-----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, FF63LhBoMyUi7jakwLLSHw2JVLEfDgOqEXuqGLW2ftt/McxovFN+mMUfoe+Lyasw YP8tLMZlSnCPJCPBU21+pw== 0000313395-98-000054.txt : 19981201 0000313395-98-000054.hdr.sgml : 19981201 ACCESSION NUMBER: 0000313395-98-000054 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19980831 FILED AS OF DATE: 19981130 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: 98760842 BUSINESS ADDRESS: STREET 1: 500 N LOOP 1604 E STE 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 YEAR ENDED AUGUST 31, 1998 Page 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, 1998 |_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File Number 0-9120 THE EXPLORATION COMPANY (Exact name of Registrant as specified in its charter) Colorado 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. |X| The aggregate market value of the voting stock (which consists solely of shares of Common Stock) held by non-affiliates of the registrant is $16,028,405 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 10, 1998. The number of shares outstanding of the Registrant's Common Stock as of November 10, 1998, was 15,613,516 of which 13,148,815 shares were held by non-affiliates. Documents Incorporated by Reference: None Page 2 INDEX AND CROSS REFERENCE SHEET
PART I Page Item 1. Business..................................................................................... 3 Item 2. Properties................................................................................... 11 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.......................................................................... 27 Signatures................................................................................................ 28 Audited Financial Statements of The Exploration Company.................................................. F-0
Page 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. Throughout its history, the Company's primary focus has been oil and gas and mineral exploration and production. Its business strategy has been to acquire undeveloped mineral interests, 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, to explore and develop these internally-developed prospects and to selectively participate with industry partners in prospects generated by other parties. 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 also may 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. In order to provide the Company downstream opportunities, management entered the then emerging alternative fuels vehicle conversion business through the creation of its own alternative fuels division, ExproFuels, in late 1992. The ExproFuels division conducted marketing activities and established varying levels of operations in Texas, Arizona, Louisiana, Asia and Latin America, but profitable operating levels were not attained. In late 1996, management redirected its focus and resources to its core oil and gas exploration and production business. Accordingly, the ExproFuels division was incorporated and spun-off via a stock dividend, with the Company retaining approximately a 40% stock interest. At fiscal year end 1998, ExproFuels, Inc. had discontinued all operations, had liquidated its tangible assets and was attempting to settle its remaining outstanding obligations. The significant inflows of new equity and debt capital realized by The Exploration Company during 1997 and continuing into 1998 confirmed Management's expectations of significant benefits by focusing on its core business of oil and gas exploration and production. Fiscal year 1997 operating results included a 115% increase in both oil and gas revenues and proved oil and gas reserves over 1996 levels. During fiscal 1998, the Company continued this strong growth trend with a 195% increase in production volumes and gross operating revenues, while further increasing its proved oil and gas reserves by 183%. While the dramatic growth rates in gross revenues and oil and gas reserves reflect significant exploration success, net loss from operations increased over prior years levels due to the industry wide impact of the progressive weakening of oil and gas prices during the year. In addition to negatively impacting the Company's ability to generate working capital from operations, the lingering impact of low energy prices restricts the overall industry's ability to attract outside sources of working capital. During fiscal 1998, the economics of the Company's Texas based natural gas exploration projects proved sufficiently attractive to obtain additional investment from within the industry, while its Williston Basin oil exploration projects remain on hold pending a sufficient recovery in crude oil prices. Page 4 PRINCIPAL AREAS OF ACTIVITY Oil and Gas Operations Throughout the year, the Company has been actively evaluating its mineral interests in major oil and gas producing basins in South Texas, North Dakota, South Dakota and Montana. These activities included the drilling of 6 new gas wells in South Texas and 3 oil prospects in North Dakota during 1998. The expanded Maverick Basin drilling activity reflects the Company's continued ability to generate sufficient working capital, from both internal and external sources, for expansion of its Texas based natural gas exploration and production activities, not withstanding a general weakening in natural gas prices for the last half of 1998. The reduction in Williston Basin activity reflects the impact of the significant reduction in capital available to the Company during 1998 versus 1997 from internal or external sources for oil exploration activities due to the collapse of oil prices beginning in December 1997 and continually worsening through August 1998. Maverick Basin Glen Rose/Rodessa Formation: The Company has owned at least a 50 percent leasehold interest in approximately 50,000 contiguous acres in Maverick County, Texas since 1989. The property is on the Chittim Anticline, a large regional structure, under which hydrocarbons have been found in as many as seven separate horizons. 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 of the field was halted because of the inability of operators to accurately predict the location of these porosity-bearing reefs. The Company applied a different processing method to the seismic available in the area and discovered what appeared to be a method of determining the location of these porosity intervals. Further investigation revealed that every well drilled in the vicinity of existing seismic lines with a good porosity zone had a certain signature pattern on the seismic processing, while every well which lacked the porosity zone did not have this pattern. Through 1993, the Company participated in the drilling of five wells to test its theories to locate the patch reefs using 2-D seismic. In all cases the Company was successful in predicting the presence of, or absence of, porosity-bearing patch reefs using the new seismic interpretation methods. Although only one of the wells, the Paloma #1-84, was a successful gas producer, as the others contained only water, the Company used the information gained from each exploratory well to refine its interpretation and model of the patch reefs' depositional environment. Between 1993 and in 1997, the Company ran two contiguous 3-D seismic surveys over a total of 43 square miles (approximately 26,000 acres) of the Company's lease position. Seismic analysis of the combined surveys identified numerous patch reefs on the 26,000 acres that represented only one-half of the potentially productive 50,000 acres. Using this 3-D seismic information, the Company has drilled Glen Rose reef wells with steadily improving success rates. Through ongoing modifications of earlier interpretation of the initial seismic data based on successive drilling results, the Company's success rate climbed to 75% for fiscal year 1997. With the drilling of the Paloma #2-108, the Paloma #1-106, the Paloma #2-106 and the Paloma #2-83. Three of the four wells were Glen Rose reef producers. While still 100% successful in locating Glen Rose patch reefs, Management continued to review technical data gained with the drilling of each well to improve its ability to distinguish between water-filled reefs and gas-filled reefs. Although the Company's success ratio had improved from its early start of 20% successful wells from its first five Glen Rose wells through 1993 to a 75% successful ratio on the four wells drilled in 1997, Management continued to improve the ratio. In August, 1997 the Company extended its seismic database by completing a second 3-D seismic study on 13,000 acres of its Paloma lease. Additionally, it commissioned re-processing its existing Paloma lease seismic database, utilizing the downhole information obtained from its previous drilling successes. The resulting seismic data and improved interpretations have been extremely favorable in identifying future drilling prospects and has proved to be the key in further improving the Company's drilling success ratio. Page 5 The success of the Paloma #2-83 in October 1997 confirmed the evolution of the Company's model for interpretation of its 3-D seismic database. The well was the first of 6 new gas well discoveries in succession on the Paloma Lease. This new and ongoing success ratio of 100% has effectively extended the Prickly Pear Field by several miles north and east of its previously recognized boundaries. Since October 1997, the Company successfully drilled and commenced marketing gas production from the Paloma #2-83, the Paloma #1-66 in February 1998, the Paloma #1-90 in June 1998, the Paloma #2-66 in August 1998, the Paloma #4-51 in September 1998 and the Paloma #1-65 in November 1998. The 6 latest wells have encountered between 40 and 72 feet of productive Glen Rose reefs, with gross daily production volumes ranging from 1,000,000 to 4,000,000 cubic feet of gas per day per well. In November 1998, drilling was in process on the Paloma #1-64, the Company's 7th successful Glen Rose well in a row on the Paloma lease. Early indications suggest gross daily production levels consistent with those of the previous six Glen Rose wells. During fiscal 1998, the Company built two additions totaling 10 miles of new six-inch gas pipeline across a portion of the Paloma lease. The new gathering system provides significant new capacity for new producing wells and allows for higher production volumes from existing wells previously restricted by area pipeline capacity limitations. The new pipeline also provides marketing flexibility which positions the Company to profit from enhanced pricing opportunities on future gas deliveries. For the year ended August 31, 1998, natural gas production from Maverick Basin properties produced an average of approximately 1,955 net Mcfd (million cubic feet of natural gas per day) from 8 net wells. However, by October 1998, the Company's daily net production was averaging 5,205 net Mcfd, with additional increases expected in November and December 1998 reflecting additional first quarter completions of the two newest gas wells, the Paloma #1-65 and the Paloma #1-64. Overall Company operated gross gas production has increased to 14,000,000 cubic feet of gas per day from 17 gross wells, excluding production from the November 1998 completions of the Paloma #1-65 and #1-64, its latest gas discoveries. This compares to gross gas production of 2,400,000 cubic feet of gas per day at the end of fiscal year 1997 from 13 gross wells. Ongoing production increases are a direct result of the application of $3,500,000 in production payment based financing obtained from Range Energy Finance Corporation, through August 31, 1998. The funding included provisions for drilling the latest Paloma lease wells, as well as completion of the last 3.5 mile section of new six-inch gas pipeline. The newly attained production levels will allow the Company to internally generate sufficient working capital for its current fiscal year 1999 development plans. These latest drilling successes dramatically reaffirm the Company's longstanding belief that it has significant development possibilities on its 50,000 acres Maverick County lease block since it has successfully demonstrated that its updated 3-D seismic model can accurately predict the presence of porosity and gas-bearing zones within the Glen Rose formation. Based upon the extensive seismic data gathered to date, the Company has accumulated 43 square miles of 3-D seismic data over 26,000 of its 50,000 acres Maverick Basin lease block at year end, with clear evidence of 10 to 20 additional porosity-bearing Glen Rose patch reefs scattered across its extensive acreage position. Based on current drilling plans, these patch reefs represent a one to two year drilling inventory of new gas well prospects. During the first quarter of fiscal 1999, the Company finalized agreements with two industry participants, acquiring an interest in a total of 21,600 additional acres of mineral leases contiguous to the Paloma lease. The Company's recent drilling success has effectively increased industry interest in the Maverick Basin play surrounding its acreage block. Management intends to position the Company to maximize the benefit of its expanded technical knowledge by participating in new opportunities to extend the known limits of its primary producing area. Consistent with this strategy, the Company acquired a 63% working interest in 8,800 acres immediately west of its existing block from one party, and may participate with a 25% working interest in locations drilled on 12,800 acres immediately east of the Paloma block owned by the second party. The agreements provide the Company with rights to approximately 43 square miles of additional 3-D seismic data. The Company has extended its 3-D seismic interpretive expertise over the expanded area, effectively doubling the size of its existing seismic database in exchange for its expertise in selecting potential productive Glen Rose reef locations. The new agreements extend the Company's ability to expand its participation in the gas play surrounding its existing production and to further capitalize on its growing expertise and reputation, as confirmed by offers from industry participants in the area. As required under the lease terms of the new 8,800 acre block, the Company completed the drilling phase of its first gas prospect, the Alkek #1-232, during October 1998, and is currently evaluating its completion alternatives. Page 6 Also during the first quarter of fiscal 1999, the Company finalized agreements with a joint venture partner, allowing the venture participants to earn up to a 50% interest in the Company's existing 17,000 acre Kincaid lease in exchange for their funding and commencing a 27 square mile 3-D seismic program on parameters established by TXCO over the entire tract. While the terms reduce the Company's remaining interest in the lease to 50% in shallow zones, it allows the Company to keep its deeper rights, including the Jurassic interval, intact. Preliminary location work is progressing on the seismic program that, upon completion, should dramatically enhance the Company's ability to identify additional Glen Rose gas-bearing patch reef drilling prospects. Additionally, the seismic may develop Georgetown and Pearsall interval prospects while allowing the Company to further seismically define its developing deep Jurassic prospect. The Company expects to find numerous gas-bearing patch reefs scattered across the Kincaid lease area, further expanding its multi-year drilling inventory in the Maverick Basin. In addition to locating gas-bearing patch reefs, investment in the 3-D seismic data acquisition has proved to be valuable to the Company in locating faults and fractures associated with production from the other potentially productive zones under its Maverick County leases. From its review of the data from other strata, the Company has identified numerous drill sites targeting various productive horizons. The Austin Chalk, Georgetown and Pearsall intervals all have produced on the lease from faults and fractures which have been further defined using the comprehensive seismic data. Jurassic Formations: The Company's geophysicists and geologists have established that the 43 square miles of 3-D seismic shot to date across its 50,000 acre block in Maverick County indicates a significant potential for development of the deep Jurassic interval. Three wells have attempted to discover Jurassic reserves in the area. They were drilled by Shell, Exxon and Conoco 20 to 30 years ago. Upon acquiring magnetic surveys that were flown across the region approximately 11 years ago, the Company discovered that the Shell and Exxon wells were not drilled within what is now known to be the limits of the Maverick Basin. The Company's 3-D seismic shows that although the Conoco well was drilled within the basin, it was not drilled deep enough to reach the Jurassic interval. The Jurassic zones are prolific producers in all known Jurassic basins along the Gulf Coast except for the Maverick Basin which has not had a well drilled of sufficient depth to test the Jurassic interval. The Company has continued development on its 3-D seismic model of the interval and expects further enhancements to result from a new 17,000 acres 3-D seismic acquisition program currently underway. While significant interest continues from negotiations with prospective industry partners during 1998, the Management continues in its search for industry partners who will join in the drilling of an exploratory well to test the Jurassic formations on terms consistent with the best interest of the Company's shareholders. 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 acquired some of the leases with its common stock, but the majority interest was acquired by selling a Swiss institutional investor a 50% net profits interest in the entire 320,000 acres for cash which was used to purchase the leases in February 1997. Subsequent to acquiring the leases, the Company participated in the drilling of 11 gross wells through August, 1997 in attempts to develop oil and gas reserves in the Red River and Lodgepole formations. Fiscal year 1998 drilling was limited to 3 Red River oil well prospects, two being completed with marginal success, while one was plugged and abandoned. For the year ended August 31, 1998, production from Williston basin properties produced an average of approximately 193 net barrels of crude oil per day from 4.32 net wells. Overall exploration efforts in the Williston Basin have slowed significantly, failing to reach original expectations to date, primarily due to the over 40% drop in crude oil prices since September 1997 and the related industry-wide curtailment of investment in exploration activities in that geographic area. The continuing weakness in crude oil prices have rendered the production of marginal levels of oil with high associated water production, as is typical of many wells in the Basin, uneconomical. Red River Formation: During 1997, The Company entered into several joint venture agreements with industry partners to help develop its extensive acreage positions. The Company entered into Joint Operating Agreements (JOA) with a select group of highly Page 7 experienced and well financed industry partners, including Continental Resources, Inc. ("CRI") and Union Pacific Resources Company ("UPRC"), by combining a total of 25,600 acres covering portions of North Dakota and South Dakota. The Company entered into a separate JOA with CRI covering 8,700 acres in Harding County, South Dakota. The Company also entered into another JOA with UPRC covering additional leases on the North Dakota and South Dakota border totaling 44,000 acres. The Company also entered a JOA with Eagle Oil & Gas Company covering 54,000 acres in Slope and Golden Valley Counties of North Dakota. The Company's initial strategy was intended to benefit from these joint venture partners' historical expertise in drilling within the Williston Basin. This would reduce the Company's exploration risk by participating in drilling the combined total of the respective JOA's acreage block and substantially increase its statistical likelihood of finding economically produceable oil reserves. The strategy also included leveraging its resources through the acquisitions of new 3-D seismic data in conjunction with its JOA partners as well as by utilizing existing 2-D and 3-D seismic data contributed by its JOA partners, or purchased outright, to assist in the selection of drilling locations. From the inception of drilling in the Red River interval in January 1997, the Company participated in the drilling of 11 wells through fiscal year 1997. During fiscal year 1998, only 3 additional Red River wells were drilled by the end of the first quarter, at which time further Williston Basin drilling was curtailed due to the collapse of crude oil prices and its negative impact on additional sources of working capital available to the Company. Initially, the Company's geologic model of the area indicated that the Red River "B" would produce horizontally over the entire leasehold, and the "C" and "D" should produce vertically on structures. After analyzing the drilling results of the Company and its partners along with the available 2-D and 3-D seismic, Management has modified its Red River geologic model. The Company now believes that future drilling attempts in all three intervals, "B", "C", and "D", should be maintained on structures. It is now understood that the oil is accumulating on the high points and water in the lower portions. Wells that are drilled irrespective of structure have a much greater incidence of high water production. When justified by improved crude oil prices, the Company plans to continue drilling on the seismically defined structures to encounter "C" and "D" production while also drilling shorter horizontal laterals in accordance with seismic interpretation of local structures in the "B" intervals. The Company accumulated over 1,100 miles of 2-D seismic and 32 square miles of 3-D seismic in its Williston Basin library through the end of fiscal 1997. During the second quarter of 1998, the Company completed the acquisition of an additional 20 square mile of 3-D seismic pursuant to a JOA, over certain of the JOA's joint acreage positions targeted for continued exploration by mutual agreement of the partners. The seismic acquisition commenced prior to the collapse of crude oil prices during the second quarter of 1998. After processing and interpreting the new 3-D seismic data, Company geophysicists and geologists have identified several drilling locations on its multiple lease blocks prospective for oil production. Plans for further 3-D seismic acquisitions were postponed pending adequate recovery of oil prices and the availability of sufficient levels of funding internally or from outside sources. The Company plans to selectively maintain and develop those leases which contain known drilling locations defined by 3-D seismic data. When oil exploration economics improve sufficiently to justify the search for new oil reserves in the area, the Company should be in the position to drill seismically defined prospects.. Lodgepole Formation: The Company did not participate in drilling any new Lodgepole wells during fiscal 1998. Additional wells have been permitted farther from the original discoveries and closer to the Company's larger lease position, but the wells drilled outside the Dickinson area have encountered poor results. Although the Company's 2-D seismic indicates potentially productive mounds may be present in many areas where the Company holds oil and gas leases, the Company believes that the risks in drilling these wells exceed acceptable levels. While interpretative work continues, existing geophysical models do not yet consistently predict where productive reefs are located. Management maintained its strategy of reducing its risk in searching for productive reefs by farming-out the initial wells on prospects to other operators and keeping smaller interests in any resultant exploratory well. The Company would then be able to increase its interest in the subsequent wells in a discovered field. Page 8 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 1998, three purchasers of the Company's oil and gas production accounted for 34%, 28% and 21%, 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. These companies also possess substantially larger technical staffs, which puts the Company at a significant competitive disadvantage compared to others in the industry. EMPLOYEES As of August 31, 1998, 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 is 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. Page 9 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. 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 is 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 carryforward should be sufficient to shelter a substantial amount of production. See Notes to the audited financial statements. Page 10 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, 1998. The average sales prices as of such dates used for purposes of said estimates were $10.98 per barrel of crude oil and $1.82 per mcf of natural gas, representing a decrease of 38% and 19%, 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. 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 of the remaining properties. 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 The Company has experienced recurring losses. For the years ended August 31, 1998, 1997 and 1996, the Company recorded net losses of $8.4 million, $3.4 million and $1.9 million, respectively. 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. Page 11 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. Proved Reserves, Future Net Revenue and Present Value of Estimated Future Net Revenues The following unaudited information as of August 31, 1998, 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, 1998, 1997 and 1996 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, 1998, are as follows: 10% Present Value of Years Ending Estimated Future August 31 Net Revenues 1999 2,406,000 2000 2,866,000 2001 1,614,000 2002 886,000 2003 486,000 Thereafter 566,000 TOTAL $ 8,824,000 ========== 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. Page 12 Production (2) 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.
Years Ended August 31 1998 1997 1996 ---- ----- ---- Oil: Production in Barrels 79,138 23,086 2,862 Average sales price per Barrel $15.78 $18.64 $18.03 Gas: Production in MCF 713,752 206,059 215,274 Average Sales Price per MCF $2.29 $2.65 $ $1.79 Average cost of production per equivalent Mcf (1) $.74 $.72 $.45
(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 andproduction taxes. 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, 1998:
Productive Wells ------------------------------------------------------------ Developed Acreage Oil Gas Total ----------------- ------------ ---------------- ------------------ Gross Net Gross Net Gross Net Gross Net 8,920 3,894 16 5.26 17 8.05 33 13.31
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, 1998, 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 FY1999 United States Gross Acres Net Acres Delay Rentals - ------------- -------- -------- -------- Texas ...... 56,401 43,668 $142,321 North Dakota 443,490 293,353 138,086 South Dakota 66,333 57,902 33,940 Montana .... 33,245 22,449 1,440 -------- -------- -------- Totals ... 599,469 417,554 $315,787 ======== ======== ======== A Texas lease containing approximately 33,000 acres also has a requirement to drill a well every 90 days to keep the lease in effect since the primary term of the lease has expired. The Company is presently drilling under the terms of the lease and expects to keep the lease in force by continuous development during the year. Page 13 Drilling Activity During fiscal 1998, the Company's drilling activity decreased to 7 wells from the 1997 level of 15 wells. The Company participated in the drilling of four gas wells in the Maverick Basin and three oil wells in the Williston Basin, one of which is temporarily abandoned. 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. Maverick Basin The Company completed a new 3-D seismic program covering nearly 13,000 additional acres of the Paloma Ranch during the fourth quarter of fiscal 1997. Interpretation of the processed data indicated numerous patch reefs in the Glen Rose interval as well as the anticipated fracturing and faulting in other intervals. Current year drilling was planned after integrating this new seismic data and modifying the Company's geologic model of the area. Fiscal year 1998 drilling results have achieved a 100% success ratio, as the Company has drilled and completed six Glen Rose reef wells in a row on its Paloma lease in Maverick County, Texas, with the last two wells being completed during the first quarter of fiscal 1999. The Paloma #2-83 that was drilled in October 1997 had 78 feet of gas-bearing Glen Rose reef. It was completed with initial production of 2,000 mcfd (thousands of cubic feet of gas per day) that was later increased to 4,000 mcfd. The Paloma #1-66 followed in February 1998 with 72 feet of gas bearing reef. Its initial production of 2,000 mcfd, was later increased to 4,000 mcfd. Next drilled was the Paloma #1-90 which had 60 feet of gas-bearing reef present and produces at 1,500 mcfd from the Glen Rose. The last well commenced in fiscal 1998 was the Paloma #2-66 which encountered 70 feet of gas-bearing Glen Rose reef and produces at 2,000 mcfd. In September 1998 drilling continued with the Paloma #4-51 which had 38 feet of gas-bearing Glen Rose reef present and produces at 1,000 mcfd. The sixth successive Paloma lease well, the Paloma #1-65, was drilled in October, 1998 and had 70 feet of Glen Rose reef present. Completion of the well is currently underway, with an expected production rate of 4,000 mcfd. The Company is the general partner in a limited partnership that completed construction of 6.5 miles of six-inch pipeline to gather gas on the Maverick Basin properties during December, 1997. Due to previous pipeline constraints, the Company and its partners' production had been limited to only 2,400 mcfd. After completing the new pipeline, daily production from the lease increased by over 50 percent to 3,800 mcfd. With 1998's expansive drilling success, additional pipeline capacity was needed to optimize production from Paloma lease. By August, 1998 the Company completed a 3.5 mile addition to its growing gathering system, bringing total pipeline additions to 10 miles for the year. By year end, daily gas deliveries reached over 12,000 mcfd, with further increases to over 14,000 mcfd by November, 1998. The Company expects these delivery rates to increase further with the drilling of at least 4 additional gas well prospects scheduled through the remaining nine months of fiscal year 1999. Williston Basin During the first quarter of 1998, the Company participated in the drilling of 3 Red River tests located in various counties of North Dakota. The Marty #1-17 was drilled horizontally in September 1997 in Bowman County. It was completed as an oil well in the Red River "B" zone and placed on production at 100 bopd and 150 bwpd. Also in September, the Company, in participation with Continental Resources as operator, drilled the Table Mountain #1-7 in Harding County. Completed horizontally in the "B" zone, the well was placed on production at 65 bopd and 350 bwpd. In November 1997, the Company horizontally drilled the Dottie #1-23 in Golden Valley County. The well encountered mechanical problems during sidetrack operations. While attempting to drill a second lateral, the horizontal drilling motor and directional tools were lost in the hole. Completion efforts failed to produce any show of oil. Subsequently, the Company decided to plug-back the well and further evaluate the Ratcliff interval prior to abandonment. All drilling costs to date were charged to dry hole cost. Page 14 Also during the quarter the Company completed a new 3-D seismic program covering 20 square miles in an area southwest of the Marty #1-17 in Bowman County, North Dakota. Under the terms of a joint operating agreement, by shooting seismic across the area referred to as the Grand River Seismic Program, the Company earned a 50% interest in Continental Resources' leases within the seismic program. The Company commenced processing the new seismic data and anticipated additional exploration activity to resume once the Company geophysicists and geologists completed their review, as planned for some time in the second or third quarter of fiscal 1998. December 1997 marked the beginning of the currently ongoing industry wide collapse of oil and gas prices. While the depressed oil and gas price environment in fiscal years 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 $12.98 by February 1998. Prices progressively worsened through the balance of the year, ending at $10.35 at August 31, 1998. These lower prices, combined with high unit production costs at current production levels, have resulted in failed economics on many of the Company's Williston Basin producing properties. The Company curtailed its capital spending program in the area during midyear of fiscal 1998, implementing a cost reduction plan which minimized ongoing expenditures other than those needed to maintain production levels to maximize cash flow above break- even on a cash basis. Curtailed current period expenses included the non-payment of lease renewals totaling over 18,000 acres of Company leases in Montana, North and South Dakota. Leases targeted were those not covered under existing 3-D seismic programs or otherwise not possessing distinguishing features of particular significance. At year end of fiscal 1998, the Company continued its evaluation of all operations in the Williston Basin, with particular emphasis on the changed economics resulting from the ongoing weakness in oil prices. Management identified 3 marginal producing wells for impairment and 1 non-producing well for abandonment. The review also identified oil leases targeted for impairment, totaling over 46,800 net acres in North and South Dakota, with primary expirations prior to December 31, 1999. The Company determined it was reasonable and conservative to charge current period earnings with an impairment for the lease acreage it does not reasonably expect to renew. 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 except for the following disputes between the Company's former subsidiary, ExproFuels, Inc. and CNG International, American Engineering Inc. (AEI) and American Technical Institute (ATI) have resulted in the filing of two lawsuits in July, 1997, one by ExproFuels in federal court in San Antonio, Texas, and the other by ATI and AEI in state court in Memphis, Tennessee. Both suits were settled during the year on terms favorable to the Company. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matter was submitted to a vote of security holders of the Company during the fourth quarter of the fiscal year ended August 31, 1998. Page 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 1998 .................................... $ 1.94 $ 1.16 May 1998 ....................................... 2.81 1.69 February 1998 .................................. 3.50 1.63 November 1997 .................................. 8.44 2.50 August 1997 .................................... $ 8.44$ $ 5.44 May 1997 ....................................... 6.44 5.44 February 1997 .................................. 6.81 2.94 November 1996 .................................. 3.38 2.25 As of November 10, 1998, there were approximately 1,711 holders of record of the Company's Common Stock. The transfer agent for the Company is Boston 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 -------------------------------------------------------------------- 1998 1997 1996 1995 1994 ---- ---- ---- ------ ------- Operating Revenues $3,048,277 $1,083,511 $ 521,593 $ 331,253 $ 236,440 Loss from continuing operations (8,417,218) (3,398,866) (1,880,389) (2,153,365) (1,550,953) Loss per common share from continuing operations (0.55) (0.27) (0.31) (0.44) (0.36) Total Assets(1) 16,264,632 21,652,726 8,433,434 4,111,980 2,262,283 Long-term obligations(1) 4,823,927 4,995,000 2,462,197 2,429,697 630,111 Shareholders' equity 10,595,141 14,770,770 5,670,688 1,377,747 1,613,121 Weighted average shares outstanding (1) 15,328,292 12,576,255 6,140,176 4,863,961 4,267,363
(1) Amounts reflect adjustments in 1995 and 1994 for the reclassification of ExproFuels as an equity investment due to its spin-off in 1996. Page 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 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 options 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. In July 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) allowing for the borrowing of up to $4,000,000. 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 provide 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 will become evident during the first quarter of fiscal year 1999. As the latest new wells are placed on production, Management is confident of continuing significant improvements in the Company's ability to meet its ongoing operating cash requirements. Page 17 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. 1996 - ---- In fiscal year 1996, the Company raised funds under an agreement with Comstar BioCapital, Inc., a foreign entity, through an offering of the Company's common stock to foreign investors. The Company raised $2,100,000 in exchange for 1,175,000 shares of the Company's common stock pursuant to Regulation S of the Securities Act of 1933, as amended. The Company also realized $602,000 from the payment of an outstanding note receivable, received $55,000 due to the expiration of a drilling option and obtained $132,500 as proceeds from long-term borrowings during the year. Proceeds were utilized to fund the Company's cash loss from operations of $1,375,000, including the payment of interest of $378,000, payments on current portion of debt and capital leases of $40,100 and for capital expenditures of $182,000. The capital expenditures included approximately $55,000 to develop oil and gas properties, $80,000 for equipment purchases for use in U.S. operations of ExproFuels, and $41,000 for purchases of other assets. Additional capital investments and advances totaling $442,000 were made by ExproFuels in CNG International, LLC. At August 31, 1996, the Company had current assets of $1,039,425 and current liabilities of $1,073,049. However, its current assets included $967,838 in cash, and its current liabilities included a $500,000 convertible note payable not due until May, 1997. This compared to a cash position of only $78,655 at August 31, 1995. Page 18 1998 Capital Requirements - ------------------------- The major components of the Company's plans, and the requirements for additional capital at August 31, 1998, include the following: Maverick Basin Activity: During fiscal 1999, the Company plans to drill a minimum of 7 additional wells, in keeping with lease renewal minimum requirements, with a total drilling budget of $1,850,000. Drilling on the first four of the planned wells commenced during the first quarter of fiscal 1999. Initial results indicated the three wells drilled on the Paloma lease, (the Paloma #4-51, #1-65 and the #1-64) will be completed as gas wells producing from separate patch reefs in the Glen Rose formation. The fourth well, the Alkek #1-232 was drilled on a newly acquired 8,800 acre lease adjoining the Paloma lease. The lower Glen Rose reef contained water, therefore, Company engineers and geologists are currently evaluating its completion alternatives. Based on interpretation of the Company's extensive 3-D seismic database, over 20 potentially drillable patch reef prospects have been identified on the Paloma Ranch lease, targeting the Glen Rose formation. The Company's share of the cost of each Glen Rose well is approximately $260,000 for a completed well and $160,000 for a dry hole. Company engineers are planning to test other formations with a massive fracturing treatment with the hope of unlocking additional reserves not previously productive due to the formations' low permeability. The fracturing treatment 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. Delay rentals required to maintain the Company's interest in its remaining undeveloped South Texas leasehold acreage for fiscal 1999 are $142,000. Williston Basin Activity: Due to the continuing weakness in crude oil prices, the Company has delayed further expenditures in the Williston Basin until favorable economics justify the risk of further drilling. Company management intends to continue its review of potential locations for new drilling operations using its 3-D seismic data and intends to make attractive prospects available to other industry operators. While the Company intends to proceed cautiously with its drilling activities, the extensive acreage position it holds in the Williston Basin requires a high level of drilling activity that comprises a formidable challenge to the Company given its limited access to exploration funds. Delay rentals required to maintain the Company's interest in its remaining undeveloped Williston Basin leasehold acreage for fiscal 1999 are $173,000, plus scheduled area lease options of $18,000. Due to the Company's limited financial resources, Management continues to seek, review, and negotiate for acceptable opportunities to participate via farmouts to industry members who would drill Red River and Lodgepole wells on its acreage, thereby limiting the Company's exposure. Summary of Capital Resources and Liquidity Subsequent to the end of fiscal 1998, the Company successfully drilled and completed three new Glen Rose gas wells during the first quarter of fiscal year 1999. In addition, the Company announced in August 1998 that it had commenced operation of its new 3.5 mile extension to its Paloma lease gas gathering system. First Quarter 1999 operating results will reflect initial production revenues from the Paloma E #2-66, the Paloma E #4-51 and by late November, the Paloma E # 1-65. Independent well testing indicates initial production rates should be between 1 million cubic feet of gas per day (cfd) and 4 million cfd per well upon connection to the Company's gathering system. The Company's net revenues from the three wells combined should increase by $1,000,000 to $2,000,000 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 not deteriorate further, causing the Company to re-evaluate its expected sources of working capital and operating plans. Management is endeavoring to identify additional sources that could provide new funds required to increase its current drilling activity during fiscal year 1999. Increases in Texas gas production from the 4 new gas wells coming on line during the last two quarters of 1998 and 3 additional wells coming on line during the first quarter of 1999 should continue to offset the effect of lower natural gas prices. The new wells should provide additional increases of 25% to 50% in the Company's monthly oil and gas sales revenues by the second quarter of 1999 compared to the respective prior quarters in 1998. The newly expanded gas pipeline system has allowed the Company to increase revenues by removing a historical restriction on its Maverick basin production caused by a lack of available pipeline capacity or alternative sales outlets. Management continues to pursue additional sources of debt and equity financing, and remains hopeful 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. Page 19 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 is currently conducting a review of these systems to verify their compliance with Year 2000 date codes. In addition, the Company is conducting 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 is also developing an overall plan outlining the tasks, resources and target dates necessary to ensure the ongoing operation of the Company's systems through the turn of the century and beyond. The Company plans to complete remediation of the systems that it finds are not in compliance and to begin testing all of its systems in fiscal 1999. While the Company's inventory, review and assessment is still in process, the Company expects that the required modifications will not have a material effect on the Company's operating results. RESULTS OF OPERATIONS 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 dry holes during the year compared to only one dry-hole in the previous year. The Abrahamson #41-33H was drilled late in the fourth quarter of the prior year. The 40% fall of oil prices at mid-year rendered the completion of the well uneconomical. The Dottie #1-23 was drilled in November 1997 and failed to encounter economic quantities of oil. 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 that required impairment. Additionally, non-producing leaseholds were reviewed for potential impairment. Certain leases, with expiration dates through December 1999, were identified that 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 $890,714. 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. Page 20 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. 1996 Compared to 1995 - --------------------- Revenues from oil and gas sales increased by 50% in 1996 to $455,000 from $304,000 in 1995, primarily as a result of higher gas sales due to the successful completion of the Paloma "B" #2-112 during 1996 and the first full year of production from the Paloma #1-107 and the Paloma "A"#83-1H. Additionally, gas prices increased an average of 10% during 1996 over 1995 levels. Lease operating expenses for 1996 increased to $75,000 from $41,000 in 1995 reflecting a higher number of operated properties and overall higher costs in operating certain producing wells. Exploration expenses increased by $526,000 due to the drilling of two dry holes during the year, the Paloma "C"#1-108 and the Paloma "D"#1-73. Additionally, during 1996, the Company expensed the costs incurred in 1995 in drilling the Paloma #1-89, which remained shut in at the end of 1995 pending its final evaluation. Depletion per equivalent barrel of production increased to $4.12 in 1996 from $3.17 in 1995, resulting in an overall increase of $58,000 depletion expense for the year. Other costs included an increase in interest expense to $378,000 from $285,000 in 1995 attributable to interest accruing for a full year in 1996 versus a partial year in 1995 on the Company's primary convertible note payable which had an outstanding balance of $1,764,000 at August 31, 1996. Page 21 In total, revenues increased $463,000 or 42%, from $1,065,000 in 1995 to $1,568,000 in 1996. Costs of sales, including general and administrative, depreciation, depletion and amortization, increased only $207,000, thereby resulting in a net decrease to prior year losses from operations of $255,000. Other income and expense, in total, decreased by $17,000, with an increase in interest expense of $93,000 being partially offset by an increase in interest income of $58,000 and an increase in sublease income of $52,000. As a result, the Company's net loss decreased to ($1,880,000) in 1996 from ($2,153,000) in 1995. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK None - See additional comments pertaining to certain business risk on page 10. 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 Page 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, 1998:
Name Position Age ------------ ------------------- --- Stephen M. Gose, Jr. Chairman of the Board of Directors 68 Member Audit and Compensation Committees Michael Pint Director, Chairman Audit and Compensation Committees 55 Robert L. Foree, Jr. Director, Member Audit and Compensation Committees 69 Thomas H. Gose Director and Assistant Secretary 43 James E. Sigmon President and Director 50 Roberto R. Thomae Chief Financial Officer 47 Secretary/Treasurer, Vice President-Finance Richard A. Sartor Controller 46
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 of the Board of Directors since June, 1997 and served as their Chairman through April, 1998. He has been active for more than 35 years in exploration and development of oil and gas properties, in real estate development, and in ranching through the operations of Cibolo Properties, 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 is the sole Director, CEO and President of Cibolo Properties, Inc. and Retamco Operating, Inc. He formerly served as President of Spectrum Resources, Inc. (a large shareholder of the Company) since 1987. He has also 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 is the President and a 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. and is also a Director of ExproFuels, Inc. Prior to joining the Company, Mr. Sigmon served in the management of a private oil and gas exploration company active in drilling wells in South Texas. Mr. Thomae has served as Chief Financial Officer and Vice President-Finance of the Company since September, 1996 and as Secretary/Treasurer since March 1997. He also served as Vice-President-Finance of ExproFuels, Inc. from August 1996 to September 1998 and as its Secretary-Treasurer from March 1997 to September 1998. 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. Mr. 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. Page 23 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 1998 $ 132,000 $ 0 (1) $41,623 $ 0 $ 0 President & CEO 1997 120,000 0 (1) 20,827 0 0 1996 72,000 0 (1) 12,498 0 7,500
(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 --------- ------- -------------- --------- -------- -------- James E. Sigmon (1) 600,000 100% $ 2.125 2008 (2) $ 291,947
(1)Mr. Sigmon's ten year non-qualified incentive stock options to purchase shares at 110% of current market price at date of grant, 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. (2)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 4.0%; dividend yield of 0%; volatility factors of the expected market price of the Company's common stock of .69; and a weighted-average expected life of the option of five years. Page 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, 1998 August 31, 1998 --------- --------- -------- ----------------------- ------------------- James E. Sigmon (2) - - 750,000 (1) $ 0 Michael Pint (3) - - 75,000 (1) $ 0 Robert L. Foree, Jr (3) - - 75,000 (1) $ 0 Roberto R. Thomae (4) - - 50,000 (1) $ 0
(1) Value of unexercised options calculated as the difference in the stock price at August 31,1998 and the option price. None of the unexercised options were "in the money" at August 31, 1998; accordingly the options are valued at $0 at year end. (2) 150,000 of Mr. Sigmon's unexercised options were exercisable as of August 31, 1998, and the remaining 600,000 are exercisable as described in footnote (1) of the previous table. (3) 50,000 of Mr. Pint and Mr. Foree's options, respectively, were exercisable as of August 31, 1998. (4) 25,000 of Mr. Thomae's options were exercisable at August 31, 1998. 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. Page 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 15,613,516 shares outstanding as of November 10, 1998. 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 as of November 10, 1998. Percent Owned Name and Address of Number of Shares Primary Shares Beneficial Owner Beneficially Owned Outstanding - ---------------- ------------------ ----------- Thomas H. Gose .......................... 1,107,101 7.09% 500 North Loop 1604 East Suite 250 San Antonio, TX 78232 Stephen M. Gose, Jr ..................... 1,096,600 7.02% HCR Box 1010 Hwy 212 Roberts, Montana 59070 Trianon Opus One, Inc. .................. 1,400,000 8.97% Fohrenstrasse 25 CH-8703 Erlenbach Switzerland Finanzverwaltung des Kantons St. Gallen .. 800,000 5.12% Davidstrasse 35 9001 St. Gallen 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 10, 1998 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) ------------------------------ ------------------ ----- Thomas H. Gose ................ (3) 1,107,101 7.09% Stephen M. Gose, Jr ........... (4) 1,096,600 7.02% James E. Sigmon ............... (2) 800,000 4.89% Michael Pint .................. (5) 250,000 1.60% Robert L. Foree, Jr ........... (5) 61,000 .39% All Directors and Executive Officers as a group ................ 3,364,701 20.38% (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 150,000 shares of the Company's Common Stock reserved for issuance through options issued under the Company's 1995 Flexible Incentive Plan plus 600,000 shares reserved for issuance through non-qualified incentive stock options awarded in 1998. (3) The number of shares beneficially owned by Mr. Thomas H. Gose include 20,500 shares owned directly, plus his 50% pro rata interest in 930,070 shares owned by Spectrum Resources, Inc., 1,189,631 owned by Retamco Operating, Inc., 20,000 shares owned by Spectrum Holdings, and 33,500 shares owned by Retamco Properties, Inc. (4) The number of shares beneficially owned by Mr. Stephen M. Gose, Jr. include 10,000 shares owned directly, plus his 50% pro rata interest, shared equally with his spouse, in 930,070 shares owned by Spectrum Resources, Inc., 1,189,631 owned by Retamco Operating, Inc., 20,000 shares owned by Spectrum Holdings, and 33,500 shares owned by Retamco Properties, Inc. (5)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 and 200,000 and 11,000 respectively owned directly Page 26 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 percent 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, resulting 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. During 1997, the Company advanced ExproFuels, its former wholly-owned subsidiary, $561,224 under a formal credit arrangement, and committed to advance an additional $265,000 through December 31, 1997. Interest is at 8% and the entire amount of principal and interest is due December 31, 1998. However, due to the financial condition of ExproFuels, a provision for loan loss of the outstanding balance, accrued interest and commitment in the total amount of $845,487 was recorded at August 31, 1997. In August, 1996, 10% of the outstanding common stock of ExproFuels, Inc., previously a wholly-owned subsidiary, was given as consideration to the Directors of ExproFuels, Inc. for services rendered. During 1996, the Company exchanged 2,637,736 shares of its unregistered common stock for 131,860 gross acres (32,965 net acres) of undeveloped oil and gas properties with several parties brought to it by its investment banker. Page 27 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, 1998 and 1997 Statements of Operations, Years Ended August 31, 1998, 1997 and 1996. Statements of Stockholders' Equity, Years Ended August 31, 1998, 1997 and 1996. Statements of Cash Flows, Years Ended August 31, 1998, 1997 and 1996. Notes to Financial Statements. (2) Financial Statement Schedule for the years ended August 31, 1998, 1997 and 1996: 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. (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 27.1 Financial Data Schedule ** Previously filed (B) Reports on Form 8-K: None Filed Page 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 Registrant November 30, 1998 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 30, 1998 /s/ Thomas H. Gose Thomas H. Gose Director and Assistant Secretary November 30, 1998 /s/ James E. Sigmon James E. Sigmon President and Director (Principal Executive Officer) November 30, 1998 /s/ Michael Pint Michael Pint Director November 30, 1998 /s/ Robert L. Foree, Jr. Robert L. Foree, Jr. Director November 30, 1998 /s/ Roberto R. Thomae Roberto R. Thomae Chief Financial Officer November 30, 1998 Secretary/Treasurer (Principal Accounting Officer)
THE EXPLORATION COMPANY Index to Financial Statements August 31, 1998 and 1997 Audited Financial Statements .................. Page Independent Auditors' Report .................. F-1 Balance Sheets ................................ F-2 Statements of Operations ...................... F-4 Statements of Stockholders' Equity ............ F-5 Statements of Cash Flows ...................... F-6 Notes to Financial Statements ................. F-7 Supporting Schedule Schedule II - Valuation and Qualifying Reserves F-18 F-0 INDEPENDENT AUDITORS' REPORT The Board of Directors and Stockholders The Exploration Company We have audited the balance sheets of The Exploration Company as of August 31, 1998 and 1997, and the related statements of operations, stockholders' equity and cash flows for each of the three years in the period ended August 31, 1998. 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, 1998 and 1997, and the results of its operations and cash flows for each of the three years in the period ended August 31, 1998, 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, 1998. 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, 1998 F-1 THE EXPLORATION COMPANY Balance Sheets August 31, 1998 and 1997
1998 1997 ------------ ------------ Assets Current Assets: Cash and equivalents $ 2,329,236 $ 6,198,069 Accounts receivable: Joint interest owners 293,931 127,602 Oil and gas production 567,735 234,824 Prepaid expenses and other 17,738 49,084 ------------ ----------- Total current assets 3,208,640 6,609,579 Property and Equipment: Oiland gas properties (successful efforts), less accumulated depreciation, depletion and amortization of $2,073,491 and $680,240, and accumulated impairment of $3,894,739 and $119,397 12,502,566 14,311,450 Other property and equipment: Transportation and other equipment, less accumulated depreciation of $132,977 in 1998 and $74,418 in 1997 103,862 120,132 ------------ ------------ Net property and equipment 12,606,428 14,431,582 Other Assets: Deferred financing fees, net of amortization of $2,000 18,000 180,000 Other assets 431,564 431,565 ------------ ------------ 449,564 611,565 ------------ ------------ Total Assets $ 16,264,632 $ 21,652,726 ============ ============
See notes to financial statements. F-2 THE EXPLORATION COMPANY Balance Sheets August 31, 1998 and 1997
1998 1997 ----------- ----------- Liabilities and Stockholders' Equity Current Liabilities: Accounts payable and accrued expenses $ 737,157 $ 1,878,443 Due to joint interest owners 108,407 8,513 Current portion of long-term debt 1,846,383 961,975 ----------- ----------- Total current liabilities 2,691,947 2,848,931 Long-Term Debt, net of current portion 2,977,544 4,033,025 Stockholders' Equity: Common stock, par value $ .01 per share; authorized 200,000,000 shares; issued and outstanding 15,613,516 and 14,759,198 shares at August 31, 1998 and 1997 156,135 147,592 Additional paid-in capital 40,161,100 35,928,054 Accumulated Deficit (21,304,876 (29,722,094) ------------ ------------- Total stockholders' equity 10,595,141 14,770,770 ------------ ------------- Total Liabilities and Stockholders' Equity $ 16,264,632 $ 21,652,726 ============ =============
See notes to financial statements. F-3 THE EXPLORATION COMPANY Statements of Operations Years Ended August 31, 1998, 1997 and 1996
1998 1997 1996 ----------- ----------- ----------- Revenues: Oil and gas sales $ 2,886,676 $ 976,882 $ 455,221 Other operating income 161,601 106,629 66,372 ----------- ----------- ---------- 3,048,277 1,083,511 521,593 Costs and Expenses: Lease operations 700,381 176,019 75,634 Production taxes 178,912 71,954 28,357 Exploration expenses 2,290,649 1,549,095 677,170 Abandoned leases and equipment 1,451,880 153,066 - Impairment of mineral properties 3,775,342 28,400 - Depreciation, depletion and amortization 1,446,726 293,527 170,525 General and administrative 1,278,270 938,638 513,896 ----------- ----------- ----------- Total costs and expenses 11,122,160 3,210,699 1,465,582 ----------- ----------- ----------- (8,073,883) (2,127,188) (943,989) Net Loss from ExproFuels equity ownership - (1,215,259) (680,825) ----------- ----------- ------------ Loss from operations (8,073,883) (3,342,447) (1,624,814) Other Income (Expense): Interest income 98,770 283,462 122,428 Interest expense (260,105) (236,494) (294,003) Loan fee amortization (182,000) (103,387) (84,000) ----------- ----------- ----------- (343,335) (56,419) (255,575) ----------- ------------ ----------- Net Loss $ (8,417,218) $ (3,398,866) $ (1,880,389) Amounts Per Common Share: Basic loss per common share $ (0.55) $ (0.27) $ (0.31) =========== ============ ============ Weighted average number of common shares outstanding 15,328,292 12,576,255 6,140,176 =========== ============ ============
See notes to financial statements. F-4 THE EXPLORATION COMPANY Statements of Stockholders' Equity Years Ended August 31, 1998, 1997 and 1996
Common Stock Additional Paid-in Accumulated Shares Amount Capital Deficit Total ------ ------ ------- ------- ----------- Balance at September 1, 1995 5,527,970 $ 55,280 $ 17,348,088 $ (16,025,621) $ 1,377,747 Issuance of common stock for cash 1,175,000 11,750 2,088,250 - 2,100,000 Issuance of common stock in exchange for oil and gas properties 2,723,680 27,236 4,578,502 - 4,605,738 Issuance of common stock warrants - - 12,500 - 12,500 Spin-off of ExproFuels, Inc. - - (544,908) - (544,908) Net loss for the year - - - (1,880,389) (1,880,389) ------------ ----------- ------------ ------------ ----------- Balance at August 31, 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 =========== ========== ============ ============= =============
See notes to financial statements. F-5 THE EXPLORATION COMPANY Statements of Cash Flows Years Ended August 31, 1998, 1997 and 1996
1998 1997 1996 ------------- ------------- ------------ Operating Activities: Net Loss $ (8,417,218) $ (3,398,866) $ (1,880,389) Adjustments to reconcile net loss to net cash used in operating activities: Depreciation, depletion and amortization 1,446,726 293,527 170,525 Amortization of financing fees 162,000 83,887 86,105 Abandoned leases, equipment and other 1,451,880 153,066 220,805 Impairment of properties 3,775,342 28,400 - ExproFuels operations and loan loss reserve - 1,215,259 (80,284) Changes in operating assets and liabilities: Receivables (499,240) (290,839) 52,911 Prepaid expenses and other 31,346 (49,084) 35,343 Accounts payable and accrued expenses 864,114 1,586,380 19,417 ----------- ------------- ----------- Net cash (used) in operating activities (1,185,050 (378,270) (1,375,567) Investing Activities: Development of oil and gas properties (4,806,505) (12,924,068) (55,484) Purchase of transportation and other equipment (42,288) (115,071) (86,277) Proceeds from note receivable - - 602,528 Investments in and advances to ExproFuels - (826,224) (442,426) Other assets - (331,036) 41,509 ------------ ------------- ----------- Net cash provided (used) in investing activities (4,848,793) (14,196,399) 59,850 Financing Activities: Proceeds from long-term debt 3,646,000 5,008,140 132,500 Payments on long-term debt (1,500,990) (210,640) (40,100) Issuance of common stock, net of expenses 20,000 15,007,400 2,112,500 ------------ ------------- ----------- Net cash provided by financing activities 2,165,010 19,804,900 2,204,900 ------------ ------------- ----------- Increase (decrease) in Cash and Equivalents (3,868,833) 5,230,231 889,183 Cash and Equivalents at Beginning of Year 6,198,069 967,838 78,655 ------------ ------------- ------------ Cash and Equivalents at End of Year $ 2,329,236 $ 6,198,069 $ 967,838 ============ ============= ============ Supplemental Disclosures: Cash paid for interest $ 82,295 $ 151,955 $ 295,360 Cash paid for income taxes - - -
See notes to financial statements. F-6 THE EXPLORATION COMPANY Notes to Financial Statements August 31, 1998, 1997 and 1996 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. In 1993, the Company commenced operations in the alternative fuels industry through a division called ExproFuels. ExproFuels converted vehicle engines that use gasoline for combustion to propane or natural gas, supplies alternative fuels to customers and constructs alternative fuels refueling facilities with customers located primarily in Texas and Arizona. The ExproFuels division was incorporated in August, 1996, and was spun off from The Exploration Company on September 3, 1996, with an approximate 40% equity ownership being retained. At August 31, 1996, financial position and results of operations of ExproFuels, Inc. was reported in accordance with disposal of a line of business with a significant retained interest. The Company's net assets in ExproFuels, Inc. was reduced to $0 in 1997 by recognition of its equity ownership in losses. ExproFuels, Inc. is currently being liquidated. 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 had approximately $4,700 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 are in excess of the discounted present value of future cash flows relating to proved reserves, an impairment charge is recorded. 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. Basic Loss Per Common Share: In 1997, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 128, Earnings per Share. Statement No. 128 replaced the previously reported primary and fully diluted earnings per share with basic and diluted earnings per share. Unlike primary earnings per share, basic earnings per share excludes any dilutive effects of options, warrants and convertible securities. Diluted earnings per share is very similar to the previously reported fully diluted earnings per share. Earnings per share as previously reported did not change due to the new Statement. F-7 THE EXPLORATION COMPANY Notes to Financial Statements August 31, 1998, 1997 and 1996 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 receivables. Accounts receivable, net of allowance of $27,000 at August 31, 1998, 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 and Removal Liabilities: The estimated costs of restoration and removal of producing property well sites is generally less than the estimated salvage value of the respective property. Accordingly, the Company has not provided for an additional liability accrual. Fair Value of Financial Instruments: The only financial instruments of the Company at August 31, 1998 and 1997, 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. Reclassifications: Certain amounts for 1997 and 1996 have been reclassified for comparative purposes to 1998. F-8 THE EXPLORATION COMPANY Notes to Financial Statements August 31, 1998, 1997 and 1996 Note B - Long Term Debt Long-term debt consists of the following at August 31:
1998 1997 -------------- -------------- 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. $3,346,625 $ - Note payable to Caza Drilling with interest at 14%, due in monthly installments of $35,000 with final payment in full in December 1998, unsecured. 165,503 - 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. 847,053 - 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 - 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. 318,672 - Convertible notes payable with interest at 6%, due in full on December 31, 2001. The notes and accrued interest were converted into common stock in 1998. See below. - 4,000,000 Note payable under $1,000,000 line of credit with Luzerner Kantonalbank, Luzern, Switzerland, with interest floating at the bank's market rate, unsecured and due on demand. - 940,481 Installment notes due financing companies, with interest rates from 8.50% to 8.75% (11.90% in 1997), due in monthly installments of $2,877 ($401 in 1997) and secured by certain vehicles. 35,159 3,532 Installments due on capital lease obligations, with imputed interest rates from 21.33% to 22.64%, due in monthly installments of $2,296 and secured by related equipment. 33,548 50,987 ------------ ------------ Total long-term debt and capitalized lease obligations 4,823,927 4,995,000 Less current portion (1,846,383) (961,975) Long-term portion of debt and capitalized lease obligations $ 2,977,544 $ 4,033,025 ============ ===========
F-9 THE EXPLORATION COMPANY Notes to Financial Statements August 31, 1998, 1997 and 1996 Note B - Long Term Debt - Continued The following is a schedule of principal maturities of long-term debt as of August 31, 1998: Fiscal Year Ended August 31 Amount --------- --------- 1999 $ 1,846,383 2000 1,389,688 2001 910,262 2002 413,147 2003 264,447 Thereafter - ----------- $ 4,823,927 =========== Convertible $4,000,000 Notes Payable: During the current year, the Company converted its $4,000,000, 6% convertible notes, together with accrued interest of $221,590, into 844,318 shares of common stock at the conversion price of $5 per share. Note C - Stockholders' Equity 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, "Accounting 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, "Accounting 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 has authorized the grant of options to management, directors, and key personnel for up to 400,000 shares of the Company's common stock. All options granted have ten year terms and vest and become fully exercisable based on the specific terms imposed at the date of grant, generally ranging up to three years. 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 1998, 1997 and 1996, respectively: risk-free interest rates of 4.0%, 6.25% and 6.25%; dividend yields of -0-%; volatility factors of the expected market price of the Company's common stock of .69, .33 and .33; and a weighted-average expected life of the option of five years. F-10 THE EXPLORATION COMPANY Notes to Financial Statements August 31, 1998, 1997 and 1996 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:
1998 1997 1996 ------------ ------------- ------------ Pro forma net (loss) $ (8,608,865) $ (3,539,881) $ (1,800,389) Pro forma net loss per common share $ (0.56) $ (0.28) $ (0.31)
A summary of the status of the Company's stock option activity and related information for the years ended August 31, is as follows:
1998 1997 ------------------------------ --------------------------- Weighted-Average Weighted-Average Shares Exercised Price Shares Exercise Price ------ --------------- ------ -------------- Outstanding options at beginning of year 439,800 $ 4.06 229,800 $ 2.77 Granted 600,000 2.12 210,000 5.46 Exercised (10,000) 2.00 - - Forfeited - - - - ---------- ------- -------- ------ Outstanding options at end of year 1,029,800 $ 2.95 439,800 $ 4.06 ========== ======= ======== ====== Exercisable at end of year 379,800 $ 3.78 339,800 $ 3.32 ========== ======= ======== ====== Weighted-average fair value of options granted during the year $ .48 $ 1.57 ======= ======
F-11 THE EXPLORATION COMPANY Notes to Financial Statements August 31, 1998, 1997 and 1996 Note C - Stockholders' Equity - Continued The following table summarizes information about the options outstanding at August 31, 1998:
Options Outstanding Options Exercisable ------------------------------------------------ ------------------------------- Weighted-Average Number Remaining Weighted-Average Number Weighted-Average Exercise Price Outstanding Contractual Life Exercise Price Exercisable Exercise Price -------------- ----------- ---------------- -------------- ----------- -------------- $ 2.125 600,000 9.6 years $ 2.12 - $ 2.12 2.34 50,000 0.8 years 2.34 50,000 2.34 2.62 60,000 8.0 years 2.62 60,000 2.62 2.75 100,000 7.5 years 2.75 100,000 2.75 3.13 60,000 0.8 years 3.13 60,000 3.13 3.91 9,800 3.3 years 3.91 9,800 3.91 6.60 150,000 8.6 years 6.60 100,000 6.60 -------- --------- ------- --------- ------- 1,029,800 8.2 years $ 2.95 379,800 $ 3.78 ========== ========= ====== ======== ======
StockWarrants: The following is a summary of warrants outstanding at August 31, 1998:
Weighted Weighted Average Average Number Range of Exercise Contractual Purpose of Warrants Outstanding Prices Price Life ------------------- ----------- ------ --------- --------- Convertible notes and equity financing 798,106 $ 2.00 - $6.00 $ 2.16 3.1 years Services rendered 150,000 2.18 - 2.68 2.52 1.0 year
Note D - Operating Leases The Company leases its primary office space for $7,676 per month through February, 2000. For the years ended August 31, 1998, 1997 and 1996, the Company incurred rent expense of $93,901, $91,639, and $91,144, respectively. Future minimum rentals under all noncancellable real estate leases are as follows: Fiscal Year Ended August 31 Amount --------- ---------- 1999 $ 92,115 2000 46,057 --------- Future minimum rentals $ 138,172 ========= F-12 THE EXPLORATION COMPANY Notes to Financial Statements August 31, 1998, 1997 and 1996 Note E - Federal Income Taxes The Company has incurred losses for both financial statement and income tax purposes. 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:
1998 1997 -------------- -------------- Deferred tax assets: Tax net operating loss carryforwards $ 24,575,000 $ 17,664,000 Provision for loan losses - 845,000 Impairment of oil and gas and mineral properties 4,118,000 463,000 -------------- ------------- Gross deferred tax assets 28,693,000 18,972,000 Statutory tax rate 34% 34% -------------- ------------- 9,755,620 6,450,480 Unused general business credits 30,000 30,000 -------------- ------------- Net deferred tax assets 9,785,620 6,480,480 Less valuation allowance (9,785,620) (6,480,480) -------------- ------------- Deferred income tax asset recorded $ - $ - =============== =============
The net operating loss carryforwards available at August 31, 1998, and the related expiration dates are as follows: Expires August 31 Amount --------- -------- 1999 $ 131,000 2000 480,000 2001 1,200,000 2002 1,960,000 2003 708,000 2004 to 2008 4,875,000 2009 to 2012 15,221,000 ----------- $ 24,575,000 Note F - 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 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 have been reported at the affiliates historical cost basis, resulting 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. F-13 THE EXPLORATION COMPANY Notes to Financial Statements August 31, 1998, 1997 and 1996 Note F - Related Party Transactions - Continued During 1997, the Company advanced ExproFuels $561,224 under a formal credit arrangement, and committed to advance an additional $265,000 through December 31, 1997. Interest at 8% and the entire amount of principal and interest was due December 31, 1998. However, due to the financial condition of ExproFuels, a provision for loan loss of the outstanding balance, accrued interest and commitment in the total amount of $845,487 was recorded at August 31, 1997. The average balance outstanding on the loan during the fiscal year ended August 31, 1998 was $191,690. The average balance of the loan outstanding was $845,487 during the fiscal year ended August 31, 1998, before considering the loan loss provision. The loan was written off at August 31, 1998. In August, 1996, 10% of the outstanding common stock of ExproFuels, Inc., previously a wholly-owned subsidiary, was given to the Directors of ExproFuels, Inc. as consideration for services rendered. Also during 1996, the Company exchanged 2,637,736 shares of its unregistered common stock for 131,860 gross acres (32,965 net acres) of undeveloped oil and gas properties with several parties brought to the Company by its investment banker. Note G - 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:
1998 1997 ------------ ----------- Proved properties $ 9,098,623 $ 4,961,763 Less reserves for impairment (2,314,590) (119,397) Less accumulated depreciation, depletion and amortization (2,073,491) (680,240) ------------ ----------- Net proved properties 4,710,540 4,162,126 Unproved properties 9,372,026 10,149,324 Less reserve for impairment (1,580,000 - ------------ ------------ Net unproved properties 7,792,026 10,149,324 ------------ ------------ Net capitalized cost $ 12,502,566 $ 14,311,450 ============ ============
F-14 THE EXPLORATION COMPANY Notes to Financial Statements August 31, 1998, 1997 and 1996 Note G - Oil and Gas Producing Activities and Properties - Continued Costs incurred, capitalized, and expensed in oil and gas producing activities are as follows:
1998 1997 1996 -------- -------- -------- Property acquisition costs, unproved $ 1,232,000 $ 13,517,743 $ 4,951,598 Property development and exploration costs 6,286,745 4,024,922 732,654 Depreciation, depletion and amortization 1,103,181 258,000 160,000 Depletion per equivalent Mcf of production .93 .75 .69
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, 1995 14,124 1,342,516 Discoveries 5,710 525,000 Revisions of previous estimates 3,598 241,248 Production (2,862) (215,274) --------- --------- 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 ========= ========= All of the Company's proved reserves are developed and are located in the continental United States. F-15 THE EXPLORATION COMPANY Notes to Financial Statements August 31, 1998, 1997 and 1996 Note G - 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:
1998 1997 1996 -------------- ------------ ------------ Future cash inflows $ 11,872,000 $ 8,814,000 $ 4,658,670 Future production and development costs (1,327,000) (1,919,000) (680,120) -------------- ------------- ------------- Future net cash inflows before income tax 10,545,000 6,895,000 3,978,550 Future income tax expense - - - -------------- ------------- ------------- Future net cash flows 10,545,000 6,895,000 3,978,550 10% annual discount to reflect timing of net cash flows (1,721,000) (2,163,000) (1,778,810) -------------- ------------- ------------ Standardized Measure of discounted future net cash flows relating to proved reserves $ 8,824,000 $ 4,732,000 $ 2,199,740 ============= ============ ============
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:
1998 1997 1996 ------------ ------------ ------------ Standardized Measure, beginning of year $ 4,732,000 $ 2,199,740 $ 1,222,040 Discoveries 7,683,000 5,741,710 613,500 Sales and transfers, net of production costs (2,007,383) (728,909) (362,947) Revisions in quantity and price estimates (1,110,417) (2,260,567) 849,351 Accretion of discount (473,200) (219,974) (122,204) ------------- ------------ ------------ Standardized Measure, end of year $ 8,824,000 $ 4,732,000 $ 2,199,740 =========== =========== ===========
F-16 THE EXPLORATION COMPANY Notes to Financial Statements August 31, 1998, 1997 and 1996 Note H - Segment Information and Major Customers In 1998 and 1997, the Company operated only in the oil and gas exploration industry. In 1996, the Company also operated in the alternative fuels industry. Operations in the oil and gas industry consist of acquiring, exploring and developing oil and gas properties (see Note A). Operations in the alternative fuels industry were conducted through the Company's ExproFuels division, and are reported as a separate line item on the balance sheet and statement of operations. The Company's oil and gas sales include amounts sold to major purchasers in the three years ended August 31, as follows: Purchaser 1998 1997 1996 - --------- -------- -------- -------- A . $985,000 $ -- $ -- B . 810,000 732,000 371,000 C . 595,000 -- -- D . -- 122,000 31,000 Note I - Supplemental Disclosures of Cash Flow Information 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. Year Ended August 31, 1996 The Company issued 2,723,680 shares of its common stock in exchange for oil and gas properties (valued at the market price per share for unregistered stock). The Company exchanged a 32.5% mineral property interest for certain oil and gas properties valued at $225,000, a $100,000 note and certain other assets valued at $73,403. Note J - Year 2000 The Company is currently conducting a review of its internal systems to verify their compliance with Year 2000 date codes. It is also inquiring of its major suppliers and oil and gas purchasers whether or not they support Year 2000 date codes. While the Company's inventory, review and assessment is still in process, it expects that the required modifications will be made on a timely basis and that the cost of such modifications will not have a material effect on the Company's operating results. However, the Company can have no assurance that its operations will not be adversely affected by difficulties encountered with Year 2000 date codes by any of its major suppliers or oil and gas purchasers. F-17 THE EXPLORATION COMPANY Schedule II - Valuation and Qualifying Reserves For the Three Years Ended August 31, 1998
Balance Charges to Balance Beginning Costs and End of of Period Expense Write-offs Period --------- ------- ---------- ------ 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 Year ended August 31, 1996 Allowance for doubtful accounts - trade accounts ............................................ $ 9,973 $ -- $ -- $ 9,973 Impairment of oil and gas properties ......................... 90,997 -- -- 90,997
F-18 EX-27 2 FDS --
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE EXPLORATION COMPANY AUDITED FINANCIAL STATEMENTS FOR THE YEAR ENDED 8/31/98 AND IS QUALIFED IN ITS ENTIRETY BY REFERENCE TO SUCH THE EXPLORATION COMPANY FORM 10-k FOR THE YEAR ENDED 8/31/98. 0000313395 THE EXPLORATION COMPANY 1 US DOLLAR YEAR AUG-31-1998 SEP-01-1997 AUG-31-1998 1 2,329,236 0 861,666 0 0 3,208,640 18,707,635 6,101,207 16,264,632 2,691,947 2,977,544 0 0 156,135 10,439,006 16,264,632 3,048,277 3,048,277 9,843,890 11,122,160 0 0 442,105 (8,417,218) 0 (8,417,218) 0 0 0 (8,417,218) (.55) 0
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