-----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, EP9RSIi5hgtvfxHnsNlRIdcuMyCDUn57FxD335uVQYxrnHpGOU7nwfcqcUIFDX78 vHzENOxtADxXBFUHkMvTXQ== 0000912057-02-015330.txt : 20020416 0000912057-02-015330.hdr.sgml : 20020416 ACCESSION NUMBER: 0000912057-02-015330 CONFORMED SUBMISSION TYPE: 10KSB PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 20011231 FILED AS OF DATE: 20020416 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: 10KSB SEC ACT: 1934 Act SEC FILE NUMBER: 001-12530 FILM NUMBER: 02612836 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 10KSB 1 a2077010z10ksb.txt FORM 10-KSB ================================================================================ 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, 2001 / / 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 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: $41,661,926. 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 $25,454,000 on March 28, 2002 (based on the last sales price of $2.81 per share as reported on the NASDAQ Stock Market). 19,140,667 shares of the registrant's common stock were outstanding as of March 28, 2002. ================================================================================ ESENJAY EXPLORATION, INC. FOR YEAR ENDED DECEMBER 31, 2001 TABLE OF CONTENTS FORM 10-KSB PART I
ITEM PAGE - ---- ---- 1. Description of Business................................................... 3 2. Description of Property................................................... 17 3. Legal Proceedings......................................................... 20 4. Submission of Matters to a Vote of Security Holders....................... 20 PART II 5. Market for Common Equity and Related Stockholder Matters.................. 21 6. Management's Discussion and Analysis...................................... 21 7. Financial Statements...................................................... 33 8. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure...................................... 52 PART III 9. Directors, Executive Officers, Promoters and Control Persons; Compliance with Section 16(a) of the Exchange Act........................ 52 10. Executive Compensation.................................................... 52 11. Security Ownership of Certain Beneficial Owners and Management........................................................... 52 12. Certain Relationships and Related Transactions............................ 52 PART IV 13. Exhibits and Reports on Form 8-K.......................................... 53 Signatures................................................................ 54
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. Esenjay Exploration Inc.'s (the "Company) 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 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 greatly expanded its exploration activities when it acquired interest in 28 exploration projects located along the Texas Gulf Coast. The Exploration Projects also include the Company's interests in these projects and projects originated since that time. 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. 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. 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 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. On March 17, 2002, the Company and Santos Americas and Europe Corporation and ECM Acquisition Company, (collectively "Santos") entered into an agreement providing for Santos' acquisition of all issued and outstanding common stock of the Company by means of a tender offer at a price of US$2.84 per share in cash and a follow-on merger at the same price. Under the terms agreed, Santos initiated a formal offer on March 26, 2002. The offer must remain open through at least April 22, 2002. It is conditioned upon the receipt of at least a majority of the Company's outstanding shares. If Santos receives at least a majority of such shares, it will, subject to various typical contingencies such as the absence of any material adverse changes, close on the purchase of shares tendered and then proceed to acquire all remaining outstanding shares through a subsequent merger, the timing of which would be announced at a later date. Shareholders who do not participate in the tender offer would also receive $2.84 per share in cash in the merger. At a meeting held on Saturday, March 16, 2002, the Company's Board of Directors voted to accept and support the Santos tender offer and voted to recommend that the Company's shareholders accept the cash tender offer and approve the merger. In addition, as a condition to the offer, two major shareholders and the Chairman of the Board of Directors agreed to tender all of the shares owned by them (representing 9,991,662 shares or 52% of the Company's total outstanding shares) in the Santos tender offer and have granted Santos the option to acquire all of their shares if the tender offer is not consummated for certain reasons. In voting to accept and support the Santos tender offer, The Company's Board of Directors considered a number of factors. The Company has historically been forced to constrain capital spending and to sell larger than desired interests in its exploration projects and prospects in order to fund its capital program, which has resulted in lower than expected reserve growth. As part of the Company's evaluation of strategic alternatives, a process, initially undertaken in late 2000, the Board of 3 Directors recognized that its inability to access sufficient capital at an acceptable cost would be an ongoing impediment to the Company's ability to fully exploit its sizable asset base. The Company and it financial advisors do not anticipate a meaningful improvement in the access to affordable capital in the foreseeable future, and as a result it will be difficult to maximize the substantial reserve potential that the Company believes exists in its prospect inventory. With this in mind, and after revisiting strategic alternatives and potential transactions available to the Company in the current marketplace, the Board of Directors recommended that the Company's shareholders accept the Santos offer. In the event the tender offer and merger are closed, the Company will not continue as a public company but will be a wholly owned subsidiary of Santos. 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 over 2,000 square miles, with additional 3-D seismic surveys planned. A significant number of the Exploration Projects have reached the drilling stage, and the Company preliminarily budgeted approximately $26 million to fund its drilling, completion, land and seismic activities in 2002. This budget is currently being reviewed and it's anticipated it will be reduced to a total amount ranging from $15 to $20 million in the event the previously described tender offer is not closed. The budget is also likely to be modified should the currently pending tender offer for the common stock of the Company as described in the previous paragraph be closed. The Company, which utilizes the successful efforts method of accounting, entered 2002 having grown from total 1998 gas and oil revenues of approximately $1,372,000 and large operating cash flow deficits to a company with $31,942,264 in oil and gas revenues and operating cash flow (net income plus non-cash charges and exploration expenses, less gain on sale of assets) of approximately $11.7 million in 2001. 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 interests in the twenty-eight exploration projects acquired in May, 1998 were underdeveloped, and were comprised primarily of interests in unproven 3-D seismic based projects, which 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, 2001 the unamortized balance was $1,641,900. In 2001 this amortization resulted in a $3,457,000 expense. The amortization of properties acquired pursuant to the May 1998 acquisitions will conclude in May of 2002. Impairments totaled $4,514,077 for the year ended December 31, 2001. Impairments were primarily related to unproved property costs on projects that management believes have diminished value based upon 2001 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 into the second quarter of 2002, 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. As a result of the tax rules applicable to the acquisitions, the Company may 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. 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. 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 4 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 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. The Company added 19.256 billion cubic feet equivalent ("BCFE") of new gas and oil reserves from its 2000 drilling activities. 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. 5 OVERVIEW OF 2001 ACTIVITIES. The Company entered 2001 expecting to continue to expand its production and reserves via exploration activities on its technology-enhanced projects. By utilizing capital available to it from operating cash flow, financings and industry partner transactions, the Company continued to pursue an aggressive exploration budget in its major trends of activity. The Company participated in working interests in 46 wells which reached total depth and were logged in 2001. Its net production increased slightly from 6,843,547 thousand cubic feet of natural gas equivalent using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate and natural gas liquids ("Mcfe") in 2000 to 7,350,939 in 2001. Its net proven reserves as of December 31, 2001 totaled 18.3 billion cubic feet of natural gas equivalent ("Bcfe") down from 23.8 Bcfe at year-end 2000. The decrease was primarily attributable to sales of project interests which totaled 8.3 net Bcfe. The Company focused its exploratory drilling on higher risk, high potential return prospects and delineation drilling on its Runnells and Hordes Creek Fields. Success in the Runnells Field, as evidenced by the Runnells #5 and #7 wells drilled in 2001, substantially increased proven reserves during the year; however, the Company sold approximately 71% of its interest in the Runnells Field in the fourth quarter of 2001 for net proceeds of $20.3 million plus reimbursement of previously incurred cost on the Runnells #7 well attributable to the interests sold. Accordingly, the net reserve increases attributable to the delineation of the field were not reflected in year-end net reserve totals. Delineation of the Hordes Creek Field has proceeded at a limited pace. The Pierra Childrens Trust #3 well did not successfully expand the field. Further delineation drilling is expected in the Hordes Creek field in 2002. The Company continues to believe it remains positioned to expand its net proven reserves in 2002 via continued exploratory, delineation, and development drilling. It believes that the rate of expansion will likely be proportionate to the capital available to fund such activities. In the event the pending merger as set forth in the Santos agreement does not close, the Company will continue its business as historically conducted. It will also continue to look for opportunities to consolidate business activities with an industry partner such that more capital resources may be deployed to maximize the potential of it Exploration Projects. In 2001 the Company also completed an amendment of its credit facility with Deutsche Bank. As of year-end 2001, the amended facility provides for the bank to loan up to $38,500,000 in two tranches. Tranche A is in the amount of $30,000,000 with $13,500,000 established as the borrowing base and $7,689,071 outstanding at December 31, 2001. Tranche A will mature on August 13, 2002, at which time it will convert to a four year quarterly amortizing term loan. Tranche B is in the current amount of $8,500,000, of which the entire amount was outstanding at December 31, 2001. It is payable, interest only, until due on August 13, 2003, at which time the entire Tranche B balance is due. As of March 28, 2002, the Company has 19,140,667 total shares of common stock outstanding. It employs 42 full time employees, including six in its exploration and geophysical departments, six in its operations department, three in its exploitation department, and nine 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 6 companies that compete intensely for leases, the private right of ownership of onshore mineral rights enables individual exploration companies to proprietarily control the seismic data within focused core areas. The Company believes that by obtaining substantial amounts of proprietary 3-D seismic data and significant acreage positions within its core areas, it will be able to achieve a dominant position in focused portions of those areas. With such a dominant position, the Company believes it can better control the core areas' exploration opportunities and future production, and can attempt to minimize costs through economies of scale and other efficiencies inherent in its focused approach. Such cost savings and efficiencies include the ability to use the Company's proprietary data to reduce exploration risks and lower its leasehold acquisition costs by identifying and purchasing leasehold interests only in those focused areas in which the Company believes exploratory drilling is most likely to be successful. USE OF 3-D SEISMIC AND CAEX TECHNOLOGIES. The Company attempts to enhance the value of its Exploratory Projects through the use of 3-D seismic and CAEX technologies, with an emphasis on direct hydrocarbon detection technologies. These technologies create computer generated 3-dimensional displays of subsurface geological formations that enable the Company's explorationists to 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 May 1998 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 7 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 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. For example, 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 28, 2002(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 Lafite/Allen Dome............ 5,738.21 5,462.15 3,184.49 53 58.30% Gillock...................... 13,753.81 11,712.70 4,351.27 70 37.15% Blessing..................... 80.00 80.00 27.15 22 33.94% Tidehaven.................... 1,626.17 1,555.12 728.90 28 46.87% El Maton..................... 3,567.30 1,909.81 1,234.60 29 64.65% Midfield..................... 537.50 328.51 221.74 21 67.50% Markham...................... 1,513.94 1,354.01 434.04 5 32.06% Buckeye Ranch................ 2,987.07 2,813.35 1,361.99 40 48.41% Duncan Slough................ 7,976.60 6,399.76 1,630.67 25 25.48% La Rosa...................... 80.00 80.00 7.60 25 9.50% Vicksburg Area II Phase I.... 3,329.46 3,317.02 1,244.30 76 37.51% Vicksburg Area II Phase II... 1,126.63 1,126.63 752.79 66 66.82% Wolf Point................... 632.00 632.00 174.75 8 27.65% Archie....................... 489.40 489.40 88.70 14 18.12% Raymondville................. 18,544.10 18,516.95 1,003.03 62 5.42% Smith Point.................. -- -- -- 80 7.50% ------------ ------------- ------------ ---------------- Frio Sub-Total 61,982.19 55,777.41 16,446.02 624 WILCOX CORE AREA Gila Bend.................... 305.84 305.84 44.98 16 14.71% Hall Ranch................... 8,849.64 8,661.99 6,071.76 57 70.10% Hordes Creek................. 6,634.27 6,559.27 2,123.45 25 32.37% Mikeska W.................... 4,190.87 3,691.99 1,635.13 32 44.29% Verdad....................... 3,054.12 2,928.00 732.02 40 25.00% Orangedale West.............. 471.26 348.81 174.41 10 50.00%
8
ACRES LEASED OR UNDER OPTION AT SQUARE MILES OF MARCH 28, 2002(1) 3-D SEISMIC DATA PROJECT PROJECT COMPANY RELATING TO PROJECT PROJECT AREAS GROSS NET NET PROJECT AREA INTEREST(2) - ------------------------------------- ------------ ------------- ------------ ---------------- -------------- Riverdale.................... 6,114.55 6,114.55 1,156.65 40 18.92% ------------ ------------- ------------ ---------------- Wilcox Sub-Total 29,620.55 28,610.45 11,938.40 220 TEXAS HACKBERRY CORE AREA Lox B........................ 2,670.62 1,414.29 353.60 62 25.00% West Port Acres.............. 691.05 422.32 52.77 21 12.50% Stowell/Big Hill............. 1,662.27 121.88 10.16 56 8.33% Cheek........................ 8,890.02 5,672.11 679.17 48 11.97% Lovell Lake.................. 6,085.06 4,061.79 548.43 65 13.50% West Beaumont................ 328.15 328.15 25.18 23 7.67% ------------ ------------- ------------ ---------------- Texas Hackberry Sub-Total 20,327.17 12,020.54 1,669.31 275 YEGUA CORE AREA Papalote..................... 23,900.76 23,523.19 9,577.51 98 40.72% Inez......................... 199.25 199.25 55.79 10 28.00% West Inez.................... 112.92 112.91 98.80 10 87.50% Thomaston.................... 122.04 122.04 6.10 54 5.00% South Louisiana Eocene....... 5,771.13 5,490.24 1,446.90 85 26.35% Howards Creek................ 1,446.29 1,406.99 210.42 88 14.96% ------------ ------------- ------------ ---------------- Yegua Sub-Total 31,552.39 30,854.62 11,395.52 345 OTHER LOUISIANA Four Isle Dome............... 66.52 66.52 3.33 80 5.00% Starboard Lapeyrouse......... 447.15 29.88 3.12 35 10.44% ------------ ------------- ------------ ---------------- Louisiana Sub-Total 513.67 96.40 6.45 115 OTHER TEXAS East Texas Pinnacle Reef(3).. TBD TBD TBD 400 TBD ------------ ------------- ------------ ---------------- Other Texas Sub-Total TBD TBD TBD 400 TBD MISSISSIPPI Thompson Creek............... 840.15 671.83 628.16 12 93.50% Melvin....................... 305.38 201.65 32.54 64 16.14% ------------ ------------- ------------ ---------------- Mississippi Sub-Total 1,145.53 873.48 660.70 76 ------------ ------------- ------------ ---------------- TOTAL ALL PROJECTS 145,141.50 128,232.90 42,116.40 2,055 ============ ============= ============ ================
(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 9 license agreement, and to which the Company may acquire an interest pursuant to a geophysical technical services agreement with Aspect. EXPLORATION PROJECT AREA DESCRIPTION. 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. 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 16 active 3-D seismic survey areas that cover approximately 624 square miles. It plans to drill and/or participate in approximately 17 wells in the Frio Trend in 2002. 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 plans to focus on the area where it has had discoveries in 2001. WILCOX CORE AREA. In the Wilcox Trend, the Company has seven active 3-D seismic survey areas covering approximately 220 square miles. It plans to drill approximately 12 wells in the Wilcox Trend in 2002. 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 2002 and beyond so warrant. 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 survey areas covering approximately 275 square miles. It does not plan to drill in the Hackberry Trend in 2002. YEGUA CORE AREA. In the Yegua Trend, the Company currently has interests in six active 3-D seismic survey areas. The Company will own interests in an aggregate of approximately 345 square miles of 3-D seismic data in the trend in 2002. The Company expects to drill two wells in the Yegua Trend in 2002. 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 certain large oil companies have used 3-D seismic and CAEX technologies for approximately 25 years, these methods were not affordable by smaller, independent gas and oil companies until more recently, when improved data acquisition equipment and techniques and computer technology became available at reduced costs. 10 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. 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 typically 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 re-address 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 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. The hedged volumes were as follows:
QUARTER ENDED PRICE PER MMBtu 2001 (MMBtu/day) 2000 (MMBtu/day) ------------- --------------- ---------------- ---------------- March 31st $2.45 7,161 9,381 June 30th $2.45 6,880 9,031 September 30th $2.45 6,600 8,646 December 31st $2.45 6,319 8,278
In January 2001 these hedges were replaced with 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. Volumes committed to the collar structure include 4,500 11 MMBtu per day for calendar year 2003. These hedges are accounted for as cash flow hedges pursuant to SFAS No. 133. See discussion of SFAS No. 133 accounting at footnote eight of the financial statements. 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. They remained in place throughout their initial term and expired on December 31, 2001. In October 2001, the Company hedged an additional 6,500 MMBtu/day of natural gas production for calendar year 2002 at a price of $2.90 per MMBtu. These hedges remain in place in addition to the previously described collar. 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. As a result of the above-referenced transactions, the Company has total hedge and/or "collar" contracts covering total volumes as set forth below: NATURAL GAS
QUARTER ENDED 2001 (MMBtu/day) 2002 (MMBtu/day) 2003 (MMBtu/day) ------------- ---------------- ---------------- ---------------- March 31st 12,383 15,000 4,500 June 30th 12,900 14,500 4,500 September 30th 13,000 14,000 4,500 December 31st 13,000 13,500 4,500
OIL
QUARTER ENDED 2001 (Bbl/day) 2002 (Bbl/day) 2003 (Bbl/day) ------------- -------------- -------------- -------------- March 31st 175 0 0 June 30th 168 0 0 September 30th 161 0 0 December 31st 154 0 0
First quarter 2002 hedges are estimated to approximate 95% of the Company's natural gas production and none of its oil production for such quarter. Second quarter hedges are estimated to approximate 85% of the Company's natural gas production as additional developed wells come on line. 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 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. In 2001 purchasers accounting for more than 10% of the Company's total revenue were Dow Hydrocarbons & Resources/Duke Energy Transportation & Trading/Tejas Gas Operating. The Company does not believe the loss of any existing purchaser would have a material adverse effect on the Company. The Company had a credit facility with Duke Energy Financial Services, Inc. ("Duke"), pursuant to which an ongoing agreement was established which 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. 12 The Company expects that its daily production will 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 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' 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 13 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 which: - 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, - permits pipelines to file for authority to charge different maximum cost-based rates for peak and off-peak periods, - encourages, but does not mandate, auctions for pipeline capacity, - requires pipelines to implement imbalance management services, - restricts the ability of pipelines to impose penalties for imbalances, overruns and non-compliance with operational flow orders, and - 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 rate making 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. 14 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 U.S. Congress will continue. 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 may maintain 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 15 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. 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 the U.S. 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 16 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 7,700 square feet of office space in Houston, Texas, at an annual rent of $205,104. The lease expires on August 31, 2006, however the Company does have a right to terminate the lease on or after September 1, 2004 by payment of two months rent. The Company leases approximately 18,200 square feet of office space in Corpus Christi, Texas. The annual rent is $179,304 and the primary leases expire on June 30, 2003. The Company currently has more office space than it needs in Corpus Christi, and has the option to sublet a portion of its office space. EMPLOYEES The Company has 13 full-time employees in its Houston, Texas office and 29 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. 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 16,055 Mcf per day and 449 Bbls of oil per day for the year ended December 31, 2000 and 17,967 Mcf per day and 362 Bbls of oil per day for the year ended December 31, 2001. These properties combined with the proceeds of sales of interests in certain of its exploration projects have provided most of the Company's revenues to date. NATURAL GAS AND OIL RESERVES The following table summarizes the estimates of our historical net proved reserves as of December 31, 2001 and 2000, and the present values attributable to these reserves at these dates. The reserve data and present values were prepared by Ryder Scott Company L.P., independent petroleum engineering consultants.
AT DECEMBER 31 2001 2000 ---- ---- Net proved reserves: Natural gas (Mcf) 15,300,000 21,076,278 Oil and condensate (Bbls) 507,457 454,498 Total (Mcfe) 18,344,742 23,803,266 Standardized measure of discounted future net cash flows (1) $ 26,076,494 $ 161,545,400
(1) The standardized measure of discounted future net cash flows represents the present value of future net 17 revenues after income tax discounted at 10% per annum and has been calculated in accordance with SFAS No. 69, "Disclosures About Oil and Gas Producing Activities" (see Note 10 -- Supplemental Natural Gas Oil Information (Unaudited)) and, in accordance with current SEC guidelines, and does not include estimated future cash inflows from our hedging program. The standardized measure of discounted future net cash flows attributable to our reserves was prepared using prices in effect at the end of the respective periods presented, discounted at 10% per annum on a pre-tax basis. Average prices per Mcf of natural gas used in making the present value determinations as of December 31, 2001 and 2000 were $2.31 and $10.44, respectively. Average prices per Bbl of oil used in making the present value determinations as of December 31, 2001 and 2000 were $18.45 and $28.73, respectively. In accordance with applicable requirements of the Securities and Exchange Commission, we estimate our proved reserves and future net cash flows using sales prices and costs estimated to be in effect as of the date we make the reserve estimates. We hold the estimates constant throughout the life of the properties, except to the extent a contract specifically provides for escalation. Gas prices, which have fluctuated widely in recent years, affect estimated quantities of proved reserves and future net cash flows. Any estimates of natural gas and oil reserves and their values are inherently uncertain, including many factors beyond our control. The reserve data contained in this Annual Report on Form 10-KSB represent only estimates. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers, including those we use, may vary. In addition, estimates of reserves may be revised based upon actual production, results of future development and exploration activities, prevailing natural gas and oil prices, operating costs and other factors, which revision may be material. Accordingly, reserve estimates may be different from the quantities of natural gas and oil that we are ultimately able to recover and are highly dependent upon the accuracy of the underlying assumptions. Our estimated proved reserves have not been filed with or included in reports to any federal agency. DRILLING ACTIVITY From November 1, 1997 (the effective date of the Company's May 1998 acquisitions of project interests) through December 31, 1999, 53 exploratory and developmental wells were drilled for the Company's account, of which 34 were completed and 19 were dry holes. In 2000, 41 exploratory and 11 developmental wells were drilled and logged for the Company's account of which 31 were completed and 21 were dry holes. In 2001, 41 exploratory and five developmental wells were drilled and logged for the Company's account of which 26 were completed as of March 28, 2002, one of which was temporarily abandoned, and 19 were dry holes. The following table sets forth certain information regarding the actual drilling results for each of the years 2000 and 2001 as to wells drilled in each such individual year.
EXPLORATORY DEVELOPMENT WELLS(1) WELLS(1) ------------------- ------------------ GROSS NET GROSS NET ----- --- ----- --- 2000 ---- Productive ............................. 25 5.994 6 1.559 Dry..................................... 16 5.275 5 1.412 2001 ---- Productive.............................. 23 7.068 4 0.569 Dry..................................... 18 4.848 1 0.094
(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 April 9, 2002, the Company participated in the drilling of two additional exploratory wells and one additional development well, of which one had been completed, one of which was temporarily abandoned and one still in progress. 18 PRODUCTIVE WELL SUMMARY The following table sets forth certain information regarding the Company's ownership as of December 31, 2001 of productive gas and oil wells in the areas indicated.
GAS OIL ------------------- -------------------- GROSS NET GROSS NET -------- -------- -------- --------- Alabama .................................. 0 0 1 0.061 Kansas ................................... 1 0.137 0 0 Louisiana ................................ 2 0.110 1 0.187 Oklahoma.................................. 2 0.002 2 0.226 Texas..................................... 92 16.224 5 0.350 -------- -------- -------- --------- Total .................................. 97 16.473 9 0.824 ======== ======== ======== =========
VOLUMES, PRICES AND PRODUCTION COSTS The following table sets forth certain information regarding the production volumes, average prices received (net of transportation) and average production costs associated with the Company's sale of gas and oil for the periods indicated.
YEAR ENDED DECEMBER 31, ----------------------------- 2001 2000 ------------- ------------- Net Production: Oil (Bbl) ........................................... 132,165 163,892 Gas (Mcf)............................................ 6,557,949 5,860,195 Gas equivalent (Mcfe)................................ 7,350,939 6,843,547 Average sales price: Oil ($ per Bbl)...................................... $ 24.74(1) $ 32.34(1) Gas ($ per Mcf)...................................... $ 4.38(1) $ 4.12(1) Average production expenses and taxes ($ per Mcfe)...... $ 0.77 $ 0.48
(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 $22.37 per Bbl and $3.89 per Mcf for the year ended December 31, 2001. LEASEHOLD ACREAGE The following table sets forth as of December 31, 2001, 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 UNPROVEN ---------------- UNDEVELOPED -------- ---------- STATE GROSS NET GROSS NET GROSS NET ----- ------ ----- ------- ---- ------- ------- Alabama.............. 411 7 -- -- 1,877 26 Arkansas ............ -- -- -- -- 6,360 2,544 Kansas .............. 640 31 -- -- -- -- Louisiana ........... 320 80 -- -- 7,344 607 Mississippi.......... 0 0 -- -- 760 549 Oklahoma ............ 2,198 51 -- -- 12,929 3,727 Texas ...............34,951 7,108 320 36 100,670 31,283 ------ ----- ------- ---- ------- ------- Total ..........38,520 7,277 320 36 129,940 38,736 ====== ===== ======= ==== ======= =======
19 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. 20 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 was admitted to trading on the NASDAQ Small Cap Market under the symbol "FNGC". 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. There were no reported trades of the Series B Warrants subsequent to that time. The Series B Warrants expired on August 8, 2001. On September 23, 1999, the Company acquired 3DX via a 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, the Company issued 356,999 shares of new convertible preferred stock that could be redeemed at the Company'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 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 156 common shareholders of record and 2,979 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, 2001 $3.19 $2.00 September 30, 2001 4.10 2.45 June 30, 2001 5.24 3.50 March 31, 2001 5.19 3.50 December 31, 2000 $5.19 $3.13 September 30, 2000 4.75 2.47 June 30, 2000 4.13 1.63 March 31, 2000 2.75 1.56
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 the Company's operations for the twelve month periods ended December 31, 2001 and 2000 and should be read in conjunction with the consolidated financial statements and notes related thereto. Certain statements contained herein that set forth management's intentions, plans, beliefs, expectations or predictions of the future are forward-looking statements. It is important to note that actual results could differ materially from those projected in such forward-looking statements. The risks and uncertainties include 21 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 recent events, the impact of the successful efforts accounting method as it relates to the certain acquisitions, and a survey of the Company's history are as follows: RECENT EVENTS. On March 17, 2002, the Company and Santos entered into an agreement providing for Santos' acquisition of all issued and outstanding common stock of the Company by means of a tender offer at a price of US$2.84 per share in cash and a follow-on merger at the same price. Under the terms agreed, Santos initiated a formal offer on March 26, 2002. The offer must remain open through at least April 22, 2002. It is conditioned upon the receipt of at least a majority of the Company's outstanding shares. If Santos receives at least a majority of such shares, it will, subject to various typical contingencies such as the absence of any material adverse changes, close on the purchase of shares tendered and then proceed to acquire all remaining outstanding shares through a subsequent merger, the timing of which would be announced at a later date. Shareholders who do not participate in the tender offer would also receive $2.84 per share in cash in the merger. At a meeting held on Saturday, March 16, 2002, the Company's Board of Directors voted to accept and support the Santos tender offer and voted to recommend that the Company's shareholders accept the cash tender offer and approve the merger. In addition, as a condition to the offer, two major shareholders and the chairman of the Board of Directors agreed to tender all of the shares owned by them (representing 9,991,662 shares or 52% of the Company's total outstanding shares) in the Santos tender offer and have granted Santos the option to acquire all of their shares if the tender offer is not consummated for certain reasons. In voting to accept and support the Santos tender offer, the Company's Board of Directors considered a number of factors. The Company has historically been forced to constrain capital spending and to sell larger than desired interests in its exploration projects and prospects in order to fund its capital program, which has resulted in lower than expected reserve growth. As part of the Company's evaluation of strategic alternatives, a process, initially undertaken in late 2000, the Board of Directors recognized that its inability to access sufficient capital at an acceptable cost would be an ongoing impediment to the Company's ability to fully exploit its sizable asset base. The Company and it financial advisors do not anticipate a meaningful improvement in the access to affordable capital in the foreseeable future, and as a result it will be difficult to maximize the substantial reserve potential that the Company believes exists in its prospect inventory. With this in mind, and after revisiting strategic alternatives and potential transactions available to the Company in the current marketplace, the Board of Directors recommended that the Company's shareholders accept the Santos offer. In the event the tender offer and merger are closed, the Company will not continue as a public company, but will be a wholly owned subsidiary of Santos. The Company has also recently announced that its Poole #2 well has been temporarily abandoned due to mechanical difficulties. The well, drilled on a high potential feature, encountered several mud log shows and high-pressure gas during drilling. The Company is encouraged by such indicators and anticipates re-drilling the well. CRITICAL ACCOUNTING POLICIES INTRODUCTION. The following describes the critical accounting policies used by the Company in reporting its financial condition and results of operations. In some cases, accounting standards allow more than one alternative accounting method for reporting, such is the case with accounting for oil and gas activities described below. In those cases, the Company's reported results of operations would be different should it employ an alternative accounting method. SUCCESSFUL EFFORTS METHOD OF ACCOUNTING FOR OIL AND GAS ACTIVITIES. The Securities and Exchange Commission ("SEC") prescribes in Regulation SX the financial accounting and reporting standards for companies engaged in oil and gas producing activities. Two methods are prescribed: the successful efforts method and the full 22 cost method. Like many other oil and gas companies, the Company has chosen to follow the successful efforts method. Management believes that this method is preferable, as the Company has focused on exploration activities wherein there are risks associated with future success, and as such earnings are best represented by attachment to the drilling operations of the company. Costs of successful wells, development dry holes and leases containing productive reserves are capitalized and amortized on a unit-of-production basis over the life of the related reserves. Estimated future abandonment and site restoration costs, net of anticipated salvage values, are amortized on a unit of production basis over the life of the related reserves. Other exploration costs, including geological and geophysical expenses applicable to undeveloped leasehold, 3-D seismic data, leasehold expiration costs and delay rentals are expensed as incurred. In accordance with accounting under successful efforts, the Company reviews proved oil and gas properties for indications of impairment whenever events or circumstances indicate that the carrying value of its oil and gas properties may not be recoverable. When it is determined that an oil and gas property's estimated future net cash flows will not be sufficient to recover its carrying amount, an impairment charge must be recorded to reduce the carrying amount of the asset to its estimated fair value. For the years ended December 31, 2001 and 2000, impairments of $4,514,077 and $4,771,272, respectively, were recognized. UNPROVED PROPERTY. Unproved properties, representing unproven leasehold costs that are not being amortized pending evaluation of the respective leasehold for future development, are assessed quarterly for impairment in value, with any impairment charged to expense. In addition, interests in twenty-eight exploration projects acquired in May 1998 were underdeveloped and were comprised primarily of interests in unproven 3-D seismic based projects, which 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, 2001, the unamortized balance was $1,641,900. In 2001 this amortization resulted in a $3,457,000 expense. The amortization of properties acquired pursuant to the May 1998 acquisitions will conclude in May of 2002. Impairments totaled $4,514,077 for the year-ended December 31, 2001. Impairments were primarily related to unproved property costs on projects which management believes have diminished value based upon 2001 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 into the second quarter of 2002; 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. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES. In June 1998, Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities" was issued. The Company adopted SFAS No. 133, as amended, effective January 1, 2001. SFAS No. 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 be reported in other comprehensive income ("OCI") to the extent the derivative is effective as a hedge. 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 No. 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. 23 RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS. On June 29, 2001, SFAS No. 141, "Business Combinations" was approved by the Financial Accounting Standards Board. SFAS No. 141 requires that the purchase method of accounting be used or all business combinations initiated after June 30, 2001. The Company was required to implement SFAS No. 141 on July 1, 2001. The adoption of this statement had no effect on the Company's consolidated financial position, cash flows or results of operations. On June 29, 2001, SFAS No. 142, "Goodwill and Other Intangible Assets", was approved by the Financial Accounting Standards Board ("FASB"). SFAS No. 142 changes the accounting for goodwill from an amortization method to an impairment-only approach. Amortization of goodwill, including goodwill recorded in past business combinations, will cease upon adoption of this statement. The Company was required to implement SFAS No. 142 on January 1, 2002. Management has reviewed SFAS No. 142 and determined that this statement will not have a material effect on its consolidated financial position, cash flows or results of operation. In June 2001 the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 provides the accounting requirements for retirement obligations associated with tangible long-lived assets. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002, and early adoption is permitted. The Company is currently assessing the new standard and has not yet determined the impact on its consolidated financial position, cash flows or results of operations. In August 2001 the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." The new rules supersede SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." The new rules retain many of the fundamental recognition and measurement provisions, but significantly change the criteria for classifying an asset as held-for-sale. SFAS No. 144 is effective for fiscal years beginning after December 15, 2001. The Company is currently assessing the new standard and has not yet determined the impact on its consolidated financial position, cash flows or results of operations. NET OPERATING LOSS CARRY-FORWARDS. As a result of the tax rules applicable to the acquisitions made in May of 1998, the Company may 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. 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. 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. 24 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 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 the Company's common stock for 3.25 shares of 3DX common stock; or (ii) the issuance of a new Company convertible preferred stock at a ratio of one share of the Company's 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 the Company's common stock and approximately 9% were converted into the Company's convertible preferred stock. As a result, the Company 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 the Company'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. The Company added 19.256 billion cubic feet equivalent ("BCFE") of new gas and oil reserves from its 2000 drilling activities. 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. OVERVIEW OF 2001 ACTIVITIES. The Company entered 2001 expecting to continue to expand its production and reserves via exploration activities on its technology-enhanced projects. By utilizing capital available to it from operating cash flow, financing and industry partner transactions, the Company continued to pursue an aggressive exploration budget in its major trends of activity. 25 The Company participated in working interests in 45 wells which reached total depth and were logged in 2001. Its net production increased slightly from 6,843,547 net Mcfe in 2000 to 7,350,939 in 2001. Its net proven reserves as of December 31, 2001, totaled 18.3 Bcfe down from 23.8 Bcfe at year-end 2000. The decrease was primarily attributable to sales of project interests which totaled 8.3 net Bcfe. The Company focused its exploratory drilling on higher risk, high potential return prospects and delineation drilling on its Runnells and Hordes Creek Fields. Success in the Runnells Field, as evidenced by the Runnells #5 and #7 wells drilled in 2001, substantially increased proven reserves during the year; however, the Company sold approximately 71% of its interest in the Runnells Field in the fourth quarter of 2001 for net proceeds of $20.3 million plus reimbursement of previously incurred cost on the Runnells #7 well attributable to the interests sold. Accordingly, the net reserve increases attributable to the delineation of the field were not reflected in year-end net reserve totals. Delineation of the Hordes Creek Field has proceeded at a limited pace. The Pierra Childrens Trust #3 well did not successfully expand the field. Further delineation drilling is expected in the Hordes Creek Field in 2002. The Company continues to believe it remains positioned to expand its net proven reserves in 2002 via continued exploratory, delineation, and development drilling. It believes that the rate of expansion will likely be proportionate to the capital available to fund such activities. In the event the pending merger as set forth in the Santos agreement does not close, the Company will continue its business as historically conducted. It will also continue to look for opportunities to consolidate business activities with an industry partner such that more capital resources may be deployed to maximize the potential of its Exploration Projects. In 2001 the Company also completed an amendment of its credit facility with Deutsche Bank. As of year-end 2001, the amended facility provides for the bank to loan up to $38,500,000 in two tranches. Tranche A is in the amount of $30,000,000 with $13,500,000 established as the borrowing base and $7,689,071 outstanding at December 31, 2001. Tranche A will mature on August 13, 2002, at which time it will convert to a four year quarterly amortizing term loan. Tranche B is in the current amount of $8,500,000, of which the entire amount was outstanding at December 31, 2001. It is payable interest only until due on August 13, 2003, at which time the entire Tranche B balance is due. As of March 28, 2002, the Company has 19,140,667 total shares of common stock outstanding. It employs 42 full time employees, including six in its exploration and geophysical departments, six in its operations department, three in its exploitation department, and nine in its land department. Its focus continues to be the implementation of its business strategy as set forth in this section. COMPARISON OF 2001 TO 2000 VOLUMES, PRICES AND PRODUCTION COSTS. The following table sets forth certain information regarding the production volumes, average prices received (net of transportation) and average production costs associated with the Company's sale of gas and oil for the periods indicated.
YEAR ENDED DECEMBER 31, ---------------------------------- 2001 2000 ----------------- -------------- Net Production: Oil (Bbl) .................................... 132,165 163,892 Gas (Mcf) .................................... 6,557,949 5,860,195 Gas equivalent (Mcfe) ........................ 7,350,939 6,843,547 Average sales price: Oil ($ per Bbl)............................... $ 24.74(1) $ 32.34(1) Gas ($ per Mcf) .............................. $ 4.38(1) $ 4.12(1) Average production expenses and taxes ($ per Mcfe)..... $ 0.77 $ 0.48
26 (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 $22.37 per Bbl and $3.89 per Mcf for the year ended December 31, 2001. REVENUES. Total revenues increased 20% from $34,674,753 for the year ended December 31, 2000 to $41,661,926 for the year ended December 31, 2001. The primary reason for the increase was an increase in gain on sale of assets from $9,329,631 in 2000 to $16,227,756 in 2001. Gas and oil revenues increased in the period from $29,446,832 in 2000 to $31,942,264 in 2001. The overall change was the result of all of the factors listed and discussed below. GAS AND OIL REVENUES. Total gas and oil revenues increased 8% from $29,446,832 reported in 2000 to $31,942,264 in 2001. The increase in gas and oil revenue was attributed mainly to increases in quantities of natural gas produced net to the Company's account combined with increases in the prices for which said production was sold, partially offset by a reduction in oil production and differences in prices. Volumes increased 7% from 6,843,547 MCFE produced in 2000 to 7,350,939 MCFE in 2001. The average price received per barrel of oil sold decreased from $32.34 in 2000 to $24.74 in 2001. The average price received per MCF of natural gas sold increased from $4.12 in 2000 to $4.38 in 2001. GAIN ON SALE OF ASSETS. There was an increase of 74% in gain on sale of assets of $6,898,125 from $9,329,631 reported in 2000 to $16,227,756 in 2001. This was primarily attributable to the 2001 fourth quarter gain on the sale of a portion of the Company's interest in the Runnells Field to an industry partner of approximately $15,600,000. The gain on sale of assets in 2000 of $9,329,631 was attributable to sales of interests to industry partners in certain of Company's projects. The largest components of the total in 2000 were a $6,607,211 gain on the sale of interests in the Company's 3-D seismic Raymondville Project and a gain of $1,797,707 recognized in conjunction with a sales transaction with an interest in a 3-D seismic project overlying the Company's Papalote Project area. OPERATING FEES. Operating fees increased due to increases in the number of both exploratory and developmental wells operated, which has resulted in the increase of operating fees of 59% from $454,016 for the year ended 2000 to $722,388 for the year ended 2001. REALIZED LOSS ON COMMODITY TRANSACTIONS. The Company reduced by 26% its realized losses from various commodity hedges by $1,258,249 to a realized loss of $3,584,123 for the year ending 2001 as compared to a realized loss of $4,842,372 for the same period in 2000. The gains or losses realized are primarily attributable to various transactions in which the Company hedged future gas and oil delivery obligations. The losses realized during 2000 and 2001 were incurred as average spot market prices for the period exceeded the average hedge prices. UNREALIZED LOSS FROM HEDGING ACTIVITIES. The non-cash loss from hedging activities is incurred as a result of the implementation of SFAS 133 on January 1, 2001. There was no comparable entry in 2000. The non-cash loss of $3,838,344 in 2001 resulted primarily from the required accounting treatment applicable to the restructuring of a natural gas hedge at $2.45 per MMBtu on January 25, 2001. The restructured portion of the hedge covered 5,000 MMBtu per day of natural gas from February 2001 through December 2001. The $2.45 per MMBtu hedge was restructured as a collar with a $3.25 put or floor and a $4.00 call or cap on volumes ranging from 7,500 to 8,000 MMBtu per day in 2001, 7,000 to 8,500 MMBtu per day in 2002 and volumes of 4,500 MMBtu per day in 2003. The result served to increase actual cash available in 2001. SFAS No. 133 treatment requires the amortization of non-cash charges equal to the mark-to-market value of the hedge as it existed before the restructure. In this case, a non-cash loss will be recognized over the life of the hedge before it was restructured. This procedure resulted in a non-cash loss of $6,818,598 in 2001. Non-cash credits to income will be recognized over the life of the collar as restructured, which is in the period February 2001 through December 2003. For the year ended December 31, 2001, the unrealized gain on the collar was $2,980,254. OTHER REVENUES. The Company had other revenues of $191,985 for the year 2001 as compared with $286,646 for the year of 2000. This decrease was primarily due to normal variances of various nominal accounts. COSTS AND EXPENSES. Total costs and expenses decreased 3% from $43,335,391 in 2000 to $41,827,742 in 2001. The most significant changes relate to various facets of increased production volumes and variances in exploration 27 activity. Increased production volumes resulted in increases in lease operating expense and depletion as more fully described below. Exploration activities resulted in decreases 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 2001. Other changes in costs and expenses are described below. AMORTIZATION OF UNPROVED PROPERTIES decreased 33% to $3,457,000 in 2001 from $5,176,100 for 2000. The Company is amortizing the undeveloped and unevaluated value of the properties acquired pursuant to an acquisition of underdeveloped projects in May of 1998 over a period not to exceed forty-eight months. The 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 2001 is the result of the reductions in the size of the amortization pool in 2001 as compared to 2000. As of December 31, 2001, a $1,641,900 balance remained in this amortization pool. (Also see Overview - Successful Efforts Accounting and Related Matters.) IMPAIRMENT OF GAS AND OIL PROPERTIES was $4,514,077 in 2001 compared to $4,771,272 in 2000. 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. Impairment decreases of 5% in 2001 were primarily the result of third quarter impairments recognized on several project areas as a result of recent evolving understandings of the project areas. Included in these impairments were charges in the Lovell Lake, S. Louisiana Eocene, Cheek, Gillock, Powderhorn South Field Trend and Hackberry Trend projects. EXPLORATION COSTS - GEOLOGICAL AND GEOPHYSICAL decreased 97% from $4,613,603 for 2000 to $148,469 for 2001. These exploration costs reflect 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 has required the acquisition and interpretations 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. Differences between 2000 and 2001 costs are primarily attributable to the Company's focus on exploitation of its existing 3-D data in 2001. EXPLORATION COSTS - DRY HOLE was $6,307,129 for 2001 compared to $7,114,950 for 2000. This 11% decrease is attributable to drilling fewer dry holes. The change reflects normal variance of such costs. GENERAL AND ADMINISTRATIVE EXPENSES increased 26% from $7,187,619 for 2000 as compared to $9,031,273 for 2001. The cost increases were primarily attributable to the Company's active drilling program. This was also the result of systems implementation costs and of additional personnel and personnel upgrades. Management believes the upgrades can lead to better reporting and greater efficiency and can lead to reductions in general and administrative cost in 2002. Additionally, the estimated cost of a company wide bonus to be paid in 2002 of approximately $750,000 was accrued in 2001, whereas no bonus was accrued in 2000. DEPLETION, DEPRECIATION AND AMORTIZATION ("DD&A") increased 5% from $9,635,671 for 2000 to $10,136,584 in 2001. 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 2001. Downward reserve revisions in late 2001 regarding the Company's Hackberry production increased the unit costs of depletion in the Hackberry in 2001. (Also see Overview - Overview of 2001 Activities.) INTEREST EXPENSE increased 61% from $1,361,533 for 2000 to $2,185,777 for 2001. 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 portion of its interest associated with ongoing projects, of which capitalized amounts totaled $219,197 and $288,584 for the respective years ending 2000 and 2001. 28 PRODUCTION TAXES decreased 5% from $2,107,093 for 2000 to $1,999,759 for 2001. The decrease in production taxes was the result of further refinement of the company's ongoing analysis of production activity as it relates to severance taxes and to rebates paid by the state of Texas which were credited to 2001 production taxes. LEASE OPERATING EXPENSE increased 211% from $1,172,590 for 2000 to $3,649,199 for 2001. The increase in lease operating expenses relates primarily to an increase in the number of producing wells, salt water disposal fees and processing fees. PROVISIONS FOR INCOME TAX. In 2001 the Company incurred Alternative Minimum Federal Income Taxes totaling $291,418 which resulted from a partial sale of interest in the Runnells Field to an industry partner in the fourth quarter of 2001. There were no events in 2000 that triggered Alternative Minimum Taxes. 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 2001. NET LOSS PER COMMON SHARE decreased from a net loss of $0.40 per share for 2000 to $0.02 per share for 2001. Due to the factors discussed above, there was a $7,077,370 decrease in net loss applicable to common stockholders for the twelve months ended December 31, 2001. The increase of weighted average number of common equivalent shares at December 31, 2001 of approximately 172,000 shares as compared to 2000 also affected the per share calculations. Approximately 19,049,454 weighted average common equivalent shares were outstanding at December 31, 2001 as compared with approximately 18,877,192 at December 31, 2000. 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 its exploration projects. Management continues to believe these projects represent some of the most promising prospects in the Company's history. Production from wells drilled from 1998 through the present on its Exploration Projects has substantially increased the Company's revenues. Net growth of production in 2001 was less than expected. Net proven gas and oil reserves at year-end 2001 declined as compared with year-end 2000. This was due to sales of proven reserves pursuant to sales to industry partners during 2001, slower then anticipated delineation drilling on proven fields, and the absence of a major discovery in 2001. These factors have also resulted in reduced production in the first quarter of 2002 as compared to the first quarter of 2001. Net production is expected to increase in the second quarter of 2002 as new wells come on line. The Company believes that continued exploratory and delineation drilling on its exploration projects will yield a resumption of the growth trends in both net production and net gas and oil reserves evidenced in 1998, 1999, and 2000. Conversely, the capital expenditures planned in 2002 will continue to require substantial outlays of capital to explore, develop and produce. The Company cannot fund its planned capital budget from operating cash flow and will continue to seek supplemental sources from industry partners, mezzanine debt, or other sources. The total 2002 capital budget is being reviewed and will likely be reduced to a range of from $15 million to $20 million. Closing of the pending tender offer of Santos and the subsequent merger could cause the Company to become a wholly owned subsidiary of Santos in the second quarter of 2002. LIQUIDITY AND CAPITAL RESOURCES The Company business plan provides for substantial investment in drilling, completion, land and seismic. The budgeted amounts are based upon exploration opportunities and are periodically adjusted based upon available capital, new opportunities and industry conditions. The 2002 budget was initially anticipated to approach $26 million, about 20% of which was for new seismic data and investment in new projects. This is currently being reviewed and is anticipated to be reduced to a total of $15 million to $20 million. Investment in planned new seismic will be the area most effected as such plans will likely be deferred until 2003. The Company's sources of financing its capital budget, include borrowing capacity under its credit facilities, the sale of promoted interests in the Exploration Projects to industry partners and cash provided from operations. 29 The Company entered 2002 having grown from $1,372,000 in total 1998 gas and oil production revenues and operating cash flow deficits to a company with over $31,900,000 in gas and oil revenues and $11,700,000 in operating cash flow (net income less gain on sale of assets plus non-cash expenses, as calculated before capital expenditures for drilling and completion and new 3-D seismic data acquisition costs) in 2001. Due to the sales of interests in the Runnells Field in the fourth quarter of 2001, first quarter 2002 net production volumes are less than first quarter 2001. Additional drilling success in 2002 could allow the Company to resume the trend of increasing production. This would allow the Company to achieve 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. Lack of drilling success in the first half of 2002 would increase the Company's dependence on external sources of funds to supplement its capital budget in the second half of 2002. The Company ended 2001 with a deficit working capital of approximately $4.4 million. Of this amount approximately $0.5 million was represented by the current portion of its long-term debt. The Company's borrowing base pursuant to Tranche A was set at $13,500,000 in the fourth quarter of 2001. Pursuant to the total Deutsche Bank credit facility, $22 million is now available of which $16,189,071 had been drawn as of December 31, 2001. It is currently comprised of two tranches; $13.5 million is currently available under Tranche A of which $7,689,071 had been drawn as of December 31, 2001 and $8.5 million under Tranche B of which the entire amount had been drawn as of December 31, 2001. Tranche A is a revolving facility with no required principal payments until 2002, at which time it converts into a four-year term loan. The term loan would be amortized in quarterly payments beginning the fourth quarter of 2002. Tranche B is payable interest only until due on August 13, 2002, at which time the entire balance is due. Both loans are at a varied interest rate utilizing either Deutsche Bank's alternative interest rate or the London interbank rate plus 2% for Tranche A and plus 6% for Tranche B. As of March 28, 2002, $10.2 million was drawn under Tranche A and $8.5 million under Tranche B. All undrawn funds will be available to supplement working capital or 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. There also is 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 August 13, 2003, 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, and on August 13, 2001 a five year warrant to purchase an additional 125,000 shares of the Company's common stock for $3.00 per share. The Company expects further increases in the Tranche A borrowing base in the event its proven oil and gas reserves grow. This 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 2002. There is, however, no assurance said proven oil and gas reserve will grow. In the event reserves decline in the first half of 2002 the borrowing base could be reduced which will reduce capital available for exploration activities. Pursuant to the Company's credit agreement with Deutsche Bank, it has certain covenants regarding current interest coverage ratios and other covenants and restrictions 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 and restrictions in the year 2002, 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. Restrictions include limitations on additional borrowing, sales of significant properties and payment 30 of dividends. 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 2002, 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 2002. Second quarter hedges are estimated to approximate 85% of the Company's natural gas productions as additional developed wells come on line. Cash on hand, cash available pursuant to the Deutsche Bank credit facility, and cash flow from operations will contribute significantly to satisfaction of budget requirements for 2002. These funds will have to be supplemented by the sale of project interests to industry partners or by other sources of capital for the Company to fully fund said budget. The Company expects to fund a substantial portion of its 2002 capital budget from its cash flow from operations. It projects meaningful increases in net daily production in the second half of 2002 attributable to projected drilling activity currently being conducted and planned throughout the remainder of 2002. 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 reduced. 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. In the event the pending Santos tender offer and follow on merger do not close, the Company will continue 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. The Company will also consider potential mergers or other business and asset consolidation opportunities. 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 through December 2002 natural gas production of 6,500 MMBtu/day at $2.90/MMBtu. It also had a natural gas collar in place covering 8,500 MMBtu/day of first quarter 2002 natural gas production and 8,000, 7,500, and 7,000 MMBtu/day of second, third, and fourth quarter production respectively. The collar was comprised of a $3.25 put or floor and a $4.00 call or cap. The natural gas collar also covers 4,500 MMBtu/day of calendar year 2003 natural gas production. The company has no oil volumes hedged. 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 2002 hedges are estimated to approximate 95% of the Company's natural gas and none of its oil production for such quarter. Future percentages will vary. WORKING CAPITAL. At December 31, 2001, the Company had a cash balance of $940,919, total current assets of $14,867,774, and total current liabilities of $19,230,366. This resulted in a working capital deficit of $4,362,592. Were the current portion of long-term debt due to Deutsche Bank AG not included in current liabilities, the working capital deficit would have been $3,882,025. The current portion of long term debt at December 31, 2001 was comprised of $480,567 of Tranche A debt due to Deutsche Bank in the fourth quarter of 2002. The Company had $5,810,929 of available undrawn credit from Deutsche Bank at December 31, 2001. Had said amounts been fully drawn the Company would have had a small working capital surplus. The Company expects that in the second half of 2002 it will resume its trend of increasing gas and oil revenues and 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 31 net working capital will be negatively effected by the Company's continuing aggressive capital expenditures program on its Exploration Projects. It could also be negatively effected by any 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 intends to aggressively pursue its exploration activity on its technology-enhanced projects. 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 growth in its proven natural gas and oil reserves in 2002. The Company expects to fund significant portions of its year 2002 exploration budget from operating cash flow (prior to capital expenditures and new 3-D seismic data acquisition costs). 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 project interests to industry partners, as it seeks to maximize its interests and manage its risks while aggressively pursuing its exploration projects. The Company recognizes that it will be difficult to internally generate the total capital desired to maximize the exploration and development opportunities inherent in its expansive inventory of Exploration Projects. Accordingly if the pending Santos tender offer and follow on merger does not proceed to closing, the Company will work to seek out acquisition, merger an other asset consolidation opportunities which may lead to a larger capital structure and greater administrative economies of scale. 32 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, 2001 and 2000, and the related consolidated statements of operations, stockholders' equity and comprehensive income 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, 2001 and 2000, 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. As described in Note 1 to the consolidated financial statements, the Company changed its method of accounting for derivative and hedging instruments in accordance with Statement of Financial Accounting Standards No. 133 "Accounting for Derivative and Hedging Instruments". Deloitte & Touche LLP Houston, Texas April 12, 2002 33 ESENJAY EXPLORATION, INC. CONSOLIDATED BALANCE SHEETS ASSETS
DECEMBER 31, DECEMBER 31, 2001 2000 --------------- --------------- Current assets: Cash and cash equivalents................................... $ 940,919 $ 3,002,700 Accounts receivable, net of allowance for doubtful accounts of $482,541 at December 31, 2001 and $445,872 December 31, 2000............................... 8,144,276 8,124,026 Accounts receivable oil and gas sales....................... 1,665,570 6,135,807 Receivables from affiliates................................. 360,182 124,268 Inventory................................................... 911,445 -- Prepaid expenses and other.................................. 1,529,867 2,183,093 Current portion of derivative assets........................ 1,315,515 -- --------------- --------------- Total current assets............................... 14,867,774 19,569,894 Property and equipment, successful efforts method of accounting............................................... 97,871,396 81,977,022 Less: accumulated depletion, depreciation, amortization and impairments............................... (49,329,061) (40,087,050) -------------- --------------- Total property and equipment, net.................. 48,542,335 41,889,972 Long-term derivative assets..................................... 1,013,352 -- Other assets .................................................. 1,167,911 903,208 --------------- --------------- Total assets....................................... $ 65,591,372 $ 62,363,074 =============== ===============
The accompanying notes are an integral part of these financial statements. 34 ESENJAY EXPLORATION, INC. CONSOLIDATED BALANCE SHEETS LIABILITIES AND STOCKHOLDERS' EQUITY
DECEMBER 31, DECEMBER 31, 2001 2000 --------------- --------------- Current liabilities: Accounts payable............................................ $ 10,757,508 $ 6,450,723 Accounts payable to affiliate............................... --- 269,835 Revenue distribution payable................................ 3,718,126 6,101,354 Current portion of long-term debt........................... 480,567 6,750,000 Accrued, deferred and other liabilities..................... 3,865,503 4,687,855 Current portion of derivative liabilities................... 408,662 --- --------------- --------------- Total current liabilities.......................... 19,230,366 24,259,767 Long-term debt ................................................. 15,708,504 13,591,782 --------------- --------------- Total liabilities ................................. 34,938,870 37,851,549 Stockholders' equity: Common stock: Class A common stock, $.01 par value; 40,000,000 shares authorized; and 19,108,345 and 18,958,477 outstanding at December 31, 2001 and December 31, 2000, respectively............................................. 191,083 189,585 Additional paid-in capital ................................. 85,446,449 84,699,705 Stock subscription receivable............................... (14,640) (106,060) Accumulated other comprehensive income...................... 5,758,549 --- Accumulated deficit......................................... (60,728,939) (60,271,705) --------------- --------------- Total stockholders' equity......................... 30,652,502 24,511,525 --------------- --------------- Total liabilities and stockholders' equity......... $ 65,591,372 $ 62,363,074 =============== ===============
The accompanying notes are an integral part of these financial statements. 35 ESENJAY EXPLORATION, INC. CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31, ---------------------------------- 2001 2000 --------------- ---------------- Revenues: Gas and oil revenues........................................... $ 31,942,264 $ 29,446,832 Realized loss on commodity transactions........................ (3,584,123) (4,842,372) Unrealized loss from hedging activities........................ (3,838,344) -- Gain on sale of assets......................................... 16,227,756 9,329,631 Operating fees................................................. 722,388 454,016 Other revenues................................................. 191,985 286,646 --------------- ---------------- Total revenues........................................ 41,661,926 34,674,753 --------------- ---------------- Costs and expenses: Lease operating expense........................................ 3,649,199 1,172,590 Production taxes............................................... 1,999,759 2,107,093 Depletion, depreciation and amortization....................... 10,136,584 9,635,671 Amortization of unproved properties............................ 3,457,000 5,176,100 Impairment of oil and gas properties........................... 4,514,077 4,771,272 Exploration costs-geological and geophysical................... 148,469 4,613,603 Exploration costs-dry hole..................................... 6,307,129 7,114,950 Interest expense............................................... 2,185,777 1,361,533 Other expenses................................................. 398,475 194,960 General and administrative..................................... 9,031,273 7,187,619 --------------- ---------------- Total costs and expenses.............................. 41,827,742 43,335,391 Loss before provision for income taxes and extraordinary gain...... (165,816) (8,660,638) Benefit (provision) for income taxes............................... (291,418) -- --------------- ---------------- Net loss before extraordinary gain................................ (457,234) (8,660,638) Extraordinary gain................................................. -- 1,126,034 --------------- ---------------- Net loss attributable to common stockholders....................... $ (457,234) $ (7,534,604) =============== ================ Net loss per share of common stock: Basic and diluted: Net loss before extraordinary gain attributable to common stockholders................................. $ (0.02) $ (0.46) Extraordinary gain.......................................... 0.06 --------------- ---------------- Net loss attributable to common shareholders........................................... $ (0.02) $ (0.40) =============== ================ Weighted average number of common shares outstanding............... 19,049,454 18,877,192 =============== ================
The accompanying notes are an integral part of these financial statements. 36 ESENJAY EXPLORATION, INC. CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME
Preferred Class A Additional Stock Common Shares Paid-in Stock Accumulated -------------------- ------------------------ Capital Subscription Deficit Shares Amount Shares Amount Receivable -------- --------- ----------- ---------- ------------ ------------ ------------ Balance, January 1, 2000........... 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 subscription.... -- -- 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) ======== ========= =========== ========== ============ ============ ============ Issuance of warrants...... -- -- -- -- 150,700 -- -- Issuance of common stock................... -- -- 149,868 1,498 596,044 -- -- Payment of stock subscription receivable.............. -- -- -- -- -- 91,420 -- Issuance of common stock through subscriptions... -- -- -- -- -- -- -- Net loss.................. -- -- -- -- -- -- $ (457,234) Cumulative effect of change in accounting principle............... -- -- -- -- -- -- -- Change in fair value of derivative hedging instruments............. -- -- -- -- -- -- -- Hedge settlements re-classified to income. -- -- -- -- -- -- -- Total comprehensive income.................. -- -- -- -- -- -- -- -------- --------- ----------- ---------- ------------ ------------ ------------ Balance, December 31, 2001....... -- -- 19,108,345 $ 191,083 $ 85,446,449 $ (14,640) $(60,728,939) ======== ========= =========== ========== ============ ============ ============ Accumulated Other Total Comprehensive Stockholders' Income Equity ------------- ------------- Balance, January 1, 2000........... -- $ 32,332,750 Issuance of warrants...... -- 110,000 Redemption of preferred stock................... -- (687,225) Issuance of common stock................... -- 217,404 Payment of stock subscription receivable.............. -- 73,200 Issuance of common stock through subscription.... -- -- Net loss................. -- (7,534,604) ------------- ------------- Balance, December 31, 2000....... -- $ 24,511,525 ============= ============= Issuance of warrants...... -- 150,700 Issuance of common stock................... -- 597,542 Payment of stock subscription receivable.............. -- 91,420 Issuance of common stock through subscriptions... -- -- Net loss.................. -- (457,234) Cumulative effect of change in accounting principle............... (14,909,492) -- Change in fair value of derivative hedging instruments............. 24,506,385 -- Hedge settlements re-classified to income. (3,838,344) -- Total comprehensive income.................. -- 5,301,315 ------------- ------------- Balance, December 31, 2001....... $ 5,758,549 $ 30,195,268 ============= =============
The accompanying notes are an integral part of these financial statements. 37 ESENJAY EXPLORATION, INC CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31, -------------------------------- 2001 2000 ------------- ------------ Cash flows from operating activities: Net loss $ (457,234) $ (7,534,604) Adjustments to reconcile net loss to net cash provided by (used in) operating activities: Depletion, depreciation and amortization ..................... 10,136,584 9,635,671 Amortization of unproven property............................. 3,457,000 5,176,100 Impairment of oil and gas properties.......................... 4,514,077 4,771,272 Exploration costs - dry hole.................................. 6,307,129 7,114,950 Unrealized loss from hedging activities....................... 3,838,344 -- Gain on sale of assets........................................ (16,227,756) (9,329,631) Extraordinary gain............................................ -- (1,126,034) Changes in operating assets and liabilities: Trade and affiliate receivables............................... 4,214,072 (6,942,964) Prepaid expenses.............................................. 653,226 1,757,040 Other assets.................................................. (439,684) (136,568) Inventory..................................................... (911,445) -- Trade and affiliate payables.................................. 4,036,950 (4,201,984) Revenue distribution payable.................................. (2,383,228) 3,609,556 Accrued, deferred and other liabilities....................... (822,352) (1,407,333) ------------- ------------ Net cash provided by operating activities..................... 15,915,683 1,385,471 ------------- ------------ Cash flows from investing activities: Capital expenditures - gas and oil properties...................... (36,061,944) (19,254,789) Capital expenditures - other property and equipment................ (533,344) (183,013) Proceeds from sale of assets....................................... 21,930,873 14,362,776 ------------- ------------ Net cash used in investing activities........................... (14,664,415) (5,075,026) ------------- ------------ Cash flows from financing activities: Proceeds from issuance of debt..................................... 18,908,217 20,341,782 Repayments of long-term debt....................................... (23,060,928) (15,964,523) Preferred stock redeemed........................................... -- (683,655) Proceeds from issuance of warrants................................. 150,700 110,000 Net proceeds from issuance of common stock......................... 471,421 217,404 Proceeds from exercise of stock options............................ 126,121 -- Payment of stock subscriptions receivables......................... 91,420 73,200 ------------- ------------ Net cash (used in) provided by financing activities............. (3,313,049) 4,094,208 ------------- ------------ Net change in cash and cash equivalents............................ (2,061,781) 404,653 Cash and cash equivalents at beginning of year........................ 3,002,700 2,598,047 ------------- ------------ Cash and cash equivalents at end of year.............................. $ 940,919 $ 3,002,700 ============= ============ Supplemental disclosure of cash flow information: Cash paid for interest............................................. $ 1,942,274 $ 1,372,124 Supplemental disclosure of non cash investing and and financing activities: Issuance of common stock for 401(k) matching, bonuses and stock subscriptions...................................................... $ 132,354 $ 69,460
38 The accompanying notes are an integral part of these financial statements. 39 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 and are depleted by the unit of production method based upon estimated proved reserves. 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. On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion, amortization and impairment are eliminated from the property accounts, and the resultant gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion, amortization and impairment with a resulting gain or loss recognized in income. On the sale of an entire interest in an unproved property for cash or cash equivalent, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained. 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 $4,514,077 and $4,771,272 of impairment charges during 2001 and 2000, 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, is being amortized on a straight-line basis over a period not to exceed forty-eight months. Such amortization was $3,457,000 and $5,176,100 for the years ended December 31, 2001 and 2000, respectively. The balance in this amortizing group of unproven properties was $1,641,900 and $5,334,700 at December 31, 2001 and 2000, respectively. 40 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 carry-forwards, and tax credit carry-forwards. COMMODITY TRANSACTIONS - The Company attempts to minimize the price risk of a portion of its future oil and gas production with commodity futures contracts. Prior to January 1, 2001, gains and losses on these contracts were recognized in the period in which revenue from the related gas and oil production was recorded or when the contracts were closed. To the extent that the quantities hedged under the commodity transaction exceeded current production, the Company recognized gains or losses on the overhedged amount. This policy was changed as of January 1, 2001. In June 1998 Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities" was issued. The Company adopted SFAS No. 133, as amended, effective January 1, 2001. SFAS No. 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") to the extent the derivative is effective as a hedge. 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 No. 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. CAPITALIZED INTEREST - The Company capitalizes interest costs incurred on exploration projects. Interest capitalized for the years ended December 31, 2001 and 2000 was approximately $288,584 and $219,197, 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, 2001 and 2000 was a liability of approximately 149,182 MCF or $272,885 and 135,676 MCF or $245,719, respectively. EXPLORATION COSTS - The Company expenses exploratory dry hole costs, geological and geophysical costs, and impairment of unproved properties. In 2001 and 2000, the Company expensed $148,469 and $4,613,603 respectively in geological and geophysical costs and $6,307,129 and $7,114,950 respectively in dry hole costs. 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 - SFAS 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 41 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 were not recorded in the consolidated financial statements to the extent the swaps qualify for hedge accounting prior to January 1, 2001. This policy was changed as of January 1, 2001 when the Company adopted SFAS No. 133. 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, 2001 and 2002 all potentially diluted securities are anti-dilutive and therefore are not included in the earnings per share calculation. Such potential common shares were 1,017,435 and 766,917 for the years ended December 31, 2001 and 2000, respectively. The following table presents information necessary to calculate basic and diluted earnings per share for the periods indicated:
2001 2000 ------------- ------------ BASIC AND DILUTED EARNINGS PER SHARE Weighted average common shares outstanding ................... 19,049,454 18,877,192 ============ ============ Basic and diluted loss per share before extraordinary gain ... $ (0.02) $ (0.46) ============ ============ Basic and diluted loss per share ............................. $ (0.02) $ (0.40) ============ ============ EARNINGS FOR BASIC AND DILUTED COMPUTATION Net loss to common stockholders before extraordinary gain .... $ (457,234) $ (8,660,638) Extraordinary gain ........................................... -- 1,126,034 ------------ ------------ Net loss to common stockholders (basic and diluted loss per share computation) ........................ $ (457,234) $ (7,534,604) ============ ============
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS. On June 29, 2001, SFAS No. 141, "Business Combinations" was approved by the Financial Accounting Standards Board ("FASB"). SFAS No. 141 requires that the purchase method of accounting be used or all business combinations initiated after June 30, 2001. The Company was required to implement SFAS No. 141 on July 1, 2001. The adoption of this statement had no effect on the Company's consolidated financial position, cash flows or results of operations. On June 29, 2001 SFAS No. 142, "Goodwill and Other Intangible Assets", was approved by the FASB. SFAS No. 142 changes the accounting for goodwill from an amortization method to an impairment-only approach. Amortization of goodwill, including goodwill recorded in past business combinations, will cease upon adoption of this statement. The Company is required to implement SFAS No. 142 on January 1, 2002. Management has reviewed SFAS No. 142 and determined that this statement will not have a material effect on its consolidated financial position, cash flows or results of operation. In June 2001 the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 provides the accounting requirements for retirement obligations associated with tangible long-lived assets. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002, and early adoption is permitted. The Company is currently assessing the new standard and has not yet determined the impact on its consolidated financial position, cash flows or results of operations. 42 In August 2001 the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." The new rules supersede SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." The new rules retain many of the fundamental recognition and measurement provisions, but significantly change the criteria for classifying an asset as held-for-sale. SFAS No. 144 is effective for fiscal years beginning after December 15, 2001. The Company is currently assessing the new standard and has not yet determined the impact on its consolidated financial position, cash flows or results of operations. 2. RECENT EVENT: On March 17, 2002, the Company and Santos Americas and Europe Corporation and ECM Acquisition Company, (collectively "Santos") entered into an agreement providing for Santos' acquisition of all issued and outstanding common stock of the Company by means of a tender offer at a price of US$2.84 per share in cash and a follow-on merger at the same price. Under the terms agreed, Santos initiated a formal offer on March 26, 2002. The offer must remain open through at least April 22, 2002. It is conditioned upon the receipt of at least a majority of the Company's outstanding shares. If Santos receives at least a majority of such shares, it will, subject to various typical contingencies such as the absence of any material adverse changes, close on the purchase of shares tendered and then proceed to acquire all remaining outstanding shares through a subsequent merger, the timing of which would be announced at a later date. Shareholders who do not participate in the tender offer would also receive $2.84 per share in cash in the merger. At a meeting held on Saturday, March 16, 2002, the Company's Board of Directors voted to accept and support the Santos tender offer and voted to recommend that the Company's shareholders accept the cash tender offer and approve the merger. In addition, as a condition to the offer, two major shareholders and the Chairman of the Board of Directors agreed to tender all of the shares owned by them (representing 9,991,662 shares or 52% of the Company's total outstanding shares) in the Santos tender offer and have granted Santos the option to acquire all of their shares if the tender offer is not consummated for certain reasons. 3. STOCKHOLDERS' EQUITY: In 2001 and 2000 the Company issued 149,868 and 120,778 additional shares of common stock, respectively, pursuant to various employee options which were exercised during the year, the Company's match of shares pursuant to the Company's 401K plan and shares issued pursuant to a bonus plan. 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 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, 2001 and 2000, the Company had a common stock subscriptions receivable of $14,640 and $106,060 respectively outstanding related to these shares. 43 WARRANTS - In August of 1998 the Company issued a warrant to purchase 191,250 shares of the Company's common stock at an exercise price of $7.20 per share. The warrant was issued in connection with the sale of common stock of the Company. The warrant expires in August of 2002. 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 was recorded in the amount of $110,000. In the third quarter of 2001, in conjunction with a restructuring of a financing transaction, the Company issued warrants to purchase 125,000 shares of the Company's common stock at an exercise price of $3.00 per share. The warrants expire on August 3, 2006. The fair value of these warrants was recorded at $150,700. 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 2,546,836 shares of common stock at prices ranging from $1.83 to $4.25 were outstanding as of December 31, 2001. 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 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, 2001 and 2000.
EMPLOYEE OPTION PLANS ----------------------------------------------------- 2001 2000 ------------------------ -------------------------- WEIGHTED WEIGHTED AVERAGE AVERAGE EXERCISE EXERCISE SHARES PRICE SHARES PRICE --------- -------- ----------- -------- Outstanding at beginning of year ........ 2,497,168 $ 2.44 1,259,667 $ 2.42 Granted ................................. 110,000 3.36 1,463,000 2.44 Exercised ............................... (48,497) 2.38 (66,499) 2.38 Forfeited ............................... (11,835) 2.38 (159,000) 2.38 Outstanding at end of year .............. 2,546,836 2.48 $ 2,497,168 $ 2.44 Weighted average fair value of options granted during the year ...... $ 1.98 $ 1.51 -------- --------
Options outstanding at December 31, 2001 consisted of the following: 44
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 - $4.25 2,546,836 $2.48 7.57 years 2,046,067 $2.49
The Company accounts for employee stock-based compensation arrangements in accordance with the provisions of Accounting Principles Board Opinion No. 25 "Accounting for Stock Issued to Employees" and applies the disclosure-only provisions of SFAS 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 2001 and 2000 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:
2001 2000 ------------ ----------- Net loss attributable to common stockholders-as reported......... $ (457,234) $(7,534,604) Net loss attributable to common stockholders-pro forma........... (1,657,274) (8,531,852) Net loss per common share-as reported............................ (0.02) (0.40) Net loss per common share-pro forma.............................. (0.09) (0.45)
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 52% and 82% in 2001 and 2000; risk-free interest rate of 4.03% and 5.95% in 2001 and 2000; 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 2001 and 2000. These sales resulted in an aggregate gain of $16,227,756 in 2001 and $9,329,631 in 2000. 5. LONG-TERM DEBT: Long-term debt consists of the following:
DECEMBER 31, --------------------------------- 2001 2000 Loan with Deutsche Bank AG ("Deutsche Bank") further described below............ $ 16,189,071 $ 20,341,782 -------------- --------------- Less current portion............................................................ 480,567 6,750,000 -------------- --------------- Total long-term debt............................................................ $ 15,708,504 $ 13,591,782 ============== ===============
Maturities of long-term debt are as follows:
YEAR AT DECEMBER 31, - ---- --------------- 2001 ---- 2002.................................................................... 480,567 2003.................................................................... 10,422,268
45 2004.................................................................... 1,922,268 2005.................................................................... 1,922,268 2006.................................................................... 1,441,700
On January 25, 2000, the Company closed a credit facility with Deutsche Bank AG, New York branch. This facility provided for Deutsche Bank to loan up to $29,000,000 to be available in two tranches. On August 13, 2001, the Company completed an amendment of its credit facility with Deutsche Bank. The amended facility provides for the bank to loan up to $38,500,000 in two tranches. Tranche A is in the amount of $30,000,000 with $13,500,000 established as the borrowing base and $7,689,071 outstanding at December 31, 2001. Tranche A will mature on August 13, 2002 at which time it will convert to a four year quarterly amortizing term loan. Tranche B is in the amount of $8,500,000, of which the entire amount was outstanding at December 31, 2001. It is payable interest only until due on August 13, 2003, at which time the entire Tranche B balance is due. In addition, the Company must remain in compliance with certain covenants required by Deutsche Bank, including a re-determination 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 July 31, 2002 or the date the Tranche B Loan is repaid. The Company may repurchase this overriding royalty interest prior to September 30, 2003, if all Tranche B loans are repaid in full. As part of the credit agreement, the Company is subject to certain covenants and restrictions, among which are limitations on additional borrowing, and sales of significant properties, payment of dividends, working capital, cash, and net worth maintenance requirements and a minimum debt to net worth ratio. 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. There also is 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. The covenants regarding financial condition of the Company are as follows: Tangible Net Worth................................. $20,000,000 plus 50% of net income from inception of the credit agreement to the date of calculation treated as a single period. Current Ratio...................................... 1.0 to 1.0 (computed by including unused portion of loan commitments in current assets and excluding current portion of long-term debt from current liabilities). Debt to Capitalization............................. 0.6 to 1.0 Interest Coverage Ratio............................ 3.0 to 1.0 Debt to EBITDA Ratio............................... 3.5 to 1.0 at any time prior to March 31, 2002, and 3.0 to 1.0 at anytime on or after March 31, 2002. (Calculation of EBITDA is determined after the exclusion of all cumulative and current effects of SFAS No. 133). General and Administrative Limit................... General and Administrative expenses shall not exceed, for any four consecutive fiscal quarters beginning in the third quarter of 2001, the sum of $7,000,000 plus amounts paid pursuant to the Company's employee bonus plan, as in effect on August 13, 2001.
Calculation of all covenants is determined after the exclusion of all cumulative and current effects of SFAS No. 133. 46 As of December 31, 2001, the Company was in compliance with all above covenants. Although the Company believes it can be in compliance with these covenants throughout 2002 and beyond, there can be no assurance that it will be in compliance. As a result, it is possible that waivers may be needed in the future. In the event Deutsche Bank did not grant such waivers, if needed, the Company would be in noncompliance of the covenants and would cause all outstanding borrowings to become current and requiring the Company to seek alternative financing arrangements. The Company has entered into an interest rate swap guaranteeing a fixed rate of 4.5% on $10,000,000, the original Tranche B amount. The Company will actually pay Deutsche Bank at a rate of London Interbank offered rate ("Libor") plus 6% on Tranche B. The rate of the Tranche A loan is at Libor plus 2%. The interest rates at December 31, 2001 for Tranche A and Tranche B were 4.46% and 8.46%, respectively. Consideration paid to the bank for the amended credit facility included a five-year warrant to purchase 125,000 shares of the Company's common stock for $3.00 per share. In addition, Company will pay fees of one-half of one percent (0.5%) on the unused portion of the commitment amount. The interest rate swap had a fair value of $408,662 at December 31, 2001 and is recorded as a current liability on the balance sheet. 6. INCOME TAXES: Deferred tax assets and liabilities are as follows:
AT DECEMBER 31, ------------------------------- 2001 2000 ------------ ------------ Net operating tax loss carryforward .... $ 11,021,351 $ 18,176,646 Property and equipment ................. (7,014,012) 3,836,490 Valuation allowance .................... (18,035,363) (22,013,136) ------------ ------------ 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 carry-forwards at December 31, 2001, of approximately $31,489,573 which may be used to offset future taxable income. The operating loss carry-forwards will expire in the tax years 2009 through 2021. The ability of the Company to utilize NOL's and tax credit carry-forwards 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 carry-forwards 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. The tax benefit derived by applying the federal statutory tax rate to the Company's pretax loss is offset by the valuation allowance applied to the Company's deferred tax assets. In the fourth quarter of 2001, the Company sold a portion of its working interest in the Runnells Field resulting in a gain of approximately $15.6 million. After applying applicable NOL, the gain resulted in Alternative Minimum Tax in the amount of $291,418. 7. RELATED PARTY TRANSACTIONS: The President and Chief Executive Officer of the Company serves as the President of EPC. In addition, two members of the Company's Board of Directors serve as the President and Executive Vice President of Aspect, respectively. The Company's accounts receivable balance from affiliates of the Company at December 31, 2001 and 2000 were $360,182 and $124,268, respectively. The accounts receivable due from Aspect at December 31, 2001 47 and 2000 were $300,161 and zero, respectively. The accounts receivable due from EPC at December 31, 2001 and 2000 were zero and $101,199, respectively. The Company's accounts payable balance to the Company's affiliates at December 31, 2001 and 2000 were zero and $269,835, respectively. The accounts payable balance due to Aspect at December 31, 2001 and 2000 were zero and $122,506 respectively. 8. COMMITMENTS AND CONTINGENCIES: The Company leases office space under lease agreements, which are classified as operating leases. Lease expense under these agreements was $340,376 in 2001 and $300,290 in 2000. A summary of future minimum rentals on these operating leases is as follows:
YEAR AT DECEMBER 31, ---- 2001 --------------- 2002............................................ $378,270 2003............................................ 291,688 2004............................................ 205,106 2005............................................ 205,106 2006............................................ 136,737
Minimum rentals as set forth above include $205,106 in 2004, $205,106 in 2005 and $136,737 in 2006 attributable to the lease of office space at the Company's Houston, Texas offices. This lease can be canceled at the option of the Company effective on or after September 1, 2004 by payment of two months rent. In the event this option was exercised total minimum lease payments for 2004, 2005 and 2006 would be $170,922 and $0 and $0 respectively. 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. The hedged volumes were as follows:
QUARTER ENDED PRICE PER MMBtu 2001 (MMBtu/DAY) 2000 (MMBtu/DAY) ------------- --------------- ---------------- ---------------- March 31st $2.45 7,161 9,381 June 30th $2.45 6,880 9,031 September 30th $2.45 6,600 8,646 December 31st $2.45 6,319 8,278
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 canceled. 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 were 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. Volumes committed to the collar structure include 4,500 MMBtu per day for calendar year 2003. These hedges are accounted for as cash flow hedges pursuant to SFAS No. 133 and had a fair value at December 31, 2001 of $2,026,067. On January 25, 2001, the Company restructured its hedging arrangement with Deutsche Bank and as a result, effectively settled the terms of the original hedge. In connection with this settlement and restructuring, the Company valued the original hedge at its fair value on the settlement date at $6,818,598. This fair value was recognized as a charge against revenues over the term of the original hedge through December 31, 2001. During the year ended December 31, 2001, the Company recognized in earnings $6,818,598 of losses on hedging activities 48 related to the original hedge settled during January 2001. These losses were partially offset by an unrealized gain on the restructured hedges of approximately $2,980,254 during 2001. In the third quarter of 2000, the Company hedged an additional 5,000 MMBtu per day of natural gas. The hedge prices as of January 1, 2001 were at $4.01 per MMBtu for the months of January through December 2001. This hedge expired December 31, 2001. In the fourth quarter of 2001, the Company hedged an additional 6,500 MMBtu/day of natural gas for calendar year 2002 at a price of $2.90 per MMBtu. This contract had a fair value at December 31, 2001 of $302,800. As of January 1, 2001, the Company also had in place oil hedges for 175 barrels of oil per day in the first quarter of 2001, and 168 barrels of oil per day, 161 barrels of oil per day and 154 barrels of oil per day for the second through fourth quarters of 2001, respectively, all of which oil hedges were at $21.03 per barrel. These hedges have expired and the Company currently has no oil hedges in place. As a result, the Company has quantities of natural gas and/or oil committed to hedge and/or collar transactions in the volumes as set forth below: NATURAL GAS
QUARTER ENDED 2001 (MMBTU/DAY) 2002 (MMBTU/DAY) 2003 (MMBTU/DAY) ------------- ---------------- ---------------- ---------------- March 31st 12,383 15,000 4,500 June 30th 12,900 14,500 4,500 September 30th 13,000 14,000 4,500 December 31st 13,000 13,500 4,500
OIL
QUARTER ENDED 2001 (BBL/DAY) 2002 (BBL/DAY) 2003 (BBL/DAY) ------------- -------------- -------------- -------------- March 31st 175 0 0 June 30th 168 0 0 September 30th 161 0 0 December 31st 154 0 0
As a result of the above-referenced transactions, the Company has hedged varying quantities of its natural gas through December of 2003. First quarter 2002 hedges are estimated to be approximately 95% of the Company's natural gas production. Second quarter 2002 hedges are estimated to be approximately 85% of the Company's natural gas production as additional wells waiting on pipeline come on line. Future percentages will vary. 9. PROPERTY AND EQUIPMENT:
YEAR ENDED DECEMBER 31, ------------------------------- 2001 2000 -------------- -------------- Gas and oil properties, at cost, successful efforts method of accounting: Proved........................................... $ 38,350,379 $ 29,934,906 Unproved, subject to amortization .............. 1,641,900 5,334,700 Unproved, not subject to amortization............ 55,327,431 44,689,074 -------------- -------------- Total gas and oil properties.................... 95,319,710 79,958,680 Other property and equipment.............................. 2,551,686 2,018,342 -------------- -------------- Total property and equipment.............................. 97,871,396 81,977,022 Less accumulated depletion, depreciation, amortization, and impairments (1).................... (49,329,061) (40,087,050)
49
YEAR ENDED DECEMBER 31, ---------------------------------- 2001 2000 ---------------- -------------- Total property and equipment, net......................... $ 48,542,335 $ 41,889,972 ================ ==============
(1) Includes accumulated impairments of both proved and unproved properties. 10. SUPPLEMENTAL GAS AND OIL INFORMATION (UNAUDITED): The Company's proved gas and oil reserves are located in the United States. Proved reserves are those quantities of natural gas and crude oil which, upon analysis of geological and engineering data, demonstrate with reasonable certainty to be recoverable in the future from known gas and oil reservoirs under existing economic and operating conditions (i.e. price and costs as of the date the estimate is made). Proved developed (producing and non-producing) reserves are those proved reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped gas and oil reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. FINANCIAL DATA. The Company's gas and oil producing activities represent substantially all of the business activities of the Company. The following costs include all such costs incurred during each period, except for depreciation and amortization of costs capitalized: COSTS INCURRED IN GAS AND OIL EXPLORATION AND PRODUCTION ACTIVITIES:
YEAR ENDED DECEMBER 31, ------------------------------ 2001 2000 -------------- ----------- Acquisition of properties: Proved......................................................................... $ -- $ -- Unproved....................................................................... 11,569,664 4,525,278 Exploration costs................................................................. 23,702,948 19,491,881 Development costs................................................................. 2,932,691 916,168 -------------- ----------- Total costs incurred........................................................ $ 38,205,303 $24,933,327 ============== ===========
CAPITALIZED COSTS:
AT DECEMBER 31, ------------------------------- 2001 2000 ------------ ------------ Proved ....................................................... $ 38,350,379 $ 29,934,906 Unproved properties, subject to amortization, net ............ 1,641,900 5,334,700 Unproved properties, not subject to amortization ............. 55,327,431 44,689,074 Less accumulated depletion, amortization and impairments ..... (47,736,141) (38,806,340) ------------ ------------ Net capitalized costs .................................. $ 47,583,569 $ 41,152,340 ------------ ------------
50 ESTIMATED QUANTITIES OF PROVED GAS AND OIL RESERVES:
CRUDE OIL AND CONDENSATE -------------------------- (BARRELS) --------- NATURAL GAS (MCF) ----------------- YEARS ENDED DECEMBER 31, YEARS ENDED DECEMBER 31, ---------------------------- -------------------------- 2001 2000 2001 2000 ---------- ---------- -------- -------- Proved developed and undeveloped reserves: Beginning of period ....................... 21,076,278 18,793,038 454,498 372,795 Purchases of minerals-in-place............. -- -- -- -- Sales of minerals-in-place ................ (6,841,711) (3,334,327) (250,883) (10,653) Revisions of previous estimates ........... (4,017,585) (5,451,343) (86,786) (131,569) Extensions, discoveries and other additions 11,640,967 16,929,105 522,793 387,817 Production ................................ (6,557,949) (5,860,195) (132,165) (163,892) ---------- ---------- -------- -------- End of period ............................. 15,300,000 21,076,278 507,457 454,498 ========== ========== ======== ======== Proved developed reserves: Beginning of period ....................... 16,198,327 17,481,248 305,842 371,368 End of period ............................. 14,882,000 16,198,327 499,098 305,842
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS: The standardized measure of discounted future net cash flows is based on criteria established by SFAS No. 69, "Accounting for Oil and Gas Producing Activities" and is not intended to be a "best estimate" of the fair value of the Company's oil and gas properties. For this to be the case, forecasts of future economic conditions, varying price and cost estimates, varying discount rates and consideration of other than proved reserves (i.e., probable reserves) would have to be incorporated into the valuations. Future net cash inflows are based on the future production of proved reserves of natural gas, natural gas liquids, crude oil and condensate as estimated by petroleum engineers by applying current prices of gas and oil (with consideration of price changes only to the extent fixed and determinable and with consideration of the timing of gas sales under existing contracts or spot market sales) to estimated future production of proved reserves. Year-end prices used in determining future cash inflows averaged for natural gas and oil for the periods ended December 31, 2001 and 2000 were as follows: 2001 - $2.31 per Mcf of natural gas, $18.45 per barrel of oil; 2000 - $10.44 per Mcf of natural gas, $28.73 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, ------------------------------ 2001 2000 ------------- -------------- Future cash inflows.............................................................. $ 44,287,840 $ 233,139,437 Future development and production costs.......................................... (11,845,818) (33,404,090) Future income tax expenses....................................................... -- -- ------------- -------------- Future net cash flows............................................................ 32,442,022 199,735,347 Discount......................................................................... (6,365,528) (38,189,947) ------------- -------------- Standardized measure of discounted future net cash flows......................... $ 26,076,494 $ 161,545,400 ============= ==============
51 The following table sets forth changes in the standardized measure of discounted future net cash flows:
YEAR ENDED DECEMBER 31, --------------------------------- 2001 2000 ------------- ------------- Standardized measure of discounted future cash flows-beginning of period $ 161,545,400 $ 32,513,100 Sales of oil and gas produced, net of operating expenses ............... (26,293,306) (26,505,466) Purchases of minerals in place ......................................... -- -- Net changes in sales prices and production costs ....................... (99,634,878) 45,131,636 Extensions, discoveries and improved recovery, less related costs ...... 19,509,442 116,249,984 Change in future development costs ..................................... (4,246,830) 3,745,484 Previously estimated development costs incurred during the year ........ (1,766,850) (1,051,300) Revisions of previous quantity estimates ............................... (6,660,689) (12,252,353) Accretion of discount .................................................. 16,154,540 7,189,087 Net change of income taxes ............................................. -- -- Sales of minerals-in-place ............................................. (30,505,551) (3,077,823) Changes in production rates (timing) and other ......................... (2,024,783) (396,949) ------------- ------------- Standardized measure of discounted future cash flows-end of period ..... $ 26,076,494 $ 161,545,400 ============= =============
ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Not Applicable. PART III ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS; COMPLIANCE WITH SECTION 16(A) OF THE EXCHANGE ACT The information required by this item is hereby incorporated by reference to the Company's Proxy Statement, which will be filed with the Commission within one hundred twenty (120) days of the close of the fiscal year pursuant to regulation 14A. There is no additional required information. ITEM 10. EXECUTIVE COMPENSATION The information required by this item is hereby incorporated by reference to the Company's Proxy Statement which will be filed with the Commission within one hundred twenty (120) days of the close of the fiscal year pursuant to regulation 14A. There is no additional required information. ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information required by this item is hereby incorporated by reference to the Company's Proxy Statement which will be filed with the Commission within one hundred twenty (120) days of the close of the fiscal year pursuant to regulation 14A. There is no additional required information. ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The information required by this item is hereby incorporated by reference to the Company's Proxy Statement which will be filed with the Commission within one hundred twenty (120) days of the close of the fiscal year pursuant to regulation 14A. There is no additional required information. 52 PART IV ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K EXHIBIT NAME OF EXHIBIT 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. 10(a) 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(b) Second Amended and Restated Credit Agreement dated as of August 13, 2001 between Esenjay Exploration, Inc. , as the Borrower, and Deutsche Bank AG, New York Branch, as the Lender is incorporated by reference to the Company's report on Form 10-QSB for the quarterly period ended June 30, 2001 wherein same appeared as Exhibit 10. 10(c) 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. 10(d) Agreement dated as of March 17, 2002 between Esenjay Exploration, Inc., Santos Americas and Europe Corporation and ECM Acquisition Company is incorporated by reference to the Company's report on Form 8-K filed with the Securities and Exchange Commission on March 21, 2002 wherein same appeared as Exhibit 2.1. 11* Statement of Earnings per Share 21* Subsidiaries of Registrant. (b) Reports on Form 8-K Form 8-K filed on March 21, 2001 is incorporated by reference. *Filed herewith 53 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, 2002 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, 2002 /s/ David B. Christofferson ------------------------------------------------ David B. Christofferson, Senior Vice President, General Counsel and Chief Financial Officer Date: April 16, 2002 /s/ Barry L. Cromeans ------------------------------------------------ Barry L. Cromeans, Chief Accounting Officer Date: April 16, 2002 /s/ David W. Berry ------------------------------------------------ David W. Berry, Chairman and Director Date: April 16, 2002 /s/ Alex B. Campbell ------------------------------------------------ Alex B. Campbell, Director Date: April 16, 2002 /s/ Alex M. Cranberg ------------------------------------------------ Alex M. Cranberg, Director Date: April 16, 2002 /s/ William D. Dodge, III ------------------------------------------------ William D. Dodge, III, Director Date: April 16, 2002 /s/ Jeffrey B. Pollicoff ------------------------------------------------ Jeffrey B. Pollicoff, Director Date: April 16, 2002 /s/ Jack P. Randall ------------------------------------------------ Jack P. Randall, Director Date: April 16, 2002 /s/ Hobart A. Smith ------------------------------------------------ Hobart A. Smith, Director 54 EX-11 3 a2077010zex-11.txt EXHIBIT 11 EXHIBIT 11 TO FORM 10-KSB COMPUTATION OF EARNINGS PER COMMON SHARE AND COMMON SHARE EQUIVALENTS
Year Ended December 31, -------------------------------- 2001 2000 ------------- ------------ BASIC EARNINGS PER SHARE Weighted average common shares outstanding .............. 19,049,454 18,877,192 ============= ============ Basic loss before extraordinary gain ................ $ (0.02) $ (0.46) ============= ============ Basic loss per share ................................ $ (0.02) $ (0.40) ============= ============ DILUTED EARNINGS PER SHARE Weighted average common shares outstanding .............. 19,049,454 18,877,192 Shares issuable from assumed conversion of Convertible preferred stock ...................... -- 259,458 Shares issuable from assumed conversion of common share options and warrants ................... 1,017,435 507,459 ------------- ------------ Weighted average common shares outstanding, as adjusted.. 20,066,889 19,644,109 ============= ============ Diluted loss before extraordinary gain .............. $ (0.02) $ (0.44) ============= ============ Diluted loss per share .............................. $ (0.02) $ (0.38) ============= ============ EARNINGS FOR BASIC AND DILUTED COMPUTATION Net loss before extraordinary gain ...................... $ (457,234) $ (8,660,638) Extraordinary gain ...................................... -- 1,126,034 ------------- ------------ Net loss to common stockholders (basic and diluted earnings per share computation) ..................... $ (457,234) $ (7,534,604) ============= ============
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. 55 EX-21 4 a2077010zex-21.txt EXHIBIT 21 EXHIBIT 21 TO FORM 10-KSB/A The subsidiaries of the Registrant are: None -----END PRIVACY-ENHANCED MESSAGE-----