-----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, BfddPb4tlE/g8QZr0t0oSV18QLXdOl181Wg5qUce21+L+qo1/SJjH/sHh247Vu3J ZCIw2CzLViypyCzex44YPw== 0000313395-99-000023.txt : 19991125 0000313395-99-000023.hdr.sgml : 19991125 ACCESSION NUMBER: 0000313395-99-000023 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19990831 FILED AS OF DATE: 19991124 FILER: COMPANY DATA: COMPANY CONFORMED NAME: EXPLORATION CO CENTRAL INDEX KEY: 0000313395 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 840793089 STATE OF INCORPORATION: CO FISCAL YEAR END: 0831 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 000-09120 FILM NUMBER: 99763345 BUSINESS ADDRESS: STREET 1: 500 N LOOP 1604 EAST STREET 2: SUITE 250 CITY: SAN ANTONIO STATE: TX ZIP: 78232 BUSINESS PHONE: 2104965300 MAIL ADDRESS: STREET 1: 500 N LOOP 1604 E STREET 2: SUITE 250 CITY: SAN ANTONIO STATE: TX ZIP: 78232 10-K 1 FORM 10-K FOR THE YEAR ENDED AUGUST 31, 1999 1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark one) x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Fiscal Year Ended August 31, 1999 o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File Number 0-9120 THE EXPLORATION COMPANY OF DELAWARE, INC. (Exact name of Registrant as specified in its charter) Delaware 84-0793089 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 500 North Loop 1604 East, Suite 250, San Antonio, Texas 78232 (Address of principal executive offices) Registrant's telephone number, including area code: (210) 496-5300 Securities registered pursuant to Section 12(b) of the Act: None Securities registered pursuant to Section 12(g) of the Act: Common Stock, par value $0.01 per share 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-K 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-K or any amendment to this Form 10-K. The aggregate market value of the voting stock (which consists solely of shares of Common Stock) held by non-affiliates of the registrant is $24,261,231 based upon the average of the high and low bid price of such stock as reported by the NASDAQ Small-Cap Market under the symbol TXCO on November 1, 1999. The number of shares outstanding of the Registrant's Common Stock as of November 1, 1999 was 15,938,516 of which 13,381,815 shares were held by non-affiliates. Documents Incorporated by Reference: None 2 INDEX AND CROSS REFERENCE SHEET
PART I Page Item 1. Business..................................................................................... 3 Item 2. Properties................................................................................... 9 Item 3. Legal Proceedings............................................................................ 14 Item 4. Submission of Matters to a Vote of Security Holders.......................................... 14 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.................................................................. 15 Item 6. Selected Financial Data...................................................................... 15 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations........................................................................ 16 Item 7A. Quantitative and Qualitative Disclosures About Market Risk................................... 21 Item 8. Financial Statements and Supplementary Data ................................................. 21 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure......................................................................... 21 PART III Item 10. Directors and Executive Officers of the Registrant........................................... 22 Item 11. Executive Compensation....................................................................... 23 Item 12. Security Ownership of Certain Beneficial Owners and Management............................................................................... 25 Item 13. Certain Relationships and Related Transactions............................................... 26 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.......................................................................... 26 Signatures................................................................................................ 28 Audited Financial Statements of The Exploration Company.................................................. F-1
3 PART I ITEM 1. BUSINESS GENERAL DEVELOPMENT OF BUSINESS The Exploration Company (the "Company" or "TXCO") was incorporated in the State of Colorado on May 16, 1979, for the purpose of engaging in oil and gas exploration, development and production and became publicly held through an offering of its common stock in November, 1979. In May 1999, the Company changed its state of incorporation from Colorado to Delaware, becoming The Exploration Company of Delaware, Inc. The Company continues doing business as The Exploration Company and its trading symbol on the Nasdaq Stock MarketSM remains TXCO. Throughout its history, the Company's primary focus has been oil and gas exploration and production. Its long term business strategy has been to acquire undeveloped mineral interests and to develop a multi-year inventory of drilling prospects internally through the application of state of the art technologies, such as 3-D seismic and enhanced horizontal drilling techniques. The Company strives to discover, develop and/or acquire more oil and gas reserves than it produces each year from these internally-developed prospects, as well as selectively participating with industry partners in prospects generated by TXCO as well as by other parties. The Company also attempts to maximize the value of its technical expertise by contributing its geological, geophysical and operational knowledge base in its core area through joint ventures or forms of strategic alliances with well capitalized industry partners in exchange for carried interests in seismic acquisitions, leasehold purchases and/or wells to be drilled. From time to time, the Company offers portions of its developed and undeveloped mineral interests for sale. The Company finances its activities through a combination of debt financing, equity offerings and internally generated cash flow. When appropriate, the Company may also use its equity securities as all or part of the consideration for operating investments. Prior to 1992, the Company's revenues were derived principally from the sale of natural gas and oil production from working, royalty and mineral interests, as well as the sale of the mineral interests it acquired through its leasing activities. From 1992 through 1996 the Company expanded its activities by entering the then emerging alternative fuels vehicle conversion business through the creation of its ExproFuels division. In 1996, management redirected its focus and resources to its core oil and gas exploration and production business. Accordingly, the ExproFuels division was incorporated and a majority equity interest spun-off via a stock dividend to TXCO shareholders. The continuing availability of new equity and debt capital to The Exploration Company during fiscal years 1997, 1998 and 1999 reaffirmed Management's expectations for improved shareholder value by focusing on its core business of oil and gas exploration and production. Although profitability was not attained through fiscal year 1998, operating results included a 195% increase in oil and gas revenues and a 183% increase in proved oil and gas reserves over 1997 levels while establishing positive cashflow from operations. Earnings before interest, taxes, depreciation, depletion, amortization, impairment and exploration expenses (EBIDAX) increased to $989,484. Based on the growth of its operations in the prior two years, TXCO started 1999 with great expectations. We have not been disappointed. Although not reflected in its stock trading levels, for the year ended August 31, 1999, the Company realized the best operating results in its 20 year history, reaching profitability during the 1st quarter and ending its record breaking 1999 fiscal year with revenues of over $7,497,000 and net income of $931,000. In addition to reaching book profitability, EBIDAX surged to an all time high of $4,793,000. TXCO overcame the weakness in oil and gas prices during the first half of fiscal 1999, extending its strong growth trend through its drilling success and operational efficiencies. The Company realized a 146% increase in gross operating revenues, a 246% increase in production volumes and a 70% increase in oil and gas leasehold acreage in its core producing area. New reserve additions from 1999 drilling discoveries effectively replaced the record volume of gas and oil produced for the year, and together with improving oil and gas prices during the last half of the year, resulted in a 41% increase in the discounted present value (PV-10) of proved producing oil and gas reserves for the year. 4 TXCO has succeeded in leveraging its current success, positioning itself to further accelerate growth in fiscal years 2000 and 2001. In addition to planned new drilling in fiscal 2000 utilizing internally generated working capital, two new strategic alliances were initiated near year end which together are expected to provide TXCO with a substantial benefit from upwards of $17,000,000 in mineral leasing, 3-D seismic acquisition and exploration drilling expenditures over a 2 year period. The expenditures are targeted to develop and drill at least 12 additional Glen Rose patch reef drilling prospects in fiscal 2000 and to expand and update TXCO's 3-D seismic database to further define and then drill on a deep Jurassic Formation prospect before the end of 2000. The potential natural gas reserves of the deep Jurassic Formation could increase the Company's existing proved producing reserve base significantly. Should these exploration and development plans progress as intended, The Exploration Company expects to continue its strong growth in gas reserves, revenues and profitability well into the new millenium. PRINCIPAL AREAS OF ACTIVITY Oil and Gas Operations Throughout the year, the Company has been actively developing its core mineral interests in the Maverick Basin in South Texas, while evaluating its economic alternatives related to its remaining properties in North Dakota, South Dakota and Montana. These activities included participation in the drilling of 10 gas wells in South Texas during 1999. The increase in Maverick Basin drilling activity reflects the Company's continued ability to generate sufficient working capital from profitable internal operations and from industry sources, allowing for expansion of its Texas-based lease acreage holdings and natural gas exploration and production activities. Increased Maverick Basin gas production during 1999 resulted in improved positive cash flows, more than offsetting the effects of weak natural gas prices for the first half of 1999. The ongoing reduction in Williston Basin activity reflects the lingering impact of low crude oil prices realized by TXCO through the first half of 1999, and is consistent with Company strategy to focus on its core gas producing and exploration activities. Maverick Basin The Company has owned at least a 50% leasehold interest in approximately 50,000 contiguous acres in Maverick County, Texas since 1989. Originally the lease block consisted of two leases, the Paloma with 33,000 acres and the Kincaid with 17,000 acres. The lease block is situated on the Chittim Anticline, a large regional structure, under which hydrocarbons have been found in as many as seven separate horizons dating back over 65 years. One of these zones is the Lower Glen Rose or Rodessa interval. It is a carbonate formation that has produced billions of cubic feet of natural gas from patch reefs within the zone on or near the anticline. Past development in the area was halted due to the inability of previous operators to accurately predict the location of these porosity-bearing reefs. Utilizing new technological advances, the Company applied an innovative processing method to the 2-D seismic available in the area and confirmed a method of determining the location of these porosity intervals. Between 1993 and 1998, the Company expanded its in-house geophysical database to include multiple 3-D seismic surveys totaling over 55 square miles, covering approximately 36,000 acres of its Maverick Basin leases. Company scientists conclusively identified and mapped numerous geological formations at various depths on its leases. The mapping has provided numerous drilling alternatives for future evaluation of the multiple horizons known to be productive for oil and/or gas within and around its leases in the Maverick Basin. Consistent with the capital resources available, the Company has been selectively developing the Glen Rose interval. The shallower intervals provided alternative completion targets while pursuing the underlying reefs. 5 From 1989 to 1998, TXCO participated in the drilling of 26 wells in the Maverick Basin, with increasing degrees of drilling success. By the end of 1998, TXCO's daily net gas production from its Maverick Basin properties reached 1.96 MMcfd (million cubic feet of natural gas per day) from 16 gas wells. While successful in locating Glen Rose patch reefs, Management continued to review technical data gained with the drilling of each well, modifying its seismic interpretation model, improving its ability to distinguish between water-filled reefs and gas-filled reefs as well as expanding the geologically defined area known as the Prickly Pear Field. During fiscal year 1998, 6 new gas well discoveries in succession on the Paloma Lease extended the Prickly Pear Field by several miles north and east of its previous recognized boundaries. The 6 wells produced gross daily production volumes ranging from 1 MMcfd to 4 MMcfd per well. Fiscal year 1999 brought a continuation of growth in new production and revenues for the Company, as well as the expansion of TXCO's leasehold position over the Maverick Basin. During 1999, the Company acquired interests in over 39,000 acres of additional oil and gas leases in the immediate areas surrounding its Maverick Basin production, bringing its total lease position to approximately 90,000 acres at year end. TXCO participated in drilling 10 gas prospects, resulting in 5 new gas wells, further expanding the known producing area of the Prickly Pear Field on the Company's Paloma lease. Four of the other wells were drilled on leases acquired during fiscal 1999, while one was located on the Company's Kincaid lease. All 5 of these stepout wells were at least 5 to 9 miles from the nearest Prickly Pear Field production. Their drilling resulted in 2 completed oil wells and one completed gas well. The 2 other step out wells are being evaluated for various completion alternatives in shallower geologic formations overlying the Glen Rose patch reef interval, including the upper Glen Rose, lower and upper Georgetown, Eagleford, Austin Chalk and Buda formations . At year end August 1999, TXCO's daily net gas production from its Maverick Basin properties reached 9.10 MMcfd from 28 gas wells. Ongoing production increases are a direct result of the application of advances totaling $4,400,000 under the existing financing agreement with Range Energy Finance Corporation. The newly attained production levels and resultant positive cash flow will allow the Company to internally generate sufficient working capital to fund its current fiscal year 2000 development plans. The successful drilling results of fiscal year 1998 and 1999 dramatically reaffirm the Company's longstanding belief that it has significant development possibilities on its expanding Maverick Basin lease block. At year end, Maverick Basin leases totaled over 90,000 acres with an additional 25,000 acres reserved under seismic options which were exercised during the 1st quarter of fiscal 2000. Through 1999, the Company has accumulated 148 square miles (93,000 acres) of 3-D seismic data over most of its Maverick Basin lease block, with evidence of from 30 to 40 additional porosity-bearing Glen Rose patch reefs scattered across its extensive acreage position. Based on current drilling activity, these patch reefs represent a potential three to four year drilling inventory of new gas well prospects . Jurassic Formations: The Company's geophysicists and geologists have established that the 148 square miles of 3-D seismic shot through November 1999 across its 115,000 acre lease block in Maverick County indicates a significant potential for development of the deep Jurassic interval. Fiscal 1999 marked the year that the Company's concerted efforts resulted in a new partnership to develop the potential Jurassic reserves. In September 1999, the Company completed negotiations and entered into a joint operating agreement with Blue Star Oil and Gas, Ltd., a Dallas based private partnership, for an extensive exploration project targeting the deep Jurassic interval underlying TXCO's Maverick Basin lease block. Under its terms, Blue Star paid TXCO a cash consideration upon closing and will initially fund 100% of the costs of a 58 square mile 3-D seismic acquisition program covering over 37,000 acres of TXCO's Paloma and Kincaid leases. In addition, Blue Star will fund 100% of the costs of drilling 2 exploratory wells to test the underlying deep Jurassic interval, carrying TXCO and its partners for a 25% working interest. Blue Star is also obligated to provide a similar amount of new 3-D seismic survey data, of TXCO's selection, which Blue Star is in process of acquiring on its 191,000 acre Chittim Ranch Lease which lies adjacent to TXCO's Paloma lease. Should both wells be drilled in a timely fashion, Blue Star will earn a 50% interest in the deep rights in both leases totaling 50,000 gross acres. TXCO will keep a 15% to 50% working interest in future Jurassic wells drilled under the agreement, depending on the location of future wells. Should initial drilling not occur within certain deadlines ending in fiscal year 2000, Blue Star will be obligated to pay $900,000 to TXCO to maintain its rights under the agreement. At year end, acquisition of seismic field data was underway on various portions of the Company's acreage block. 6 Williston Basin During 1996 and 1997, the Company acquired a 50% interest in approximately 320,000 acres of oil and gas leases in the Williston Basin in North Dakota, South Dakota and Montana. The Company participated in the drilling of 11 wells in fiscal 1997 and 3 in fiscal 1998 in attempts to establish economic production and develop oil and gas reserves in the Red River and Lodgepole formations. During this same period, TXCO accumulated over 1,100 miles of 2-D seismic and approximately 64 square miles of 3-D seismic data covering over 40,800 acres of selected portions of its acreage in the Williston Basin. No new drilling was conducted on the Company's leases in the Williston Basin during 1999. The Company's interests produced an average of 122 net barrels of crude oil per day from 4.32 net wells. Industry wide exploration efforts in the Williston Basin have remained at historically low levels during the current year, with crude oil prices reaching a low of nearly $8.25 per barrel in December 1998. The weakness in crude oil prices rendered the production of marginal levels of oil with high associated water production, as is typical of many wells in the Basin, uneconomical for the Company to explore or produce. Current development plans, pending continuing recent crude oil price improvements, are limited to potential recompletions in behind pipe zones on existing wells, where electric logs indicate the presence of hydrocarbons during original drilling. Throughout 1999, the Company continued to re-evaluate all of its Williston Basin lease obligations, making lease extension payments on a selective basis, emphasizing those leases with particular geologic attributes or with adequate remaining primary lease terms. At August 31, 1999, TXCO retained approximately 263,900 net acres of its original position. The Company has established adequate provisions for impairment allowances as required for expected fiscal year 2000 lease expirations. Consistent with Management's decision to refocus its exploration efforts and resources on continuing development of its core producing area in South Texas, TXCO initiated a focused marketing effort to present its remaining Williston Basin holdings, complemented by an extensive seismic database, for sale to other exploration companies with a focus on this area. Proceeds from such sales would be primarily redirected into the Company's South Texas development activities after making provisions for any remaining lease obligations. With the recent improvement in crude oil prices, reaching $18.74 at year end and over $24.00 during the 1st quarter of fiscal year 2000, Management is cautiously optimistic that renewed industry interest in the area will assist it in its efforts to monetize its remaining area holdings. PRINCIPAL PRODUCTS AND COMPETITION The Company's principal products are natural gas and crude oil. The production and marketing of oil and gas are affected by a number of factors that are beyond the Company's control, the effect of which cannot be accurately predicted. These factors include crude oil imports, actions by foreign oil-producing nations, the availability of adequate pipeline and other transportation facilities, the marketing of competitive fuels and other matters affecting the availability of a ready market, such as fluctuating supply and demand. The Company sells all of its oil and gas under short-term contracts that can be terminated with 30 days notice, or less. None of the Company's production is sold under long-term contracts with specific purchasers. Consequently, the Company is able to market its oil and gas production to the highest bidder each month. The Company operates and directs the drilling of oil and gas wells. It contracts service companies, such as drilling contractors, cementing contractors, etc., for specific tasks. In some wells, the Company only participates as an overriding royalty interest owner. During 1999, three purchasers of the Company's oil and gas production accounted for 55%, 24% and 7%, respectively of total oil and gas sales. In the event any of these major customers declined to purchase future production, the Company believes that alternative purchasers could be found for such production at comparable prices. The oil and gas industry is highly competitive in the search for and development of oil and gas reserves. The Company competes with a substantial number of major integrated oil companies and other companies having materially greater financial resources and manpower than the Company. These competitors, having greater financial resources than the Company, have a greater ability to bear the economic risks inherent in all phases of this industry. In addition, unlike the Company, many competitors produce large volumes of crude oil that may be used in connection with their operations. These companies also possess substantially larger technical staffs, which puts the Company at a significant competitive disadvantage compared to others in the industry. 7 EMPLOYEES As of August 31, 1999, the Company employed 12 full-time employees including management. The Company believes its relations with its employees are good. None of the Company's employees are covered by union contracts. GENERAL REGULATIONS The extraction, production, transportation, and sale of oil, gas, and minerals are regulated by both state and federal authorities. The executive and legislative branches of government at both the state and federal levels, have periodically proposed and considered proposals for establishment of controls on alternative fuels, energy conservation, environmental protection, taxation of crude oil imports, limitation of crude oil imports, as well as various other related programs. If any proposals relating to the above subjects were to be enacted, the Company is unable to predict what effect, if any, implementation of such proposals would have upon the Company's operations. A listing of the more significant current state and federal statutory authority for regulation of the Company's current operations and business are provided herein below. Federal Regulatory Controls Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938 (the "NGA"), the Natural Gas Policy Act of 1978 (the "NGPA") and the regulations promulgated thereunder by the Federal Energy Regulatory Commission ("FERC"). Maximum selling prices of certain categories of natural gas sold in "first sales," whether sold in interstate or intrastate commerce, were regulated pursuant to the NGPA. On July 26, 1989, the Natural Gas Wellhead Decontrol Act (the "Decontrol Act") was enacted, which removed, as of January 1, 1993, all remaining federal price controls from natural gas sold in "first sales." The FERC's jurisdiction over natural gas transportation was unaffected by the Decontrol Act. Commencing in April 1992, the FERC issued Order Nos. 636, 636-A and 636-B (collectively "Order No. 636"), which required interstate pipelines to provide transportation, separate or "unbundled," from the pipelines' sales of gas. Although Order No. 636 did not directly regulate the Company's activities, it fostered increased competition within all phases of the natural gas industry. In December 1992, the FERC issued Order No. 547, governing the issuance of blanket marketer sales certificates to all natural gas sellers other than interstate pipelines. The order applies to non-first sales that remain subject to the FERC's NGA jurisdiction. The FERC Order No. 547, in tandem with Order No. 636, has fostered a competitive market for natural gas by giving natural gas purchasers access to multiple supply sources at market-driven prices. Order No. 547 has increased competition in markets in which the Company's natural gas is sold. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach pursued by the FERC and Congress will continue. State Regulatory Controls In each state where the Company conducts or contemplates conducting oil and gas activities, such activities are subject to various state regulations. In general, the regulations relate to the extraction, production, transportation and sale of oil and natural gas, the issuance of drilling permits, the methods of developing new production, the spacing and operation of wells, the conservation of oil and natural gas reservoirs and other similar aspects of oil and gas operations. In particular, the State of Texas (where the Company has conducted the majority of its oil and gas operations to date) regulates the rate of daily production allowable from both oil and gas wells on a market demand or conservation basis. At the present time, no significant portion of the Company's production has been curtailed due to reduced allowables. The Company knows of no newly proposed regulations, which will significantly curtail its production. 8 Environmental Regulation The Company's extraction, production and drilling operations are subject to environmental protection regulations established by federal, state, and local agencies. To the best of its knowledge, the Company believes that it is in compliance with the applicable environmental regulations established by the agencies with jurisdiction over its operations. The Company is acutely aware that the applicable environmental regulations currently in effect could have a material detrimental effect upon its earnings, capital expenditures, or prospects for profitability. The Company's competitors are subject to the same regulations and therefore, the existence of such regulations does not appear to have any material effect upon the Company's position with respect to its competitors. The Texas Legislature has mandated a regulatory program for the management of hazardous wastes generated during crude oil and natural gas exploration and production, gas processing, oil and gas waste reclamation and transportation operations. The disposal of these wastes, as governed by the Railroad Commission of Texas, is becoming an increasing burden on the industry. The Company's operations in Montana, North Dakota and South Dakota are subject to similar environmental regulations including archeological and botanical surveys as some of its leases are on federal and state lands. Federal and State Tax Considerations Revenues from oil and gas production are subject to taxation by the state in which the production occurred. In Texas, the state receives a severance tax of 4.6% for oil production and 7.5% for gas production. North Dakota production taxes typically range from 9.0% to 11.5% while Montana's taxes range up to 17.2%. These high percentage state taxes can have a significant impact upon the economic viability of marginal wells that the Company may produce and require plugging of wells sooner than would be necessary in a less arduous taxing environment. Although the Company is subject to federal income taxes on the oil and gas produced, its tax net operating loss carry forward should be sufficient to shelter a substantial amount of production. See Notes to the audited financial statements. CERTAIN BUSINESS RISKS Reliance on Estimates of Proved Reserves and Future Net Revenues: Depletion of Reserves There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and the timing of development expenditures, including many factors beyond the control of the Company. The reserve data set forth in this report represents only estimates. In addition, the estimates of future net revenues from proved reserves of the Company and the present value thereof are based on certain assumptions about future production levels, prices and costs that may not prove to be correct over time. In particular, estimates of crude oil and natural gas reserves, future net revenue from proved reserves and the present value of proved reserves for the crude oil and natural gas properties described in this report are based on the assumption that future crude oil and natural gas prices remain the same as crude oil and natural gas prices as of August 31, 1999. The average sales prices as of such dates used for purposes of these estimates were $18.68 per barrel of crude oil and $2.59 per mcf of natural gas, representing an increase of 70% and 42%, respectively, from the prior year sales prices. Any significant variance in these assumptions could materially affect the estimated quantity and value of reserves set forth herein. See "Management's Discussion and Analysis of Financial Condition and Results of Operation - Liquidity and Capital Resources" and "Properties " Depletion of Reserves The rate of production from crude oil and natural gas properties declines as reserves are depleted. Except to the extent the Company acquires additional properties containing proved reserves, conducts successful exploration and development activities or through engineering studies identifies additional behind-pipe zones or secondary recovery reserves, the proven reserves of the Company will decline as reserves are produced. Future crude oil and natural gas production is therefore highly dependent upon the Company's level of success in acquiring or finding additional reserves. 9 Title to Properties As is customary in the crude oil and natural gas industry, the Company performs a preliminary title investigation before acquiring undeveloped properties that generally consists of obtaining a title report from outside counsel or due diligence reviews by independent landmen. The Company believes that it has satisfactory title to such properties in accordance with standards generally accepted in the oil and gas industry. A title opinion from counsel is obtained before the commencement of any drilling operations on such properties. The Company's properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens, none of which the Company believes materially interferes with the use of, or affect the value of, such properties. Losses from Operations For the current year the Company recorded net income of $.93 million. However, in prior years the Company recorded net losses of $8.4 million in fiscal 1998 and $3.4 million in fiscal 1997. There can be no assurance that the Company will not experience operating losses in the future. Operating Hazards; Uninsured Risks The nature of the crude oil and natural gas business involves certain operating hazards such as crude oil and natural gas well blowouts, explosions, formations with abnormal pressures, cratering and crude oil spills and fires. Any of these could result in damage to or destruction of crude oil and natural gas wells, destruction of producing facilities, damage to life or property, suspension of operations, environmental damage and possible liability to the Company. In accordance with customary industry practices, the Company maintains insurance against some, but not all, of such risks and some, but not all, of such losses. The occurrence of such an event not fully covered by insurance could have a material adverse effect on the financial condition and results of operations of the Company. Substantial Capital Requirements The Company makes, and will continue to make, substantial capital expenditures for the acquisition, exploitation, development, exploration, and production of crude oil and natural gas reserves. Historically, the Company has financed these expenditures primarily from debt and equity offerings, supplemented by available cash flow from operations. The Company is hopeful that it will continue to be able to obtain sufficient capital to finance planned capital expenditures. However, if revenues decrease because of lower crude oil and natural gas prices, operating difficulties or declines in reserves, the Company may have limited ability to finance planned capital expenditures in the future. Therefore, there can be no assurance that additional debt or equity financing or cash generated by operations will be available to meet its capital requirements. ITEM 2. PROPERTIES PHYSICAL PROPERTIES The Company's administrative offices are located at 500 North Loop 1604 East, Suite 250, San Antonio, Texas. These offices, consisting of approximately 5,700 square feet, are leased through February 28, 2000 at $7,676 per month. All the Company's oil and gas properties, reserves, and activities are located onshore in the continental United States. There are no quantities of oil or gas subject to long-term supply or similar agreements with foreign government authorities. 10 Proved Reserves, Future Net Revenue and Present Value of Estimated Future Net Revenues The following unaudited information as of August 31, 1999, relates to the Company's estimated proved oil and gas reserves, estimated future net revenues attributable to such reserves and the present value of such future net revenues using a 10% discount factor, as estimated by Pollard, Gore and Harrison, an Austin, Texas engineering firm. Estimates of proved developed oil and gas reserves attributable to the Company's interest at August 31, 1999, 1998 and 1997 are set forth in Notes to the Audited Financial Statements included in this Annual Report on Form 10-K. Present Value of Estimated Future Net Revenues from proved developed oil and gas reserves as of August 31, 1999, are as follows: 10% Present Value of Years Ending Estimated Future August 31 Net Revenues ---------- ------------ 2000 5,751,000 2001 3,580,000 2002 1,473,000 2003 719,000 2004 364,000 Thereafter 558,000 ----------- TOTAL $ 12,445,000 =========== The present value of estimated future net revenues is computed in accordance with SEC requirements. These amounts were computed by applying current prices for oil and gas, giving effect only to those escalations in prices of gas which are currently contractually defined, deducting estimated future expenditures to develop and produce the proved reserves and applying a discount factor of 10%. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas liquids and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. No reserve estimates have been filed with or included in reports to any federal or foreign government authority or agency, other than the Securities and Exchange Commission, since the Company's latest Form 10-K filing. Production The following table summarizes the Company's net oil and gas production, average sales prices, and average production costs per unit of production for the periods indicated. With respect to newly drilled wells, there can be no assurance that current production levels can be sustained. Depending upon reservoir characteristics, such levels of production could decline significantly.
Years Ended August 31 ------------------------------------- 1999 1998 1997 ---- ----- ---- Oil: Production in Barrels 82,000 79,138 23,086 Average sales price per Barrel $12.27 $15.78 $18.64 Gas: Production in MCF 2,813,000 713,752 206,059 Average Sales Price per MCF $2.07 $2.29 $ $2.65 Average cost of production per equivalent MCF (1) $.40 $.74 $.72
(1) Oil and gas were combined by converting oil to gas mcf equivalent on the basis of 1 barrel of oil = 6 MCF of gas. Production costs include direct lease operations and production taxes. 11 Producing Properties - Wells and Acreage The following table sets forth the Company's producing wells and developed acreage assignable to such wells at August 31, for the last three fiscal years:
Productive Wells Fiscal ---------------------------------------------------------- Year Developed Acreage Oil Gas Total - ----- ------------------- -------------- ---------------- --------------- Gross Net Gross Net Gross Net Gross Net ----- --- ----- --- ----- --- ----- --- 1999 11,720 5,185 18 6.29 29 12.56 47 18.85 1998 8,920 3,894 16 5.26 17 8.05 33 13.31 1997 6,040 2,479 10 3.77 13 5.55 23 9.32
Productive wells consist of producing wells and wells capable of production, including shut-in wells and wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. A "gross well" or "gross acre" is a well or acre in which a working interest is held. The number of gross wells or gross acres is the total number of wells or acres in which working interests are owned. A "net well" or "net acre" is deemed to exist when the sum of fractional ownership interest in gross wells or gross acres equals one. The number of net wells or net acres is the sum of fractional working interests owned in gross wells or gross acres expressed as whole numbers and fractions thereof. Undeveloped Acreage As of August 31, 1999, the Company owned, by lease or in fee, the following undeveloped acres, all of which are located in the Continental United States, as follows: Estimated FY 2000 United States Gross Acres Net Acres Delay Rentals - ------------- ----------- --------- ------------- Texas 95,155 64,631 $ 81,726 North Dakota 323,294 226,904 130,405 South Dakota 32,244 20,281 3,085 Montana 25,163 15,759 1,440 ----------- --------- ------------- Totals 475,856 327,575 $ 216,656 ========== ========= ============= Five Texas leases totaling approximately 66,000 gross acres contain varying requirements to drill a well every 90 to 150 days to keep the respective lease in effect. The Company is presently drilling under the terms of the leases and expects to keep the leases in force by continuous development during the year. 12 Drilling Activity During fiscal 1999, the Company's drilling activity increased to 10 wells compared to 7 in 1998. The following table sets forth the Company's drilling activity for the last three fiscal years:
Drilling Wells 1999 1998 1997 ----------------------- -------------------------- ------------------------ Gross Net Gross Net Gross Net Prod Dry Prod Dry Prod Dry Prod Dry Prod Dry Prod Dry ---- ---- ---- ---- ---- --- ----- ---- ---- --- ---- --- Oil Wells 2 0 1.75 0 2 1 1.34 .63 9 2 3.73 <.01 Gas Wells 6 0 3.78 0 4 0 2.50 .00 4 0 2.80 .00 - - ---- - - - ---- --- - - ---- --- Total Wells 8 0 5.53 0 6 1 3.84 .63 13 2 6.53 <.01 = = ==== = = = ==== === == = ==== ===
The Company had an interest in 2 wells (1.38 net) in progress at August 31, 1999. Fiscal years 1998 and 1997 well totals include completed or dry wells commenced in the respective prior year. Maverick Basin Throughout 1999, the Company has pursued its strategy to expand its core Maverick Basin producing properties. In addition to using its internally generated working capital for exploration and development activities, TXCO has accelerated its growth by entering into strategic joint ventures or operating agreements targeted at leveraging the Company's increased leasehold values, recognized technical abilities and exploration success in its core area of interest. TXCO entered into several new joint venture or joint operating agreements during the year whereby the Company successfully teamed with qualified industry partners who contributed investment capital, mineral leases, 3-D seismic data and/or offered the Company a carried interest in mineral leases, 3-D seismic acquisition programs and wells to be drilled. These contributions were made in exchange for TXCO's geophysical, geological and operational expertise, and in certain instances, in exchange for a portion of the Company's non-producing oil and gas lease interests . During September 1998, the Company entered into a joint operating agreement (JOA ) with Ashtolla Exploration Company, Inc., whereby TXCO earned a 63% working interest in Ashtolla's 8,800 acre Alkek lease adjoining TXCO's Paloma lease, together with rights to an existing 3-D seismic survey over the subject block. In exchange, TXCO agreed to drill a well to test the Glen Rose interval, allowing the previous operator to meet the operational requirements under the terms of the original lease agreement. Two wells were drilled under this JOA during the year resulting in 1 marginal gas well completion, while the second well was awaiting completion at year end. Also in September 1998, the Company entered into a JOA with the Picosa Creek Partnership, whereby TXCO was given access to an existing 3-D seismic survey over the 12,800 acre Chittim lease which adjoins its Paloma lease. The Company earns a 25% interest in any Glen Rose reef wells it proposes and drills after reprocessing and interpreting the new 3-D seismic data. One well was drilled and completed as an oil producer under this JOA during the year, while a 2nd well was drilled and is being completed as a gas well in November 1999 . In November 1998, the Company finalized a JOA with Ameritex Ventures, II Ltd., a joint venture owned 85% by Enron Capital, allowing Ameritex and its partners to earn up to a 50% interest in TXCO's existing 17,000 acre Kincaid lease in exchange for their funding 100% of the costs of and commencement of a 27 square mile 3-D seismic program on parameters established by TXCO over the entire 17,000 acre tract. While the terms reduced the Company's remaining interest in the non-producing lease to 50% in shallow zones, it provided for TXCO to keep 100% of its deeper rights, including the deep Jurassic interval. Upon completion of the 3-D seismic acquisition program, 1 well was drilled and was being completed at year end. 13 In May 1999, the Company finalized a JOA with Castle Exploration Company, a wholly owned subsidiary of Castle Energy Corporation, (Nasdaq:CECX) whereby Castle committed to provide TXCO with up to $5,3000,000 to fund 100% of the initial costs to purchase leases, acquire 3-D seismic and drill up to 12 Glen Rose reef wells on targeted acreage contiguous to TXCO's productive Paloma lease. TXCO was named as operator, and contributed its interest in its 8,800 acre Alkek lease in exchange for shared rights to all 3-D seismic acquired, a 25% carried interest in the initial 12 wells drilled, a 50% interest in initial lease acquisitions, and the right to participate with up to a 50% interest in all future wells to be drilled on the leases. By year end, TXCO had leased or held options totaling 31,700 acres adjoining it's Paloma lease acreage. Through November 1999, all 3-D seismic acquisition work was completed over most of the acreage tract. Initial review of the completed data set by TXCO's exploration team confirmed the presence of Glen Rose patch reefs scattered across the block. Management expects to propose its initial selection of drilling locations utilizing the new seismic data during the second quarter of fiscal 2000, with drilling to commence immediately thereafter. In October 1999, TXCO drilled the first well under the terms of the JOA. The well did not encounter sufficient quantities of gas, so Castle elected not to complete the well. In August 1999, the Company closed an agreement with Peacock-Maverick Drilling and Peacock Exploration to purchase their interests in producing wells and oil and gas leases totaling 24,500 acres in exchange for 325,000 shares of TXCO common stock valued at $493,594. The purchase included a 12.5 % working interest in the 12,800 acre Chittim lease, including a similar working interest in 6 producing oil and gas wells located thereon. The acreage is contiguous to TXCO's Paloma lease. In addition, the Company received a 100% working interest in two leases totaling 11,700 acres located within 5 miles of the other tracts. In September 1999, the Company completed negotiations and entered into a JOA with Blue Star Oil and Gas, Ltd., for an extensive exploration project targeting the deep Jurassic interval underlying TXCO's Maverick Basin lease block. Under its terms, Blue Star paid TXCO a cash consideration upon closing and will initially fund 100% of the costs of a 58 square mile 3-D seismic acquisition program covering over 37,000 acres of TXCO's Paloma and Kincaid leases. In addition, Blue Star will fund 100% of the costs of drilling 2 exploratory wells to test the underlying deep Jurassic interval. Blue Star is also obligated to provide, at TXCO's selection, a similar amount of new 3-D seismic survey data which Blue Star is in process of acquiring on its 191,000 acre Chittim Ranch Lease which lies adjacent to TXCO's Paloma lease. Should both wells be drilled timely, Blue Star will earn a 50% interest in the deep rights in both leases totaling 50,000 acres. TXCO will keep a working interest in future Jurassic wells drilled under the agreement varying between 15% to 50%, depending on the location of future wells. Should initial drilling not occur within certain deadlines ending in fiscal year 2000, Blue Star will be obligated to pay $900,000 to TXCO to maintain its rights under the agreement. By the end of fiscal year 1999, the Company had extended its 3-D seismic database over an expanded area of its core producing leases by 68,000 acres, more than doubling the size of its existing seismic database at the end of the previous year. By the end of the 1st quarter of fiscal 2000, that number grew to over 93,800 acres or over 148 square miles. The Company currently has two consulting geophysicists engaged in interpretation of the new data. Management expects to identity a significant number of new 3-D defined drilling prospects in numerous horizons throughout its Maverick Basin leases further adding to its multiyear drilling prospect inventory. Williston Basin The Company did not participate in drilling any Williston Basin wells during 1999. While the depressed oil and gas price environment in fiscal year 1998 and 1999 have impacted all of the Company's operations, the Williston Basin operations were impacted the most. Realized prices for the Company's North Dakota crude oil dropped from its high of $22.52 in November 1997 to a low of $8.30 in December 1998 and back up to $18.22 in August 1999. These lower prices, combined with high unit production costs at current production levels, have resulted in failed economics on several of the Company's Williston Basin producing properties. The Company curtailed its capital spending program in the area during midyear 1998 and has continued implementing its cost reduction plan through all of 1999. Curtailed current period expenses included non-payment of lease renewals or expired leases totaling over 110,000 acres of leases in Montana, North and South Dakota, targeting primarily those leases not covered under existing 3-D seismic programs or otherwise not possessing known distinguishing features of particular significance. 14 At year end, the Company continued its evaluation of all operations in the Williston Basin, with particular emphasis on their continued economics resulting from the instability in oil prices. The review also identified oil leases targeted for impairment, totaling over 34,800 net acres in North and South Dakota, with primary expirations prior to August 31, 2000. The Company determined it was reasonable and conservative to charge future monthly period earnings with a ratably computed impairment for the lease acreage which is expected to expire during the upcoming year. Forward-looking statements in this 10-K are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Investors are cautioned that all forward-looking statements involve risks and uncertainty, including without limitation, the costs of exploring and developing new oil and natural gas reserves, the price for which such reserves can be sold, environmental concerns effecting the drilling of oil and natural gas wells, as well as general market conditions, competition and pricing. Please refer to all of TXCO's Securities and Exchange Commission filings, copies of which are available from the Company without charge, for additional information. ITEM 3. LEGAL PROCEEDINGS The Company is not involved in any matters of litigation incidental to its business of a significant nature. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matter was submitted to a vote of the security holders of the Company during the 4th quarter of fiscal year 1999. During the 2nd quarter, on February 26, 1999, the Company held its Annual Meeting of Shareholders. The following matters were submitted for approval by vote at the meeting. All matters were approved by the shareholders vote and the results of the voting is shown below for each matter. 1. Election of Directors: For Against Stephen M. Gose, Jr. 14,060,208 93,637 Thomas H. Gose 14,060,143 93,702 James E. Sigmon 14,060,208 93,637 Michael Pint 14,060,208 93,637 Robert L. Foree, Jr. 14,059,698 94,147 The members of the Board of Directors do not serve staggered terms of office. There were no changes in Directors of the Company 2. Proposal for an amendment of the Company's 1995 Flexible Incentive Plan: For Against Abstain Non-Voted 7,890,220 804,415 109,465 5,349,745 3. Proposal for the re-incorporation of the Company by changing state of incorporation of the Company from Colorado to Delaware. For Against Abstain Non-Voted 8,665,755 252,566 9,798 5,225,726 4. Proposal for ratification of the adoption of Akin, Doherty, Klein & Feuge, P.C., as independent Auditors for the Company for the fiscal year 1999. For Against Abstain 14,111,145 34,530 8,170 15 PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS The following is a range of high and low bid prices for the Company's common stock for each quarter of the last two years based upon bid prices reported by the National Association of Securities Dealers Quotations system under the call symbol "TXCO": Range of Bid Prices Quarter ended: High Low August 1999 $ 2.94 $ 1.00 May 1999 1.41 .75 February 1999 1.50 .62 November 1998 1.41 .75 August 1998 $ 1.94 $ 1.16 May 1998 2.81 1.69 February 1998 3.50 1.63 November 1997 8.44 2.50 As of November 1, 1999, there were approximately 1,697 holders of record of the Company's Common Stock. The transfer agent for the Company is EquiServe, Boston, Massachusetts. The Company has not paid any cash dividends on its Common Stock and does not expect to do so in the foreseeable future. ITEM 6. SELECTED FINANCIAL DATA The following selected financial information is derived from and qualified in its entirety by the Financial Statements of the Company and the Notes thereto as set forth in this Annual Report on Form 10-K commencing on page F-1.
Years Ended August 31 ------------------------------------------------------------------ 1999 1998 1997 1996 1995 ---- ---- ---- ---- ---- Operating Revenues $7,497,375 3,048,277 $1,083,511 $ 521,593 $ 331,253 Income (Loss) from continuing operations 931,545 (8,417,218) (3,398,866) (1,880,389) (2,153,365) Basic Income (Loss) per common share from continuing operations 0.06 (0.55) (0.27) (0.31) (0.44) Total Assets(1) 17,553,815 16,264,632 21,652,726 8,433,434 4,111,980 Long-term obligations(1) 3,094,809 4,823,927 4,995,000 2,462,197 2,429,697 Shareholders' equity 12,020,280 10,595,141 14,770,770 5,670,688 1,377,747 Weighted average shares outstanding (1) 15,668,721 15,328,292 12,576,255 6,140,176 4,863,961
(1) Amounts reflect adjustments in 1995 for the reclassification of ExproFuels as an equity investment due to its spin-off in 1996. 16 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following is a discussion of the Company's financial condition and results of operations. This discussion should be read in conjunction with the Financial Statements of the Company and Notes thereto. CAPITAL RESOURCES AND LIQUIDITY 1999 - ---- During the year ended August 31, 1999, beginning cash reserves of $2,329,236 were increased by net cash provided from operating activities of $3,858,204 resulting in a total of $6,187,440 in working capital available for use in funding the Company's ongoing development and exploration of its oil and gas properties. The ongoing positive cash flow from operations throughout the year significantly improved the Company's ability to increase its core revenues from oil and gas operations, thereby enhancing its ability to overcome the impact of weak oil and gas prices through most of 1999. An additional $900,000 was obtained during the year, under the existing financing agreement with Range Energy Finance Corporation, bringing total borrowings from Range to $4,400,000. The financing was specifically for ongoing development of the Company's natural gas producing properties in Maverick County, Texas. The Company applied $3,448,320 of its working capital to fund the expansion and ongoing development of its oil and gas properties. Included were drilling and completion costs of $2,791,544 for current year drilling of 10 Maverick Basin gas and oil wells, plus costs associated with 2 wells drilled during the last quarter of 1998. Also included were $211,101 in 3-D seismic acquisition and reprocessing costs and $390,000 in lease extension payments to maintain non-producing lease acreage in the Company's growing Maverick Basin lease block. The Company made timely payments on long term debt of $2,629,118 during 1999, including $1,966,956 paid on the Range financing agreement. Scheduled payments totaling $662,162 were made on the Company's remaining long-term notes during the remainder of the year. During the 3rd quarter of 1999, TXCO successfully entered into a joint venture agreement with Castle Exploration Company, (Castle) a wholly owned subsidiary of Castle Energy Corporation (Nasdaq:CECX), whereby Castle agreed to fund up to $5,300,000 for 100% of all costs to acquire approximately 25,000 acres of additional leases, fund a 42 square mile 3-D seismic survey and drill up to 12 gas wells. In exchange, TXCO contributed its interest in an 8,800 lease to the venture, was named operater and will be carried at no cost, for a 25% interest in the first 12 wells drilled. Additionally, TXCO will be licensed to share in all seismic data gathered and will earn a 50% working interest in all leases acquired with the funds. At year end, all 3-D seismic acquisition and processing had been completed, and Company geologists and geophysicists were in process of interpreting and evaluating the new data. During the 4th quarter of 1999, the Company successfully closed another non-cash transaction to acquire various oil and gas mineral interests near or adjoining TXCO's Maverick Basin leasehold. In exchange for 325,000 shares of its restricted common stock valued at $493,594, the Company purchased a 12.5% interest in 12,800 acres known as the Chittim Lease, including a 12.5% working interest in 6 producing oil and gas wells and associated equipment. In addition, TXCO also received a 100% working interest in two separate leases totaling approximately 11,700 acres. As a result of these activities, the Company ended fiscal year 1999 with negative working capital of $1,525,594 and a current ratio of .70 to 1. This compares to positive working capital of $516,693 and a current ratio of 1.19 to 1 at August 31, 1998. Working capital weakened during 1999 primarily due to cash outlays for its aggressive ongoing development activities and due to timely payments made under the terms of the Range financing agreement. Although the Company had a working capital deficit at year end, included in current liabilities is $2,110,620 estimated as the debt payment for fiscal 2000 under the Range financing agreement. The Range debt payments are only due and payable out of each future month's net cash flow from the collateralized producing wells. Should producing well cash flows be less than estimated, the debt repayment will be less, while the reverse is true should cash flows be greater. Due to the Company's drilling success in 1998 and 1999, it expects substantially all of the Range debt to be repaid during fiscal year 2000. Management is confident of the Company's ability to continue to generate positive cash flow from operations, and in its ability to meet its ongoing operating cash requirements. 17 1998 - ---- During the year ended August 31, 1998, beginning cash reserves of $6,198,069 were reduced by net cash used in operating activities of $1,185,050 resulting in a total of $5,013,019 in working capital available used in funding the Company's ongoing development and exploration of its oil and gas properties, significantly improving the Company's potential to increase its core revenues from oil and gas operations, and enhancing its ability to overcome the impact of continued weakness in oil and gas prices. Throughout fiscal 1998, the Company pursued opportunities to enhance its liquidity by the conversion of existing short term trade payables to long-term debt and the conversion of debentures into common stock. Management successfully converted 4 separate accounts totaling $1,684,000 in current trade payables into separate notes, with payment terms ranging from 12 to 36 months and interest accruing at rates ranging from 8% to 14%. Further improvements to the Company's debt structure were realized by Management's election to exercise the Company's option to convert its outstanding $4,000,000 debentures to equity. Effective January 1, 1998, the Company issued 844,318 shares of its common stock in exchange for the outstanding debentures, including accrued interest of $221,590, at the conversion price of $5.00 per share. In addition to the extremely favorable conversion price for the new issuance, and the elimination of $240,000 in future annual interest expense, Management's elimination of its primary long-term debt significantly enhanced the Company's ability to pursue additional sources of equity or debt-based working capital. Late in the final quarter of 1998, the Company entered into a financing agreement with Range Energy Finance Corporation, a subsidiary of Range Resources Corporation (NYSE:RRC), (formerly Domain Energy Corporation) to initially establish a borrowing ceiling of $4,000,000. During fiscal year 1999 the borrowing ceiling was increasd to $4,400,000. The financing was specifically for ongoing development of the Company's natural gas producing properties in Maverick County, Texas. Funds were advanced in exchange for a limited term overriding royalty interest tied to existing and future production from specified depths underlying certain of the Company's oil and gas leases in Maverick County. Terms provided for repayment of the funds, with interest at 18%, from a specified portion of sales proceeds from all existing and future wells to be drilled on the Paloma lease. By August 31, 1998 the Company had borrowed $3,500,000 under the agreement. Throughout the year ended August 31, 1998, the Company applied $4,806,505 of its available working capital to fund the ongoing development of its oil and gas properties. This included drilling and completion costs of $3,385,720 associated with the current year drilling of four new Maverick Basin gas wells, three new Williston Basin oil wells and costs associated with 4 wells drilled prior to the current fiscal year, plus $188,785 for completion of the newest segment of the Company's new gas gathering system in Maverick County during 1998. Also included were 1998 3-D seismic acquisitions totaling $711,294 over Company leases in North Dakota and $153,845 on the Paloma lease in South Texas. Additional investments in non-producing lease acreage totaled $366,861 for the year. Additionally, the Company made payments on its long-term debt during the year of $1,500,990. Included in the total was $940,481 paid during the first quarter, in full prepayment of the Company's outstanding line of credit with Luzerner Kantonalbank. Scheduled payments totaling $560,509 were made on the Company's remaining long-term notes during the remainder of 1998. As a result of these activities, the Company ended fiscal year 1998 with positive working capital of $516,693 and a current ratio of 1.19 to 1. This compares to positive working capital of $3,760,648 and a current ratio of 2.32 to 1 at August 31, 1997. While the Company's working capital position weakened from the previous year, the results of the Company's dramatic 100% drilling success ratio during 1998 for new Glen Rose wells became evident during the first quarter of fiscal year 1999. As new wells were placed on production, Management was assured in its confidence of continuing significant improvements in the Company's ability to meet its ongoing operating cash requirements. 18 1997 - ---- During the first quarter of 1997, the Company converted $933,485 of its debt into 340,060 shares of common stock and raised an additional $525,000 cash through the exercise of common stock warrants and sales of common stock. During the second quarter of fiscal 1997, the Company successfully closed a large transaction that resulted in its acquiring an additional 220,000 net acres of undeveloped oil and gas acreage in the Williston Basin of North and South Dakota and Montana for $22,000,000 cash and the issuance of 1,000,000 shares of restricted common stock. Simultaneous with the acquisition, the Company sold a 42.5% net profits interest in future wells on the acreage for $17,000,000 cash. Concurrent with the acquisition of undeveloped acreage and sale of the net profits interest, the Company received from the same acquiring parties $4,000,000 cash for a debenture convertible into the Company's common stock at $5.00 per share. During the same quarter, the Company completed an offering under Regulation S by successfully selling 2,800,000 shares of its common stock for $14,000,000 and also converted $1,331,212 in previously issued convertible debentures into 532,488 shares of common stock. The result of the above transactions was to significantly enhance the Company's operating position by giving it additional acreage to develop as well as the working capital with which to drill. For the entire year, the Company raised $15,007,400, net of expenses, through common stock sales and converted $2,264,702 of convertible debentures into common stock (and thereby eliminating an on-going cash outlay for interest as well as the future repayment of the debt). The Company also raised $17,000,000 through the sale of the net profits interest in future Williston basin wells to be drilled and raised an additional $5,000,000 through new debt financing, which included proceeds from the sale of $4,000,000 in convertible debentures plus proceeds from its existing $1,000,000 line of credit. A portion of this new capital was used to finance the second quarter acquisition of the Company's additional 220,000 net acres of Williston Basin oil leases purchased for $22,000,000 cash plus 1,000,000 shares of the Company's common stock. Proceeds were also used to fund the Company's loss for the year of $3,398,866, including the payment of interest of $236,000, payments on current portion of debt and capital leases of $210,000 and for capital and investment expenditures of $14,196,000. Capital expenditures included approximately $115,000 in equipment, $125,000 in drilling bonds and deposits, $200,000 in prepaid loan fees and cumulative advances to ExproFuels totaling $826,000. Most significantly, $12,924,000 was invested in the development of the Company's oil and gas properties, including the drilling of four Maverick Basin wells in Texas, 11 Williston Basin wells in North Dakota, the acquisition of $780,000 of 3-D seismic data and $279,000 for expansion of the Company's Maverick County natural gas pipeline infrastructure. At August 31, 1997, the Company had cash of $6,198,069 and working capital of $3,760,648, on current assets of $6,609,579 and current liabilities of $2,848,931. This compared to a cash position of $967,838 and a working capital deficit of $33,624 at August 31, 1996. 2000 Capital Requirements - ------------------------- The major components of the Company's plans, and the requirements for additional capital at August 31, 1999, include the following: Maverick Basin Activity: During fiscal 2000, the Company's plans to drill a minimum of 9 additional wells, in keeping with lease renewal minimum requirements, with a total drilling budget of $2,000,000. Two of these wells are scheduled to be drilled under and funded by the Castle project at no cost to TXCO. The remaining 7 wells are targeted as Glen Rose reef prospects, each costing approximately $225,000 to 275,000 to complete or $160,000 as a dry hole. Company engineers are planning to test other formations with horizontal drilling techniques with the hope of unlocking additional reserves not previously productive from vertical drilling, due to the formations' low permeability. The horizontal drilling increases the typical gross completion cost of a well by $150,000 to $300,000, with the Company's share being approximately $90,000 to $180,000. In the event of continuing improvements in realized oil and gas prices, the Company can accelerate its drilling program as additional internally generated working capital becomes available during the year. It can also accelerate the Castle program as directed by the funding partner during the year. Estimated expenditures required to maintain the Company's interest in its remaining undeveloped South Texas leasehold acreage for fiscal 2000 are $269,000. 19 The Company has effectively layed off a significant portion of the capital requirements for which it would have otherwise had to provide funding for during fiscal 2000 and 2001. This capital outlay reduction was made possible by the carried interest feature included in two key strategic joint ventures it entered in during 1999. TXCO will be carried for a 25% interest in the next 11 wells proposed to be drilled under its joint operating agreement with Castle Exploration Company. Upon completion of the new 3-D seismic data set's interpretation, the results from the new 31,700 acre 3-D seismic survey should generate a number of new drillable Glen Rose reef prospects in excess of TXCO's internal drilling program. In addition, all of TXCO's currently remaining 3-D seismic expenditures for both the Castle project and the Blue Star Jurassic project are covered entirely by its partners. Williston Basin Activity: Due to the continuing uncertainty in crude oil prices and unattractive economics for continued exploration, the Company has deferred further expenditures in the Williston Basin, except for maintaining existing producing properties and the payment of delay rentals and lease extensions on selected leases. Management will continue its efforts to offer its remaining prospects to other industry operators. Delay rentals required to maintain the Company's interest in its remaining undeveloped Williston Basin leasehold acreage for fiscal 2000 are $135,000. Summary of Capital Resources and Liquidity Subsequent to the end of fiscal 1999, the Company successfully drilled two wells, completing one as a Georgetown formation gas well in October 1999. Drilling on the second well was completed in November 1999, with electric logs indicating the well encountered a 55 foot section of Glen Rose reef which appears to be gas productive. The Company's net revenues from both wells should increase by $500,000 to $750,000 per year. While management is confident it has identified sufficient sources of working capital to carry out its current exploration and development plans on its Texas leaseholds, as well as to meet its obligations in the ordinary course of business through the end of the new fiscal year, there is no assurance that energy prices will either continue to improve or return to their weakened positions as they were during the first half of 1999. Should prices weaken, the reduction in revenues could cause the Company to re-evaluate its expected sources of working capital and reduce its current operating plans. Management is actively involved in ongoing discussions with various domestic and foreign based sources of debt and equity financing that could provide favorably structured funding as required to increase the Company's planned drilling activity during fiscal year 2000. Management remains confident that financial resources will remain available, enabling the Company to continue the rapid development of its oil and gas properties and continue to meet its normal operational and debt service obligations. Year 2000 Over the last three years the Company has replaced or upgraded most of the core management information systems used in the Company's business. The Company has conducted a review of these systems to verify their compliance with Year 2000 date codes. In addition, the Company has conducted an inventory, review and assessment of its desktop computers, networks and servers, software applications and packages, and products and services provided by third parties for internal operations to determine whether or not they support Year 2000 date codes. The Company believes it has successfully completed required modifications to all mission critical applications included in its internal systems. In addition, the Company has contacted its major gas purchasers, gas pipeline carriers, stock transfer agent and banking institutions and received written assurances and/or viewed assurances on their websites that they have no material Year 2000 problems. The Company does not believe the Year 2000 issue will materially affect its ability to pay its vendors and suppliers, track its assets in the custody of financial institutions or otherwise prevent it from conducting its business on an ongoing basis. RESULTS OF OPERATIONS 1999 Compared to 1998 The Company reported net income of $931,545 or $0.06 per diluted share for the year ended August 31, 1999, compared to a net loss of ($ 8,417,218) or ($0.55) per diluted share for the same period in 1998. The attainment of profitability was primarily the result of a 146% increase in revenues over 1998 levels due primarily to significant new production from 9 new wells placed on line during the year, including 2 gas wells completed late in the last quarter of the prior year. While very positive, the increases were significantly offset by the weakness in oil and gas prices through the first half of 1999. Gas sales volume increases also reflect the impact of the first full year of operation of the expanded gas gathering system completed during the latter part of 1998. 20 Exploration expenses decreased by 88% compared to 1998 levels due to the high drilling success in the Maverick Basin compared to multiple Williston Basin dry holes drilled or abandoned during the prior year. Abandoned leases and equipment expense decreased by 78% primarily to the non-recurring nature of the one time charge off of uneconomical producing properties during 1998 due to the oil and gas price collapse during 1998. Impairment expense decreased by 92% also due to the non-recurring nature of the initially large impairment provisions required due to the oil price collapse in the prior year, while lower 1999 impairment provisions proved adequate in light of the improvement in realized oil and gas prices during the last half of the current year. Depreciation, depletion and amortization increased by 61% over 1998 levels due primarily to an increase in depletion. The change in depletion was due to the adverse impact on year end reserve estimates caused by declining oil production and increasing water disposal costs associated with Williston Basin production. The decrease in loan fee amortization expense as compared to 1998, reflects the non-recurring nature of the prior period's recognition of $180,000 in previously capitalized prepaid loan fees due to the conversion of a $4,000,000 debenture in January 1998. Fiscal 1998 loan fee amortization expense has been reclassified for comparative purposes with current year expense. Interest expense increased by 142% over 1998, reflecting a full year of interest charges on borrowings under the Range financing agreement entered into during the last quarter of the prior year. 1998 Compared to 1997 Revenues from oil and gas sales increased 195% over 1997 as a result of significant new production from the successful completion of the nine new wells during the last part of the 1997, plus the additional production from 4 new gas wells added during 1998. Lease operating expenses, related directly to the costs of operating the newly producing Williston Basin oil wells with very high production associated water disposal costs, increased by 297% over 1997. The disproportionately higher increase in lease operating expense increases reflects the difference in the Company's normal natural gas production expense level versus the significantly higher per unit production cost associated with its Williston Basin oil production. Exploration expenses, including the costs of unsuccessful wells increased by 47% due to the write-off of two high working interest dry holes during the year compared to two very low working interest dry-holes in the previous year. The 40% fall of oil prices at mid-year rendered the completion of the wells uneconomical. Abandoned leases and equipment increased to $1,451,880, reflecting the ongoing impact of the 40% fall of oil prices during the year that rendered marginal properties uneconomic to maintain or renew. Included in the non-cash charge off for the current year are $608,573 in Williston Basin leases, $156,670 in Zavala County leases (South Texas), and $26,757 in Canadian Crown leases, all determined to be uneconomic and expiring during the current year due to the continued impact of low oil and gas prices. Also included in the 1998 non-cash writeoff was the remaining capitalized costs $659,880 for the Kincaid #1-99, a horizontal Georgetown test well drilled in Maverick County during the third quarter of 1997 that failed to produce economic quantities of gas. Pursuant to the Successful Efforts Method of accounting for mineral properties, the Company periodically assesses its producing properties and non-producing mineral leases for impairment. Based on the 40% fall in oil prices during the year and the resulting impact on the updated reserve estimates at year end, the Company identified certain producing properties which required impairment. Additionally, non-producing leaseholds were reviewed for potential impairment. Certain leases, with expiration dates through December 1999, were identified which will not be renewed. Non-cash impairment charges totaling $3,655,342 were recorded at year end including $1,580,820 of Williston Basin and Texas non-producing leases set to expire through calendar year 1999. Additionally, a $2,194,522 impairment was recorded reflecting the excess of unamortized book value over the future realizable reserves primarily related to certain of its Williston Basin wells. Additional expenses during the year include depreciation, depletion and amortization of 1,446,726, plus current year exploration expenses of $2,290,649. Except for the statutory, intangible (non-cash) expenses required for compliance reporting purposes described above and current year exploration expenses, actual operating activities for the year ended August 31, 1998 resulted in positive cash flow from producing operations of $989,484. This level of positive cash flow, if sustained, is sufficient to provide for funding of the Company's primary administrative operations. Management feels confident this source of internally generated working capital will continue to grow as the Company's Texas gas production levels expand through fiscal 1999 and beyond. 21 General and administrative costs increased to $1,278,270 from $938,000. Increases in salaries totaling approximately $211,000 were due primarily to a full twelve months of wages in 1998 for the increased number of new employee positions required by the Company's expansion in operations as a result of the Williston Basin lease acquisition versus only a partial year for the previous year. The $184,692 decrease in interest income in 1998 reflects the lower cash levels in interest bearing accounts during 1998 versus the prior year. 1997 Compared to 1996 Revenues from oil and gas sales increased 115% over 1996, to $976,000 from $455,000, as a result of significant new production from the successful completion of the nine new wells during the last part of the year. Lease operating expenses, related directly to the costs of operating the producing wells, accordingly increased to $176,000 from $75,000 in 1996. Exploration expenses, which includes the costs of unsuccessful wells, increased by 129% to $1,549,000 from $677,170, with $965,000 in dry hole costs related to the James #1-9F. The well was in the process of drilling at August 31, 1997, but subsequently did not produce sufficient hydrocarbons to be economically viable. Although the Company may re-enter the well and drill another lateral in a different direction, all costs related to the James #1-9F were accrued and included in fiscal 1997 operations as a loss, in accordance with generally accepted accounting principles. Other costs included non-cash expenses of $153,000 in abandoned leases, primarily represented by certain expired acreage in Canada, as well as depletion and depreciation of $293,000. General and administrative costs increased to $938,000 from $513,000 due primarily to increased salaries for new employee positions required by the Company's expansion in operations as a result of the Williston Basin lease acquisition. Although interest expense decreased by $141,500, this was almost all offset by the write-off of deferred financing fees on debt converted during the year. In total, revenues increased $561,000 or 108%, to $1,083,000 in 1997 from $521,000 in 1996. Cost of sales, including exploration expenses, general and administrative expenses, and abandoned leases, increased 119%, to $3,210,000 in 1997 from $1,465,000 in 1996, resulting in an increase in the Company's loss from its oil and gas operations to $2,127,000 in 1997 from $943,000 in 1996. The Company also incurred a loss on its investment in ExproFuels of $1,215,000 compared to $680,000 in 1996. However, since this investment has been written down to zero dollars, and no additional cash advances are expected after December 31, 1997, (advances committed to ExproFuels of $265,000 for September 1, 1997 to December 31, 1997 were accrued at August 31, 1997) operations should not suffer from this investment in future periods. As a result of the above, loss from operations increased to ($3,342,000) in 1997 from ($1,624,000) in 1996. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK None - See additional comments pertaining to certain business risk on page 8. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The Financial Statements and Notes thereto are set out in this Form 10-K commencing on page F-1. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES None 22 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The following table sets forth certain information regarding the directors and executive officers of the Company, as of November 10, 1999:
Name Position Age ---- -------- --- Stephen M. Gose, Jr. Chairman of the Board of Directors 69 Member Audit and Compensation Committees Michael Pint Director, Chairman Audit and Compensation Committees 56 Robert L. Foree, Jr. Director, Member Audit and Compensation Committees 70 Thomas H. Gose Director and Assistant Secretary 44 James E. Sigmon President and Director 51 Roberto R. Thomae Chief Financial Officer 48 Secretary/Treasurer, Vice President-Finance Richard A. Sartor Controller 47
Stephen M. Gose, Jr., has served as Chairman of the Board of Directors of the Company since July 1984. He has been a member of the Audit and Compensation Committees since June 1997 and served as their Chairman through April 1998. He has been active for more than 45 years in exploration and development of oil and gas properties, in real estate development, and in ranching through the operations of Retamco Operating, Inc., its predecessors and affiliates. Mr. Gose also serves as Chairman of the Board of Directors of ExproFuels, Inc. Michael Pint has served as a Director since May, 1997. He has been a member of the Audit and Compensation Committees of the Board of Directors since June, 1997 and has served as their Chairman since April, 1998. Since 1995, Mr. Pint has served as a Director of Valley Bancorp, Inc. and Valley Bank of Arizona, Inc. of Phoenix, Arizona and Midway National Bank of St. Paul, Minnesota. Previous bank regulatory and management positions include a four year term as Commissioner of Banks and Chairman of the Minnesota Commerce Commission from 1979 to 1983 and Senior Vice-President and Chief Financial Officer of the Federal Reserve Bank of Minneapolis, Minnesota through 1983. Robert L. Foree, Jr. has served as a Director since May, 1997 and as a member of the Audit and Compensation Committees of the Board of Directors since June, 1997. Since 1992, Mr. Foree has served as President of Foree and Company, a Dallas, Texas based independent oil and gas exploration and production company. Thomas H. Gose has served as a Director of the Company since February, 1989, as Secretary from 1992 through May, 1997 and as Assistant Secretary since May, 1997. He formerly served as Director, CEO and President of Retamco Operating, Inc., (a large shareholder of the Company) its predecessors and affiliates, since 1987. He also serves as President and Director of ExproFuels, Inc. Thomas H. Gose is the son of Stephen M. Gose, Jr. James E. Sigmon has served as the Company's President since February 1985. He has been a Director of the Company since July 1984. He served as a Director of ExproFuels, Inc. through November 1998. Prior to joining the Company, Mr. Sigmon served in the management of a private oil and gas exploration company active in drilling oil and gas wells in South Texas. Roberto R. Thomae has served as Chief Financial Officer and Vice President-Finance of the Company since September 1996 and as Secretary/Treasurer since March 1997. From September 1995 through September 1996 he was a consultant to the Company in a financial management capacity. From 1989 through 1995 Mr. Thomae was self- employed as a management consultant primarily involved in the development of domestic and international oil and gas exploration projects and the marketing of refined products. 23 Richard A. Sartor has served as Controller of the Company since April 1997. A Certified Public Accountant since 1980, Mr. Sartor owned his own private accounting practice from 1989 through March 1997. Each of the aforementioned Executive Officers and/or Directors have been elected to serve for one year or until his successor is duly elected. ITEM 11. EXECUTIVE COMPENSATION Summary Compensation Information: The following table contains certain information for each of the fiscal years indicated with respect to the chief executive officer and those executive officers of the Company as to whom the total annual salary and bonuses exceed $100,000:
SUMMARY COMPENSATION TABLE Name and Other Annual Long-term All other Principal Position Year Salary Bonuses Compensation Compensation Compensation - ------------------ ---- ------ ------- ------------ ------------ ------------ James E. Sigmon 1999 $ 150,000 $ 0 (1) $56,678 $ 0 $ 0 President & CEO 1998 132,000 0 (1) 41,623 0 0 1997 120,000 0 (1) 20,827 0 0
(1) Amounts represent income from an overriding royalty interest.
OPTIONS/SAR GRANTS IN LAST FISCAL YEAR % of Total Options Grant # Options Granted to Employees Exercise Price Expiration Date Name Granted in Fiscal Year per Share Date Value (1) - ----------------- ------- ------------------- ------------- ----------- ------------ Roberto R. Thomae 25,000 18% $0.98 2008 $23,750 CFO & Secr/Treas
(1) The fair value for all options granted, whether vested or not, was estimated at the date of grant using the Black-Scholes option pricing model with the following weighted-average assumption: risk-free interest rate of 5.0%; dividend yield of 0%; volatility factors of the expected market price of the Company's common stock of .95 and a weighted-average expected life of the option of five years. 24 AGGREGATED OPTION/SAR EXERCISES IN LAST FISCAL YEAR AND FISCAL YEAR END OPTION/SAR VALUES
Number of Unexercised Value of Unexercised # Shares Value Options/SARs Options/SARs Name Exercised Realized August 31, 1999 August 31, 1999 (1) --------- --------- -------- ----------------------- ------------------- James E. Sigmon (2) - - 700,000 $ 0 Michael Pint (3) - - 75,000 0 Robert L. Foree, Jr .(3) - - 75,000 0 Roberto R. Thomae (4) - - 75,000 $30,200
(1) Value of unexercised options calculated as the difference in the stock price at August 31,1999 and the option price. None of these unexercised options were "in the money" at August 31, 1999 and/or were not vested; accordingly the options are valued at $0 at year end. (2) 100,000 of Mr. Sigmon's unexercised options were exercisable as of August 31, 1999, and the remaining 600,000 options vest and are exercisable in specified amounts upon the Company's common stock attaining the following price levels: 200,000 shares at $5.00, 100,000 shares at $7.50, 100,000 shares at $10.00, 100,000 shares at $12.50 and 100,000 shares at $15.00. (3) 50,000 of Mr. Pint and Mr. Foree's options, respectively, were exercisable as of August 31, 1999. (4) 50,000 of Mr. Thomae's options were exercisable at August 31, 1999. COMPENSATION OF DIRECTORS Members of the Board of Directors who serve as Executive Officers of the Company are not compensated for any services provided as a Director. Outside (non-employee) Directors of the Company are paid a fee of $1,000 for each board meeting physically attended or $250 for telephonic attendance plus reimbursement of related travel expenses. Additionally, upon assuming Director status, the two outside directors were awarded 10 year options for the purchase of 75,000 shares of Company common stock at 110% of the stock's market value on the date of grant, with such options vesting equally over their first three years of service. EMPLOYMENT CONTRACTS The Company has an employment agreement with its president, Mr. James E. Sigmon, which sets his salary at a minimum of $150,000 annually, and includes the grant of a proportionately reduced 1% overriding royalty interest under all leases the Company has or acquires during his term as President. The agreement is cancelable with 90 days notice by the Company. COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION No Compensation Committee interlocks existed during the Company's last completed fiscal year. The Compensation Committee of the Board of Directors of the Company was established in June, 1997 and consists of Michael Pint (Chairman), Robert L. Foree, Jr. and. Stephen M. Gose, Jr. The principal function of the Committee is to approve the compensation of all executive officers of the Company, to recommend to the Board the terms of principal compensation plans requiring stockholder approval and to direct the administration of the Company's 1995 Flexible Incentive Plan. 25 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The following tables set forth beneficial ownership of the Company's common stock, its only class of equity security. The percent owned is based on 15,938,516 shares outstanding and 17,490,816 fully diluted shares which includes 1,552,300 shares under options and warrants as of November 1, 1999. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS The following table sets forth information concerning all persons known to the Company to beneficially own 5% or more if its common stock, including information filed pursuant to Rule 13d filings made available to the company during the year. Percent Owned Name and Address of Number of Shares Primary Shares Beneficial Owner Beneficially Owned Outstanding ------------------------------------------ ------------------ ----------- Thomas H. Gose ............................ 1,094,101 6.86% 500 North Loop 1604 East Suite 250 San Antonio, TX 78232 Stephen M. Gose, Jr ....................... 1,176,600 7.38% HCR Box 1010 Hwy 212 Roberts, Montana 59070 Trianon Opus One, Inc. .................... 1,400,000 8.78% Fohrenstrasse 25 CH-8703 Erlenbach Switzerland Pensionskasse der F. Hoffman La Roche A.G . 1,074,600 6.74% Funds I & II Grenzacherstrasse 124 4070 Basel Switzerland SECURITY OWNERSHIP OF DIRECTORS AND EXECUTIVE OFFICERS The following table sets forth the number of shares of common stock beneficially owned as of November 1, 1999 by each director, each executive officer named in the Summary Compensation Table and by all directors and executive officers as a group. Information provided is based on the Form 4's, stock records of the Company and the Company's transfer agent. Number of Shares Percent Name Beneficially Owned Owned (1) -------------------------- ------------------ --------- Stephen M. Gose, Jr. ....... (3) 1,176,600 7.38% Thomas H. Gose .............. 1,094,101 6.86% James E. Sigmon ............. (2) 750,000 4.51% Michael Pint ................ (4) 275,000 1.72% Robert L. Foree, Jr ......... (4) 61,000 .38% All Directors and Executive Officers as a group ........... 3,431,701 20.35% 26 (1) Except as otherwise noted, the Company believes that each named individual has sole voting and investment power over the shares beneficially owned. (2) The number of shares beneficially owned by Mr. James E. Sigmon includes 50,000 shares owned directly and 700,000 shares of the Company's Common Stock reserved for issuance through options issued under the Company's 1995 Flexible Incentive Plan. (3) The number of shares beneficially owned by Mr. Stephen M. Gose, Jr. include 30,000 shares owned directly, plus his 100% interest, shared equally with his spouse, in 1,146,600 shares owned by Retamco Operating, Inc. (4) The number of shares beneficially owned by Mr. Pint and Mr. Foree each includes 50,000 shares of the Company's Common Stock reserved for issuance under non-qualified options issued to outside directors of the Company exercisable at August 31, 1998 plus 225,000 and 11,000 respectively, of directly owned shares. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS During 1997, the Company purchased undeveloped oil and gas leases covering approximately 220,000 net acres for exploration in the Williston Basin of North and South Dakota and Montana. The acquisition was paid for with $22,000,000 cash and the issuance of 1,000,000 shares of common stock valued at $5 per share. A 67% interest in the leases was acquired from Retamco Operating, Inc., a company affiliated with two directors of the Company. Concurrently with the acquisition, the Company sold to third parties a 42.5% net profits interest in wells to be drilled on the oil and gas leases for $17,000,000 cash. The oil and gas leases acquired have been reported at the affiliates cost basis, which resulted in a reduction to the basis in the properties of $9,773,154 and a charge for the same amount to additional paid-in capital. The Company's ExproFuels division was spun off from The Exploration Company on September 3, 1996 with a 40% equity ownership being retained. During 1997 the Company's net investment in ExproFuels, Inc. was reduced to $0 by recognition of a $1,215,259 charge to operations. ExproFuels has no remaining assets and no current operations. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (A) The following documents are being filed as part of this annual report on Form 10-K after the signature page, commencing on page F-1. (1) Financial Statements: Independent Auditors' Reports. Balance Sheets, August 31, 1999 and 1998 Statements of Operations, Years Ended August 31, 1999, 1998 and 1997. Statements of Stockholders' Equity, Years Ended August 31, 1999, 1998 and 1997. Statements of Cash Flows, Years Ended August 31, 1999, 1998 and 1997. Notes to Financial Statements. (2) Financial Statement Schedule for the years ended August 31, 1999, 1998 and 1997: Schedule II - Valuation and Qualifying Reserves. All other schedules for which provision is made in the applicable accounting regulations of the Securities and Exchange Commission are omitted as the required information is inapplicable or the information is presented in the Consolidated Financial Statements or Notes thereto. 27 (3) Exhibits: ** 3.1 Articles of Incorporation of the Registrant filed as Exhibit 3(B) to the registration statement on Form S-1; Reg. No. 2-65661. ** 3.2 Articles of Amendment to Articles of Incorporation of The Exploration Company, dated July 27, 1984, filed as Exhibit 3.2 to Registrant's Annual report on Form 10-K, dated February 4, 1985. ** 3.3 Articles of Amendment to the Articles of Incorporation of the Exploration Company dated April 2, 1985. ** 3.4 By-Laws of the Registrant filed as Exhibit 5(A) to the Registration Statement on Form S-1; Reg. 2-65661. ** 3.5 Amendment to By-Laws of registrant, dated Sept 1, 1985. ** 3.6 Articles of Amendment to the Articles of Incorporation of The Exploration Company dated April 6, 1990. **10.2 Employment Agreement between the Registrant and James E. Sigmon, dated October 1, 1984. **10.3 Registrant's Amended and Restated 1983 Incentive Stock Option Plan filed as Exhibit A to registrant's definitive Proxy Statement, dated February 20, 1985. **10.4 Registrant's 1995 Flexible Incentive Plan, filed as Exhibit A to registrant's definitive Proxy Statement, dated April 28, 1995. **10.5 Registrant's Form S-8 Registration Statement for its 1995 Flexible Incentive Plan, dated November 26, 1996. **10.6 Registrant's Amendment to its 1995 Flexible Incentive Plan, filed as Proposal II of the registrants definitive Proxy Statement, dated Jan 12,1999. **10.7 Registrant's Plan and Agreement of Merger of The Exploration Company with and into The Exploration Company of Delaware, Inc., filed as Appendix A of the registrants definitive Proxy Statement, dated January 12, 1999. **10.8 Registrant's Certificate of Incorporation of The Exploration Company of Delaware, Inc., filed as Appendix B of the registrants definitive Proxy Statement, dated January 12, 1999. **10.9 Registrant's Certificate of Amendment of Certificate of Incorporation of The Exploration Company of Delaware, Inc., filed as Appendix C of the registrants definitive Proxy Statement, dated January 12, 1999. **10.10 Registrant's Bylaws of The Exploration Company of Delaware, Inc., filed as Appendix D of the registrants definitive Proxy Statement, dated January 12, 1999. 27.1 Financial Data Schedule ** Previously filed (B) Reports on Form 8-K: None Filed 28 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized. THE EXPLORATION COMPANY OF DELAWARE, INC. Registrant November 23, 1999 By: /s/ James E. Sigmon --------------------------------- James E. Sigmon, President Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signatures Title Date - ----------- ----------------------------------- ----------- /s/ Stephen M. Gose, Jr. - ----------------------------- Stephen M. Gose, Jr. Chairman of the Board of Directors November 23, 1999 /s/ Thomas H. Gose - ---------------------------- Thomas H. Gose Director and Assistant Secretary November 23, 1999 /s/ James E. Sigmon - ---------------------------- James E. Sigmon President and Director (Principal Executive Officer) November 23, 1999 /s/ Michael Pint - ---------------------------- Michael Pint Director November 23, 1999 /s/ Robert L. Foree, Jr. - ---------------------------- Robert L. Foree, Jr. Director November 23, 1999 /s/ Roberto R. Thomae - ---------------------------- Roberto R. Thomae Chief Financial Officer November 23, 1999 Secretary/Treasurer (Principal Accounting Officer)
F-1 INDEPENDENT AUDITORS' REPORT The Board of Directors and Stockholders The Exploration Company San Antonio, Texas We have audited the balance sheets of The Exploration Company of Delaware, Inc. (hereinafter referred to as "The Exploration Company") as of August 31, 1999 and 1998, and the related statements of operations, stockholders' equity and cash flows for each of the three years in the period ended August 31, 1999. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of The Exploration Company as of August 31, 1999 and 1998, and the results of its operations and cash flows for each of the three years in the period ended August 31, 1999, in conformity with generally accepted accounting principles. We have also audited Schedule II of The Exploration Company for each of the three years in the period ended August 31, 1999. In our opinion, this schedule presents fairly, in all material respects, the information required to be set forth therein. AKIN, DOHERTY, KLEIN & FEUGE, P.C. San Antonio, Texas November 12, 1999 F-2 THE EXPLORATION COMPANY Balance Sheets August 31, 1999 and 1998
1999 1998 ---------- ---------- Assets Current Assets: Cash and equivalents $ 968,516 $ 2,329,236 Accounts receivable: Joint interest owners 583,985 293,931 Oil and gas production 1,669,364 567,735 Prepaid expenses and other 256,334 17,738 ------------ ------------ Total current assets 3,478,199 3,208,640 Property and Equipment: Oil and gas properties (successful efforts), less accumulated depreciation, depletion and amortization of $4,353,550 and $2,073,491, and accumulated impairment of $2,323,584 and $3,894,739 13,538,938 12,502,566 Other property and equipment: Transportation and other equipment, less accumulated depreciation of $179,211 and $132,977 89,114 103,862 ------------ ------------ Net property and equipment 13,628,052 12,606,428 Other Assets 447,564 449,564 ------------ ------------ Total Assets $ 17,553,815 $ 16,264,632 ============ ============
See notes to audited financial statements. F-3 THE EXPLORATION COMPANY Balance Sheets August 31, 1999 and 1998
1999 1998 ---------- ---------- Liabilities And Stockholders' Equity Current Liabilities: Accounts payable and accrued expenses $ 678,478 $ 737,157 Due to joint interest owners 1,760,248 108,407 Current portion of long-term debt 2,565,067 1,846,383 ------------ ------------ Total current liabilities 5,003,793 2,691,947 Long-Term Debt, net of current portion 529,742 2,977,544 Stockholders' Equity: Preferred stock; authorized 10,000,000 shares, issued and outstanding -0- shares - - Common stock, par value $ .01 per share; authorized 50,000,000 shares; issued and outstanding 15,938,516 and 15,613,516 shares 159,385 156,135 Additional paid-in capital 40,651,444 40,161,100 Accumulated deficit (28,790,549) (29,722,094) ------------ ------------ Total stockholders' equity 12,020,280 10,595,141 ------------ ------------ Total Liabilities and Stockholders' Equity $ 17,553,815 $ 16,264,632 ============ ============
See notes to audited financial statements. F-4 THE EXPLORATION COMPANY Statements of Operations Years Ended August 31, 1999, 1998 and 1997
1999 1998 1997 ---------- ---------- ---------- Revenues: Oil and gas sales $ 6,881,767 $ 2,886,676 $ 976,882 Other operating income 615,608 161,601 106,629 ------------ ------------ ------------ 7,497,375 3,048,277 1,083,511 Costs and Expenses: Lease operations 864,675 700,381 176,019 Production taxes 471,193 178,912 71,954 Exploration expenses 269,344 2,290,649 1,549,095 Abandoned leases and equipment 323,784 1,451,880 153,066 Impairment of mineral properties 300,000 3,775,342 28,400 Depreciation, depletion and amortization 2,327,992 1,446,726 293,527 General and administrative 1,442,338 1,278,270 938,638 Net loss from ExproFuels equity ownership - - 1,215,259 ------------ ------------ ------------ Total costs and expenses 5,999,326 11,122,160 4,425,958 Income (loss) from operations 1,498,049 (8,073,883) (3,342,447) Other Income (Expense): Interest income 73,892 98,770 283,462 Interest expense (628,396) (260,105) (236,494) Loan fee amortization (12,000) (182,000) (103,387) ------------ ------------ ------------ (566,504) (343,335) (56,419) ------------ ------------ ------------ Net Income (Loss) $ 931,545 $ (8,417,218) $ (3,398,866) ============ ============ ============ Amounts Per Common Share: Basic income (loss) $ 0.06 $ (0.55) $ (0.27) ============ ============ ============ Diluted income (loss) $ 0.06 $ (0.55) $ (0.27) ============ ============ ============ Weighted average number of common shares outstanding: Basic 15,668,721 15,328,292 12,576,255 ============ ============ ============ Diluted 15,678,567 15,328,292 12,576,255 ============ ============ ============
See notes to audited financial statements. F-5 THE EXPLORATION COMPANY Statements of Stockholders' Equity Years Ended August 31, 1999, 1998, and 1997
Additional Common Stock Paid-in Accumulated Shares Amount Capital Deficit Total ------ ------ ------- ------- ----- Balance at September 1, 1996 9,426,650 $ 94,266 $ 23,482,432 $ (17,906,010) $ 5,670,688 Issuance of common stock for cash 3,280,000 32,800 14,492,200 - 14,525,000 Issuance of common stock in exchange for oil and gas properties 1,000,000 10,000 4,990,000 - 5,000,000 Adjustment of oil and gas properties to affiliates historical cost basis - - (9,773,154) - (9,773,154) Common stock warrants exercised 180,000 1,800 480,600 - 482,400 Conversion of debt to common stock 872,548 8,726 2,255,976 - 2,264,702 Net loss for the year - - - (3,398,866) (3,398,866) ----------- --------- ----------- ------------ ----------- Balance at August 31, 1997 14,759,198 147,592 35,928,054 (21,304,876) 14,770,770 Conversion of debt to common stock 844,318 8,443 4,213,146 - 4,221,589 Common stock warrants exercised 10,000 100 19,900 20,000 Net loss for the year - - - (8,417,218) (8,417,218) ----------- --------- ----------- ------------ ----------- Balance at August 31, 1998 15,613,516 156,135 40,161,100 (29,722,094) 10,595,141 Issuance of common stock in exchange for oil and gas properties 325,000 3,250 490,344 - 493,594 Net income for the year - - - 931,545 931,545 ------------ --------- ------------ ------------- ------------ Balance at August 31, 1999 $ 15,938,516 $ 159,385 $ 40,651,444 $ (28,790,549) $ 12,020,280 ============ ========= ============ ============= ============
See notes to audited financial statements. F-6 THE EXPLORATION COMPANY Statements of Cash Flows Years Ended August 31, 1999, 1998, and 1997
1999 1998 1997 ---------- ----------- ----------- Operating Activities: Net income (loss) $ 931,545 $ (8,417,218) $ (3,398,866) Adjustments to reconcile net income (loss) to net cash provided (used) in operating activities: Depreciation, depletion and amortization 2,327,992 1,446,726 293,527 Amortization of financing fees 12,000 162,000 83,887 Abandoned leases, equipment and other 323,784 1,451,880 153,066 Impairment of properties 300,000 3,775,342 28,400 ExproFuels operations and loan loss reserve - 1,215,259 Changes in operating assets and liabilities: Receivables (1,391,683) (499,240) (290,839) Prepaid expenses and other (238,596) 31,346 (49,084) Accounts payable and accrued expenses 1,593,162 864,114 1,586,380 ------------ ----------- ----------- Net cash provided (used) in operating activities 3,858,204 (1,185,050) (378,270) Investing Activities: Development of oil and gas properties (3,448,320) (4,806,505) (12,924,068) Purchase of transportation and other equipment (31,486) (42,288) (115,071) Investments in and advances to ExproFuels - - (826,224) Other assets (10,000) - (331,036) ------------ ----------- ----------- Net cash (used) in investing activities (3,489,806) (4,848,793) (14,196,399) Financing Activities: Proceeds from long-term debt 900,000 3,646,000 5,008,140 Payments on long-term debt (2,629,118) (1,500,990) (210,640) Issuance of common stock, net of expenses - 20,000 15,007,400 ------------ ----------- ----------- Net cash provided (used) by financing activities (1,729,118) 2,165,010 19,804,900 ------------ ----------- ----------- Change in Cash and Equivalents (1,360,720) (3,868,833) 5,230,231 Cash and Equivalents at Beginning of Year 2,329,236 6,198,069 967,838 ------------ ----------- ----------- Cash and Equivalents at End of Year $ 968,516 $ 2,329,236 $ 6,198,069 ============ =========== =========== Supplemental Disclosures: Cash paid for interest $ 721,292 $ 82,295 $ 151,955 Cash paid for income taxes - - -
See notes to audited financial statements. F-7 THE EXPLORATION COMPANY Notes to Audited Financial Statements August 31, 1999, 1998 and 1997 NOTE A - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Organization and Operations: The financial statements include the accounts of The Exploration Company (the Company) which is engaged in the business of acquiring, exploring and developing oil and gas properties. The Company=s oil and gas operations are located primarily in Texas, North Dakota and Montana. During 1999, the Company changed its State of Incorporation from Colorado to Delaware and, as a result, changed its legal name to The Exploration Company of Delaware, Inc. However, the Company continues to conduct all business under the name The Exploration Company. From 1993 through 1996, the Company operated in the alternative fuels industry through a division called ExproFuels. Cash and Equivalents: Cash and equivalents consist of all demand deposits and funds invested in short-term investments with original maturities of three months or less. All of the Company's cash and money market accounts are maintained with Frost National Bank and AIM Institutional Fund Services, Inc. At year end, the Company did not have any cash equivalents in excess of insured limits. Oil and Gas Properties: The Company uses the successful efforts method of accounting for its oil and gas activities. Costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells that find proved reserves, and to drill and equip development wells are capitalized. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed as incurred. Depreciation, depletion and amortization (DD&A) of oil and gas properties are computed using the unit-of-production method based upon recoverable reserves as determined by Company engineers. Oil and gas properties are periodically assessed for impairment, and if the unamortized capitalized costs of proved properties are in excess of the discounted present value of future cash flows relating to proved reserves, an impairment charge is recorded. Unproved properties are also evaluated periodically and if the unamortized cost is in excess of estimated fair value an impairment is recognized. Other Property and Equipment: Transportation and other equipment are recorded at cost. Depreciation is computed using the straight-line method over the estimated useful lives of the assets ranging from five to fifteen years. Major renewals and betterments are capitalized while repairs are expensed as incurred. Included in other property and equipment are an insignificant amount of assets under capital lease. Amortization related to capital lease obligations is included in the Statement of Operations under depreciation, depletion and amortization. Federal Income Taxes: Deferred tax assets and liabilities are determined based on differences between financial reporting and tax basis of assets and liabilities, and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. A valuation allowance is provided against net deferred assets for which realization is doubtful. Income (Loss) Per Common Share: Income (loss) per common share is calculated in accordance with Financial Accounting Standards Board Statement No. 128. Basic income (loss) per share considers as outstanding only common stock, without giving any effect to options or warrants. Diluted income per share gives effect to options and warrants using the treasury stock method. F-8 NOTE A - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - continued Comprehensive Income: During 1998, the Company adopted Statement No. 130, Reporting Comprehensive Income. Statement No. 130 establishes new rules for the reporting and display of comprehensive income and its components; however, the adoption of this Statement had no impact on the Company's net income or stockholders' equity as previously reported or in the current year. Concentrations of Credit Risk: Financial instruments that potentially expose the Company to credit risk consist principally of accounts receivable. Accounts receivable, net of allowance of $27,026 at August 31, 1999, are generally from companies with significant oil and gas marketing activities. The Company performs ongoing credit evaluations and generally requires no collateral from customers. Use of Estimates: The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Management believes that it is reasonably possible that estimates of proved crude oil and natural gas reserves could significantly change in the future. Stock-Based Compensation: Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation," encourages, but does not require, companies to record compensation cost for stock-based employee compensation plans at fair value. The Company has chosen to continue to account for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board Opinion No. 25 "Accounting for Stock Issued to Employees," and related interpretations. Accordingly, compensation cost for stock options is measured as the excess, if any, of the quoted market price of the Company's stock at the date of the grant over the amount an employee must pay to acquire the stock. Government Regulations: Substantially all of the Company's producing oil and gas properties are subject to Federal, state and local provisions regulating the discharge of materials into the environment. Management believes that its current practices and procedures for the control and disposition of such wastes comply with applicable federal and state requirements. Restoration, Removal and Environmental Matters: The estimated costs of restoration and removal of producing property well sites is generally less than the estimated salvage value of the respective property and, accordingly, the Company has not provided for a liability accrual. The estimated future costs for known environmental remediation requirements are accrued when it is probable that a liability has been incurred and the amount of remediation costs can be reasonably estimated. The Company is not aware of any such remediation requirements material to its operations. Fair Value of Financial Instruments: The only financial instruments of the Company are cash and equivalents, trade accounts receivable and payable, and long-term debt. In all cases the carrying amount of financial instrument approximates fair value. Revenue Recognition: The Company recognizes oil and gas revenue from its interest in producing wells as the oil and gas is sold from the wells. F-9 NOTE B - LONG TERM DEBT Long-term debt consists of the following at August 31:
1999 1998 ---------- ----------- Note payable to Range Energy Finance Corporation, with interest at 18% and payable from an overriding royalty interest (ORRI) granted to Range in certain oil and gas properties currently producing, as well as those completed and to be drilled on its Maverick County, Texas leasehold acreage subsequent to June 1, 1998. The ORRI terminates upon final payment of the debt. $ 2,279,669 $ 3,346,625 Note payable to Continental Resources, Inc. with interest at 9.50%, due in monthly installments of $30,000, with final payment in 2001, and collateralized by certain oil and gas properties. 562,396 847,053 Note payable to Union Pacific Resources, with interest at 8%, due in monthly installments of $10,000, with final payment in 2001, and collateralized by certain oil and gas properties. 212,957 318,672 Note payable to Caza Drilling with interest at 14%, due in monthly installments of $35,000 with final payment in December 1998, unsecured. - 165,503 Note payable to Quantum Geophysical, with interest at 12%, due in monthly installments of $15,940, with final payment in 1999, and unsecured. - 77,367 Installment notes with interest from 8.5% to 22.64%, due in current monthly installments of $5,631. 39,787 68,707 ------------ ------------ Total long-term debt 3,094,809 4,823,927 Less current portion (2,565,067) (1,846,383) ------------ ------------ Long-term portion of debt $ 529,742 $ 2,977,544 ============ ============
F-10 NOTE B - LONG TERM DEBT - continued The following is a schedule of maturities of long-term debt as of August 31, 1999: Fiscal Year Ended August 31 Amount 2000 $ 2,565,067 2001 529,742 ----------- $ 3,094,809 =========== NOTE C - STOCKHOLDERS' EQUITY Preferred Stock: The Company has authorized 10,000,000 shares of preferred stock, none of which has been issued at August 31, 1999. Terms of the stock have not been established by the Board of Directors. Stock Options: The Company grants options to its officers, directors, and key employees under its 1995 Flexible Incentive Plan. In 1998, the Company also issued options for the purchase of 600,000 shares of common stock under a nonqualified plan. The Company has elected to follow Accounting Principles Board Opinion No. 25, AAccounting for Stock Issued to Employees,@ (APB 25) and related Interpretations in accounting for its employee stock options because, as discussed below, the alternative fair value accounting provided for under FASB Statement No. 123, AAccounting for Stock-Based Compensation,@ (FASB 123) requires use of option valuation models that were not developed for use in valuing employee stock options. Under APB 25, because the exercise price of the Company=s stock options equals or exceeds the market price of the underlying stock on the date of grant, no compensation expense is recognized. The Company's 1995 Flexible Incentive Plan was authorized to grant options to management, directors, and key personnel for up to 400,000 shares of the Company's common stock. During 1999, the Plan was amended to increase the number of options to allow for the purchase of up to 1,500,000 common stock shares. All options granted have ten year terms and vest and become fully exercisable based on the specific terms imposed at the date of grant. Pro forma information regarding net income and earnings per share is required by FASB 123, which also requires that the information be determined as if the Company has accounted for its employee stock options granted subsequent to August 31, 1995 under the fair value method of that Statement. The fair value for these options was estimated at the date of grant using a Black-Scholes option pricing model with the following weighted-average assumptions for 1999, 1998 and 1997, respectively: risk-free interest rates of 5.0%, 4.0%, and 6.25%; dividend yields of -0-%; volatility factors of the expected market price of the Company's common stock of .95, .69, and .33; and a weighted-average expected life of the option of five years. F-11 NOTE C - STOCKHOLDERS' EQUITY - continued The Black-Scholes option valuation model was developed for use in estimating the fair value of trade options which have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility. Because the Company's employee stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management's opinion, the existing models do not necessarily provide a reliable single measure of the fair value of its employee stock options. For purposes of pro forma disclosures, the estimated fair value of the options is amortized to expense over the options' vesting period. The Company's pro forma information is as follows for the years ended August 31:
1999 1998 1997 ---------- ---------- ---------- Pro forma net income (loss) $ 695,970 $ (8,608,865) $ (3,539,881) Pro forma net (income) loss per common share: Basic $ 0.04 $ (0.56) $ (0.28) Diluted 0.04 N/A N/A
A summary of the status of the Company's stock option activity and related information for the years ended August 31, is as follows:
1999 1998 ---------------------------- ----------------------------- Weighted-Average Weighted-Average Shares Exercise Price Shares Exercise Price ---------- --------------- ---------- ---------------- Outstanding options at beginning of year 1,029,800 $ 2.95 439,800 $ 4.06 Granted 139,000 1.20 600,000 2.12 Exercised - - (10,000) 2.00 Forfeited (124,000) 2.70 - - ---------- ------ ---------- -------- Outstanding options at end of year 1,044,800 $ 2.72 1,029,800 $ 2.95 ========== ====== ========== ====== Exercisable at end of year 334,800 $ 4.32 379,800 $ 3.78 ========== ====== ========== ====== Weighted-average fair value of options granted during the year $ 0.95 $ 0.48 ====== ======
F-12 NOTE C - STOCKHOLDERS' EQUITY - continued The following table summarizes information about the options outstanding at August 31, 1999:
Options Outstanding Options Exercisable ------------------------------------------------- ----------------------------- Weighted-Average Number Remaining Weighted-Average Number Weighted-Average Exercise Price Outstanding Contractual Life Exercise Price Exercisable Exercise Price --------------- ----------- ---------------- ---------------- ----------- --------------- $ 0.98 25,000 10.0 years $ 25,000 $ 0.98 1.25 110,000 10.0 years 1.25 - 1.25 2.125 600,000 8.6 years 2.12 - 2.12 2.62 50,000 7.0 years 2.62 50,000 2.62 2.75 100,000 6.5 years 2.75 100,000 2.75 3.91 9,800 2.3 years 3.91 9,800 3.91 6.60 150,000 7.6 years 6.60 150,000 6.60 ---------- ----------- ------ --------- ------ 1,044,800 8.2 years $ 2.72 334,800 $ 3.78 ========== =========== ====== ========= ======
Stock Warrants: The following is a summary of warrants outstanding at August 31, 1999:
Weighted Weighted Average Average Number Range of Exercise Contractual Purpose of Warrants Outstanding Prices Price Life ------------------- ----------- ------ ----- ---- Convertible notes and equity financing 457,500 $ 2.00 - $ 6.00 $ 3.31 3 years Services rendered 50,000 $ 2.18 2.18 1 year
F-13 NOTE D - EARNINGS PER SHARE The following is a reconciliation of the numerators and denominators of the basic and diluted earnings per share (EPS) computation for the year ended August 31, 1999:
Per Share Income Shares Amount ------ ------ ------ Basic EPS: Net income $ 931,545 15,668,721 $ 0.06 Effect of dilutive options 9,846 --------- ----------- ------ Dilutive EPS $ 931,545 15,678,567 $ 0.06 ========= =========== ======
Options and warrants exercisable to purchase 813,300 shares of common stock were outstanding at August 31, 1999 but were not included in the computation of diluted EPS because the exercise price was greater than the average market price of the common shares. The 1998 and 1997 loss per share does not include the effect of options and warrants as their impact would be antidilutive given the Company's loss position in those years. NOTE E - OPERATING LEASES The Company leases its primary office space for $7,676 per month through February 2000. For the years ended August 31, 1999, 1998, and 1997, the Company incurred rent expense of approximately $95,000, $94,000, and $92,000, respectively. Future minimum rentals under all noncancellable real estate leases are as follows: Fiscal Year Ended August 30 Amount ------------ --------- 2000 $ 46,057 F-14 NOTE F - FEDERAL INCOME TAXES The Company has incurred losses for both financial statement and income tax purposes in prior years. A valuation allowance equal to the net deferred tax asset has been recorded due to the uncertainty of the realization of the asset. The following items give rise to the deferred tax assets and liabilities at August 31: 1999 1998 ---------- ------------ Deferred tax assets: Tax net operating loss carryforwards ........... $ 23,055,000 $ 24,575,000 Impairment of oil and gas and mineral properties 2,485,000 4,118,000 ------------ ----------- Gross deferred tax assets ........................ 25,540,000 28,693,000 Statutory tax rate ............................... 34% 34% ------------ ----------- Net deferred tax assets .......................... 8,683,600 9,755,620 Less valuation allowance ......................... (8,683,600) (9,755,620) ------------ ---------- Deferred income tax asset recorded ............... $ -- $ -- ============ ========== The net operating loss carryforwards available at August 31, 1999, and the related expiration dates are as follows: Expires August 31 Amount --------- ------------- 2000 $ 480,000 2001 1,200,000 2002 1,960,000 2003 708,000 2004 168,000 2005 to 2009 5,850,000 2010 to 2014 12,689,000 ------------- $ 23,055,000 ============= F-15 NOTE G - RELATED PARTY TRANSACTIONS During 1997, the Company purchased undeveloped oil and gas leases covering approximately 222,000 net acres for exploration in the Williston Basin of North and South Dakota and Montana. The acquisition was paid for with $22,000,000 cash and the issuance of 1,000,000 shares of common stock valued at $5 per share. 67% of the acquisition was from a company affiliated with two directors of the Company. Concurrently with the acquisition, the Company sold to third parties a 42.5% net profits interest in wells to be drilled on the oil and gas leases for $17,000,000 cash. The oil and gas leases acquired were reported at the affiliates historical cost basis, which resulted in a reduction to the basis in the properties of $9,773,154, and a charge for the same amount to additional paid-in capital. The Company's ExproFuels division was spun off from The Exploration Company on September 3, 1996, with a 40% equity ownership being retained. During 1997, the Company's net assets in ExproFuels, Inc. was reduced to $0 by recognition of a $1,215,259 charge to operations. ExproFuels, Inc. has no remaining assets and no current operations. NOTE H - SEGMENT INFORMATION AND MAJOR CUSTOMERS The Company operates only in the oil and gas industry. The Company's oil and gas sales include amounts sold to major purchasers in the three years ended August 31, as follows: Purchaser 1999 1998 1997 - --------- --------- --------- --------- A . $ 3,800,000 $ -- $ -- B . 150,000 985,000 -- C . 480,000 810,000 732,000 D . 1,630,000 595,000 -- E . -- 122,000 NOTE I - SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION Year Ended August 31, 1999 The Company issued 325,000 shares of its common stock in exchange for oil and gas properties (valued at the market price per share for unregistered stock). Year Ended August 31, 1998 The Company converted $4,000,000 of convertible notes payable and $221,590 of accrued interest into 844,318 shares of its common stock. The Company converted $1,684,000 of accounts payable into long-term debt. Year Ended August 31, 1997 The Company issued 1,000,000 shares of its common stock in exchange for oil and gas properties (valued at the market price per share for unregistered stock). The Company converted $2,264,702 of debentures into 872,548 shares of its common stock. F-16 NOTE J - OIL AND GAS PRODUCING ACTIVITIES AND PROPERTIES Capitalized Costs and Costs Incurred Relating to Oil and Gas Activities The Company's investment in oil and gas properties is as follows at August 31: 1999 1998 ------------ ------------ Proved properties ............ $ 12,948,366 $ 9,098,623 Less reserve for impairment .. (2,323,584) (2,314,592) Less accumulated depreciation, depletion and amortization . (4,353,550) (2,073,491) ------------ ------------ Net proved properties ... 6,271,232 4,710,540 Unproved properties .......... 7,429,182 9,372,026 Less reserve for impairment .. (161,476) (1,580,000) ------------ ------------ Net unproved properties . 7,267,706 7,792,026 ------------ ------------ Net capitalized cost ......... $ 13,538,938 $ 12,502,566 ============ ============ Costs incurred, capitalized, and expensed in oil and gas producing activities are as follows:
1999 1998 1997 -------- -------- -------- Property acquisition costs, unproved $ 890,418 $ 1,232,000 $ 13,517,743 Property development and exploration costs 3,340,702 6,286,745 4,024,922 Depreciation, depletion and amortization 2,281,758 1,103,181 258,000 Depletion per equivalent MCF of production .69 .93 .75
F-17 NOTE J - OIL AND GAS PRODUCING ACTIVITIES AND PROPERTIES - continued Estimated Quantities of Proved Oil and Gas Reserves (Unaudited) The following estimates of proved developed and undeveloped reserve quantities and related standardized measure of discounted net cash flow are estimates only, and do not purport to reflect realizable values or fair market values of the Company's reserves. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. Proved reserves are estimates of crude oil (including condensate and natural gas liquids) and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those expected to be recovered through existing well, equipment and operating methods. The estimates have been prepared by an independent reservoir engineering firm. Oil Gas (Barrels) (MCF) Reserves at August 31, 1996 ...................... 20,570 1,893,490 Discoveries .................................. 289,770 1,147,345 Revisions of previous estimates .............. (41,554) (678,676) Production ................................... (23,086) (206,059) ---------- ---------- Reserves at August 31, 1997 ...................... 245,700 2,156,100 Discoveries .................................. 70,700 4,541,500 Revisions of previous estimates .............. (136,662) 117,852 Production ................................... (79,138) (713,752) ---------- ---------- Reserves at August 31, 1998 ...................... 100,600 6,101,700 Discoveries .................................. 32,000 2,803,000 Purchases of minerals in place ............... 1,600 338,000 Revisions of previous estimates .............. 53,800 (166,700) Production ................................... (82,000) (2,813,000) ---------- ---------- Reserves at August 31, 1999 ...................... 106,000 6,263,000 ========== ========== Substantially all of the Company's proved reserves are developed and are located in the continental United States. F-18 NOTE J - OIL AND GAS PRODUCING ACTIVITIES AND PROPERTIES - continued Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited) The "Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves" (Standardized Measure) presented below is computed in accordance with SFAS No. 69. The Standardized Measure does not purport to present the fair market value of a company's proved oil and gas reserves. This would require consideration of expected future economic and operating conditions, which are not taken into account in calculating the Standardized Measure. Under the Standardized Measure, future cash inflows were estimated by applying year-end prices, adjusted for fixed determinable escalations, to the estimated future production and development costs based on year-end costs to determine pre-tax cash inflows. Future income taxes were computed by applying the statutory tax rate to the excess of pre-tax cash inflows over the company's basis in the associated proved oil and gas properties. Tax credits, permanent differences and net operating loss carryforwards were also considered in the future income tax calculations, thereby reducing the expected tax expense to zero. Set forth below is the Standardized Measure relating to proved oil and gas reserves at August 31:
1999 1998 1997 -------------- ------------ ------------ Future cash inflows $ 17,370,000 $ 11,872,000 $ 8,814,000 Future production and development costs (2,484,000) (1,327,000) (1,919,000) ------------ ------------- ----------- Future net cash inflows before income tax 14,886,000 10,545,000 6,895,000 Future income tax expense - - - ------------ ------------- ----------- Future net cash flows 14,886,000 10,545,000 6,895,000 10% annual discount to reflect timing of net cash flows (2,441,000) (1,721,000) (2,163,000) ------------ ------------- ----------- Standardized Measure of discounted future net cash flows relating to proved reserves $ 12,445,000 $ 8,824,000 $ 4,732,000 ============ ============= ============
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited) The following is an analysis of the changes in the Standardized Measure:
1999 1998 1997 ------------ ------------ ----------- Standardized Measure, beginning of year $ 8,824,000 $ 4,732,000 $ 2,199,740 Discoveries 6,810,000 7,683,000 5,741,710 Purchases of minerals in place 350,000 - - Sales and transfers, net of production costs (5,545,899) (2,007,383) (728,909) Revisions in quantity and price estimates 2,888,899 (1,110,417) (2,260,567) Accretion of discount (882,000) (473,200) (219,974) ------------ ----------- ----------- Standardized Measure, end of year $ 12,445,000 $ 8,824,000 $ 4,732,000 ============ =========== ===========
F-19 NOTE K - YEAR 2000 Over the last three years the Company has replaced or upgraded most of the core management information systems used in the Company's business. The Company has conducted a review of these systems to verify their compliance with Year 2000 date codes. In addition, the Company has conducted an inventory, review and assessment of its desktop computers, networks and servers, software applications and packages, and products and services provided by third parties for internal operations to determine whether or not they support Year 2000 date codes. The Company believes it has successfully completed required modifications to all mission critical applications included in its internal systems. In addition, the Company has contacted its major gas purchasers, gas pipeline carriers, stock transfer agent and banking institutions and received written assurances and/or viewed assurances on their websites that they have no material Year 2000 problems. The Company does not believe the Year 2000 issue will materially affect its ability to pay its vendors and suppliers, track its assets in the custody of financial institutions or otherwise prevent it from conducting its business on an ongoing basis. F-20 THE EXPLORATION COMPANY Schedule II - Valuation and Qualifying Reserves For the Three Years Ended August 31, 1999
Balance . Charges to Balance Beginning Costs and End of of Period Expense Write-offs Period --------- ------- ---------- ------ Year ended August 31, 1999 Allowance for doubtful accounts - trade accounts ........... $ 27,000 $ -- $ -- $ 27,000 Impairment of oil and gas properties ....................... 3,894,739 147,369 (1,718,524) 2,323,584 Year ended August 31, 1998 Allowance for doubtful accounts - trade accounts .......... $ -- $ 27,000 $ -- $ 27,000 Impairment of loan to ExproFuels, Inc. ..................... 845,487 -- (845,487) -- Impairment of oil and gas properties ....................... 119,397 3,775,342 -- 3,894,739 Year ended August 31, 1997 Allowance for doubtful accounts - trade accounts .......... $ 9,973 $ -- $ (9,973) $ -- Impairment of loan to ExproFuels, Inc. ..................... -- 845,487 -- 845,487 Impairment of oil and gas properties ...................... 90,997 28,400 -- 119,397
EX-27 2 ARTICLE 5 FDS FOR 10-K FOR THE EXPLORATION COMPANY
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE EXPLORATION COMPANY AUDITED FINANCIAL STATEMENTS FOR THE YEAR ENDED AUGUST 31, 1999 AND IS QUALIFED IN ITS ENTIRETY BY REFERENCE TO SUCH. 0000313395 THE EXPLORATION COMPANY 1 US DOLLAR 12-MOS AUG-31-1999 SEP-01-1998 AUG-31-1999 1 968516 0 2253349 0 0 3478199 20484397 6856345 17553815 5003793 529742 0 0 159385 11860895 17553815 7497375 7497375 4556988 5999326 0 0 640396 931545 0 931545 0 0 0 931545 .06 .06
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