-----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, RLX2nzxOD/a8rQtZhGJhhAIbSjv/7l7LToKSWDgOvqjO0BmzHbpoz4ilfsBc2fZo hbIL2cUHiD4e2/P3yScvxg== /in/edgar/work/0000912057-00-050220/0000912057-00-050220.txt : 20001116 0000912057-00-050220.hdr.sgml : 20001116 ACCESSION NUMBER: 0000912057-00-050220 CONFORMED SUBMISSION TYPE: 10QSB PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 20000930 FILED AS OF DATE: 20001114 FILER: COMPANY DATA: COMPANY CONFORMED NAME: ESENJAY EXPLORATION INC CENTRAL INDEX KEY: 0000901611 STANDARD INDUSTRIAL CLASSIFICATION: [1311 ] IRS NUMBER: 731421000 STATE OF INCORPORATION: OK FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10QSB SEC ACT: SEC FILE NUMBER: 001-12530 FILM NUMBER: 768610 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 10QSB 1 a2030797z10qsb.txt 10QSB - -------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-QSB [X] QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 2000 [ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ______ to ______ Commission file number: 1-12530 ESENJAY EXPLORATION, INC. (Exact name of small business issuer as specified in its charter) DELAWARE 73-1421000 (State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification Number) 500 NORTH WATER STREET, SUITE 1100 CORPUS CHRISTI, TEXAS 78471 (Address of principal executive offices including zip code) (361) 883-7464 (Issuer's telephone number including area code) 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 [ ] 18,914,099 shares as the registrant's common stock were outstanding as of November 10, 2000. Transitional Small Business Disclosure Format (Check one): Yes [ ] No [X] - -------------------------------------------------------------------------------- ESENJAY EXPLORATION, INC. FORM 10-QSB FOR THE QUARTER ENDED SEPTEMBER 30, 2000 INDEX
Page ---- PART I. FINANCIAL INFORMATION ITEM 1. Financial Statements - General Information......................................................3 Condensed Consolidated Balance Sheets as of September 30, 2000 (unaudited) and December 31, 1999.......................................................................4 Condensed Consolidated Statements of Operations for the three months and nine months ended September 30, 2000 and 1999 (unaudited)..............................................5 Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2000 and 1999 (unaudited)...............................................6 Notes to Condensed Consolidated Financial Statements (unaudited)...............................7 ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations..............................................................11 PART II. OTHER INFORMATION..............................................................................23
2 PART I - FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS GENERAL The Condensed Consolidated Financial Statements herein have been prepared by the Company without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (the "SEC"). As applicable under such regulations, certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted. The Company believes the presentation and disclosures herein are adequate to make the information not misleading, and the financial statements reflect all elimination entries and normal adjustments that are necessary for a fair presentation of the results of operations for the three and nine months ended September 30, 2000 and 1999. Operating results for interim periods are not necessarily indicative of the results for full years. It is suggested that these condensed consolidated financial statements be read in conjunction with the consolidated financial statements for the year ended December 31, 1999 and the related notes thereto included in Form 10-KSB and 10KSB/A as filed with the SEC. 3 ESENJAY EXPLORATION, INC. CONDENSED CONSOLIDATED BALANCE SHEETS
SEPTEMBER 30, DECEMBER 31, ASSETS 2000 1999 ------------------- ---------------- (unaudited) Current assets: Cash and cash equivalents......................................... $ 386,940 $ 2,598,047 Accounts receivable, net of allowance for doubtful accounts of $445,872 at September 30, 2000 and $519,137 at December 31, 1999................................... 13,870,912 7,078,109 Prepaid expenses and other......................................... 1,282,882 3,940,133 Receivables from affiliates........................................ 118,806 363,027 ------------------- ----------------- Total current assets...................................... 15,659,540 13,979,316 Property and equipment, successful efforts method of accounting......... 80,176,102 80,120,781 Less accumulated depletion, depreciation And amortization................................................... (34,546,687) (25,937,472) ------------------- ----------------- 45,629,415 54,183,309 Other assets .......................................................... 1,247,967 770,210 ------------------- ----------------- Total assets.............................................. $ 62,536,922 $ 68,932,835 =================== ================= LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable................................................... $ 12,786,006 $ 8,838,629 Accounts payable to affiliate, net................................. 269,836 2,083,913 Revenue distribution payable....................................... 2,837,617 2,491,798 Current portion of long-term debt.................................. 5,384,178 11,013,162 Accrued and other liabilities...................................... 1,299,216 6,095,188 ------------------- ----------------- Total current liabilities................................. 22,576,853 30,522,690 Long-term debt ......................................................... 12,457,604 4,750,000 Non-recourse debt ...................................................... 864,000 864,000 Accrued interest on non-recourse debt .................................. 562,034 463,395 ------------------- ----------------- Total liabilities ........................................ 36,460,491 36,600,085 Stockholders' equity: Convertible preferred stock $.01 par value; 5,000,000 shares authorized; 0 and 356,999 shares issued and outstanding at September 30, 2000 and December 31, 1999, respectively................................. --- 3,570 Common stock: Class A common stock, $.01 par value; 40,000,000 shares authorized; and 18,889,441 and 18,837,699 outstanding at September 30, 2000 and December 31, 1999, respectively................................. 188,894 188,377 Additional paid-in capital ........................................ 84,383,631 84,877,904 Accumulated deficit................................................ (58,496,094) (52,737,101) ------------------- ----------------- Total stockholders' equity................................ 26,076,431 32,332,750 ------------------- ----------------- Total liabilities and stockholders' equity................ $ 62,536,922 $ 68,932,835 =================== =================
The accompanying notes are an integral part of these financial statements. 4 ESENJAY EXPLORATION, INC. CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30 SEPTEMBER 30, 2000 1999 2000 1999 --------------- ----------------- --------------- -------------- Revenues: Gas and oil revenues............................ $ 7,983,234 $ 2,577,335 $ 18,903,840 $ 4,334,441 Realized gain (loss) on commodity transactions.. (1,680,669) 33,557 (2,985,847) 231,580 Gain (loss) on sale of assets................... 1,311,681 1,924,273 9,468,399 2,034,905 Operating fees.................................. 116,108 69,803 341,586 223,154 Other revenues.................................. 29,733 10,474 81,662 34,911 --------------- ----------------- --------------- -------------- Total revenues.............................. 7,760,087 4,615,442 25,809,640 6,858,991 --------------- ----------------- --------------- -------------- Costs and expenses: Lease operating expense......................... 198,745 109,622 672,618 482,210 Production taxes................................ 561,678 158,241 1,360,712 273,475 Transportation and gathering costs.............. 14,546 --- 18,093 --- Depletion, depreciation and amortization........ 2,772,310 1,065,641 7,185,419 2,241,468 Amortization of unproved properties............. 1,294,400 1,692,600 4,176,000 6,050,600 Impairment of assets............................ 941,639 358,106 983,628 358,106 Exploration costs - geological and geophysical.. 2,839,217 280,896 4,550,324 1,565,374 Exploration costs - dry hole.................... 3,300,617 332,820 6,225,277 398,098 Interest expense................................ 292,759 212,538 853,394 520,977 General and administrative expense.............. 1,678,855 1,266,805 5,176,476 4,348,901 Other tax expense............................... 96,683 --- 207,689 --- Delay rental expense............................ 66,537 178,547 159,003 249,556 --------------- ----------------- --------------- -------------- Total costs and expenses.................... 14,057,986 5,655,816 31,568,633 16,488,765 --------------- ----------------- --------------- -------------- Loss before provision for income taxes............... (6,297,899) (1,040,374) (5,758,993) (9,629,774) Benefit (provision) for income taxes................. --- --- --- --- --------------- ----------------- --------------- -------------- Net loss applicable to common stockholders........... $ (6,297,899) $ (1,040,374) $ (5,758,993) $ (9,629,774) =============== ================= =============== ============== Net loss per common and common equivalent share - basic........................... $ (0.33) $ (0.06) $ (0.31) $ (0.61) =============== ================= =============== ============== Net loss per common and common equivalent share - diluted......................... $ (0.33) $ (0.06) $ (0.31) $ (0.61) =============== ================= =============== ============== Weighted average number of common shares outstanding - basic ( in thousands)................ 18,883 16,062 18,864 15,881 =============== ================= =============== ============== Weighted average number of common shares outstanding - diluted ( in thousands).............. 18,883 16,062 18,864 15,881 =============== ================= =============== ==============
The accompanying notes are an integral part of these financial statements. 5 ESENJAY EXPLORATION, INC. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Nine Months Ended September 30, ------------------------------------------ 2000 1999 ------------------- ------------------ Cash flows from operating activities: Net loss...................................................... $ (5,758,993) $ (9,629,774) Adjustments to reconcile net loss to net cash used in operating activities: Depletion, depreciation and amortization ..................... 7,185,419 2,241,468 Amortization of unproven property............................. 4,176,000 6,050,600 Impairment of assets.......................................... 983,628 358,106 Gain on sale of assets........................................ (9,468,399) (2,034,905) Amortization of financing costs and warrants.................. 147,413 73,886 Exploration costs............................................. 6,225,277 398,098 Changes in operating assets and liabilities: Trade and affiliate receivables........................... (6,548,582) (2,074,369) Prepaid expenses and other................................ (2,657,251) (814,205) Other assets.............................................. (477,757) (659,025) Accounts payable.......................................... 3,947,377 632,028 Accounts payable to affiliates............................ (1,814,077) (937,560) Revenue distribution payable.............................. 345,819 247,791 Accrued and other......................................... (4,795,972) 844,282 ------------------- ------------------ Net cash used in operating activities......................... (8,510,098) (5,303,579) ------------------- ------------------ Cash flows from investing activities: Capital expenditures - gas and oil properties................. (7,945,947) (10,116,390) Capital expenditures - other property and equipment........... (140,193) (172,429) Proceeds from sale of assets.................................. 12,703,837 8,435,500 ------------------- ------------------ Net cash provided by (used in) investing activities....... 4,617,697 (1,853,319) ------------------- ------------------ Cash flows from financing activities: Proceeds from issuance of common stock 189,899 159,387 Redemption of preferred stock................................. (687,225) --- Proceeds from issuance of debt................................ 21,841,782 8,920,000 Repayments of long-term debt.................................. (19,663,162) (1,508,074) ------------------- ------------------ Net cash provided by financing activities................. 1,681,294 7,571,313 ------------------- ------------------ Net increase (decrease) in cash and cash equivalents...... (2,211,107) 414,415 Cash and cash equivalents at beginning of period................... 2,598,047 646,200 ------------------- ------------------ Cash and cash equivalents at end of period......................... $ 386,940 $ 1,060,615 =================== ================== Supplemental disclosure of cash flow information: Cash paid for interest........................................ $ 919,152 $ 1,326,919 =================== ==================
The accompanying notes are an integral part of these financial statements. 6 ESENJAY EXPLORATION, INC. NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: The accompanying unaudited condensed consolidated financial statements of Esenjay Exploration, Inc. and its subsidiaries (the "Company") have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information. Accordingly they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. Interim results are not necessarily indicative of results for a full year. The Company uses the successful efforts method of accounting for gas and oil exploration and development costs. All costs of acquired wells, productive exploratory wells, and development wells are capitalized and depleted by the unit of production method based upon estimated proved developed reserves. Exploratory dry hole costs, geological and geophysical costs, and lease rentals on non-producing leases are expensed as incurred. Gas and oil leasehold acquisition costs are capitalized. Costs of unproved properties are transferred to proved properties when reserves are proved. 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. The Company recognized impairments for both the three and nine month periods ended September 30, 2000 of $941,639 and $983,628, respectively. The Company recognized impairments for both the three and nine month periods ended September 30, 1999 of $358,106. In addition, the $54,200,000 fair market value assigned to unproven gas and oil exploration projects contributed by Esenjay Petroleum Corporation ("EPC") and Aspect Resources LLC ("Aspect") pursuant to certain acquisitions of undeveloped exploration projects (the "Acquisitions") which closed on May 14, 1998 is, until such time as the book value of each such project is either drilled and transferred to producing properties or is otherwise evaluated as impaired, are being amortized on a straight-line basis over a period not to exceed forty-eight months. For the three and nine month periods ended September 30, 2000, such amortization was $1,294,400 and $4,176,000, respectively. For the three and nine month periods ended September 30, 1999, such amortization was $1,692,600 and $6,050,600, respectively. The remaining balance in this amortization group of unproven properties was $6,334,800 at September 30, 2000. A summary of all of the Company's significant accounting policies is presented on pages 39 and 40 of its 1999 Form 10KSB/A filed with the SEC. Users of financial information are encouraged to refer to the footnotes contained therein when reviewing interim financial results. There have been no material changes in the accounting policies followed by the Company during 2000. The accompanying interim financial statements contain all material adjustments, which are in the opinion of management, consistent with the adjustments necessary to present the fairly stated consolidated financial position, results of operations and cash flows of Esenjay Exploration, Inc. for the interim period. Certain prior period amounts have been reclassified to conform to the current period presentation. 2. RECENT EVENT: On October 12, 2000 the Company finalized and closed an agreement with 420 Energy Investments, Inc. ("420") pursuant to which $864,000 in non-recourse debt and $562,034 in interest on non-recourse debt was satisfied. Consideration paid to 420 was $300,000 in cash, plus an agreement to pay to 420 cash payments on the date drilling may commence on any future wells it may drill in one exploration project area located in Terrebonne Parish, Louisiana. The Company has no obligation to drill any such future wells. Any such future payments would 7 range from $20,000 per well to $100,000 per well, but would never exceed a total of $300,000. In addition, 420 retained its prior right to an overriding royalty equal to 2% of the Company's interest in any well drilled in the project area in Terrebonne Parish. One well is currently drilling in the project area. As a result of the transaction, the Company will recognize a gain in the fourth quarter of 2000. Settlement of the obligation also facilitated the commencement of the current drilling on the project. 3. LONG-TERM DEBT: (SEE NOTE 2) Long-term debt consists of the following:
SEPTEMBER 30, DECEMBER 31, 2000 1999 ---------------- ----------------- Non-recourse loan, payable out of an 8% ORRI on the Starboard Prospect, interest accrued at 15%..................................................... $ 864,000 $ 864,000 Note payable, interest at 12%, payable monthly................................. --- 100,000 Loan with Bank of America NT&SA ("B of A"), repaid in 2000................... --- 8,523,162 Loan with Duke Energy Field Services, Inc. repaid in 2000...................... --- 7,140,000 Loan with Deutsche Bank AG closed on January 25, 2000 as further Described below.............................................................. 17,841,782 --- ---------------- ----------------- 18,705,782 16,627,162 Less current portion........................................................... 5,384,178 11,013,162 ---------------- ----------------- $ 13,321,604 $ 5,614,000 ================ =================
On October 12, 2000 the non-recourse loan was satisfied. (See Note 2) On January 25, 2000, the Company closed a credit facility with Deutsche Bank AG, New York branch. This facility provides for Deutsche Bank to lend up to $29,000,000 to be available in two tranches. Tranche A is in the amount of $20,000,000, with $15,000,000 established as the current available borrowing base, and Tranche B is fully drawn in the amount of $9,000,000. Under the terms and conditions of this facility, the facilities existing at December 31, 1999 with Duke Energy Financial Services, Inc. and Bank of America, NT&SA, were paid in full utilizing approximately $15,800,000 of the available proceeds from Deutsche Bank. Tranche A is currently scheduled to mature on January 25, 2001, at which time any remaining unpaid principal will convert to a fully amortizing term loan payable in twenty equal quarterly installments beginning April 1, 2001. The Company intends to ask the bank to extend the Tranche A maturity from January 25, 2001 to January 25, 2002. There is no current agreement with the bank to do so. The Tranche B loan is payable interest only through April 30, 2001 at which date the amount available begins to decrease by 25% per quarter beginning April 30, 2001 with a final maturity in January of 2002. In addition, the Company must remain in compliance with certain covenants required by Deutsche Bank, including a redetermination of the borrowing base every six months. The company also is required to assign an overriding royalty interest to Deutsche Bank for those wells logged prior to the later of the maturity date of Tranche B or the Tranche A termination date or the date the Tranche B Loan is repaid. The Company may repurchase this overriding royalty interest prior to April 30, 2002, 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 the limitations on additional borrowing, and sales of significant properties, working capital, cash, and net worth maintenance requirements and a minimum debt to net worth ratio. The covenants regarding the financial condition of 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..................... 1.1 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
8 At September 30, 2000 the Company was in compliance with all such covenants. The Company has entered into an interest rate swap guaranteeing a fixed Libor rate of 7.075%. The rate the Company pays Deutsche Bank is Libor plus 2%. In addition, the Company will pay fees of one-half of one percent (0.5%) on the unused portion of the commitment amount. 4. RELATED PARTY TRANSACTIONS The Company's outstanding accounts receivable from employees and affiliates of the Company at September 30, 2000 and December 31,1999 was $118,806 and $363,027, respectively. The September 30, 2000 balance includes a net $101,199 receivable from EPC primarily related to joint interest billings. In addition, at September 30, 2000 the Company had a net account payable to Aspect in the amount of $269,836. 5. COMMITMENTS AND CONTINGENCIES 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 restructured all existing natural gas hedges with an affiliate of Deutsche Bank. Pursuant to these hedges, the Company had 9,381 MMBtu/day of net production hedged in the first quarter of 2000, and 9,031 MMBtu/day hedged for the second quarter of 2000. It also hedged 8,646 MMBtu/day for the third quarter of 2000, 8,278 MMBtu/day for the fourth quarter of 2000, 7,161 MMBtu/day for the first quarter of 2001, 6,880 MMBtu/day for the second quarter of 2001, 6,600 MMBtu/day for the third quarter of 2001, and 6,319 MMBtu/day for the fourth quarter of 2001. All of the above hedges are at $2.45 per MMBtu. Concurrent with the restructuring of the hedges, the Company was relieved of any liability or rights pursuant to all previously existing natural gas hedges. 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. The Company also had an existing "collar" hedge arrangement on 280 barrels of oil per day in the first quarter of 2000, and 256 and 237 barrels of oil per day in the second and third quarters of 2000, respectively, which was transferred to the Deutsche Bank affiliate at the existing $18.00 floor price and $20.40 cap price in February 2000. These positions were supplemented with oil hedges at $21.03 per barrel on volumes of 238 barrels of oil per day in the fourth quarter of 2000 and 175, 168, 161, and 154 barrels of oil per day in the first through fourth quarters of 2001, respectively. Third quarter 2000 hedges approximated 57% of the Company's natural gas and 52% of its oil production for such quarter. Future percentages will vary. 6. ACQUISITION 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 9 approximately 9% were converted into Esenjay convertible preferred stock. As a result, Esenjay issued approximately 2,906,778 new shares of common stock and approximately 356,999 shares of convertible preferred stock. The convertible preferred stock may be redeemed at Esenjay's sole option until September 23, 2000 at $1.925 per share. If not redeemed by that time, the preferred will automatically convert into one share of Esenjay common stock on October 1, 2000 if the average closing price of Esenjay common stock is greater than or equal to $1.875 during the month of September 2000. If the Esenjay common stock averages less than $1.875 in September of 2000, the preferred holder has the right, during the month of October of 2000, to "put" the shares to Esenjay. If put, Esenjay will then have the right to retire the convertible preferred stock for $1.65 in cash or for common stock with the number of shares of common stock adjusted based upon a formula set out in the merger agreement. Under any scenario the convertible preferred stock is scheduled to be converted or redeemed not later than November 1, 2000. 3DX Technologies Inc. was a Houston-based exploration and production company whose strategic business focus was the utilization of 3-D seismic imaging and other advanced technologies in the search for natural gas and oil principally in the onshore gulf coast of the United States. As a result of the merger, the Company employed four members of the reservoir engineering and geophysical staff of 3DX, plus one support person, increased its gas and oil reserves, its monthly gas and oil revenues, and expanded its ownership of 3D seismic data and projects. The Acquisition has been accounted for using the purchase method of accounting and, accordingly, the purchase price has been allocated to the assets and liabilities acquired based on fair value at the date of acquisition. The Acquisition included, at fair value, current assets of $2.5 million, property and equipment of $5.8 million, other assets of $0.1 million and liabilities of $0.9 million. The operating results of the Acquisition has been included in the Company's condensed consolidated financial statements from the date of acquisition. On a pro forma basis, assuming the Acquisition had occurred on January 1, 1999, revenues for the three and nine months ended September 30, 1999 would have been $5,045,186 and $8,468,917, respectively. The net loss for the three and nine months ended September 30, 1999 would have been $1,376,831 and $13,597,281; and on a per share basis, basic and diluted loss per share would have been $0.07 and $0.73 for the three and nine months ended September 30, 1999, respectively. 7. NEW ACCOUNTING PRONOUNCEMENTS In June 1999, the Financial Accounting Standards Board ("FASB") issued SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities-Deferred of the Effective Date of FASB Statement No. 133" ("SFAS 137"). SFAS 137, which is effective for all fiscal quarters of fiscal years beginning after June 15, 2000, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as "derivatives") and for hedging activities. SFAS 137 requires that an entity recognize all derivatives as either assets or liabilities in the balance sheet and measure those instruments at fair value. The Company is currently evaluating the impact of the application of SFAS 137, which when adopted on January 1, 2001, could have a material effect on its consolidated financial statements. In December 1999, the Securities and Exchange Commission ("SEC") issued Staff Accounting Bulletin ("SAB") No. 101, "Revenue Recognition in Financial Statements." SAB 101 summarizes certain of the SEC's view in applying generally accepted accounting principles to revenue recognition in financial statements. The Company is required to adopt SAB 101, as amended, in the fourth quarter of fiscal 2000. The Company does not expect the adoption of SAB 101 to have a material affect on its financial position or results of operations. 10 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion and analysis reviews Esenjay Exploration, Inc.'s results of operations for the three and nine month periods ended September 30, 2000 and 1999 and should be read in conjunction with the consolidated financial statements and notes related thereto. Certain statements contained herein that set forth management's intentions, plans, beliefs, expectations or predictions of the future are forward-looking statements. It is important to note that actual results could differ materially from those projected in such forward-looking statements. The risks and uncertainties include but are not limited to potential unfavorable or uncertain results of 3-D seismic surveys, drilling costs and operational uncertainties, risks associated with quantities of total reserves and rates of production from existing gas and oil reserves and pricing assumptions of said reserves, potential delays in the timing of planned operations, competition and other risks associated with permitting seismic surveys and with leasing gas and oil properties, potential cost overruns, potential dry holes and regulatory uncertainties and the availability of capital to fund planned expenditures as well as general industry and market conditions. OVERVIEW OVERVIEW OF HISTORICAL DEVELOPMENTS - INCEPTION THROUGH DECEMBER 31, 1999. In mid-1996, the Company refocused its activities from acquiring gas reserves principally in the mid-continent region of the United States to concentrate on exploration and related development drilling projects in Southern Louisiana and along the Gulf Coast region of Alabama, Mississippi and Texas. During 1996 and 1997, the Company's drilling activities, which were based primarily on 2-D seismic data, were largely unsuccessful. This fact, along with an unexpected drop in production from the Company's Mobile Bay area wells, greatly reduced the Company's cash and capital resources. To address the Company's capital needs, the Board of Directors, at its meeting on August 12, 1997, directed management to look for potential assets to acquire in exchange for the Company's Common Stock, to identify and review potential business consolidation opportunities, identify potential partners to help fund the Company's proposed drilling activities, and to consider any other avenues to strengthen the Company's capital resources and diversify its exploration opportunities. The Board also directed management to reduce overhead wherever prudently possible and the Company retained an investment advisor to aid in achieving these objectives. The Company explored a series of such transactions and the Board, after receipt of the advice of management and its investment advisor, and receipt of due diligence reports and other materials, unanimously agreed that a transaction with Aspect and EPC was the best option for the Company's shareholders. This process led to the Company entering into the Acquisition Agreement among the Company, EPC, and Aspect. This Acquisition Agreement, and certain provisions of it, required approval of the shareholders of the Company. At a special meeting of shareholders held on May 14, 1998 the shareholders approved the Acquisition Agreement, a recapitalization of the Company pursuant to which each outstanding share of common stock would convert into one-sixth (1/6) of a share of new common stock (the "Reverse Split"), a plan and agreement of merger pursuant to which the Company would reincorporate in the state of Delaware and would change its name to Esenjay Exploration, Inc. (the "Reincorporation"), and the election of seven directors. On May 14, 1998 after a Special Meeting of Shareholders, the Company closed the transactions provided for in the Acquisition Agreement, implemented the Reverse Split, and completed the Reincorporation. All references in the accompanying financial statements to the number of common shares have been restated to reflect the foregoing. In addition, as required by the Acquisition Agreement, the Company called for the redemption of all of its issued and outstanding cumulative convertible preferred stock and did redeem said preferred stock. The result of the foregoing is that the Company conveyed a substantial majority of its Common Stock to acquire an array of significant technology enhanced natural gas oriented exploration projects. The Company believed the Acquisitions would facilitate expanded access to capital markets due to the value and diversity of its exploration project portfolio. The Company also believes the transactions significantly enhanced the Company's management team. In connection with the Acquisitions, an affiliate of Enron Corp. exercised an option to exchange $3.8 million of debt Aspect owed to such Enron affiliate for 675,000 shares of the Company's Common Stock that would otherwise have been issued to Aspect in the Acquisitions, at an effective conversion rate of $5.63 per share. 11 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. On Exploration Projects acquired in 1998 pursuant to the Acquisitions, the Company participated in the drilling of twenty-four wells through December 31, 1998 with working interests ranging from 8% to 79%. Of those twenty-four wells, thirteen wells were completed and eleven were dry holes. Several of the successful wells went into production late in the third quarter of 1998, and in the fourth quarter of 1998. 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 have reached the drilling stage. In many instances the requisite process of geological and/or engineering analysis, followed by acreage acquisition of leasehold rights and seismic permitting, and 3-D seismic field data acquisition, then processing of the data and finally its interpretation, 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 should allow the Company to consistently drill on a broad array of exploration prospects, as was demonstrated in 1999, and in subsequent years. In 1999, the Company participated in 29 new wells that reached total depth and were logged during the year. Of the total wells drilled and logged in 1999, 22 were productive and seven were dry holes. Only two of the 1999 wells were producing as of July 1, 1999 and, as a result, the Company's net daily oil and gas production increased substantially in the third and fourth quarters of 1999. Based upon estimated sustainable flow rates, the 1999 wells helped to increase the Company's net daily production to approximately 532 barrels of oil per day and 14,605 thousand cubic feet (mcf) of natural gas per day or 17,797 Mcf equivalent (mcfe) per day as of December 1999. The Company's net cost in the 29 wells drilled in 1999 was approximately $8,652,439 for drilling and completion, not including certain prior expenditures incurred at the project level for land and seismic. It should be noted that the Company defines a "project" as a distinct 3-D seismic data area that often comprises several distinct exploratory "prospects". Independently evaluated net proved reserves attributable to the 29 wells drilled in 1999 totaled 18,466,712 Mcfe, including 1999 production. By year end 1999, the Company had grown from nominal third quarter 1998 gas and oil revenues of approximately $35,000 per month and large operating cash flow deficits to a company that averaged $1,815,637 per month in net oil and gas revenues (and associated hedging revenues from commodity transactions) in the fourth quarter of 1999. Revenues increased significantly as the wells drilled in 1999 continued to come on line, which 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 of 1999, and increasing operating cash flow in the fourth quarter. As a result of this trend, approximately 56% of the Company's 1999 gas and oil revenue was attributable to the fourth quarter of the year. On September 23, 1999, the Company acquired, via merger, 3DX Technologies, Inc. ("3DX"). In connection with this transaction, Esenjay issued approximately 2,906,800 new shares of common stock, as well as approximately 357,000 shares of convertible preferred stock scheduled to be converted or redeemed (at the Company's option) not later than November 1, 2000. The Company redeemed the convertible preferred stock in September 2000 at a price of $1.925 per share for a total redemption price of approximately $687,200. OVERVIEW OF 2000 ACTIVITIES. The Company believes that it entered 2000 in a position to continue to expand its exploration activities on its technology-enhanced projects. By utilizing increased capital available to it from cash flow, financings and industry partner transactions, the Company is pursuing an aggressive exploration program in all of its major trends of activity. The Company's net production averaged 462 barrels of oil per day and 15,197 Mcf of natural gas per day in the first nine months of 2000. This net production is after a reduction of 6 barrels of oil per day and 1,981 Mcf of natural gas per day attributable to the sale of interests in the Raymondville Project as described in the following paragraph. In the third quarter of 2000, net production averaged 464 barrels of oil per day and 14,978 Mcf of natural gas per day. The Company currently anticipates its net daily production to increase to a range from 600 to 700 barrels of oil and a range from 22,000 to 25,700 Mcf of natural gas by year end 2000 as wells currently drilled come on line in the fourth quarter. 12 The Company also successfully improved its working capital and cash resources in 2000. On February 7, 2000, it announced the closure of a $29 million credit facility with Deutsche Bank AG, New York Branch. Initial availability pursuant to the facility was $21 million, with a borrowing base adjustment scheduled for the second quarter of 2000. A portion of the available proceeds was utilized to retire approximately $15.8 million of previously existing debt with Bank of America and Duke Energy Financial Services, Inc., of which approximately $11 million was classified as the current portion of long-term debt. The amount outstanding under the new facility was all classified as long term debt upon inception. $5,384,178 is classified as current portion as of September 30, 2000. The total available pursuant to the credit facility increased to $24.0 million in the third quarter 2000. In addition, the Company sold approximately 84.39% of its interest in its Raymondville Project in Willacy County, Texas to Cody Texas, L.P. for cash proceeds of $11,668,132 ($11,254,896 net of transaction fees). The sale closed on March 20, 2000 but was effective as of January 1, 2000. Pursuant to this sale the Company sold 3,462,967 Mcfe of its reserves classified as proved as of December 31, 1999. Its borrowing base availability with Deutsche Bank was not reduced. The combination of these two financing transactions made available $18.8 million in net additional cash resources (after repayment of existing debt) and created significant improvements in working capital for the Company. As a result of its current cash flow and the impact of these two transactions, the Company positioned itself to fund a substantial portion of its 2000 drilling activities, the results of which are intended to help continue the upward trends in cash flow and reserves. As newly drilled wells come on line in the fourth quarter of 2000, it expects significant increases in its net daily production as a result of its 2000 drilling activities. The Company will look to a variety of sources to further supplement its capital expenditures budget, including its credit facilities and sales of additional promoted project interests to industry partners, as it seeks to maximize its interests and manage its risks while aggressively pursuing its exploration projects. In the nine months ended September 30, 2000, the Company incurred approximately $14,015,000 in 2000 drilling and completion expenditures and $7,616,000 in 2000 for land and seismic costs. In the nine months ended September 30, 2000, the Company participated in the drilling of 43 new wells. Of the 43 new wells, 15 were producing, six were being completed or awaiting pipeline connections, 18 were dry holes and four were drilling as of September 30. The increase in dry holes in 2000 reflects the Company's shift in drilling emphasis to higher risk/reward prospects. On October 12, 2000 the Company finalized and closed an agreement with 420 Energy Investments, Inc. ("420") pursuant to which $864,000 in non-recourse debt and $562,034 in interest on non-recourse debt was satisfied. Consideration paid to 420 was $300,000 in cash, plus an agreement to pay to 420 cash payments on the date drilling may commence on any future wells it may drill on one exploration project area located in Terrebonne Parish, Louisiana. The Company has no obligation to drill any such future wells. Any such future payments would range from $20,000 per well to $100,000 per well, but would never exceed a total of $300,000. In addition, 420 retained its prior right to an overriding royalty equal to 2% of the Company's interest in any well drilled in the project area in Terrebonne Parish. One well is currently drilling in the project area. As a result of the transaction, the Company will recognize a gain in the fourth quarter of 2000. Settlement of the obligation also facilitated the commencement of the current drilling on the project. Certain projects of the Company were subject to an agreement with Seagull Energy E&P, Inc. ("Seagull"), a subsidiary of Ocean Energy, Inc., which agreement provided an option in favor of Seagull to acquire 50% of the Company's unproven interests in the Mikeska and Hall Ranch projects for $6.5 million, plus, at Seagull's option, 50% of the Company's unproven interests in the Orangedale, Verdad, Hordes Creek and Riverdale projects for an additional $2.0 million. The option was not exercised and it expired in the third quarter of 2000. On October 2, 2000 the Company announced it had retained Deutsche Bank Securities, Inc. to advise it concerning various strategic alternatives intended to better maximize shareholder value. It also retained the firm of Randall & Dewey, Inc. to initiate and manage a transaction to seek to better realize this value through various alternatives such as selling the Company for cash, merger, stock trade or acquisition. It intends to evaluate such possibilities as well as potential acquisitions by the Company with an objective of better maximizing shareholder value. It may or may not consummate any such transaction and does not intend to do so unless its board believed a substantial enhancement of shareholder value would be achieved. The Company has budgeted $18,000,000 in drilling and completion expenditures on its interests in over 45 13 wells and an additional $8,000,000 in land and new seismic costs in 2000. The budgeted drilling and completion expenditures, which are primarily for exploratory wells, compares to total drilling and completion expenditures of approximately $8,652,439 in 1999, when the Company had less capital available. Through this exploration program, the Company believes it will continue its trends of growth in net production, net revenues, operating cash flow and net gas and oil reserves. In particular, it believes that its exploratory drilling in the third quarter and the fourth quarter of 2000 through the date hereof has resulted in the addition of significant new gas and oil reserves. It anticipates its net daily production will grow to 25,000 to 30,000 mcfe before the end of the fourth quarter and continue to grow in early 2001 as a result of its exploration success. SUCCESSFUL EFFORTS ACCOUNTING AND RELATED MATTERS. The Company utilizes the successful efforts method of accounting. Under this method it expenses its exploratory dry hole costs and the field acquisition costs of 3-D seismic data as incurred. The undeveloped properties, which were acquired pursuant to the Acquisitions, were comprised primarily of interests in unproven 3-D seismic based projects, and were recorded in May of 1998 at an independently estimated fair market value of $54.2 million as determined by Cornerstone Ventures, L.P., a Houston, Texas based investment banking firm. Pursuant to the successful efforts method of accounting, the Company is amortizing such initial costs of unproved properties on a straight-line basis over a period not to exceed forty-eight months, as well as recognizing property specific impairments. As of September 30, 2000 the unamortized balance was $6,334,800. Hence significant non-cash charges have depressed reported earnings of the Company and will likely continue to do so in 2000; 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 will likely not be able to fully use its existing net operating loss carry forward in the future. RESULTS OF OPERATIONS The following table sets forth certain operating information of the Company during the periods indicated:
THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30 SEPTEMBER 30 2000 1999 2000 1999 ------------ ------------ ------------ ------------ PRODUCTION: Gas (Mcf)........................ 1,540,700 851,700 4,369,300 2,078,400 Oil and condensate (Bbls)........ 46,300 33,400 130,900 50,200 Total equivalent (Mcfe).......... 1,818,500 1,052,100 5,154,700 2,379,600 AVERAGE SALES PRICE:(2) Gas (per Mcf).................... $ 4.35 $ 2.45 $ 3.48 $ 1.81 Oil and condensate (per Bbl)..... $ 27.84 $ 14.66 $ 27.35 $ 11.22 AVERAGE EXPENSES (PER MCFE): Lease operating (1).............. $ 0.11 $ 0.10 $ 0.13 $ 0.20 Depletion of oil and gas properties: $ 1.52 $ 1.01 $ 1.39 $ 0.94
(1) Includes all direct expenses of operating the Company's properties, as well as production and ad valorem taxes. (2) Including the effects of hedging activities, the average gas and oil sales price was $3.71/mcf and $25.49/bbl for the three months ended September 30, 2000, and $2.34/mcf and $14.66/bbl for the three months ended September 30, 1999, respectively, and $3.11/mcf and $24.94/bbl for the nine months ended September 30, 2000 and $1.98/mcf and $11.22/bbl for the nine months ended September 30, 1999, respectively. THREE MONTHS ENDED SEPTEMBER 30, 2000 COMPARED WITH THREE MONTHS ENDED SEPTEMBER 30, 1999 REVENUE. Total revenues increased 68% from $4,615,422 in the third quarter ended September 30, 1999 to $7,760,087 in the third quarter ended September 30, 2000. This is primarily attributed to the factors set forth below. GAS AND OIL REVENUES. Total gas and oil revenues increased from $2,577,335 for the third quarter of 1999 to $7,983,234 for the third quarter of 2000,an increase of 210%. The increase is attributable to a combination of the 14 increase in commodity sales prices in the third quarter of 2000, as contrasted with 1999, and in an increase in the Company's net gas and oil production in 2000. The average gas sales price increased from $2.45 per Mcf in the third quarter of 1999 to $4.35 in the third quarter of 2000, and the average sales price per barrel of oil and condensate increased from $14.66 in the third quarter of 1999 to $27.84 in the third quarter of 2000. Net gas production increased from approximately 851,700 Mcf for the third quarter of 1999 to approximately 1,540,700 Mcf in the third quarter of 2000. Net oil and condensate production increased from approximately 33,400 barrels in the third quarter of 1999 to approximately 46,300 barrels in the third quarter of 2000. REALIZED GAIN (LOSS) ON COMMODITY TRANSACTIONS. In the third quarter of 1999, the Company realized a gain of $33,557 on commodity transactions, as contrasted with a loss of $1,680,669 in the third quarter of 2000. This entry results from actual commodity prices being greater or less than the Company's hedged price on natural gas or oil. This change is attributable to the increase in gas and oil prices such that the hedges currently in place on the Company's production portfolio were at lower prices for the third quarter of 2000 as contrasted with commodity prices in the third quarter of 1999 at which time a slight gain was realized. Although the Company has hedges in place at higher prices in the third quarter of 2000 than in the third quarter of 1999, commodity prices increased more resulting in the loss for the period. The Company currently has hedges in place in volumes that decrease quarterly and end at December 31, 2001. (See Liquidity and Capital Resources). GAIN ON SALE OF ASSETS. The gain on sale of assets in the third quarter of 2000 was $1,311,681, 32% below the gain on sale of assets reported in 1999. These gains are attributable to sales of interests to industry partners in certain of the Company's projects. The balance of the gain also includes any gain on sales of working interests to industry partners in wells anticipated to be drilled in the year 2000. OPERATING FEES. The 66% increase in revenue from operations from $69,803 in the third quarter of 1999 to $116,108 in the third quarter of 2000 is basically attributable to increased volume of activity. OTHER REVENUES. Other revenues in the third quarter of the year 2000 were comprised of interest income, which increased from $10,474 in the third quarter of 1999 to $29,733 in the third quarter of 2000. COSTS AND EXPENSES. Total costs and expenses of the Company increased 149% from $5,655,816 for the third quarter ended September 30, 1999 to $14,057,986 for the third quarter ended September 30, 2000. This is primarily due to changes discussed in the categories below. This total is significantly affected by the Company's successful efforts method of accounting and related factors. (See Overview - Successful Efforts Accounting and Related Matters) LEASE OPERATING EXPENSES. Lease operating expense increased 81% from $109,622 for the third quarter of 1999 to $198,745 for the third quarter of 2000. This is due to the increased number of producing wells owned by the Company. PRODUCTION TAXES. Production taxes increased 255% from $158,241 for the third quarter of 1999 to $561,678 for the third quarter of 2000. The increase in production taxes is primarily attributable to revenues from wells placed on production in late 1999 and early 2000 and increases in product prices. DEPRECIATION, DEPLETION AND AMORTIZATION ("DD&A"). Depreciation, depletion and amortization ("DD&A") increased 160% from $1,065,641 for the third quarter of 1999 to $2,772,310 for the third quarter of 2000. The increase in DD&A was attributable to increased production values. AMORTIZATION OF UNPROVED PROPERTIES. Amortization of unproved properties decreased from $1,692,600 for the third quarter of 1999 to $1,294,400 for the third quarter of 2000. The decline resulted from reductions in the book value of the amortizable assets due to the transfer of costs to proven properties and the sale of interests in certain projects. The Company is amortizing the undeveloped and unevaluated value of the properties acquired pursuant to the 1998 Acquisitions over a period not to exceed forty-eight months. (See "Overview Successful Efforts Accounting and Related Matters"). 15 IMPAIRMENT OF ASSETS. The Company recognized impairments of $941,639 for the three months ended September 30, 2000 as compared to $358,106 for the three months ended September 30, 1999. This impairment is a non-cash charge based upon the expected recoverability of the book value of individual projects. EXPLORATION COSTS - GEOLOGICAL AND GEOPHYSICAL. Exploration costs - -geological and geophysical increased 911% from $280,896 for the third quarter of 1999 to $2,839,217 for the third quarter of 2000. 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. Included in the 2000 charge was $3,354,112 in costs related to the acquisition of new exploratory seismic data during the period. EXPLORATION COSTS - DRY HOLE. Exploration costs - dry hole increased 892% from $332,820 for the third quarter of 1999 to $3,300,617 in the third quarter of 2000. The increase is attributable to the increased drilling activity. INTEREST EXPENSE. Interest expense increased 38% from $212,538 for the third quarter of 1999 to $292,759 for the same period 2000 due to increased loans outstanding. The Company capitalized interest costs of $324,142 in the third quarter of 1999 and $164,398 in the third quarter of 2000 that were associated with its ongoing projects. GENERAL AND ADMINISTRATIVE EXPENSES. General and administrative expenses increased 33% from $1,266,805 for the third quarter of 1999 to $1,678,855 for the third quarter of 2000. This increase was primarily attributable to payment of $180,870 in cash bonus payments during the quarter pursuant to a Company-wide bonus program based upon 1999 drilling results. There was no plan the prior year. NET LOSS PER COMMON SHARE. Net loss per common share increased from a net loss of $0.06 per share for the third quarter of 1999 to a net loss of $0.33 per share for the third quarter of 2000. Due to the factors enumerated above, there was a increase in net loss applicable to common stockholders of $5,257,525 from the third quarter of 1999 to the third quarter of 2000. Approximately 18,883,000 weighted average common equivalent shares were outstanding at September 30, 2000, as compared with approximately 16,062,000 at September 30, 1999, which further influenced the change in net loss per share in 2000. NINE MONTHS ENDED SEPTEMBER 30, 2000 COMPARED WITH NINE MONTHS ENDED SEPTEMBER 30, 1999 REVENUE. Total revenues increased 276% from $6,858,991 in the nine months ended September 30, 1999 to $25,809,640 in the nine months ended September 30, 2000, due to the factors listed below. GAS AND OIL REVENUES. Total gas and oil revenues increased from $4,334,441 in the nine months ended September 30, 1999 to $18,903,840 in the nine months ended September 30, 2000. This increase is primarily attributable to wells placed on production in late 1999 and throughout 2000, which resulted in an increase in the Company's net production. It was further impacted by general increases in commodity prices, which became more pronounced in September 2000. REALIZED GAIN (LOSS) ON COMMODITY TRANSACTIONS. The Company realized a loss from various commodity transactions of $2,985,847 for the nine months ended September 30, 2000. This contrasted with a net gain of $231,580 in the first nine months of 1999. These gains and losses result from actual commodity prices for the period being greater or less than the Company's hedge prices on natural gas or oil. Although the Company has hedges in place at higher prices in the first nine months of 2000 than in the first nine months of 1999, commodity prices increased by a greater amount, resulting in the loss for the period. GAIN ON SALE OF ASSETS. There was an increase in gain on sale of assets from $2,034,905 for the nine months ended September 30, 1999 to $9,468,399 for the nine months ended September 30, 2000. The increase was due to the closing of various project interest sales to third parties. The majority of the 2000 gain was attributable to recognition of a $1,797,707 gain on the sale of interests in the Papalote Project to an industry partner and the $6,822,240 gain on the sale of the Company's Raymondville Project. 16 OPERATING FEES. The increase in revenue from operating fees from $223,154 in the first nine months of 1999 to $341,586 in the first nine months of 2000 is attributable to the increased volume of the Company's activity. OTHER REVENUES. The increase in other revenues from $34,911 in the first nine months of 1999 to $81,662 in the first nine months of 2000 was attributable to an increase in interest income. COSTS AND EXPENSES. Total costs and expenses of the Company increased 91% from $16,488,765 for the nine months ended September 30, 1999 to $31,568,633 for the nine months ended September 30, 2000. This total is significantly affected by the Company's successful efforts method of accounting and related factors. (See Overview - Successful Efforts Accounting and Related Matters.) The primary factors are set forth below. AMORTIZATION OF UNPROVED PROPERTIES. Amortization of unproved properties was $4,176,000 for the nine months ended September 30, 2000 compared to $6,050,600 in the first nine months of 1999. The 31% decrease in 2000 was attributable to reductions in the basis of properties being amortized due to certain property costs being moved to the proven property category or certain properties having been sold and the basis therefor removed from the amortization pool. The Company will amortize the undeveloped and unevaluated value of the properties acquired pursuant to the 1998 Acquisition over a period not to exceed forty-eight months. (See "Overview Successful Efforts Accounting and Related Matters"). IMPAIRMENT OF ASSETS. The Company recognized impairments of $983,628 for the nine months ended September 30, 2000 as compared to $358,106 for the nine months ended September 30, 1999. The impairment is a non-cash charge based upon the expected recoverability of the book value of individual projects. GENERAL AND ADMINISTRATIVE EXPENSES. General and administrative expenses increased 19% from $4,348,901 for the nine months ended September 30, 1999 to $5,176,476 for the nine months ended September 30, 2000. This increase was primarily due to $762,804 in cash bonus payments made pursuant to a Company-wide bonus based upon 1999 drilling results. DEPLETION, DEPRECIATION AND AMORTIZATION ("DD&A"). Depletion, depreciation and amortization ("DD&A") increased 221% from $2,241,468 for the nine months ended September 30, 1999 to $7,185,419 for the nine months ended September 30, 2000. The increase in DD&A was primarily attributed to increased production volumes. LEASE OPERATING EXPENSES. Lease operating expenses increased 39% from $482,210 for the nine months ended September 30, 1999 to $672,618 for the nine months ended September 30, 2000. The increase in lease operating expenses relates primarily to operational cost for the increased number of Company's producing wells. INTEREST EXPENSE. Interest expense increased 64% from $520,977 for the nine months ended September 30, 1999 to $853,394 for the nine months ended September 30, 2000. The increase in interest expense was attributable to increased borrowing pursuant to its credit facility. The Company capitalized interest costs of $898,261 in the nine months ended September 30, 1999 and $311,087 in the nine months ended September 30, 2000 that were associated with on-going projects. PRODUCTION TAXES. Production taxes increased 398% from $273,475 for the nine months ended September 30, 1999 to $1,360,712 for the nine months ended September 30, 2000. This increase in production taxes was attributed to revenues of wells placed in production late 1999 and early 2000. Increases in both production volumes and product sales prices contributed to the increase. EXPLORATION COSTS - GEOLOGICAL AND GEOPHYSICAL. Exploration costs - -geological and geophysical increased 191% from $1,565,374 for the nine months ended September 30, 1999 to $4,550,324 for the nine months ended September 30, 2000. The increase resulted from an increase in the acquisition of new 3-D seismic field data in 2000. 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. 17 EXPLORATION COSTS - DRY HOLE. Exploration costs - dry hole increased 1,464% from $398,098 for the nine months ended September 30, 1999 to $6,225,277 for the nine months ended September 30, 2000. The increase is attributable to the increased drilling activity and the Company's exposure to higher cost exploration wells. NET INCOME (LOSS) PER COMMON SHARE. Net income per common share decreased from a net loss of $0.61 per share for the nine months ended September 30, 1999 to a net loss of $0.31 per share for the nine months ended September 30, 2000. Due to factors mentioned above, there was an increase in net income applicable to common stockholders of $3,870,781 from the nine months ended September 30, 1999 as compared to the nine months ended September 30, 2000. Approximately 18,864,000 weighted average common equivalent shares were outstanding for the nine months ended September 30, 2000 as compared with approximately 15,881,000 at September 30, 1999, which further influenced the change in net income per share in 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 the projects acquired in the Acquisitions and the acquisition of 3DX, as well as its other projects developed by the Company. Management continues to believe these projects represent the most promising prospects in the Company's history. The wells drilled in 1998, 1999 and 2000 on projects acquired pursuant to the 1998 Acquisitions continue to increase the Company's year 2000 revenues as compared with 1999. It expects its net daily oil and gas production to increase substantially by the end of the fourth quarter as a direct result of its drilling activities in the second half of 2000. The capital expenditures being planned for 2001 will continue to require substantial outlays of capital to explore, develop and produce. Drilling results for 1998 resulted in substantial revenue increases. Drilling results in 1999 resulted in rapidly expanding revenues in the third and fourth quarters of 1999. Revenues expanded in the first nine months of 2000 as gas and oil prices increased. Oil and gas revenue growth should accelerate in late 2000 and early 2001, provided that there is no large downward movement in product prices. However, because the Company expects to increase its 2001 drilling budget, capital from sources other than cash flow from operations may be required to fund capital expenditures, including cash on hand and anticipated available credit. The trend of increasing revenues was slowed in early 2000 by (1) the sale of the Raymondville Interests, effective January 1, 2000, which reduced production by approximately 2,000 Mcfe per day, (2) production problems incurred on one well early in the second quarter, which resulted in a reduction of approximately 2,300 Mcf and 126 bbls of oil per day, and (3) natural production declines. Anticipated growth in revenue will be dependent upon production from drilled wells projected to come on line late in 2000, the Company's continued drilling success on wells currently drilling and to be drilled through 2001, and future oil and gas prices. LIQUIDITY AND CAPITAL RESOURCES The Company 2000 business plan provided for net expenditures of $18,000,000 in drilling and completion and $8,000,000 in land and geophysical costs resulting in a $26,000,000 capital budget for 2000. In the nine month period ended September 30, 2000, the Company incurred approximately $14,015,000 in drilling and completion costs, which costs were partially offset by $2,158,649 in cash fees paid to the Company from industry partners for interests in the wells drilled. The Company also incurred approximately $7,616,000 in land and geophysical costs in the nine month period. The geophysical costs were partially offset by cash fees paid or due to the Company by industry partners in conjunction with 3-D surveys, including a $1,166,666 fee paid by one partner in the second quarter. These budgeted amounts are based upon exploration opportunities and may be adjusted based upon available capital, new opportunities and industry conditions. The Company believes its capital spending will be consistent with the budget in 2000. The Company's sources of financing include borrowing capacity under its credit facilities, the sale of promoted interests in the Exploration Projects to industry partners and cash provided from operations. The Company's 2000 budget includes the sales of certain project interests to industry partners. The Company entered 1999 having gone from nominal second quarter 1998 gas and oil production revenues of approximately $35,000 per month and large operating cash flow deficits to a company which averaged $1,815,637 per month in oil and gas revenues (including realized revenue from hedges on production) in the fourth quarter of 1999. 18 These revenues averaged $1,754,884 per month in the first quarter of 2000; however, $122,884 of this average was attributable to adjustments to prior periods and the average gas and oil revenues attributable to actual first quarter 2000 production was $1,632,000 per month. This was achieved despite the sale of interests in the Raymondville Project, which sale was effective January 1, 2000. Second quarter gas and oil revenues averaged $1,885,317 per month. Third quarter gas and oil revenues increased to average $2,661,078 per month. The Company believes its fourth quarter 2000 average daily production from existing wells will show substantial growth as drilled wells come on line during the quarter. Additional success in 2000 on wells currently drilling, if obtained, would result in continued increases in production in early 2001. The Company ended 1999 with a deficit working capital of approximately $16,543,374. Of this amount, approximately $11.0 million represented the current portion of its long term debt. This working capital deficit greatly improved when the Company, on January 25, 2000, closed a new credit facility with Deutsche Bank AG, New York Branch. Pursuant to this facility, all of the $15.8 million of the Company's long term debt at December 31, 1999 was repaid. This repayment included $4.8 million of long term debt classified as long term and the repayment of approximately $11.0 million of long term debt classified as current. Pursuant to the Deutsche Bank credit facility, $21 million was initially available. This was increased at mid year to $24 million. All amounts available were initially long term debt. $5,384,178 is classified as current portion at September 30, 2000, but is not due until 2001. The credit facility with Deutsche Bank is in two tranches. $12 million was initially available under Tranche A, and $9 million under Tranche B. Tranche A was increased to $15.0 million. Tranche A is a revolving facility with no required principal payments until January 24, 2001, after which date it is scheduled to convert into a five year term loan. The Company intends to ask the bank to extend the Tranche A maturity in order to allow additional cash resources to be available to fund the 2001 capital budget. Tranche B is payable interest only until the second quarter of 2001, at which time the principal is amortized at a rate of 25% per quarter until fully repaid. Both loans are at a varied interest rate utilizing either Deutsche Bank's alternative interest rate or the London interbank rate plus 2% for both Tranche A and Tranche B. As of November 10, 2000, $8,841,782 was drawn under Tranche A and $9 million under Tranche B. Undrawn funds will be available for future activities of the Company. The facility is secured by a mortgage on most of the 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 closing. The agreement also requires the Company to convey to the bank a 1.5% overriding royalty interest, proportionately reduced to the Company's net interest, on future proven wells on the date any such future wells are logged, for as long as funds are outstanding pursuant to Tranche B. In the event the Tranche B loans are repaid in full prior to April 30, 2002, the Company may redeem the overriding royalty interests conveyed to Deutsche Bank AG for an amount equal to (a) an amount which, when added to the interest paid to Deutsche Bank AG, plus revenues received by Deutsche Bank AG from the overriding royalties conveyed to Deutsche Bank AG, would provide to Deutsche Bank AG an internal rate of return of approximately 15%, plus (b) 60% of the then remaining present value of the overriding royalties to be redeemed after subtracting the amount calculated in (a) above. In addition, Deutsche Bank also received a five-year warrant to purchase 250,000 shares of the Company's common stock at a price equal to $1.50 per share. Proceeds of the credit facility were utilized to retire the Company's existing long-term debt and additional proceeds can be utilized to supplement working capital and exploration costs. The Company expects further increases in the borrowing base of its credit facility with Deutsche Bank when its proven gas and oil reserves are updated at December 31, 2000. The Company believes that it is reasonable to anticipate that Tranche A availability under the credit facility will expand such that Tranche B obligations to the bank can be funded from Tranche A credit increases. This would allow more of its cash flow to be expended on its 2001 capital budget. The Company's working capital was further enhanced when it closed a sale of project interests to Cody Texas, L.P. for an amount net to the Company totaling approximately $11,254,905 on March 20, 2000. In this sale, the Company conveyed 84.39% of its net interest in its Raymondville Project in Willacy County, Texas to Cody Texas, L.P. The Company's borrowing base pursuant to Tranche A with Deutsche Bank was not reduced as a result of the sale. The proceeds of the sale of interests to Cody Texas, L.P. were utilized to increase working capital, to reduce outstanding amounts under the revolving borrowing base available to the Company pursuant to Tranche A of the Deutsche Bank facility, and to fund capital expenditures of the Company. 19 In the second quarter of 2000, the Company finalized bonuses to employees for results achieved in 1999. The bonuses were primarily based upon drilling results achieved and the drilling and completion costs incurred to achieve the results. The Company achieved a significant return on drilling and completion costs incurred in 1999. The bonuses were paid in two installments. $581,934 was paid in the second quarter of 2000 and $180,870 was paid in the third quarter. The Company believes that in 2000 it has achieved a much more desirable liquidity position than it has experienced since the consummation of the Acquisitions in May of 1998. Improvements in its working capital position, which have resulted from the closing of the facility with Deutsche Bank and the sale to Cody Texas, L.P., combined with the Company's increased cash flow, place it in a good position to significantly fund its year 2000 capital expenditures budget from cash, currently available credit and anticipated operating cash flow. It expects its net daily production to increase substantially by year end as currently drilled wells come on line. This would result in substantial revenue increases, which would provide substantial funding for its 2001 capital budget. Such revenue increases could be reduced or increased by any substantial change in product prices. Given its current preliminary estimate of a 2001 capital expenditure budget of over $30 million, the Company may still depend upon some sales or other transactions with industry partners to fund the budget. Its ongoing business plan is to always implement such transactions in order to properly manage the spread of risk in its drilling activities as well as to be a source of capital expenditure funds. Pursuant to the Company's credit agreement with Deutsche Bank, it has certain covenants regarding current interest coverage ratios and other covenants regarding which it is expected to be in compliance at the end of each quarter. Although the Company believes it will be in compliance with these covenants in the years 2000 and 2001, there can be no assurance that it will be in compliance. In the event it is not in compliance, the Company will be required to seek waivers of said covenants or would be required to seek alternative financing arrangements. The Company was in compliance at September 30, 2000. 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 September 2000, 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 had an ambitious capital expenditure plan for 2000, which included approximately $18,000,000 in drilling and completion costs, and an additional $4,600,000 and $3,600,000, respectively, in geological and geophysical and land costs for the year. In the first nine months, the Company incurred approximately $14,015,000 in drilling and completion costs and approximately $7,616,000 in geological and geophysical costs and land costs. The Company now expects budgeted capital costs in the fourth quarter to be exceeded and anticipates an expanded capital budget in 2001. Cash on hand, cash currently available pursuant to the Deutsche Bank credit facility and cash flow from operations will contribute significantly to said budgets. The Company anticipates that its availability pursuant to Tranche A of its credit facility will expand such that it can pay Tranche B obligations due in 2001 from Tranche A available funds. This would require increases in availability and resetting of the maturity date of its Tranche A facility, which it believes are reasonable anticipations based upon increases in the Company's gas and oil reserves. If Tranche A is modified as expected, the Company anticipates increased oil and gas revenue will provide cash flow to substantially fund 2001 anticipated capital costs. Many of the factors that may affect the Company's future operating performance and long-term liquidity are beyond the Company's control, including, but not limited to, oil and natural gas prices, governmental actions and taxes, the availability and attractiveness of financing and its operational results. The Company continues to examine alternative sources of long-term capital, including the acquisition of a company with producing properties for common stock or other equity securities, and also including bank borrowings, the issuance of debt instruments, the sale of common stock or other equity securities, the issuance of net profits interests, sales of promoted interests in its Exploration Projects, and various forms of joint venture financing. In addition, the prices the Company receives for its future oil and natural gas production and the level of the Company's production will have a significant impact on 20 future operating cash flows. It also seeks to be aware of any consolidation opportunities with other companies that may help increase shareholder value. On October 2, 2000 the Company announced it had retained Deutsche Bank Securities, Inc. to advise it concerning various strategic alternatives intended to better maximize shareholder value. It also retained the firm of Randall & Dewey, Inc. to initiate and manage a transaction to seek to better realize this value through various alternatives such as selling the Company for cash, merger, stock trade or acquisition. It intends to evaluate such possibilities as well as potential acquisitions by the Company with an objective of better maximizing shareholder value. It may or may not consummate any such transaction, and does not intend to do so unless its board believed a substantial enhancement of shareholder value would be achieved. 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 currently has natural gas hedges in place covering 13,278 MMBtu of gas production in the fourth quarter of 2000 at a weighted average price of $3.297 per MMBtu. It has hedges in place covering 12,161 MMBtu of gas production in the first quarter of 2001 at a weighted average price of $3.091 per MMBtu. It has hedges in place covering 11,880 MMBtu of gas production in the second quarter of 2001 at a weighted average price of $3.107 per MMBtu. It has hedges in place covering 11,600 MMBtu of gas production in the third quarter of 2001 at a weighted average price of $3.122 per MMBtu. It has hedges in place covering 11,319 MMBtu of gas production in the fourth quarter of 2001 at a weighted average price of $3.139 per MMBtu. The Company also has hedges on oil production at a price of $21.03 per barrel. Volumes at this price are 238 barrels of oil per day in the fourth quarter of 2000 and volumes of 175, 168, 161 and 154 barrels of oil per day for the first through fourth quarters of 2001, respectively. The Company currently has no hedges in place for periods beyond December 31, 2001. WORKING CAPITAL. At September 30, 2000, the Company had a cash balance of $386,940, total current assets of $15,659,540, and total current liabilities of $22,576,853. This resulted in a working capital deficit of $6,917,313. The Company expects its trend of increasing gas and oil revenues and associated hedging revenues from commodity transactions will continue the growth in revenues in excess of the ongoing costs of operations, which may also enhance the Company's working capital position. Conversely, the Company utilizes excess cash to reduce its revolving line of credit, which may result in lower reported working capital than would be reported were it to utilize more long-term debt, but does not affect available cash resources. Tranche B of the Deutsche Bank facility begins amortizing at a rate of 25% of the principal per quarter in the second quarter of 2001. Tranche A is scheduled to amortize over four years beginning in the first quarter of 2001; however, the intention of the Company is to request the extension of the commencement of the Tranche A amortization period. The net working capital can be negatively effected by the Company's continuing aggressive capital expenditures program on its exploration projects to the extent said capital expenditures exceed cash generated from operations and from the sale of project interests and/or growth in its credit facilities. SUMMARY. The Company believes it is positioned to continue to expand its exploration activity on its technology-enhanced projects. Many of the projects have reached the drilling stage. In many instances, the requisite process of geological and/or engineering analysis, followed by acreage acquisition of leasehold rights and seismic permitting and 3-D seismic field data acquisition, then processing of the data and finally its interpretation took several years of time and the investment of significant capital. Management believes the acquisition of projects at this advanced stage has not only reduced the drilling risk, but should allow the Company to consistently drill on a broad array of exploration prospects throughout 2000 and beyond. As evidence of this activity the Company participated in the drilling of 43 wells on its exploration projects in the first nine months of 2000, not including wells commenced after September 30. The addition of wells drilled in 1999 and 2000 to producing status increased the Company's net daily production to an average of approximately 17,969 MCFE per day in the nine months ended September 30. The net production averaged 17,762 MCFE per day in the third quarter. The Company expects net daily production to be at least 25,000 to 30,000 MCFE per day prior to year end 2000 as additional drilled wells come on line. The Company expects that the associated revenues will provide 21 positive growing operating cash flow throughout 2001 (prior to capital expenditures and new 3-D seismic data acquisition costs, which costs the successful efforts accounting method utilized by the Company mandates to be expensed rather than capitalized). The Company's 1999 and 2000 drilling results have further served to increase its confidence in its future drilling on the technology enhanced Exploration Projects. Additional exploration success would continue this positive trend. The Company expects to fund significant portions of its 2001 drilling and completion budget from operating cash flow (i.e., cash flow calculated prior to successful efforts reduction for dry hole capital expenditures and new expensed 3-D seismic data acquisition costs). It expects the 2001 capital budget to exceed its 2000 capital budget of about $18,000,000. It also expects to continue to acquire new seismic data and leasehold. The Company will utilize a variety of sources to fund its continuing capital expenditures budget including operating cash flow, currently available credit facilities and certain sales of promoted project interests to industry partners, as it seeks to maximize its interests and manage its risks while aggressively pursuing its exploration projects. The Company intends to aggressively pursue its exploration plan in 2001 while continuing to enhance its project inventory through its ongoing acquisition of 3-D seismic-enhanced opportunities. It will also focus on any potential merger or acquisition, which it believes, can enhance shareholder value through expansion of exploration opportunities or increased economies of scale. 22 PART II - OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS The Company currently has no action filed against it other than ordinary routine litigation. ITEM 2. CHANGES IN SECURITIES. In the nine months ended September 30, 2000 and in the fourth quarter through November 10, 2000, the Company has issued 51,742 and 3,431 shares, respectively, of its common stock pursuant to its employees' 401-K plan. The shares represent the employer's pro rata match of employee contributions. It also sold 84,000 shares of common stock comprised of 12,000 shares to each of seven of its directors. The shares were part of an overall compensation package for its directors, which package included stock options as further described in Item 10 located at Part III of the Company's report on Form 10-KSB/A for the year ended December 31, 1999 dated April 28, 2000. The price per share paid by Directors was $1.83 per share payable one third upon subscription, one third on or before May 14, 2000 and one third on or before May 15, 2001. The shares issued pursuant to the 401-K plan and to the Directors have been registered in the fourth quarter of 2000. ITEM 3. DEFAULTS UPON SENIOR SECURITIES. None. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. On September 28, 2000, the annual meeting of shareholders of Esenjay Exploration, Inc. was held. At that meeting the shareholders voted as follows: a) The following directors were elected (by the vote indicated) at such meeting:
Name of Nominee Number of Number of Number of Shares Voted For Shares Voted Against Shares Abstained Alex M. Cranberg 16,804,540 0 166,194 Michael E. Johnson 16,923,173 0 47,561 Jack P. Randall 16,916,572 0 54,162 b) To approve and adopt the Long-Term Incentive Plan For 10,783,136 Against 2,056,341 Abstain 15,010
ITEM 5. OTHER INFORMATION. None. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K. (a) Exhibits (11) Computation of Earnings Per Common Share (27.1) Financial Data Schedule (b) Reports on Form 8-K Form 8-K filed October 2, 2000 is incorporated herein by reference. 23 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf of the undersigned thereunto duly authorized. ESENJAY EXPLORATION, INC. Date: November 14, 2000 By: /S/ MICHAEL E. JOHNSON ------------------------------- MICHAEL E. JOHNSON, President, Chief Executive Officer and Director Date: November 14, 2000 By: /S/ DAVID B CHRISTOFFERSON ------------------------------- DAVID B. CHRISTOFFERSON, Senior Vice President, General Counsel, Principal Financial Officer Date: November 14 , 2000 By: /S/ ANGELA D. CONWAY ------------------------------- ANGELA D. CONWAY, Controller 24 EX-11 2 a2030797zex-11.txt EXHIBIT 11 EXHIBIT 11 TO FORM 10QSB ESENJAY EXPLORATION, INC. COMPUTATION OF EARNINGS PER COMMON SHARE
Three months ended September 30, Nine months ended September 30, 2000 1999 2000 1999 ---------------- -------------- ------------- ---------------- BASIC EARNINGS PER SHARE Weighted average common shares Outstanding.................................... 18,883,393 16,062,302 18,863,839 15,881,590 ================ ============== ============= ================ Basic loss per share......................... ($0.33) ($0.06) ($0.31) ($0.61) ================ ============== ============= ================ DILUTED EARNINGS PER SHARE Weighted Average Common Shares Outstanding................................... 18,883,393 16,062,302 18,863,839 15,881,590 Shares issuable from assumed conversion of Common share options and warrants............ 805,340 7,500 775,389 7,500 Convertible preferred stock.................. 356,999 27,163 356,999 9,154 ---------------- -------------- ------------- ---------------- Weighted average common shares Outstanding, as adjusted....................... 20,045,731 16,096,965 19,996,227 15,898,244 ================ ============== ============= ================ Diluted loss per share....................... ($0.31) ($0.06) ($0.29) ($0.61) ================ ============== ============= ================ EARNINGS FOR BASIC AND DILUTED COMPUTATION Net loss........................................... ($6,297,899) ($1,040,374) ($5,758,993) ($9,629,774) Preferred share dividends.......................... --- --- --- --- ---------------- -------------- ------------- ---------------- Net loss to common shareholders (Basic and diluted earnings per share computation).............................. ($6,297,899) ($1,040,374) ($5,758,993) ($9,629,774) ================ ============== ============= ================
EX-27.1 3 a2030797zex-27_1.txt EXHIBIT 27.1
5 9-MOS DEC-31-2000 JAN-01-2000 SEP-30-2000 386,940 0 14,316,784 (445,872) 0 15,659,540 80,176,102 (34,546,687) 62,536,922 22,576,854 12,457,604 0 0 188,894 25,887,537 62,536,922 18,903,839 23,809,640 0 30,715,239 0 0 853,394 (5,758,993) 0 (5,758,993) 0 0 0 (5,758,993) (0.33) (0.31)
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