-----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, JWcArwn9AlFHRQOZXOSjC9TIlEBZHSxF3fXPpxn7rV7zhFojaU2r/gQUU+yqprR4 Gi8ETb2zAKvWm+CHn5kUXg== 0000950134-01-003319.txt : 20010416 0000950134-01-003319.hdr.sgml : 20010416 ACCESSION NUMBER: 0000950134-01-003319 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 20001231 FILED AS OF DATE: 20010412 FILER: COMPANY DATA: COMPANY CONFORMED NAME: VENUS EXPLORATION INC CENTRAL INDEX KEY: 0000312037 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 133299127 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: SEC FILE NUMBER: 000-14334 FILM NUMBER: 1601735 BUSINESS ADDRESS: STREET 1: 1250 NE LOOP 410 STREET 2: SUITE 1000 CITY: SAN ANTONIO STATE: TX ZIP: 78209 BUSINESS PHONE: 2109304900 MAIL ADDRESS: STREET 1: 1250 NE LOOP 410 STREET 2: SUITE 1000 CITY: SAN ANTONIO STATE: TX ZIP: 78209 FORMER COMPANY: FORMER CONFORMED NAME: XPLOR CORP DATE OF NAME CHANGE: 19940906 10-K405 1 d85666e10-k405.txt FORM 10-K FOR FISCAL YEAR END DECEMBER 31, 2000 1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2000 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to ----------------- ----------------- Commission File Number 0-14334 VENUS EXPLORATION, INC. (Exact name of registrant as specified in its charter) DELAWARE 13-3299127 (State or other jurisdiction of (I.R.S. Employer Identification No.) incorporation or organization) 1250 N.E. LOOP 410, SUITE 1000, SAN ANTONIO, TX 78209 (Address of principal executive offices) (zip code) Registrant's telephone number, including area code (210) 930-4900 Securities registered pursuant to Section 12(b) of the Act: None Securities registered pursuant to Section 12(g) of the Act: Common Stock, $0.01 par value (Title of Class) 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 twelve months, 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 the Registrant's knowledge, in the definitive proxy statement 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 Common Stock held by non-affiliates of the Registrant (all directors, officers and holders of five percent or more of the Common Stock of the Company are presumed to be affiliates for purposes of this calculation), computed by reference to the closing bid price of such stock on March 19, 2001, was approximately $4,300,000. As of March 19, 2001, the Registrant had outstanding 12,343,196 shares of Common Stock. 1 2 DOCUMENTS INCORPORATED BY REFERENCE The information required by Part III of this Annual Report on Form 10-K will be included in the Registrant's definitive Proxy Statement for its 2001 Annual Shareholder Meeting. It is expected that the Proxy Statement will be filed with the Commission not later than April 30, 2001. TABLE OF CONTENTS PART I....................................................................................................................3 ITEM 1. BUSINESS.....................................................................................................3 ITEM 2. PROPERTIES..................................................................................................15 ITEM 3. LEGAL PROCEEDINGS...........................................................................................19 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.........................................................19 PART II..................................................................................................................20 ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS...................................20 ITEM 6. SELECTED FINANCIAL DATA.....................................................................................21 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.......................21 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK..................................................27 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.................................................................27 ITEM 9. CHANGES IN, AND DISAGREEMENTS WITH, ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE......................27 PART III.................................................................................................................28 ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT..........................................................28 ITEM 11. EXECUTIVE COMPENSATION......................................................................................28 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT..............................................28 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS..............................................................28 PART IV..................................................................................................................28 ITEM 14. EXHIBITS, FINANCIAL STATEMENTS SCHEDULES...................................................................28
2 3 PART I ITEM 1. BUSINESS FORWARD-LOOKING STATEMENTS This Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Those statements are contained under this Item 1 "-Business," under Item 7 "-Management's Discussion and Analysis of Financial Condition and Results of Operations," and elsewhere in this Form 10-K. The forward-looking statements are identified by language that speaks of future events. For example, words such as "may," "could," "believe," "expect," "intend," "anticipate," "estimate," "target," "continue," "projected," "future," "will," "seek," and "plan". The forward-looking statements address such matters as geological estimates of oil and gas reserves, exploratory and development drilling plans and schedules, capital expenditures, availability of capital resources, financial projections, present values of future production, financing assumptions and other statements that are not historical facts. Although statements involving those matters are based on information available at the time this Annual Report on Form 10-K was prepared and although Venus believes that its statements are based on reasonable assumptions, it can give no assurance that its goals will be achieved or that the level of production or financial return expected can be achieved. Some of the important factors that could cause actual results to differ materially from those predicted in the forward-looking statements include (i) state and federal regulatory developments and statutory changes, (ii) the timing and extent of changes in commodity prices and markets, (iii) the timing and extent of success in acquiring leasehold interests and in discovering, developing or acquiring oil and gas reserves, (iv) the conditions of the capital and equity markets during the periods covered by the forward-looking statements, (v) reliance on estimates of reserves, (vi) drilling results, (vii) the Company's success in raising additional capital to fund its operations and to fund the execution of its strategy, and (viii) other matters beyond the control of the Company; e.g., the risk factors that are listed beginning on page 6. COMPANY OVERVIEW Venus Exploration, Inc. ("Venus" or the "Company") is an independent oil and gas exploration and development company. We acquire producing oil and gas properties onshore in the United States and apply advanced geoscience technology to the exploration for and exploitation of undiscovered reserves. The Company presently has oil and gas properties, acreage and production in eight states, including Texas, Louisiana, Oklahoma and Utah. Our current focus is: o the Expanded Yegua Trend of the Upper Texas and Louisiana Gulf Coast, and o the Cotton Valley Trend of East Texas and Western Louisiana. Oil and gas terms and abbreviations that are used in this Annual Report on Form 10-K are defined in this Item 1 under "Business - Definition of Certain Oil and Gas Terms, beginning on page 13. Those terms and abbreviations are usually capitalized in the text. Proved Reserves as of December 31, 2000, totaled 10.8 Bcfe, a decrease of .3 Bcfe from the 11.1 Bcfe that we reported at year-end 1999, a 2.7% decrease. The decrease is due to the downward revision of reserves of some existing properties and by normal production. Production for 2000 totaled .9 Bcfe and new discoveries, extensions and revisions of reserves on our existing properties totaled .5 Bcfe. In 2000, average daily net production increased to 2,400 Mcfe/day from 2,250 Mcfe/day in 1999, a 6.7% increase. The increase is due to increased production on existing wells and the completion of a new well. As of December 31, 2000, approximately 47% of our reserves are natural gas reserves. As of December 31, 1999, approximately 39% of our reserves were natural gas. Venus operates 47% of its Net Wells. BUSINESS STRATEGY Venus's strategy consists of: o Exploration for oil and natural gas reserves in geographic areas where the Company has expertise o Exploitation and development drilling in existing oil and gas fields o Acquisition of strategic producing properties with upside potential Exploration - We use advanced geoscience technology to conduct exploration programs for new oil and gas reserves and undiscovered fields in geological trends that are considered to contain an undiscovered resource base of oil and natural gas. High-risk exploration gives us the opportunity to participate in discovery of substantial oil and gas reserves and the resultant 3 4 rapid growth in asset values that can occur. Because of the inherent uncertainty and high financial risk associated with the outcome of individual drilling prospects, we maintain an inventory of many exploratory Prospect Leads from which drilling prospects are confirmed and generated. We attempt to reduce our financial risk and to obtain financing for a large portion of the exploration costs through sale to oil and gas industry co-venturers of working interests in prospects originated by us. Our management has used this strategy successfully in the past. Due to the decline in oil prices between 1997 and 1999, capital available for exploration budgets was reduced during that period, both for the oil and gas industry in general and for Venus specifically. As a result, Venus reduced exploration activity and continue to work only selected prospects believed to have extraordinary merit. Our exploration team currently concentrates on two geographic areas: the Expanded Yegua Trend of the Upper Texas and Louisiana Gulf Coast and the Cotton Valley Trend of East Texas and Western Louisiana. Secondary areas are the South Midland Basin and the mid-continent. We have an inventory of exploration Prospects and Prospect Leads, and we are reactivating exploratory drilling projects so that when, and if, industry drilling budgets are restored for exploration, we will have drilling projects available in which to offer participation to industry co-venturers. The primary geoscience technologies we use to evaluate Prospects and Prospect Leads are 2-D and 3-D seismic surveys and the subsurface geological studies used to interpret the data gathered by these seismic surveys. Our in-house technical capability is an important ingredient in our current and continuing ability to conduct comprehensive exploration programs and ongoing exploitation of existing fields. Exploitation - We use advanced geoscience technology to exploit and to develop oil and gas reserves in currently producing fields which we believe are not fully developed. We are conducting active exploitation and development activities in seven different fields in Texas, Oklahoma and Utah. Our working interest in those fields varies from 2.5% to 100%, and we operate in four of the seven active fields. During periods of low commodity prices, we emphasize acquisition and expansion of reserves in existing oil and gas fields rather than exploration for new reserves in unestablished areas. Acquisition - We seek strategic producing property acquisitions that offer near-term production enhancement potential and longer-term development drilling potential. These opportunities on properties we may potentially acquire can be investigated through the application of advanced technology by our technical team. We also seek to accomplish strategic acquisitions of producing assets with development and exploratory potential through strategic alliances with other oil and gas companies. We may also sell non-strategic properties as a part of our effort to concentrate on our focus areas. COMPANY HISTORY We were incorporated in the State of Delaware in September 1985 under the name Xplor Corporation. In 1997, through a reverse merger, the present management team was put into place, implementing our current exploration and development focus. After that merger and change of management, we changed our name to Venus Exploration, Inc. We are a public entity traded on the Nasdaq SmallCap Market(SM) under the symbol VENX. Members of our management team have been responsible for the discovery, development and exploitation of relatively significant reserves of oil and gas for privately held predecessor companies over the last 30 years. During the period between 1997 and 1999, our financial situation deteriorated in large part due to a downturn in oil and gas prices, a lack of cash flow and an inability to raise capital to finance new drilling projects or acquisitions of oil and gas properties. To address our financial condition, including our failure to comply with some covenants of our credit facility and our lack of liquidity in late 1998 and 1999, our management developed and implemented a restructuring plan. The following steps were implemented: o selling non-core properties o reducing office personnel o concentrating on development projects that have a lower degree of geological and engineering risk relative to the economic investment and anticipated rate of return o using our technical expertise and our network of contacts in the industry to acquire attractive packages of oil and gas properties that are already producing and that have undrilled potential o raising equity capital RECENT DEVELOPMENTS Below is an update of significant developments during 2000. 4 5 Conversion to Common Stock - We converted $1,000,000 original principal amount of notes into 1,142,854 shares of our common stock. We issued an aggregate of 63,053 shares of our common stock in payment of the interest that became due on the notes due or accrued during 2000. These shares were issued in lieu of cash interest payments accrued of $37,858 through August 22, 2000, the date of the last conversion. The shares were issued pursuant to an exemption from registration under the Securities Act of 1933, as amended; therefore the shares are restricted. Repayment of bank debt - In December of 1999, we completed the sale of some oil and gas properties that were held through a joint venture, EXUS Energy, with another industry participant. On January 6, 2000, we used $7.1 million of the net proceeds from the sale of the EXUS Properties to repay our share of the EXUS Energy bank debt under a credit facility with NationsBank, $7 million to repay our convertible note to the other joint venturer, $250,000 to satisfy a prepayment penalty under that convertible note, and $3.7 million to reduce our then existing bank debt. The balance of our bank debt, $152,000, was paid on March 30, 2000. Nasdaq Listing - On January 28, 2000 Nasdaq removed the conditional status of our Nasdaq listing that arose in 1999 from our temporary inability to comply with all of Nasdaq's continued listing requirements. On July 17, 2000, Nasdaq sent us a letter stating that our minimum bid price had not been at least $1.00 over the preceding 30 consecutive trading days as required under Marketplace Rule 4310(c)(4). Failure to comply with this rule constitutes grounds for delisting; however, the rule provides an automatic 90 day period for our bid price to exceed $1.00 for at least 10 consecutive trading days, at which time, Nasdaq's staff would determine if we were in compliance with the rule. The rule also sets out an appellate process which includes a hearing. On October 12, 2000, we requested a hearing in order to appeal the matter and, on October 13, 2000, Nasdaq granted us a hearing on November 9, 2000. Beginning, October 4, 2000, our closing bid price exceeded $1.00 for a period that exceeded the 10 consecutive trading day minimum and, on November 2, 2000, we received a letter from Nasdaq stating that we were in compliance with Nasdaq Marketplace Rule 4310(c)(4) and the November 9, 2000 hearing was cancelled as it was no longer necessary. We have continued to be in compliance with the rule since that date. Current Credit Facility - On May 5, 2000, we entered into a loan agreement with a new primary lender establishing a one year, $15 million revolving line of credit subject to a borrowing base that will be redetermined by the lender every six months (October 1 and April 1), based on our oil and gas reserves. The initial borrowing base was $2.45 million and, by the terms of the loan agreement, such borrowing base has declined at the rate of $50,000 per month. On October 1, 2000, the lender determined the borrowing base was $2.2 million, which base continued to decline at $50,000 per month until the next borrowing base redetermination on April 1, 2001, at which time, our lender determined our borrowing base to be $1,130,000. We may request interim redeterminations; however, changes in the borrowing base are solely at the discretion of the lender based on the lender's then current engineering standards and are subject to the lender's credit approval process. Mandatory prepayment is required to the extent outstanding amounts under the credit facility exceed the borrowing base. Outstanding balances under the facility bear interest at the lender's prime rate plus 1%. The loan agreement terminates on May 8, 2001. Although we intend to refinance the outstanding balance, to date, we have not obtained a commitment from a lender for such a refinancing. Gain on Sale of Other Asset - During the first quarter 2000 we sold an asset classified as other assets on our financial statements for $253,000. We recorded a gain of approximately $199,000 during the first quarter 2000 related to the sale of the asset. Management Changes - During the third quarter 2000, Patrick Garcia, our previous Chief Financial Officer, resigned his positions with us to pursue other business opportunities. On October 31, 2000, P. Mark Stark joined us in a management capacity and on December 12, 2000, Mr. Stark was named Chief Financial Officer. In addition, Terry Hardeman, who had held several positions with us and our predecessors was named Chief Accounting Officer. Stock Repurchase Plan - Effective September 18, 2000, the Executive Committee of the Board of Directors approved a plan for the repurchase of up to 300,000 shares of our common stock. With the consent and approval of our lender under our credit facility, we have the authority to purchase $100,000 worth of our common stock in open market transactions at prices related to the independent market for common stock, all in accordance with the terms and provisions of Rule 10b-18 ("Rule 10b-18") under the Securities and Exchange Act of 1934, as amended. Unless renewed by action of the Board of Directors, the repurchase plan, as amended, shall terminate on the earlier of the purchase of the 300,000 shares or June 15, 2001. 5 6 Restoration of Salary Levels - On or about March 31, 2000, salaries that were reduced as a part of our restructuring plan initiated in 1998 were increased to their previous levels. Successful Completion of the #1 Apache Gas Unit Well - We successfully completed a development well in Jefferson County, Texas, in the Constitution Field the #1 Apache Gas Unit in the Westbury Middle Yegua Sand. The well began producing on October 2, 2000, at an initial production rate of 3.682 million cubic feet of gas per day (Mmcfd) and 312 barrels of condensate per day, with 168 barrels of water per day flowing through 15/64 inch choke with 3,870 #psi flowing tubing pressure. We have a 15% Working Interest. Increase in the Number of Authorized Shares - At our 2000 Annual Meeting, our shareholders approved an amendment to the Certificate of Incorporation that increased the number of authorized shares of common stock from 30,000,000 to 50,000,000 shares. RISK FACTORS Lack of Liquidity - Our assets are predominately real property rights and intellectual information that we developed regarding our properties and other geographical areas that we are studying for exploration and development. The market for these types of properties fluctuates and can be very small. Therefore, our assets can be very illiquid and not easily converted to cash. Even if a sale can be arranged, the price may be significantly less than levels that management believes the properties are worth. That lack of liquidity can have materially adverse effect on our strategic plans, normal operations and credit facilities. Lack of Profitable Operations - Since commencing operations in 1996, we have not reported operating profits. We incurred net losses of approximately $2,007,000 for the year ended December 31, 1996, $4,168,000 for the year ended December 31, 1997, and $8,670,000 for the year ended December 31, 1998. Although we reported net income of $1,010,000 for 1999, that was a result of reporting a $4.8 million pre-tax gain from the sale of properties. In 1999, we reported a $3 million operating loss, and in 2000 the operating loss was $1.5 million. We may never generate sufficient revenues to achieve profitability, excluding gains that we may report from sales of assets. Even if we attain profitability, we may not sustain or increase profitability on a quarterly or annual basis in the future. At December 31, 2000, we had an accumulated deficit of approximately $16.7 million. Non-Traditional Financing to Fund Business Plan - We may use non-traditional sources of financing to acquire properties or to fund our capital expenditures, including the costs of drilling wells. For example, if we find unencumbered properties to buy, we may use financing that is secured only by those properties and the oil and gas production from those properties. In an arrangement like that, the lender will have no recourse against our other assets, and the prospective lender may require us to pay a higher rate of interest on the indebtedness. In addition, we may issue short-term or bridge financing, including indebtedness, or issue preferred stock or other securities in order to raise capital. Given our recent financial condition, if we issue these securities, the purchaser may require us to pay a premium or to agree to more onerous conversion or other terms. Volatility of Oil and Gas Prices - Historically, the market prices for oil and gas have been volatile, and they are likely to continue to be volatile in the future. We sell most of our oil and gas at current market prices rather than through fixed-price contracts. Thus, volatility in market prices can jeopardize our financial condition, operating results and future growth. Sharply reduced oil and gas prices during 1998 and early 1999 negatively impacted our results of operations, our access to capital, and the estimated value of our oil and gas reserves. This drop in prices also increased our operating losses. The price volatility is the result of factors beyond our control including: o domestic and foreign political conditions, o the overall supply of and demand for oil and gas, o the price of imports of oil and gas, o weather conditions, o the price and availability of alternative fuels, o overall economic conditions, o exploration and drilling costs, o pipeline availability and transportation costs, and o federal and state regulatory and statutory developments. 6 7 On a pro forma basis for the twelve months ended December 31, 2000, taking into account the sales of non-core properties, our 2000 production was 68% crude oil and condensate; however, our earnings and cash flow are sensitive to fluctuations in both oil and gas prices. Excluding production from properties sold during 2000, a $0.10 per Mcf change in average gas prices would have resulted in approximately a $31,000 difference in gross revenues for the twelve months ended December 31, 2000. Also on a pro forma basis, a $1.00 per Bbl change in average oil prices would have resulted in approximately a $95,000 difference in gross revenue for the twelve months ended December 31, 2000. Debt Financing - We plan to incur significant indebtedness as we execute our exploration, exploitation and acquisition strategy. A high debt structure may require us to pursue non-traditional and more expensive financing. The higher level of indebtedness that we may incur will have several important effects on our future operations, including: o a substantial portion of cash flow from operations will be used to pay interest on the outstanding debt and will not be available for other purposes, o our bank credit agreement will likely limit the uses of capital, o our ability to obtain additional financing in the future may be impaired, o since the interest on our indebtedness likely will be calculated with a variable rate, increases in that rate could further decrease our liquidity, and o our lender may require us to hedge production prices, which could result in a loss of revenues from potential increases in product prices paid for our oil and gas production. Replacement and Expansion of Reserves - Our financial condition and results of operations depend substantially upon our ability to find or acquire additional oil and gas reserves that are economically viable and to successfully develop those reserves. If we are unable to do so, our proved reserves will usually decline as those reserves are produced. As used in this annual report, the term "proved reserves" means the estimated quantities of oil and gas that the geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions and current regulatory practices. Our value is directly related to our level of reserves. We must replace our reserves, even during periods of low oil and gas prices when it is difficult to raise the capital necessary to finance acquisitions or development. Without successful exploration, development or acquisition activities, our reserves, production and revenues will decline rapidly. We may not be able to find or acquire new reserves or to profitably develop and produce new reserves. Exploration Risks - Our business strategy focuses in part on adding reserves through exploration, where the risks are greater than in acquisitions and development drilling. By definition, exploration involves operations in areas about which little is known. We use 3-D seismic data and other advanced technologies to identify possible new reserve locations and to reduce our exploration risk, but exploratory drilling remains speculative. Even when extensively used and properly interpreted, 3-D seismic data and other similar visualization techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators. These techniques do not conclusively allow an interpreter to know if hydrocarbons in the form of oil or gas are present or are economically producible. The use of 3-D seismic data and other technologies also requires greater pre-drilling expenditures than traditional drilling strategies. We could incur losses as a result of these higher expenditures. We, likewise, may fail to increase our reserves through exploration. Acquisition Risks - Part of our business plan is to acquire properties already producing oil and gas and to increase the reserves attributable to those properties through development drilling. The successful acquisition of producing properties requires an assessment of recoverable reserves, future oil and gas prices, operating costs and potential environmental and contractual liabilities. Our assessment, however, will not reveal all existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not perform inspections on every well or pipeline, and structural and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may not be willing, or financially able, to give contractual protection against the problems, and the decision may be made to assume environmental and other liabilities in connection with acquired properties. After a property is acquired, environmental liabilities may be discovered that may exceed our total net worth. These factors and others can turn an apparently beneficial acquisition into a financially disastrous liability. Drilling and Operating Risks - A large part of our business plan is to drill exploratory wells. Exploratory wells are wells drilled into horizons with little or no history of oil or gas production. Our business plan heightens many of the 7 8 considerable risks associated with drilling in general. Unexpected circumstances may be encountered more often when we drill exploratory wells versus other types of wells, because we are drilling at locations and into formations where no wells have been drilled before. Moreover the probability that we will discover and produce oil or gas from an exploratory well is lower than drilling a development well because less is known about the area where the exploratory well is drilled. Therefore, these risks may pose more of a danger to us than they would to a company that focuses primarily on drilling development wells. Development wells are wells drilled into known producing oil and gas fields and horizons. We anticipate drilling or participating in the drilling of thirteen (13) development wells and four (4) exploration wells during 2001. Depending on the success of those wells, we may drill additional wells in 2001. However, even if we drill and complete these wells as producing wells, they may not produce sufficient net revenues to return a profit after drilling, operating and other costs. The cost of drilling, completing and operating wells is often uncertain. Our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors. We insure risks typical to companies in our industry. Some risks just come with the business; others may not be within the scope of traditional insurance policies. In our case, the following are examples of the operating hazards against which we cannot or do not insure: o land title problems o compliance with governmental requirements o shortages or delays in the delivery of equipment and services o unexpected pressure or irregularities in underground formations (other than those causing a well to flow out of control above or below the surface of the ground) o mechanical problems encountered in drilling a well o the collapse of the well bore, whether due to loss of underground formation support or failure of the well bore casing The occurrence of an event that is not covered by our insurance, or not fully covered by insurance, could have a material adverse effect on our financial condition and results of operations. Uncertainty of Estimates of Reserves - The reserve data set forth in this annual report are only estimates even when referred to as "proved." Petroleum engineers consider many factors and make assumptions in estimating our oil and gas reserves and future net cash flows. These estimates utilize assumptions the Securities and Exchange Commission requires for all public companies, including us. Estimates by definition are imprecise. Reservoir engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured exactly and of making assumptions based on the process. Inherent uncertainties exist in the projection of future rates of production and the timing of development expenditures. The timing of production may be considerably different from the periods estimated. Assumptions are based on factors such as historical production from the area as compared with production from other areas, assumed effects of governmental regulation and assumptions regarding future oil and gas prices, costs, taxes and capital expenditures. Although we believe that our reserve estimates are reasonable, you should expect that actual production, revenues and expenditures relating to our reserves will vary from any estimates, and these variations may be material. The estimates of future net revenues from the our proved reserves and the present value of those revenues are based upon assumptions about future production levels. These assumptions may be wrong. The SEC PV-10 values as reported are based on a calculated present value of assumed future revenues. Those calculations do not provide for changes in oil and gas prices or for escalation of expenses and capital costs. "SEC PV-10" refers to present value calculated using a 10% discount rate and other conditions required by the Securities and Exchange Commission. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions and discount rate upon which they are based. For example, the rules for determining SEC PV-10 require us to use market prices as of December 31, 2000, to predict cash flow from our properties. Because of the extremely high prices in effect at the end of December 2000, we do not believe that extrapolation of those prices is justified at this time, and our internal calculations of present value are less than the SEC PV-10 value. Markets - The availability of a ready market for any oil and gas that we produce depends upon numerous factors that are beyond our control. These factors include: o federal and state regulatory developments and statutory enactments, o the timing and extent of changes in commodity prices, o exploratory and development drilling success, o the amount of oil and gas available for sale, o the availability of professional expertise and operating personnel, o the availability of drilling equipment and drilling personnel, o the availability of completing equipment and completing personnel, 8 9 o crude oil imports, o access to adequate capital, o the availability of adequate pipeline and other transportation facilities, and o the marketing of competitive fuels and other matters affecting the availability of a ready market, such as fluctuating supply and demand Competition - The oil and gas industry is highly competitive in all of its phases and in particular in the acquisition of unexplored acreage, undeveloped acreage and existing production. There are a significant number of operators engaged in oil and gas property acquisition and development, and our competitive position depends on its geological, geophysical and engineering expertise, on our financial resources, and on our ability to find, acquire and prove new oil and gas reserves. We encounter strong competition in acquiring economically desirable properties and in obtaining equipment and labor to operate and to maintain our properties. That competition is from major and independent oil and gas companies, many of which possess greater financial resources and larger staffs than we have. Labor and equipment markets have shown much volatility recently, and we cannot be certain that they will be available at the prices we have budgeted. Financial Reporting Impact of Successful Efforts Method of Accounting - We use the "successful efforts" method of accounting for our investment in oil and gas properties. This method of accounting can adversely affect our reported earnings and thereby the market value of our stock because many drilling and other costs may be required to be charged to expense earlier than might be the case with "full cost" accounting, which is used by many oil and gas companies. This charge to expense can result in reduced earnings or larger losses than might be the case with the full cost accounting method. Government Laws and Regulations - The oil and gas business is subject to extensive federal rules and regulations. If we fail to comply with these rules and regulations, we can incur substantial penalties. In general, the regulatory burden on the oil and gas industry increases our cost of doing business and decreases our profitability. Because these rules and regulations are frequently amended or reinterpreted, the future cost or impact of complying with these laws cannot be predicted with any certainty. The State of Texas and many other states require permits for drilling operations, drilling bonds and reports concerning operations. They also impose other requirements relating to the exploration and production of oil and natural gas. Many states have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from wells, and the regulation of spacing, plugging and abandonment of wells. Our activities with regard to exploration, development and production of oil and gas, including the operation of saltwater injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of drilling and operating oil and gas wells. Various governmental entities can impose civil and criminal fines and penalties for noncompliance with these environmental laws and regulations. Some environmental laws can impose joint and several retroactive liabilities, without regard to fault or the legality of the original conduct. In addition, a release of oil into water or other areas can result in us being held responsible for the costs of cleaning up the release. That liability can be extensive, depending on the nature of the release. Other environmental regulations impose standards for the treatment, storage and disposal of both hazardous and nonhazardous solid wastes. We, like others in the industry, generate hazardous and nonhazardous solid waste in connection with our routine operations. Additionally, these environmental laws and regulations require operators like Venus to get permits or other governmental authorizations before undertaking routine industry activities. Because any violation of environmental statutes could affect a large area and because our exploration projects are drilled into horizons where little is known about the conditions we will encounter, we could incur substantial liability under these environmental statutes. If a large environmental liability is incurred, our costs would increase. Increased costs could reduce the profitability and value of our properties. Given our dependence on debt financing and the importance of our lender's valuation of our collateral, any substantial decrease in the then-current estimates of total value could have detrimental effects on our operations and business plan. Potential Dilution - As of December 31, 2000, there were 2,131,416 shares of our common stock currently issuable upon exercise of outstanding warrants or vested options. On January 23, 2001, warrants totaling 1,044,706 expired, leaving 1,086,710 shares issuable upon exercise of outstanding warrants or vested options. The issuance of any of these shares could be considered dilutive to then-existing stockholders and could depress our stock price. In addition, the possibility that so many shares could be issued could further depress the price of our common stock. Control by Certain Stockholders - As of December 31, 2000, Range Resources Corporation and our current officers and directors as a group beneficially own more than forty three percent (43%) of the undiluted voting power of the voting equity. One of our directors is the president of Range Resources Corporation. Consequently, if our current officers and 9 10 directors and Range Resources Corporation act together, those stockholders are in a position to effectively control our affairs, including the election of all of our directors and the approval or prevention of certain corporate transactions that require majority stockholder approval. Dependence on Key Personnel - We are dependent upon Eugene L. Ames, Jr., Chairman of the Board and Chief Executive Officer, and John Y. Ames, President and Chief Operating Officer. Mr. Eugene L. Ames, Jr. is our executive with the most extensive contacts and relationships in the oil and gas industry. John Y. Ames has extensive experience in land management and acquisition. We are also dependent on Thomas E. Ewing and Bonnie Weise, both of whom are actively involved in the technical application of the geoscience methods that are the basis for our exploration activities. Dr. Ewing and Ms. Weise possess valuable experience and knowledge with regard to oil and gas exploration, and their technical expertise would be difficult to replace. We have employment agreements with Mr. Ames, Jr., Dr. Ewing and Ms. Weise, all of which have non-competition clauses. We do not carry key-man insurance on any of these individuals. Our business and operations could be seriously harmed if Mr. Ames, Jr., Mr. J. Ames, Dr. Ewing or Ms. Weise were to leave us. Compliance with Nasdaq Listing Requirements - At December 31, 2000, we had tangible net worth of $2.1 million which is $0.1 million above the minimum required for a Nasdaq SmallCap Market(SM) listing. If in 2001 our net income is not at least $500,000 or our tangible net worth decreases below $2 million, we may be delisted from the Nasdaq SmallCap Market(SM). There is no assurance that we will have either sufficient tangible net worth at December 31, 2001, or, alternatively, sufficient net income for the year ending December 31, 2001 to maintain our Nasdaq listing. From time to time over the past several months our closing bid price has fallen below the Nasdaq minimum of $1 per share. There is no assurance that the bid price will stay above the minimum required in accordance with Nasdaq SmallCap Market(SM) listing requirements. If Nasdaq delists us, our common stock will be traded on the OTC Bulletin Board or the "pink sheets," or not traded at all. Many institutional and other investors refuse to invest in stocks that are traded at levels below the Nasdaq SmallCap Market(SM), and that could make our effort to raise capital more difficult. In addition, the firms that currently make a market for our common stock could discontinue that role. OTC Bulletin Board and "pink sheet" stocks are often lightly traded or not traded at all on any given day. Any reduction in liquidity or active interest on the part of investors in our common stock could hurt our shareholders either because of reduced market prices or a lack of a regular, active trading market for the our common stock. Loan Covenant Defaults - During 1998 our financial situation deteriorated in large part due to a downturn in oil and gas prices, a lack of cash flow and an inability to raise capital to finance new drilling projects or acquisitions of oil and gas properties. During the last half of 1998 and throughout 1999 we received a series of waivers from our previous lender for defaults of certain financial covenants in our revolving credit agreement, including a waiver through March 31, 2000, for defaults existing as of December 31, 1999. We entered into our current credit facility in May of 2000. It has similar financial covenants that we failed to satisfy as of December 31, 2000, and we have requested and received from our current lender a waiver of such defaults. Other than recording gains from sales of producing properties or other assets, we do not expect to generate net earnings until more Development Wells are drilled and successfully completed. Also, oil and natural gas prices are volatile, and an unexpected drop in crude oil or natural gas prices could cause us, at some point in the future, to be in default under the terms of the current credit facility or its replacement. Accordingly, although our management intends to maintain compliance with our current financial covenants, there is no assurance that management can do so. Substantial Capital Requirements - The cash flow generated by our current operations is sufficient to fund our general and administrative expenses, but we rely on bank and other financing to implement our business plan. Our credit facility expires on May 8, 2001. Although we intend to refinance the outstanding balance under our credit facility, to date, we have not obtained a commitment from a lender for such a refinancing. Future availability of credit will depend on the success of our development program and our ability to stay in compliance with our credit facility debt covenants, neither of which is assured. Availability of Equipment and Personnel - Shortages or the high cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our development and exploration operations, which could have a material adverse effect on our business, financial condition or results of operations. In the event that drilling activity increases, we may experience increases in associated costs, including those related to drilling rigs, equipment, supplies and personnel, as well as the services and products of other vendors to the industry. Increased drilling activity in the regions in which we operate will likely decrease the availability of drilling rigs and related equipment and personnel. We cannot assure you that costs will not increase further or that necessary equipment and services will be available to us at economical prices. Impact of Asset Impairments - Accounting rules require that we review periodically the carrying value of our oil and natural gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties. A write-down constitutes 10 11 a non-cash charge to earnings, which reduces our equity. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken. Hedging Activities - Our lender requires us to enter into contracts that fix our revenue from the sales of our oil and gas production within an agreed price range. We have done so with an affiliate of the our lender. However, the lender is not obligated to observe a default by its affiliate, and if the lender's affiliate defaults on its obligations under the hedging agreements, that may affect our ability to service our debt obligations with our lender. The possible effects include our default on our payment obligations and our lender's foreclosure of its security interests in our oil and gas properties. REGULATIONS General Federal and State Regulation - Our business is subject to extensive federal rules and regulations. Failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases the cost of doing business and affects our profitability. Because such rules and regulations are frequently amended or reinterpreted, the future cost and impact of complying with such laws are difficult to predict. The State of Texas and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and natural gas. Many states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from wells, and the regulation of spacing, plugging and abandonment of such wells. Many states restrict production to the market demand for oil and gas. Some states have enacted statutes prescribing ceiling prices for gas sold within their boundaries. Also, from time to time regulatory agencies impose price controls and limitations on production by restricting the rate of flow of oil and gas wells below natural production capacity in order to conserve supplies of oil and gas. Environmental Regulation - The exploration, development and production of oil and gas, including the operation of saltwater injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. Such laws and regulations can increase the costs of planning, designing, installing and operating oil and gas wells. Our domestic activities are subject to a variety of environmental laws and regulations. A partial list of those is: o Oil Pollution Act of 1990, o Clean Water Act, o Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), o Resource Conservation and Recovery Act ("RCRA"), and o Clean Air Act. Civil and criminal fines and penalties may be imposed for non-compliance with these environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking certain activities. Under the Oil Pollution Act, if we release oil into water or other areas designated by the statute, we can be held responsible for the costs of remediating such a release, damages specified in the Act, and the damage to natural resources. That liability can be extensive, depending on the nature of the release. CERCLA and comparable state statutes, also known as "Superfund" laws, can impose joint and several retroactive liabilities, without regard to fault or the legality of the original conduct. In practice, cleanup costs are usually allocated among various responsible parties. Although CERCLA currently exempts most petroleum products like crude oil, gas and natural gas liquids from the definition of "hazardous substance," our operations may involve the use or handling of other materials that may be classified as hazardous substances under CERCLA. Additionally there is no assurance that the exemption will be preserved in future amendments of the act. RCRA and comparable state and local requirements impose standards for the management, including treatment, storage and disposal, of both hazardous and non-hazardous solid wastes. We generate hazardous and non-hazardous solid waste in connection with routine operations. From time to time, proposals have been made that would reclassify certain oil and gas wastes, including wastes generated during drilling and production operations, as "hazardous wastes" under RCRA. While state laws vary on this issue, state initiatives to further regulate oil and gas wastes could have a similar impact. 11 12 PRODUCT SALES AND MAJOR CUSTOMERS Our production is generally sold at the wellhead to various oil and natural gas purchasing companies, typically those that are in the areas where the oil or natural gas is produced. Crude oil and condensate are typically sold at prices that are based on posted field prices. All of our natural gas is sold on the spot market. The term "spot market" refers to contracts with a term of six months or less or contracts that call for a redetermination of sales prices every six months or more often. We do not believe that the loss of one or more of our current natural gas spot purchasers would have a material adverse effect on our business because any individual spot purchaser could be readily replaced by another spot purchaser who would pay a similar sales price. However, while we believe that there will be a spot market available, that market is highly sensitive to changes in current market prices, and a downward trend in spot market prices can have a significant impact on our cash flow. Three customers each accounted for approximately 10% or more of consolidated revenues in 2000. Those are Flying J Oil & Gas, Inc. (26%), Duke Energy Field Service, Inc. (13%) and Gulfmark Energy, Inc. (10%). In 1999, two customers each accounted for approximately 10% or more of consolidated revenues. Those were Stephens & Johnson Operating Company (13%) and Flying J Oil & Gas, Inc. (19%). EMPLOYEES As of March 15, 2001, the Company had 11 employees. EXECUTIVE OFFICERS OF VENUS EXPLORATION, INC. At March 15, 2001, our executive officers were Eugene L. Ames, Jr., John Y. Ames, P. Mark Stark and Terry F. Hardeman. Eugene L. Ames, Jr., age 67, became Chairman, Chief Executive Officer and a director of our company in 1997. He has been in the oil and gas business since 1954 and has been associated with us and our predecessor entities since 1962 and chief executive officer of those predecessor entities since 1991. Mr. Ames received a B.S. degree in Geology from the University of Texas at Austin in 1955. He served as Chairman of the Independent Petroleum Association of America from 1991 to 1993 and currently serves as a member of the policy committee of the American Petroleum Institute, and chairman of the Texas Oil and Gas Association. He is also the Vice Chairman of the Board of Directors of the Southwest Research Institute. John Y. Ames, age 45, became President, Chief Operating Officer and a director of our company in 1997. He is a graduate of the University of Texas at Austin with a BBA degree in Petroleum Land Management. He had eight years of experience in the energy business before becoming associated with us and our predecessor entities as a Vice President in 1984. He became Executive Vice President of our predecessor entities in 1995 and President and Chief Operating Officer in 1996. He is the son of Eugene L. Ames, Jr. P. Mark Stark, age 46, joined our company in October 2000 and was named Chief Financial Officer in December 2000. He comes to us with 17 years of experience at the CFO level, much of it in the energy arena. From December 1998 through October 2000, Mr. Stark was the Executive Vice President for Alamo Water Refiners, Inc. From December 1995 through December 1998, he was the Chief Financial Officer for Dawson Production Services, Inc. ("DPS" - NYSE), a publicly held oil field service company. Mr. Stark received his Bachelor of Business Administration degree in Finance from the University of Texas in 1977, and his Masters of Business Administration degree in 1978 from Southern Methodist University. Terry Hardeman, age 60, joined our company's predecessor in 1990. He was named Chief Accounting Officer in December 2000 and is responsible for accounting, taxation and day-to-day management of Venus' accounting activities. Mr. Hardeman, a Certified Public Accountant in the State of Texas, has held senior financial positions with other San Antonio area companies and comes to industry after having been in public accounting for five years with KPMG LLP (formerly KPMG Peat Marwick). Mr. Hardeman received a Bachelor of Science degree in Accounting from Stephen F. Austin State University and his Masters of Business Administration from the University of Houston. 12 13 DEFINITIONS OF CERTAIN OIL AND GAS TERMS The terms defined in this section are used throughout this Annual Report on Form 10-K. Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons. Bcf. One billion cubic feet of natural gas and related compounds at standard conditions. Bcfe. Equivalent of one billion cubic feet of natural gas. In reference to natural gas, natural gas equivalents are determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. Btu. One British thermal unit. The quantity of heat required to raise the temperature of one pound of water one degree Fahrenheit at standard conditions. Completion. The installation of permanent equipment for the production of oil or gas, or, in the case of a dry hole, the reporting of abandonment to the appropriate authority. Developed Acreage. The number of acres that are allocated or assignable to producing wells or wells capable of production. Development Well. A well drilled or to be drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon believed to be productive. Dry Hole or Dry Well. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as a producing oil or gas well. Exploitation. The process whereby the value of a property is increased by working over existing wells, by making new completions in existing wells and by conducting other similar operations intended to increase production from existing wells in a developed area. Exploratory Well. A well drilled to find and to produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir beyond the currently expected limits of the known reservoir. These wells involve a high degree of risk, given the unknown nature of the horizons being tested. Gross Acres or Gross Wells. The total acres or wells, as the case may be, in which a working interest is owned. Mbbls. One thousand barrels of crude oil or other liquid hydrocarbons. Mmbtu. One million Btu's. Mcf. One thousand cubic feet of natural gas and related compounds at standard conditions. Mcfe. The equivalent of one thousand cubic feet of natural gas. In reference to natural gas, natural gas equivalents are determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. Mmcfe. The equivalent of one million cubic feet of natural gas. In reference to natural gas, natural gas equivalents are determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. Net Acres or Net Wells. The sum of the fractional Working Interests owned in Gross Acres or Gross Wells. Production Cost. Also referred to as lifting cost, it is the cost of operation and maintenance of wells, related equipment and facilities that are expensed as incurred as a part of the cost of oil and gas produced; e.g., labor to operate the wells and facilities, repair and maintenance expenses, materials and supplies consumed, taxes and insurance on property, and severance taxes. 13 14 PV-10 Value, or Present Value of Estimated Future Net Revenues. The present value of estimated future net revenues as of a specified date, after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting federal income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their "present value." The present value is shown to indicate the effect of time on the value of the revenue stream. Productive Well. A well that is producing oil or gas or that is capable of production. Prospect. An area that has been interpreted to be prospective for commercial hydrocarbon accumulation based on seismic evaluations; leases may or may not have been acquired in the area of the Prospect. Prospect Lead. An area that preliminary evaluations suggest may be prospective for commercial hydrocarbon accumulation; usually no seismic studies will have been conducted on such an area, nor will have any leases been acquired in it. Proved Developed Reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved Reserves. The estimated quantities of crude oil, natural gas and natural gas liquids 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 Undeveloped Reserves, or PUD. Proved Reserves that are under undeveloped spacing units that are so close and so related to developed spacing units that they may be assumed with confidence to become commercially productive when drilled. Royalty Interest. An interest in an oil and gas property entitling the owner to a share of the oil and gas produced, free of costs of production. Seismic Data. Geophysical information collected by transmitting sound waves into the earth from a transmitter, or source, and measuring, with appropriate receivers, the time of the sound waves' arrival and their intensity when they are reflected or refracted back to the surface. 2-D seismic data is collected along a surface line of sources and receivers, giving a section representing a slice through the earth. 3-D seismic data is collected by distributing sources and receivers over an area, yielding a volume of information representing the 3-dimensional section of earth beneath the area being studied. The improved imaging of 3-D data makes it the preferred advanced technological method of attempting to determine the location, extent and properties of hydrocarbon accumulations. Undeveloped Acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether such acreage contains Proved Reserves. Working Interest, or WI. The cost-bearing operating interest that gives the owner the right to drill, to produce and to conduct operating activities on the property and to share a proportionate part of production. 14 15 ITEM 2. PROPERTIES OIL AND NATURAL GAS RESERVES As of December 31, 2000, Ryder Scott Company, independent petroleum engineers, evaluated all of our properties in order to generate our PV-10 Value. The PV-10 Values shown in this Annual Report on Form 10-K are not intended to represent the current market value of the estimated net Proved Reserves of oil and natural gas properties we own. Prices and costs have been held constant based on December 31, 2000, prices and costs. We have not filed any estimate of oil or gas reserve information with any federal authority or agency other than the U.S. Securities and Exchange Commission (SEC). The following table summarizes our estimates of our net Proved Reserves and their PV-10 Value as of December 31, 2000. PROVED RESERVES (AS OF DECEMBER 31, 2000)
PROVED PROVED DEVELOPED UNDEVELOPED TOTAL ----------- ----------- ---------- Oil and Condensate (Mbbls) 554.25 398.11 952.36 Natural Gas (Bcf) 2.49 2.63 5.12 Combined Equivalent BCF (Bcfe) 5.81 5.02 10.83 PV-10 Value (in thousands)(1) 14,212.37 16,612.36 30,824.73 =========== =========== ==========
PROVED RESERVES BY STATE (AS OF DECEMBER 31, 2000)
TOTAL GAS PERCENT OF PV-10 PERCENT GROSS OIL GAS EQUIV. TOTAL VALUE OF PV-10 STATE WELLS (MBBL) (BCF) (BCFE)(3) (BCFE) ($1,000)(1) VALUE - ---------------- --------- ------------ ------------ ---------------- ---------------- ------------ ------------ Texas 79 387 4.47 6.80 62.8% 26,212 85.0% Utah 7 362 .26 2.43 22.4% 2,576 8.4% Oklahoma 211 187 .36 1.48 13.7% 1,933 6.3 Other (2) 10 16 .02 .12 1.1% 104 .3 --------- ------------ ------------ ---------------- ---------------- ------------ ------------ TOTAL 307 952 5.11 10.83 100.0% 30,825 100.0% ========= ============ ============ ================ ================ ============ ============
(1) Pre-tax (2) Other states are Alabama, Louisiana and California. All of our Proved Reserves are in the United States. (3) We used a 6:1 ratio (mcf of gas/-bbl of oil) for the conversion. The foregoing table represents an increase in value but a decrease in volume of Proved Reserves as compared with December 31, 1999. The increase in reserve value is primarily due to the increase in oil and natural gas prices at year-end 2000 as compared to year-end 1999. The decrease in amount of reserves is primarily due the downward revision of reserves of some existing properties and normal production. See Note 13 of Notes to Consolidated Financial Statements (Supplementary Oil and Gas Disclosures) for further information. The reserve data presented in this Annual Report on Form 10-K are estimates only. In general, estimates of economically recoverable oil and gas reserves and of the future net revenues therefrom are based upon a number of variable factors and assumptions, such as historical production from the subject properties, the assumed effects of regulation by governmental agencies and assumptions concerning future oil and gas prices and future operating costs, all of which may vary considerably from actual results. All reserves are evaluated based on the assumption that all reported data are stated at standard temperature and pressure. If that assumption proves to be incorrect, it may have a substantial effect on estimated gas reserves. All such estimates are to some degree speculative, and classifications of reserves are only attempts to define the degree of speculation involved. For these reasons, estimates of the economically recoverable oil and gas reserves attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net revenues expected therefrom prepared by different engineers or by the same engineers at different times may vary substantially. Therefore, we emphasize that the actual production, revenues, severance and excise taxes, development and operating expenditures with respect to our reserves will likely vary from such estimates, and such variances could be material. 15 16 Estimates with respect to Proved Reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history will most likely result in variations in the initially estimated reserves and those variations may be substantial. In accordance with applicable requirements of the Securities and Exchange Commission, the estimated discounted future net revenues from estimated Proved Reserves are based on prices and costs as of the date of the estimate unless such prices or costs are contractually determined at such date. Actual future prices and costs may be materially higher or lower. Actual future net revenues also will be affected by factors such as actual production, supply and demand for oil and natural gas, curtailments or increases in consumption by natural gas purchasers, changes in governmental regulations or taxation and the impact of inflation on costs. DRILLING ACTIVITY We drilled, or participated in the drilling of, the following number of wells during the periods indicated:
DEVELOPMENT WELLS ------------------------------------------------------------------------- GROSS WELLS NET WELLS -------------------------------------- ---------------------------------- YEAR PRODUCTIVE DRY TOTAL PRODUCTIVE DRY TOTAL - ---- ----------- ----------- -------------- ----------- ----------- ---------- 1998 4.00 1.00 5.00 1.44 1.00 2.44 1999 3.00 1.00 4.00 .11 .07 0.18 2000 2.00 -- 2.00 .17 -- .17 ----------- ----------- -------------- ----------- ----------- ---------- Totals 9.00 2.00 11.00 1.72 1.07 2.79 =========== =========== ============== =========== =========== ==========
EXPLORATORY WELLS ------------------------------------------------------------------------- GROSS WELLS NET WELLS -------------------------------------- ---------------------------------- YEAR PRODUCTIVE DRY TOTAL PRODUCTIVE DRY TOTAL - ---- ----------- ----------- -------------- ----------- ----------- ---------- 1998 1.00 2.00 3.00 .26 .87 1.13 1999 1.00 -- 1.00 .07 -- 0.07 2000 0.00 1.00 1.00 .00 .10 .10 ----------- ----------- -------------- ----------- ----------- ---------- Totals 2.00 3.00 5.00 .33 .97 1.30 =========== =========== ============== =========== =========== ==========
PRODUCTIVE WELLS AS OF DECEMBER 31, 2000 ------------------------------------------------------------------------- GROSS WELLS NET WELLS -------------------------------------- ---------------------------------- STATE OIL GAS TOTAL OIL GAS TOTAL - ----- ----------- ----------- -------------- ----------- ----------- ---------- Texas 46 33 79 2.524 5.042 7.566 Oklahoma 194 17 211 15.189 1.273 16.462 Utah 4 3 7 1.002 1.400 2.402 Other (1) 9 1 10 2.204 .040 2.244 ----------- ----------- -------------- ----------- ----------- ---------- Totals 253 54 307 20.919 7.755 28.674 =========== =========== ============== =========== =========== ==========
(1) Other states are Michigan, Alabama, Louisiana and California. 16 17 ACREAGE The following table sets forth our Developed and Undeveloped Acreage as of December 31, 2000:
DEVELOPED AND UNDEVELOPED ACREAGE - ------------------------------------------------------------------------------------------- GROSS ACRES NET ACRES ---------------------------------- ---------------------------------- STATE DEVELOPED UNDEVELOPED DEVELOPED UNDEVELOPED - ----- ----------------- ---------------- ----------------- ---------------- Oklahoma 13,695 179 573 163 Texas 7,163 14,460 2,381 3,205 Utah 4,943 -- 1,536 -- Louisiana -- 780 -- 780 Alabama 400 -- 136 -- California 400 -- 26 -- Michigan 80 880 40 400 Kansas -- 480 -- 480 ----------------- ---------------- ----------------- ---------------- Totals 26,681 16,779 4,692 5,028 ================= ================ ================= ================
PRODUCTION The following table summarizes our net oil and gas production, weighted average sales prices and average production (lifting) costs per unit of production for the periods indicated:
UNITS OF PRODUCTION AVERAGE SALES PRICE AVERAGE ----------------------------- ----------------------------- OIL GAS OIL GAS LIFTING COST* -------------- -------------- -------------- -------------- -------------- YEAR (MBBLS) (BCF) $/BBL $/MCF $/MCFE - ---- 1998 119 .572 12.84 2.15 1.25 1999 84 .316 17.54 2.23 1.25 2000 94 .310 28.17 4.12 1.66 -------------- -------------- -------------- -------------- --------------
*Includes severance taxes and ad valorem taxes. NOTE: ALL OF OUR PRODUCTION IS IN THE UNITED STATES. During 2000, we sold two properties in Wharton County, Texas, and one property in Seward County, Kansas. Production for 1999 attributable to the properties sold totaled 1,505 barrels of oil and 18,779 Mcf of gas. Not reflected in the table above is our share of production attributable to our equity interest in EXUS Energy, which for 1999 totaled 544,200 Mcf at an average price of $2.86 per Mcf and average lifting cost of $0.39 per Mcf. We acquired our interest in EXUS Energy on June 30, 1999, and sold it on December 31, 1999. TITLE TO PROPERTIES Over 99% of our properties are Working Interests derived from oil and gas leases on property owned by third parties. None of our properties are mineral or fee interests. We usually perform title research before acquiring leases or interests in leases, and we believe that we have satisfactory title to our producing properties. The degree of research we conduct varies depending on the value initially assessed to the property, whether the property is producing at the time of acquisition, and other factors. The properties are usually subject to the rights of lessors who are paid a Royalty Interest out of production. They are also often subject to overriding royalties and other burdens, none of which we believe to be a material burden on the value of our interest. Substantially all of our properties are and will continue to be subject to liens and mortgages to secure borrowings under our credit facility. Substantially all of the properties that we own are subject to exploration or development agreements with third parties. The exploration and development agreements are subject to "Area of Mutual Interest," or "AMI," provisions that give the third party participants certain limited rights of first refusal on interests acquired within the AMI. If the third party elects not to 17 18 acquire such interest, in a majority of cases we have the right to acquire the third party's proportionate part of the interest. Once interests are acquired, the parties to the agreements usually also have an election before a well is drilled. If a party elects not to drill, we usually have the right to acquire certain interests from the non-drilling party, but depending upon the size of the interest and the cost of the proposed well, we may or may not elect to acquire that interest. In the exploration and development projects in which we place the most value, a third party election not to drill could leave little value to our interest unless we could find another third party to assume the non-drilling party's interest. OIL AND GAS PROPERTIES Constitution Field - We hold approximately 4,946 gross (4,538 net) acres in this field and own a 15% working interest in the acreage block and we are the operator. We shot a 3D seismic survey of the Constitution field in 1999. Our technical staff processed and interpreted this data and integrated the information obtained from this seismic survey with other subsurface geological information. The results of our technical analysis have caused our staff to estimate that 6 proved, undeveloped drill sites with a total of 11 zones exist in the Constitution field. The independent engineering consulting firm of Ryder Scott Company concurred with this estimate. During November 1999, we completed a successful fracture stimulation of the No. 1 Westbury Farms, which was originally completed in March 1998 as a gas condensate well through perforations in the middle Yegua Formation. During 2000 the well produced an estimated daily average production of 3.0 million cubic feet of gas and 388 barrels of condensate through 13/64" choke with 4,000 pounds per square inch tubing pressure. In 2000, we successfully completed a development well, the #1 Apache Gas Unit in the Westbury Middle Yegua Sand. This well began generating sales on October 2, 2000. The initial production rate was 3.682 million cubic feet of gas per day (MMCF) and 312 barrels of condensate per day flowing through 15/64 inch choke with 3,870 #psi flowing tubing pressure. On December 20, 2000, we spudded the Paggi #1, which was completed in February 2001. The initial production rate was 3.700 million cubic feet of gas per day (MMCF) and 475 barrels of condensate per day flowing through 22/64 inch choke with 1,986 #psi flowing tubing pressure. On February 26, 2001, we commenced drilling the fourth well in this field, and it is targeted for completion in multiple productive reservoirs. During 2001, we plan on drilling three more wells in this field, with four wells targeted to be drilled in 2002. Jackson Parish, La. - On June 30, 1999, we acquired an interest in oil and gas producing properties in Jackson Parish, Louisiana. The total purchase price was $27.6 million; however in order to finance the acquisition at no net cash outlay to us, we sold 50% of the acquisition to another company that agreed to arrange 100% of the capital required to close the acquisition. To facilitate the financing of the acquisition with our 50% co-venturer, the properties were acquired by a limited liability company in which we owned 50%. On December 31, 1999, we sold our interest in the properties, and we realized a pre-tax gain on the sale of $4.7 million, of which $4.3 million was recorded in 1999, and the balance was recorded in 2000 when contingencies related to part of the properties sold were cleared. This acquisition was a product of our strategy under which our explorationists, after conducting regional trend studies in areas they deemed to be prospective, identify producing oil and gas fields with exploitation potential as acquisition targets. Then, our management utilized its contacts with larger companies, and we were successful in our effort to acquire those properties. Sale of Properties in 2000 - In 2000, we sold two properties in Wharton County, Texas, and one in Seward County, Kansas, for an aggregate gross price of approximately $17,000. OFFICE LEASE In May 1997, we relocated our executive and operating offices to San Antonio, Texas, where we occupy premises of approximately 12,570 useable square feet pursuant to a lease that expires on December 31, 2002. We recently sub-leased that space and will be moving into a smaller area in the same building. The lease of the new space expires on May 31, 2006. The lease of the San Antonio office space provides for increased rents at stated amounts and intervals and an adjustment for variations in utility costs. We also lease an office in Houston, Texas. The Houston office address is 363 W. Sam Houston Parkway, Suite 490, Houston, Texas 77060. That lease terminates on August 26, 2001. We no longer have employees in Houston, and we have subleased this office space. Our annual rental expense is approximately $237,000. See "Item 1 - BUSINESS" for additional information concerning our oil and gas properties. 18 19 ITEM 3. LEGAL PROCEEDINGS From time to time, we are involved in litigation relating to claims arising out of our operations in the normal course of business. As of December 31, 2000, we were not engaged in any legal proceedings that are expected, individually or in the aggregate, to have a material adverse effect on the our financial condition or results of operations. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS An Annual Meeting of our Stockholders was held on December 12, 2000, for the following purposes: o To elect eight (8) directors to serve until the next Annual Meeting of Stockholders o To ratify amendments to our 1997 Incentive Plan of the Company to remove some of the limitations on the number and type of awards that may be granted under the Plan and to increase the number of shares of common stock that may be awarded under the Plan o To ratify the amendment to our Certificate of Incorporation to increase the number of authorized shares of common stock to 50,000,000 shares o To ratify the amendment to our Certificate of Incorporation to grant our Board of Directors the power to determine the voting rights of each share of preferred stock that may be issued o To ratify the appointment of KPMG LLP as our independent certified public accountants for the fiscal year ended December 31, 2000 All the matters were approved by the vote of our stockholders, and the results are tabulated below:
FOR AGAINST ABSTAIN OR WITHHELD ---------------------- ---------------------- --------------------- (1) Election of Directors E.L. Ames, Jr. 9,213,271 2,812 None John Y. Ames 9,213,271 2,812 None J.C. Anderson 9,213,281 2,802 None Martin A. Bell 9,213,271 2,812 None James W. Gorman 9,213,271 2,812 None Michael E. Little 9,213,281 2,802 None Jere W. McKenny 9,213,271 2,812 None John H. Pinkerton 9,213,281 2,802 None (2) Amendments to 1997 Incentive Plan 8,778,664 434,639 2,777 (3) Increase number of Authorized Shares to 50,000,000 9,190,795 24,127 1,159 (4) Amendment to Certificate of Incorporation regarding voting rights of Preferred Stock 8,597,975 21,384 3,892 (5) Ratification of KPMG LLP as auditors 9,211,329 4,088 666
19 20 PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS Our Common Stock is traded on the NASDAQ SmallCap Market(SM) under the symbol "VENX." The following table sets forth the range of high and low closing bid prices for each quarterly period during the two most recent fiscal years as reported by the NASDAQ SmallCap Market(SM). All SmallCap quotations represent inter-dealer quotations, without retail mark-up, mark-down or commission, and may not represent actual transactions.
HIGH LOW -------- --------- 2000 First Quarter $ 2.0000 $ .4375 Second Quarter 1.0625 .6562 Third Quarter 1.1875 .6250 Fourth Quarter 1.8750 .7500 1999 First Quarter $ 1.7500 $ .8125 Second Quarter 1.8750 .7500 Third Quarter 1.8750 1.1875 Fourth Quarter 1.4375 .9375
On March 19, 2001, the closing bid price for our Common Stock was $.875 per share. We had 977 stockholders of record as of March 19, 2001, (includes nominee holders such as banks and brokerage firms that hold shares for beneficial owners). We have not paid dividends in recent periods and have no present intention to resume payment of dividends. We presently intend to reinvest our net revenues in our ongoing business. Potential Dilution - As of December 31, 2000, there were 2,131,416 shares of our common stock currently issuable upon exercise of outstanding warrants or vested options. On January 23, 2001, warrants totaling 1,044,706 expired, leaving 1,086,710 shares issuable upon exercise of outstanding warrants or vested options. The exercise prices and expiration dates for all outstanding warrants and options are as follows:
NUMBER OF OPTIONS OR WARRANTS EXERCISE PRICE EXPIRATION DATE - ------------------------------ ---------------------------- -------------------------------------- 179,016 $0.6562 - $1.0470 Various times in 2001 through 2009 136,801 $1.1191 March 2009 133,554 $1.1520 December 2005 108,311 $1.2310 March 2004 20,000 $1.2500 August 2003 100,000 $1.3125 July 2004 24,526 $1.4900 March 2009 160,000 $1.5000 June 2005 20,000 $1.8750 January 2006 29,000 $2.00 - 2.1250 various times in 2007 and 2008 154,002 $3.29 - 3.7125 various times in 2004 and 2008 ---------- TOTAL - 1,086,710
The issuance of any of these shares could be considered dilutive to then-existing stockholders and could depress our stock price. In addition, the possibility that so many shares could be issued could further depress the price of our common stock. 20 21 We entered into our current credit facility with a bank effective May 5, 2000. Under terms of the credit facility, we are not permitted to declare or to pay any dividend on any of our shares or to make any distribution to our stockholders. Effective September 18, 2000, the Executive Committee of the Board of Directors approved a plan for the repurchase of up to 300,000 shares of our common stock. With the consent and approval of our lender under our credit facility, we have the authority to purchase $100,000 worth our common stock in open market transactions at prices related to the independent market for common stock, all in accordance with the terms and provisions of Rule 10b-18 ("Rule 10b-18") under the Securities and Exchange Act of 1934, as amended. Unless renewed by action of the Board of Directors, the repurchase plan, as amended, shall terminate on the earlier of the purchase of the 300,000 shares or June 15, 2001. ITEM 6. SELECTED FINANCIAL DATA The following table sets forth for the periods indicated our selected historical financial data. The selected historical financial data as of and for each of the years in the five-year period ended December 31, 2000, have been derived from our audited historical financial statements. We acquired or divested significant producing oil and gas properties in all the periods presented, with most of the activity concentrated in 1999. Those acquisitions affect the comparability of the historical financial and operating data for the periods presented. The information below should be read in conjunction with Item 7 - "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS" and our Historical Financial Statements and the notes thereto included elsewhere in this Annual Report on Form 10-K. SELECTED FINANCIAL DATA AS OF AND FOR THE FIVE-YEAR PERIOD ENDED DECEMBER 31, 2000 (IN THOUSANDS, EXCEPT PER SHARE INFORMATION)
2000 1999 1998 1997 1996 ---------- ---------- ---------- ---------- ---------- Total revenues $ 3,718 $ 2,184 $ 2,805 $ 2,476 $ 543 Dividends paid(1) -- -- -- -- 35 Income (loss) before extraordinary items (1,266) 1,010 (8,324) (4,168) (2,007) Net income (loss) (1,516) 1,010 (8,670) (4,168) (2,007) Per common share: Net income (loss) -- Basic (.13) 0.09 (0.87) (0.57) (0.60) Net income (loss) -- Diluted (.13) 0.09 (0.87) (0.57) (0.60) Long term debt -- 1,750 -- 2,005 -- Other long-term liabilities 13 18 23 27 -- Convertible redeemable preference shares -- -- -- -- 4,955 Total assets 7,117 24,465 8,136 12,931 4,343
(1) Our predecessor was a privately held S Corporation. Dividends paid in 1996 were paid by the S Corporation. Fiscal 1999 includes pre-tax gain of $4.8 million from the sale of properties. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS We were incorporated in the State of Delaware in September 1985 as Xplor Corporation. In 1997, through a reverse merger, the majority of the present management team was put into place, implementing our current exploration and development focus. After that merger and change of management, we changed our name to Venus Exploration, Inc. We are publicly traded on the Nasdaq SmallCap Market(SM) under the symbol VENX. Our management team has been responsible for the discovery, development and exploitation of relatively significant reserves of oil and gas for our privately-held predecessor companies over the last 30 years. In our current form, we are an independent oil and gas exploration and development company. We acquire producing oil and gas properties onshore in the United States and apply advanced geoscience technology to the exploration for and exploitation of undiscovered reserves. We presently have oil and gas properties, acreage and production in seven states, including Texas, Louisiana, Oklahoma and Utah. Our current focuses are: o the Expanded Yegua Trend of the Upper Texas and Louisiana Gulf Coast, and o the Cotton Valley Trend of East Texas and Western Louisiana 21 22 In 2000 we participated in drilling four wells. One of the four wells was exploratory, and the other three were development wells. Two of the development wells were completed as gas wells, one in the Constitution Field, Jefferson County, Texas, and the other in the Welburton Field, Latimer County, Oklahoma. One will be tested on pump as an oil well in the Midway-Holst Field, San Patricio County, Texas, and one was drilling at year end and completed in February 2001 as a gas well. In 2001, among others, we anticipate participating in two wells in the Texas Panhandle; one reentry and one sidetrack to develop reserves in the Yegua Formation in Wharton County, Texas; three or more wells in the Constitution Field, Jefferson County, Texas; and two wells in another Yegua Formation gas field in Jefferson County, Texas. One of the development wells, the #1 Kolander, is currently drilling in the Constitution Field and should be completed in April of this year. Because of the increased gas price, increased demand for natural gas and increased cash flows within the industry, we expect to increase generation of exploratory prospects in 2001. This prospect generation activity will primarily be accomplished by utilizing geological and geophysical data supporting prospects and leads in our database and prospect inventory. We already have oil and gas leases on some of the properties in our prospect inventory. As to the other properties in our prospect inventory, we will attempt to obtain oil and gas leases where the prospects appear promising. From time to time, we may acquire new prospects from independent geologists or other exploration and production companies. In expanding our exploration activity, we expect to continue our historical practice of selling participation to industry venturers in order to reduce our financial risk and capital requirements. Our Proved Reserves as of December 31, 2000, totaled 10.8 Bcfe, a decrease of .3 Bcfe from the 11.1 Bcfe we reported at year-end 1999, a 2.7% decrease. Production for 2000 totaled .9 Bcfe. Production was partially offset by .6 Bcfe of net new reserves added through discoveries, extensions and revisions of reserves on our existing properties. In 2000, average daily net production increased to 2,400 Mcfe/day from 2,250 Mcfe/day in 1999, a 6.7% increase. The increase was due to increased production from existing wells and the completion of a new well. During 1999, due to the significant decline in oil and natural gas prices during 1998 and our shortage of capital, we emphasized acquiring and expanding reserves in existing oil and gas fields rather than exploring for new reserves in unestablished areas. At the end of 1999 and during 2000, we began working on exploration projects again. In November 1999 we successfully restimulated our #1 Westbury Farms well in the Constitution Field, Jefferson County, Texas. In 2000, we participated in two wells in the Constitution Field in order to help define the limits of this exploratory project. During 2000, we also expanded our exploration activity in the Bossier/Cotton Valley trend in East Texas. We acquired a license to obtain 3-D seismic data covering a 100-mile area as a component of a joint venture entered into with a major oil company. We are the manager of the joint venture, and the major oil company as co-venturer retains the right to a 50% participating interest in lease acquisition and in drilling exploratory wells within this area of mutual interest ("AMI"). We currently own rights to 100% of the joint venture acreage, subject to the right of the major oil company to take 50%. Of the area to be explored, leases covering approximately 4,500 acres have been acquired. We are also acquiring leases on other prospects in the Bossier/Cotton Valley trend in East Texas. The 2001 budget provides for capital expenditures of approximately $6.2 million for projects that include the drilling and completion of 13 development wells, drilling 4 exploratory wells, 2-D and 3-D seismic acquisition for exploration projects, and acreage acquisition, all of which is subject to obtaining financing. Our share of the 4 exploration wells and the seismic acquisition is budgeted at $100,000. We anticipate that our interest in the exploration projects will be "sold down" or reduced by selling participating interests to industry co-venturers. This is done to reduce financial risk and to spread our available exploration capital over more prospects. The actual timing of the drilling of the wells is dependent upon many unpredictable factors such as the availability of capital and of drilling rigs. Any of these factors could postpone or enlarge the needed expenditures. The only contractual commitment for any of the budgeted costs is in our contract with Greywolf Drilling Company in the Constitution Field where we are in a continuous development program. However, the commitment is only for the next well after the #1 Kolander, which is currently drilling. In addition, depending on the level of success of the development wells and exploitation wells, we may drill additional wells during 2001; however, we are not able to budget such additional wells at this time. 22 23 RESULTS OF OPERATIONS YEAR ENDED DECEMBER 31, 2000, COMPARED WITH YEAR ENDED DECEMBER 31, 1999 We reported a net loss of $1.5 million for 2000 versus a net income of $1.0 million for 1999. In 1999, we reported $4.8 million pre-tax gains on the sale of oil and gas properties. Our oil and gas production was 878 Mmcfe in 2000, compared to 821 Mmcfe in 1999, an increase of 7%. Average oil prices increased from $17.54 per barrel in 1999 to $28.17 in 2000, a 61% increase. Average natural gas prices increased from $2.23 per Mcf to $4.12, an 85% increase. As a result of the increase in production and prices, oil and gas revenue increased by $1.5 million to $3.7 million in 2000 from $2.2 million in 1999. Oil and gas production costs in 2000 were $1,456,335 ($1.66 per Mcfe) compared with $1,025,947 in 1999 ($1.25 per Mcfe). The increase in total production expense of $.41 per Mcfe is due to an increase in production taxes of $.22 per Mcfe (54% of the increase), which is a result of higher prices in 2000. Well workover expense increased $.08 Mcfe (19%), and lease operating expense increased $.11 per Mcfe (27%). 2000 production or lifting cost as a percentage of oil and gas sales decreased to 39%, compared with 47% in 1999. This decrease is almost entirely due to higher oil and gas prices since lifting cost per Mcfe increased between the two periods as mentioned in the immediately preceding paragraph. During the first quarter of 1999, we sold our West Virginia properties and two producing Texas wells. Production for 1999 attributable to the properties sold totaled 18.313 Mmcfe of gas. Revenues less operating expenses of the properties sold totaled $37,047 in 1999. During 2000, we recorded no impairment expense as compared to $.5 million recorded in 1999. We review for impairment whenever circumstances indicate that the carrying value of an asset may not be recoverable. Such reviews were done for both 2000 and 1999. We follow SFAS No. 121 and recognize an impairment when the net future cash flow that is expected to be generated by a long-lived asset is less than the net carrying value of the asset. This comparison is performed on a field by field basis. If the net carrying value is greater, an impairment write down is recorded in the amount of the difference between the net carrying value and fair value. Fair value is based on estimated future discounted cash flows to be generated. Future cash flows for both the impairment test and for determining the amount of the write down are estimated using only proved reserves and our estimate of future product prices. Our current future price assumption is based on New York Mercantile Exchange ("Nymex") futures pricing of crude oil and natural gas contracts for the periods that we consider to have meaningful trading volumes. By conducting the comparison on a field by field basis we may record an impairment even though the total estimated value of all our properties is greater than their total net carrying value. Exploration expense, including geological, geophysical and seismic data acquisition and analysis and dry hole expenses of $1,159,132 in 2000 increased by $494,551 from $664,581 in 1999. The increase is due to an increase in exploration activity, (primarily with respect to our activity in the Bossier/Cotton Valley trend in East Texas), the abandonment of an exploratory prospect in Goliad County, Texas, and an increase in salaries as a result of the reinstatement of salaries that were reduced as part of our restructuring plan initiated in 1998. Depreciation, depletion, and amortization (DDA) expense of $694,743 ($0.79 per Mmcfe) in 2000 increased by $31,507 from $663,236 ($.81 per Mcfe) in 1999. Approximately $45,772 of the increase is due to the increase in sales volume, and that amount is partially offset by a decrease of $14,328, attributable to lower DDA rates. The lower DDA rates for 2000 are due to higher estimated proved reserves as a result of using higher prices in estimating proved reserves and lower net carrying value of our oil and gas properties as a result of prior year impairments. During 2000, general and administrative expense of $1,894,204 decreased $396,813 from $2,291,017 in 1999. This decrease was primarily due to various cost reduction measures implemented in late 1998 and throughout 1999. These cost reduction measures were primarily related to reductions in the number of employees. The amounts include costs of severance packages for former employees. Interest expense was $169,217 in 2000, compared to $895,602 in 1999. The $726,385 decrease is primarily due the retirement of the debt in 1999 and early 2000. During 1999 we recorded interest expense of $429,333 related to the EXCO note and $359,111 related to bank debt. Both debts were repaid in late 1999 and early 2000. Interest expense includes amortization of deferred financing cost of $72,367 in 2000 and $29,202 in 1999. The average daily balances of interest-bearing debt was $1.5 million in 2000, compared to $8.3 million in 1999. 23 24 YEAR ENDED DECEMBER 31, 1999, COMPARED WITH YEAR ENDED DECEMBER 31, 1998 We reported after tax net income of $1.0 million for 1999 versus a net loss of $8.7 million for 1998. In 1999, we reported $4.8 million pre-tax gains on the sale of oil and gas properties. Our oil and gas production was 821 Mmcfe in 1999 compared to 1,285 Mmcfe in 1998, a decrease of 36%. Approximately 37% of this decrease is due to the sale of properties during the first quarter of 1999. The balance of the decrease was due to a decline in production on existing wells. Average oil prices increased from $12.84 per barrel in 1998 to $17.54 in 1999, a 37% increase. Average natural gas prices increase from $2.15 per Mcf to $2.23, a 4% increase. As a result of the decrease in production, oil and gas revenue decreased by $0.6 million to $2.2 million in 1999 from $2.8 million in 1998. Our oil and gas production costs in 1999 were $1,025,947 ($1.25 per Mcfe) compared with $1,609,733 in 1998 ($1.25 per Mcfe). The decrease in total production expense was due primarily to the decrease in reported sales volume as a result of the sale of properties and declining production on existing wells. 1999 production or lifting cost as a percentage of oil and gas sales decreased to 47%, compared with 57% in 1998. This decrease was almost entirely due to higher oil and gas prices since lifting cost per Mcfe was virtually unchanged between the two periods as mentioned in the immediately preceding paragraph. During the first quarter of 1999, we sold our West Virginia properties and two producing Texas wells. Production for 1999 attributable to the properties sold totaled 18,313 Mcf of gas. Production for 1998 attributable to the properties sold totaled 1,566 barrels of oil and 177,830 Mcf of gas. Revenues less operating expenses of the properties sold totaled $37,047 in 1999 and $213,784 in 1998. During 1999, we recorded impairment expense of $0.5 million, as compared to $2.8 million recorded in 1998. Approximately 45% of the 1999 impairment was the result of an unexpected decline in value of one of our operated properties. The balance was due to a decline in the values of non-operated properties. The impairment in 1998 was primarily the result of the effect of significantly lower natural gas and crude oil prices in 1998. We review for impairment whenever circumstances indicate that the carrying value of an asset may not be recoverable. Such reviews were done for both 1999 and 1998. As explained above, we follow SFAS No. 121 and recognize an impairment when the net future cash flow that is expected to be generated by a long-lived asset is less than the net carrying value of the asset. Exploration expense, including geological, geophysical and seismic data acquisition and analysis and dry hole expenses of $664,581 in 1999 decreased by $596,976 from $1,261,557 in 1998. The decrease was due mainly to dry hole costs of $530,358 recorded in 1998 attributable to a well drilled in West Texas and reduced exploration activity. Depreciation, depletion, and amortization (DDA) expense of $663,236 ($0.81 per Mcfe) in 1999 decreased by $1,111,763 from $1,774,999 ($1.38 per Mcfe) in 1998. Approximately 58% of the decrease was due to the decrease in sales volume, and the balance of the decrease (42%) was attributable to lower DDA rates. The lower DDA rates for 1999 were due to higher estimated proved reserves as a result of using higher prices in estimating proved reserves and lower net carrying value of our oil and gas properties as a result of prior year impairments. During 1999, general and administrative expense of $2,291,017 decreased $883,139 from $3,174,156 in 1998. This decrease was primarily due to various cost reduction measures implemented in late 1998 and throughout 1999. These cost reduction measures were primarily related to reductions in the number of employees. The 1998 amount also included cost of severance packages for former employees. Interest expense was $895,602 in 1999, compared to $568,085 in 1998. The $327,517 increase was primarily due to interest on the EXCO convertible promissory note, which we used to finance our 50% share of the EXUS Energy properties. During 1999 we recorded interest expense of $429,333 related to the EXCO note. Offsetting this increase was the reduction in our bank facility as a result of the sale of the West Virginia properties and the H.E. White wells. We applied approximately $1.7 million of the sales proceeds to our outstanding bank debt. Interest expense includes amortization of deferred financing cost of $29,202 in 1999 and $103,260 in 1998. The average daily balances of interest-bearing debt was $8.3 million in 1999, compared to $4.8 million in 1998. 24 25 ACCOUNTING POLICIES In June 1998, the Financial Accounting Standards Board (FASB) issued Statement No 133, Accounting for Derivative Instruments and Hedging Activities (FAS 133). The Statement establishes accounting and reporting standards requiring that every derivative instrument be recorded in the balance sheet as either an asset or liability measured at fair value and that changes in fair value be recognized currently in earnings, unless specific hedge accounting criteria are met. In June 1999, the FASB issued Statement No. 137, Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement 133, which delays the required adoption of FAS 133 to fiscal 2001. We will adopt SFAS No. 133 effective January 1, 2001. Under the transition provisions of SFAS No. 133, on January 1, 2001 we will record an after-tax cumulative-effect-type adjustment to other comprehensive income of approximately $334,000 related to certain derivative instruments consisting principally of commodity collar agreements covering at least fifty percent (50%) of our monthly oil and gas production, as required by our bank lender. We have elected not to use hedge accounting for derivatives existing at January 1, 2001. Future changes in fair value of those derivatives will be recorded in income. LIQUIDITY AND CAPITAL RESOURCES At December 31, 2000, we had a working capital deficit of $2,835,202 compared with working capital deficit of $922,899 at December 31, 1999, and a decrease in working capital of $1,912,303. Working capital at year-end 2000 and year-end 1999 reflects classifying notes payable of $1,130,000 and $17,919,716 as current. In 1999 we classified the notes as current because they were required to be repaid from funds due from escrow agent and assets held for sale, both of which were classified as current assets and relate to the sale of the EXUS properties. The entire balance of those notes payable was repaid during the first quarter 2000. We believe that the higher prices we are receiving for our oil and gas, our recent successes in the Constitution Field in Jefferson County, Texas, and the Development Wells we plan to drill will contribute significantly to our ability to fund our operations. We expect that we will be able to refinance our credit facility and that the refinanced credit facility will be sufficient to provide us with the capital to drill development wells in the Constitution Field and four other fields. To the extent we are successful in our development drilling activities, our borrowing base should increase, and that should fund additional Development Wells in the more promising fields. CURRENT CREDIT FACILITY On May 5, 2000, we entered into a loan agreement with a new lender establishing a $15,000,000 revolving line of credit subject to a borrowing base that will be redetermined by the lender every six months (April 1 and October 1) based on our oil and gas reserves, which are used as security for the loan. The interest rate is the lender's base rate plus 1%. The interest rate on December 31, 2000, was 10.5%. At December 31, 2000, the entire balance of the revolving credit facility has been classified as a current liability because the agreement terminates on May 8, 2001, which is within twelve months of the balance sheet date. Although it is our intent to refinance the outstanding balance, at this point we do not yet have a commitment from a lender for such refinancing. The initial borrowing base was $2.45 million, and it declined at the rate of $50,000 per month beginning June 1, 2000. At September 30, 2000, the borrowing base was $2.25 million. On October 1, 2000, the lender redetermined the borrowing base to be $2.2 million, and it declined at the rate of $50,000 per month beginning November 1, 2000 and continued to decline at that rate until the next borrowing base redetermination on April 1, 2001, at which time, our lender determined our borrowing base to be $1,130,000. We may request interim redeterminations. Changes in the borrowing base are solely at the discretion of the lender based on the lender's then current engineering standards and are subject to the lender's credit approval process. Mandatory prepayment is required to the extent outstanding amounts under the credit facility exceed the borrowing base. As of April 2, 2001, we have no additional availability under the credit facility. We paid a facility fee of 1% of the initial borrowing base at closing. A 1/2% facility fee will be due on all incremental increases in the borrowing base, and a 3/8% per annum fee is due on the unused portion of the borrowing base. We are also required to pay a $5,000 engineering fee for the initial borrowing base determination and for each subsequent redetermination. The facility is secured by all of our oil and gas properties, and contains usual and standard covenants such as: debt and lien restrictions; dividend and distribution prohibitions; prohibits cash payments to other debt holders; liquidity, leverage, net worth and debt service coverage ratios; and financial statement reporting requirements. The credit facility also requires that we hedge at least 50% of our oil and gas production for twelve months. Although we believe that we will be able to refinance our credit facility at levels that are sufficient to fund our business plan for 2001, future availability 25 26 of credit will depend on the success of our development program and our ability to stay in compliance with credit facility debt covenants. In the event our current credit facility is not refinanced, we believe that we will be successful in obtaining alternative sources of debt or equity financing. Our current credit facility contains the following financial covenants: (1) Consolidated tangible net worth cannot be less than 85% of consolidated tangible net worth reported as of December 31, 1999, plus the sum of 70% of the Company's positive quarterly net income, and plus 100% of any increase in shareholder's equity from the sale of stock in the Company subsequent to December 31, 1999. (2) The Company will not pay or incur, or otherwise become obligated to pay general and administrative expenses which exceed $350,000 during any quarter beginning with the quarter ended September 30, 2000. Non-cash charges to general and administrative expense are excluded. (3) The Company will maintain a current ratio of at least 1:1, with initial calculation of such ratio to be made as of June 30, 2000. For purposes of computing the current ratio, current maturities under the credit facility are excluded. (4) The Company will maintain a debt service coverage ratio of at least 1.2:1.0 with the initial calculation of such ratio to be made as of September 30, 2000. Debt service coverage ratio is defined as the ratio from dividing earnings before interest, taxes, depreciation, depletion and amortization, and other non-cash charges (EBITDA) for any quarter by debt service for such quarter. The facility contains other usual and standard covenants such as: debt and lien restrictions, dividend and distribution prohibitions, and financial statement reporting requirements. At December 31, 2000 we were in default of the listed financial covenants; however, a waiver was obtained from our lender for the quarter ended December 31, 2000. HEDGING ACTIVITIES As discussed under Liquidity and Capital Resources, we obtained our current credit facility which required us to hedge approximately one-half of our production for a period of one year. On May 12, 2000, we entered into commodity collar agreements for 125 barrels of oil per day for twelve months and 500 MMBtu of gas per day for twelve months. The hedged volumes represent approximately 50% of estimated production for the twelve month period ending May 2001. The contract term is June 2000 through May 2001. The oil hedge is a costless collar with a floor of $24.00 per barrel and a cap of $27.50 per barrel. If the average NYMEX price is less than $24.00 for any month, the Company receives the difference between $24.00 and the average NYMEX price for that particular month. If the average NYMEX price is greater than $27.50 for any month, the Company pays the difference between $27.50 and the average NYMEX price for that particular month. The natural gas hedge is a costless collar with a floor of $2.90 per MMBtu and a cap of $3.65 per MMBtu. If the indexed price of natural gas is less than $2.90 per MMBtu for any month, the Company receives the difference between $2.90 and the indexed price for that particular month. If the indexed price of natural gas is greater than $3.65 per MMBtu for any month, the Company pays the difference between $3.65 and the indexed price for that particular month. The reference price for natural gas is the Houston Ship Channel index for large packages as quoted by Inside Ferc. Transaction gains and losses are determined monthly and are included in oil and gas revenues in the period the hedged production is sold. We have determined that hedge accounting will not be elected for our derivative positions existing at January 1, 2001. Future changes in the fair value of those derivatives will be recorded in income. On January 1, 2001 we will record an after-tax, cumulative-effect-type adjustment to other comprehensive income of approximately $334,000 related to these contracts. 26 27 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK We are exposed to market risk due to fluctuations in the price of natural gas and crude oil, as well as changes in interest rates. Natural gas and crude oil prices fluctuate widely in response to changing market forces, which are beyond our control. Substantially all of our revenue is from the sale of natural gas and crude oil, so these price fluctuations can have a significant effect on our revenue. During the second quarter 2000 we hedged approximately 50% of our oil and natural gas production pursuant to the requirements of our existing credit facility. On May 12, 2000 we entered into commodity collar contracts for 125 barrels of oil per day (approximately 11,250 barrels per quarter) for 12 months and 500 MMBtu per day of gas (approximately 45,000 MMBtu per quarter) for 12 months, which approximates at least 50% of estimated production from our existing wells for the 12 month period June 2000 through May 2001. The hedging arrangements have the effect of locking in the effective prices we receive for the volumes hedged. For these volumes our exposure to a significant decline in product prices is significantly reduced; however, they also limit the benefit we might have received if prices increased above the cap. For every $1 the NYMEX average for a month is above the $27.50 per barrel cap, the Company's net income would decrease by approximately $4,000 for the month. For every $0.10 per MMBtu the indexed price of natural gas is above $3.65 per MMBtu for a month, the Company's net income would decrease by approximately $2,000 for the month. While these transactions have no carrying value, their fair value, represented by the estimated amount that would be required to terminate them, was a loss of approximately $334,000 at December 31, 2000. We have determined that hedge accounting will not be elected for our derivative positions existing at January 1, 2001. Future changes in the fair value of those derivatives will be recorded in income. On January 1, 2001 we will record an after-tax, cumulative-effect-type adjustment to other comprehensive income of approximately $334,000 related to these contracts. While we are required to do so under the terms of our current credit facility, our use of these contracts has the intended impact of reducing the volatility of our oil and gas revenues. Should the price of a commodity decline, the revenue received from the sale of the product tends to decline to a corresponding extent. The decline in revenue is then partially offset based on the amount of production hedged and the hedge price. In 2000, a 10% reduction in oil and gas prices would have reduced revenue by approximately $395,000 offset by a reduction in hedging losses of approximately $44,000. Changes in product prices can also have a significant effect on the value of our oil and gas properties for purposes of determining whether an impairment write-down must be recorded. Although impairment write-downs do not affect cash flow, they do reduce our tangible net worth, which in turn affects our ability to meet the tangible net worth requirements under our existing credit facility and Nasdaq market listing requirements. Our earnings are also affected by changes in interest rates because our bank debt ($1,130,000 at December 31, 2000) is subject to a floating prime rate plus 1%. We plan to use significant levels of bank debt now and in the future to fund our capital expenditures and working capital needs. Fluctuations in these rates directly impact our interest expense. For every 1% change in the interest rate charged by the lender, our monthly net income would change inversely by approximately $1,000 based on the level of indebtedness in place on March 16, 2001; e.g., a 1% interest rate increase would decrease month net income by approximately $1,000. Historically, except when required by a lender, we have not used financial instruments such as futures contracts or interest rate swaps to mitigate the effect of changes in commodity prices or interest rates. We had no existing contracts at December 31, 1999. All of our market risk sensitive instruments were entered into for purposes other than trading. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA This information appears in a separate section of this report following Part IV. ITEM 9. CHANGES IN, AND DISAGREEMENTS WITH, ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Not applicable. 27 28 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information required by this item will be set forth under the captions "Election of Directors," "Section 16(a) Beneficial Ownership Reporting Compliance," and "Management and Remuneration" of our proxy statement for our 2001 Annual Meeting of Shareholders (the "Proxy Statement"), which will be filed with the Commission pursuant to Regulation 14A under the Exchange Act and is incorporated herein by reference. The Proxy Statement is expected to be filed prior to April 30, 2001. ITEM 11. EXECUTIVE COMPENSATION The information required by this item is set forth under the caption Executive Compensation Summary under "Management and Remuneration" of our Proxy Statement, which will be filed with the Commission pursuant to Regulation 14A under the Exchange Act and is incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information required by this item is set forth under the caption "Ownership of Securities" of our Proxy Statement, which will be filed with the Commission pursuant to Regulation 14A under the Exchange Act and is incorporated herein by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The information required by this item is set forth under the captions "Management and Remuneration" - Director Compensation and Certain Relationships and Related Party Transactions" of our Proxy Statement, which will be filed with the Commission pursuant to Regulation 14A under the Exchange Act and is incorporated herein by reference. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENTS SCHEDULES AND REPORTS ON FORM 8-K (a) The following documents are filed as part of this Annual Report on Form 10-K: 1. FINANCIAL STATEMENTS See Index to Financial Statements on page F-1 to this Annual Report on Form 10-K. 2. FINANCIAL STATEMENT SCHEDULES All schedules are omitted because the information is not required under the related instructions or is inapplicable or because the information is included in the Financial Statements or related Notes. 3. EXHIBITS *3.1 Articles of Incorporation of Venus Exploration, Inc. (incorporated by reference to Exhibit 3.1 to the Company's Annual Report on Form 10-K for the year ended December 31, 1997) *3.2 Bylaws of Venus Exploration, Inc., as amended (incorporated by reference to Exhibit 3.2 to the Company's Annual Report on Form 10-K for the year ended December 31, 1997) *4.1 Warrant to purchase Common Stock issued to Martin A. Bell (incorporated by reference to Exhibit 4.1 to the Company's Annual Report on Form 10-K for the year ended December 31, 1997) 28 29 *4.2 Form of Registration Rights Agreement between Venus Exploration, Inc. and various holders of 7% Convertible Subordinated Notes (incorporated by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q for the period ended June 30, 1999) *+4.3 Form of Salary Reduction Stock Option Agreement (incorporated by reference to Exhibit 4.1 to the Company's Quarterly Report on Form 10-Q for the period ended June 30, 1999) *+10.1 Registrant's 1985 Incentive Stock Option Plan (incorporated by reference to Exhibit 10.12 to the Company Registration Statement on Form S-4 (File No. 33-1903) declared effective January 8, 1986) *+10.2 Registrant's 1995 Incentive Stock Option Plan (incorporated by reference to Exhibit 10.1 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995) +10.3 1997 Incentive Plan, as amended and restated (filed herewith) *10.4 Letter Agreement dated February 4, 1999, between Venus Exploration, Inc., and Petroleum Development Corporation (incorporated by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K filed February 26, 1999) *10.5 Amendment to Letter Agreement dated February 11, 1999, between Venus Exploration, Inc., and Petroleum Development Corporation (incorporated by reference to Exhibit 2.2 to the Company's Current Report on Form 8-K filed February 26, 1999) *+10.6 Executive Employment Agreement dated July 1, 1999, for E.L. Ames, Jr. (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the period ended September 30, 1999) *10.7 Registration Rights Agreement dated November 30, 1998 between Venus Exploration, Inc. and Stratum Group, L.P. (incorporated by reference to Exhibit 4.4 to the Company's Registration Statement on Form S-3 (File No. 333-73457) filed March 5, 1999) *10.8 Purchase and Sale Agreement between Apache Corporation as seller, and Venus Exploration, Inc., buyer, dated May 13, 1999 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed July 15, 1999) *10.9 Credit Agreement among EXUS Energy, LLC, as borrower, NationsBank, N.A., as administrative agent, and financial institutions listed on Schedule I, dated June 30, 1999 (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K filed July 15, 1999) *10.10 Limited Liability Company Agreement of EXUS Energy, LLC, dated June 30, 1999 (incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K filed July 5, 1999) *10.11 Convertible Promissory Note made by Venus Exploration, Inc. in favor of EXCO Resources, Inc., dated June 30, 1999 (incorporated by reference to Exhibit 10.4 to the Company's Current Report on Form 8-K filed July 15, 1999) *10.12 Pledge Agreement made by Venus Exploration, Inc. for the benefit of EXCO Resources, Inc., dated June 30, 1999 (incorporated by reference to Exhibit 10.5 to the Company's Current Report on Form 8-K filed July 15, 1999) *10.13 Registration Rights Agreement between EXCO Resources, Inc. and Venus Exploration, Inc., dated June 30, 1999 (incorporated by reference to Exhibit 10.6 to the Company's Current Report on Form 8-K filed July 15, 1999) *10.14 Agreement Among Members between EXCO Resources Inc., dated June 30, 1999 (incorporated by reference to Exhibit 10.7 to the Company's Current Report on Form 8-K filed July 15, 1999) 29 30 *10.15 Purchase and Sale Agreement between Venus Exploration, Inc. as seller, and Anadarko Petroleum Corporation, as buyer, dated December 17, 1999 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed July 18, 2000) *10.16 Amendment to Purchase and Sale Agreement dated December 17, 1999, between Venus Exploration, Inc. as seller, and Anadarko Petroleum Corporation., buyer, dated December 31, 1999 (incorporated by reference to Exhibit 10.31 to the Company's Annual Report on Form 10-K for the year ended December 31, 2000) +10.17 Consulting Agreement effective October 30, 2000, between Venus Exploration, Inc. and P. Mark Stark (filed herewith) *21.1 List of Subsidiaries (incorporated by reference to Exhibit 21 to the Company's Annual Report on Form 10-K for the year ended December 31, 1997) 23.1 Consent of KPMG LLP regarding incorporation by reference (filed herewith) 23.2 Consent of Ryder Scott Company regarding incorporation by reference (filed herewith) - ---------- * Incorporated herein by reference. + Management contract or compensatory plan or arrangement. (b) Reports on Form 8-K. None. (c) Exhibits. See the list of exhibits filed as part of this Form 10-K listed under sub-item (a) 3 above. (d) No financial statement schedules are required to be filed herewith. See sub-item (a) 2 above. 30 31 SIGNATURE PAGE 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 in the City of San Antonio, Texas, on the 12th day of April, 2001. VENUS EXPLORATION, INC. By: /s/ EUGENE L. AMES, JR. -------------------------- Eugene L. Ames, Jr. Chairman of the Board of Directors and Chief Executive Officer 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.
DATE TITLE SIGNATURE April 12, 2001 Chairman of the Board of Directors /s/ EUGENE L. AMES, JR. and Chief Executive Officer ----------------------------------- Eugene L. Ames, Jr. April 12, 2001 President, Director and Chief /s/ JOHN Y. AMES Operating Officer ----------------------------------- John Y. Ames April 12, 2001 Chief Financial Officer /s/ P. MARK STARK (Principal Financial Officer) ----------------------------------- P. Mark Stark April 12, 2001 Chief Accounting Officer /s/ TERRY F. HARDEMAN (Principal Accounting Officer) ----------------------------------- Terry F. Hardeman April 12, 2001 Majority of the Directors of the /s/ MARTIN A. BELL Registrant (including Eugene L. ----------------------------------- Ames, Jr. and John Y. Ames) Martin A. Bell April 12, 2001 Majority of the Directors of the /s/ JERE W. MCKENNY Registrant (including Eugene L. ----------------------------------- Ames, Jr. and John Y. Ames) Jere W. McKenny April 12, 2001 Majority of the Directors of the /s/ J.C. ANDERSON Registrant (including Eugene L. ----------------------------------- Ames, Jr. and John Y. Ames) J.C. Anderson
31 32 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA VENUS EXPLORATION, INC. AND SUBSIDIARIES INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE Independent Auditors' Report F-2 Consolidated Balance Sheets as of December 31, 2000 and 1999 F-3 Consolidated Statements of Operations for Each of the years in the three-year period Ended December 31, 2000 F-4 Consolidated Statements of Shareholders' Equity and Comprehensive Income for each of the years in the three-year period Ended December 31, 2000 F-5 Consolidated Statements of Cash Flows for each of the Years in the three-year period ended December 31, 2000 F-6 Notes to Consolidated Financial Statements F-7
F-1 33 INDEPENDENT AUDITORS' REPORT The Board of Directors and Shareholders of Venus Exploration, Inc.: We have audited the accompanying consolidated balance sheets of Venus Exploration, Inc. and subsidiary as of December 31, 2000 and 1999, and the related consolidated statements of operations, shareholders' equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2000. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free 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 consolidated financial statements referred to above present fairly, in all material respects, the financial position of Venus Exploration, Inc. and subsidiaries as of December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States of America. KPMG LLP March 28, 2001, except as to note 16, which is as of April 10, 2001 San Antonio, Texas F-2 34 VENUS EXPLORATION, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
DECEMBER 31, ---------------------------- 2000 1999 ------------ ------------ ASSETS Current assets: Cash and equivalents $ 1,086,035 $ 235,673 Trade accounts receivable 1,034,375 717,964 Funds due from escrow agent -- 17,303,582 Assets held for sale -- 1,236,030 Prepaid expenses and other 73,461 90,177 ------------ ------------ Total current assets 2,193,871 19,583,426 Oil and gas properties and equipment, at cost under the successful efforts method, net 4,783,125 4,300,876 Other property and equipment, net 93,644 136,274 Deferred financing costs, at cost less accumulated amortization 30,813 20,380 Other assets, at cost less accumulated amortization 15,730 423,750 ------------ ------------ $ 7,117,183 $ 24,464,706 ============ ============ LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities: Trade accounts payable $ 3,435,011 $ 1,447,920 Other liabilities 464,062 1,138,689 Current notes payable 1,130,000 17,919,716 ------------ ------------ Total current liabilities 5,029,073 20,506,325 Long-term debt -- 1,750,000 Other long-term liabilities 13,085 18,131 ------------ ------------ Total liabilities 5,042,158 22,274,456 Shareholders' equity: Preferred stock; par value of $0.01; 5,000,000 shares authorized; none issued and outstanding -- -- Common stock; par value of $.01; 50,00,000 shares authorized; 12,341,065 and 11,055,285 shares issued, and 12,314,185 and 11,055,285 shares outstanding in 2000 and 1999, respectively 123,411 110,553 Additional paid-in capital 18,721,312 17,336,593 Accumulated deficit (16,710,706) (15,194,396) Less cost of treasury stock (26,880 shares) (40,242) -- Accumulated other comprehensive income - net unrealized appreciation on investment securities -- 68,750 Unearned compensation (18,750) (131,250) ------------ ------------ Total shareholders' equity 2,075,025 2,190,250 Commitments and contingencies ------------ ------------ $ 7,117,183 $ 24,464,706 ============ ============
See accompanying notes to consolidated financial statements. F-3 35 VENUS EXPLORATION, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, -------------------------------------------- 2000 1999 1998 ------------ ------------ ------------ Oil and gas revenues $ 3,718,364 $ 2,183,681 $ 2,804,749 ------------ ------------ ------------ Costs of operations: Production expense 1,456,334 1,025,947 1,609,733 Exploration expenses, including dry holes 1,159,132 664,581 1,261,557 Impairment of oil and gas properties -- 544,740 2,803,152 Depreciation, depletion and amortization 694,743 663,236 1,774,999 General and administrative 1,894,204 2,291,017 3,174,156 ------------ ------------ ------------ Total expenses 5,204,413 5,189,521 10,623,597 ------------ ------------ ------------ Operating loss (1,486,049) (3,005,840) (7,818,848) ------------ ------------ ------------ Other income (expense): Interest expense (169,217) (895,602) (568,085) Equity in net earnings from EXUS Energy, LLC -- 444,968 -- Debt conversion expense (235,451) -- -- Gain on sale of assets 598,502 4,762,170 30,007 Interest and other income 25,905 33,888 32,502 ------------ ------------ ------------ 219,739 4,345,424 (505,576) ------------ ------------ ------------ Net income (loss) before income taxes and extraordinary item (1,266,310) 1,339,584 (8,324,424) Income tax expense -- 330,000 -- ------------ ------------ ------------ Income (loss) before extraordinary item (1,266,310) 1,009,584 (8,324,424) Extraordinary loss on early extinguishment of debt (250,000) -- (345,905) ------------ ------------ ------------ Net income (loss) $ (1,516,310) $ 1,009,584 $ (8,670,329) ============ ============ ============ Basic and diluted earnings (loss) per share: Earnings (loss) before extraordinary item $ (.11) $ 0.09 $ (0.84) Extraordinary loss on early extinguishment of debt (.02) $ -- (0.03) ------------ ------------ ------------ Earnings (loss) $ (.13) $ 0.09 $ (0.87) ============ ============ ============ Common shares and equivalents outstanding: Basic 11,666,444 11,011,218 9,934,251 ============ ============ ============ Diluted 11,666,444 11,579,723 9,934,251 ============ ============ ============
See accompanying notes to consolidated financial statements. F-4 36 VENUS EXPLORATION, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY AND COMPREHENSIVE INCOME
Accumu- lated other Additional Retained Compre- Issued Common Paid-in Treasury Earnings hensive Unearned shares Stock capital Stock (deficit) Income Compensation Total ------------ --------- ------------ ---------- ------------ ----------- ------------ ----------- Balances, 9,736,815 $ 97,368 $ 15,010,189 -- $ (7,533,651) $ -- $ -- $ 7,573,906 December 31, 1997 Net loss -- -- -- -- (8,670,329) -- -- (8,670,329) Stock issued for -- -- Stratum settlement 1,100,000 11,000 1,756,500 -- -- -- -- 1,767,500 Compensation cost for stock and stock options 134,510 1,345 442,353 -- -- -- (337,500) 106,198 Earned compensation -- -- -- -- -- -- 93,750 93,750 ------------ --------- ------------ ---------- ------------ ----------- ------------ ----------- Balances, 10,971,325 109,713 17,209,042 -- (16,203,980) -- (243,750) 871,025 December 31, 1998 Net income -- -- -- -- 1,009,584 -- -- 1,009,584 Net unrealized change in investment securities -- -- -- -- -- 68,750 -- 68,750 ----------- Comprehensive income -- -- -- -- -- -- -- 1,078,334 Compensation cost for stock and stock options 62,536 626 100,644 -- -- -- -- 101,270 Interest paid with common stock 21,424 214 26,907 -- -- -- -- 27,121 Earned compensation -- -- -- -- -- -- 112,500 112,500 ------------ --------- ------------ ---------- ------------ ----------- ------------ ----------- Balances, December 31, 1999 11,055,285 110,553 17,336,593 -- (15,194,396) 68,750 (131,250) 2,190,250 Net Loss -- -- -- -- (1,516,310) -- -- (1,516,310) Net unrealized change included in net income -- -- -- -- -- (68,750) -- (68,750) ----------- Comprehensive income (loss) (1,585,060) Treasury stock - 26,880 shares purchased -- -- -- (40,242) -- -- -- (40,242) Compensation cost for stock and stock options 79,873 799 112,347 -- -- -- -- 113,146 Interest paid with common stock 63,053 630 54,920 -- -- -- -- 55,550 Convertible subordinated notes converted 1,142,854 11,429 1,217,452 -- -- -- -- 1,228,881 to common stock Earned compensation -- -- -- -- -- -- 112,500 112,500 ------------ --------- ------------ ---------- ------------ ----------- ------------ ----------- Balances, December 31, 2000 12,341,065 $ 123,411 $ 18,721,312 $ (40,242) $(16,710,706) $ -- $ (18,750) $ 2,075,025 ============ ========= ============ ========== ============ =========== ============ ===========
See accompanying notes to consolidated financial statements. F-5 37 VENUS EXPLORATION, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CASH FLOWS
YEARS ENDED DECEMBER 31, -------------------------------------------- 2000 1999 1998 ------------ ------------ ------------ Operating Activities: Net earnings (loss) $ (1,516,310) $ 1,009,584 $ (8,670,329) Adjustments to reconcile net loss to net cash used in operating activities: Depreciation, depletion and amortization of oil and gas properties 694,743 663,236 1,774,999 Other depreciation and amortization 151,181 147,388 263,985 Impairments, abandoned leases, and dry hole costs 195,864 593,470 3,350,260 Gain on sale of property and equipment (598,502) (4,762,170) (30,007) Debt and option conversion expense 228,881 -- -- Equity in net earnings of EXUS -- (444,968) -- Loss on early extinguishment of debt 250,000 -- 345,905 Compensation expense for stock and stock options 225,647 213,770 161,198 Interest expense paid with common stock 55,550 27,121 -- Deferred interest expense on EXCO note (71,556) 71,556 -- Changes in operating assets and liabilities: Trade accounts receivable (316,411) (303,269) 1,853,803 Prepaid expenses and other 986 (12,878) 27,668 Trade accounts payable 1,987,092 179,177 (1,793,957) Advances from interest owners -- -- (17,862) Other liabilities (603,071) 633,577 206,777 ------------ ------------ ------------ Net cash provided by (used in) operating activities 684,094 (1,984,406) (2,527,560) ------------ ------------ ------------ Investing Activities: Capital expenditures (1,542,891) (584,815) (3,271,352) Investment in EXUS -- (7,450,806) -- Distributions from EXUS 250,000 493,839 -- Proceeds from sales of property and equipment 19,376,964 2,641,129 160,733 ------------ ------------ ------------ Net cash provided by (used in) investing activities 18,084,073 (4,900,653) (3,110,619) ------------ ------------ ------------ Financing Activities: Net proceeds from issuance of long-term debt and notes payable 3,678,609 9,063,495 7,492,202 Principal payments on long-term debt and notes payable (21,223,371) (2,038,239) (2,355,832) Deferred financing costs (82,801) (30,356) (76,045) Proceeds from issuance of stock -- -- 21,250 Prepayment penalty on early extinguishment of debt (250,000) -- -- Purchase of treasury stock (40,242) -- -- ------------ ------------ ------------ Net cash provided by (used in) financing activities (17,917,805) 6,994,900 5,081,575 ------------ ------------ ------------ Increase (decrease) in cash and equivalents 850,362 109,841 (556,604) Cash and equivalents, beginning of year 235,673 125,832 682,436 ------------ ------------ ------------ Cash and equivalents, end of year $ 1,086,035 $ 235,673 $ 125,832 ============ ============ ============
See accompanying notes to consolidated financial statements. F-6 38 VENUS EXPLORATION, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 2000 AND 1999 (1) ORGANIZATION AND BUSINESS COMBINATION Venus Exploration, Inc. (the Company) is primarily engaged in the business of exploring for, acquiring, developing and operating onshore oil and gas properties in the United States. The Company presently has oil and gas properties, acreage and production in eight states. The Company is the result of a merger which occurred on May 21, 1997. Xplor Corporation acquired the assets of Venus in a reverse acquisition. After the transaction, the Company's name was changed from Xplor Corporation to Venus Exploration, Inc. (2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (a) Principles of Consolidation The consolidated financial statements include the financial statements of Venus Exploration, Inc. and its wholly-owned subsidiary. All significant intercompany balances and transactions have been eliminated in consolidation. (b) Cash and Equivalents The Company considers all highly liquid investments with an original maturity of three months or less when purchased and money market accounts to be cash equivalents. (c) Oil and Gas Properties The Company uses the successful efforts method of accounting for its oil and gas operations. Under this method, the costs of unproved leases and exploratory wells are initially capitalized pending the results of exploration efforts. The costs of unproved properties are assessed periodically for impairment, on a field-by-field basis, and a loss is recognized to the extent, if any, that the cost of a property has been impaired. Exploration expenses, including geological and geophysical costs, delay rentals, and dry hole costs are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but are charged to expense if and when the well is determined to be unsuccessful. As unproved properties are determined to be productive, the property acquisition costs and related exploratory drilling costs of successful wells are transferred to proved properties. Development costs of proved properties, including producing wells and related facilities and any development dry holes, are capitalized. Depletion of the costs of proved properties are provided by the unit-of-production method based upon estimates of proved oil and gas reserves on a field-by-field basis. Capitalized costs of proved properties are periodically reviewed for impairment on a field-by-field basis, and, if necessary, an impairment provision is recognized to reduce the net carrying amount of such properties to their estimated fair values generally determined on a discounted cash flow basis. In determining if an impairment is necessary, the Company estimates future cash flows based on proved reserves and its estimate of future commodity prices to determine if the carrying amount of the property is in excess of its estimated undiscounted future cash flows. The Company's current future price assumption is based on New York Mercantile Exchange ("NYMEX") futures pricing of crude oil and natural gas contracts. F-7 39 (d) Other Property and Equipment Depreciation and amortization of transportation equipment and office furniture, fixtures, equipment, and leasehold improvements are computed using the straight-line method over the respective estimated useful lives. Maintenance, repairs and renewals are charged to operations, except that renewals which extend the life of the property are capitalized. (e) Income Taxes The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for the estimated future tax effects of temporary differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax laws or rates is recognized in income in the period that includes the enactment date. (f) Revenue Recognition The Company records revenue for oil sales when the oil is sold. The Company records revenue following the entitlement method of accounting for gas imbalances. As of December 31, 2000 and 1999, there were no significant imbalances. Three customers accounted for approximately 26%, 13% and 10% of total consolidated revenues for the year ended December 31, 2000. Three customers accounted for approximately 19%, 13% and 8% of total consolidated revenues for the year ended December 31, 1999. Three customers accounted for approximately 16%, 13% and 12% of total consolidated revenues for the year ended December 31, 1998. (g) Deferred Financing Costs Deferred financing costs consist of costs associated with obtaining the Company's debt agreements, as discussed in Note 6, which are amortized over the expected term of the related borrowings. (h) Hedging Transactions As required by its bank lender, the Company enters into commodity derivative contracts for non-trading purposes as a hedging strategy to manage commodity prices associated with oil and gas sales and to reduce the impact of price fluctuations. The Company utilizes the hedge or deferral method of accounting for commodity derivative financial instruments whereby gains and losses on these hedging instruments are recognized and recorded as revenues on the statement of operations when the related natural gas or oil has been produced, purchased or delivered. As a result, gains and losses on commodity financial instruments are generally offset by similar changes in the realized prices of natural gas and crude oil. To qualify as hedging instruments, these instruments must be highly correlated to anticipated future sales such that the Company's exposure to the risks of commodity price changes is reduced. While commodity financial instruments are intended to reduce the Company's exposure to declines in the market price of natural gas and crude oil, the commodity financial instruments may also limit the Company's gain from increases in the market price of natural gas and crude oil. On May 12, 2000, the Company entered into hedge contracts for 125 barrels of oil per day for twelve months (or 45,625 barrels) and 500 mmbtu per day for twelve months (or 182,500 mmbtu). The hedge term is June 2000 through May 2001. The oil hedge is a costless collar with a floor of $24.00 per barrel and a cap of $27.50 per barrel. The natural gas hedge is a costless collar with a floor of $2.90 per mmbtu and a cap of $3.65 per mmbtu. The reference price for oil is the New York Mercantile Exchange West Texas Intermediate future contract. For natural gas the index price is the Houston Ship Channel index for large packages as quoted by Inside Ferc. As of December 31, 2000, the estimated fair value of the Company's positions was a net payable of approximately $334,000 based upon an estimate of what the Company would owe if the contracts were liquidated. F-8 40 (i) Stock-Based Compensation Financial Accounting Standards Board Statement No. 123, Accounting for Stock-Based Compensation, allows companies to adopt a fair value based method of accounting for stock-based employee compensation plans or to continue to use the intrinsic-value based method of accounting prescribed by Accounting Principles Board ("APB") Opinion No. 25, Accounting for Stock Issued to Employees. The Company has elected to continue to account for stock-based compensation under the intrinsic-value method under the provisions of APB Opinion No. 25 and related interpretations. Under this method, compensation expense is recognized for stock options when the exercise price of the options is less than the current market value of the underlying stock on the date of grant. (j) Use of Estimates The preparation of consolidated 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 consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. (k) Commitments and Contingencies Liabilities for loss contingencies arising from claims, assessments, litigation, fines, and penalties are recorded when it is probable that a liability has been incurred and that the related amount can be reasonably estimated. (l) Fair Values of Financial Instruments The Company's financial instruments consist primarily of short-term trade receivables or payables or issued debt instruments with floating interest rates for which management believes fair value approximates carrying value. (m) Concentration of Credit Risk Financial instruments which potentially subject the Company to concentrations of credit risk consist primarily of temporary cash investments and trade receivables. The Company places its temporary cash investments in U.S. Government securities and in other high quality financial instruments. The Company's customer base consists primarily of independent oil and natural gas producers and purchasers of oil and gas products. (n) Earnings (loss) per share The Company follows Statement of Financial Accounting Standards ("FAS") No. 128, "Earnings Per Share" under which basic net earnings (loss) per common share is computed by dividing net loss by the weighted average number of common shares outstanding. Diluted earnings (loss) per share is computed by assuming the issuance of common shares for all dilutive potential common shares outstanding. In 1998 and 2000 the Company reported net losses therefore basic and diluted earnings per share are not presented. In 1999 basic and diluted earnings per share were calculated as follows. F-9 41
1999 ------------ Basic earnings per share: Net income available to common shareholders (numerator) $ 1,009,584 Weighted average common shares outstanding (denominator) 11,011,218 ------------ Earnings per share $ 0.09 ============ Diluted earnings per share: Net income available to common shareholders $ 1,009,584 Interest paid to convertible note holders 44,771 ------------ Net income available to common shareholders plus assumed conversions (numerator) $ 1,054,355 ============ Weighted average common shares outstanding 11,011,218 Effect of dilutive securities: Conversion of convertible subordinated notes 556,163 Assumed exercise of dilutive stock options and warrants 19,694 Less common shares issued to pay interest (7,352) ------------ Weighted average common shares outstanding plus assumed conversions (denominator) 11,579,723 ============ Diluted earnings per share $ 0.09 ============
(o) New Accounting Pronouncement In June 1998, the Financial Accounting Standards Board (FASB) issued Statement No 133, Accounting for Derivative Instruments and Hedging Activities (FAS 133). The Statement establishes accounting and reporting standards requiring that every derivative instrument be recorded in the balance sheet as either an asset or liability measured at fair value and that changes in fair value be recognized currently in earnings, unless specific hedge accounting criteria are met. In June 1999, the FASB issued Statement No. 137, Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement 133, which delays the required adoption of FAS 133 to fiscal 2001. The Company will adopt SFAS No. 133 effective January 1, 2001. Under the transition provisions of SFAS No. 133, on January 1, 2001 the Company will record an after-tax cumulative-effect-type adjustment to other comprehensive income of approximately $334,000 related to certain derivative instruments consisting principally of commodity collar agreements covering at least fifty percent (50%) of its monthly oil and gas production. The Company has determined that hedge accounting will not be elected for derivatives existing at January 1, 2001. Future changes in fair value of those derivatives will be recorded in income. F-10 42 (3) ACQUISITIONS AND DISPOSITIONS On June 30, 1999, EXUS, owned 50% by the Company and 50% by EXCO Resources, Inc. (EXCO), completed the acquisition of certain oil and natural gas producing properties located in Jackson Parish, Louisiana (the EXUS Properties). The purchase price, after closing adjustments, was $27.6 million. EXUS funded the acquisition with $14 million drawn under a new bank credit facility it established, and $14 million of EXUS equity capital which consisted of $7 million cash contribution each by the Company and EXCO. The Company's capital was funded by a $7 million convertible promissory note in favor of EXCO dated June 30, 1999. On December 31, 1999 the Company sold its entire 50% share of the EXUS Properties. To effect the sale, EXUS distributed the EXUS Properties to Venus and EXCO, and Venus and EXCO then sold their undivided interest on December 31, 1999, resulting in a pre-tax gain of $4.7 million to the Company, of which $4.3 million was recorded in 1999 and the remaining $0.4 million was recorded in the first quarter 2000 when contingencies related to part of the properties sold were cleared. The Company recorded approximately $445,000 in equity in net earnings from EXUS during the six months it owned the investment. In addition, the Company reported approximately $360,000 in currently due interest related to the EXCO note and $72,000 in deferred interest. (4) OIL AND GAS PROPERTIES Oil and gas properties consist of the following at December 31, 2000 and 1999:
2000 1999 ------------ ----------- Proved properties $ 8,685,387 $ 8,058,806 Unproved properties 116,360 267,298 ------------ ----------- 8,801,747 8,326,104 Less accumulated depreciation, depletion and amortization (4,018,622) (4,025,228) ------------ ----------- $ 4,783,125 $ 4,300,876 ============ ===========
The impairment of oil and gas properties recognized in 1999 includes a write-down of proved properties of approximately $544,740 (none in 2000). Impairment is recognized only if the carrying amount of a property is greater than its expected future cash flows based on proved reserves and estimated future commodity prices. The amount of the impairment is based on the estimated fair value of the property. (5) OTHER PROPERTY AND EQUIPMENT Other property and equipment consists of the following at December 31, 2000 and 1999:
2000 1999 ------------ ----------- Transportation equipment $ 6,293 $ 6,293 Furniture, fixtures and office equipment 556,234 523,430 Geophysical interpretation system 118,516 118,516 ------------ ----------- 681,043 648,239 Less accumulated depreciation, depletion and amortization (587,399) (511,965) ------------ ----------- $ 93,644 $ 136,274 ============ ===========
F-11 43 (6) LONG-TERM DEBT AND NOTES PAYABLE Long-term debt consists of the following at December 31, 2000 and 1999:
2000 1999 ------------ ------------ 7% Convertible subordinated promissory notes $ -- $ 1,000,000 Subordinated debenture -- 750,000 ------------ ------------ $ -- $ 1,750,000 ============ ============
Notes payable consists of the following at December 31, 2000 and 1999:
2000 1999 ------------ ------------ Revolving credit $ 1,130,000 $ 3,819,716 EXCO Convertible Note -- 7,000,000 NationsBank, N. A. Credit Facility -- 7,100,000 ------------ ------------ $ 1,130,000 $ 17,919,716 ============ ============
7% Convertible Subordinated Promissory Notes In the second quarter of 1999, the Company completed the private placement to six investors (including one director of the Company and one person who was later appointed a director of the Company) of six unsecured convertible subordinated promissory notes (the "Subordinated Notes") totaling $1,000,000. The net proceeds to the Company were $975,000 after legal fees associated with the transaction. The Company used the proceeds to fund working capital. The interest rate on the Subordinated Notes was 7% per annum, and at the option of the Company the interest was payable in the Company's common stock. During 1999 the Company paid interest for the quarters ended June 30, 1999, and September 30, 1999, with 21,424 shares of the Company's common stock. In January 2000 the Company issued 15,731 shares in payment of the interest due for the quarter ended December 31, 1999, and the Company subsequently issued 47,322 shares in payment of the interest due for the quarters ended March 31, 2000, June 30, 2000, and September 30, 2000. The Subordinated Notes were to mature in 2004, and the noteholders had the option to convert the debt into the Company's common stock at any time, at a conversion price of $1.15 per share, the market value of the common stock on the date the terms were agreed to. On June 30, 2000, five of the six noteholders agreed to convert the original principal amount of their debt holdings, $700,000, into 799,997 shares of the Company's common stock pursuant to an offer by the Company to induce conversion. The Company offered the noteholders the opportunity, until June 30, 2000, to convert the Subordinated Notes at a conversion price of $0.875 per share. The lower conversion price of $0.875 per share resulted in 191,303 additional shares being issued than would have been issued under the original conversion price of $1.15 per share. During the quarter ended June 30, 2000, the Company recorded $167,000 in non-cash debt conversion expense related to the fair value of the 191,303 additional shares issued. The Company also incurred $7,000 of legal cost related to the debt conversion. During the quarter ended September 30, 2000, the Company extended the inducement to convert option to August 31, 2000. On August 22, 2000, the remaining noteholder elected to convert his debt holdings, $300,000, into 342,857 shares of the Company's common stock, which included 81,987 additional shares due to the reduced conversion price. The Company recorded $61,000 in non-cash debt conversion expense related to the fair value of the 81,987 additional shares issued. Subordinated Debenture During October 1999, the chief executive officer of the Company advanced the Company $750,000 in exchange for a Subordinated Debenture (the "Debenture") issued by the Company. The net proceeds to the F-12 44 Company were approximately $730,000 after legal and other costs associated with the transaction. The Company used the proceeds to fund working capital. On May 12, 2000, the Debenture was repaid in full from proceeds drawn from the new bank credit facility. Revolving Credit As of December 31, 1999, the Company had a revolving line of credit subject to a borrowing base determined by the bank based on the Company's oil and gas reserves which were used as security for the loan. The interest rate at December 31, 1999 was 9.50%. On January 6, 2000, as part of the cash settlement from the sale of the Company's interest in the EXUS Properties, $3,716,000 was used to reduce the outstanding balance under the credit facility, resulting in a outstanding loan balance of $152,000 as of January 6, 2000. On March 30, 2000, the outstanding balance under the credit facility was repaid. EXCO Convertible Note On June 30, 1999, the Company borrowed $7 million from EXCO under the terms of an $8 million convertible promissory note (the "EXCO Note") due July 1, 2004. The Company drew $7 million under the EXCO Note to fund its capital contribution to EXUS and the entire amount was repaid on January 6, 2000, from proceeds from the escrow account created on December 31, 1999, when the EXUS Energy properties were sold. There was no conversion of any part of the EXCO Note into common shares before its termination, and interest during the actual term outstanding was 10%. The EXCO Note contained a prepayment penalty provision of 3.57% of the principal prepaid for any prepayment occurring on or before July 1, 2000. On January 6, 2000, the Company paid a $250,000 prepayment penalty when it prepaid the entire $7 million outstanding balance. During the first quarter of 2000 the Company recognized an extraordinary loss for the amount of the prepayment penalty. In addition, the Company recorded a reversal of $70,000 in accrued imputed interest that did not have to be paid because of the prepayment. NationsBank, N.A. Credit Facility In connection with EXUS' acquisition of the properties in Jackson Parish, Louisiana, on June 30, 1999, EXUS entered into a credit facility with NationsBank, N.A. as administrative agent and lender. The credit facility, which was due to mature on June 30, 2002, provided for borrowings up to $50 million, subject to borrowing base limitations. The borrowing base at December 31, 1999 totaled $19.5 million, of which $14.2 million was outstanding. On December 31, 1999 EXUS distributed the credit facility and EXUS' oil and gas properties to Venus and EXCO so that Venus and EXCO could sell the properties on December 31, 1999. Venus' share of the outstanding balance under the credit facility at December 31, 1999, totaled $7.1 million and the entire balance was repaid on January 6, 2000, from proceeds from the escrow account created on December 31, 1999, when the oil and gas properties were sold. Bank One On May 5, 2000, the Company entered into a loan agreement with a new bank establishing a $15,000,000 revolving line of credit subject to a borrowing base determined every six months (March 1 and September 1) by the bank based on the Company's oil and gas reserves which are used as security for the loan. The interest rate is the bank's base rate plus 1%. The interest rate on December 31, 2000, was 10.5%. The revolving credit facility has been classified as a current liability because the agreement terminates on May 8, 2001. Although it is the Company's intent to refinance the outstanding balance, at this point the Company has not yet obtained a commitment from a lender for such refinancing. The initial borrowing base was $2.45 million and it declined at the rate of $50,000 per month beginning June 1, 2000. On October 1, 2000, the lender determined the borrowing base to be $2.2 million, and it declined at the rate of $50,000 per month beginning November 1, 2000 and will continue until the next borrowing base redetermination on April 1, 2001. The Company may request interim redeterminations. Changes in the borrowing base are solely at the discretion of the lender based on the lender's then current engineering F-13 45 standards and are subject to the lender's credit approval process. Mandatory prepayment is required to the extent outstanding amounts under the credit facility exceed the borrowing base. A facility fee of 1% of the initial borrowing base was paid at closing. A 1/2% facility fee will be due on all incremental increases in the borrowing base, and a 3/8% per annum fee is due on the unused portion of the borrowing base. The Company is also required to pay a $5,000 engineering fee for the initial borrowing base determination and for each subsequent redetermination. The facility is secured by all of the Company's oil and gas properties, and contains usual and standard covenants such as: debt and lien restrictions; dividend and distribution prohibitions; prohibits cash payments to other debtholders; liquidity, leverage, net worth and debt service coverage ratios; and financial statement reporting requirements. The credit facility also requires that the Company hedge at least 50% of its oil and gas production for twelve months. The Company is in compliance with or has obtained waiver of these covenants as of December 31, 2000. (7) INCOME TAXES No provision for federal income taxes has been recorded in the accompanying financial statements for the year ended December 31, 2000 due to the losses recorded by the Company. For the year ended December 31, 1999, no provision was recorded due to the availability of net operating loss carryforwards. The tax provision for the year ended December 31, 1999 consists solely of state income taxes due to the sale of oil and gas properties. The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2000 and 1999 are presented below:
2000 1999 ----------- ----------- Deferred tax assets: Oil and gas and other property and equipment, principally due to differences in depreciation, depletion, and amortization $ 241,000 $ 648,000 Net operating loss carryforwards 4,255,000 3,401,000 Depletion carryforwards 330,000 96,000 Other 16,000 28,000 ----------- ----------- Total gross deferred tax assets 4,842,000 4,173,000 Less valuation allowance (4,842,000) (4,173,000) ----------- ----------- Net deferred tax assets $ -- $ -- =========== ===========
The valuation allowance for deferred tax assets as of January 1, 2000 and 1999 was $4,842,000 and $4,173,000, respectively. The net change in the total valuation allowance for the years ended December 31, 2000 and 1999 was an increase of $669,000 and a decrease of $714,000, respectively. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. The net deferred tax asset at December 31, 2000 and 1999 has been offset entirely by a valuation allowance due to the uncertainty of the ultimate realization of such benefits. As of December 31, 2000, the Company has an estimated net operating loss carryforward for U.S. federal income tax purposes of approximately $11,500,000 which is available to offset future taxable income, if any. These net operating loss carryforwards expire in various years, beginning in 2013, through 2020. F-14 46 (8) SHAREHOLDERS' EQUITY The following table lists warrants outstanding at December 31, 2000 and 1999.
Warrants Outstanding --------------------------------------------------------------- Exercise Number of Expiration Date Price Warrants --------------------------------- -------- ---------- June 1, 2005 $ 1.50 50,000 January 20, 2001 $ 2.00 500,000 January 20, 2001 $ 3.00 544,706 ---------- 1,094,706 ==========
(9) RELATED PARTY TRANSACTIONS Certain officers and shareholders of the Company have working interests in certain properties operated by the Company. In addition, they participate with the Company in developing certain properties. The Company receives $2,500 per month from Venus Oil Company, which is owned by certain shareholders of the Company, for overhead reimbursement of certain administrative costs. At December 31, 2000, Venus Oil Company owed the Company $57,152 while at December 31, 1999, the Company owed Venus Oil Company $39,387. The amount due from Venus Oil Company at December 31, 2000, was paid during March, 2001. (10) STOCK OPTIONS The Company has adopted an incentive plan that authorizes the grant of awards to employees, consultants, contractors and non-employee directors. The awards to employees, consultants and contractors can be in the form of options, stock appreciation rights, stock or cash. The awards to non-employee directors are limited to grants for shares of the Company's common stock. The Company issued 79,873 shares of the Company's common stock in 2000 to non-employee directors. The plan is administered by the compensation committee of the Company's board of directors. In 1998, the Company issued 100,000 shares of restricted stock to two employees for services provided. The stock vests over three years. The Company recorded the transaction at fair market value of the stock on the date of the transaction, $337,500, and is amortizing the cost straight-line over the vesting period. At the annual shareholders meeting December 12, 2000 the Company's incentive plan was amended to set the number of shares of the Company's stock that is subject to the incentive plan at 2,000,000, less the number of shares that were subject to previous plans of the Company and that are not assumed by the current incentive plan. As of December 31, 2000, the Company had reserved 1,417,136 shares out of the 2,000,000 shares available for the incentive plan. F-15 47 In 2000 the Company granted 366,244 options at fair market value and there were 17,873 options expired or surrendered. 349,402 of the options granted in 2000 were issued under a salary reduction plan and vested by December 31, 2000. In addition to the options granted in 2000 for salary reduction, 16,842 were granted for employment and consulting incentive. They will vest April 30, 2001.
YEARS ENDED DECEMBER 31, --------------------------------------------------------------------------------------- 2000 1999 1998 --------------------------- -------------------------- -------------------------- Weighted Weighted Weighted Average Average Average Exercise Exercise Exercise Options Price Options Price Options Price ----------- ----------- ----------- ----------- ------------ --------- Options outstanding, 741,846 2.045 519,000 $ 2.534 390,000 $ 1.782 beginning of period Expired -- -- (20,000) $ 3.290 -- -- Surrendered (17,873) 3.269 (14,611) $ 2.639 (79,000) $ 1.500 Granted 366,244 1.108 257,457 $ 1.155 218,000 $ 3.486 Exercised -- -- -- -- (10,000) $ 2.125 ----------- ----------- ------------ Options outstanding, end of period 1,090,217 1.632 741,846 $ 2.045 519,000 $ 2.534 =========== =========== ============ Options exercisable, end of period 1,036,710 1.575 638,846 $ 1.693 344,500 $ 1.756 =========== =========== ============
The following summarizes information about stock options outstanding at December 31, 2000:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE --------------------------------------------------------------------------- --------------------------------- Weighted- Average Remaining Weighted- Weighted- Range of Options Contractual Average Options Average Exercise Outstanding Life Exercise Outstanding Exercise Prices at Year End (Years) Price at Year End Price ---------------------- -------------- ------------- ------------ -------------- --------------- $0.66 - $0.99 51,759 7.66 $ 0.780 51,759 $ 0.780 $1.00 - $1.49 667,291 5.97 $ 1.120 650,449 $ 1.180 $1.50 - $1.99 151,500 4.82 $ 1.790 151,500 $ 1.558 $2.00 - $2.99 32,000 6.69 $ 2.080 29,000 $ 2.078 $3.00 - $3.71 187,667 4.68 $ 3.478 154,002 $ 3.425
F-16 48 The Company applies APB No. 25 in accounting for its stock option plan, accordingly, the only compensation cost recognized for its stock options in the financial statements is the estimated value of stock options issued to consultants related to an arrangement whereby certain consultants reduced their fees in exchange for the stock options and costs associated with the conversion of some options from qualified to nonqualified. Had the Company determined compensation cost based upon the fair value at the date of grant for its stock options under SFAS No. 123, the Company's net income would have been reduced to the pro forma amounts indicated below:
2000 1999 ------------ ----------- Net income (loss): As Reported $ (1,516,310) $ 1,009,584 Pro forma (1,825,946) 684,438 Earnings (loss) per share, basic and diluted: As Reported $ (.13) $ 0.09 Pro forma (.16) 0.06
The fair value of each option grant was estimated on the date of grant using the Black-Scholes option pricing model with the following assumptions:
2000 1999 ---- ---- Expected option life (years) 3-9 4-9 Risk-free interest rate 5.17% 4.80% Volatility 71.05% 73.49% Dividend yield None None
(11) EMPLOYEE BENEFIT PLAN The Company has a Profit Sharing 401(k) Plan (the Plan). Benefits under the Plan are based on the participants vested interests in the value of their respective accounts at the time the benefits become payable as a result of retirement, separation from service, or other events. Eligible participants include all Company employees who have reached age 21 and have completed three months of service with the Company. Employees may elect to contribute a portion of their base compensation to the Plan. The Company may make matching contributions on behalf of the participants based on actual participant contributions. Employer contributions are discretionary. The Company made contributions to the Plan of $4,585, $4,613, and $12,764 for 2000, 1999, and 1998, respectively. (12) COMMITMENTS AND CONTINGENCIES The Company leases office space and certain automobiles under noncancelable operating leases. The following is a schedule of future minimum lease payments under noncancelable operating leases with initial or remaining lease terms in excess of one year as of December 31, 2000: YEARS ENDING DECEMBER 31, 2001 $ 303,301 2002 287,333 2003 12,125 ---------- Total future minimum lease payments $ 602,759 ==========
Rental expense under operating leases was $289,486, $278,856, and $335,860 for the years ended December 31, 2000, 1999, and 1998, respectively. Effective July 1, 1999, the Company entered into a noncancelable sublease agreement whereby it has subleased excess office space to a third party. The sublease expires on F-17 49 August 26, 2001, the same date the Company's primary lease expires on the same office space. Under the sublease agreement, for 2001 the Company expects to receive $12,000. (13) SUPPLEMENTAL OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (a) Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
2000 1999 1998 ---------- ---------- ---------- Property acquisition costs: Proved $ 57,796 $ 179,107 $ 189,053 Unproved 4,922 -- 130,686 Exploration costs 726,107 584,210 1,791,454 Development costs 1,668,174 421,555 2,589,804
(b) Results of Operations for Oil and Gas Producing Properties
YEARS ENDED DECEMBER 31, -------------------------------------------- 2000 1999 1998 ------------ ------------ ------------ Oil and gas revenues $ 3,718,364 $ 2,183,681 $ 2,804,749 Production expenses (1,456,334) (1,025,947) (1,609,733) Exploration expenses, including dry holes (1,159,132) (664,581) (1,261,557) Impairment of oil and gas properties -- (544,740) (2,803,152) Depreciation, depletion and amortization (694,743) (663,236) (1,774,999) ------------ ------------ ------------ Operating gain (loss) 408,155 (714,823) (4,644,692) Income tax expense -- -- -- ------------ ------------ ------------ Results of operations from producing activities $ 408,155 $ (714,823) $ (4,644,692) ============ ============ ============
F-18 50 (c) Reserve Quantity Information The following table presents the Company's estimate of its proved oil and gas reserves, all of which are located in the United States. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, the estimates are expected to change as future information becomes available. The estimates have been prepared by independent petroleum reservoir engineers, in conjunction with the Company's internal petroleum reservoir engineers.
YEARS ENDED DECEMBER 31, -------------------------------------------------------------------- 2000 1999 1998 -------------------- -------------------- -------------------- Oil Gas Oil Gas Oil Gas (mbbl) (mmcf) (mbbl) (mmcf) (mbbl) (mmcf) -------- -------- -------- -------- -------- -------- PROVED RESERVES: Beginning of the year 1,135 4,332 708 8,869 977 6,491 Revisions of previous estimates (206) 145 291 (1,834) (154) 483 Extensions, discoveries and additions 117 947 222 1,557 4 2,467 Property divestitures -- -- (2) (3,944) -- -- Production (94) (310) (84) (316) (119) (572) -------- -------- -------- -------- -------- -------- End of year 952 5,114 1,135 4,332 708 8,869 ======== ======== ======== ======== ======== ======== PROVED DEVELOPED RESERVES: Beginning of the year 762 2,151 468 6,174 634 5,337 ======== ======== ======== ======== ======== ======== End of year 554 2,485 762 2,151 468 6,174 ======== ======== ======== ======== ======== ========
(d) Standardized Measure of Discounted Future Net Cash Flows The Company's standardized measures of discounted future net cash flows and changes therein as of December 31, 2000, 1999 and 1998 are provided based on present values of future net revenues from proved oil and gas reserves estimated by independent petroleum engineers in conjunction with the Company's internal petroleum reservoir engineers in accordance with guidelines established by the Securities and Exchange Commission. These estimates were computed by applying appropriate current oil and natural gas prices to estimated future production of proved oil and gas reserves over the economic lives of the reserves and assuming continuation of existing economic conditions. Year ended 2000 calculations were made utilizing prices for oil and natural gas that existed at December 31, 2000 of $27.04 per barrel and $9.62 per Mcf, respectively. Income taxes are computed by applying the statutory federal income tax rate to the net cash inflows relating to proved oil and gas reserves less the tax bases of the properties involved and giving effect to net operating loss carryforwards, tax credits and allowances relating to such properties. The reserve volumes provided by the independent petroleum engineers are estimates only and should not be construed as exact quantities. These reserves may or may not be recovered and may increase or decrease as result of future operations of the Company and changes in market conditions. F-19 51
YEARS ENDED DECEMBER 31, (IN THOUSANDS) -------------------------------------- 2000 1999 1998 ---------- ---------- ---------- Future cash flow $ 75,493 $ 38,106 $ 24,477 Future development costs (6,050) (5,065) (2,051) Future production costs (17,504) (13,159) (7,405) ---------- ---------- ---------- Future net cash flows before income taxes 51,939 19,882 15,021 Income taxes (12,282) * * ---------- ---------- ---------- Future net cash flows after income taxes 39,657 19,882 15,021 10% annual discount (16,121) (8,462) (6,883) ---------- ---------- ---------- Standardized measure of discounted future net cash flows after income tax $ 23,536 $ 11,420 $ 8,138 ========== ========== ==========
(*) No income tax expense has been reflected as the Company had operating loss carryforwards from oil and gas operations and sufficient tax basis in oil and gas properties to offset the future net cash flows before income taxes. (e) Principal Sources of Changes in the Standardized Measure of Discounted Future Net Cash Flows
YEARS ENDED DECEMBER 31, (IN THOUSANDS) -------------------------------------- 2000 1999 1998 ---------- ---------- ---------- Standardized measure of discounted future net cash $ 11,420 $ 8,138 $ 11,397 flows, beginning of year Revisions of previous quantity estimates (3,992) (81) (2,719) Net changes in prices and production costs and other 18,129 3,391 (4,220) Changes in estimated future development costs (244) (90) 1,585 Development costs incurred during period that reduced future development costs 559 113 524 Sales of reserves in place -- (2,752) -- Extensions and discoveries 6,299 3,100 1,580 Sales of oil and gas produced during the period, net of production costs (2,488) (1,213) (1,149) Income taxes (7,289) -- -- Accretion of discount 1,142 814 1,140 ---------- ---------- ---------- Standardized measure of discounted future net cash flows, end of year $ 23,536 $ 11,420 $ 8,138 ========== ========== ==========
F-20 52 (14) QUARTERLY RESULTS OF OPERATIONS (UNAUDITED) Summarized quarterly financial data for 2000 and 1999 (in thousands, except per share data) are as follows:
FIRST SECOND THIRD FOURTH QUARTER QUARTER QUARTER QUARTER TOTAL --------- --------- --------- --------- --------- 2000 Oil and gas revenues $ 934 $ 886 $ 931 $ 967 $ 3,718 Operating profit (loss) (381) (309) (193) (603) (1,486) Net income (loss) (5) (519) (333) (659) (1,516) Earnings (loss) per share: Basic -- (.05) (.03) (.05) (.13) Diluted -- (.05) (.03) (.05) (.13) 1999 Oil and gas revenues $ 385 $ 434 $ 644 $ 721 $ 2,184 Operating profit (loss) (832) (465) (436) (1,273) (3,006) Net income (loss) (130) (575) (795) 2,510 1,010 Earnings (loss) per share: Basic (0.01) (0.05) (0.07) 0.23 0.09 Diluted (0.01) (0.05) (0.07) 0.21 0.09
The fourth quarter of 1999 includes adjustments to reflect the impairment of oil and gas properties of approximately $544,740. The sum of the quarterly earnings per share will not necessarily equal earnings per share for the entire year. (15) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION The Company paid $428,938, $392,295, and $464,825, for interest in 2000, 1999, and 1998 , respectively. The Company assigned overriding royalty interests to a lender totaling $30,605 for 1998. In addition, the Company received in 1998 overriding royalty interests valued at $96,737 and stock warrants valued at $20,000. In 1998, the Company issued 1,100,000 shares of Common Stock in exchange for outstanding long-term debt of the Company totaling $1,605,632. On December 31, 1999, EXUS distributed properties with a cost basis of $13,813,161 and notes payable of $7,100,000 to the Company. In 2000, the Company issued 1,142,854 shares of common stock in exchange for $1,000,000 of its convertible-subordinated notes. (16) LIQUIDITY The Company's assets are predominately real property rights and intellectual information that it developed regarding those properties and other geographical areas that the Company is studying for exploration and development. The market for these types of properties fluctuates and can be very small. Therefore, the Company's assets can be very illiquid and not easily converted to cash. Even if a sale can be arranged, the price may be significantly less than what the Company believes the properties are worth. That lack of liquidity can have materially adverse effects on the Company's strategic plans, normal operations and credit facilities. At December 31, 2000, the Company had a working capital deficit of $2,835,000. Additionally, the Company's existing bank loan agreement expires on May 8, 2001. Although it is the Company's intent to refinance the outstanding balance, at this point the Company has not yet obtained a commitment from a lender for such refinancing. Future availability of credit will depend on the success of the Company's development program and its ability to stay in compliance with credit facility debt covenants. Management believes that the higher prices being received for oil and gas, the recent successes in the Constitution Field in Jefferson County, Texas, and the development wells planned to be drilled will contribute significantly to the ability to fund operations. Management expects that it will be able to renew or refinance the credit facility and that credit facility will be sufficient to provide the capital to drill development wells in the Constitution Field and four other fields. To the extent the Company is successful in its development drilling F-21 53 activities, the borrowing base should increase, and that should fund additional development wells in the more promising fields. Although management believes that the Company will be able to refinance its credit facility at levels that are sufficient to fund the business plan for 2001, future availability of credit will depend on the success of the development program and the Company's ability to stay in compliance with credit facility debt covenants. In the event the current credit facility is not renewed, management believes that it will be successful in obtaining alternative sources of debt or equity financing. On April 1, 2001, the Company's lender determined its borrowing base to be $1,130,000. As of April 2, the Company had no additional availability under the credit facility. F-22 54 INDEX TO EXHIBITS
EXHIBIT NUMBER DESCRIPTION - ------- ----------- *3.1 Articles of Incorporation of Venus Exploration, Inc. (incorporated by reference to Exhibit 3.1 to the Company's Annual Report on Form 10-K for the year ended December 31, 1997) *3.2 Bylaws of Venus Exploration, Inc., as amended (incorporated by reference to Exhibit 3.2 to the Company's Annual Report on Form 10-K for the year ended December 31, 1997) *4.1 Warrant to purchase Common Stock issued to Martin A. Bell (incorporated by reference to Exhibit 4.1 to the Company's Annual Report on Form 10-K for the year ended December 31, 1997) *4.2 Form of Registration Rights Agreement between Venus Exploration, Inc. and various holders of 7% Convertible Subordinated Notes (incorporated by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q for the period ended June 30, 1999) *+4.3 Form of Salary Reduction Stock Option Agreement (incorporated by reference to Exhibit 4.1 to the Company's Quarterly Report on Form 10-Q for the period ended June 30, 1999) *+10.1 Registrant's 1985 Incentive Stock Option Plan (incorporated by reference to Exhibit 10.12 to the Company Registration Statement on Form S-4 (File No. 33-1903) declared effective January 8, 1986) *+10.2 Registrant's 1995 Incentive Stock Option Plan (incorporated by reference to Exhibit 10.1 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995) +10.3 1997 Incentive Plan, as amended and restated (filed herewith) *10.4 Letter Agreement dated February 4, 1999, between Venus Exploration, Inc., and Petroleum Development Corporation (incorporated by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K filed February 26, 1999) *10.5 Amendment to Letter Agreement dated February 11, 1999, between Venus Exploration, Inc., and Petroleum Development Corporation (incorporated by reference to Exhibit 2.2 to the Company's Current Report on Form 8-K filed February 26, 1999) *+10.6 Executive Employment Agreement dated July 1, 1999, for E.L. Ames, Jr. (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the period ended September 30, 1999) *10.7 Registration Rights Agreement dated November 30, 1998 between Venus Exploration, Inc. and Stratum Group, L.P. (incorporated by reference to Exhibit 4.4 to the Company's Registration Statement on Form S-3 (File No. 333-73457) filed March 5, 1999) *10.8 Purchase and Sale Agreement between Apache Corporation as seller, and Venus Exploration, Inc., buyer, dated May 13, 1999 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed July 15, 1999) *10.9 Credit Agreement among EXUS Energy, LLC, as borrower, NationsBank, N.A., as administrative agent, and financial institutions listed on Schedule I, dated June 30, 1999 (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K filed July 15, 1999) *10.10 Limited Liability Company Agreement of EXUS Energy, LLC, dated June 30, 1999 (incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K filed July 5, 1999)
55 *10.11 Convertible Promissory Note made by Venus Exploration, Inc. in favor of EXCO Resources, Inc., dated June 30, 1999 (incorporated by reference to Exhibit 10.4 to the Company's Current Report on Form 8-K filed July 15, 1999) *10.12 Pledge Agreement made by Venus Exploration, Inc. for the benefit of EXCO Resources, Inc., dated June 30, 1999 (incorporated by reference to Exhibit 10.5 to the Company's Current Report on Form 8-K filed July 15, 1999) *10.13 Registration Rights Agreement between EXCO Resources, Inc. and Venus Exploration, Inc., dated June 30, 1999 (incorporated by reference to Exhibit 10.6 to the Company's Current Report on Form 8-K filed July 15, 1999) *10.14 Agreement Among Members between EXCO Resources Inc., dated June 30, 1999 (incorporated by reference to Exhibit 10.7 to the Company's Current Report on Form 8-K filed July 15, 1999) *10.15 Purchase and Sale Agreement between Venus Exploration, Inc. as seller, and Anadarko Petroleum Corporation, as buyer, dated December 17, 1999 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed July 18, 2000) *10.16 Amendment to Purchase and Sale Agreement dated December 17, 1999, between Venus Exploration, Inc. as seller, and Anadarko Petroleum Corporation., buyer, dated December 31, 1999 (incorporated by reference to Exhibit 10.31 to the Company's Annual Report on Form 10-K for the year ended December 31, 2000) +10.17 Consulting Agreement effective October 30, 2000, between Venus Exploration, Inc. and P. Mark Stark (filed herewith) *21.1 List of Subsidiaries (incorporated by reference to Exhibit 21 to the Company's Annual Report on Form 10-K for the year ended December 31, 1997) 23.1 Consent of KPMG LLP regarding incorporation by reference (filed herewith) 23.2 Consent of Ryder Scott Company regarding incorporation by reference (filed herewith)
- ---------- * Incorporated herein by reference. + Management contract or compensatory plan or arrangement. EX-10.17 2 d85666ex10-17.txt CONSULTING AGREEMENT - P. MARK STARK 10/30/00 1 EXHIBIT 10.17 CONSULTING SERVICES AGREEMENT This CONSULTING AGREEMENT ("Agreement") is made and entered effective as of October 30, 2000, by and between Venus Exploration, Inc., a Delaware corporation that is referred to hereinafter as "Venus" or the "Company" and whose address is 1250 N.E. Loop 410, Suite 1000, San Antonio, Texas 78209, and P. Mark Stark, who is referred to hereinafter as "Consultant" and whose address is 7431 Dietz Elkhorn Road, Fair Oaks Ranch, Texas 78015. FOR AND IN CONSIDERATION of the mutual covenants herein contained and the mutual benefits to be gained by the performance thereof and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto hereby agree as follows: 1. TERM OF SERVICES. Venus hereby contracts for the services of Consultant, and Consultant hereby agrees to provide services described below to Venus for a six-month term beginning on October 30, 2000. 2. DUTIES AND RESPONSIBILITIES. Primarily, Consultant shall provide financial analyses and accounting services for Venus. Consultant shall report to John Y. Ames, President of Venus. Consultant shall, in the performance of services hereunder, use his best efforts to serve and to advance the interests of Venus well and faithfully. Consultant is responsible for completion of all work assigned by Venus and accepted by Consultant. The time allotted for completion will be determined by the parties when a project is assigned and accepted. 3. COMPENSATION. The compensation to be paid to Consultant under this Agreement is listed in paragraphs 3.01 and 3.02 below, and that compensation shall constitute the full consideration to be paid to Consultant for all services of whatever type to be rendered by Consultant to Venus. 3.01 As compensation for services rendered pursuant to this Agreement, Consultant shall be entitled to receive from Venus a consultant fee of $50,000 for the six-month term of this Agreement, and it is payable in twelve equal installments beginning of November 15, 2000, and thereafter on the fifteenth day and the last day of each month within the term of this Agreement, but not beyond April 30, 2001. 3.02 Subject to the terms of this Agreement, a separate Independent Contractor Award Agreement for Non-Qualified Stock Options and 2 pursuant to the 1997 Incentive Plan of Venus Exploration, Inc. (the "Plan") for its key management employees, directors and independent contractors, Venus grants to Consultant options ("Restricted Options") to buy a total of $20,000 worth of shares of its common stock based on the stock price of $1.1875 per share; i.e., the per share stock price quoted by the NASDAQ SmallCap Market for such common stock at the closing of business on October 30, 2000 ("Date of Grant"). In that regard and without limiting the provisions of the above-referenced documents, unless the Restricted Options or the underlying Common Stock is issued to Consultant in a transaction registered under applicable federal and state securities laws, Consultant represents and warrants to the Company that all Restricted Options and underlying Common Stock will be acquired by the Consultant for investment purposes for his own account only and not with any intent for resale or distribution in violation of federal or state securities laws. Unless the Restricted Options or underlying Common Stock is issued to him in a transaction registered under the applicable federal and state securities laws, all certificates issued with respect to the Restricted Options or the underlying Common Stock shall bear an appropriate restrictive investment legend. 4. CONFIDENTIAL INFORMATION. The term "Confidential Information," as used herein, shall mean and include any and all documents, knowledge, data or information (in whatever medium) known, communicated, provided or made available to Consultant, whether before or after the execution of this Agreement, that Consultant knows or reasonably should know constitute trade secrets of Venus or information belonging to third parties to whom Venus may have an obligation of confidentiality or that embody, comprise, relate to, are incorporated in or constitute "Intellectual Property" (as herein defined) in any stage of development; including, in each case, all trade secrets and other proprietary ideas, concepts, methodologies and information incorporated therein; provided, however, that Confidential Information shall not include any information or materials that are or become generally available to the public other than as a result of any breach of the provisions of this Agreement or any other agreement between Consultant and Venus (or their respective successors, assigns or affiliates). The term "Intellectual Property," as used herein, shall include any and all information or materials, in any medium, of a technical or a business nature relating to the actual or reasonably anticipated business of the Company, including, without limitation, the work product of this Agreement or the business plan of the Company. 5. CONFIDENTIALITY. Consultant acknowledges and agrees that, in his work with Venus pursuant to this Agreement, he occupies a position of trust and confidence. Venus agrees to give him access to, and to allow him to become familiar 2 3 with, Venus's Confidential Information. Consultant further acknowledges and agrees that the Confidential Information, including any and all copies thereof, constitutes trade secrets of Venus and is confidential and proprietary information of Venus and is the property of Venus in its entirety and to the exclusion of all others, including Consultant. Consultant further acknowledges and agrees that he has no right, title, interest or claim in or to any of the Confidential Information or any copies thereof. Consultant agrees to maintain the confidentiality of the Confidential Information and agrees that he will not take, or permit to be taken, any action with respect to the Confidential Information (or any portion thereof) that is inconsistent with the confidential and proprietary nature of such information. Without limiting the generality of the foregoing, Consultant agrees that he will not, directly or indirectly, without the prior specific written consent of Venus, except as specifically required in the course of his assignment: (i) communicate, divulge, transmit or otherwise disclose any Confidential Information to any person, firm, partnership, corporation or other entity, or (ii) use any Confidential Information in any manner except as specifically required in connection with the performance of services hereunder, or (iii) copy, reproduce or otherwise duplicate any Confidential Information in any fashion, in whole or in part. Consultant agrees to take any and all steps reasonably necessary to protect the confidentiality of the Confidential Information, and Consultant shall, upon termination of this Agreement, immediately return to Venus all Confidential Information in Consultant's control or possession, including, without limitation, any and all copies thereof. Consultant shall not use any knowledge or Confidential Information obtained pursuant to this Agreement to the detriment of Venus, and without limiting the rights of Venus, Venus will have a right of first refusal and prior right to buy any oil or gas prospect that Consultant or his assigns may develop or identify within three years of the termination of this Agreement or any extension hereof if any of such Confidential Information was used by Consultant in that development or identification. This Section shall survive the expiration or termination of this Agreement. 6. RESTRICTIVE COVENANT AND NONCOMPETITION. 6.01 As an independent covenant, Consultant agrees that, for a period of three (3) years commencing upon the termination of this Agreement by Consultant , by Company if Consultant is terminated for cause, or the expiration of this Agreement, Consultant will not, unless granted express written permission by the Board of Directors of Company, develop, work on or in any way advance, directly 3 4 or indirectly, as an officer, director, stockholder, employee, advisor, consultant, partner, owner, agent, representative or in any other capacity, any competitor of Company or any other third party, any oil, gas or mineral exploration or production from the prospects or prospect leads on which he worked or to which he had access to the relevant Confidential Information during his service; provided, however, that the foregoing shall not prohibit Consultant from becoming a passive shareholder owning less than five percent (5%) of the shares of a competing corporation whose shares are publicly traded. 6.02 As an independent covenant, Consultant agrees, during the term of this Agreement and, upon termination or expiration of this Agreement for any reason, for a period of eighteen (18) months thereafter, not to induce or to attempt to influence any employee or consultant of Company to terminate his or her employment with, or service to, the Company. 6.03 As an independent covenant, Consultant agrees, during the term of this Agreement and, upon termination or expiration of this Agreement for any reason, for a period of eighteen (18) months thereafter, not to solicit any investment in oil or natural gas projects by any of the entities that have invested in the Company or any its projects during the period of Consultant's service to the Company and its predecessors. 6.04 Consultant agrees that the covenants and agreements set forth in this Section 6 are made to protect the legitimate business interests of Company, including Company's interest in Confidential Information and Intellectual Property, and not to restrict his mobility or to prevent him from utilizing his skills. Consultant recognizes the necessarily national scope of the market served by Company and agrees that the restrictions set forth in this Section are reasonable. 6.05 This Section 6 shall survive the expiration or termination of this Agreement. Any period of breach of the terms of this Section 6 shall not count toward the specified time duration of the covenant, but instead that period of breach shall be added to the specified time period. 7. TERMINATION. This Agreement may be terminated by the Consultant or by Venus by that party giving thirty days (30) days written notice of termination to the other party. Such termination shall not prejudice any remedy that the terminating party may have, either at law, in equity or under this Agreement, nor shall it invalidate any rights or obligations of or to the other party hereunder, which rights and obligations shall survive the termination. In the event of the termination of this Agreement, the 4 5 Consultant shall be entitled to the compensation earned by him prior to the date of termination as provided for in this Agreement. The Consultant shall be entitled to no further compensation as of the date of termination. This Agreement may be terminated by Venus with cause at any time. If Venus does not give Consultant notice of non-renewal before April 1, 2001, the term of this Agreement shall be extended for another 6-month term. If extended, no Stock Grant shall be included in the compensation for the extended term unless and until the Compensation Committee approves of such additional compensation. 8. NO OTHER AGREEMENTS. This Agreement contains the entire agreement of the parties with respect to the matters referred to herein, and all prior agreements and understandings of the parties are revoked. This Agreement may be amended only by a written instrument executed by Venus and Consultant. VENUS EXPLORATION, INC. By: /s/ JOHN Y. AMES ----------------------------- John Y. Ames, President CONSULTANT /s/ P. MARK STARK - ------------------------------ P. MARK STARK 5 EX-23.1 3 d85666ex23-1.txt CONSENT OF KPMG LLP 1 EXHIBIT 23.1 INDEPENDENT ACCOUNTANTS' CONSENT The Board of Directors and Shareholders Venus Exploration, Inc.: We consent to incorporation by reference in the registration statement (No. 33-61193) on Form S-8 and registration statement (No. 33-73457) on Form S-3 of Venus Exploration, Inc. of our report dated March 28, 2001, except as to note 16, which is as of April 10, 2001, relating to the consolidated balance sheets of Venus Exploration, Inc. and subsidiaries as of December 31, 2000 and 1999, and the related consolidated statements of operations, shareholders' equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2000 which report appears in the December 31, 2000 annual report on Form 10-K of Venus Exploration, Inc. KPMG LLP San Antonio, Texas April 11, 2001 EX-23.2 4 d85666ex23-2.txt CONSENT OF RYDER SCOTT COMPANY 1 EXHIBIT 23.2 CONSENT OF INDEPENDENT ENGINEERS Ryder Scott Company hereby consents to the reference to us and our report entitled "Venus Exploration, Inc. Estimated Future Reserves and Income Attributable to Certain Leasehold and Royalty Interests (S.E.C. Parameters) as of December 31, 2000", in the Venus Exploration, Inc.'s (the "Company") Annual Report on Form 10-K (Form 10-K) for the fiscal year ended December 31, 2000, and the incorporation of our report by reference to the Form 10-K in the Company's (i) Registration Statement on Form S-8 (file no. 333-61193) and (ii) Registration Statement on Form S-3 (file no. 333-73457). RYDER SCOTT COMPANY, L.P. Houston, Texas April 11, 2001 -----END PRIVACY-ENHANCED MESSAGE-----