ENDED DECEMBER 31, ------------------------------------ 2000 1999 -------------- --------------- Net Production: Oil (Bbl) ....................................... 163,892 100,559 Gas (Mcf) ....................................... 5,860,195 3,381,592 Gas equivalent (Mcfe) ........................... 6,843,547 3,984,946 Average sales price: Oil ($ per Bbl).................................. $ 32.34(1) $ 18.01(1) Gas ($ per Mcf) ................................. $ 4.12(1) $ 2.35(1) Average production expenses and taxes ($ per Mcfe)........ $ 0.48 $ 0.35
- ------------ (1) Average sales prices do not include the Company's hedging instruments for oil and gas. Including the effect of hedging activities, average sales prices would have been $29.38 per Bbl and $3.38 per Mcf for the year ended December 31, 2000, and $19.01 Bbl and $2.36 per Mcf for the year ended December 31, 1999. REVENUES. Total revenues increased 176% from $12,566,165 for the year ended December 31, 1999 to $34,674,753 for the year ended December 31, 2000. This is primarily attributable to the increases in gas and oil revenue, gain on sale of assets, and other revenues as more fully described below, which increases were partially offset by an increase in the realized loss on commodity transactions as more fully described below. GAS AND OIL REVENUES. Total gas and oil revenues increased 201% from $9,781,352 reported in 1999 to $29,446,832 in 2000. The increase in gas and oil revenue was attributed mainly to increases in quantities of natural gas and oil produced net to the Company's account and increases in the prices for which said production was sold. Volumes increased 72% from 3,984,946 MCFE produced in 1999 to 6,843,547 MCFE in 2000. The average price received per barrel of oil sold increased from $18.01 to $32.34. The average price received per MCF of natural gas sold increased from $2.35 to $4.12. GAIN ON SALE OF ASSETS. There was an increase of 316% in gain on sale of assets of $7,086,120 from $2,243,511 reported in 1999 to $9,329,631 in 2000. This was primarily attributable to the gain on the sale of an interest in the Company's Raymondville Project to an industry partner of approximately $6,607,211 and the recognition of the gain on sale of an interest in its Papalote Project to an industry partner of $1,797,707. OPERATING FEES. Operating fees increased due to increases of both exploratory and developmental wells operated, which has resulted in the increase of operating fees of 32% from $344,539 for the year ended 1999 to $454,016 for the year ended 2000. REALIZED GAIN (LOSS) ON COMMODITY TRANSACTIONS. The Company realized losses from various commodity hedges of $4,842,372 for the year ending 2000, and realized a gain of $146,337 for the same period in 1999. The gains or losses realized are primarily attributable to various transactions in which the Company hedged future gas and oil delivery obligations. The gains realized during 1999 were attributed to the Company's average hedge pricing exceeding the spot market prices for the period. The losses realized during 2000 were incurred as average spot market prices for the period exceeded the average hedge prices. The size of the loss in 2000 was primarily the result of the rapid rise in spot natural gas prices during the year. OTHER REVENUES. The Company had other revenues of $286,646 for the year 2000 as compared with $50,426 for the year of 1999. This increase was primarily due to increased interest income from overnight investments. COSTS AND EXPENSES. Total costs and expenses increased 90% from $22,816,403 in 1999 to $43,335,391 in 2000. The most significant changes relate to various facets of increased production volumes and increased exploration activity. Increased production volumes resulted in increases in lease operating expense, production taxes and depletion as more fully described below. Increased exploration activities led to increases in geological and geophysical costs, dry hole expenses and impairments as more fully described below. Increases in general and administrative costs and interest expense also related to the increased activity level of the Company in 2000. Other changes in costs and expenses are described below. AMORTIZATION OF UNPROVED PROPERTIES decreased 31% to $5,176,100 in 2000 from $7,546,000 for 1999. The Company is amortizing the undeveloped and unevaluated value of the properties acquired pursuant to the Acquisition Agreement between the Company, EPC and Aspect over a period not to exceed forty-eight months. The 23 amounts are amortized until the applicable properties are moved into the proven property base or reduced to zero by amortization or impairment. The lower amount of such costs incurred in 2000 is the result of the reductions in the size of the amortization pool in 2000 as compared to 1999. As of December 31, 2000, a $5,334,700 balance remained in this amortization pool. (Also see Overview - Successful Efforts Accounting and Related Matters.) IMPAIRMENT OF GAS AND OIL PROPERTIES was $4,771,272 in 2000 compared to $358,106 in 1999. Management periodically reviews each individual Exploration Project which can result 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. Major impairment increases of 1232% in 2000 were primarily the result of fourth quarter impairments recognized on two project areas as a result of recent unfavorable drilling results in the project areas. The primary impairments were a $2,132,577 impairment recognized against the value of the Lapeyrouse Project Area and an $809,234 impairment recognized against the Mathis Project Area. Other impairment increases resulted from the increased activity level in 2000. EXPLORATION COSTS - GEOLOGICAL AND GEOPHYSICAL increased 189% from $1,597,372 for 1999 to $4,613,603 for 2000. 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 technology-enhanced exploration program on the Exploration Projects requires the acquisition and interpretation of substantial quantities of such data. 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. The cash flow statement does not permit expenditures for geological and geophysical costs to be included as an oil and gas investing activity or as an add back to operating activities. EXPLORATION COSTS - DRY HOLE was $7,114,950 for 2000 compared to $692,642 for 1999. This 927% increase was the result of an increase in both the number and the average cost of dry holes. In 2000 the Company drilled a higher percentage of higher risk, higher reward wells. This was a foreseeable cost increase as the Company sought the higher returns from more costly exploration. The expectation is that the greater gas and oil reserves discovered in this drilling profile would create higher ultimate, overall returns. During 2000, the Company participated in the drilling of 21 wells which were dry holes. GENERAL AND ADMINISTRATIVE EXPENSES increased 26% from $5,713,408 for 1999 as compared to $7,187,619 for 2000. The cost increases were primarily attributable to the Company's active drilling program combined with its efforts to expand its project inventory. In addition, $635,580 of the increase was due to payment of a bonus to all employees in 2000, which bonus was not paid in 1999. Increased costs were also incurred in the land and financial areas as the Company took steps to enhance its systems and abilities in both areas. DEPLETION, DEPRECIATION AND AMORTIZATION ("DD&A") increased 124% from $4,292,837 for 1999 to $9,635,671 in 2000. The increase was primarily attributed to an increase in volumes produced, and to high depletion costs per unit produced from the Company's Hackberry wells in 2000. Downward reserve revisions in late 2000 regarding the Company's Hackberry production increased the unit costs of depletion in the Hackberry in 2000. (Also see Overview - Overview of 2000 Activities.) INTEREST EXPENSE increased 56% from $871,501 for 1999 to $1,361,533 for 2000. The increase in interest expense was primarily attributable to the Company's usage of its expanded credit facility with Deutsche Bank AG. The Company capitalized a large portion of its interest associated with ongoing projects, of which capitalized amounts totaled $1,023,221 and $219,197 for the respective years ending 1999 and 2000. PRODUCTION TAXES increased 222% from $655,145 for 1999 to $2,107,093 for 2000. The increase in production taxes was the result of increased net volumes produced, and further significantly increased by increased sales revenues due to natural gas price increases throughout 2000. LEASE OPERATING EXPENSE increased 56% from $752,861 for 1999 to $1,172,590 for 2000. This increase is attributable to an increase in the number of producing wells in 2000, and to the number of wells drilled, completed and placed into production in 2000. The addition of producing wells acquired through the 3DX merger for the full year of 2000 also contributed to this increase. 24 DELAY RENTAL EXPENSE decreased 42% from $336,531 for 1999 to $194,960 for 2000. This cost is primarily attributable to rentals payable on leases acquired for projects and prospects not yet developed but which were determined to be a part of the Company's proved undeveloped reserves. EXTRAORDINARY GAIN. Extraordinary gain during 2000 was the result of the settlement of the non-recourse debt and accrued interest with 420-Energy Investments, Inc. There were no extraordinary items during 1999. NET LOSS PER COMMON SHARE. Net loss per common share decreased from a net loss of $0.62 per share for 1999 to $0.40 per share for 2000. Due to the factors discussed above, there was a $2,715,634 decrease in net loss applicable to common stockholders of $7,534,604 for 2000 as compared to 1999. The increase of weighted average number of common equivalent shares at December 31, 2000 of approximately 2,265,000 shares as compared to 1999 also affected the per share calculations. The common shares related to the 3DX merger were outstanding all of 2000, thereby increasing the weighted average number outstanding as compared to the partial year 1999. Approximately 18,877,000 weighted average common equivalent shares were outstanding at December 31, 2000 as compared with approximately 16,612,000 at December 31, 1999. KNOWN AND ANTICIPATED TRENDS, CONTINGENCIES AND DEVELOPMENTS IMPACTING FUTURE OPERATING RESULTS. The Company's future operating results will continue to be substantially dependent upon the success of the Company's efforts to develop the projects acquired in the Acquisitions and thereafter. Management continues to believe these projects represent the most promising prospects in the Company's history. Production from wells drilled from 1998 through the present on projects acquired pursuant to the Acquisitions continue to substantially increase the Company's revenues. Conversely, the capital expenditures planned in 2001 will continue to require substantial outlays of capital to explore, develop and produce. Drilling results for 1998 and 1999 resulted in substantial production increases in those years. The Company believes the field delineation and development drilling which will comprise a significant portion of its 2001 capital expenditures plan enhance the likelihood of significant increases in its net daily production throughout 2001. LIQUIDITY AND CAPITAL RESOURCES The Company business plan calls for net expenditures of $26 million in drilling, completion, land and seismic costs for 2001. These budgeted amounts are based upon exploration opportunities and may be adjusted based upon available capital, new opportunities and industry conditions. The Company's sources of financing include borrowing capacity under its credit facilities, the sale of promoted interests in the Exploration Projects to industry partners and cash provided from operations. The Company entered 2001 having gone from nominal second quarter 1998 gas and oil production revenues of approximately $35,000 per month and large operating cash flow deficits to a company which averaged over $3,500,000 per month in gas and oil revenues in the fourth quarter of 2000. Gas and oil production is expected to continue to increase as new gas and oil production from wells drilled in 2000 and 2001 continues to come on line. Additional success in 2001 on wells currently drilling would continue the trend of increasing production. This should allow the Company to achieve steadily increasing operating cash flow (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). These increases could be limited to the extent offset by potential decreases in the sales price of gas or oil produced. The Company ended 2000 with a deficit working capital of approximately $4.7 million. Of this amount approximately $6.8 million was represented by the current portion of its long term debt. The Company's borrowing base pursuant to Tranche A was increased to $20,000,000 on April 16, 2001. Pursuant to the total Deutsche Bank credit facility, $29 million is now available. The credit facility with Deutsche Bank continues in two tranches; $20 million under Tranche A and $9 million under Tranche B. Tranche A is a revolving facility with no required principal payments until 2002, at which time it converts into a 60-month term loan. Tranche B is payable interest only until the second quarter of 2001, at 25 which time the principal is amortized at a rate of 25% per quarter until fully repaid. Both loans are at a varied interest rate utilizing either Deutsche Bank's alternative interest rate or the London interbank rate plus 2% for both Tranche A and Tranche B. As of March 31, 2001, $14.84 million was drawn under Tranche A and $9 million under Tranche B. All undrawn funds will be available for future activities of the Company. The facility is secured by a mortgage on most proven properties currently owned by the Company. In addition, the Company has a negative pledge and an agreement to mortgage any of the Company's unproven projects or properties at the demand of the bank. In addition to the foregoing, Deutsche Bank AG received a 1.5% overriding royalty interest, proportionately reduced to the Company's net interest, on the gas and oil properties classified as proven as of the date of initial closing on January 24, 2000, and an agreement that the Company would convey to the bank a 1.5% overriding royalty interest, proportionately reduced to the Company's net interest, on future proven wells on the date any such future wells are logged, for as long as funds are outstanding pursuant to Tranche B. In the event the Tranche B loans are repaid in full prior to April 30, 2002, the Company may redeem the overriding royalty interests conveyed to Deutsche Bank AG for an amount equal to (a) an amount which, when added to the interest paid to Deutsche Bank AG, plus revenues received by Deutsche Bank AG from the overriding royalties conveyed to Deutsche Bank AG, would provide to Deutsche Bank AG an internal rate of return of approximately 15%, plus (b) 60% of the then remaining present value of the overriding royalties to be redeemed after subtracting the amount calculated in (a) above. In addition, Deutsche Bank also received on January 24, 2000 a five-year warrant to purchase 250,000 shares of the Company's common stock at a price equal to $1.50 per share. The Company expects further increases in the Tranche A borrowing base in the event its proven oil and gas reserves continue to grow. Its 2001 business plan calls for a reduced need for additional credit in 2001. As such, certain of the growth anticipated in Tranche A of the facility during 2001 and 2002 is intended to be used to amortize the Tranche B debt prior to April 30, 2002. This plan would allow for most of the Company's operating cash flow (prior to capital expenditures and new 3-D seismic data acquisition costs) to be utilized to fund the Company's capital budget in 2001. Pursuant to the Company's credit agreement with Deutsche Bank, it has certain covenants regarding current interest coverage ratios and other covenants regarding which it is expected to be in compliance at the end of each quarter. Although the Company believes it can be in compliance with these covenants in the year 2001, there can be no assurance that it will be in compliance. In the event it is not in compliance, the Company will be required to seek waivers of said covenants or would be required to seek alternative financing arrangements. Effective January 1, 2001, Statement of Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" became effective. At current natural gas prices, the effect will be a balance sheet charge named Other Comprehensive Income ("OCI"), which will reduce total equity to less than $20,000,000 in 2001. Depending upon the classification of the nature of certain of the Company's derivatives, a portion of this charge could be taken through the income statement in a category named Unrealized Gain or Loss from Commodity Transactions. OCI will likely materially increase or decrease from period to period for the Company based upon then current market prices of natural gas and oil. The Company has a covenant with Deutsche Bank that its tangible net worth will equal or exceed, at all times, $20,000,000. It has requested that Deutsche Bank exclude the effect of OCI, and the effect of other non-cash charges resulting from this change in standard, from the compliance calculation. Deutsche Bank has advised the Company that it intends to complete appropriate amendments to the covenant to negate the effect of such charges on compliance as of March 31, 2001. In the event this is not done, the Company would likely not be in compliance during parts of 2001. 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, sales of project interests to industry partners and with cash provided by operating activities. Its major obligations as of March 2001, consisted principally of (i) servicing loans under the credit facilities with Deutsche Bank and other loans, (ii) funding of the Company's exploration activities, and (iii) funding of the day-to-day operating costs. The Company has an ambitious capital expenditure plan for 2001, which includes approximately $26 million in drilling, completion, land and seismic costs for the year. Cash on hand, cash available pursuant to the Deutsche Bank credit facility, and cash flow from operations will contribute significantly to said budgets. These 26 funds may be supplemented by the sale of project interests to industry partners for the purpose of managing exposure to individual wells and/or to increase available cash. The Company expects to fund a substantial portion of its 2001 capital budget from its cash flow from operations. Its increased daily net production in 2000 has combined with the industry-wide increase in natural gas prices in 2000 to significantly increase Company revenues. It anticipates greater increases in its 2001 net production due to continued drilling, in particular the addition of delineation and development wells to its drilling plan. These wells, planned in relation to its Runnells #3 discovery of the Grand Slam Field and its Pereira Children Trust #2 discovery (recently renamed the Hamman & Anderson #2 well) of the Hordes Creek Field, represent a lower risk profile at locations where the production infrastructure is already installed at adjacent locations. The lower risk profile enhances the likelihood of success and the infrastructure decreases the time to market. The Company expects this delineation and development drilling activity, combined with its ongoing exploratory drilling program, to lead to increased net daily production throughout 2001. This, in turn, would lead to increased capital resources throughout the year. In the event net daily production does not increase, or lower product prices offset the potential revenue from greater production, or both, the Company would be more dependent upon sales of project interests to industry partners or credit facilities to support its capital budget. If such sources were not available, the capital budget would then have to be adjusted. 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, including the acquisition of a company with producing and exploratory properties for common stock or other equity securities, and also 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. 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. The Company had hedge agreements in place covering January 2001 natural gas production of 7,191 MMBtu/day at $2.45/MMBtu and covering 5,000 MMBtu/day at $4.01/MMBtu. It also had a hedge agreement in place covering January 2001 oil production 175 barrels of oil per day at $21.03/barrel. Hedge agreements were in place covering 5,000 MMBtu/day of February and March 2001 natural gas production at $4.01/MMBtu. It also had a natural gas collar in place covering 7,500 MMBtu/day of February and March 2001 natural gas production, which collar was comprised of a $3.25 put or floor and a $4.00 call or cap. In February and March 2001, oil production totaling 175 barrels of oil per day was hedged at $21.03/barrel. The Company currently has 5,000 MMBtu/day of natural gas production hedged at $4.01/MMBtu for the second, third and fourth quarters of 2001. It also has 7,900 MMBtu/day of second quarter 2001 natural gas production and 8,000 MMBtu/day of third and fourth quarter 2001 natural gas production covered by a collar with a $3.25 floor and a $4.00 cap. Oil production hedged at $21.03/barrel totals 168 barrels per day, 161 barrels per day and 154 barrels per day in the second, third and fourth quarters, respectively, of 2001. It also has a collar position in place on natural gas production in 2002 and 2003 covering volumes that range from 4,500 MMBtu/day to 8,500 MMBtu/day which position is at a $3.25 floor and a $4.00 cap. As a result of the above-referenced transactions, the Company has hedged varying quantities of its natural gas and oil production through December of 2003. First quarter 2001 hedges are estimated to approximate 76.6% of the Company's natural gas and 50.5% of its oil production for such quarter. Future percentages will vary. WORKING CAPITAL. At December 31, 2000, the Company had a cash balance of $3,002,700, total current assets of $19,569,894, and total current liabilities of $24,259,767. This resulted in a working capital deficit of $4,689,873. Were the current portion of long term debt due to Deutsche Bank AG not included in current liabilities, the working capital surplus would have been $2,060,127. The current portion of long term debt at December 31, 2000 was comprised of $6,750,000 of Tranche B debt due to Deutsche Bank within one year. 27 The Company expects to service a $2,250,000 Tranche B principal obligation in the second quarter of 2001 with advances under Tranche A. Given an expected mid-year increase in Tranche A availability, third and fourth quarter Tranche B obligations would be satisfied in the same manner. The Company expects its trend of increasing gas and oil revenues will continue the growth in revenues in excess of the ongoing costs of operations, which may also enhance the Company's working capital position. The net working capital can be negatively effected by the Company's continuing aggressive capital expenditures program on its exploration projects or by decreases in natural gas or oil prices. To the extent a working capital shortfall develops due to capital expenditures exceeding available cash, including cash generated from operations, it could be addressed with cash proceeds from sales of interests in Exploration Projects to industry partners or by adjustments to the capital budget, or by other sources of capital believed available. SUMMARY. The Company believes it is positioned to continue to expand its exploration activity on its technology enhanced projects. Many of the projects have reached the drilling stage. In addition, two recent discoveries provide significant opportunities to drill field delineation wells in 2001. Successful delineation wells can create additional developmental drilling opportunities that can allow for continuous expansion of the company's monthly net gas and oil production in a more predictable manner than during 2000 when there was a greater concentration of higher risk exploratory drilling. In 2001 the Company plans to expand its delineation and developmental drilling while continuing its aggressive exploratory drilling program on high potential geologic features. The Company controls an array of Exploration Projects regarding which 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 has been completed. Management believes that its mix of delineation, development and exploratory drilling positions it for dramatic growth in its proven natural gas and oil reserves in 2001. The Company expects to fund significant portions of its $26 million year 2001 exploration budget from operating cash flow (prior to capital expenditures and new 3-D seismic data acquisition costs). Its total capital budget will be funded from anticipated cash flow and credit facilities, and supplemented with proceeds from selected sales of interests in its Exploration Projects to industry partners. The Company will utilize a variety of sources to fund its continuing capital expenditures budget including operating cash flow, currently available credit facilities and certain 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. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS. In June 1998, Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133) was issued. The Company adopted SFAS 133 effective January 1, 2000. SFAS 133 requires that all derivatives be recognized as either assets or liabilities and measured at fair value, and changes in the fair value of derivatives be reported in current earnings, unless the derivative is designated and effective as a hedge. If the intended use of the derivative is to hedge the exposure to changes in the fair value of an asset, liability or firm commitment, then changes in the fair value of the derivative instrument will generally be offset in the income statement by the change in the hedged item's fair value. However, if the intended use of the derivative is to hedge the exposure to variability in expected future cash flows, then changes in the fair value of the derivative instrument will generally be reported in Other Comprehensive Income (OCI). The gains and losses on the derivative instrument that are reported in OCI will be reclassified to earnings in the periods in which earnings are impacted by the hedged item. In accordance with the transition provisions of SFAS 133 on January 1, 2001, the Company recorded a cumulative-effect type adjustment of ($14,909,492), in OCI to recognize the fair value of all derivatives that are designated as cash-flow hedges. This adjustment will change from period to period, either up or down, in relation to commodity market prices as compared to the Company's derivative instruments in place at such time. 28 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. and subsidiaries (the "Company") as of December 31, 2000 and 1999, 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 auditing standards generally accepted in the United States of America. 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, 2000 and 1999, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. Deloitte & Touche LLP Houston, Texas April 16, 2001 29 ESENJAY EXPLORATION, INC. CONSOLIDATED BALANCE SHEETS ASSETS
DECEMBER 31, DECEMBER 31, 2000 1999 -------------- ------------- Current assets: Cash and cash equivalents.................................. $ 3,002,700 $ 2,598,047 Accounts receivable, net of allowance for doubtful accounts of $445,872 and $519,137, respectively........ 14,259,833 7,078,109 Prepaid expenses and other................................. 2,183,093 3,940,133 Receivables from affiliates................................ 124,268 363,027 ------------- ------------- Total current assets.............................. 19,569,894 13,979,316 Property and equipment.......................................... 81,977,022 80,120,781 Less accumulated depletion, depreciation and amortization........................................... (40,087,050) (25,937,472) ------------- ------------- 41,889,972 54,183,309 Other assets .................................................. 903,208 770,210 ------------- ------------- Total assets...................................... $ 62,363,074 $ 68,932,835 ============= =============
30 ESENJAY EXPLORATION, INC. CONSOLIDATED BALANCE SHEETS LIABILITIES AND STOCKHOLDERS' EQUITY
DECEMBER 31, DECEMBER 31, 2000 1999 ------------ ------------ Current liabilities: Accounts payable .......................................... $ 6,450,723 $ 8,838,629 Accounts payable to affiliate ............................. 269,835 2,083,913 Revenue distribution payable .............................. 6,101,354 2,491,798 Current portion of long-term debt ......................... 6,750,000 11,013,162 Accrued, deferred and other liabilities ................... 4,687,855 6,095,188 ------------ ------------ Total current liabilities ........................ 24,259,767 30,522,690 Long-term debt ................................................. 13,591,782 4,750,000 Non-recourse debt .............................................. -- 864,000 Accrued interest on non-recourse debt .......................... -- 463,395 ------------ ------------ Total liabilities ................................ 37,851,549 36,600,085 Stockholders' equity: Convertible preferred stock $.01 par value; 5,000,000 shares authorized; 356,999 shares issued and outstanding at December 31, 1999 ....................... -- 3,570 Common stock: Class A common stock, $.01 par value; 40,000,000 shares authorized; and 18,958,477 and 18,837,699 outstanding, respectively .............................. 189,585 188,377 Additional paid-in capital ................................ 84,699,705 84,987,704 Stock subscription receivable ............................. (106,060) (109,800) Accumulated deficit ....................................... (60,271,705) (52,737,101) ------------ ------------ Total stockholders' equity ....................... 24,511,525 32,332,750 ------------ ------------ Total liabilities and stockholders' equity ....... $ 62,363,074 $ 68,932,835 ============ ============
The accompanying notes are an integral part of these financial statements. 31 ESENJAY EXPLORATION, INC. CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31, ----------------------------- 2000 1999 ------------ ------------ Revenues: Gas and oil revenues ................................... $ 29,446,832 $ 9,781,352 Realized gain (loss) on commodity transactions ......... (4,842,372) 146,337 Gain on sale of assets ................................. 9,329,631 2,243,511 Operating fees ......................................... 454,016 344,539 Other revenues ......................................... 286,646 50,426 ------------ ------------ Total revenues ................................ 34,674,753 12,566,165 ------------ ------------ Costs and expenses: Lease operating expense ................................ 1,172,590 752,861 Production taxes ....................................... 2,107,093 655,145 Depletion, depreciation and amortization ............... 9,635,671 4,292,837 Amortization of unproved properties .................... 5,176,100 7,546,000 Impairment of oil and gas properties ................... 4,771,272 358,106 Exploration costs-geological & geophysical ............. 4,613,603 1,597,372 Exploration costs-dry hole ............................. 7,114,950 692,642 Interest expense ....................................... 1,361,533 871,501 Delay rentals .......................................... 194,960 336,531 General and administrative ............................. 7,187,619 5,713,408 ------------ ------------ Total costs and expenses ...................... 43,335,391 22,816,403 ------------ ------------ Loss before provision for income taxes and extraordinary gain ...................................................... (8,660,638) (10,250,238) Benefit (provision) for income taxes ........................ -- -- ------------ ------------ Net loss before extraordinary gain .......................... (8,660,638) (10,250,238) Extraordinary gain .......................................... 1,126,034 -- ------------ ------------ Net loss attributable to common stockholders ................ $ (7,534,604) $(10,250,238) ============ ============ Net loss per share of common stock: Basic and diluted: Net loss before extraordinary gain attributable to common stockholders ........................ $ (0.46) $ (0.62) Extraordinary gain .................................. 0.06 -- ------------ ------------ Net loss attributable to common shareholders ........ $ (0.40) $ (0.62) ============ ============ Weighted average number of common shares outstanding ........ 18,877,192 16,612,314 ============ ============
The accompanying notes are an integral part of these financial statements. 32 ESENJAY EXPLORATION, INC. CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
Preferred Class A Stock Common Shares Additional Stock -------------------------- ------------------------ Paid-in Subscription Accumulated Shares Amount Shares Amount Capital Receivable Deficit ----------- ------------- ----------- ------------ ------------ ------------ ------------- Balance, December 31, 1998 ...... -- -- 15,784,834 $ 157,849 $ 77,651,602 -- $(42,486,863) Issuance of common stock for acquisitions, net ..... -- -- 2,906,839 29,068 6,378,334 -- -- Issuance of preferred stock ....... 356,999 $ 3,570 -- -- 683,653 -- -- Issuance of common stock ................ -- -- 62,026 620 121,235 -- -- Issuance of common stock through subscriptions ......... -- -- 84,000 840 152,880 $ (109,800) -- Net loss .............. -- -- -- -- -- -- (10,250,238) ------------ ------------ ------------ ------------ ------------ ------------ ------------ Balance, December 31, 1999 ... 356,999 3,570 18,837,699 188,377 84,987,704 (109,800) (52,737,101) Issuance of warrants .... -- -- -- -- 110,000 -- -- Redemption of preferred stock ....... (356,999) (3,570) -- -- (683,655) -- -- Issuance of common stock ................. -- -- 88,778 888 216,516 -- -- Payment of stock subscription receivable ......... -- -- -- -- -- 73,200 -- Issuance of common stock through subscriptions . -- -- 32,000 320 69,140 (69,460) -- Net loss ............... -- -- -- -- -- -- (7,534,604) ------------ ------------ ------------ ------------ ------------ ------------ ------------ Balance, December 31, 2000 ..... -- $ -- 18,958,477 $ 189,585 $ 84,699,705 $ (106,060) $(60,271,705) ============ ============ ============ ============ ============ ============ ============
The accompanying notes are an integral part of these financial statements. 33 ESENJAY EXPLORATION, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31, ---------------------------------------- 2000 1999 ----------------- ---------------- Cash flows from operating activities: Net loss .......................................................... $ (7,534,604) $ (10,250,238) Adjustments to reconcile net loss to net cash provided by (used in) operating activities: Depletion, depreciation and amortization ..................... 9,635,671 4,292,837 Amortization of unproven property............................. 5,176,100 7,546,000 Impairment of oil and gas properties.......................... 4,771,272 358,106 Exploration costs - dry hole.................................. 7,114,950 692,642 Gain on sale of assets........................................ (9,329,631) (2,243,511) Amortization of financing costs............................... --- 101,587 Extraordinary gain............................................ (1,126,034) --- Changes in operating assets and liabilities: Trade and affiliate receivables............................... (6,942,964) (3,487,403) Prepaid expenses.............................................. 1,757,040 (3,817,711) Other assets.................................................. (136,568) (323,119) Trade and affiliate payables.................................. (4,201,984) 479,387 Revenue distribution payable.................................. 3,609,556 495,707 Accrued, deferred and other liabilities....................... (1,407,333) 5,610,432 ----------------- ---------------- Net cash provided by (used in) operating activities........... 1,385,471 (545,284) ----------------- ---------------- Cash flows from investing activities: Capital expenditures - gas and oil properties...................... (19,254,789) (19,478,942) Capital expenditures - other property and equipment................ (183,013) (558,748) Proceeds from sale of assets....................................... 14,362,776 14,970,015 ----------------- ---------------- Net cash used in investing activities........................... (5,075,026) (5,067,675) ----------------- ---------------- Cash flows from financing activities: Proceeds from issuance of debt..................................... 20,341,782 8,920,000 Repayments of long-term debt....................................... (15,964,523) (1,508,074) Preferred stock redeemed........................................... (683,655) --- Proceeds from issuance of warrants................................. 110,000 --- Net proceeds from issuance of common stock......................... 217,404 152,880 Payment of stock subscriptions receivables......................... 73,200 --- ----------------- ---------------- Net cash provided by financing activities....................... 4,094,208 7,564,806 ----------------- ---------------- Net increase in cash and cash equivalents.......................... 404,653 1,951,847 Cash and cash equivalents at beginning of year.......................... 2,598,047 646,200 ----------------- ---------------- Cash and cash equivalents at end of year................................ $ 3,002,700 $ 2,598,047 ================= ================
34
Year Ended December 31, ---------------------------------------- 2000 1999 ----------------- ---------------- Supplemental disclosure of cash flow information: Cash paid for interest............................................. $1,372,124 $ 1,763,323 Supplemental disclosure of non-cash investing and financing activities: Sale of oil and gas properties in satisfaction of payable to affiliates...................................... --- $ 2,700,000 Acquisition of assets........................................... --- 8,333,853 Proxy costs..................................................... --- 316,503 Assumption of related liabilities............................... --- 923,252 Issuance of common stock........................................ $ 69,460 6,723,378 Issuance of preferred stock..................................... --- 687,223
The accompanying notes are an integral part of these financial statements. 35 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 accounting principles generally accepted in the United States of America 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. 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. 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. 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 the sales are completed. Remaining costs are 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. Unproved properties are periodically assessed for impairment and, if necessary, a loss is recognized. This analysis resulted in $4,771,272 and $358,106 of impairment charges during 2000 and 1999, 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. Such amortization was $5,176,100 and $7,546,000 for the years ended December 31, 2000 and 1999, respectively. The balance in this amortizing group of unproven properties was $5,334,700 and $13,392,100 at December 31, 2000 and 1999, respectively. 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. 36 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. This policy was changed as of January 1, 2001. (See Note 2 - Recent Events) CAPITALIZED INTEREST - The Company capitalizes interest costs incurred on exploration projects. Interest capitalized for the years ended December 31, 2000 and 1999 was approximately $219,197 and $1,023,221, 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, 2000 and 1999 was approximately 135,676 MCF or $245,719 and 114,721 MCF or $117,952 overproduced, respectively. EXPLORATION COSTS - The Company expenses exploratory dry hole costs, geological and geophysical costs, and impairment of unproved properties. In 2000 and 1999, the Company expensed $4,613,603 and $1,597,372 in geological and geophysical costs, respectively, and $7,114,950 and $692,642 in dry hole costs, respectively. For purposes of reporting cash flows, the Company adds back to operating activities all exploration costs which have been previously capitalized, such as dry hole costs. 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. These unrealized losses on these contracts 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. This policy was changed as of January 1, 2001. (See Note 2 - Recent Events) 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, 2000 and 1999 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:
2000 1999 ------------ ------------- BASIC AND DILUTED EARNINGS PER SHARE Weighted average common shares outstanding ................................... 18,877,192 16,612,314 ============ ============ Basic and diluted loss per share before extraordinary gain ................... $ (0.46) $ (0.62) ============ ============ Basic and diluted loss per share ............................................. $ (0.40) $ (0.62) ============ ============ EARNINGS FOR BASIC AND DILUTED COMPUTATION Net loss to common stockholders before extraordinary gain .................... $ (8,660,638) $(10,250,238) Extraordinary gain ........................................................... 1,126,034 --- ------------ ------------ Net loss to common shareholders (basic and diluted loss per share computation) ........................................ $ (7,534,604) $(10,250,238) ============ ============
2. RECENT EVENTS As of December 31, 2000, Tranche A of the Company's credit facility with Deutsche Bank AG, New York Branch ("Deutsche Bank") was scheduled to mature on January 24, 2001, at which time any remaining principal 37 balance would convert to a five-year monthly amortizing term loan. Effective February 23, 2001, the maturity date of Tranche A was reset to January 25, 2002, at which time any remaining principal balance will convert into a five-year monthly amortizing term loan. The effect of this change is reflected as of December 31, 2000. On April 16, 2001 the available borrowing base pursuant to Tranche A of the Deutsche Bank credit facility was increased to $20,000,000. The borrowing base is scheduled to again be reviewed in the third quarter of 2001. On January 25, 2001, the Company completed a restructuring of a significant portion of its outstanding natural gas price hedges. The hedges restructured covered 7,161 MMBtu/day of natural gas production in February and March of 2001, 6,880 MMBtu/day for the second quarter of 2001, 6,600 MMBtu/day for the third quarter of 2001, and 6,319 MMBtu/day for the fourth quarter of 2001. All hedges were at $2.45 per MMBtu. These hedges were restructured on January 25, 2001 for all periods beginning February 1, 2001, and any rights or obligations of the Company pursuant to the previously existing $2.45 hedges were cancelled. Pursuant to the restructured agreements, the Company has subjected volumes of its Gulf Coast natural gas production to a "collar" structure with a floor price of $3.25 per MMBtu and a ceiling or cap price of $4.00 per MMBtu. Volumes committed to this structure are 7,500 MMBtu per day in February and March of 2001, 7,900 MMBtu per day in the second quarter of 2001, and 8,000 MMBtu per day in the third and fourth quarter of 2001. In 2002, volumes committed are 8,500, 8,000, 7,500 and 7,000 MMBtu per day in the first through fourth quarter, respectively. Finally, volumes committed to the collar structure include 4,500 MMBtu per day for calendar year 2003. In June 1998, Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133) was issued. The Company adopted SFAS 133 effective January 1, 2000. SFAS 133 requires that all derivatives be recognized as either assets or liabilities and measured at fair value, and changes in the fair value of derivatives be reported in current earnings, unless the derivative is designated and effective as a hedge. If the intended use of the derivative is to hedge the exposure to changes in the fair value of an asset, liability or firm commitment, then changes in the fair value of the derivative instrument will generally be offset in the income statement by the change in the hedged item's fair value. However, if the intended use of the derivative is to hedge the exposure to variability in expected future cash flows, then changes in the fair value of the derivative instrument will generally be reported in Other Comprehensive Income (OCI). The gains and losses on the derivative instrument that are reported in OCI will be reclassified to earnings in the periods in which earnings are impacted by the hedged item. In accordance with the transition provisions of SFAS 133 on January 1, 2001, the Company recorded a cumulative effect type adjustment of ($14,909,492) in OCI to recognize the fair value of all derivatives that are designated as cash-flow hedges. This adjustment will change from period to period, either up or down, in relation to commodity market prices as compared to the Company's derivative instrument in place at such time. 3. STOCKHOLDERS' EQUITY: In 2000 and 1999 the Company issued 120,778 and 3,052,865 additional shares of common stock, respectively. On May 12, 1999, the Company announced that on May 11, 1999 it had signed a Plan and Agreement of Merger with 3DX Technologies Inc. ("3DX") which provided for the merger of 3DX into the Company (the "Acquisition"). The shareholders of both companies approved the transaction at duly called shareholders meetings on September 23, 1999 and the merger was consummated the same day. The purchase price of the Acquisition was approximately $7.4 million, of which $6.7 million was in the Company's common stock and $0.7 million was in the Company's preferred stock. The terms of the merger provided for 3DX shareholders to receive, at their election, either (i) the issuance of one share of Esenjay common stock for 3.25 shares of 3DX common stock; or (ii) the issuance of a new Esenjay convertible preferred stock at a ratio of one share of Esenjay convertible preferred stock for each 2.75 shares of 3DX common stock. Approximately 91% of the 3DX common shares converted into Esenjay common stock and approximately 9% were converted into Esenjay convertible preferred stock. As a result, Esenjay issued 2,906,778 new shares of common stock and 356,999 shares of convertible preferred stock. The convertible preferred stock could be redeemed at Esenjay's sole option until September 23, 2000 at $1.925 per share. On September 23, 2000, the Company redeemed all 356,999 outstanding shares of the convertible 38 preferred stock for $1.925 per share. In May of 1999, seven directors of the Company each subscribed for the purchase of 12,000 shares of common stock of the Company for an aggregate total of 84,000 shares. The shares were at a price of $1.83 per share payable one-third upon subscription, one-third in May of 2000 and one-third in May of 2001. Shares were delivered in 2000. In June of 2000, one director of the Company subscribed to purchase 12,000 shares of Common Stock of the Company at $1.83 per share payable one-third upon subscription, one-third on or before May 15, 2001 and one-third on or before May 15, 2002. At December 31, 2000, the Company had a common stock subscription receivable of $58,560 outstanding related to these shares. In 2000 the Company issued a total of 47,252 and 61,547 shares of common stock pursuant to various employee options which were exercised during the year and the Company's match of shares purchased in the Company's 401K plan, respectively. WARRANTS - Since December 31, 1997, the Company has had Series B Warrants, which entitles the holder to purchase one share of common stock for $12.15 until 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. In January of 1996, the Company issued warrants to purchase 83,334 shares of common stock, 41,667 of which shares were at an exercise price of $21.735 per share and 41,667 of which shares were at an exercise price of $12.00 per share. The warrants exercisable at $21.735 expire January 3, 2001 and the warrants exercisable at $12.00 per share expire January 12, 2001. In the first quarter of 2000, the Company issued warrants in connection with a financing transaction to purchase 250,000 shares of the Company's common stock at an exercise price of $1.50 per share. The warrants expire January 25, 2005. The fair value of these warrants were recorded in the amount of $110,000. EMPLOYEE OPTION PLANS - The Company has option plans for employees and directors that authorize the issuance of up to 3,000,000 options to purchase one share of common stock. Options to purchase 2,497,168 shares of common stock at prices ranging from $1.83 to $3.86 are currently outstanding. Under the plans, 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. Unless otherwise so designated, the options shall be exercisable at a rate of 33 1/3% in the year following the effective date of the grant, and 33 1/3% each of the two years 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. The following table summarizes activity under the Company's stock option plans for the years ended December 31, 2000 and 1999. 39
EMPLOYEE OPTION PLANS ----------------------------------------------------- 2000 1999 ------------------------- -------------------------- WEIGHTED WEIGHTED AVERAGE AVERAGE EXERCISE EXERCISE SHARES PRICE SHARES PRICE ------------ ----------- ----------- ------------- Outstanding at beginning of year......................... 1,259,667 $ 2.42 94,001 $ 3.92 Granted.................................................. 1,463,000 2.44 1,169,000 2.38 Exercised................................................ (66,499) 2.38 Forfeited................................................ (159,000) 2.38 (3,334) 7.68 ------------ ----------- ----------- ------------- Outstanding at end of year............................... 2,497,168 $ 2.44 1,259,667 $ 2.42 ============ =========== =========== ============= Weighted average fair value of options granted during the year....................... $ 1.51 $ 1.34 =========== =============
Options outstanding at December 31, 2000 consisted of the following:
EXERCISABLE OPTIONS --------------------------------- RANGE OF WEIGHTED WEIGHTED WEIGHTED EXERCISE PRICES NUMBER OF AVERAGE EXERCISE AVERAGE REMAINING NUMBER OF AVERAGE EXERCISE PER SHARE OPTIONS PRICE PER SHARE CONTRACTUAL LIFE OPTIONS PRICE PER SHARE ----------------- ----------- ----------------- -------------------- ------------ ------------------ $1.83 - $3.86 2,497,168 $2.44 7.9 - 9.8 years 2,139,205 $2.41
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 2000 and 1999 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:
2000 1999 ------------- --------------- Net loss attributable to common stockholders-as reported........................... $(7,534,604) $(10,250,238) Net loss attributable to common stockholders-pro forma............................. $(8,531,852) $(11,247,486) Net loss per common share-as reported.............................................. $(0.40) $(0.62) Net loss per common share-pro forma................................................ $(0.45) $(0.68)
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 81.61% and 80.99% in 2000 and 1999; risk-free interest rate of 5.95% and 5.625% in 2000 and 1999; and expected lives of 10 years. 4. SALE OF GAS AND OIL ASSETS AND SEISMIC DATA: The Company sold various interests in a number of different projects, prospects and wells during 2000 and 1999. These sales resulted in an aggregate gain of approximately $9,329,631 in 2000 and $2,243,511 in 1999. 40 5. LONG-TERM DEBT: (SEE NOTE 2) Long-term debt consists of the following:
DECEMBER 31, -------------------------------- 2000 1999 -------------- -------------- Non-recourse loan retired in 2000................................................. --- $ 864,000 Note payable paid in 2000......................................................... --- 100,000 Loan with Deutsche Bank AG, New York Branch ("Deutsche Bank"), in two Tranches: Tranche A is a revolving credit facility which terminates January 24, 2001, thereafter converting the unpaid balance into a five year term loan requiring monthly principal and interest payments; Tranche B is payable as to interest only until April 30, 2001, at which time quarterly payments of $2,250,000 plus interest are required until the loan is amortized. Both loans are at a varied interest rate utilizing, at the Company's election, either Deutsche Bank's Alternative Reference Rate or the Interbank rate plus 2% for both Tranche A and Tranche B. The loan is secured by a mortgage on most properties currently owned by the Company................................... $20,341,782 --- Loan with Bank of America NT&SA was repaid with a portion of the proceeds from financing provided by Deutsche Bank........................................... --- 8,523,162 Loan with Duke Energy Field Services, Inc. was repaid with a portion of the proceeds from financing provided by Deutsche Bank............................. --- 7,140,000 -------------- -------------- 20,341,782 16,627,162 Less current portion.............................................................. 6,750,000 11,013,162 -------------- -------------- $13,591,782 $ 5,614,000 ============== ==============
Maturities of long-term debt are as follows:
YEAR AT DECEMBER 31, --------------- 2000(1) ------ 2001.................................................................... $ 6,750,000 2002.................................................................... 6,219,623 2003.................................................................... 2,268,356 2004.................................................................... 2,268,356 2005.................................................................... 2,268,356 2006.................................................................... 567,091
(1) Amortization of amounts advanced pursuant to Tranche A of the Deutsche Bank credit facility was reset in 2001 and, as such, no Tranche A amounts are currently scheduled for amortization in 2001. (See Note 2 for information regarding maturities under this facility over the next 5 years.) On January 25, 2000, the Company closed a credit facility with Deutsche Bank AG, New York branch. This facility provides for Deutsche Bank to loan up to $29,000,000 to be available in two tranches. Tranche A is structured in the amount of $20,000,000, with $16,000,000 established as the current available borrowing base, and Tranche B is fully drawn in the amount of $9,000,000. Under the terms and conditions of this facility, the facilities existing at December 31, 1999 with Duke Energy Financial Services, Inc. and Bank of America, NT&SA, were paid in full utilizing approximately $15,800,000 of the available proceeds from Deutsche Bank. As of December 31, 2000, Tranche A was scheduled to mature on January 24, 2001, at which time any remaining unpaid principal would convert to a five-year monthly amortizing term loan. This was reset in February 2001 to mature on January 25, 2002 and the change is incorporated in the above schedule. The Tranche B loan is payable interest only through April 30, 2001 after which date the amount available decreases by 25% per quarter beginning April 30, 2001 with a final maturity in January of 2006. In addition, the Company must remain in compliance with certain covenants required by Deutsche Bank, including a redetermination of the borrowing base every six months. The company also is required to assign an overriding royalty interest to Deutsche Bank for those wells logged prior to the later of the maturity date of Tranche B or the Tranche A termination date or the date the Tranche B Loan is repaid. The 41 Company may repurchase this overriding royalty interest prior to April 30, 2002, if all Tranche B loans are repaid in full. The amount available pursuant to Tranche A has been increased since December 31, 2000. (See Note 2 - Recent Events.) 6. INCOME TAXES: Deferred tax assets and liabilities are as follows:
AT DECEMBER 31, ---------------------------------- 2000 1999 --------------- --------------- Net operating tax loss carry forward................................. $ 18,176,646 $ 17,590,565 Property and equipment............................................... 3,836,490 2,166,546 Valuation allowance.................................................. (22,013,136) (19,757,111) ---------------- ---------------- 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, 2000, of approximately $51,900,000 which may be used to offset future taxable income. The operating loss carryforwards expire in the tax years 2006 through 2020. 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. The Company incurred such an Ownership Change in 1998. 7. RELATED PARTY TRANSACTIONS: On December 31, 2000 and 1999, the Company had accounts receivable from employees and affiliates totaling net amounts of $124,267 and $553,950, respectively. The December 31, 2000 balance includes net accounts payable due to Aspect in the amount of $122,506. The December 31, 2000 and 1999 balance includes net accounts receivable due from EPC in the amount of $101,199 and $190,923, respectively. At December 31, 1999, the company had a net account payable due to Aspect in the amount of $2,083,913. 8. COMMITMENTS AND CONTINGENCIES: The Company leases office space under lease agreements, which are classified as operating leases. Lease expense under these agreements was $300,290 in 2000 and $291,169 in 1999. A summary of future minimum rentals on these non-cancelable operating leases is as follows:
AT DECEMBER 31, YEAR 2000 - ---- ---- 2001.................................................................... $248,445 2002.................................................................... 168,137 2003.................................................................... 84,068
42 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 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 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 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 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 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. In September of 1999, the Company entered into a series of swap agreements on additional natural gas and oil production. It hedged 5,000 MMBtu per day of natural gas for the months of September through December 1999 at a price of $3.055 per MMBtu, it hedged 3,000 MMBtu per day for the period of January through March of 2000, 2,400 MMBtu per day for the period April through June of 2000, and 1,700 MMBtu per day for the period of July through September of 2000, the latter three hedges of which were all at a price of $2.68 per MMBtu. In addition, the Company entered into a "collar" hedge arrangement on certain of its oil production. This oil hedge was for a quantity equal to 300 barrels of oil per day in the fourth quarter of 1999, 280 barrels of oil per day in the first quarter of 2000, 256 barrels of oil per day in the second quarter of 2000, and 237 barrels of oil per day in the third quarter of 2000, all of which transactions were structured with an $18.00 floor price and a $20.40 cap price. In February of 2000, in conjunction with its financing with Deutsche Bank, the Company restructured all existing natural gas hedges with an affiliate of Deutsche Bank. Pursuant to these hedges, the Company had 9,381 MMBtu/day of net production hedged in March, 2000, 9,031 MMBtu/day hedged for the second quarter of 2000, 8,646 MMBtu/day for the third quarter of 2000, 8,278 MMBtu/day for the fourth quarter of 2000, 7,161 MMBtu/day for the first quarter of 2001, 6,880 MMBtu/day for the second quarter of 2001, 6,600 MMBtu/day for the third quarter of 2001, and 6,319 MMBtu/day for the fourth quarter of 2001. All hedges were at $2.45 per MMBtu. Concurrent with the restructuring of the hedges, the Company was relieved of any liability or rights pursuant to all previously existing natural gas hedges. An existing "collar" hedge arrangement on 280 barrels of oil per day in the first quarter of 2000, and 256 and 237 barrels of oil per day in the second and third quarters of 2000, respectively, was transferred to the Deutsche Bank affiliate at the existing $18.00 floor price and $20.40 cap price. These positions were supplemented with oil hedges at $21.03 per barrel on volumes of 238 barrels of oil per day in the fourth quarter of 2000 and 175, 168, 161, and 154 barrels of oil per day in the first through fourth quarters of 2001, respectively. In the third quarter of 2000, the Company hedged an additional 5,000 MMBtu/day of natural gas. The hedge prices were $4.70 per MMBtu for the months of September through December 2000, and $4.01 per MMBtu for the months of January through December 2001. In January of 2001 certain of the above hedge instruments were restructured. (See Note 2 - Recent Events.) 9. ACQUISITIONS: On May 12, 1999, the Company announced that on May 11, 1999 it had signed a Plan and Agreement of Merger with 3DX Technologies Inc. ("3DX") which provided for the merger of 3DX into the Company (the "3DX Acquisition"). The shareholders of both companies approved the transaction at duly called shareholders meetings on September 23, 1999 and the merger was consummated the same day. The purchase price of the 3DX Acquisition was approximately $7.4 million, of which $6.7 million was in the Company's common stock and $0.7 million was in the Company's preferred stock. The 3DX Acquisition included, at fair value, current assets of $2.5 million, property and equipment of $5.8 million, other assets of $0.1 million and liabilities of $0.9 million. 3DX Technologies Inc. was a Houston-based exploration and production company whose strategic business focus was the utilization of 3-D seismic imaging and other advanced technologies in the search for natural gas and oil principally in the onshore gulf coast of the United States. As a result of the merger, the Company employed four 43 members of the reservoir engineering and geophysical staff of 3DX, plus one support person, increased its gas and oil reserves, its monthly gas and oil revenues, and expanded its ownership of 3D seismic data and projects. The acquisitions have been accounted for using the purchase method of accounting and, accordingly, the purchase price has been allocated to the assets and liabilities acquired based on fair value at the date of acquisition. The operating results of the acquisitions have been included in the Company's consolidated financial statements from their respective dates of acquisition. The following unaudited pro forma information presents a summary of the consolidated results of operations for the year ended December 31, 1999 as if the acquisitions had occurred prior to January 1, 1999.
YEAR ENDED DECEMBER 31, 1999 ----------------- Revenues..................................................... $ 14,176,091 Total costs and expenses..................................... 28,393,836 ----------------- Net loss..................................................... $ (14,217,745) ================= Basic and diluted loss per share............................. $ (0.73) ================= Weighted average number of common shares Outstanding............................................ 19,518,839 =================
10. PROPERTY AND EQUIPMENT:
YEAR ENDED DECEMBER 31, --------------------------------- 2000 1999 --------------- -------------- Gas and oil properties, at cost, successful efforts method of accounting: Proved........................................... $ 29,934,906 $ 30,586,079 Unproved, subject to amortization .............. 5,334,700 13,392,100 Unproved, not subject to amortization............ 44,689,074 34,180,470 Total gas and oil properties.................. 79,958,680 78,158,649 Other property and equipment.............................. 2,018,342 1,962,132 ------------ ------------ Total oil and gas properties and equipment................ 81,977,022 80,120,781 Less accumulated depletion, depreciation and amortization..................................... (40,087,050) (25,937,472) ------------ ------------ Total property and equipment, net......................... $ 41,889,972 $ 54,183,309 ============ ============
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. 44 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: COSTS INCURRED IN GAS AND OIL EXPLORATION AND PRODUCTION ACTIVITIES:
YEAR ENDED DECEMBER 31, -------------------------- 2000 1999 ----------- ----------- Acquisition of properties: Proved.............................................................. $ --- $ 848,505 Unproved............................................................ 4,525,278 5,214,982 Exploration costs...................................................... 19,491,881 11,577,425 Development costs...................................................... 916,168 859,349 ----------- ----------- Total costs incurred............................................. $24,933,327 $18,500,261 =========== ===========
CAPITALIZED COSTS:
AT DECEMBER 31, ----------------------------- 2000 1999 ------------ ------------ Proved.......................................................................... $ 29,934,906 $ 30,586,079 Unproved properties, subject to amortization.................................... 5,334,700 13,392,100 Unproved properties, not subject to amortization................................ 44,689,074 34,180,470 Less accumulated amortization................................................... (38,806,340) (24,828,022) ------------ ------------ Net capitalized costs..................................................... $41,152,340 $ 53,330,627 ============ ============
ESTIMATED QUANTITIES OF PROVED GAS AND OIL RESERVES:
CRUDE OIL, CONDENSATE AND NATURAL GAS LIQUIDS NATURAL GAS (MCF) (BARRELS) ---------------------------------- -------------------------- YEARS ENDED DECEMBER 31, YEARS ENDED DECEMBER 31, ---------------------------------- -------------------------- 2000 1999 2000 1999 --------------- --------------- ------------ ------------ Proved developed and undeveloped reserves: Beginning of period............................. 18,793,038 11,929,667 372,795 100,195 Purchases of minerals-in-place.................. --- 291,055 --- 4,802 Sales of minerals-in-place...................... (3,334,327) --- (10,653) --- Revisions of previous estimates................. (5,451,343) (6,027,430) (131,569) (45,872) Extensions, discoveries and other additions..... 16,929,105 15,981,338 387,817 414,229 Production...................................... (5,860,195) (3,381,592) (163,892) (100,559) --------------- --------------- ------------ ------------ End of period................................... 21,076,278 18,793,038_ 454,498 372,795_ ============== =============== =========== ============ Proved developed reserves: Beginning of period............................. 17,481,248 6,864,564 371,368 59,085 End of period................................... 16,198,327 17,481,248 305,842 371,368
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. 45 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. Year end prices used in determining future cash inflows averaged for natural gas and oil for the periods ended December 31, 2000 and 1999 were as follows: 2000 - $10.44 per Mcf of natural gas, $28.73 per barrel of oil; 1999 - - $2.30 per Mcf of natural gas, $22.20 per barrel of 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, -------------------------------- 2000 1999 -------------- ------------ Future cash inflows............................................................. $233,139,437 $49,970,700 Future development and production costs......................................... (33,404,090) (10,635,400) Future income tax expenses...................................................... --- --- -------------- ------------ Future net cash flows........................................................... 199,735,347 39,335,300 Discount........................................................................ (38,189,947) (6,822,200) --------------- ---------- Standardized measure of discounted future net cash flows........................ 161,545,400 $32,513,100 ============== ============
The following table sets forth changes in the standardized measure of discounted future net cash flows:
YEAR ENDED DECEMBER 31, ----------------------------------- 2000 1999 ----------------- --------------- Standardized measure of discounted future cash flows-beginning of period....... $ 32,513,100 $12,520,021 Sales of oil and gas produced, net of operating expenses....................... (26,505,466) (9,037,645) Purchases of minerals in place................................................. --- 817,070 Net changes in sales prices and production costs............................... 45,131,636 1,067,500 Extensions, discoveries and improved recovery, less related costs.............. 116,249,984 47,838,148 Change in future development costs............................................. 3,745,484 1,351,700 Previously estimated development costs incurred during the year................ (1,051,300) (9,353,624) Revisions of previous quantity estimates....................................... (12,252,353) (14,486,234) Accretion of discount.......................................................... 7,189,087 2,212,137 Net change of income taxes..................................................... --- --- Sales of minerals-in-place..................................................... (3,077,823) --- Changes in production rates (timing) and other................................. (396,949) (415,973) ----------------- --------------- Standardized measure of discounted future cash flows-end of period............. $161,545,400 $32,513,100 ================ ==============
ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Not Applicable. 46 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)(6)................................. 51 Chairman of the Board Alex M. Cranberg(1)(2)(4)............................ 46 Vice Chairman of the Board Michael E. Johnson(1)(4)............................. 53 Director, President and Chief Executive Officer Alex B. Campbell(3)(6)............................... 43 Director William D. Dodge, III(2)(5).......................... 48 Director Jack P. Randall(1)(3)(4)............................. 51 Director Hobart A. Smith(2)(3)(5)............................. 64 Director Jeffrey B. Pollicoff(6).............................. 48 Director David B. Christofferson.............................. 52 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 2003. (5) Director whose term expires in 2001 (6) Director whose term expires in 2002 DAVID W. BERRY 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 Independent Petroleum Association of America. 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 public 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. ALEX B. CAMPBELL has been a director of the Company since May 14, 1998. He has been an officer of Aspect Management Corporation since August 1996 and is currently an Executive Vice President 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 is currently a partner at Duran, Dodge & Associates, a Corpus Christi insurance agency. He was Regional President of Pacific Southwest Bank, Corpus Christi, Texas from 1995 until 2001. He was 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 47 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 is co-founder and President of Houston-based Randall & Dewey, Inc., a full-service transaction advisory firm focusing solely on upstream oil and gas mergers, acquisitions, divestments, trades and alliances. Its clients include a cross section of companies ranging from the major oil companies to small private independents. Prior to co-founding Randall & Dewey with Ken Dewey, Mr. Randall was with Amoco Production Company for 15 years. He held his last position, Manager of Acquisitions and Divestments, for seven years. Mr. Randall is a graduate of The University of Texas (Austin) with a BS in Engineering (1972) and an MS in Engineering (1975). He is a member of the Board of Directors of Cross Timbers Oil Company and Esenjay Exploration, Inc.; the Engineering Foundation Advisory Committee at the University of Texas as well as Chairman of the Petroleum Engineering Visiting Committee. Mr. Randall is also on the Board of Directors of the Sam Houston Council of the Boy Scouts of America as well as District Chairman of the Rising Star District; the M.D. Anderson Cancer Center Board of Visitors as well as being a member of the SPE, API and IPAA. 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. JEFFREY B. POLLICOFF has been a director of the Company since November 10, 1999. Mr. Pollicoff has been the Managing Partner with Pollicoff, Smith & Remels, L.L.P. since 1991, and has been with the firm since 1982. From 1981 to 1982, Mr. Pollicoff served as Executive Vice President of Norris Petroleum Company and Care Drilling Company. From 1979 to 1981, Mr. Pollicoff served as Vice President and Energy Loan Officer for Texas Commerce Bank. From 1974 to 1979, he held several engineering positions at Atlantic Richfield Corporation. Mr. Pollicoff is a member of the American Bar Association, State Bar of Texas, Houston Bar Association and College of the State Bar of Texas. He received a BS decree in Electrical Engineering from Texas A&M University in 1974 and a J.D. from the University of Houston Law School in 1980. 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 employees have significant responsibilities with the Company. DALE W. ALEXANDER, 45, 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. JAMES SMITH, 58, is Vice President-Land. Mr. Smith joined the Company in July of 2000, when he became the Company's Vice President of Land. From 1998 to 1999, he served as management consultant to various joint venture groups, including OMNITRANS, Lone Star Broadcasting and Selected Lands Corporation. From 1988 to 1998, he served as a business and financial consultant to a variety of companies. From 1980 to 1988 he was with Universal Resources Corporation where he worked in land management and as an assistant exploration manager. From 1971 to 1980, he worked in various staff and management positions in the land departments at Statex Petroleum, Tenneco Exploration and Ashland Exploration. Mr. Smith has a BA in Political Science and Speech from Lamar University and attended South Texas College of Law and the University of Oklahoma. ERIC GARDNER, 37, is Exploration Manager in the Houston office. Mr. Gardner joined the Company in 48 September of 1999. From 1994 to 1999 he served as project leader and senior explorationist at 3DX Technologies Inc. From 1985 to 1994 he was a senior geophysicist at Amoco Production Company. He received a BS in Engineering Physics from Colorado School of Mines in 1985. WILLIAM L. JACKSON, 45, 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. MICHAEL E. MOORE, 43, is Vice President-Exploration. Mr. Moore joined EPC in 1982 as a staff geologist and became the Company's Vice President-Exploration 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. SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE 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, 2000, its officers, directors and 10% shareholders complied with all Section 16(a) filing requirements applicable to such individuals. ITEM 10. EXECUTIVE COMPENSATION The following table sets forth the total remuneration paid during 2000, 1999, and 1998 to the individuals who served as Chief Executive Officer of the Company during 2000 and the Company's other most highly compensated officers who received compensation in excess of $100,000 during 2000. 49 SUMMARY COMPENSATION TABLE
LONG-TERM COMPENSATION ----------------------------------- ANNUAL COMPENSATION(1) AWARDS PAYOUTS ------------------------------------- ----------------------- ------- NAME OTHER SECURITIES ALL AND ANNUAL RESTRICTED UNDERLYING OTHER PRINCIPAL COMPENS- STOCK OPTIONS/ LTIP COMPEN- POSITION YEAR SALARY($) BONUS($)(5) ATION($) AWARD(S) SARS(#)(2) PAYOUTS SATION($) -------- ---- --------- ----------- -------- -------- ---------- ------- --------- Michael E. Johnson(3)....... 2000 $200,000 $84,771 ------ ------ 600,000 ------ ------ President and 1999 $200,000 ------ ------ ------ ------ ------ ------ Chief Executive Officer 1998 $125,000 ------ ------ ------ ------ ------ ------ David W. Berry(4)........... 2000 $155,000 $65,698 ------ ------ 600,000 ------ ------ Chairman of the Board 1999 $155,000 ------ ------ ------ ------ ------ ------ 1998 $147,079 ------ ------ ------ ------ ------ $264,000(6) David B Christofferson...... 2000 $130,000 $55,101 ------ ------ 150,000 ------ ------ Senior Vice President and 1999 $130,000 ------ ------ ------ ------ ------ ------ Principal Financial Officer 1998 $121,606 ------ ------ ------ ------ ------ $224,000(6) William L. Jackson.......... 2000 $114,700 $47,401 ------ ------ 75,000 ------ ------ Senior Vice President - 1999 $114,700 ------ ------ ------ ------ ------ ------ Operations 1998 $ 71,688 ------ ------ ------ ------ ------ ------ Dale Alexander.............. 2000 $100,641 $40,266 ------ ------ 100,000 ------ ------ Vice President - 1999 $ 95,000 ------ ------ ------ ------ ------ ------ Exploitation 1998 $ 59,375 ------ ------ ------ ------ ------ ------
- ------------------------------ (1) Does not include perquisites and other personal benefits that are the lesser of 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 which were granted during the year. (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) The Company has instituted a bonus plan which is significantly based upon dollars expended during a given year on drilling and completion costs contrasted with the present value return in the form of net revenue received and projected to be received as determined by engineering evaluation of such drilled projects. 1999 operations results were primarily used to determine the 2000 bonus. 2000 operations results will primarily determine the 2001 bonus. The bonus may be paid up to 50% in common stock, based upon market value at the time of issuance, at the election of the Company. (6) 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". OPTION GRANTS The option grants made in 2000 to the individuals named in the Summary Compensation Table above are as set forth in the following table:
Individual Grants ------------------------------------------------------------------------------- % OF TOTAL NUMBER OF SECURITES OPTIONS GRANTED TO EXERCISE OF UNDERLYING EMPLOYEES IN FISCAL PRICE PER EXPIRATION NAME OPTIONS GRANTED YEAR 2000(1) SHARE DATE - ---- --------------------- --------------------- ----------- ------------- Michael E. Johnson............ 600,000(2) 25.3% $2.375 5/14/08 David W. Berry................ 600,000(2) 25.3% $2.375 5/14/08 David B Christofferson........ 150,000(2) 6.3% $2.375 5/14/08 William L. Jackson............ 75,000(2) 3.2% $2.375 5/14/08 Dale W. Alexander......... 100,000(2) 4.2% $2.375 5/14/08
50 - ------------------- (1) Based on options to purchase a total of 2,376,999 shares of Common Stock granted during 2000, of which 244,331 (or 10.3%) have expired. (2) Consists of options issued under the Esenjay Exploration, Inc. Long Term Incentive Plan, 66.67% of which are currently exercisable. OPTION REPRICING There were no option repricings made in 2000 to the individuals named in the Summary Compensation Table above. OPTION EXERCISE AND YEAR-END VALUES The following table sets forth certain information as of December 31, 2000 with respect to the unexercised options to purchase Common Stock to the individuals named in the Summary Compensation Table above. None of such individuals exercised any stock options during 2000.
DECEMBER 31, 2000 OPTION/SAR VALUES NUMBER OF VALUE OF SECURITIES UNEXERCISED UNDERLYING IN-THE-MONEY UNEXERCISED OPTIONS/SARS AT OPTIONS/SARS AT DECEMBER 31, 2000 DECEMBER 31, 2000 SHARES ACQUIRED VALUE EXERCISABLE/ EXERCISABLE/ NAME ON EXERCISE(#) REALIZED($) UNEXERCISABLE UNEXERCISABLE(1) - ------------------------------- --------------- ----------------- ---------------- ------------------ Michael E. Johnson(2)...... ------ ------ 400,000/200,000 $925,200/$462,600 David W. Berry(3).......... ------ ------ 432,000/200,000 $954,256/$462,600 David B Christofferson(4).. ------ ------ 158,667/50,000 $284,569/$115,650 William L. Jackson(2)...... ------ ------ 50,000/25,000 $115,650/$57,825 Dale W. Jackson(2)......... ------ ------ 66,667/33,333 $154,200/$77,099
- -------------- (1) Based on the last sale price of the Common Stock on the Nasdaq Small-Cap Market on December 29, 2000 of $4.688. (2) All options are exercisable at a price of $2.375 per share. (3) 400,000 currently exercisable options are exercisable at a price of $2.375 per share and 32,000 currently exercisable options are exercisable at a price of $3.78 per share. All options not currently exercisable are exercisable at a price of $2.375 per share. (4) 100,000 currently exercisable options are exercisable at a price of $2.375 per share and 58,667 currently exercisable options are exercisable at a price of $3.78 per share. All options not currently exercisable are exercisable at a price of $2.375 per share. DIRECTORS' COMPENSATION The Board of Directors has adopted a standard compensation policy for each of its directors whereby each director is paid a quarterly fee of $5,625. There are currently no additional amounts paid for committee participation or special assignments. The Board of Directors has also instituted a standardized compensation arrangement for each director who began service on the board of directors on May 15, 1998. This includes all directors other than Mr. Pollicoff. In this regard, in April of 2000 each such director was issued: o an option to purchase 12,000 shares of common stock at an exercise price of $1.83 per share exercisable through May 15, 2008; and 51 o an option to purchase an additional 12,000 shares of common stock at a price of $2.10 per share exercisable through May 15, 2009; and o provided that the director still serves on the board of directors on May 15, 2001, an option to purchase an additional 12,000 shares of common stock at a price of $2.38 per share exercisable through May 15, 2010. In conjunction therewith, each such director has purchased, and in April of 2000 was issued, 12,000 shares of common stock at a price of $1.83 per share payable one-third upon subscription, one-third on or before May 15, 2000, and one-third on or before May 15, 2001. Mr. Berry is not an officer of the Company but serves it full time in his role as Chairman of the Board of Directors. Accordingly, he receives a salary and other benefits for his services. (See Item 10-Executive Compensation). Mr. Pollicoff has been granted a similar compensation package. In this regard, he has been issued in May 2000: o an option to purchase 12,000 shares of common stock at an exercise price of $1.83 per share, exercisable through May 15, 2008; and o provided that he still serves on the board of directors on May 15, 2001, an option to purchase 12,000 shares of common stock at an exercise price of $2.10 per share, exercisable through May 15, 2009; and o provided that he still serves on the board of directors on May 15, 2002, an option to purchase 12,000 shares of common stock at an exercise price of $2.38 per share through May 15, 2010. In conjunction therewith, Mr. Pollicoff also purchased 12,000 shares of common stock at a price of $1.83 per share payable one-third upon subscription, one-third one year thereafter, and the balance two years after purchase. ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT EMPLOYMENT CONTRACTS AND COMPENSATORY PLANS OR ARRANGEMENTS There were no employment contracts in effect with any named executive officer in 2000. The Company has adopted an Employee Incentive and Severance Protection Plan that covers all employees including its officers. Pursuant to such plan, in the event the Company was acquired by a third party or incurred a change in control, and the individual employee agreed to remain with the Company for a minimum of six months after such change in control, then at the end of such six months the employee would be paid a one time bonus equal to six months of their base salary. BENEFICIAL OWNERSHIP OF COMMON STOCK The following table sets forth certain information, as of March 29, 2001, 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 2000 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. 52
NUMBER OF PERCENT OF NAME OF BENEFICIAL OWNER SHARES(1) CLASS(2)(3) - ------------------------ ---------------------------- ------------------ Esenjay Petroleum Corporation(4)................. 4,896,415 25.8% Aspect Resources LLC(5).......................... 4,748,156 25.0% David W. Berry(6)................................ 867,751(7) 4.6% Alex M. Cranberg(5).............................. 4,850,268(8) 25.6% Michael E. Johnson(4)............................ 5,650,303(9)(10) 29.8% Charles J. Smith(4).............................. 4,985,415(9) 26.3% Alex B. Campbell(5).............................. 48,713(11) * William D. Dodge, III(6)......................... 48,000(11) * Jack P. Randall(6)............................... 48,000(11) * Hobart A. Smith(6)............................... 48,000(11) * Jeffrey B. Pollicoff(6).......................... 50,000(11) * William L. Jackson(4)............................ 99,008(12) * Dale W. Alexander(4)............................. 111,886(13) * David B Christofferson(6)........................ 218,231(14) 1.1% Wellington Management Company, LLP(15)........... 1,135,000 6.0% Centennial Energy Partners, L.L.C.(16)........... 965,000 5.1% All executive officers and Directors as a group (11 persons) 2,241,477(17) 11.8%
- -------------------------- * 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 18,980,698 shares of common stock outstanding at March 29, 2001, 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 or warrants. 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., 500 North Water Street, Suite 1100 South, Corpus Christi, Texas 78471. (5) Address: 511 16th Street, Suite 300, Denver, Colorado 80202. (6) Address: c/o Esenjay Exploration, Inc., 500 Dallas, Suite 2920, Houston, Texas 77002 (7) Includes 668,000 shares of common stock issuable upon the exercise of stock options currently exercisable or exercisable within sixty days. (8) Includes (i) 54,112 shares of common stock owned by the spouse of Mr. Cranberg, and (ii) 4,748,156 shares of common stock owned by Aspect, as to which Mr. Cranberg disclaims beneficial ownership. Also includes 36,000 shares of common stock issuable upon the exercise of options currently exercisable or exercisable within 60 days. (9) Includes 4,896,415 shares of common stock owned by EPC, as to which Messrs. Johnson and Smith disclaim beneficial ownership. (10) Includes 636,000 shares of common stock issuable upon the exercise of options currently exercisable or exercisable within 60 days. (11) Includes 36,000 shares of common stock issuable upon the exercise of options currently exercisable or exercisable within 60 days. (12) Includes 75,000 shares of common stock issuable upon the exercise of stock options currently exercisable or exercisable within sixty days and 1,753 shares of common stock owned by the spouse of Mr. Jackson. (13) Includes 100,000 shares of common stock issuable upon the exercise of stock options currently exercisable or exercisable within sixty days. (14) Includes 208,667 shares of common stock issuable upon the exercise of stock options currently exercisable or exercisable within sixty days. (15) Address: 75 State Street, Boston, Massachusetts 02109. 53 (16) Address: 900 Third Ave., Suite 1801, New York, New York 10022. Based solely upon statements of beneficial ownership filed of record, Centennial Energy Partners, L.L.C. beneficially owns 938,800 shares of common stock, which shares comprise 4.9% of the total outstanding shares. Joseph H. Reich and Peter K. Seldin of the same address are also beneficial owners of said 938,800 shares of common stock based solely upon statements of beneficial ownership filed of record. Based upon other information available to the Company, Centennial Energy Partners, L.L.C. currently is the beneficial owner of 965,000 shares of common stock of the Company, which shares comprise 5.1% of the total outstanding shares. (17) Includes 1,903,667 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. ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The Company and Aspect Management Corporation, the manager of Aspect ("Aspect Management"), entered into a Geotechnical Services Consulting Agreement on May 14, 1998, pursuant to which Aspect Management may perform geotechnical services for the Company. 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 Services 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. No such services were provided in 1999 or 2000 under this agreement. The Company and Aspect Management also entered into a Land Service Consulting Agreement on May 14, 1998, pursuant to which Aspect Management could provide certain land related services to the Company in connection with certain oil and gas properties to which both parties share an ownership interest. This agreement contained terms and provisions similar to the above-referenced Geotechnical Services Consulting Agreement. No services were provided pursuant to this Land Service Consulting Agreement in 1999 and the parties agreed to terminate the agreement. It was terminated in 1999 and is no longer in effect. In the second quarter of 1999, the Company closed an agreement pursuant to which it sold 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. Proceeds from the sale were used to help settle amounts due Aspect. In that Aspect is a related party, closing was subject to receipt of an independent fairness opinion which was obtained. The Company operates certain wells in which Aspect and EPC own interests. Pursuant to joint operating agreements which include the same terms as apply to unrelated third parties, Aspect and EPC pay normal operation costs associated with such wells. Conversely, Aspect operates certain Exploration Projects and wells in which the Company owns interests. Pursuant to joint operating agreements which include the same terms as apply to unrelated third parties, the Company pays normal operation costs associated with such Exploration Projects and wells. In 2000 Sommersault, LLC, an investment entity owned 100% by David W. Berry, the Chairman of the Board of Directors of the Company, purchased working interests in three exploratory drilling prospects operated by the Company. All of the working interests were purchased pursuant to the same terms as concurrent transactions with industry partners. The total costs paid by Mr. Berry to the Company in 2000 were less than $100,000. In 1999 the Company retained the firm of Randall and Dewey, Inc. ("Randall and Dewey") to assist in the marketing and sale of interests in its Raymondville Project in Willacy County, Texas. Jack P. Randall, a director of the Company, is also President and CEO and a substantial shareholder of Randall and Dewey. Pursuant to the agreement with Randall and Dewey, the Company reimbursed Randall and Dewey for $30,715 in costs incurred in 1999. In addition, upon closing of a sale of interests in the Raymondville Project in March of 2000, the Company paid Randall and Dewey a transaction fee of $382,192. This fee included a base transaction fee of $250,000 plus 0.75% of the total 54 selling price. The Company's share of the fee was approximately 80.88% with third parties who also sold interests in the Raymondville Project, including EPC, reimbursing the Company for their 19.12% pro rata share of the total fee. The Company believes the fee charged was the normal fee which would be charged to third parties for comparable services. In 2000 the Company retained the firm of Randall and Dewey to initiate, analyze and manage potential transactions which may better maximize shareholder value. Deutsche Bank Securities, Inc. was retained to advise the Company concerning various strategic alternatives in this regard. Potential alternatives included possible mergers, acquisitions or a potential cash sale. The company does not presently intend to aggressively pursue such options. In 2000 the Company paid Randall and Dewey an advisory fee of $150,000. In the event a transaction was consummated pursuant to its agreement with Randall and Dewey, it would owe Randall and Dewey a transaction fee of 0.75 percent of the value of the transaction plus 1.125% of the value of the transaction in excess of $56.7 MM. On December 31, 2000 and 1999, the Company had accounts receivable from employees and affiliates totaling net amounts of $124,267 and $553,950, respectively. The December 31, 2000 balance includes net accounts payable due to Aspect in the amount of $122,506. The December 31, 2000 and 1999 balances include net accounts receivable due from EPC in the amount of $101,199 and $190,923, respectively. At December 31, 1999, the Company had a net account payable due to Aspect in the amount of $2,083,913. 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. 55 PART IV ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K
EXHIBIT NAME OF EXHIBIT - ------- --------------- 2(a) Plan and Agreement of Merger of Esenjay Exploration, Inc. and 3DX Technologies Inc. is incorporated by reference to the Company's Quarterly Report on Form 10QSB for the quarter ended March 31, 1999 dated May 19, 1999 wherein the same appears as Exhibit 2. 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(a) 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. 4(b) Certificate of Designations of Esenjay Exploration, Inc. establishing the designations, preferences, limitations, and relative rights of its Series A Convertible Preferred Stock is incorporated by reference to the Company's Quarterly Report on Form 10-QSB for the quarter ended September 30, 1999 dated November 15, 1999 wherein the same appears as Exhibit 4. 10(a) $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(b) Credit Agreement by and between Esenjay Exploration, Inc. and Duke Energy Financial Services, Inc. dated as of January 28, 1999, 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). 10(c) 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(d) 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(e) 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(f) 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(g) 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(h) Warrant Agreement between Frontier Natural Gas Corporation and Gaines, Berland Energy Fund, L.P. dated 56 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(i) 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(j) 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). 10(k) Credit Agreement by and between Esenjay Exploration, Inc. and Deutsche Bank AG, New York and/or Cayman Islands Branches, dated as of January 25, 2000, as incorporated by reference to the Company's Annual Report on Form 10-KSB for the fiscal year ended December 31, 1999, dated April 13, 2000, wherein the same appears as Exhibit 10(m). 10(l)* Amendment Number One to Credit Agreement by and between Esenjay Exploration, Inc. and Deutsche Bank AG, New York and/or Cayman Islands Branch, dated as of January 24, 2001. 10(m)* Amendment Number Two to Credit Agreement by and between Esenjay Exploration, Inc. and Deutsche Bank AG, New York and/or Cayman Islands Branch, dated as of February 23, 2001. 10(n) Esenjay Exploration, Inc. Long Term Incentive Plan is incorporated by reference to the Company's Definitive Proxy Statement filed September 7, 2000 wherein it appeared as an exhibit. 11* Statement of Earnings per Share 21* Subsidiaries of Registrant. (b) Reports on Form 8-K. Form 8-K filed on October 2, 2000 is incorporated by reference.
- -------------------- *Filed herewith 57 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 16, 2001 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 16, 2001 /s/ David B. Christofferson --------------------------------------------- David B Christofferson, Senior Vice President General Counsel and Chief Financial Officer Date: April 16, 2001 /s/ David W. Berry --------------------------------------------- David W. Berry, Chairman and Director Date: April 16, 2001 /s/ Alex B. Campbell --------------------------------------------- Alex B. Campbell, Director Date: April 16, 2001 /s/ Jeffrey B. Pollicoff --------------------------------------------- Jeffrey B. Pollicoff, Director Date: April 16, 2001 /s/ Jack P. Randall --------------------------------------------- Jack P. Randall, Director Date: April 16, 2001 /s/ Hobart A. Smith --------------------------------------------- Hobart A. Smith, Director
58 EX-10.(L) 2 a2043667zex-10_l.txt EXHIBIT 10(L) AMENDMENT NO. 1 TO CREDIT AGREEMENT THIS AMENDMENT NO. 1 TO CREDIT AGREEMENT (this "AMENDMENT NO. 1"), dated as of January 24, 2001, between ESENJAY EXPLORATION, INC., a Delaware corporation (the "BORROWER"), and DEUTSCHE BANK AG, New York and/or Cayman Islands Branch (the "LENDER"), W I T N E S S E T H: WHEREAS, the Borrower and the Lender are parties to that certain Credit Agreement, dated as of January 25, 2000 (as the same has been from time-to-time amended, hereinafter referred to as the "EXISTING CREDIT AGREEMENT"); and WHEREAS, the Borrower has requested that certain amendments be made to the Existing Credit Agreement; and WHEREAS, the Lender is willing to make certain amendments to the Existing Credit Agreement on the terms and conditions hereinafter provided; and NOW, THEREFORE, in consideration of the agreements herein contained, the parties hereto hereby agree as follows: ARTICLE I. DEFINITIONS SECTION 1.1 CERTAIN DEFINITIONS. The following terms (whether or not underscored) when used in this Amendment No. 1 shall have the following meanings: "AMENDED CREDIT AGREEMENT" means the Existing Credit Agreement as amended by this Amendment No. 1. SECTION 1.2 OTHER DEFINITIONS. Unless otherwise defined or the context otherwise requires, terms used herein (including in the preamble and recitals hereto) have the meanings provided for in the Existing Credit Agreement. ARTICLE II. AMENDMENT TO EXISTING CREDIT AGREEMENT Effective as of January 24, 2001, the Existing Credit Agreement is amended in accordance with the terms of this ARTICLE II; except as so amended, the Existing Credit Agreement shall continue to remain in all respects in full force and effect. SECTION 2.1 AMENDMENT TO SECTION 1.1. (a) SECTION 1.1 is hereby amended by deleting the text of the existing definition of "Tranche A Availability Termination Date" and inserting the following definition in its place in SECTION 1.1: "TRANCHE A AVAILABILITY TERMINATION DATE" means February 23, 2001. ARTICLE III. REPRESENTATIONS AND WARRANTIES In order to induce the Lender to make the amendments provided for in ARTICLE II, the Borrower hereby (a) represents and warrants that the Borrower has full power and authority to execute, deliver and perform its obligations under this Amendment No. 1 and all other Loan Documents delivered to Lender in connection herewith, and this Amendment No. 1 and all such Loan Documents are the legally valid and binding obligations of Borrower, enforceable against Borrower in accordance with their respective terms; (b) represents and warrants that each of the representations and warranties contained in the Existing Credit Agreement and in the other Loan Documents is true and correct as of the date hereof as if made on the date hereof (except, if any such representation and warranty relates to an earlier date, such representation and warranty shall be true and correct in all material respects as of such earlier date) and Borrower has performed each of the covenants and agreements in the Existing Credit Agreement and the other Loan Documents required to be performed by Borrower as of the date hereof; -2- (c) represents and warrants that there is no Default or Event of Default by Borrower or any other Obligor under the Existing Credit Agreement or any other Loan Document and no event exists which, with the giving of notice or the passage of time or both, would give rise to a Default or Event of Default by Borrower or any other Obligor under the Existing Credit Agreement or any Loan Document. ARTICLE IV. CONDITIONS TO EFFECTIVENESS SECTION 4.1 EFFECTIVENESS. This Amendment No. 1 shall become effective when the conditions set forth in this SECTION 4.1 have been satisfied: (a) EXECUTION OF COUNTERPARTS. The Lender shall have received counterparts of this Amendment No. 1 duly executed and delivered on behalf of the Borrower and the Lender. (b) CLOSING FEES, EXPENSES, ETC. The Lender shall have received all reasonable costs and expenses due and payable pursuant to SECTIONS 3.3 and 10.3 of the Existing Credit Agreement, if then invoiced. (c) LEGAL DETAILS, ETC. All documents executed or submitted pursuant hereto, and all legal matters incident thereto, shall be satisfactory in form and substance to the Lender and its counsel. ARTICLE V. MISCELLANEOUS SECTION 5.1 LOAN DOCUMENT PURSUANT TO EXISTING CREDIT AGREEMENT. This Amendment No. 1 is a Loan Document executed pursuant to the Existing Credit Agreement. Except as expressly amended or waived hereby, all of the representations, warranties, terms, covenants and conditions contained in the Existing Credit Agreement and each other Loan Document shall remain unamended and in full force and effect. The amendments set forth herein shall be limited precisely as provided for herein and shall not be deemed to be a waiver of, amendment of, consent to or modification of any other term or provision of the Existing Credit Agreement or of any term or provision of any other Loan Document or of any transaction or further or future action on the part of the Borrower which would require the consent of the Lender under the Existing Credit Agreement or any other Loan Document. -3- SECTION 5.2 COUNTERPARTS, ETC. This Amendment No. 1 may be executed by the parties hereto in several counterparts, each of which shall be deemed to be an original and all of which shall constitute together but one and the same agreement with the same effect as if all parties hereto had signed the same signature page. Any signature page of this Amendment No. 1 may be detached from any identical counterpart of this Amendment No. 1 having attached to it one or more additional signature pages. SECTION 5.3 GOVERNING LAW; ENTIRE AGREEMENT. THIS AMENDMENT NO. 1 SHALL BE DEEMED TO BE A CONTRACT MADE UNDER AND GOVERNED BY THE INTERNAL LAWS OF THE STATE OF NEW YORK. SECTION 5.4 TITLES AND HEADINGS. The titles and headings of the Sections of this Amendment No. 1 are intended for convenience only and shall not in any way affect the meaning or construction of any provision of this Amendment No. 1. SECTION 5.5 CHANGES AND MODIFICATIONS IN WRITING. No provision of this Amendment No. 1 may be changed or modified except by an instrument in writing signed by the party against whom enforcement of the change or modification is sought. -4- IN WITNESS WHEREOF, the parties hereto have caused this Amendment No. 1 to be executed by their respective officers hereunto duly authorized as of the day and year first above written. BORROWER ESENJAY EXPLORATION, INC., a Delaware corporation By: /s/ David B. Christofferson -------------------------------- Name: David B. Christofferson Title: Senior Vice President LENDER DEUTSCHE BANK AG, NEW YORK AND/OR CAYMAN ISLANDS BRANCH By: /s/ Kurt A. Schreder -------------------------------- Name: KURT A. SCHREDER Title: Vice President By: /s/ Kerri L. Fox -------------------------------- Name: KERRI L. FOX Title: Vice President EX-10.(M) 3 a2043667zex-10_m.txt EXHIBIT 10(M) AMENDMENT NO. 2 TO CREDIT AGREEMENT THIS AMENDMENT NO. 2 TO CREDIT AGREEMENT (this "AMENDMENT NO. 2"), dated as of February 23, 2001, between ESENJAY EXPLORATION, INC., a Delaware corporation (the "BORROWER"), and DEUTSCHE BANK AG, New York and/or Cayman Islands Branch (the "LENDER"), W I T N E S S E T H: WHEREAS, the Borrower and the Lender are parties to that certain Credit Agreement, dated as of January 25, 2000 (as the same has been from time-to-time amended, hereinafter referred to as the "EXISTING CREDIT AGREEMENT"); and WHEREAS, the Borrower has requested that certain amendments be made to the Existing Credit Agreement; and WHEREAS, the Lender is willing to make certain amendments to the Existing Credit Agreement on the terms and conditions hereinafter provided; and NOW, THEREFORE, in consideration of the agreements herein contained, the parties hereto hereby agree as follows: ARTICLE I. DEFINITIONS SECTION 1.1 CERTAIN DEFINITIONS. The following terms (whether or not underscored) when used in this Amendment No. 2 shall have the following meanings: "AMENDED CREDIT AGREEMENT" means the Existing Credit Agreement as amended by this Amendment No. 2. SECTION 1.2 OTHER DEFINITIONS. Unless otherwise defined or the context otherwise requires, terms used herein (including in the preamble and recitals hereto) have the meanings provided for in the Existing Credit Agreement. ARTICLE II. AMENDMENT TO EXISTING CREDIT AGREEMENT Effective as of February 23, 2001, the Existing Credit Agreement is amended in accordance with the terms of this ARTICLE II; except as so amended, the Existing Credit Agreement shall continue to remain in all respects in full force and effect. SECTION 2.1 AMENDMENT TO SECTION 1.1. (a) SECTION 1.1 is hereby amended by deleting the text of the existing definition of "Tranche A Availability Termination Date" and inserting the following definition in its place in SECTION 1.1: "TRANCHE A AVAILABILITY TERMINATION DATE" means January 25, 2002. ARTICLE III. REPRESENTATIONS AND WARRANTIES In order to induce the Lender to make the amendments provided for in ARTICLE II, the Borrower hereby (a) represents and warrants that the Borrower has full power and authority to execute, deliver and perform its obligations under this Amendment No. 2 and all other Loan Documents delivered to Lender in connection herewith, and this Amendment No. 2 and all such Loan Documents are the legally valid and binding obligations of Borrower, enforceable against Borrower in accordance with their respective terms; (b) represents and warrants that each of the representations and warranties contained in the Existing Credit Agreement and in the other Loan Documents is true and correct as of the date hereof as if made on the date hereof (except, if any such representation and warranty relates to an earlier date, such representation and warranty shall be true and correct in all material respects as of such earlier date) and Borrower has performed each of the covenants and agreements in the Existing Credit Agreement and the other Loan Documents required to be performed by Borrower as of the date hereof; (c) represents and warrants that there is no Default or Event of Default by Borrower or any other Obligor under the Existing Credit Agreement or any other Loan Document and no event exists which, with the giving of notice or the passage -2- of time or both, would give rise to a Default or Event of Default by Borrower or any other Obligor under the Existing Credit Agreement or any Loan Document. ARTICLE IV. CONDITIONS TO EFFECTIVENESS SECTION 4.1 EFFECTIVENESS. This Amendment No. 2 shall become effective when the conditions set forth in this SECTION 4.1 have been satisfied: (a) EXECUTION OF COUNTERPARTS. The Lender shall have received counterparts of this Amendment No. 2 duly executed and delivered on behalf of the Borrower and the Lender. (b) CLOSING FEES, EXPENSES, ETC. The Lender shall have received all reasonable costs and expenses due and payable pursuant to SECTIONS 3.3 and 10.3 of the Existing Credit Agreement, if then invoiced. (c) LEGAL DETAILS, ETC. All documents executed or submitted pursuant hereto, and all legal matters incident thereto, shall be satisfactory in form and substance to the Lender and its counsel. ARTICLE V. MISCELLANEOUS SECTION 5.1 LOAN DOCUMENT PURSUANT TO EXISTING CREDIT AGREEMENT. This Amendment No. 2 is a Loan Document executed pursuant to the Existing Credit Agreement. Except as expressly amended or waived hereby, all of the representations, warranties, terms, covenants and conditions contained in the Existing Credit Agreement and each other Loan Document shall remain unamended and in full force and effect. The amendments set forth herein shall be limited precisely as provided for herein and shall not be deemed to be a waiver of, amendment of, consent to or modification of any other term or provision of the Existing Credit Agreement or of any term or provision of any other Loan Document or of any transaction or further or future action on the part of the Borrower which would require the consent of the Lender under the Existing Credit Agreement or any other Loan Document. SECTION 5.2 COUNTERPARTS, ETC. This Amendment No. 2 may be executed by the parties hereto in several counterparts, each of which shall be deemed to be an original and all of which shall constitute together but one and the same agreement with the same effect as if all parties hereto had signed the same signature page. Any signature -3- page of this Amendment No. 2 may be detached from any identical counterpart of this Amendment No. 2 having attached to it one or more additional signature pages. SECTION 5.3 GOVERNING LAW; ENTIRE AGREEMENT. THIS AMENDMENT NO. 2 SHALL BE DEEMED TO BE A CONTRACT MADE UNDER AND GOVERNED BY THE INTERNAL LAWS OF THE STATE OF NEW YORK. SECTION 5.4 TITLES AND HEADINGS. The titles and headings of the Sections of this Amendment No. 2 are intended for convenience only and shall not in any way affect the meaning or construction of any provision of this Amendment No. 2. SECTION 5.5 CHANGES AND MODIFICATIONS IN WRITING. No provision of this Amendment No. 2 may be changed or modified except by an instrument in writing signed by the party against whom enforcement of the change or modification is sought. -4- IN WITNESS WHEREOF, the parties hereto have caused this Amendment No. 2 to be executed by their respective officers hereunto duly authorized as of the day and year first above written. BORROWER -------- ESENJAY EXPLORATION, INC., a Delaware corporation By: /s/ David B. Christofferson ------------------------------ Name: David B. Christofferson Title: Senior Vice President LENDER DEUTSCHE BANK AG, NEW YORK AND/OR CAYMAN ISLANDS BRANCH By: /s/ Gregory J. Moroney ------------------------------ Name: Gregory J. Moroney Title: Managing Director By: /s/ John H. Honier ------------------------------ Name: John H. Honier Title: Managing Director EX-11 4 a2043667zex-11.txt EXHIBIT 11 EXHIBIT 11 TO FORM 10-KSB COMPUTATION OF EARNINGS PER COMMON SHARE AND COMMON SHARE EQUIVALENTS
Year Ended December 31, ----------------------------------- 2000 1999 ---------------- --------------- BASIC EARNINGS PER SHARE Weighted average common shares outstanding ............ 18,877,192 16,612,314 ============ ============ Basic loss before extraordinary gain .............. $ (0.46) $ (0.62) ============ ============ Basic loss per share .............................. $ (0.40) $ (0.62) ============ ============ DILUTED EARNINGS PER SHARE Weighted average common shares outstanding ............ 18,877,192 16,612,314 Shares issuable from assumed conversion of Convertible preferred stock .................... 259,458 96,830 Shares issuable from assumed conversion of common share options and warrants ................. 507,459 10,437 ------------ ------------ Weighted average common shares outstanding, as adjusted 19,644,109 16,719,581 ============ ============ Diluted loss before extraordinary gain ............ $ (0.44) $ (0.61) ============ ============ Diluted loss per share ............................ $ (0.38) $ (0.61) ============ ============ EARNINGS FOR BASIC AND DILUTED COMPUTATION Net loss before extraordinary gain .................... $ (8,660,638) $(10,250,238) Extraordinary gain .................................... 1,126,034 --- ------------ ------------ Net loss to common shareholders (basic and diluted earnings per share computation) ................... $ (7,534,604) $(10,250,238) ============ ============
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. EX-21 5 a2043667zex-21.txt EXHIBIT 21 EXHIBIT 21 TO FORM 10-KSB/A The subsidiaries of the Registrant are:
NAME STATE OF INCORPORATION - ---- ---------------------- Frontier Acquisition Corp. Oklahoma
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