-----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, PBLZDYp9tNV9t3Pxwf6omOKD14Z363W2V0CThNoelb8IPMekvuNA+oR3BxeSZ5Cd CCa6PekVijrC6889odcA+A== 0000930661-99-000625.txt : 19990331 0000930661-99-000625.hdr.sgml : 19990331 ACCESSION NUMBER: 0000930661-99-000625 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 19981231 FILED AS OF DATE: 19990330 FILER: COMPANY DATA: COMPANY CONFORMED NAME: AVIVA PETROLEUM INC /TX/ CENTRAL INDEX KEY: 0000910659 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 751432205 STATE OF INCORPORATION: TX FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: SEC FILE NUMBER: 001-13440 FILM NUMBER: 99578568 BUSINESS ADDRESS: STREET 1: 8235 DOUGLAS AVE STREET 2: STE 400 CITY: DALLAS STATE: TX ZIP: 75225 BUSINESS PHONE: 2146913464 MAIL ADDRESS: STREET 1: 8235 DOUGLAS AVE STREET 2: STE 400 CITY: DALLAS STATE: TX ZIP: 75225 10-K405 1 ANNUAL REPORT 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 [NO FEE REQUIRED] For the fiscal year ended DECEMBER 31, 1998 ----------------- OR [_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED] For the transition period from________to________ Commission File Number 0-22258 AVIVA PETROLEUM INC. (Exact name of registrant as specified in its charter) TEXAS 75-1432205 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification Number) 8235 DOUGLAS AVENUE, 75225 SUITE 400, DALLAS, TEXAS (Zip Code) (Address of principal executive offices) (214) 691-3464 (Registrant's telephone number, including area code) Securities registered pursuant to Section 12(b) of the Act: Names of each exchange ---------------------- Title of each class on which registered ------------------- ------------------- Depositary Receipts, American Stock Exchange* each representing five shares of Common Stock, without par value Securities registered pursuant to Section 12(g) of the Act: Common Stock, without par value *The American Stock Exchange has advised the Company that it will delist the Company's Depositary Shares, each of which represents five shares of Company Common Stock, effective as of April 9, 1999. Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [_] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] The aggregate market value of voting and non-voting securities held by non- affiliates of the Registrant on February 26, 1999 was approximately $1,763,000. As of such date, the last sale price on the American Stock Exchange of a Depositary Share representing five shares of Common Stock, without par value ("Common Stock"), was U.S. $0.20, and the middle market price of Common Stock on the London Stock Exchange Limited was U.K. 5.5 pence. As of February 26, 1999, 46,700,132 shares of Registrant's Common Stock were outstanding, of which 24,354,215 shares of Common Stock were represented by Depositary Shares. DOCUMENTS INCORPORATED BY REFERENCE None. TABLE OF CONTENTS TO FORM 10-K
Page ---- Part I Important Information - Going Concern Risk............................ 1 Item 1. Business General................................................... 1 Garnet Merger............................................. 1 Current Operations........................................ 1 Risks Associated with the Company's Business.............. 2 Products, Markets and Methods of Distribution............. 3 Regulation................................................ 4 Competition............................................... 8 Employees................................................. 8 Item 2. Properties Productive Wells and Drilling Activity.................... 8 Undeveloped Acreage....................................... 9 Title to Properties....................................... 9 Federal Leases............................................ 10 Reserves and Future Net Cash Flows........................ 10 Production, Sales Prices and Costs........................ 10 Significant Properties Colombia............................................... 11 United States.......................................... 12 Papua New Guinea....................................... 13 Item 3. Legal Proceedings........................................... 14 Item 4. Submission of Matters to a Vote of Security Holders......... 14 Part II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters Price Range of Depositary Shares and Common Stock......... 15 Dividend History and Restrictions......................... 16 Item 6. Selected Financial Data..................................... 17 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Results of Operations..................................... 18 Year 2000................................................. 20 New Accounting Pronouncements............................. 21 Liquidity and Capital Resources........................... 21 Item 7A. Quantitative and Qualitative Disclosure about Market Risk... 23 Item 8. Financial Statements and Supplementary Data................. 23 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure................................... 23 Part III Item 10. Directors and Executive Officers of the Registrant Directors of the Company.................................. 24 Executive Officers of the Company......................... 24 Meetings and Committees of the Board of Directors......... 25 Compliance with Section 16(a) of the Securities Exchange Act of 1934.............................................. 25 Item 11. Executive Compensation Summary Compensation Table................................ 26 Directors' Fees........................................... 26 Option Grants During 1998................................. 26 Option Exercises During 1998 and Year End Option Values... 26
(i) TABLE OF CONTENTS TO FORM 10-K (CONTINUED)
Page ---- Compensation Committee Interlocks and Insider Participation in Compensation Decisions...................... 27 Employment Contracts......................................... 27 Compensation Committee Report on Executive Compensation...... 27 Performance Graph............................................ 28 Item 12. Security Ownership of Certain Beneficial Owners and Management Security Ownership of Certain Beneficial Owners.............. 29 Security Ownership of Management............................. 30 Item 13. Certain Relationships and Related Transactions................. 30 Part IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K....................................................... 31 Signatures............................................................... 36
(ii) PART I IMPORTANT INFORMATION GOING CONCERN RISK If the Company is unable to consummate the merger discussed herein, then, in the absence of another business transaction or debt restructuring, the Company cannot maintain compliance with or make principal payments required by its bank credit facilities and, accordingly, the lenders could declare a default, accelerate all amounts outstanding and attempt to realize upon the collateral securing the debt (which comprises substantially all the Company's assets). As a result of this uncertainty, management believes there is substantial doubt about the Company's ability to continue as a going concern. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources" and Note 2 of the Notes to Consolidated Financial Statements contained elsewhere herein. ITEM 1. BUSINESS General Aviva Petroleum Inc. (referred to collectively with its consolidated subsidiaries as the "Company"), a Texas corporation, through its subsidiaries, is engaged in the exploration for and production and development of oil and gas in Colombia, offshore in the United States, and in Papua New Guinea. The Company was incorporated in 1973 and the common stock, without par value ("Common Stock"), of the Company has been traded on the London Stock Exchange Limited (the "London Stock Exchange") since 1982. Depositary shares ("Depositary Shares"), each representing the beneficial ownership of five shares of Common Stock, have traded on the Primary List of the American Stock Exchange since May 31, 1995, and prior to that on the Emerging Company Marketplace of the American Stock Exchange since November 14, 1994. The Company's principal executive offices are located in Dallas, Texas, and the Company maintains a regional office in Bogota, Colombia. Garnet Merger On October 28, 1998, the Company acquired Garnet Resources Corporation ("Garnet") in exchange for the issuance, in the aggregate, of approximately 14 million shares of the Company's common stock. Pursuant to the Agreement and Plan of Merger dated as of June 24, 1998, an indirect, wholly owned subsidiary of the Company was merged with and into Garnet. Garnet's $15 million of 9 1/2% Convertible Subordinated Debentures were acquired and canceled, and the outstanding bank debt of Garnet and the Company was refinanced under a new $15 million credit facility. As a result of the merger, the Company has been able to effect cost savings, particularly in Colombia where each company has an interest in the same properties. Current Operations Colombia. The Company is the owner of interests in, and is engaged in -------- exploration for, and development and production of oil from, two contracts granted by Empresa Colombiana de Petroleos, the Colombian national oil company ("Ecopetrol"). The Company's Colombian activities have been carried out by the Company's wholly owned subsidiary, Neo Energy, Inc. ("Neo"), and Argosy Energy International ("Argosy"), which operates the Colombian properties and is a subsidiary of Garnet. Prior to December 31, 1998, Neo had a 45% interest and Argosy had the remaining 55% interest in the contracts. Effective December 31, 1998, the net assets of Neo were transferred into Argosy. Argosy is currently party to two contracts with Ecopetrol called Santana and Aporte Putumayo. Both contract areas are located in the Putumayo Basin of southwestern Colombia. The Company's exploration and development activities are currently concentrated in the Santana contract area. Twenty-one wells have been drilled on the Santana concession. Of thirteen exploratory wells, seven have been productive and six were dry holes. Of eight development wells, seven have been productive. Four fields have been discovered and have been declared commercial by Ecopetrol. Gross production from the Santana concession has totaled approximately 14.1 million barrels during the period from April 1992, when production commenced, through December 1998. The Aporte Putumayo block produced from 1976 until March 1995, when declining production caused the block to be unprofitable under the terms of the contract. Ecopetrol has accepted the Company's request for relinquishment, which is pending abandonment and restoration operations on certain old wells in the block. The contracts for the La Fragua concession, which adjoined Santana to the north, and the Yuruyaco concession, which adjoined Santana and La Fragua to the east, were approved by Ecopetrol in June 1992 and September 1995, respectively. The acquisition of all seismic data required under these contracts was completed. The Company determined, however, that further exploration on these concessions was not technically justified and the concessions were formally relinquished in December 1998. 1 Each concession is governed by a separate contract with Ecopetrol. Generally, the contracts cover a 28-year period and require certain exploration expenditures in the early years of the contract and, in the later years of the contract, permit exploitation of reserves that have been found. All of the contracts provide that Ecopetrol shall receive, on behalf of the Colombian Ministry of Mines, royalty payments in the amount of 20% of the gross proceeds of the oil produced pursuant to the respective contract, less certain costs of transporting the oil to the point of sale. Under each of the contracts, application must be made to Ecopetrol for a declaration of commerciality for each discovery. If Ecopetrol declares the discovery commercial, it has the right to a 50% reversionary interest in the field and is required to pay 50% of all future costs. If, alternatively, Ecopetrol declines to declare the discovery commercial, Argosy has the right to proceed with development and production at its own expense until such time as it has recovered 200% of the costs incurred, at which time Ecopetrol is entitled to back in for a 50% working interest in the field without payment or reimbursement of any historical costs. Exploration costs (as defined in the concession agreements) incurred by Argosy prior to the declaration of commerciality are recovered by means of retention by Argosy of all of the non-royalty proceeds of production from each well until costs relating to that well are recovered. United States. In the United States the Company, through its wholly owned ------------- subsidiary, Aviva America, Inc. ("AAI"), is engaged in the production of oil and gas attributable to its working interests in 17 wells located in the Gulf of Mexico offshore Louisiana, at Main Pass 41 and Breton Sound 31 fields. AAI is the operator of Breton Sound 31 field. Effective January 1, 1999, the Company relinquished operatorship of Main Pass 41 field. The Company acquired its interests in these fields through the acquisition of Charterhall Oil North America PLC in 1990. Papua New Guinea. In Papua New Guinea the Company, through its wholly owned ---------------- subsidiary, Garnet PNG Corporation ("Garnet PNG"), is engaged in the exploration for oil and gas attributable to its 2% carried working interest in Petroleum Prospecting License No. 206 ("PPL-206"). The Company acquired Garnet PNG as part of the merger with Garnet. See "-- Garnet Merger." Risks Associated with the Company's Business General. The Company's operations are subject to oil field operating hazards ------- such as fires, explosions, blowouts, cratering and oil spills, any of which can cause loss of hydrocarbons, personal injury and loss of life, and can severely damage or destroy equipment, suspend drilling operations and cause substantial damage to subsurface structures, surrounding areas or property of others. As protection against operating hazards, the Company maintains broad insurance coverage, including indemnity insurance covering well control, redrilling and cleanup and containment expenses, Outer Continental Shelf Lands Act coverage, physical damage on certain risks, employers' liability, comprehensive general liability, appropriate auto and marine liability and workers' compensation insurance. The Company believes that such insurance coverage is customary for companies engaged in similar operations, but the Company may not be fully insured against various of the foregoing risks, because such risks are either not fully insurable or the cost of insurance is prohibitive. The Company does not carry business interruption insurance because of the prohibitively high cost. The occurrence of an uninsured hazardous event could have a material adverse effect on the financial condition of the Company. Colombia. The Company has expended significant amounts of capital for the -------- acquisition, exploration and development of its Colombian properties and may expend additional capital for further exploration and development of such properties. Even if the results of such activities are favorable, further drilling at significant costs may be required to determine the extent of and to produce the recoverable reserves. Failure to fund certain capital expenditures could result in forfeiture of all or part of the Company's interests in the applicable property. For additional information on the Company's concession obligations, see "-- Current Operations," and regarding its cash requirements, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources." The Company is subject to the other risks inherent in the ownership and development of foreign properties including, without limitation, cancellation or renegotiation of contracts, royalty and tax increases, retroactive tax claims, expropriation, adverse changes in currency values, foreign exchange controls, import and export regulations, environmental controls and other laws, regulations or international developments that may adversely affect the Company's properties. The Company does not maintain political risk insurance. Exploration and development of the Company's Colombian properties are dependent upon obtaining appropriate governmental approvals and permits. See"-- Regulation." The Company's Colombian operations are also subject to price risk. See "-- Products, Markets and Methods of Distribution." 2 There are logistical problems, costs and risks in conducting oil and gas activities in remote, rugged and primitive regions in Colombia. The Company's operations are also exposed to potentially detrimental activities by the leftist guerrillas who have operated within Colombia for many years. The guerrillas in the Putumayo area, where the Company's property is located, have as recently as August 3, 1998, significantly damaged the Company's assets. Although the Company's losses were substantially recovered through insurance, there can be no assurance that such coverage will remain available or affordable. The Colombian army guards the Company's operations, however, there can be no assurance that the Company's operations will not be the target of significant guerrilla attacks in the future. United States. The Company's activities in the United States are subject to a ------------- variety of risks. The U.S. properties could, in certain circumstances, require expenditure of significant amounts of capital. Failure to fund its share of such costs could result in a diminution of value of, or under applicable operating agreements forfeiture of, the Company's interest. The Company's ability to fund such expenditures is also dependent upon the ability of the other working interest owners to fund their share of the costs. If such working interest owners fail to do so, the Company could be required to pay its proportionate share or forego further development of such properties. The Company's activities in the United States are subject to various environmental regulations and to price risk. See "-- Regulation" and "-- Products, Markets and Methods of Distribution." Information concerning the amounts of revenue, operating loss and identifiable assets attributable to each of the Company's geographic areas is set forth in Note 13 of the Notes to Consolidated Financial Statements contained elsewhere herein. Products, Markets and Methods of Distribution Colombia. The Company's oil is sold pursuant to a sales contract with -------- Ecopetrol. The contract provides for cancellation by either party with notice. In the event of cancellation by Ecopetrol, the Company may export its oil production. Ecopetrol has historically purchased the Company's production, but there can be no assurance that it will continue to do so, nor can there be any assurance of ready markets for the Colombian production if Ecopetrol does not elect to purchase the production. The Company currently produces no natural gas in Colombia. See "Item 2. Properties." During each of the three years ended December 31, 1998, the Company received the majority of its revenue from Ecopetrol. Sales to Ecopetrol accounted for $2,632,000, or 79.0% of oil and gas revenue for 1998, $7,405,000, or 76.1% of oil and gas revenue for 1997 and $9,437,000, or 68.6% of oil and gas revenue for 1996, representing the Company's entire Colombian oil revenue. If Ecopetrol were to elect not to purchase the Company's Colombian oil production, the Company believes that other purchasers could be found for such production. United States. The Company does not refine or otherwise process domestic ------------- crude oil and condensate production. The domestic oil and condensate it produces are sold to refineries and oil transmission companies at posted field prices in the area where production occurs. The Company does not have long term contracts with purchasers of its domestic oil and condensate production. The Company's domestic gas production is primarily sold under short-term arrangements at or close to spot prices. Some gas is committed to be processed through certain plants. The Company has not historically hedged any of its domestic production. During 1998, 1997 and 1996, the Company received more than 10% of its revenue from one domestic purchaser. Such revenue accounted for $479,000, or 14.4% of oil and gas revenue for 1998, $1,516,000, or 15.6% of oil and gas revenue for 1997 and $1,609,000, or 11.7% of oil and gas revenue for 1996. If this purchaser were to elect not to purchase the Company's oil and gas production, the Company believes that other purchasers could be found for such production. General. Oil and gas are the Company's only products. There is substantial ------- uncertainty as to the prices that the Company may receive for production from its existing oil and gas reserves or from oil and gas reserves, if any, which the Company may discover or purchase. It is possible that under market conditions prevailing in the future, the production and sale of oil or gas, if any, from the Company's properties in Papua New Guinea may not be commercially feasible. The availability of a ready market and the prices received for oil and gas produced depend upon numerous factors beyond the control of the Company including, without limitation, adequate transportation facilities (such as pipelines), marketing of competitive fuels, fluctuating market demand, governmental regulation and world political and economic developments. World oil and gas markets are highly volatile and shortage or surplus conditions substantially affect prices. As a result, there have been dramatic swings in both oil and gas prices in 3 recent years. From time to time there may exist a surplus of oil or natural gas supplies, the effect of which may be to reduce the amount or price of hydrocarbons that the Company may produce and sell while such surplus exists. Regulation Environmental Regulation. The Company's operations are subject to foreign, ------------------------ federal, state, and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit by operators before drilling commences; restrict the types, quantities, and concentration of various substances that can be released into the environment in connection with drilling and production activities; limit or prohibit drilling activities on certain lands lying within wilderness areas, wetlands, and other protected areas; require remedial measures to mitigate pollution from former operations, such as plugging and abandoning wells; and impose substantial liabilities for pollution resulting from the Company's operations. The regulatory burden on the oil and gas industry increases the cost of doing business and consequently affects its profitability. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, disposal, remedial, drilling, or operational requirements could have a material adverse impact on the operating costs of the Company, as well as significantly impair the Company's ability to compete with larger, more highly capitalized companies. Management believes that the Company is in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on the Company's operations, capital expenditures, and earnings. Management further believes, however, that risks of substantial costs and liabilities are inherent in oil and gas operations, and there can be no assurance that significant costs and liabilities, including administrative, civil and criminal penalties for violations of environmental laws and regulations, will not be incurred. Colombia. Any significant exploration or development of the Company's -------- Colombian concessions, such as conducting a seismic program, the drilling of an exploratory or developmental well or the construction of a pipeline, requires environmental review and the advance issuance of environmental permits by the Colombian government. In 1993, Instituto de Recursos Naturales y Ambiente ("Inderena"), the Colombian federal environmental agency, began reviewing the environmental standards and permitting processes for the oil industry in general, and in 1994 a new Ministry of the Environment was organized. In connection with its review, Inderena requested that additional environmental studies be submitted for the Company's area of operations north of the Caqueta River. See "Item 2. Properties -- Significant Properties -- Colombia -- Santana Concession." As a result of the review and requests for additional environmental studies, the Company's operations north of the Caqueta River were suspended for a period of approximately 10 months pending review and approval of additional environmental studies submitted by the Company. Since the lifting of the above referenced suspension, the Company has received subsequent permits, without substantial delay. There can be, however, no assurance that the Company will not experience future delays in obtaining necessary environmental licenses. See also "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources" and "Item 2. Properties -- Significant Properties -- Colombia." United States. The Company believes that its domestic operations are ------------- currently in substantial compliance with U.S. federal, state, and local environmental laws and regulations. Over the past year, the Company has incurred significant costs to make capital improvements, including the drilling and completion of a salt water injection well at Breton Sound 31 field and the upgrading and modification of production and water treatment facilities at Main Pass 41 field, to maintain compliance with these U.S. environmental laws or regulations. There can be no assurance that the Company will not expend additional significant amounts in the future to maintain such compliance. The Oil Pollution Act of 1990 ("OPA '90") and regulations thereunder impose a variety of requirements on "responsible parties" related to the prevention of oil spills and liability for damages resulting from such spills in waters of the United States. A "responsible party" includes the owner or operator of an onshore facility, vessel or pipeline, or the lessee or permittee of the area in which an offshore facility is located. OPA '90 assigns liability to each responsible party for oil spill removal costs and a variety of public and private damages from oil spills. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill is caused by gross negligence or willful misconduct, the spill resulted from violation of a federal safety, construction, or operating regulation, or a party fails to report a spill or to cooperate fully in the cleanup. Few defenses exist to the liability imposed under OPA '90 for oil spills. The failure to comply with these requirements or inadequate cooperation in a spill event may subject a responsible party to civil or criminal enforcement actions. Management of the Company is 4 currently unaware of any oil spills for which the Company has been designated as a responsible party under OPA '90 and that will have a material adverse impact on the Company or its operations. OPA '90 also imposes ongoing requirements on facility operators, such as the preparation of an oil spill contingency plan. The Company has such plans in place. With amendments to OPA '90 signed into law by President Clinton on October 19, 1996, OPA '90 now requires owners and operators of offshore facilities that have a worst case oil spill of more than 1,000 barrels to demonstrate financial responsibility in amounts ranging from $10 million in specified state waters to $35 million in federal outer continental shelf waters, with higher amounts of up to $150 million in certain limited circumstances where the U.S. Minerals Management Service ("MMS") believes such a level is justified by the risks posed by the quantity or quality of oil that is handled by the facility. The Company's two U.S. properties, Main Pass Block 41 field, a federal lease on the outer continental shelf ("OCS") offshore Louisiana, and Breton Sound Block 31 field, on state leases offshore Louisiana, are subject to OPA '90 as amended. On August 11, 1998, the MMS promulgated a final rule implementing these OPA '90 financial responsibility requirements. The Company believes that it currently has established adequate proof of financial responsibility for its offshore facilities. However, the Company cannot predict whether these financial responsibility requirements under the OPA '90 amendments or the final rule will result in the imposition of significant additional annual costs to the Company in the future or otherwise have a material adverse effect on the Company. The impact of financial responsibility requirements is not expected to be any more burdensome to the Company than it will be to other similarly or less capitalized owners or operators in the Gulf of Mexico. The Outer Continental Shelf Lands Act ("OCSLA") imposes a variety of requirements relating to safety and environmental protection on lessees and permittees operating on the OCS. Specific design and operational standards may apply to OCS vessels, rigs, platforms, vehicles, and structures. Violations of lease conditions or regulations issued pursuant to OCSLA can result in substantial civil and criminal penalties, as well as potential court injunctions curtailing operations and the cancellation of leases. Such enforcement liabilities can result from either governmental or private prosecution. With respect to the Federal Water Pollution Control Act, the United States Environmental Protection Agency ("EPA") issued regulations prohibiting the discharge of produced water and produced sand derived from oil and gas operations in certain coastal areas (primarily state waters) of Louisiana and Texas, effective February 8, 1995. In connection with these regulations, however, the EPA also issued an administrative order that effectively delayed compliance with the no discharge requirement for produced water until January 1, 1997. Effective August 27, 1996, the Louisiana Department of Environmental Quality ("LDEQ") officially assumed responsibility for compliance and enforcement issues for produced water as they relate to the Company's Breton Sound Block 31 facilities with the EPA operating in an oversight capacity. In connection with the issuance of these regulations by the EPA, and following various extensions granted by the LDEQ, the Company drilled and completed a saltwater injection well at the Breton Sound Block 31 facilities in October 1998. The Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered responsible for the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury, property damage and recovery of response costs allegedly caused by the hazardous substances released into the environment. The Company has not received any notification nor is it otherwise aware of circumstances indicating that it may be potentially responsible for cleanup costs under CERCLA. The federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes regulate the storage, treatment and disposal of wastes, including hazardous wastes. The EPA and various state agencies have limited the approved methods of disposal for certain hazardous and nonhazardous wastes, thereby making such disposal more costly. Furthermore, certain wastes generated by the Company's oil and natural gas operations that are currently exempt from treatment as hazardous wastes may in the future be designated as hazardous wastes and therefore be subject to more rigorous and costly operating and disposal requirements. 5 Other Regulation - Colombia. The Company's Colombian operations are regulated --------------------------- by Ecopetrol, the Ministry of Mines and Energy, and the Ministry of the Environment, among others. The review of current environmental laws, regulations and the administration and enforcement thereof, or the passage of new environmental laws or regulations in Colombia, could result in substantial costs and liabilities in the future or in delays in obtaining the necessary permits to conduct the Company's operations in that country. These operations may also be affected from time to time in varying degrees by political developments in Colombia. Such political developments could result in cancellation or significant modification of the Company's contract rights with respect to such properties, or could result in tax increases and/or retroactive tax claims being assessed against the Company. Other Regulation - United States. Domestic exploration for and production -------------------------------- and sale of oil and gas are extensively regulated at both the national and local levels. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations applicable to the oil and gas industry that are often difficult and costly to comply with and that may carry substantial penalties for failure to comply. The regulations also generally specify, among other things, the extent to which acreage may be acquired or relinquished, permits necessary for drilling of wells, spacing of wells, measures required for preventing waste of oil and gas resources and, in some cases, rates of production. The heavy and increasing regulatory burdens on the oil and gas industry increase the costs of doing business and, consequently, affect profitability. Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938 ("NGA"), the Natural Gas Policy Act of 1978 ("NGPA") and the regulations promulgated thereunder by the Federal Energy Regulatory Commission ("FERC"). In the past, the federal government has regulated the prices at which gas could be sold. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all NGA and NGPA price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993. Congress could, however, reenact price controls in the future. The Company's sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation remain subject to extensive federal and state regulation. Several major regulatory changes have been implemented by Congress and the FERC from 1985 to the present that affect the economics of natural gas production, transportation and sales. In addition, the FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies, that remain subject to the FERC's jurisdiction. These initiatives may also affect the intrastate transportation of gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation of the natural gas industry. The ultimate impact of the complex rules and regulations issued by the FERC since 1985 cannot be predicted. In addition, many aspects of these regulatory developments have not become final but are still pending judicial and FERC final decisions. The Company cannot predict what further action the FERC will take on these matters. However, some of the FERC's more recent proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. The Company does not believe that it will be affected by any action taken materially differently than other natural gas producers, gatherers and marketers with which it competes. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue. A portion of the Company's operations are located on federal oil and gas leases, which are administered by the MMS. Such leases are issued through competitive bidding, contain relatively standardized terms and require compliance with detailed MMS regulations and orders pursuant to the OCSLA (which are subject to change by the MMS). For offshore operations, lessees must obtain MMS approval for exploration plans and development and production plans prior to the commencement of such operations. In addition to permits required from other agencies, lessees must obtain a permit from the MMS prior to commencement of drilling. The MMS has promulgated regulations requiring offshore production facilities located on the OCS to meet stringent engineering and construction specifications. The MMS also has regulations restricting the flaring or venting of natural gas and has recently proposed to amend such regulations to prohibit the flaring of liquid hydrocarbons and oil without prior authorization. Similarly, the MMS has promulgated other regulations governing the plugging and abandonment of wells located offshore and the removal of all production facilities. To cover the various obligations of lessees on the OCS, the MMS generally requires that lessees post substantial bonds or other acceptable assurances that such obligations will be met. The cost of such bonds or other surety can be substantial and there is no assurance that bonds or other surety 6 can be obtained in all cases. Under certain circumstances, the MMS may require Company operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect the Company's financial condition and operations. The MMS has issued a notice of proposed rulemaking in which it proposes to amend its regulations governing the calculation of royalties and the valuation of crude oil produced from federal leases. This proposed rule would modify the valuation procedures for both arm's length and non-arm's length crude oil transactions to decrease reliance on oil posted prices and assign a value to crude oil that better reflects its market value, establish a new MMS form for collecting differential data, and amend the valuation procedure for the sale of federal royalty oil. The Company cannot predict what action the MMS will take on this matter, nor can it predict how the Company will be affected by any change to this regulation. The MMS has recently approved its intention to issue a proposed rule that would require all but the smallest producers to be capable of reporting production information electronically. The MMS recently implemented a final rule that describes the types of transportation components that are deductible for calculating and reporting royalties, as well as various cost components associated with marketing functions that are not deductible. In particular, under the rule, the MMS will not allow deduction of costs associated with marketer fees, cash out and other gas pipeline imbalance penalties, or long-term storage fees. The Company cannot predict at this time how it might be affected by implementation of the new rule. Finally, the MMS is conducting an inquiry (not specifically directed at the Company) into certain contractual agreements from which producers on MMS leases have received settlement proceeds that are royalty bearing and the extent to which producers have paid the appropriate royalties on those proceeds. The Company believes that this inquiry will not have a material adverse impact on its financial condition, liquidity or results of operations. Sales of crude oil, condensate and gas liquids by the Company are not currently regulated and are made at market prices. Effective as of January 1, 1995, the FERC implemented regulations establishing an indexing system for transportation rates for oil that could increase the cost of transporting oil to the purchaser. The Company is not able to predict what effect, if any, this order will have on it, but other factors being equal, it may tend to increase transportation costs or reduce wellhead prices for crude oil. The Company cannot accurately predict the effect that any of the aforementioned orders or the challenges to the orders will have on the Company's operations. Additional proposals and proceedings that might affect the oil and natural gas industries are pending before Congress, the FERC and the courts. The Company cannot accurately predict when or whether any such proposals or proceedings may become effective. State Regulation. Production of any domestic oil and gas by the Company is ---------------- affected by state regulations. Many states in which the Company has operated have statutory provisions regulating the production and sale of oil and gas, including provisions regarding deliverability. Such statutes, and the regulations promulgated in connection therewith, are generally intended to prevent waste of oil and gas and to protect correlative rights to produce oil and gas between owners of a common reservoir. Such regulations include requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells, and the disposal of fluids used in connection with operations. The Company's operations are also subject to various conservation laws and regulations including the regulation of the size of drilling and spacing units or proration units, the density of wells that may be drilled, and the unitization or pooling of oil and gas properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability of production. The effect of these regulations may limit the amount of oil and natural gas that the Company can produce from its wells and may limit the number of wells or the locations at which the Company can drill. Inasmuch as such laws and regulations are periodically expanded, amended and reinterpreted, the Company is unable to predict the future cost or impact of complying with such regulations; however, the Company does not believe it will be affected by these laws and regulations materially differently than the other oil and natural gas producers with which it competes. Other Regulations Papua New Guinea. The Company's operations in Papua New ---------------------------------- Guinea are currently governed by the Department of Mining and Petroleum, which has jurisdiction over all petroleum exploration in that country. In the event the Company develops and operates a petroleum business in Papua New Guinea, the Company 7 will be subject to regulation by the Investment Promotion Authority, which regulates almost all business operations with significant foreign equity or with foreign management control. Competition The Company encounters strong competition from other independent operators and from major oil companies in acquiring properties suitable for exploration, in contracting for drilling equipment and in securing trained personnel. Many of these competitors have financial and other resources substantially greater than those available to the Company. The Company's ability to discover reserves in the future depends on its ability to select, generate and acquire suitable prospects for future exploration. The Company does not currently generate its own prospects and depends exclusively upon external sources for the generation of oil and gas prospects. Employees As of December 31, 1998, Aviva had 65 full-time employees including 7 in the United States and 58 in Colombia. ITEM 2. PROPERTIES Productive Wells and Drilling Activity The following table summarizes the Company's developed acreage and productive wells at December 31, 1998. "Gross" refers to the total acres or wells in which the Company has a working interest, and "net" refers to gross acres or wells multiplied by the percentage working interest owned by the Company. Developed Acreage (1) Gross Net ----- ----- United States 3,880 1,565 Colombia(2) 3,706 1,296 ----- ----- 7,586 2,861 ===== ===== Productive Wells (3) Oil Gas ------------- ------------- Gross Net Gross Net ----- ----- ----- ----- United States (4) 10 5.29 7 2.87 Colombia 14 4.90 - - -- ----- ----- ----- 24 10.19 7 2.87 == ===== ===== ===== (1) Developed acreage is acreage assignable to productive wells. (2) Excludes Aporte Putumayo acreage pending relinquishment. (3) Productive wells represent producing wells and wells capable of producing. (4) Two of the oil wells and one of the gas wells are dually completed. 8 During the periods indicated, the Company drilled or participated in the drilling of the following development and exploratory wells. Net Wells Drilled ----------------- Development Exploratory ----------------------- ---------------- Productive Dry Productive Dry ----------- ---- ---------- --- 1998 United States - - - - Colombia - - - - ----------- ---- ---------- --- Total - - - - =========== ==== ========== === 1997 United States - - - - Colombia 0.5 - - - ----------- ---- ---------- --- Total 0.5 - - - =========== ==== ========== === 1996 United States 0.4 - - - Colombia 0.3 - - 0.3 ----------- ---- ---------- --- Total 0.7 - - 0.3 =========== ==== ========== === In the above table, a productive well is an exploratory or development well that is not a dry well. A dry well is an exploratory or a development well found to be incapable of producing either oil or gas in commercial quantities. A development well is a well drilled within the proved area of an oil and gas reservoir to the depth of a stratigraphic horizon known to be productive. An exploratory well is any well that is not a development well. Undeveloped Acreage The Company's undeveloped acreage in Colombia is held pursuant to the Santana contract with the Colombian government. The Company relinquished all undeveloped acreage associated with the La Fragua and Yuruyaco contracts in December 1998. No further relinquishments are required for the Santana contract until the expiration of the contract in 2015. See "-- Significant Properties." The Company's undeveloped acreage in Papua New Guinea is held pursuant to PPL- 206. See "-- Significant Properties." The Company does not have an undeveloped acreage position in the United States because of the costs of maintaining such a position. Oil and gas leases in the United States generally can be acquired by the Company for specific prospects on reasonable terms either directly or through farmout arrangements. The following table shows the undeveloped acreage held by the Company at December 31, 1998. Undeveloped acreage is 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. Undeveloped Acres ------------------ Gross Net --------- ------ Colombia 48,636 48,636 Papua New Guinea 1,228,187 24,564 --------- ------ 1,276,823 73,200 ========= ====== Title to Properties The Company has not performed a title examination for offshore U.S. leases in federal waters because title emanates from the United States government. Title examinations also are not performed in Colombia, where mineral title emanates from the national government. The Company believes that it generally has satisfactory title to all of its oil and gas properties. The Company's working interests are subject to customary royalty and overriding royalty 9 interests generally created in connection with their acquisition, liens incident to operating agreements, liens for current taxes and other burdens and minor liens, encumbrances, easements and restrictions. The Company believes that none of such burdens materially detracts from the value of such properties or its interest therein or will materially interfere with the use of the properties in the operation of the Company's business. Federal Leases The Company conducts a portion of its operations on federal oil and gas leases and therefore must comply with numerous additional regulatory restrictions, including certain nondiscrimination statutes. Certain of the Company's operations on federal leases must be conducted pursuant to appropriate permits or approvals issued by various federal agencies. Pursuant to certain federal leases, approval of certain operations must be obtained from one or more government agencies prior to the commencement of such operation. Federal leases are subject to extensive regulation. See "Item 1. Business -- Regulation." Reserves and Future Net Cash Flows See Supplementary Information Related to Oil and Gas Producing Activities in "Item 8. Financial Statements and Supplementary Data" for information with respect to the Company's reserves and future net cash flows. The Company will file with the Department of Energy (the "DOE") a statement with respect to the Company's estimate of proved oil and gas reserves as of December 31, 1998, that is not the same as that included in the estimate of proved oil and gas reserves as of December 31, 1998, as set forth in "Item 8. Financial Statements and Supplementary Data" elsewhere herein. The information filed with the DOE includes the estimated proved reserves of the properties of which the Company is the operator, whereas the estimated proved reserves contained in Item 8 hereof include only the Company's percentage share of the estimated proved reserves of all properties in which the Company has an interest. Production, Sales Prices and Costs The following table summarizes the Company's oil production in thousands of barrels and natural gas production in millions of cubic feet for the years indicated: Year ended December 31, ----------------------- 1998 1997 1996 ------ ------ ------- Oil (1) United States 44 76 94 Colombia 255 426 476 Gas United States 68 316 1,146 Colombia - - - (1) Includes crude oil and condensate. 10 The average sales price per barrel of oil and per thousand cubic feet ("MCF") of gas produced by the Company and the average production (lifting) cost per dollar of oil and gas revenue and per barrel of oil equivalent (6 MCF: 1 barrel) were as follows for the years indicated:
Year ended December 31, (1) --------------------------- 1998 1997 1996 ------ ------ ------ Average sales price per barrel of oil (2) United States $12.03 $19.17 $20.68 Colombia $10.31 $17.39 $19.82 Average sales price per MCF of gas United States $ 2.42 $ 2.73 $ 2.07 Colombia $ - $ - $ - Average production cost per dollar of oil and gas revenue United States $ 1.80 $ 0.54 $ 0.45 Colombia $ 0.86 $ 0.40 $ 0.31 Average production cost per barrel of oil equivalent United States $22.54 $ 9.81 $ 6.76 Colombia $ 8.88 $ 6.98 $ 6.11
(1) All amounts are stated in United States dollars. (2) Includes crude oil and condensate. Significant Properties Colombia. -------- The Company's Colombian properties currently consist of two contracts, both of which are located in the Putumayo Basin in southwestern Colombia along the eastern front of the eastern cordillera of the Andes Mountains. The Company's interest in each of the contracts is subject to certain reversionary interests in favor of Ecopetrol as described below. Argosy, as operator of the properties, carries out the program of operations for the two concessions. The program is determined by Argosy and approved by Ecopetrol. The Santana contract, which now consists of approximately 52,000 acres and contains 14 producing wells, has been in effect since 1987 and is the focus of the Company's exploration and development activities. The Aporte Putumayo contract, which consists of approximately 77,000 acres and contains three shut-in wells, has been in effect since 1972. The Company has filed with Ecopetrol an application for formal relinquishment of the Aporte Putumayo contract. Such formal relinquishment is expected to occur during 1999. Production from the Santana concession is sold pursuant to a sales contract with Ecopetrol. The contract provides that 25% of the sales proceeds will be paid in Colombian pesos. As a result of certain currency restrictions, pesos resulting from these payments must generally remain in Colombia and are used by the Company to pay local expenses. The Company's pretax income from Colombian sources, as defined under Colombian law, is subject to Colombian income taxes at a statutory rate of 35%, although a "presumptive" minimum income tax based on net assets, as defined under Colombian law, may apply in years of little or no net income. The Company's income after Colombian income taxes is subject to a Colombian remittance tax that accrues at a rate of 7% (10% prior to 1998). Payment of the remittance tax may be deferred under certain circumstances if the Company reinvests such income in Colombia. See Note 9 of the Notes to Consolidated Financial Statements contained elsewhere herein. The Colombian government also imposed a production tax which was equal to 7% of the oil price in effect through December 1997. The production tax was, however, eliminated for 1998 and thereafter. Santana Contract. The Santana block is held pursuant to a "risk-sharing" ---------------- contract for which Ecopetrol has the option to participate on the basis of a 30% working interest in exploration activities in the contract area. If a commercial field is discovered, Ecopetrol's working interest increases to 50% and the costs theretofore incurred and attributable to the 20% working interest differential will be recouped by the Company from Ecopetrol's share of 11 production on a well by well basis. The risk-sharing contract provides that, when 7 million barrels of cumulative production from the concession have been attained, Ecopetrol's revenue interest and share of operating costs increases to 65% but it remains obligated for only 50% of capital expenditures. In June 1996, the 7 million barrel threshold was reached. At that time, Argosy and Neo's aggregate revenue interest in the contract declined from 40% to 28% and their share of operating expenses declined from 50% to 35%. The Santana concession is divided by the Caqueta River. Two fields located south of the river, the Toroyaco and Linda fields, were declared commercial by Ecopetrol and commenced production in 1992. There are currently four producing wells in the Toroyaco field and four producing wells in the Linda field. During 1995, a 3-D seismic survey covering the Toroyaco and Linda fields was completed. Based on this survey, one development well was drilled in each field during 1996 and one additional development well was drilled in the Linda field in 1997. No further drilling is anticipated for these fields. The Company constructed a 42-kilometer pipeline (the "Uchupayaco Pipeline") which was completed and commenced operations during 1994 to transport oil production from the Toroyaco and Linda fields to the Trans-Andean Pipeline owned by Ecopetrol, through which the Company's production is transported to the port of Tumaco on the Pacific coast of Colombia. Two additional fields, the Mary and Miraflor fields, were discovered north of the Caqueta River and were declared commercial by Ecopetrol during 1993. Except for oil produced during production tests of wells located in these fields, the production was shut-in until the first quarter of 1995 when construction of a pipeline was completed and commercial production began. Completion of this pipeline provided the Company with direct pipeline access from all of its fields to the Pacific coast port of Tumaco. There are currently four producing wells in the Mary field and one producing well in the Miraflor field. A 3-D seismic survey was completed over the Mary and Miraflor fields during early 1997. This survey confirms the presence of several prospects and leads previously identified from two-dimensional seismic data. The most promising prospect, Mary West, appears to be an extension of the Mary field. The drilling of an exploratory well on this prospect has been deferred pending environmental permits and appropriate financing. The survey also confirmed that additional development drilling is not required for the Miraflor field. The Company has fulfilled all the exploration obligations required by the Santana risk-sharing contract. The Company's current work program contemplates the recompletion of certain existing wells to increase production therefrom. The Santana contract has a term of 28 years and expires in 2015. In 1993, the Company relinquished 50% of the original Santana area in accordance with the terms of the contract. In July 1995, an additional 25% of the original contract area was relinquished. A final relinquishment was made in 1997 such that all remaining contract areas except for those areas within five kilometers of a commercial field were relinquished. Under the terms of a contract with Ecopetrol, all oil produced from the Santana contract area is sold to Ecopetrol. If Ecopetrol exports the oil, the price paid is the export price received by Ecopetrol, adjusted for quality differences, less a commercialization fee of $0.165 per barrel. If Ecopetrol does not export the oil, the price paid is based on the price received from Ecopetrol's Cartagena refinery, adjusted for quality differences, less Ecopetrol's cost to transport the crude to Cartagena and a commercialization fee of $0.165 per barrel. In 1998, Ecopetrol exported the crude each month and the sales price averaged $10.31 per barrel. Aporte Putumayo Contract. The discoveries on the Aporte Putumayo contract ------------------------ were not declared commercial by Ecopetrol and the properties were operated by Argosy and Neo without participation by Ecopetrol. There are no remaining exploration obligations under this contract. Ecopetrol has accepted the Company's request for relinquishment, which is pending abandonment and restoration operations. United States. ------------- The Company's oil and gas properties in the United States are located in the Gulf of Mexico offshore Louisiana at Main Pass 41 and Breton Sound 31 fields. The Breton Sound 31 field is operated by the Company. The Company relinquished operatorship of the Main Pass 41 field effective January 1, 1999. 12 Main Pass Block 41 is a federal lease located approximately 25 miles east of Venice, Louisiana, in 50 feet of water. There are currently five productive wells in the field. The field's 1998 production averaged 30 barrels of oil per day and 119 MCF per day, net to the Company's interest, from six completions in four sands between 6,000 and 7,500 feet. The Company owns a 35% interest in this field. Breton Sound Block 31 is located 20 miles offshore Louisiana in 16 feet of water. The field is approximately 55 miles southeast of New Orleans on state leases. During 1998, six wells averaged 92 barrels of oil per day and 49 MCF of gas per day, net to the Company's interest, from three sands completed between 3,850 feet and 6,500 feet. The Company's interests in the leases comprising the field vary from 41% to 67%. The interpretation of 3-D seismic data in 1996 identified two deep and several shallow prospects in the Breton Sound Block 31 field. The Company is continuing its efforts to secure an industry partner to farm-in to the Company's acreage by drilling one or more exploratory wells that would test the deep prospects. As for the shallow prospects, the Company anticipates that it will drill at least one exploratory well, following consummation of the proposed merger with Sharpe Resources Corporation. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources". Papua New Guinea. ---------------- The area covered by PPL-206 is located in the Western, Gulf and Southern Highland Provinces of Papua New Guinea. The northern section of the area is in a mountainous tropical rain forest while the southern section of the area is predominantly lowlands, jungle and coastal swamps. In 1986 oil was discovered approximately 20 kilometers from the northern border of PPL-206 in an adjoining license area and in 1999 gas was discovered approximately 20 kilometers southwest of the western border. According to the terms of the agreement governing PPL-206, the parties agreed to perform surface geological work and complete a seismic program during late 1997 and early 1998. These activities have been completed and a decision regarding the drilling of an exploratory well in late 1999 will be made following the final evaluations of the geological work and seismic program. The Company is not obligated to pay any of the costs relative to the work presently underway. Should the parties decide to drill an exploratory well, the Company will have no obligation to pay its share of the drilling, testing and completion costs of this well pursuant to its 2% carried working interest. Under the provisions of PPL-206 the terms of any oil and gas development are set forth in a Petroleum Agreement with the Government of Papua New Guinea. The Petroleum Agreement provides that the operator must carry out an appraisal program after a discovery to determine whether the discovery is of commercial interest. If the appraisal is not carried out or the discovery is not of commercial interest, the license may be forfeited. If the discovery is of commercial interest, the operator must apply for a Petroleum Development License. The Government retains a royalty on production equal to 1.25% of the wellhead value of the petroleum and, at its election, may acquire up to a 22.5% interest in the petroleum development after recoupment by the operator of the project costs attributable thereto out of production. In addition, income from petroleum operations is subject to a Petroleum Income Tax at the rate of 50% of net income, which is defined as gross revenue less royalties, allowances for depreciation, interest deductions, operating costs and previous tax losses carried forward. An Additional Profits Tax of 50% of cash flow (after deducting ordinary income tax payments) is also payable when the accumulated value of net cash flows becomes positive. For annual periods in which net cash flows are negative, the cumulative amount is carried forward and increased at an annual accumulation of 27%. The Additional Profits Tax is calculated separately for each Petroleum Development License. In calculating the applicable tax, interest expenses paid by Garnet PNG prior to the issuance of a Petroleum Development License and, thereafter, to the extent that Garnet PNG's debt to equity ratio exceeds two-to-one, are not deductible. The Company leases corporate office space in Dallas, Texas containing approximately 5,100 square feet pursuant to a lease which expires in January 2002. The annual lease payments for these offices are approximately $102,000. 13 ITEM 3. LEGAL PROCEEDINGS There are no legal proceedings to which the Company is a party or to which its properties are subject which are, in the opinion of management, likely to have a material adverse effect on the Company's results of operations or financial condition. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS The Special Meeting in lieu of the 1998 Annual Meeting of Shareholders of Aviva Petroleum Inc. was held on October 20, 1998, pursuant to notice, at which the following persons were elected directors of the Company to serve until the next annual meeting of the shareholders or until their successors are elected and qualify: For Against Abstain ---------- ------- ------- Ronald Suttill 24,333,447 26,323 14,334 Eugene C. Fiedorek 24,339,712 19,738 14,654 In addition the following proposals were approved by the shareholders: The issuance of common stock of the Company pursuant to the Agreement and Plan of Merger dated as of June 24, 1998, providing for the merger of an indirect, wholly owned subsidiary of the Company with and into Garnet Resources Corporation was passed with 20,633,550 votes in favor, 14,675 votes against, 23,545 votes abstaining and 3,702,334 broker non-votes. The re-appointment of KPMG LLP as independent auditors of the Company for fiscal year 1998 was passed with 24,346,043 votes in favor, 13,656 votes against and 14,405 votes abstaining. The text of the above proposals is incorporated by reference to Aviva's Proxy Statement for the Special Meeting in lieu of the 1998 Annual Meeting of Shareholders dated October 20, 1998, filed with the Securities and Exchange Commission ("SEC") on Form S-4. 14 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS. Price Range of Depositary Shares and Common Stock The Company's Depositary Shares, each representing the beneficial ownership of five shares of Common Stock, have traded on the Primary List of the American Stock Exchange since May 31, 1995 and prior to that on the Emerging Company Marketplace of the American Stock Exchange since November 14, 1994 (collectively the "ASE"). In addition, the Company's Common Stock has been traded on the London Stock Exchange since 1982 and has been quoted in the National Quotation Bureau's Daily Quotation Sheets (known as the "pink sheets") since December 1993. In August 1998, the ASE notified the Company that it had initiated a review of Aviva's listing eligibility in light of the Company's continued net losses and financial difficulties. On October 27, 1998, the Company was informed by the ASE of its intention to delist Aviva's Depositary Shares. The Company appealed this decision, however on March 25, 1999, the ASE advised the Company that it will delist the Company's Depositary Shares effective as of April 9, 1999. When the Depositary Shares cease to be listed on the ASE, the Depositary Shares will become subject to Rule 15g-9 under the Exchange Act. This Rule (the "Penny Stock Rule") imposes additional sales practice requirements on broker-dealers that sell such securities to persons other than established customers and "accredited investors" (generally, individuals with a net worth in excess of $1,000,000 or annual incomes exceeding $200,000, or $300,000 together with their spouses). For transactions covered by Rule 15g-9, a broker-dealer must make a special suitability determination for the purchaser and have received the purchaser's written consent to the transaction prior to the sale. Consequently, such rule may affect the ability of the broker-dealer to sell the Company's securities and may affect the ability of purchasers to sell any of the Company's securities in the secondary market. During 1998, an aggregate of 2,751,000 Depositary Shares were traded on the ASE. The following table sets forth, for the periods indicated and subject to the following qualifications, the high and low prices for the Depositary Shares on the ASE and the high and low prices for the Common Stock on the London Stock Exchange. In the United Kingdom, the average daily trading volume of the Common Stock on the London Stock Exchange during 1998 was approximately 11,000 shares. The London Stock Exchange prices indicated in the table are the middle market prices for the Common Stock as published in the Daily Official List and do not represent actual transactions. Prices on the London Stock Exchange are expressed in British pounds sterling, and, accordingly, the prices for the Common Stock traded on the London Stock Exchange included in the following table are similarly expressed. For ease of reference, these prices are also expressed in U.S. dollars, having been converted using the exchange rate in effect on the first day on which the stock price attained the high or low price indicated. 15
1998 1997 1996 ---------------------- ---------------------- ----------------------- High Low High Low High Low ---- --- ----- --- ---- --- ASE - --- Depositary Shares (1) - --------------------- First Quarter $1.75 $1.00 $4.13 $2.88 $ 4.38 $3.88 Second Quarter $1.19 $0.69 $3.00 $1.63 $11.38 $3.50 Third Quarter $1.00 $0.13 $4.13 $1.63 $ 6.25 $3.00 Fourth Quarter $0.31 $0.06 $2.06 $0.98 $ 5.75 $3.00 London Stock Exchange - --------------------- Common Stock - ------------ First Quarter (Pounds) (Pounds)0.28 (Pounds)0.12 (Pounds)0.42 (Pounds)0.28 (Pounds)0.46 (Pounds)0.34 US$ $0.45 $0.20 $0.69 $0.45 $ 0.71 $0.52 Second Quarter (Pounds) (Pounds)0.14 (Pounds)0.10 (Pounds)0.32 (Pounds)0.27 (Pounds)0.41 (Pounds)0.25 US$ $0.22 $0.16 $0.51 $0.44 $ 0.63 $0.38 Third Quarter (Pounds) (Pounds)0.10 (Pounds)0.05 (Pounds)0.30 (Pounds)0.21 (Pounds)0.34 (Pounds)0.25 US$ $0.17 $0.08 $0.50 $0.34 $ 0.53 $0.38 Fourth Quarter (Pounds) (Pounds)0.06 (Pounds)0.04 (Pounds)0.25 (Pounds)0.17 (Pounds)0.41 (Pounds)0.28 US$ $0.10 $0.07 $0.40 $0.28 $ 0.67 $0.43
(1) Representing five shares of Common Stock. As of February 26, 1999, the Company had approximately 5,800 shareholders of record, including nominees for an undetermined number of beneficial holders. Dividend History and Restrictions No dividends have been paid since June 1983, nor is there any current intention on the part of the directors of the Company to pay dividends in the future. Furthermore, in October 1998, the Company entered into a restated credit agreement pursuant to which the Company is prohibited from paying dividends. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources." 16 ITEM 6. SELECTED FINANCIAL DATA The following table summarizes certain selected financial data with respect to the Company for, and as of the end of, each of the five years ended December 31, 1998, which should be read in conjunction with the Consolidated Financial Statements included elsewhere herein.
For the Years Ended December 31, ------------------------------------------------------- 1998 1997 1996 1995 1994 ------- -------- ------- ------- --------- (in thousands, except per share, per barrel and per MCF data) For the period Revenues $ 3,332 $ 9,726 $13,750 $10,928 $ 8,546 Loss before extraordinary item $(16,881) $(22,482) $ (937) $(2,689) $(2,460) Extraordinary item - debt extinguishment $ (197) $ - $ - $ - $ - Net loss $(17,078) $(22,482) $ (937) $(2,689) $(2,460) Loss before extraordinary item per common share $ (0.49) $ (0.71) $ (0.03) $ (0.09) $ (0.08) Basic and diluted net loss per common share $ (0.50) $ (0.71) $ (0.03) $ (0.09) $ (0.08) Weighted average shares outstanding 34,279 31,483 31,483 31,483 31,483 Cash dividends per common share $ - $ - $ - $ - $ - Total annual net oil production (barrels) Colombia 255 426 476 435 250 United States 44 76 94 106 99 -------- -------- ------- ------- ------- Total 299 502 570 541 349 -------- -------- ------- ------- ------- Total annual net gas production (MCF) United States 68 316 1,146 1,184 1,839 Average price per barrel of oil Colombia $ 10.31 $ 17.39 $ 19.82 $ 16.39 $ 13.60 United States $ 12.03 $ 19.17 $ 20.68 $ 16.78 $ 15.40 Average price per MCF of Gas - United States $ 2.42 $ 2.73 $ 2.07 $ 1.70 $ 1.97 At period end Total assets $ 11,422 $ 16,445 $42,944 $45,460 $42,383 Long term debt, including current portion $ 14,805 $ 7,690 $ 7,990 $13,067 $ 6,640 Stockholders' equity (deficit) $(11,083) $ 3,748 $26,230 $27,167 $29,856
In connection with the application of the full cost method, the Company recorded ceiling test write-downs of oil and gas properties of $12,343,000 in 1998 and $19,953,000 in 1997 (see Note 1 of Notes to Consolidated Financial Statements). 17 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. The following discussion and analysis should be read in conjunction with the Consolidated Financial Statements included elsewhere herein. Results of Operations 1998 versus 1997 - ---------------- United States Colombia Oil Gas Oil Total ------ ----- ------- -------- (Thousands) Revenue - 1997 $1,459 $ 862 $ 7,405 $ 9,726 Volume variance (606) (572) (3,613) (4,791) Price variance (318) (74) (1,427) (1,819) Garnet revenue - - 267 267 Other - (51) - (51) ------ ----- ------- ------- Revenue - 1998 $ 535 $ 165 $ 2,632 $ 3,332 ====== ===== ======= ======= Colombian oil volumes were 255,000 barrels in 1998, a decrease of 171,000 barrels from 1997. Such decrease is due to a 185,000 barrel decrease resulting from production declines and a 23,000 barrel decrease due to lost production caused by guerilla attacks in August that damaged oil processing and storage facilities and caused production from various wells to be shut-in for periods ranging from 6 to 57 days, partially offset by a 37,000 barrel increase due to the acquisition of Garnet effective October 28, 1998. U.S. oil volumes were 44,000 barrels in 1998, down approximately 32,000 barrels from 1997. Of such decrease, approximately 9,000 barrels was due to the Company's Breton Sound 31 field being shut-in during the months of September and October and a portion of November due to the drilling and completion of a saltwater disposal well and adverse weather, approximately 15,000 barrels was due to the Company's Main Pass 41 field being shut-in for approximately 187 days during 1998 due to upgrading and modification of production and water treatment facilities and adverse weather, and 8,000 barrels resulted from normal production declines. U.S. gas volumes before gas balancing adjustments were 54,000 MCF in 1998, down 219,000 MCF from 1997. Of such decrease, approximately 119,000 MCF was due to the aforementioned shut-in of the Main Pass 41 field and 38,000 MCF was due to the suspension of production of one of the wells at Main Pass 41 from January 9 to August 27, 1998. The remaining 62,000 MCF was due to production declines. Colombian oil prices averaged $10.31 per barrel during 1998. The average price for the same period of 1997 was $17.39 per barrel. The Company's average U.S. oil price decreased to $12.03 per barrel in 1998, down from $19.17 per barrel in 1997. In 1998 prices have been lower than in 1997 due to a dramatic decrease in world oil prices. U.S. gas prices averaged $2.42 per MCF in 1998 compared to $2.73 per MCF in 1997. In addition to the above-mentioned variances, U.S. gas revenue decreased approximately $51,000 as a result of gas balancing adjustments. Operating costs decreased approximately 17%, or $710,000, primarily due to lower operating costs in Colombia. Such decreases have resulted mainly from the elimination of the production tax on the majority of the Company's Colombian production and lower pipeline tariffs resulting from lower volumes. Depreciation, depletion and amortization ("DD&A") decreased by 48%, or $2,915,000, primarily due to a decrease in costs subject to amortization resulting from property write-downs and lower levels of production. 18 The Company recorded write-downs of $10,556,000 and $1,787,000 to the carrying amounts of its Colombian and U.S. oil and gas properties, respectively, as a result of ceiling test limitations on capitalized costs during 1998. General and administrative ("G&A") expenses declined $436,000 mainly due to a $159,000 decrease in legal fees, a $127,000 decrease in directors' fees and expenses, and a $191,000 reduction in payroll. These savings were partially offset by lower amounts of capitalized G & A. In December 1998 the Company recorded a $420,000 provision for doubtful accounts receivable due from joint-venture partners. Interest and other income increased $923,000 from 1997 as the Company realized a $720,000 gain on the settlement of litigation involving the administration of a take or pay contract settlement. Income taxes were $89,000 higher in 1998 principally as a result of Colombian deferred tax benefits recorded in the second quarter of 1997, partially offset by lower presumptive income taxes in 1998. The deferred tax benefits in 1997 resulted from the write-down of the carrying amount of the Company's Colombian oil properties. 1997 versus 1996 - ---------------- United States Colombia Oil Gas Oil Total ------ ------- ------- -------- (Thousands) Revenue - 1996 $1,940 $ 2,373 $ 9,437 $13,750 Volume variance (366) (1,782) (995) (3,143) Price variance (115) 223 (1,037) (929) Other - 48 - 48 ------ ------- ------- ------- Revenue - 1997 $1,459 $ 862 $ 7,405 $ 9,726 ====== ======= ======= ======= Colombian oil volumes were 426,000 barrels in 1997, a decrease of 50,000 barrels from 1996. Such decrease resulted from a 68,000 barrel decrease due to the Company's net revenue interest declining from 18% to 12.6% in June 1996 when cumulative production from the Santana concession reached the 7 million barrel threshold specified in the risk-sharing contract, and a 119,000 barrel decrease resulting from normal production declines, partially offset by a 136,000 barrel increase primarily due to the completion of two development wells in the latter part of 1996 and one development well completed in June 1997. U.S. oil volumes were 76,000 barrels in 1997, down 18,000 barrels from 1996. This decrease resulted primarily from the sale of the Company's U.S. onshore properties on December 23, 1996. U.S. gas volumes before gas balancing adjustments were 274,000 MCF in 1997, down 862,000 MCF from 1996. Such decrease is the result of an 896,000 MCF decrease resulting from the U.S. onshore property sale, and normal production declines partially offset by new production from a development well completed at Main Pass 41 during October 1996. Colombian oil prices averaged $17.39 per barrel during 1997. The average price for the same period in 1996 was $19.82 per barrel. The Company's average U.S. oil price decreased to $19.17 per barrel in 1997, down from $20.68 in 1996. U.S. gas prices averaged $2.73 per MCF in 1997 compared to $2.07 per MCF in 1996. In addition to the above-mentioned variances, U.S. gas revenue increased approximately $48,000 as a result of gas balancing adjustments. Operating costs decreased by $599,000, or 12%. Of such decrease, approximately $845,000 resulted from the sale of the U.S. onshore properties, offset by a $181,000 increase for the U.S. offshore properties and a $65,000 increase for the Colombian properties. DD&A decreased $1.3 million, or 17%, mainly due to lower production levels. 19 The Company recorded write-downs to the carrying amounts of its U.S. and Colombian oil and gas properties of $2,124,000 and $17,829,000, respectively, during 1997. The U.S. write-down was primarily due to lower prices. The Colombian write-down resulted primarily from lower prices and, to a somewhat lesser extent, downward revisions of proved oil reserves. G&A expense decreased $44,000 mainly due to reductions in the number of employees, officers, directors and related fees and expenses which resulted in cost savings of approximately $262,000 during 1997. These savings were partially offset by increases in legal and consulting fees aggregating $201,000. Interest and other income (expense) decreased mainly due to the absence in 1997 of a $641,000 gain recorded in 1996 relating to the sale of the U.S. onshore oil and gas properties. Interest expense was $156,000 lower, primarily as a result of lower average balances outstanding. Income taxes were lower in 1997 primarily due to Colombian deferred tax benefits resulting from the write-down of the carrying amount of the Company's Colombian oil and gas properties. Year 2000 The Year 2000 problem is the inability of a meaningful proportion of the world's computers, software applications and embedded semiconductor chips to cope with the change of the year from 1999 to 2000. This issue can be traced to the infancy of computing, when computer data and programs were designed to save memory space by truncating the date field to just six digits (two for the day, two for the month and two for the year). Such information applications automatically assume that the two-digit year field represents a year within the 20th century. As a result of this, systems could fail to operate or fail to produce correct results. The Year 2000 problem affects computers, software applications, and related equipment used, operated or maintained by the Company. Accordingly, the Company is currently assessing the potential impact of, and the costs of remediating, the Year 2000 problem for its internal systems and on facilities and equipment. The Company's business is substantially dependent upon the operations of computer systems, and as such, the Company has established a committee made up of leaders from the operational areas of the Company. The committee has the involvement of senior management and its objectives are high priority. The Company is in the process of identifying the computers, software applications, and related equipment used in connection with its operations that must be modified, upgraded or replaced to minimize the possibility of a material disruption of its business. The Company has commenced the process of modifying, upgrading and replacing systems which have already been assessed as adversely affected by the Year 2000 problem, and expects to complete this process by the end of the third quarter of 1999. In addition to computers and related systems, the operation of office equipment, such as fax machines, copiers, telephone switches, security systems and other common devices may be affected by the Year 2000 problem. The Company is currently assessing the potential effect of, and costs of remediating, the Year 2000 problem on its office systems and equipment. The Company has initiated communications with third party suppliers of computers, software, and other equipment used, operated or maintained by the Company to identify and, to the extent possible, to resolve issues involving the Year 2000 problem. However, the Company has limited or no control over the actions of these third party suppliers. Thus, while the Company expects that it will be able to resolve any significant Year 2000 problems with these systems, there can be no assurance that these suppliers will resolve any or all Year 2000 problems with these systems before the occurrence of a material disruption to the business of the Company. Any failure of these third parties to timely resolve Year 2000 problems with their systems could have a material adverse effect on the Company's business, financial condition, and results of operations. Because the Company's assessment is not complete, it is unable to accurately predict the total cost to the Company of completing any required modifications, upgrades, or replacements of its systems or equipment. The Company does not, however, believe that such total cost will exceed $200,000. The Company expects to identify and resolve all Year 2000 problems that could materially adversely affect its business operations. However, management believes that it is not possible to determine with complete certainty that all Year 2000 problems affecting the Company, its purchasers or its suppliers have been identified or corrected. The number of devices that could be 20 affected and the interactions among these devices are simply too numerous. In addition, no one can accurately predict how many Year 2000 problem-related failures will occur or the severity, duration, or financial consequences of these perhaps inevitable failures. As a result, management expects that the Company will likely suffer the following consequences: (i) a significant number of operational inconveniences and inefficiencies for the Company, its purchasers and its suppliers will divert management's time and attention and financial and human resources from its ordinary business activities; (ii) a few serious system failures that will require significant effort by the Company, its purchasers or its suppliers to prevent or alleviate material business disruptions; (iii) several routine business disputes and claims due to Year 2000 problems that will be resolved in the ordinary course of business; and (iv) possible business disputes alleging that the Company failed to comply with the terms of its contracts or industry standards of performance, some of which could result in litigation. The Company will develop contingency plans to be implemented if its efforts to identify and correct Year 2000 problems affecting its operational systems and equipment are not effective. The Company plans to complete its contingency plans by the end of the second quarter of 1999. Depending on the systems affected, any contingency plans developed by the Company, if implemented, could have a material adverse effect on the Company's financial condition and results of operations. The discussion of the Company's efforts, and management's expectations, relating to Year 2000 compliance are forward-looking statements. The Company's ability to achieve Year 2000 compliance and the level of incremental costs associated therewith, could be adversely impacted by, among other things, the availability and cost of programming and testing resources, vendors' ability to modify proprietary software, and unanticipated problems identified in the ongoing compliance review. New Accounting Pronouncements The Company is assessing the reporting and disclosure requirements of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. This statement establishes accounting and reporting standards for derivative instruments and hedging activities. The statement is effective for financial statements for fiscal years beginning after June 15, 1999. The Company believes SFAS No. 133 will not have a material impact on its financial statements or accounting policies. The Company will adopt the provisions of SFAS No. 133 in the first quarter of 2000. Liquidity and Capital Resources 21 During the last quarter of calendar year 1997 and throughout calendar year 1998, world oil prices have declined dramatically. This decline in oil prices has been particularly severe in Colombia. Colombian oil prices have, during the twenty-four month period ended December 31, 1998, fallen from a high of $22.71 per barrel in January 1997 to $7.50 per barrel in December 1998. Whereas the sale price for crude oil from the Santana contract averaged $19.82 per barrel in 1996 and $17.39 per barrel in 1997, the sale price averaged $10.31 per barrel during calendar year 1998. These price declines have materially and adversely affected the results of operations and the financial position of the Company. During the years ended December 31, 1998, 1997 and 1996, the Company reported net losses of $17.1 million, $22.5 million and $0.9 million, respectively, and declining amounts of net cash provided by (used in) operating activities of $(0.05) million, $1.7 million and $8.9 million, respectively. As of December 31, 1998, the Company's stockholders' deficit was approximately $11.1 million. The Company is highly leveraged with $14.8 million in current debt as of December 31, 1998, pursuant to bank credit facilities with ING (U.S.) Capital Corporation ("ING Capital") and Chase Bank of Texas, N.A. ("Chase"), as more fully described in note 5 to the consolidated financial statements contained elsewhere herein. As of December 31, 1998, the Company is not in compliance with various covenants under the bank credit facilities. Furthermore, assuming no change in its capital structure, the Company does not have the financial resources to maintain the minimum escrow balance required under the bank credit facilities beginning March 31, 1999, nor to pay the minimum monthly principal payments of $5.7 million on April 30, 1999, and $281,250 each month thereafter until December 31, 2001. Management of the Company is in discussions with the Company's lenders to restructure the above-referenced debt as set forth below. On February 22, 1999, the Company signed a letter of intent to merge with Sharpe Resources Corporation ("Sharpe"), a publicly traded oil and gas exploration and production company incorporated in Ontario, Canada. Sharpe currently has onshore oil and gas production in the United States from working and overriding royalty interests in over 115 wells on 107 properties in 4 states which include Texas, Oklahoma, New Mexico and Wyoming. Sharpe's offshore Gulf of Mexico production is from its operated interests in Matagorda One and Matagorda Two properties located offshore Matagorda Island, Texas in 48 feet of water. Sharpe's principal office is located in Houston, Texas. The proposed arrangements contemplate that Sharpe will be the parent company following the merger, that each six shares of Company Common Stock will be converted into one share of Sharpe Common Stock, and that the Company's lenders will restructure the Company's indebtedness to them. Such debt restructuring may include the conversion of a portion of the debt to a preferred stock position in the merged entity. The proposed arrangements are subject to numerous and substantial contingencies, the most important of which are: (i) completion of negotiations between the Company and Sharpe regarding the structure of the proposed transaction; (ii) preparation, negotiation, execution and delivery of a definitive merger agreement; (iii) approval of the definitive merger agreement and consent to the proposed debt restructuring by the Company's lenders (i.e., ING Capital, Chase and the Overseas Private Investment Corporation); approval of the debt restructuring arrangements by the board of directors of the Company; and approval of the definitive merger agreement by the boards of directors and stockholders of the Company and Sharpe. The proposed merger is subject to preparation, negotiation, execution and delivery of definitive debt restructuring agreements between the Company and its lenders. Management believes that the consummation of this merger will provide the combined companies with the ability to raise additional capital which is necessary to continue operations and proceed with certain development and exploration activities that management believes are essential to the survival of the Company. While management of the Company is pursuing the reorganization of the Company assiduously, its ability to effect such a reorganization is dependent upon the acquiesence of the Company's lenders and Sharpe, matters that are beyond the control of the Company. In particular, the Company's lenders must: (i) consent to waive the defaults of the Company under its bank credit facilities pending preparation, negotiation, execution and delivery of a definitive merger agreement and a definitive debt restructuring agreement and pending receipt of stockholder approvals of the definitive merger agreement; (ii) agree to debt restructuring arrangements that are acceptable to Sharpe; and (iii) negotiate, execute and deliver a definitive debt restructuring agreement. The Company's lenders have not yet and may not ever agree to a restructuring of the Company's debt. If the Company is unable to consummate the merger, then, in the absence of another business transaction or debt restructuring, the Company cannot maintain compliance with nor make principal payments required by the bank credit facilities and, accordingly, the lenders could declare a default, 22 accelerate all amounts outstanding, and attempt to realize upon the collateral securing the debt. As a result of this uncertainty, management believes there is substantial doubt about the Company's ability to continue as a going concern. During the period 1996 through 1998, costs incurred in oil and gas property acquisition, exploration and development activities by the Company totaled approximately $21.1 million. Of this figure, approximately $2.0 million was for exploration predominantly in Colombia, $10.8 million pertained to development costs in the United States (41%) and Colombia (59%), and $8.3 million relates to the acquisition of Garnet. The Company's sources of funds during this period were: (i) cash provided by (used in) operating activities - 1998 - $(0.05) million; 1997 - $1.7 million; and 1996 - $8.9 million; (ii) net cash provided by investing activities (before property and equipment expenditures) - 1998 - $1.4 million; 1997 - $0.02 million; and 1996 - $2.7 million; and (iii) net cash provided by (used in) financing activities - 1998 - $1.1 million; 1997 - $(0.3) million; and 1996 - $(5.1) million. The Company may recomplete certain existing wells and engage in various other projects in Colombia. The Company's share of the estimated future costs of these development activities is approximately $0.6 million at December 31, 1998. Failure to fund certain expenditures could result in the forfeiture of all or part of the Company's interest in the concessions. The Company will most likely fund the recompletion of certain wells through arrangements with service companies whereby the services are paid for with proceeds from the sale of incremental oil production. Any miscellaneous projects will be funded through cash provided from operations. Any substantial decreases in the borrowing base as hereinafter defined or increases in the amounts of these required expenditures could adversely affect the Company's ability to fund these activities. Delays in obtaining the required environmental approvals and permits on a timely basis, as described above under "Item 1. Business -- Regulation," and other delays could, through the impact of inflation, increase the required expenditures. Cost overruns resulting from factors other than inflation could also increase the required expenditures. Historically, the inflation rate of the Colombian peso has been in the range of 15-30% per year. Devaluation of the peso against the U.S. dollar has historically been slightly less than the inflation rate in Colombia. The Company has historically funded capital expenditures in Colombia by converting U.S. dollars to pesos at such time as the expenditures have been made. As a result of the interaction between peso inflation and devaluation of the peso against the U.S. dollar, inflation, from the Company's perspective, had not been a significant factor. During 1994, the first half of 1995 and 1996, however, devaluation of the peso was substantially lower than the rate of inflation of the peso, resulting in an effective inflation rate in excess of that of the U.S. dollar. There can be no assurance that this condition will not occur again or that, in such event, there will not be substantial increases in future capital expenditures as a result. Due to Colombian exchange controls and restrictions and the lack of an effective market, it is not feasible to hedge against the risk of net peso inflation against the U.S. dollar and the Company has not done so. Depending on the results of future exploration and development activities, substantial expenditures which have not been included in the Company's cash flow projections may be required. The outcome of these matters cannot be projected with certainty. With the exception of historical information, the matters discussed in this annual report to shareholders contain forward-looking statements that involve risks and uncertainties. Although the Company believes that its expectations are based on reasonable assumptions, it can give no assurance that its goals will be achieved. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include, among other things, general economic conditions, volatility of oil and gas prices, the impact of possible geopolitical occurrences world-wide and in Colombia, imprecision of reserve estimates, changes in laws and regulations, unforeseen engineering and mechanical or technological difficulties in drilling, working- over and operating wells during the periods covered by the forward-looking statements, as well as other factors described in "Item 1. Business - Risks Associated with the Company's Business." ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK The Company is exposed to market risk from changes in interest rates on debt and changes in commodity prices. The Company's exposure to interest rate risk relates to variable rate loans that are benchmarked to LIBOR interest rates. The Company does not use derivative financial instruments to manage overall borrowing costs or reduce exposure to adverse fluctuations in interest rates. The impact on the Company's results of operations of a one-point interest rate change on the outstanding balance of the variable rate debt as of December 31, 1998 would be immaterial. The Company produces and sells crude oil and natural gas. These commodities are sold based on market prices established with the buyers. The Company does not use financial instruments to hedge commodity prices. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA See the Financial Statements of Aviva Petroleum Inc. attached hereto and listed in Item 14 herein. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. None. 23 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Directors of the Company The by-laws of the Company provide that the number of directors may be fixed by the Board of Directors at a number between one and seven, except that a decrease in the number of directors shall not have the effect of reducing the term of any incumbent director. Effective October 28, 1998, the Board of Directors, by resolution, decreased the number of directors from five to three. The information set forth below, furnished to the Company by the respective individuals, shows as to each individual his name, age and principal positions with the Company.
NAME AGE POSITIONS DIRECTOR SINCE - ---- --- --------- -------------- Ronald Suttill 67 President, Chief Executive Officer 1985 and Director Eugene C. Fiedorek 67 Director 1997 Robert J. Cresci 55 Director 1998
The following sets forth the periods during which directors have served as such and a brief account of the business experience of such persons during at least the past five years. RONALD SUTTILL has been a director of the Company since August 1985 and has been President and Chief Executive Officer of the Company since January 1992. In December 1991, Mr. Suttill was appointed President and Chief Operating Officer and prior to that served as Executive Vice President of the Company. EUGENE C. FIEDOREK has been a director of the Company since July 1997. Mr. Fiedorek is a Managing Director of EnCap Investments, L.C., a company he co- founded in 1988. He was previously associated with RepublicBank Dallas for more than 20 years, most recently as the Managing Director in the Energy Department in charge of all energy-related commercial lending and corporate finance activities. Prior to joining RepublicBank, Mr. Fiedorek was with Shell Oil Company as an Exploitation Engineer. Mr. Fiedorek currently serves on the boards of Energy Capital Investment Company PLC, Apache Corporation and privately held Matador Petroleum Corporation. ROBERT J. CRESCI has been a director of the Company since October 1998. Mr. Cresci has been a Managing Director of Pecks Management Partners, Ltd., an investment management firm, since September 1990. Mr. Cresci currently serves on the boards of Bridgeport Machines, Inc., EIS International, Inc., Sepracor, Inc., Arcadia Financial, Ltd., Hitox, Inc., Meris Laboratories, Inc., Film Roman, Inc., Educational Medical, Inc., Source Media, Inc., Castle Dental Centers, Inc., Candlewood Hotel Co., Inc., SeraCare, Inc. and several private companies. Executive Officers of the Company The following table lists the names and ages of each of the executive officers of the Company and their principal occupations for the past five years. NAME AND AGE POSITIONS - ------------ --------- Ronald Suttill, 67 President and Chief Executive Officer since January 1992, President and Chief Operating Officer from December 1991 to January 1992 and Executive Vice President prior to that. 24 James L. Busby, 38 Treasurer since May 1994, Secretary since June 1996, Controller since November 1993 and a Senior Manager with the accounting firm of KPMG LLP prior to that. Meetings and Committees of the Board of Directors The Board of Directors of the Company held six meetings during 1998. Each director attended at least 75% of the aggregate of (i) the total number of meetings of the Board of Directors held during the period in which he was a director and (ii) the total number of meetings held by all committees on which he served. The Audit Committee and the Compensation Committee are the only standing committees of the Board of Directors, and the members of such committees are appointed at the initial meeting of the Board of Directors each year. The Company does not have a formal nominating committee; the Board of Directors performs this function. The Audit Committee, of which Mr. Fiedorek is the sole member, consults with the independent accountants of the Company and such other persons as the committee deems appropriate, reviews the preparations for and scope of the audit of the Company's annual financial statements, makes recommendations as to the engagement and fees of the independent accountants and performs such other duties relating to the financial statements of the Company as the Board of Directors may assign from time to time. The Audit Committee held two meetings during 1998. The Compensation Committee, which is comprised of Messrs. Fiedorek and Cresci, makes recommendations to the Board of Directors regarding the compensation of executive officers of the Company, including salary, bonuses, stock options and other compensation. The Compensation Committee held no meetings during 1998. Compliance with Section 16(a) of the Securities Exchange Act of 1934 Section 16(a) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), requires officers, directors and holders of more than 10% of the Common Stock (collectively, "Reporting Persons") to file reports of ownership and changes in ownership of the Common Stock with the SEC within certain time periods and to furnish the Company with copies of all such reports. Based solely on its review of the copies of such reports furnished to the Company by such Reporting Persons or on the written representations of such Reporting Persons, the Company believes that, during the year ended December 31, 1998, all of the Reporting Persons complied with their Section 16(a) filing requirements. 25 ITEM 11. EXECUTIVE COMPENSATION Summary Compensation Table The following table sets forth certain information regarding compensation earned in each of the last three fiscal years by the President and Chief Executive Officer of the Company (the "Named Executive Officer").
Summary Compensation Table -------------------------- Long Term Compensation Annual Compensation Awards Payouts -------------------------- -------------------------- ------- Other Annual Restricted Securities Name and Compen- Stock Underlying LTIP All Other Principal Salary Bonus sation Award(s) Options/ Payouts Compensa- Position Year ($) ($) ($) ($) SARs (#) ($) tion ($) - --------- ---- ------- -------- ------- ---------- ------------ ------- --------- Ronald Suttill(1) President and CEO 1998 157,500 - - - - - 4,750 President and CEO 1997 185,000 - - - - - 4,750 President and CEO 1996 200,000 - - - - - 4,750
(1) The amounts reported for all other compensation for Mr. Suttill represent matching contributions made under the Aviva Petroleum Inc. 401(k) Retirement Plan (the "401(k) Plan"). Directors' Fees Mr. Fiedorek received $5,000 for his services as a director in 1998. Beginning April 1, 1998, directors are no longer paid a cash fee. Directors are, however, reimbursed for travel and lodging expenses. Mr. Suttill receives no compensation as a director but is reimbursed for travel and lodging expenses incurred to attend meetings. On July 1 each year, non-employee directors who have served in such capacity for at least the entire proceeding calendar year each receives an option to purchase 5,000 shares of the Company's Common Stock pursuant to the Aviva Petroleum Inc. 1995 Stock Option Plan, as amended. Option Grants During 1998 There were no options granted to the Named Executive Officer during 1998. No stock appreciation rights have been issued by the Company. Option Exercises During 1998 and Year End Option Values The following table provides information related to options exercised by the Named Executive Officer during 1998 and the number and value of options held at year-end. No stock appreciation rights have been issued by the Company.
Number of Securities Value of Unexercised Underlying Unexercised In-the-Money Options Options at FY-End (#) at FY-End ($) (1) Shares Acquired Value --------------------------- --------------------------- Name on Exercise (#) Realized ($) Exercisable Unexercisable Exercisable Unexercisable - ---- --------------- ------------ ----------- ------------- ----------- ------------- Ronald Suttill none none 250,000 - - -
(1) No values are ascribed to unexercised options of the Named Executive Officer at December 31, 1998 because the fair market value of a share of the Company's Common Stock at December 31, 1998 ($0.02) did not exceed the exercise price of any such options. 26 Compensation Committee Interlocks and Insider Participation in Compensation Decisions As indicated above, the Compensation Committee, none of the members of which is an employee of the Company, makes recommendations to the Board of Directors regarding the compensation of the executive officers of the Company, including salary, bonuses, stock options and other compensation. There are no Compensation Committee interlocks. Until this committee was originally appointed in 1993, the compensation of the executive officers was established by the Board of Directors as a whole, including Mr. Suttill. Employment Contracts Each executive officer serves at the discretion of the Board of Directors, except that, effective in January 1995, the Company entered into an employment contract with Mr. Suttill. Mr. Suttill's contract provides for annual compensation of not less than $200,000 if his employment is terminated for any reason other than death, disability or cause, as defined in the contract. Mr. Suttill's contract was automatically renewed for one-year periods on January 1, 1996, 1997, 1998 and 1999. Compensation Committee Report on Executive Compensation The Company currently employs only two executive officers, the names of whom are set forth above under "Item 10. Directors and Executive Officers of the Registrant--Executive Officers of the Company." Decisions regarding compensation of the executive officers are made by the Board of Directors, after giving consideration to recommendations made by the Compensation Committee. The Company's compensation policies are designed to provide a reasonably competitive level of compensation within the industry in order to attract, motivate, reward and retain experienced, qualified personnel with the talent necessary to achieve the Company's performance objectives. These objectives are to increase oil and gas reserves and to control costs, both objectives selected to increase shareholder value. These policies were implemented originally by the entire Board of Directors, and, following its establishment, were endorsed by the Compensation Committee. It is the intention of the Compensation Committee and the Board of Directors to balance compensation levels of the Company's executive officers, including the Chief Executive Officer, with shareholder interests. The incentive provided by stock options and bonuses, in particular, is intended to promote congruency of interests between the executive officers and the shareholders. Neither the Compensation Committee nor the Board of Directors, however, believes that it is appropriate to rely on a formulaic approach, such as profitability, revenue growth or return on equity, in determining executive officer compensation because of the nature of the Company's business. The Company's business objectives include overseeing a significant exploration and development effort in Colombia and the maintenance of oil and gas production levels and offshore operations in the United States. Success in one such area is not measurable by the same factors as those used in the other. Accordingly, the Compensation Committee and the Board of Directors rely primarily on their assessment of the success of the executive officers, including the Chief Executive Officer, in fulfilling the Company's performance objectives. The Board of Directors also considers the fact that the Company competes with other oil and gas companies for qualified executives and therefore it considers available information regarding compensation levels for executives of companies similar in size to the Company. Compensation for the Company's executive officers during 1998 was comprised of salary, stock options and matching employer contributions made pursuant to the Company's 401(k) Plan. The Company's 401(k) Plan is generally available to all employees after one year of service. The Company makes matching contributions of 50% of the amount deferred by the employee, up to 3% of an employee's annual salary. There were no bonuses paid to the executive officers during or for 1998. Compensation Committee E. C. Fiedorek R. J. Cresci 27 Performance Graph The following line-graph presentation compares five-year cumulative shareholder returns on an indexed basis with a broad equity market index and a published industry index. The Company has selected the American Stock Exchange Market Value Index as a broad equity market index, and the SIC Index "Crude Petroleum and Natural Gas" as a published industry index. COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN OF THE COMPANY, INDUSTRY INDEX AND BROAD MARKET - --------------------------FISCAL YEAR ENDING-------------------------- COMPANY/INDEX/MARKET 1993 1994 1995 1996 1997 1998 AVIVA PETROLEUM INC. 100.0 122.62 104.76 92.86 39.29 2.38 INDUSTRY INDEX 100.0 104.80 115.26 153.26 155.34 124.43 BROAD MARKET 100.0 88.33 113.86 120.15 144.57 142.61 28 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Security Ownership of Certain Beneficial Owners The following table sets forth certain information as to each person who, to the knowledge of the Company, is the beneficial owner of more than five percent of the outstanding Common Stock of the Company. Unless otherwise noted, the information is furnished as of February 26, 1999.
NAME AND ADDRESS OF AMOUNT AND NATURE OF Beneficial Owner or Group BENEFICIAL OWNERSHIP (1) PERCENT OF CLASS (2) - ------------------------- ------------------------ --------------------- Wexford Management LLC(3) 5,438,639 11.28% 411 West Putnam Avenue Greenwich, Connecticut 06830 Pecks Management Partners Ltd. (4) 5,155,108 10.70% One Rockefeller Plaza New York, New York 10020 Lehman Brothers Inc.(5) 2,966,876 6.16% 3 World Financial Center 11th Floor New York, NY 10285 ING (U.S.) Capital Corporation(6) 2,700,000 5.60% 135 East 57th Street New York, New York 10022 Yale University(7) 2,551,886 5.29% 230 Prospect Street New Haven, CT 06511
(1) Except as set forth below, to the knowledge of the Company, each beneficial owner has sole voting and sole investment power. (2) Based on 46,700,132 shares of the Common Stock issued and outstanding on February 26, 1999, plus warrants for 1,500,000 shares held by ING (U.S.) Capital Corporation. (3) Information regarding Wexford Management LLC ("Wexford Management") is based on a Schedule 13D dated November 12, 1998 filed by Wexford Management with the SEC. The shares are held by four investment funds. Wexford Management serves as investment advisor to three of the funds and as sub-investment advisor to the fourth fund which is organized as a corporation. Wexford Advisors, LLC ("Wexford Advisors") serves as the investment advisor to the corporate fund and as general partner to the remaining funds which are organized as limited partnerships. One of the limited partnerships, Wexford Special Situations 1996 L.P., holds more than 5% of Aviva Common Stock. Wexford Management shares voting and dispositive power with respect to these shares with each of the funds, with Wexford Advisors, and with Charles E. Davidson and Joseph M. Jacob, each of whom is a controlling person of Wexford Management and Wexford Advisors. (4) Based on the number of shares issued on October 28, 1998, in connection with the acquisition of Garnet Resources Corporation. The shares are held by three investment advisory clients of Pecks Management Partners Ltd. ("Pecks"). One such client, Delaware State Employees' Retirement Fund, holds more than 5% of Aviva's Common Stock. Pecks has sole investment and dispositive power with respect to these shares. (5) Information regarding Lehman Brothers Inc. is based on information received from Lehman Brothers Inc. on March 16, 1998. (6) Based on 1,200,000 shares held by ING, plus warrants to acquire an additional 1,500,000 shares. (7) Information regarding Yale University is based on a Schedule 13G dated March 11, 1994 filed by Yale University with the SEC. 29 Security Ownership of Management The following table sets forth certain information as of February 26, 1999, concerning the Common Stock of the Company owned beneficially by each director, by the Named Executive Officer listed in the Summary Compensation Table above, and by directors and executive officers of the Company as a group:
NAME AND ADDRESS OF AMOUNT AND NATURE Beneficial Owner OF BENEFICIAL OWNERSHIP(1) PERCENT OF CLASS(2) - ------------------- -------------------------- -------------------- Ronald Suttill 2,129,939(3)(4) 4.36% 8235 Douglas Avenue, Suite 400 Dallas, TX 75225 Eugene C. Fiedorek 916,542 1.88% 3811 Turtle Creek Blvd., Suite 1080 Dallas, TX 75219 Robert J. Cresci 0(5) * Pecks Management Partners Ltd. One Rockefeller Plaza New York, NY 10020 All directors and executive officers as a group (4 persons) 3,640,566(6) 7.45%
(1) Except as noted below, each beneficial owner has sole voting power and sole investment power. (2) Based on 46,700,132 shares of Common Stock issued and outstanding on February 26, 1999. Treated as outstanding for purposes of computing the percentage ownership of each director, the Named Executive Officer and all directors and executive officers as a group are shares issuable upon exercise of vested stock options granted pursuant to the Company's stock option plans and 1,500,000 shares represented by warrants issued to ING Capital. (3) Included are options for 250,000 shares exercisable on or within 60 days of February 26, 1999. (4) Includes the entire ownership of AMG Limited, a limited liability company of which Mr. Suttill is a member, as of February 26, 1999, of 935,550 shares of Common Stock. (5) Does not include shares owned by Pecks, of which Mr. Cresci is a managing director. For information with respect to such shares, see note (4) under "Security Ownership of Certain Beneficial Owners." (6) Included are 935,550 shares beneficially owned through AMG Limited and options for 341,333 shares exercisable on or within 60 days of February 26, 1999. * Less than 1% of the outstanding Aviva Common Stock. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS None. 30 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K a. The following documents are filed as part of this report: (1) Financial Statements: The Financial Statements of Aviva Petroleum Inc. filed as part of this report are listed in the "Index to Financial Statements" included elsewhere herein. (2) Financial Statement Schedules: All schedules called for under Regulation S-X have been omitted because they are not applicable, the required information is not material or the required information is included in the consolidated financial statements or notes thereto. (3) Exhibits: *2.1 Agreement and Plan of Merger dated as of June 24, 1998, by and among Aviva Petroleum Inc., Aviva Merger Inc. and Garnet Resources Corporation (filed as exhibit 2.1 to the Registration Statement on Form S-4, File No. 333-58061, and incorporated herein by reference). *2.2 Debenture Purchase Agreement dated as of June 24, 1998, between Aviva Petroleum Inc. and the Holders of the Debentures named therein (filed as exhibit 2.2 to the Registration Statement on Form S-4, file No. 333-58061, and incorporated herein by reference). *3.1 Restated Articles of Incorporation of the Company dated July 25, 1995 (filed as exhibit 3.1 to the Company's annual report on Form 10-K for the year ended December 31, 1995, File No. 0- 22258, and incorporated herein by reference). *3.2 Amended and Restated Bylaws of the Company, as amended as of January 23, 1995 (filed as exhibit 3.2 to the Company's annual report on Form 10-K for the year ended December 31, 1994, File No. 0-22258, and incorporated herein by reference). *10.1 Risk Sharing Contract between Empresa Colombiana de Petroleos ("Ecopetrol"), Argosy Energy International ("Argosy") and Neo Energy, Inc. ("Neo") (filed as exhibit 10.1 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.2 Contract for Exploration and Exploitation of Sector Number 1 of the Aporte Putumayo Area ("Putumayo") between Ecopetrol and Cayman Corporation of Colombia dated July 24, 1972 (filed as exhibit 10.2 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.3 Operating Agreement for Putumayo between Argosy and Neo dated September 16, 1987 and amended on January 4, 1989 and February 23, 1990 (filed as exhibit 10.3 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.4 Operating Agreement for the Santana Area ("Santana") between Argosy and Neo dated September 16, 1987 and amended on January 4, 1989, February 23, 1990 and September 28, 1992 (filed as exhibit 10.4 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.5 Agreement of Withdrawal from Argosy dated September 16, 1987 by and among Argosy, Neo, and Argosy Energy Incorporated, as general partners; and Parkside Investments, Richard Shane McKnight, Douglas W. Fry, P-5 Ltd., GO-DEO, Inc., Dale E. Armstrong, Richard Shane McKnight, The Yvonne McKnight Trust, and William Gaskin, as limited partners (filed as exhibit 10.5 to the Company's Registration Statement on Form10, File No. 0- 22258, and incorporated herein by reference). *10.6 Option Agreement dated September 16, 1987 between the general and limited partners of Argosy and Neo (filed as exhibit 10.6 to the Company's Registration Statement on Form10, File No. 0- 22258, and incorporated herein by reference). *10.7 Escrow Agreement between Argosy, Neo, Overseas Private Investment Corporation and The Chase Manhattan Bank dated March 15, 1988 and amended on May 31, 1990 (filed as exhibit 10.7 to the Company's Registration Statement on Form10, File No. 0- 22258, and incorporated herein by reference). 31 *10.8 Santana Block A Relinquishment dated March 6, 1990 between Ecopetrol, Argosy and Neo (filed as exhibit 10.8 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.9 Purchase Sale - Transportation and Commercialization of the Santana Crude between Ecopetrol, Argosy and Neo (filed as exhibit 10.9 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.10 La Fragua Association Contract dated June 1, 1992 between Ecopetrol, Argosy and Neo (filed as exhibit 10.10 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.11 Operating Agreement for the La Fragua Area between Argosy and Neo dated April 15, 1992 (filed as exhibit 10.11 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.12 Employment Agreement between the Company and Ronald Suttill dated November 29, 1991 (filed as exhibit 10.12 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.13 Employee Stock Option Plan of the Company (filed as exhibit 10.13 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.14 Letter agreement dated January 6, 1993 between NationsBank Investment Banking and the Company (filed as exhibit 10.14 to the Company's Registration Statement on Form10, File No. 0- 22258, and incorporated herein by reference). *10.15 Letter agreement dated March 3, 1993 between EnCap Investments L.C. and the Company (filed as exhibit 10.15 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.16 Credit Agreement dated August 6, 1993 between the Company, Aviva America, Inc. ("Aviva America"), Neo and Internationale Nederlanden Bank N.V., New York Branch ("ING Capital") (filed as exhibit 10.16 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.17 Subordination Agreement dated August 6, 1993 between the Company, Aviva America, Aviva Operating Company ("Aviva Operating"), Neo and ING Capital (filed as exhibit 10.17 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.18 Stock Pledge Agreement dated August 6, 1993 between the Company and ING Capital (filed as exhibit 10.18 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.19 Stock Pledge Agreement dated August 6, 1993 between Aviva America and ING Capital (filed as exhibit 10.19 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.20 Guaranty dated August 6, 1993 made by the Company in favor of ING Capital (filed as exhibit 10.20 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.21 Guaranty dated August 6, 1993 made by Aviva America in favor of ING Capital (filed as exhibit 10.21 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.22 Guaranty dated August 6, 1993 made by Aviva Operating in favor of ING Capital (filed as exhibit 10.22 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.23 Form of Subscription Agreement dated June 18, 1993 between the Company and purchasers of 12,884,207 shares of common stock ("Purchasers") (filed as exhibit 10.23 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.24 Option Agreement between RBS and Aviva Energy Inc. ("Aviva Energy") dated July 1, 1993 (filed as exhibit 10.24 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.25 Option Agreement between Aviva Energy and Purchasers dated July 1, 1993 (filed as exhibit 10.25 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.26 Santana Block B 50% relinquishment dated September 13, 1993 between Ecopetrol, Argosy and Neo (filed as exhibit 10.26 to the Company's annual report on Form 10-K for the year ended December 31, 1993, File No. 0-22258, and incorporated herein by reference). 32 *10.27 Amendment to La Fragua Association contract dated December 2, 1993 between Ecopetrol, Argosy and Neo (filed as exhibit 10.27 to the Company's annual report on Form 10-K for the year ended December 31, 1993, File No. 0-22258, and incorporated herein by reference). *10.28 Letter from Ecopetrol dated February 24, 1994 and Resolution dated February 18, 1994 revising pipeline tariff (filed as exhibit 10.28 to the Company's annual report on Form 10-K for the year ended December 31, 1993, File No. 0-22258, and incorporated herein by reference). *10.29 Aviva Petroleum Inc. 401(k) Retirement Plan effective March 1, 1992 (filed as exhibit 10.29 to the Company's annual report on Form 10-K for the year ended December 31, 1993, File No. 0- 22258, and incorporated herein by reference). *10.30 Relinquishment of Putumayo dated December 1, 1993 (filed as exhibit 10.30 to the Company's annual report on Form 10-K for the year ended December 31, 1993, File No. 0-22258, and incorporated herein by reference). *10.31 Amendment to ING Capital agreement dated March 28, 1994 (filed as exhibit 10.31 to the Company's annual report on Form 10-K for the year ended December 31, 1993, File No. 0-22258, and incorporated herein by reference). *10.32 Deposit Agreement dated September 15, 1994 between the Company and Chemical Shareholder Services Group, Inc. (filed as exhibit 10.29 to the Company's Registration Statement on Form S-1, File No. 33-82072, and incorporated herein by reference). *10.33 Form of Registration Agreement dated as of September 15, 1994 between the Company and Shearson Lehman Brothers Inc. (filed as exhibit 10.30 to the Company's Registration Statement on Form S- 1, File No. 33-82072, and incorporated herein by reference). *10.34 Form of Registration Agreement and Limited Power of Attorney dated as of September 15, 1994 between the Company and all other Selling Shareholders (filed as exhibit 10.31 to the Company's Registration Statement on Form S-1, File No. 33-82072, and incorporated herein by reference). *10.35 Form of Broker-Dealer Agreement dated as of October 19, 1994 between the Company and Petrie Parkman & Co. (filed as exhibit 10.32 to the Company's Registration Statement on Form S-1, File No. 33-82072, and incorporated herein by reference). *10.36 Purchase and Sale Agreement dated July 22, 1994 by and between Newfield Exploration Company and Aviva America (filed as exhibit 10.33 to the Company's Registration Statement on Form S-1, File No. 33-82072, and incorporated herein by reference). *10.37 Letter from ING Capital dated October 27, 1994, amending Section 5.2 (n) of the Credit Agreement (filed as exhibit 10.37 to the Company's annual report on Form 10-K for the year ended December 31, 1994, File No. 0-22258, and incorporated herein by reference). *10.38 Letter from Ecopetrol dated December 28, 1994, accepting relinquishment of Putumayo (filed as exhibit 10.38 to the Company's annual report on Form 10-K for the year ended December 31, 1994, File No. 0-22258, and incorporated herein by reference). *10.39 Letter from Ecopetrol dated February 28, 1995, accepting modifications to the La Fragua Association Contract (filed as exhibit 10.39 to the Company's annual report on Form 10-K for the year ended December 31, 1994, File No. 0-22258, and incorporated herein by reference). *10.40 Amendment to ING Capital Credit Agreement dated March 7, 1995 (filed as exhibit 10.40 to the Company's annual report on Form 10-K for the year ended December 31, 1994, File No. 0-22258, and incorporated herein by reference). *10.41 Santana Crude Oil Sale Contract dated March 19, 1995 (filed as exhibit 10.41 to the Company's annual report on Form 10-K for the year ended December 31, 1994, File No. 0-22258, and incorporated herein by reference). *10.42 Employment Agreement between the Company and Ronald Suttill effective January 1, 1995 (filed as exhibit 10.1 to the Company's quarterly report on Form 10-Q for the quarter ended March 31, 1995, File No. 0-22258, and incorporated herein by reference). *10.43 Employment Agreement between the Company and Robert C. Boyd effective January 1, 1995 (filed as exhibit 10.2 to the Company's quarterly report on Form 10-Q for the quarter ended March 31, 1995, File No. 0-22258, and incorporated herein by reference). *10.44 Amendment to ING Capital Credit Agreement dated June 9, 1995 (filed as exhibit 10.3 to the Company's quarterly report on Form 10-Q for the quarter ended June 30, 1995, File No. 0-22258, and incorporated herein by reference). 33 *10.45 Amendment to the Incentive and Nonstatutory Stock Option Plan of the Company (filed as exhibit 10.4 to the Company's quarterly report on Form 10-Q for the quarter ended September 30, 1995, File No. 0-22258, and incorporated herein by reference). *10.46 Aviva Petroleum Inc. 1995 Stock Option Plan (filed as exhibit 10.5 to the Company's quarterly report on Form 10-Q for the quarter ended September 30, 1995, File No. 0-22258, and incorporated herein by reference). *10.47 Yuruyaco Association Contract dated September 20, 1995 between Ecopetrol, Argosy and Neo (filed as exhibit 10.6 to the Company's quarterly report on Form 10-Q for the quarter ended September 30, 1995, File No. 0-22258, and incorporated herein by reference). *10.48 Letter from ING Capital dated November 3, 1995, amending Section 5.2 (n) of the Credit Agreement (filed as exhibit 10.7 to the Company's quarterly report on Form 10-Q for the quarter ended September 30, 1995, File No. 0-22258, and incorporated herein by reference). *10.49 Amendment to the Santana Crude Oil Sale Contract (filed as exhibit 10.49 to the Company's annual report on Form 10-K for the year ended December 31, 1995, File No. 0-22258, and incorporated herein by reference). *10.50 Amendment to the La Fragua Association Contract dated April 27, 1995 (filed as exhibit 10.50 to the Company's annual report on Form 10-K for the year ended December 31, 1995, File No. 0- 22258, and incorporated herein by reference). *10.51 Santana Block B 25% relinquishment dated October 2, 1995 (filed as exhibit 10.51 to the Company's annual report on Form 10-K for the year ended December 31, 1995, File No. 0-22258, and incorporated herein by reference). *10.52 Amendment to the La Fragua Association Contract dated August 1, 1995 (filed as exhibit 10.52 to the Company's annual report on Form 10-K for the year ended December 31, 1995, File No. 0- 22258, and incorporated herein by reference). *10.53 Operating Agreement for the Yuruyaco Area between Argosy and Neo dated November 7, 1995 (filed as exhibit 10.53 to the Company's annual report on Form 10-K for the year ended December 31, 1995, File No. 0-22258, and incorporated herein by reference). *10.54 Letter from ING Capital dated March 19, 1996, amending the borrowing base, schedule of principal repayments and Section 5.2 (m) of the Credit Agreement (filed as exhibit 10.54 to the Company's annual report on Form 10-K for the year ended December 31, 1995, File No. 0-22258, and incorporated herein by reference). *10.55 Amendment to the ING Capital Credit Agreement dated March 29, 1996 (filed as exhibit 10.1 to the Company's quarterly report on Form 10-Q for the quarter ended March 31, 1996, File No. 0- 22258, and incorporated herein by reference). *10.56 Aviva Petroleum Inc. Severance Benefit Plan (filed as exhibit 10.2 to the Company's quarterly report on Form 10-Q for the quarter ended March 31, 1996, File No. 0-22258, and incorporated herein by reference). *10.57 Amendment to the ING Capital Credit Agreement dated November 22, 1996 (filed as exhibit 10.57 to the Company's annual report on Form 10-K for the year ended December 31, 1996, File No. 0- 22258, and incorporated herein by reference). *10.58 Purchase and Sale Agreement dated November 22, 1996 between BWAB Incorporated and Aviva America (filed as exhibit 10.58 to the Company's annual report on Form 10-K for the year ended December 31, 1996, File No. 0-22258, and incorporated herein by reference). *10.59 Purchase and Sale Agreement dated December 6, 1996 between Lomak Petroleum Inc. and Aviva America (filed as exhibit 10.59 to the Company's annual report on Form 10-K for the year ended December 31, 1996, File No. 0-22258, and incorporated herein by reference). *10.60 Santana Crude Sale and Purchase Agreement dated February 10, 1997 (filed as exhibit 10.60 to the Company's annual report on Form 10-K for the year ended December 31, 1996, File No. 0- 22258, and incorporated herein by reference). *10.61 Aviva Petroleum Inc. 1995 Stock Option Plan, as amended (filed as Appendix A to the Company's definitive Proxy Statement for the Annual Meeting of Shareholders dated June 10, 1997, and incorporated herein by reference). *10.62 Amendment to the ING Capital Credit Agreement dated August 12, 1997 (filed as exhibit 10.2 to the Company's quarterly report on Form 10-Q for the quarter ended June 30, 1997, File No. 0-22258, and incorporated herein by reference). *10.63 Amended and Restated Aviva Petroleum Inc. Severance Benefit Plan dated September 30, 1997 (filed as exhibit 10.3 to the Company's quarterly report on Form 10-Q for the quarter ended September 30, 1997, File No. 0-22258, and incorporated herein by reference). 34 *10.64 Amendment to the ING Capital Credit Agreement dated December 29, 1997 (filed as exhibit 10.64 to the Company's annual report on Form 10-K for the year ended December 31, 1997, File No. 0- 22258, and incorporated herein by reference). *10.65 Amendment to the Santana Crude Sale and Purchase Agreement dated January 5, 1998 (filed as exhibit 10.65 to the Company's annual report on Form 10-K for the year ended December 31, 1997, File No. 0-22258, and incorporated herein by reference). *10.66 Amendment to the ING Capital Credit Agreement dated February 13, 1998 (filed as exhibit 10.66 to the Company's annual report on Form 10-K for the year ended December 31, 1997, File No. 0- 22258, and incorporated herein by reference). *10.67 Amendment to the ING Capital Credit Agreement dated August 6, 1998 (filed as exhibit 10.1 to the Company's quarterly report on Form 10-Q for the quarter ended June 30, 1998, File No. 0-22258, and incorporated herein by reference). *10.68 Restated Credit Agreement dated as of October 28, 1998, between Neo Energy, Inc., Aviva Petroleum Inc. and ING (U.S.) Capital Corporation (filed as exhibit 99.1 to the Company's Form 8-K dated October 28, 1998, File No. 0-22258, and incorporated herein by reference). *10.69 Joint Finance and Intercreditor Agreement dated as of October 28, 1998, between Neo Energy, Inc., Aviva Petroleum Inc., ING (U.S.) Capital Corporation, Aviva America, Inc., Aviva Operating Company, Aviva Delaware Inc., Garnet Resources Corporation, Argosy Energy Incorporated, Argosy Energy International, Garnet PNG Corporation, the Overseas Private Investment Corporation, Chase Bank of Texas, N.A. and ING (U.S.) Capital Corporation as collateral agent for the creditors (filed as exhibit 99.2 to the Company's Form 8-K dated October 28, 1998, File No. 0-22258, and incorporated herein by reference). **10.70 Amendment to the Santana Crude Sale and Purchase Agreement dated February 16, 1999. **21.1 List of subsidiaries of Aviva Petroleum Inc. **27.1 Financial Data Schedule. ____________________ * Previously Filed ** Filed Herewith b. Reports on Form 8-K ------------------- The Company filed the following Current Reports on Form 8-K during and subsequent to the end of the fourth quarter: Date of 8-K Description of 8-K ----------- ------------------ October 2, 1998 Submitted a description of the resignation of James E. Tracey, a director of the Company, along with his resignation letter (including its antecedents). October 28, 1998 Submitted a description of the merger with Garnet Resources Corporation that was completed on October 28, 1998. Also submitted a summary of the new bank credit facilities signed on October 28, 1998. March 4, 1999 Submitted a copy of the Company's Press Release dated March 4, 1999, announcing the merger plans between Aviva America, Inc., a wholly owned subsidiary of Aviva Petroleum Inc., and Sharpe Resources Corporation. 35 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. AVIVA PETROLEUM INC. By: /s/ RONALD SUTTILL ------------------- Ronald Suttill Chief Executive Officer and Director 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. SIGNATURE TITLE DATE /s/ RONALD SUTTILL President, Chief Executive Officer March 26, 1999 - ------------------ and Director (principal executive -------------- Ronald Suttill officer) /s/ JAMES L. BUSBY Treasurer and Secretary March 26, 1999 - ------------------ (principal financial and accounting -------------- James L. Busby officer) /s/ EUGENE C. FIEDOREK Director March 26, 1999 - ---------------------- -------------- Eugene C. Fiedorek /s/ ROBERT J. CRESCI Director March 26, 1999 - -------------------- -------------- Robert J. Cresci 36 INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES Page ---- Independent Auditors' Report................................... 38 Consolidated Balance Sheet as of December 31, 1998 and 1997.... 39 Consolidated Statement of Operations for the years ended December 31, 1998, 1997 and 1996.................... 40 Consolidated Statement of Cash Flows for the years ended December 31, 1998, 1997 and 1996.................... 41 Consolidated Statement of Stockholders' Equity for the years ended December 31, 1998, 1997 and 1996.................... 42 Notes to Consolidated Financial Statements..................... 43 Supplementary Information Related to Oil and Gas Producing Activities (Unaudited).................................... 57 All schedules called for under Regulation S-X have been omitted because they are not applicable, the required information is not material or the required information is included in the consolidated financial statements or notes thereto. 37 INDEPENDENT AUDITORS' REPORT ---------------------------- The Board of Directors Aviva Petroleum Inc.: We have audited the accompanying consolidated financial statements of Aviva Petroleum Inc. and subsidiaries as listed in the accompanying index. 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 generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Aviva Petroleum Inc. and subsidiaries as of December 31, 1998 and 1997, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 1998, in conformity with generally accepted accounting principles. The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the financial statements, the Company has suffered recurring losses from operations and has a net capital deficiency, which conditions raise substantial doubt about its ability to continue as a going concern. Management's plans in regard to these matters are also described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty. /s/ KPMG LLP Dallas, Texas March 5, 1999 38 AVIVA PETROLEUM INC. AND SUBSIDIARIES Consolidated Balance Sheet DECEMBER 31, 1998 AND 1997 (in thousands, except number of shares)
1998 1997 --------- --------- ASSETS Current assets: Cash and cash equivalents $ 1,712 $ 690 Restricted cash (note 5) 417 - Accounts receivable (note 10): Oil and gas revenue 363 1,108 Trade 554 518 Other 586 177 Inventories 836 602 Prepaid expenses and other 627 203 -------- -------- Total current assets 5,095 3,298 -------- -------- Property and equipment, at cost (note 5): Oil and gas properties and equipment (full cost method) 68,636 61,036 Other 612 606 -------- -------- 69,248 61,642 Less accumulated depreciation, depletion and amortization (64,440) (49,873) -------- -------- 4,808 11,769 Other assets (note 4) 1,519 1,378 -------- -------- $ 11,422 $ 16,445 ======== ======== LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT) Current liabilities: Current portion of long term debt (note 5) $ 14,805 $ 480 Accounts payable 5,526 3,091 Accrued liabilities 308 356 -------- -------- Total current liabilities 20,639 3,927 -------- -------- Long term debt, excluding current portion (note 5) - 7,210 Gas balancing obligations and other (note 12) 1,866 1,560 Stockholders' equity (deficit) (notes 5 and 7): Common stock, no par value, authorized 348,500,000 shares; issued 46,700,132 in 1998 and 31,482,716 shares in 1997 2,335 1,574 Additional paid-in capital 34,862 33,376 Accumulated deficit* (48,280) (31,202) -------- -------- Total stockholders' equity (deficit) (11,083) 3,748 Commitments and contingencies (note 11) -------- -------- $ 11,422 $ 16,445 ======== ========
*Accumulated deficit of $70,057 was eliminated at December 31, 1992 in connection with a quasi-reorganization. See note 7. See accompanying notes to consolidated financial statements. 39 AVIVA PETROLEUM INC. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF OPERATIONS YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (in thousands, except per share data)
1998 1997 1996 -------- -------- -------- Oil and gas sales (note 10) $ 3,332 $ 9,726 $ 13,750 -------- -------- -------- Expense: Production 3,525 4,235 4,834 Depreciation, depletion and amortization 3,152 6,067 7,339 Write-down of oil and gas properties (note 1) 12,343 19,953 - General and administrative 1,074 1,510 1,554 Provision for losses on accounts receivable 420 - - Severance (note 8) - - 196 -------- -------- -------- Total expense 20,514 31,765 13,923 -------- -------- -------- Other income (expense): Interest and other income (expense), net (note 6) 1,045 122 1,061 Interest expense (748) (658) (814) Debt refinancing expense (note 5) - - (100) -------- -------- -------- Total other income (expense) 297 (536) 147 -------- -------- -------- Loss before income taxes and extraordinary item (16,885) (22,575) (26) Income (taxes) benefits (note 9) 4 93 (911) -------- -------- -------- Loss before extraordinary item (16,881) (22,482) (937) Extraordinary item - debt extinguishment (197) - - -------- -------- -------- Net loss $(17,078) $(22,482) $ (937) ======== ======== ======== Weighted average common shares outstanding 34,279 31,483 31,483 ======== ======== ======== Basic and diluted net loss per common share $ (0.50) $ (0.71) $ (0.03) ======== ======== ========
See accompanying notes to consolidated financial statements. 40 AVIVA PETROLEUM INC. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CASH FLOWS YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (in thousands)
1998 1997 1996 --------- --------- -------- Net loss $(17,078) $(22,482) $ (937) Adjustments to reconcile net loss to net cash provided by operating activities: Depreciation, depletion and amortization 3,152 6,067 7,339 Write-down of oil and gas properties 12,343 19,953 - Provision for losses on accounts receivable 420 - - Deferred foreign income taxes - (692) 195 Loss (gain) on sale of assets, net - 15 (651) Foreign currency exchange loss (gain), net (1) 75 16 Other (275) (217) (253) Changes in assets and liabilities: Escrow account (417) - - Accounts and notes receivable 825 1,934 (916) Inventories 195 118 88 Prepaid expenses and other (196) 79 406 Accounts payable and accrued liabilities 983 (3,119) 3,656 -------- -------- ------- Net cash provided by (used in) operating activities (49) 1,731 8,943 -------- -------- ------- Cash flows from investing activities: Property and equipment expenditures (1,405) (2,757) (8,667) Proceeds from sale of assets - 19 2,729 Other 1,421 - (46) -------- -------- ------- Net cash provided by (used in) investing activities 16 (2,738) (5,984) -------- -------- ------- Cash flows from financing activities: Proceeds from long term debt 1,560 - - Principal payments on long term debt (400) (300) (5,077) Other (97) - - -------- -------- ------- Net cash provided by (used in) financing activities 1,063 (300) (5,077) -------- -------- ------- Effect of exchange rate changes on cash and cash equivalents (8) (44) (41) -------- -------- ------- Net increase (decrease) in cash and cash equivalents 1,022 (1,351) (2,159) Cash and cash equivalents at beginning of year 690 2,041 4,200 -------- -------- ------- Cash and cash equivalents at end of year $ 1,712 $ 690 $ 2,041 ======== ======== =======
See accompanying notes to consolidated financial statements. 41 AVIVA PETROLEUM INC. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (DEFICIT) YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (in thousands, except number of shares)
Common Stock ------------------- Additional Total Number of Paid-in Accumulated Stockholders' Shares Amount Capital Deficit Equity (Deficit) ---------- ------ ---------- ------------ ---------------- Balances at December 31, 1995 31,482,716 $1,574 $33,376 $ (7,783) $ 27,167 Net loss - - - (937) (937) ---------- ------ ---------- ----------- -------- Balances at December 31, 1996 31,482,716 1,574 33,376 (8,720) 26,230 Net loss - - - (22,482) (22,482) ---------- ------ ---------- ----------- -------- Balances at December 31, 1997 31,482,716 1,574 33,376 (31,202) 3,748 Issuance of common stock pursuant to amendments of credit agreement (note 5) 1,200,000 60 49 - 109 Issuance of common stock pursuant to the acquisition of Garnet Resources Corporation (note 3) 14,017,416 701 1,437 - 2,138 Net loss - - - (17,078) (17,078) ---------- ------ ---------- ----------- -------- Balances at December 31, 1998 46,700,132 $2,335 $34,862 $(48,280) $(11,083) ========== ====== ========== =========== ========
See accompanying notes to consolidated financial statements. 42 AVIVA PETROLEUM INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1) Summary of Significant Accounting Policies General Aviva Petroleum Inc. and its subsidiaries (the "Company") are engaged in the business of exploring for, developing and producing oil and gas in Colombia and in the United States. The Company's Colombian oil production is sold to Empresa Colombiana de Petroleos, the Colombian national oil company ("Ecopetrol"), while the Company's U.S. oil and gas production is sold to numerous U.S. purchasers (See notes 10 and 13). Oil and gas are the Company's only products and there is substantial uncertainty as to the prices that the Company may receive for its production. A decrease in these prices would affect operating results adversely. Basis of Presentation The Company's consolidated financial statements have been presented on a going concern basis which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. As discussed in note 2 below there is substantial doubt about the Company's ability to continue as a going concern. The consolidated financial statements do not include any adjustments relating to the recoverability and classification of asset carrying amounts or the amount and classification of liabilities that might result should the Company be unable to continue as a going concern. Principles of Consolidation The consolidated financial statements include the accounts of Aviva Petroleum Inc. and its subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. Inventories Inventories consist primarily of tubular goods, oilfield equipment and spares and are stated at the lower of average cost or market. Property and Equipment Under the full cost method of accounting for oil and gas properties, all productive and nonproductive property acquisition, exploration and development costs are capitalized in separate cost centers for each country. Such capitalized costs include lease acquisition costs, delay rentals, geophysical, geological and other costs, drilling, completion and other related costs and direct general and administrative expenses associated with property acquisition, exploration and development activities. Capitalized general and administrative costs include internal costs such as salaries and related benefits paid to employees to the extent that they are directly engaged in such activities, as well as all other directly identifiable general and administrative costs associated with such activities, including rent, utilities and insurance and do not include any costs related to production, general corporate overhead, or similar activities. Capitalized internal general and administrative costs were $60,000 in 1998, $127,000 in 1997 and $129,000 in 1996. Evaluated capitalized costs of oil and gas properties and the estimated future development, site restoration, dismantlement and abandonment costs are amortized by cost center, using the units-of-production method. Total net future site restoration, dismantlement and abandonment costs are estimated to be 1,479,000. Depreciation, depletion and amortization expense per equivalent barrel of production was as follows: 1998 1997 1996 ------ ------ ------ United States $27.00 $ 7.32 $ 5.93 Colombia $ 5.98 $11.59 $11.49 In accordance with the full cost method of accounting, the net capitalized costs of oil and gas properties less related deferred income taxes for each cost center are limited to the sum of the estimated future net revenues from the properties at current prices less estimated future expenditures, discounted at 10%, and unevaluated costs not being amortized, less income tax effects related to differences between the financial and tax bases of the properties, computed on a quarterly basis. The following table summarizes the write-downs of the 43 AVIVA PETROLEUM INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) carrying amounts of the Company's oil and gas properties as a result of ceiling limitations on capitalized costs (in thousands): 1998 1997 ------- ------- Colombia $10,556 $17,829 United States 1,787 2,124 ------- ------- $12,343 $19,953 ======= ======= Depletion expense and limits on capitalized costs are based on estimates of oil and gas reserves which are inherently imprecise and assume current prices for future net revenues. Accordingly, it is reasonably possible that the estimates of reserves quantities and future net revenues could differ materially in the near term from amounts currently estimated. Moreover, a future decrease in the prices the Company receives for its oil and gas production or downward reserve adjustments could, for either the U.S. or Colombian cost centers, result in a ceiling test write-down that is significant to the Company's operating results. Gains and losses on sales of oil and gas properties are not recognized in income unless the sale involves a significant portion of the reserves associated with a particular cost center. Capitalized costs associated with unevaluated properties are excluded from amortization until it is determined whether proved reserves can be assigned to such properties or until the value of the properties is impaired. Unevaluated costs of $532,000 and $251,000 were excluded from amortization at December 31, 1998 and 1997, respectively. Unevaluated properties are assessed quarterly to determine whether any impairment has occurred. The unevaluated costs at December 31, 1998 represent exploration costs and were incurred primarily during the three-year period ended December 31, 1998. Such costs are expected to be evaluated and included in the amortization computation within the next three years. In December 1996, the Company sold its remaining U.S. onshore oil and gas properties for $2,702,000 in cash, net of closing adjustments. The sale involved a significant portion of the reserves associated with the U.S. cost center and, accordingly, the resultant gain on the sale was recognized in the accompanying Consolidated Statement of Operations for 1996 (See note 6). Other property and equipment is depreciated using the straight-line method over the estimated useful lives of the assets. Gas Balancing The Company uses the entitlements method of accounting for gas sales. Gas production taken by the Company in excess of amounts entitled is recorded as a liability to the other joint owners. Excess gas production taken by others is recognized as income to the extent of the Company's proportionate share of the gas sold and a related receivable is recorded from the other joint owners. Interest Expense The Company capitalizes interest costs on qualifying assets, principally unevaluated oil and gas properties. During 1998, 1997 and 1996, the Company capitalized $29,000, $91,000 and $189,000 of interest, respectively. Loss Per Common Share The Company adopted Statement of Financial Accounting Standards No. 128 ("SFAS 128") during the fourth quarter of 1997. Under SFAS 128, basic earnings per share ("EPS") is computed by dividing income available to common shareholders by the weighted-average number of common shares outstanding for the period. Diluted EPS reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock or resulted in the issuance of common stock that then shared in the earnings of the entity. For the years presented herein, basic and diluted EPS are the same since the effects of potential common shares (notes 5 and 7) are antidilutive. 44 AVIVA PETROLEUM INC. AND SUBSIDIARIES Notes to Consolidated Financial Statements (Continued) Income Taxes The Company accounts for income taxes in accordance with Statement of Financial Accounting Standards No. 109 ("Statement 109") which requires recognition of deferred tax assets in certain circumstances and deferred tax liabilities for the future tax consequences of temporary differences between the financial statement carrying amounts and the tax bases of assets and liabilities. Statement of Cash Flows The Company considers all highly liquid debt instruments with original maturities of three months or less to be cash equivalents. The Company paid interest, net of amounts capitalized, of $860,000 in 1998, $641,000 in 1997 and $834,000 in 1996 and paid income taxes of $117,000 in 1998, $212,000 in 1997 and $111,000 in 1996. Fair Value of Financial Instruments The reported values of cash, cash equivalents, accounts receivable and accounts payable approximate fair value due to their short maturities. The reported value of long-term debt approximates its fair value since the applicable interest rate approximates market rates. Foreign Currency Translation The accounts of the Company's foreign operations are translated into United States dollars in accordance with Statement of Financial Accounting Standards No. 52. The United States dollar is used as the functional currency. Exchange adjustments resulting from foreign currency transactions are recognized in expense or income in the current period. Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Comprehensive Income Effective January 1, 1998, the Company adopted Statement of Financial Accounting Standards No. 130, "Reporting Comprehensive Income" which establishes standards for reporting and display of comprehensive income in a full set of general-purpose financial statements. Comprehensive income includes net income and other comprehensive income which is generally comprised of changes in the fair value of available-for-sale marketable securities, foreign currency translation adjustments and adjustments to recognize additional minimum pension liabilities. For each period presented in the accompanying consolidated statement of operations, comprehensive income and net income are the same amount. (2) LIQUIDITY During the last quarter of calendar year 1997 and throughout calendar year 1998, world oil prices have declined dramatically. This decline in oil prices has been particularly severe in Colombia. Colombian oil prices have, during the twenty-four month period ended December 31, 1998, fallen from a high of $22.71 per barrel in January 1997 to $7.50 per barrel in December 1998. Whereas the sale price for crude oil from the Santana contract averaged $19.82 per barrel in 1996 and $17.39 per barrel in 1997, the sale price averaged $10.31 per barrel during calendar year 1998. These price declines have materially and adversely affected the results of operations and the financial position of the Company. During the years ended December 31, 1998, 1997 and 1996, the Company reported net losses of $17.1 million, $22.5 million and $0.9 million, respectively, and declining amounts of net cash provided by (used in) operating activities of $(0.05) million, $1.7 million and $8.9 million, respectively. As of December 31, 1998, the Company's stockholders' deficit was approximately $11.1 million. 45 AVIVA PETROLEUM INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) The Company is highly leveraged with $14.8 million in current debt as of December 31, 1998, pursuant to bank credit facilities with ING (U.S.) Capital Corporation ("ING Capital") and Chase Bank of Texas, N.A. ("Chase"), as more fully described in note 5. As of December 31, 1998, the Company is not in compliance with various covenants under the bank credit facilities. Furthermore, assuming no change in its capital structure, the Company does not have the financial resources to maintain the minimum escrow balance required under the bank credit facilities beginning March 31, 1999, nor to pay the minimum monthly principal payments of $5.7 million on April 30, 1999, and $281,250 each month thereafter until December 31, 2001. Management of the Company is in discussions with the Company's lenders to restructure the above-referenced debt as set forth below. On February 22, 1999, the Company signed a letter of intent to merge with Sharpe Resources Corporation ("Sharpe"), a publicly traded oil and gas exploration and production company incorporated in Ontario, Canada. Sharpe currently has onshore oil and gas production in the United States from working and overriding royalty interests in over 115 wells on 107 properties in 4 states which include Texas, Oklahoma, New Mexico and Wyoming. Sharpe's offshore Gulf of Mexico production is from its operated interests in Matagorda One and Matagorda Two properties located offshore Matagorda Island, Texas in 48 feet of water. Sharpe's principal office is located in Houston, Texas. The proposed arrangements contemplate that Sharpe will be the parent company following the merger, that each six shares of Company Common Stock will be converted into one share of Sharpe Common Stock, and that the Company's lenders will restructure the Company's indebtedness to them. Such debt restructuring may include the conversion of a portion of the debt to a preferred stock position in the merged entity. The proposed arrangements are subject to numerous and substantial contingencies, the most important of which are: (i) completion of negotiations between the Company and Sharpe regarding the structure of the proposed transaction; (ii) preparation, negotiation, execution and delivery of a definitive merger agreement; (iii) approval of the definitive merger agreement and consent to the proposed debt restructuring by the Company's lenders (i.e., ING Capital, Chase and the Overseas Private Investment Corporation); approval of the debt restructuring arrangements by the board of directors of the Company; and approval of the definitive merger agreement by the boards of directors and stockholders of the Company and Sharpe. The proposed merger is subject to preparation, negotiation, execution and delivery of definitive debt restructuring agreements between the Company and its lenders. Management believes that the consummation of this merger will provide the combined companies with the ability to raise additional capital which is necessary to continue operations and proceed with certain development and exploration activities that management believes are essential to the survival of the Company. While management of the Company is pursuing the reorganization of the Company assiduously, its ability to effect such a reorganization is dependent upon the acquiescence of the Company's lenders and Sharpe, matters that are beyond the control of the Company. In particular, the Company's lenders must: (i) consent to waive the defaults of the Company under its bank credit facilities pending preparation, negotiation, execution and delivery of a definitive merger agreement and a definitive debt restructuring agreement and pending receipt of stockholder approvals of the definitive merger agreement; (ii) agree to debt restructuring arrangements that are acceptable to Sharpe; and (iii) negotiate, execute and deliver a definitive debt restructuring agreement. The Company's lenders have not yet and may not ever agree to a restructuring of the Company's debt. If the Company is unable to consummate the merger, then, in the absence of another business transaction or debt restructuring, the Company cannot maintain compliance with nor make principal payments required by the bank credit facilities and, accordingly, the lenders could declare a default, accelerate all amounts outstanding, and attempt to realize upon the collateral securing the debt. As a result of this uncertainty, management believes there is substantial doubt about the Company's ability to continue as a going concern. 46 AVIVA PETROLEUM INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) (3) GARNET MERGER On October 28, 1998, the Company completed the merger of Garnet Resources Corporation ("Garnet") with one of the Company's subsidiaries. As a result of the merger, the Company now owns over 99% of the Colombian joint operations. Additionally, the Company now holds a 2% carried working interest in an oil and gas Petroleum Prospecting License in Papua New Guinea. The merger arrangements included Aviva refinancing Garnet's 99.24% owned subsidiary's net outstanding debt to Chase Bank of Texas, N.A. ("Chase") which is guaranteed by the U.S. Overseas Private Investment Corporation ("OPIC"), issuing approximately 1.1 million and 12.9 million new Aviva common shares to Garnet shareholders and Garnet debenture holders, respectively, and canceling Garnet's $15 million of 9.5% subordinated debentures due December 21, 1998. (See note 5 for further details.) The merger was accounted for as a "purchase" of Garnet for financial accounting purposes with Aviva's subsidiary as the surviving entity. The purchase price of Garnet, approximately $9.9 million, consists of $2.4 million related to the issuance of 14 million shares of Aviva's common stock at $0.167 per share plus merger costs and the assumption of approximately $6.0 million of net debt and $1.5 million of current and other liabilities. A summary of the assets acquired and liabilities assumed as of October 28, 1998 follows (in thousands): Current assets $ 1,659 Oil and gas properties 8,250 Current liabilities (1,169) Long term debt (5,954) Other liabilities (346) ------- Fair value of net assets acquired $ 2,440 ======= The following sets forth selected consolidated financial information for the Company on a pro forma basis for the years ended December 31, 1998 and 1997 assuming the Garnet merger had occurred on January 1, 1997. The following selected pro forma combined financial information is based on the historical consolidated statements of operations of Aviva and Garnet as adjusted to give effect to the merger using the purchase method of accounting for business combinations. In addition, the following selected pro forma combined financial information gives effect to the purchase of Garnet debentures by Aviva pursuant to the Debenture Purchase Agreement, the borrowing by Aviva of $15 million pursuant to the Bank loans (as discussed in note 5) and the application of such funds to refinance Aviva's outstanding debt and the debt to Chase of a Garnet subsidiary (as discussed in note 3.) The following selected pro forma combined financial information may not necessarily reflect the financial condition or results of operations of Aviva that would actually have resulted had the merger occurred as of the date and for the periods indicated or reflect the future results of operations of Aviva (in thousands, except per share amounts). 1998 1997 -------- -------- Revenues $ 5,933 $ 18,708 ======== ======== Net loss $(24,466) $(48,262) ======== ======== Basic and diluted net loss per common share $ (0.52) $ (1.03) ======== ======== The above pro forma net losses for the years ended December 31, 1998 and 1997, include combined historical charges for ceiling write-downs of oil and gas producing properties of $17,470,000 and $45,714,000, respectively. 47 AVIVA PETROLEUM INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) (4) OTHER ASSETS A summary of other assets follows: December 31 --------------- (thousands) 1998 1997 ------ ------ Abandonment funds for U.S. offshore properties $1,402 $1,272 Deferred financing charges 113 102 Other 4 4 ------ ------ $1,519 $1,378 ====== ====== (5) LONG TERM DEBT On August 6, 1993, the Company entered into a credit agreement with ING Capital, secured by a mortgage on substantially all U.S. oil and gas assets, a pledge of Colombian assets and the stock of three subsidiaries, pursuant to which ING Capital agreed to loan to the Company up to $25 million, subject to an annually redetermined borrowing base which was predicated on the Company's U.S. and Colombian reserves. As of December 31, 1997, the borrowing base permitted, and the outstanding loan balance was, $7,690,000. The outstanding loan balance has been subject to interest at the prime rate, as defined (7.75% at December 31, 1998) plus 1% or, at the option of the Company, a fixed rate, based on the London Interbank Offered Rate ("LIBOR") plus 2.75%, for a portion or portions of the outstanding debt from time to time. In February 1998, the Company entered into an agreement with ING Capital pursuant to which the outstanding loan balance was paid down to $7,440,000 from $7,690,000, the interest rate was increased to the prime rate, as defined, plus 1.5%, or at the option of the Company, a fixed rate based on LIBOR plus 3%, and the repayment schedule was amended to require monthly payments of 80% of defined monthly cash flows until October 1, 1999, at which time the remaining balance would be due and payable. Additionally, ING Capital reduced to $2 million the minimum amount of consolidated tangible net worth that the Company is required to maintain. As of June 30, 1998, the Company was not in compliance with the above- referenced tangible net worth covenant. Accordingly, on August 6, 1998, the Company entered into an agreement with ING Capital to further amend the credit facility in order to: (i) waive the Company's non-compliance with the tangible net worth covenant through July 1, 1999; (ii) require the Company to consummate the merger with Garnet on or before October 31, 1998; and (iii) provide to the Company a cash advance of $760,000 in order to supplement the Company's existing working capital. As compensation for making the new advance and entering into the new agreement, the Company issued to ING Capital 400,000 new shares of the Company's common stock. On October 28, 1998, concurrently with the consummation of the Garnet merger, Neo Energy, Inc., an indirect subsidiary of the Company, and the Company entered into a Restated Credit Agreement with ING Capital. ING Capital, Chase and OPIC also entered into a Joint Finance and Intercreditor Agreement (the "Intercreditor Agreement") with the Company. ING Capital agreed to loan Neo Energy, Inc. an additional $800,000, bringing the total outstanding balance due ING Capital to $9,000,000. The outstanding balance due to Chase was paid down to $6,000,000 from the $6,350,000 balance owed by Garnet prior to the merger. ING Capital and Chase now share on a 60/40 basis, respectively, all collateral. The ING Capital loan and the Chase loan (the "Bank Credit Facilities") are guaranteed by the Company and its material domestic subsidiaries. Both loans are also secured by the Company's consolidated interest in the Santana contract and related assets in Colombia, a first mortgage on the United States oil and gas properties of the Company and its subsidiaries, a lien on accounts receivable of the Company and its subsidiaries, and a pledge of the capital stock of the Company's subsidiaries. The Chase loan is unconditionally guaranteed by OPIC. 48 AVIVA PETROLEUM INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Borrowings under the ING Capital loan bear interest at LIBOR plus 3.0% per annum. Borrowings under the Chase loan bear interest at the LIBOR rate plus 0.6% per annum. In addition, a guarantee fee of 2.4% per annum on the borrowings under the Chase loan guaranteed by OPIC will be payable to OPIC. Subsequent to consummation of the Garnet merger, Aviva issued to ING Capital 800,000 shares of Aviva common stock and warrants to purchase 1,500,000 shares of Aviva common stock at an exercise price of $0.50 per share in payment of financial advisory fees. The 800,000 shares were valued at their quoted market value on October 28, 1998, the date on which the Bank Credit Facilities were consummated. The warrants were valued using the Black-Scholes option-pricing model. Both amounts are included in debt extinguishment costs in the 1998 consolidated statement of operations. Borrowings under the Bank Credit Facilities are payable as follows: $50,000 per month through March 1999, $5,700,000 in April 1999, and thereafter $281,250 per month until final maturity on December 31, 2001. The terms of the Bank Credit Facilities, among other things, prohibit the Company from merging with another company or paying dividends, limit additional indebtedness, general and administrative expense, sales of assets and investments and require the maintenance of certain minimum financial ratios. As of December 31, 1998, the Company is not in compliance with various covenants under the Bank Credit Facilities. The Company has, therefore, classified all long-term debt as current in the December 31, 1998 consolidated balance sheet. The Company is also required to maintain an escrow account of $250,000 until March 31, 1999. On March 31, 1999 and thereafter, the escrow account must contain the total of the following for the next succeeding three-month period: (i) the amount of the minimum monthly principal payments (as defined in the loan documents), plus (ii) the interest payments due on the combined loans, plus (iii) the amount of all fees due under the loan documents and under the Intercreditor Agreement. In consideration of certain modifications to the above referenced credit agreement in March 1996 the Company paid a fee of $100,000 to ING Capital. (6) INTEREST AND OTHER INCOME (EXPENSE) A summary of interest and other income (expense) follows:
(thousands) 1998 1997 1996 ------ ------ ------ Gain on settlement of litigation $ 720 $ - $ - Interest income 70 138 231 Foreign currency exchange gain (loss) 1 (75) (16) Gain (loss) on sale of assets, net - (15) 651 Other, net 254 74 195 ------ ----- ------ $1,045 $ 122 $1,061 ====== ===== ======
In January 1998, the Company realized a $720,000 gain on the settlement of litigation involving the administration of a take or pay contract settlement. (7) STOCKHOLDERS' EQUITY Quasi-Reorganization Effective December 31, 1992, the Board of Directors of the Company approved a quasi-reorganization which resulted in a reclassification of the accumulated deficit of $70,057,000 at that date to paid-in capital. No adjustments were made to the Company's assets and liabilities since the historical carrying values approximated or did not exceed the estimated fair values. 49 AVIVA PETROLEUM INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Stock Option Plans At December 31, 1998, the Company has two stock option plans, which are described below. The Company applies APB Opinion No. 25 and related Interpretations in accounting for its plans. Accordingly, no compensation cost has been recognized for its stock option plans. Had compensation cost for the Company's stock option plans been determined consistent with FASB Statement No. 123, the Company's net loss and loss per share would have been increased to the pro forma amounts indicated below (in thousands, except per share data):
1998 1997 1996 -------- -------- ------ Net loss As reported $(17,078) $(22,482) $ (937) Pro forma $(17,095) $(22,506) $ (947) Loss per share As reported $ (0.50) $ (0.71) $(0.03) Pro forma $ (0.50) $ (0.71) $(0.03)
At the Annual Meeting of Shareholders held on June 6, 1995, the Company's shareholders approved the adoption of the Aviva Petroleum Inc. 1995 Stock Option Plan (the "Current Plan"). The Current Plan is administered by a committee (the "Committee") composed of two or more outside directors of the Company, who are disinterested within the meaning of Rule 16b-3(c) under the Securities Exchange Act of 1934, as amended (the "Exchange Act"). Except as indicated below and except for non-discretionary grants to non- employee directors, the Committee has authority to determine all terms and provisions under which options are granted pursuant to the Current Plan, including (i) the determination of which employees shall be eligible to receive options, (ii) the number of shares for which an option shall be granted and (iii) the terms and conditions upon which options may be granted. Options will vest at such times and under such conditions as determined by the Committee, as permitted under the Current Plan. An aggregate of up to 1,000,000 shares of the Company's common stock may be issued upon exercise of stock options or in connection with restricted stock awards that may be granted under the Current Plan. The aggregate fair market value (determined at the time of grant) of shares issuable pursuant to incentive stock options which first become exercisable in any calendar year by a participant in the Current Plan may not exceed $100,000. The maximum number of shares of common stock which may be subject to an option or restricted stock grant awarded to a participant in a calendar year cannot exceed 100,000. Incentive stock options granted under the Current Plan may not be granted at a price less than 100% of the fair market value of the common stock on the date of grant (or 110% of the fair market value in the case of incentive stock options granted to participants in the Current Plan holding 10% or more of the voting stock of the Company). Non-qualified stock options may not be granted at a price less than 50% of the fair market value of the common stock on the date of grant. At the Annual Meeting of Shareholders held on June 10, 1997, the Company's shareholders approved the amendment of the Current Plan. The amendment increased the 200,000 shares reserved for options to be awarded to non- employee directors to 400,000 shares. In addition, the amendment provides for the grant, on July 1, 1997, and on each subsequent July 1, to each non- employee director who has served in such capacity for at least the entire preceding calendar year of an option to purchase 5,000 shares of the Company's common stock (the "Annual Option Awards"), exercisable as to 2,500 shares on the first anniversary of the date of grant and as to the remaining shares on the second anniversary thereof. Except for the vesting provisions relating to the Annual Options Awards, the provisions of the Plan relating to vesting of such options, the determination of the exercise prices thereof and other terms of such options remain unchanged. As a result of the adoption of the Current Plan, during 1995 the Company's former Incentive and Non-Statutory Stock Option Plan was terminated as to the grant of new options, but options then outstanding for 258,000 shares of the Company's common stock remain in effect as of December 31, 1998. 50 AVIVA PETROLEUM INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions:
1998 1997 1996 ------ ----- ----- Expected life (years) 10.0 10.0 5.0 Risk-free interest rate 4.8% 6.6% 7.0% Volatility 77.0% 71.0% 77.0% Dividend yield 0.0% 0.0% 0.0%
A summary of the status of the Company's two fixed stock option plans as of December 31, 1998, 1997 and 1996, and changes during the years ended on those dates is presented below:
1998 1997 1996 ------ ----- ----- Weighted- Weighted- Weighted- Average Average Average Shares Exercise Shares Exercise Shares Exercise Fixed Options (000) Price (000) Price (000) Price ------------------- ------ --------- ------ -------- ------ --------- Outstanding at beginning of year 550 $1.53 530 $1.80 716 $1.60 Granted 675 .06 45 .52 20 .74 Forfeited (77) 3.60 (25) 4.95 (206) 1.25 ------ ------ ------ Outstanding at end of year 1,148 .53 550 1.53 530 1.80 ====== ===== ====== Options exercisable at year-end 655 445 401 Weighted-average fair value of options granted during the year $ .05 $ .42 $ .50
The following table summarizes information about fixed stock options outstanding at December 31, 1998:
Options Outstanding Options Exercisable ----------------------------------------------- ---------------------------- Range Number Weighted-Avg. Number of Outstanding Remaining Weighted-Avg. Exercisable Weighted-Avg. Exercise Prices at 12/31/98 Contractual Life Exercise Price at 12/31/98 Exercise Price ------------------ ----------- ---------------- ---------------- ----------- -------------- $ .06 to .17 675,000 9.84 years $ 0.06 209,333 $ 0.06 .51 to .98 223,000 4.59 0.86 195,500 0.91 1.08 to 2.79 250,000 4.24 1.49 250,000 1.49 --------------- --------- ------- $ .06 to 2.79 1,148,000 7.60 0.53 654,833 0.86 =============== ========= =======
(8) SEVERANCE EXPENSE The Board of Directors had charged a committee of the Board with the task of reviewing the Company's general and administrative expenses and making recommendations as to the reduction of such expenses. On March 18, 1996, the Board, acting on one of such committee's recommendations, determined to terminate the employment of the Executive Vice President and Chief Operating Officer of the Company (the "Officer") effective on June 1, 1996. In connection with the severance arrangements between the Company and the Officer, the Company incurred costs of $172,000. 51 AVIVA PETROLEUM INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) On July 25, 1996, the above mentioned committee was dissolved and its function was assumed by the entire Board of Directors. In the third quarter of 1996, the Company incurred an additional $24,000 of severance expense relating to the termination of certain employees affected by the program. (9) INCOME TAXES Income tax expense includes current Colombian income taxes (benefit) of $(4,000) in 1998, $587,000 in 1997 and $709,000 in 1996 and deferred Colombian income taxes (benefit) of $-0- in 1998, $(692,000) in 1997 and $195,000 in 1996. Income tax expense also includes $-0-, $12,000 and $7,000 of state income taxes in 1998, 1997 and 1996, respectively. The Company's effective tax rate differs from the U.S. statutory rate each year principally due to losses without tax benefit. The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 1998 and 1997 follow:
(thousands) 1998 1997 -------- -------- Deferred tax assets - principally net operating loss carryforwards $ 46,028 $ 42,053 Less valuation allowance 46,028 42,053 -------- -------- Net deferred tax assets - - Deferred tax liabilities - - -------- -------- Net deferred tax liability $ - $ - ======== ========
The valuation allowance for deferred tax assets at January 1, 1996 was $39,124,000. The net change in the valuation allowance was a $3,975,000 increase in 1998, a $5,927,000 increase in 1997 and a $2,998,000 decrease in 1996. Subsequently recognized tax benefits relating to the valuation allowance of $33,318,000 for deferred tax assets at January 1, 1993 will be credited to additional paid in capital. At December 31, 1998, the Company and its subsidiaries have aggregate net operating loss carryforwards for U.S. federal income tax purposes of approximately $113,000,000, expiring from 1999 through 2013, which are available to offset future federal taxable income. The utilization of a portion of these net operating losses is subject to an annual limitation of approximately $2,400,000 and a portion may only be utilized by certain subsidiaries of the Company. (10) FINANCIAL INSTRUMENTS AND CREDIT RISK CONCENTRATIONS Financial instruments which are subject to risks due to concentrations of credit consist principally of cash and cash equivalents and receivables. Cash and cash equivalents are placed with high credit quality financial institutions to minimize risk. Receivables are typically unsecured. Historically, the Company has not experienced any material collection difficulties from its customers. The carrying values of cash equivalents, accounts receivable and accounts payable approximate fair value due to the current maturities of these financial instruments. The fair value of the Company's debt cannot be reasonably determined due to uncertainties surrounding the Company's ability to repay (see note 2). Ecopetrol has an option to purchase all of the Company's production in Colombia. For the years ended December 31, 1998, 1997 and 1996, Ecopetrol exercised that option and sales to Ecopetrol accounted for $2,632,000 (79.0%), $7,405,000 (76.1%) and $9,437,000 (68.6%), respectively, of the Company's aggregate oil and gas sales. 52 AVIVA PETROLEUM INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) For the years ended December 31, 1998, 1997 and 1996, sales to one U.S. purchaser accounted for $479,000 (14.4%), $1,516,000 (15.6%) and $1,609,000 (11.7%), respectively, of oil and gas sales. (11) COMMITMENTS AND CONTINGENCIES The Company is engaged in ongoing operations on the Santana contract in Colombia. The contract obligations have been met, however, the Company may recomplete certain existing wells and engage in various other projects. The Company's share of the estimated future costs of these activities is approximately $0.6 million at December 31, 1998. Failure to fund certain expenditures could result in the forfeiture of all or part of the Company's interest in this contract. Any substantial increases in the amounts of the above referenced expenditures could adversely affect the Company's ability to meet these obligations. The Company will most likely fund the recompletion of certain wells through arrangements with service companies whereby the services are paid for with proceeds from the sale of incremental oil production. Any miscellaneous projects will be funded using cash provided from operations. Risks that could adversely affect funding of such activities include, among others, a decrease in the Company's borrowing base, delays in obtaining the required environmental approvals and permits, cost overruns, failure to produce the reserves as projected or a further decline in the sales price of oil. Depending on the results of future exploration and development activities, substantial expenditures which have not been included in the Company's cash flow projections may be required. On August 3, 1998, leftist Colombian guerrillas inflicted significant damage on the Company's oil processing and storage facilities at the Mary field, and to a lesser extent, at the Linda facilities. The Colombian army guards the Company's operations; however, there can be no assurance that the Company's operations will not be the target of guerrilla attacks in the future. The damage resulting from the above referenced attack was covered by insurance. There can be no assurance that such coverage will remain available or affordable. Under the terms of the contracts with Ecopetrol, 25% of all revenues from oil sold to Ecopetrol is paid in Colombian pesos which may only be utilized in Colombia. To date, the Company has experienced no difficulty in repatriating the remaining 75% of such payments, which are payable in U.S. dollars. Activities of the Company with respect to the exploration, development and production of oil and natural gas are subject to stringent foreign, federal, state and local environmental laws and regulations, including but not limited to the Oil Pollution Act of 1990, the Outer Continental Shelf Lands Act, the Federal Water Pollution Control Act, the Resource Conservation and Recovery Act and the Comprehensive Environmental Response, Compensation, and Liability Act. Such laws and regulations have increased the cost of planning, designing, drilling, operating and abandoning wells. In most instances, the statutory and regulatory requirements relate to air and water pollution control procedures and the handling and disposal of drilling and production wastes. Although the Company believes that compliance with environmental laws and regulations will not have a material adverse effect on the Company's future operations or earnings, risks of substantial costs and liabilities are inherent in oil and gas operations and there can be no assurance that significant costs and liabilities, including civil or criminal penalties for violations of environmental laws and regulations, will not be incurred. Moreover, it is possible that other developments, such as stricter environmental laws and regulations or claims for damages to property or persons resulting from the Company's operations, could result in substantial costs and liabilities. The Company's policy is to accrue environmental and restoration related costs once it is probable that a liability has been incurred and the amount can be reasonably estimated. The Company is involved in certain litigation involving its oil and gas activities, but unrelated to environmental contamination issues. Management of the Company believes that these litigation matters will not have any material adverse effect on the Company's financial condition or results of operations. 53 AVIVA PETROLEUM INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) The Company has one lease for office space in Dallas, Texas, which expires in January 2002. Rent expense relating to the lease was $90,000, $83,000 and $84,000 for 1998, 1997 and 1996, respectively. Future minimum payments under the lease are: 1999 - $96,000; 2000 - $102,000; 2001 - $102,000; and 2002 - $9,000. (12) GAS BALANCING As of December 31, 1998 and 1997, other joint owners had sold net gas with a volume equivalent of approximately 2,000 thousand cubic feet ("MCF") (with an estimated value of $4,000 included in other assets), for which the Company is generally entitled to be repaid in volumes ("underproduced"). As of December 31, 1998 and 1997, the Company had sold net gas with a volume equivalent of approximately 444,000 MCF and 458,000 MCF (with an estimated value of $725,000 and $748,000 included in gas balancing obligations and other), respectively, for which the other joint owners are entitled generally to be repaid in volumes ("overproduced"). In certain instances the parties have the option of requesting payment in cash. In connection with the sale of the Company's U.S. onshore properties in December 1996, approximately 384,000 MCF for which the Company was underproduced and approximately 337,000 MCF for which the Company was overproduced were assumed by the buyer of such properties. In 1997, the Company reacquired from the aforementioned buyer for $98,000 in cash approximately 196,000 MCF for which the Company was overproduced. 54 AVIVA PETROLEUM INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) (13) GEOGRAPHIC AREA INFORMATION The Company is engaged in the business of exploring for, developing and producing oil and gas in the United States and Colombia. Information about the Company's operations in different geographic areas as of and for the years ended December 31, 1998, 1997 and 1996 follows:
(Thousands) United States Colombia Total -------- --------- --------- 1998 ---- Oil and gas sales $ 700 $ 2,632 $ 3,332 ------- -------- -------- Expense: Production 1,259 2,266 3,525 Depreciation, depletion and amortization 1,556 1,596 3,152 Write-down of oil and gas properties 1,787 10,556 12,343 General and administrative 1,042 32 1,074 Provision for losses on accounts receivable 420 - 420 ------- -------- -------- 6,064 14,450 20,514 ------- -------- -------- Interest and other income (expense), net 768 277 1,045 Interest expense (346) (402) (748) ------- -------- -------- Loss before income taxes and extraordinary item (4,942) (11,943) (16,885) Income tax benefit - 4 4 ------- -------- -------- Loss before extraordinary item (4,942) (11,939) (16,881) Extraordinary item - debt extinguishment - (197) (197) ------- -------- -------- Net loss $(4,942) $(12,136) $(17,078) ======= ======== ======== Identifiable assets $ 1,906 $ 7,387 $ 9,293 ======= ======== Corporate assets-cash, cash equivalents and restricted cash balances 2,129 -------- Total assets $ 11,422 ========
55 AVIVA PETROLEUM INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(Thousands) United States Colombia Total ------- -------- -------- 1997 ---- Oil and gas sales $ 2,321 $ 7,405 $ 9,726 ------- -------- -------- Expense: Production 1,262 2,973 4,235 Depreciation, depletion and amortization 1,009 5,058 6,067 Write-down of oil and gas properties 2,124 17,829 19,953 General and administrative 1,499 11 1,510 ------- -------- -------- 5,894 25,871 31,765 ------- -------- -------- Interest and other income (expense), net 92 30 122 Interest expense (399) (259) (658) ------- -------- -------- Loss before income taxes (3,880) (18,695) (22,575) Income (taxes) benefit (12) 105 93 ------- -------- -------- Net loss $(3,892) $(18,590) $(22,482) ======= ======= ======== Identifiable assets $ 3,789 $ 11,966 $ 15,755 ======== ======== Corporate assets-cash and cash equivalents 690 -------- Total assets $ 16,445 ======== 1996 ---- Oil and gas sales $ 4,313 $ 9,437 $ 13,750 ------- -------- -------- Expense: Production 1,926 2,908 4,834 Depreciation, depletion and amortization 1,750 5,589 7,339 General and administrative 1,539 15 1,554 Severance 196 - 196 ------- -------- -------- 5,411 8,512 13,923 ------- -------- -------- Interest and other income (expense), net 894 167 1,061 Interest expense (355) (459) (814) Debt refinancing expense - (100) (100) ------- -------- -------- Income (loss) before income taxes (559) 533 (26) Income taxes (7) (904) (911) ------- -------- -------- Net loss $ (566) $ (371) $ (937) ======= ======== ======== Identifiable assets $ 6,838 $ 34,065 $ 40,903 ======= ======== Corporate assets-cash and cash equivalents 2,041 -------- Total assets $ 42,944 ========
56 AVIVA PETROLEUM INC. AND SUBSIDIARIES Supplementary Information Related to Oil and Gas Producing Activities (UNAUDITED) The following information relating to the Company's oil and gas activities is presented in accordance with Statement of Financial Accounting Standards No. 69. The Financial Accounting Standards Board has determined the information is necessary to supplement, although not required to be a part of, the basic financial statements. Capitalized costs and accumulated depreciation, depletion and amortization relating to oil and gas producing activities were as follows:
(Thousands) United States Colombia Total -------- -------- ------- December 31, 1998 - ----------------- Unevaluated oil and gas properties $ 158 $ 374 $ 532 Proved oil and gas properties 13,114 54,990 68,104 ------- ------- ------- Total capitalized costs 13,272 55,364 68,636 Less accumulated depreciation, depletion and amortization 13,947 49,947 63,894 ------- ------- ------- Capitalized costs, net $ (675) $ 5,417 $ 4,742 ======= ======= ======= December 31, 1997 - ----------------- Unevaluated oil and gas properties $ 142 $ 109 $ 251 Proved oil and gas properties 12,075 48,710 60,785 ------- ------- ------- Total capitalized costs 12,217 48,819 61,036 Less accumulated depreciation depletion and amortization 10,622 38,725 49,347 ------- ------- ------- Capitalized costs, net $ 1,595 $10,094 $11,689 ======= ======= =======
57 AVIVA PETROLEUM INC. AND SUBSIDIARIES Supplementary Information Related to Oil and Gas Producing Activities (UNAUDITED) (CONTINUED) Costs incurred in oil and gas property acquisition, exploration and development activities were as follows:
(Thousands) United States Colombia Total ------ -------- ------ 1998 - ---- Exploration $ 15 $ 136 $ 151 Development 1,039 209 1,248 Acquisition of Garnet properties - 8,250 8,250 ------ ------ ------ Total costs incurred $1,054 $8,595 $9,649 ====== ====== ====== 1997 - ---- Exploration $ 25 $ 470 $ 495 Development 176 2,085 2,261 ------ ------ ------ Total costs incurred $ 201 $2,555 $2,756 ====== ====== ====== 1996 - ---- Exploration $ - $1,382 $1,382 Development 3,239 4,030 7,269 ------ ------ ------ Total costs incurred $3,239 $5,412 $8,651 ====== ====== ======
58 AVIVA PETROLEUM INC. AND SUBSIDIARIES SUPPLEMENTARY INFORMATION RELATED TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (CONTINUED) The following schedule presents the Company's estimate of its proved oil and gas reserves. The proved oil and gas reserves in Colombia and the United States were determined by independent petroleum engineers, Huddleston & Co., Inc. and Netherland, Sewell & Associates, Inc., respectively. The figures presented are estimates of reserves which may be expected to be recovered commercially at current prices and costs. Estimates of proved developed reserves include only those reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. Estimates of proved undeveloped reserves include only those reserves which are expected to be recovered on undrilled acreage from new wells which are reasonably certain of production when drilled or from presently existing wells which could require relatively major expenditures to effect recompletion.
Changes in the Estimated Quantities of Reserves ----------------------------------------------- United States Colombia Total ------ -------- ----- Year ended December 31, 1998 - ---------------------------- Oil (Thousands of barrels) Proved reserves: Beginning of period 195 1,476 1,671 Revisions of previous estimates (143) (200) (343) Acquisition of Garnet - 1,331 1,331 Production (44) (255) (299) ----- ----- ----- End of period 8 2,352 2,360 ===== ===== ===== Proved developed reserves, end of period 8 2,352 2,360 ===== ===== ===== Gas (Millions of cubic feet) Proved reserves: Beginning of period 1,119 - 1,119 Revisions of previous estimates (1,054) - (1,054) Production (61) - (61) ----- ----- ----- End of period 4 - 4 ===== ===== ===== Proved developed reserves, end of period 4 - 4 ===== ===== =====
59 AVIVA PETROLEUM INC. AND SUBSIDIARIES Supplementary Information Related to Oil and Gas Producing Activities (UNAUDITED) (CONTINUED)
Changes in the Estimated Quantities of Reserves ----------------------------------------------- United States Colombia Total ------ -------- ----- Year ended December 31, 1997 - ---------------------------- Oil (Thousands of barrels) Proved reserves: Beginning of period 305 2,817 3,122 Revisions of previous estimates (34) (915) (949) Production (76) (426) (502) ----- ----- ----- End of period 195 1,476 1,671 ===== ===== ===== Proved developed reserves, end of period 195 1,476 1,671 ===== ===== ===== Gas (Millions of cubic feet) Proved reserves: Beginning of period 1,682 - 1,682 Revisions of previous estimates (247) - (247) Production (316) - (316) ----- ----- ----- End of period 1,119 - 1,119 ===== ===== ===== Proved developed reserves, end of period 1,119 - 1,119 ===== ===== =====
60 AVIVA PETROLEUM INC. AND SUBSIDIARIES Supplementary Information Related to Oil and Gas Producing Activities (UNAUDITED) (CONTINUED)
Changes in the Estimated Quantities of Reserves ----------------------------------------------- United States Colombia Total ------ -------- ----- Year ended December 31, 1996 - ---------------------------- Oil (Thousands of barrels) Proved reserves: Beginning of period 564 3,255 3,819 Revisions of previous estimates (74) 38 (36) Discoveries and extensions 6 - 6 Sales of reserves (97) - (97) Production (94) (476) (570) ----- ----- ----- End of period 305 2,817 3,122 ===== ===== ===== Proved developed reserves, end of period 305 2,008 2,313 ===== ===== ===== Gas (Millions of cubic feet) Proved reserves: Beginning of period 7,037 - 7,037 Revisions of previous estimates (770) - (770) Discoveries and extensions 23 - 23 Sales of reserves (3,462) - (3,462) Production (1,146) - (1,146) ----- ----- ----- End of period 1,682 - 1,682 ===== ===== ===== Proved developed reserves, end of period 1,682 - 1,682 ===== ===== =====
61 AVIVA PETROLEUM INC. AND SUBSIDIARIES Supplementary Information Related to Oil and Gas Producing Activities (UNAUDITED) (CONTINUED) The following schedule is a standardized measure of the discounted net future cash flows applicable to proved oil and gas reserves. The future cash flows are based on estimated oil and gas reserves utilizing prices and costs in effect as of the applicable year end, discounted at ten percent per year and assuming continuation of existing economic conditions. The standardized measure of discounted future net cash flows, in the Company's opinion, should be examined with caution. The schedule is based on estimates of the Company's proved oil and gas reserves prepared by independent petroleum engineers. Reserve estimates are, however, inherently imprecise and 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. Therefore, the standardized measure of discounted future net cash flows does not necessarily reflect the fair value of the Company's proved oil and gas properties.
(Thousands) United States Colombia Total ------ -------- -------- At December 31, 1998: - --------------------- Future gross revenues $ 78 $ 17,645 $ 17,723 Future production costs (77) (10,242) (10,319) Future development costs, including abandonment of U.S. offshore platforms (969) (570) (1,539) ----- -------- -------- Future net cash flows before income taxes (968) 6,833 5,865 Future income taxes - - - ----- -------- -------- Future net cash flows after income taxes (968) 6,833 5,865 Discount at 10% per annum 136 (1,382) (1,246) ----- -------- -------- Standardized measure of discounted future net cash flows $(832) $ 5,451 $ 4,619 ===== ======== ========
62 AVIVA PETROLEUM INC. AND SUBSIDIARIES Supplementary Information Related to Oil and Gas Producing Activities (UNAUDITED) (CONTINUED)
(Thousands) United States Colombia Total ------ -------- ----- At December 31, 1997: - --------------------- Future gross revenues $ 6,009 $ 21,124 $ 27,133 Future production costs (3,548) (7,709) (11,257) Future development costs, including abandonment of U.S. offshore platforms (970) (555) (1,525) ------- -------- -------- Future net cash flows before income taxes 1,491 12,860 14,351 Future income taxes - - - ------- -------- -------- Future net cash flows after income taxes 1,491 12,860 14,351 Discount at 10% per annum (38) (2,893) (2,931) ------- -------- -------- Standardized measure of discounted future net cash flows $ 1,453 $ 9,967 $ 11,420 ======= ======== ======== At December 31, 1996: - --------------------- Future gross revenues $14,070 $ 63,666 $ 77,736 Future production costs (6,128) (11,362) (17,490) Future development costs, including abandonment of U.S. offshore platforms (970) (3,067) (4,037) ------- -------- -------- Future net cash flows before income taxes 6,972 49,237 56,209 Future income taxes (51) (1,052) (1,103) ------- -------- -------- Future net cash flows after income taxes 6,921 48,185 55,106 Discount at 10% per annum (993) (9,513) (10,506) ------- -------- -------- Standardized measure of discounted future net cash flows $ 5,928 $ 38,672 $ 44,600 ======= ======== ========
63 AVIVA PETROLEUM INC. AND SUBSIDIARIES Supplementary Information Related to Oil and Gas Producing Activities (UNAUDITED) (CONTINUED) The following schedule summarizes the changes in the standardized measure of discounted future net cash flows.
(Thousands) 1998 1997 1996 ------ ------ ------ Sales of oil and gas, net of production costs $ 192 $ (5,491) $(8,916) Sales of reserves in place - - (3,924) Development costs incurred that reduced future development costs - 801 3,043 Accretion of discount 1,142 4,547 3,577 Discoveries and extensions - - 87 Purchase of reserves in place 2,998 - - Revisions of previous estimates: Changes in price (9,585) (24,154) 13,468 Changes in quantities (539) (7,054) 153 Changes in future development costs (448) 1,175 (86) Changes in timing and other changes (561) (3,878) 2,303 Changes in estimated income taxes - 874 (540) ------- -------- ------- Net increase (decrease) (6,801) (33,180) 9,165 Balances at beginning of year 11,420 44,600 35,435 ------- -------- ------- Balances at end of year $ 4,619 $ 11,420 $44,600 ======= ======== =======
64 INDEX TO EXHIBITS
Sequentially Numbered Number Description of Exhibit Page - ------ ---------------------- ------------ *2.1 Agreement and Plan of Merger dated as of June 24, 1998, by and among Aviva Petroleum Inc., Aviva Merger Inc. and Garnet Resources Corporation (filed as exhibit 2.1 to the Registration Statement on Form S-4, File No. 333-58061, and incorporated herein by reference). *2.2 Debenture Purchase Agreement dated as of June 24, 1998, between Aviva Petroleum Inc. and the Holders of the Debentures named therein (filed as exhibit 2.2 to the Registration Statement on Form S-4, file No. 333-58061, and incorporated herein by reference). *3.1 Restated Articles of Incorporation of the Company dated July 25, 1995 (filed as exhibit 3.1 to the Company's annual report on Form 10-K for the year ended December 31, 1995, File No. 0-22258, and incorporated herein by reference). *3.2 Amended and Restated Bylaws of the Company, as amended as of January 23, 1995 (filed as exhibit 3.2 to the Company's annual report on Form 10-K for the year ended December 31, 1994, File No. 0-22258, and incorporated herein by reference). *10.1 Risk Sharing Contract between Empresa Colombiana de Petroleos ("Ecopetrol"), Argosy Energy International ("Argosy") and Neo Energy, Inc. ("Neo") (filed as exhibit 10.1 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.2 Contract for Exploration and Exploitation of Sector Number 1 of the Aporte Putumayo Area ("Putumayo") between Ecopetrol and Cayman Corporation of Colombia dated July 24, 1972 (filed as exhibit 10.2 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.3 Operating Agreement for Putumayo between Argosy and Neo dated September 16, 1987 and amended on January 4, 1989 and February 23, 1990 (filed as exhibit 10.3 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.4 Operating Agreement for the Santana Area ("Santana") between Argosy and Neo dated September 16, 1987 and amended on January 4, 1989, February 23, 1990 and September 28, 1992 (filed as exhibit 10.4 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.5 Agreement of Withdrawal from Argosy dated September 16, 1987 by and among Argosy, Neo, and Argosy Energy Incorporated, as general partners; and Parkside Investments, Richard Shane McKnight, Douglas W. Fry, P-5 Ltd., GO-DEO, Inc., Dale E. Armstrong, Richard Shane McKnight, The Yvonne McKnight Trust, and William Gaskin, as limited partners (filed as exhibit 10.5 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.6 Option Agreement dated September 16, 1987 between the general and limited partners of Argosy and Neo (filed as exhibit 10.6 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.7 Escrow Agreement between Argosy, Neo, Overseas Private Investment Corporation and The Chase Manhattan Bank dated March 15, 1988 and amended on May 31, 1990 (filed as exhibit 10.7 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.8 Santana Block A Relinquishment dated March 6, 1990 between Ecopetrol, Argosy and Neo (filed as exhibit 10.8 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.9 Purchase Sale - Transportation and Commercialization of the Santana Crude between Ecopetrol, Argosy and Neo (filed as exhibit 10.9 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.10 La Fragua Association Contract dated June 1, 1992 between Ecopetrol, Argosy and Neo (filed as exhibit 10.10 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference).
1
Sequentially Numbered Number Description of Exhibit Page - ------ ---------------------- ------------ *10.11 Operating Agreement for the La Fragua Area between Argosy and Neo dated April 15, 1992 (filed as exhibit 10.11 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.12 Employment Agreement between the Company and Ronald Suttill dated November 29, 1991 (filed as exhibit 10.12 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.13 Employee Stock Option Plan of the Company (filed as exhibit 10.13 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.14 Letter agreement dated January 6, 1993 between NationsBank Investment Banking and the Company (filed as exhibit 10.14 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.15 Letter agreement dated March 3, 1993 between EnCap Investments L.C. and the Company (filed as exhibit 10.15 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.16 Credit Agreement dated August 6, 1993 between the Company, Aviva America, Inc. ("Aviva America"), Neo and Internationale Nederlanden Bank N.V., New York Branch ("ING Capital") (filed as exhibit 10.16 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.17 Subordination Agreement dated August 6, 1993 between the Company, Aviva America, Aviva Operating Company ("Aviva Operating"), Neo and ING Capital (filed as exhibit 10.17 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.18 Stock Pledge Agreement dated August 6, 1993 between the Company and ING Capital (filed as exhibit 10.18 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.19 Stock Pledge Agreement dated August 6, 1993 between Aviva America and ING Capital (filed as exhibit 10.19 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.20 Guaranty dated August 6, 1993 made by the Company in favor of ING Capital (filed as exhibit 10.20 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.21 Guaranty dated August 6, 1993 made by Aviva America in favor of ING Capital (filed as exhibit 10.21 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.22 Guaranty dated August 6, 1993 made by Aviva Operating in favor of ING Capital (filed as exhibit 10.22 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.23 Form of Subscription Agreement dated June 18, 1993 between the Company and purchasers of 12,884,207 shares of common stock ("Purchasers") (filed as exhibit 10.23 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.24 Option Agreement between RBS and Aviva Energy Inc. ("Aviva Energy") dated July 1, 1993 (filed as exhibit 10.24 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.25 Option Agreement between Aviva Energy and Purchasers dated July 1, 1993 (filed as exhibit 10.25 to the Company's Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference). *10.26 Santana Block B 50% relinquishment dated September 13, 1993 between Ecopetrol, Argosy and Neo (filed as exhibit 10.26 to the Company's annual report on Form 10-K for the year ended December 31, 1993, File No. 0-22258, and incorporated herein by reference).
2
Sequentially Numbered Number Description of Exhibit Page - ------ ---------------------- ------------ *10.27 Amendment to La Fragua Association contract dated December 2, 1993 between Ecopetrol, Argosy and Neo (filed as exhibit 10.27 to the Company's annual report on Form 10-K for the year ended December 31, 1993, File No. 0-22258, and incorporated herein by reference). *10.28 Letter from Ecopetrol dated February 24, 1994 and Resolution dated February 18, 1994 revising pipeline tariff (filed as exhibit 10.28 to the Company's annual report on Form 10-K for the year ended December 31, 1993, File No. 0-22258, and incorporated herein by reference). *10.29 Aviva Petroleum Inc. 401(k) Retirement Plan effective March 1, 1992 (filed as exhibit 10.29 to the Company's annual report on Form 10-K for the year ended December 31, 1993, File No. 0-22258, and incorporated herein by reference). *10.30 Relinquishment of Putumayo dated December 1, 1993 (filed as exhibit 10.30 to the Company's annual report on Form 10-K for the year ended December 31, 1993, File No. 0-22258, and incorporated herein by reference). *10.31 Amendment to ING Capital agreement dated March 28, 1994 (filed as exhibit 10.31 to the Company's annual report on Form 10-K for the year ended December 31, 1993, File No. 0-22258, and incorporated herein by reference). *10.32 Deposit Agreement dated September 15, 1994 between the Company and Chemical Shareholder Services Group, Inc. (filed as exhibit 10.29 to the Company's Registration Statement on Form S-1, File No. 33-82072, and incorporated herein by reference). *10.33 Form of Registration Agreement dated as of September 15, 1994 between the Company and Shearson Lehman Brothers Inc. (filed as exhibit 10.30 to the Company's Registration Statement on Form S-1, File No. 33-82072, and incorporated herein by reference). *10.34 Form of Registration Agreement and Limited Power of Attorney dated as of September 15, 1994 between the Company and all other Selling Shareholders (filed as exhibit 10.31 to the Company's Registration Statement on Form S-1, File No. 33-82072, and incorporated herein by reference). *10.35 Form of Broker-Dealer Agreement dated as of October 19, 1994 between the Company and Petrie Parkman & Co. (filed as exhibit 10.32 to the Company's Registration Statement on Form S-1, File No. 33-82072, and incorporated herein by reference). *10.36 Purchase and Sale Agreement dated July 22, 1994 by and between Newfield Exploration Company and Aviva America (filed as exhibit 10.33 to the Company's Registration Statement on Form S-1, File No. 33-82072, and incorporated herein by reference). *10.37 Letter from ING Capital dated October 27, 1994, amending Section 5.2 (n) of the Credit Agreement (filed as exhibit 10.37 to the Company's annual report on Form 10-K for the year ended December 31, 1994, File No. 0-22258, and incorporated herein by reference). *10.38 Letter from Ecopetrol dated December 28, 1994, accepting relinquishment of Putumayo (filed as exhibit 10.38 to the Company's annual report on Form 10-K for the year ended December 31, 1994, File No. 0-22258, and incorporated herein by reference). *10.39 Letter from Ecopetrol dated February 28, 1995, accepting modifications to the La Fragua Association Contract (filed as exhibit 10.39 to the Company's annual report on Form 10-K for the year ended December 31, 1994, File No. 0-22258, and incorporated herein by reference). *10.40 Amendment to ING Capital Credit Agreement dated March 7, 1995 (filed as exhibit 10.40 to the Company's annual report on Form 10-K for the year ended December 31, 1994, File No. 0-22258, and incorporated herein by reference). *10.41 Santana Crude Oil Sale Contract dated March 19, 1995 (filed as exhibit 10.41 to the Company's annual report on Form 10-K for the year ended December 31, 1994, File No. 0-22258, and incorporated herein by reference). *10.42 Employment Agreement between the Company and Ronald Suttill effective January 1, 1995 (filed as exhibit 10.1 to the Company's quarterly report on Form 10-Q for the quarter ended March 31, 1995, File No. 0-22258, and incorporated herein by reference).
3
Sequentially Numbered Number Description of Exhibit Page - ------ ---------------------- ------------ *10.43 Employment Agreement between the Company and Robert C. Boyd effective January 1, 1995 (filed as exhibit 10.2 to the Company's quarterly report on Form 10-Q for the quarter ended March 31, 1995, File No. 0-22258, and incorporated herein by reference). *10.44 Amendment to ING Capital Credit Agreement dated June 9, 1995 (filed as exhibit 10.3 to the Company's quarterly report on Form 10-Q for the quarter ended June 30, 1995, File No. 0-22258, and incorporated herein by reference). *10.45 Amendment to the Incentive and Nonstatutory Stock Option Plan of the Company (filed as exhibit 10.4 to the Company's quarterly report on Form 10-Q for the quarter ended September 30, 1995, File No. 0-22258, and incorporated herein by reference). *10.46 Aviva Petroleum Inc. 1995 Stock Option Plan (filed as exhibit 10.5 to the Company's quarterly report on Form 10-Q for the quarter ended September 30, 1995, File No. 0-22258, and incorporated herein by reference). *10.47 Yuruyaco Association Contract dated September 20, 1995 between Ecopetrol, Argosy and Neo (filed as exhibit 10.6 to the Company's quarterly report on Form 10-Q for the quarter ended September 30, 1995, File No. 0-22258, and incorporated herein by reference). *10.48 Letter from ING Capital dated November 3, 1995, amending Section 5.2 (n) of the Credit Agreement (filed as exhibit 10.7 to the Company's quarterly report on Form 10-Q for the quarter ended September 30, 1995, File No. 0-22258, and incorporated herein by reference). *10.49 Amendment to the Santana Crude Oil Sale Contract (filed as exhibit 10.49 to the Company's annual report on Form 10-K for the year ended December 31, 1995, File No. 0-22258, and incorporated herein by reference). *10.50 Amendment to the La Fragua Association Contract dated April 27, 1995 (filed as exhibit 10.50 to the Company's annual report on Form 10-K for the year ended December 31, 1995, File No. 0-22258, and incorporated herein by reference). *10.51 Santana Block B 25% relinquishment dated October 2, 1995 (file as exhibit 10.51 to the Company's annual report on Form 10-K for the year ended December 31, 1995, File No. 0-22258, and incorporated herein by reference). *10.52 Amendment to the La Fragua Association Contract dated August 1, 1995 (filed as exhibit 10.52 to the Company's annual report on Form 10-K for the year ended December 31, 1995, File No. 0-22258, and incorporated herein by reference). *10.53 Operating Agreement for the Yuruyaco Area between Argosy and Neo dated November 7, 1995 (filed as exhibit 10.53 to the Company's annual report on Form 10-K for the year ended December 31, 1995, File No. 0-22258, and incorporated herein by reference). *10.54 Letter from ING Capital dated March 19, 1996, revising the borrowing base and schedule of principal repayments and Section 5.2 (m) of the Credit Agreement (filed as exhibit 10.54 to the Company's annual report on Form 10-K for the year ended December 31, 1995, File No. 0-22258, and incorporated herein by reference). *10.55 Amendment to the ING Capital Credit Agreement dated March 29, 1996 (filed as exhibit 10.1 to the Company's quarterly report on Form 10-Q for the quarter ended March 31, 1996, File No. 0-22258, and incorporated herein by reference). *10.56 Aviva Petroleum Inc. Severance Benefit Plan (filed as exhibit 10.2 to the Company's quarterly report on Form 10-Q for the quarter ended March 31, 1996, File No. 0-22258, and incorporated herein by reference). *10.57 Amendment to the ING Capital Credit Agreement dated November 22, 1996 (filed as exhibit 10.57 to the Company's annual report on Form 10-K for the year ended December 31, 1996, File No. 0-22258, and incorporated herein by reference). *10.58 Purchase and Sale Agreement dated November 22, 1996 between BWAB Incorporated and Aviva America (filed as exhibit 10.58 to the Company's annual report on Form 10-K for the year ended December 31, 1996, File No. 0-22258, and incorporated herein by reference).
4
Sequentially Numbered Number Description of Exhibit Page - ------ ---------------------- ------------ *10.59 Purchase and Sale Agreement dated December 6, 1996 between Lomak Petroleum Inc. and Aviva America (filed as exhibit 10.59 to the Company's annual report on Form 10-K for the year ended December 31, 1996, File No. 0-22258, and incorporated herein by reference). *10.60 Santana Crude Sale and Purchase Agreement dated February 10, 1997 (filed as exhibit 10.60 to the Company's annual report on Form 10-K for the year ended December 31, 1996, File No. 0-22258, and incorporated herein by reference). *10.61 Aviva Petroleum Inc. 1995 Stock Option Plan, as amended (filed as Appendix A to the Company's definitive Proxy Statement for the Annual Meeting of Shareholders dated June 10, 1997, and incorporated herein by reference). *10.62 Amendment to the ING Capital Credit Agreement dated August 12, 1997 (filed as exhibit 10.2 to the Company's quarterly report on Form 10-Q for the quarter ended June 30, 1997, File No. 0-22258, and incorporated herein by reference). *10.63 Amended and Restated Aviva Petroleum Inc. Severance Benefit Plan dated September 30, 1997 (filed as exhibit 10.3 to the Company's quarterly report on Form 10-Q for the quarter ended September 30, 1997, File No. 0-22258, and incorporated herein by reference). *10.64 Amendment to the ING Capital Credit Agreement dated December 29, 1997 (filed as exhibit 10.64 to the Company's annual report on Form 10-K for the year ended December 31, 1997, File No. 0-22258, and incorporated herein by reference). *10.65 Amendment to the Santana Crude Sale and Purchase Agreement dated January 5, 1998 (filed as exhibit 10.65 to the Company's annual report on Form 10-K for the year ended December 31, 1997, File No. 0-22258, and incorporated herein by reference). *10.66 Amendment to the ING Capital Credit Agreement dated February 13, 1998 (filed as exhibit 10.66 to the Company's annual report on Form 10-K for the year ended December 31, 1997, File No. 0-22258, and incorporated herein by reference). *10.67 Amendment to the ING Capital Credit Agreement dated August 6, 1998 (filed as exhibit 10.1 to the Company's quarterly report on Form 10-Q for the quarter ended June 30, 1998, File No. 0-22258, and incorporated herein by reference). *10.68 Restated Credit Agreement dated as of October 28, 1998, between Neo Energy, Inc., Aviva Petroleum Inc. and ING (U.S.) Capital Corporation (filed as exhibit 99.1 to the Company's Form 8-K dated October 28, 1998, File No. 0-22258, and incorporated herein by reference). *10.69 Joint Finance and Intercreditor Agreement dated as of October 28, 1998, between Neo Energy, Inc., Aviva Petroleum Inc., ING (U.S.) Capital Corporation, Aviva America, Inc., Aviva Operating Company, Aviva Delaware Inc., Garnet Resources Corporation, Argosy Energy Incorporated, Argosy Energy International, Garnet PNG Corporation, the Overseas Private Investment Corporation, Chase Bank of Texas, N.A. and ING (U.S.) Capital Corporation as collateral agent for the creditors (filed as exhibit 99.2 to the Company's Form 8-K dated October 28, 1998, File No. 0-22258, and incorporated herein by reference). **10.70 Amendment to the Santana Crude Sale and Purchase Agreement dated February 16, 1999. **21.1 List of subsidiaries of Aviva Petroleum Inc. **27.1 Financial Data Schedule. - --------------- * Previously Filed ** Filed Herewith
5 EX-10.70 2 AMNDMNT TO SANTANA CRUDE SALE AND PURCHASE AGT Exhibit 10.70 CONTRACT No.: GCI-003-99 SELLER: ARGOSY ENERGY INTERNATIONAL AND OBJECT: SANTANA CRUDE SALE/PURCHASE PERIOD: FEBRUARY 1, 1999 TO DECEMBER 31, 1999 AMOUNT: UNDETERMINED QUANTITY The contracting parties, on one hand, the EMPRESA COLOMBIANA DE PETROLEOS "ECOPETROL", which hereinafter will be called "ECOPETROL", an Industrial and Commercial State owned Company, authorized by Law 165 of 1948 and regulated by its approved statutes by Decree 1209 of 1994, with main headquarters located in the City of Santafe de Bogota, D.C., represented by LUIS AUGUSTO YEPES G., of legal age, identified by Colombian Identity Card No. 19.125.070 issued in Bogota, residing in Bogota, who declares: a. That he acts in his capacity of Vice President and in exercise of legal and internal norms of Ecopetrol.-b. As party of the second part, ARGOSY ENERGY INTERNATIONAL, an existent and organized company in accordance with the laws of the State of Utah, of The United States of America, domiciled in Salt Lake City, State of Utah, with a subidiary established in Colombia, duly constituted by Public Deed number 5323 conceded in the Seventh Notary of Bogota on October 25, 1983, and registered in the Chamber of Commerce of Bogota, under registry No. 200848, on November 23, 1983, represented by SANTIAGO GONZALEZ ANGULO, of legal age, identified by Colombian Identity Card No. 5.584.373, issued in Barrancabermeja, company which henceforth will be designated as THE SELLER, who enter into this purchase and sale contract of Santana Crude, contained in the following clauses: CLAUSE ONE: - - OBJECT AND QUANTITIES. THE SELLER is obliged to sell and to deliver to ECOPETROL, under the conditions here set forth, the crude oil produced under the contract of "Santana" Risk Participation, that corresponds to THE SELLER, in the quantity and quality that is stipulated and in agreement with that provided in Clause Two of this document and that in consequence, ECOPETROL is obliged to receive and pay. PARAGRAPH 1: The "Santana"Risk Participation contract was entered into on May 27, 1987, with effective date that of July 27, 1987, between ECOPETROL AND ARGOSY ENERGY INTERNATIONAL AND NEO ENERGY, INC, which was modified by means of Public Deed No. 00064 dated January 19, 1999, conceded by Notary 50 in Bogota. PARAGRAPH 2: All purchases will be made by ECOPETROL in accordance with the preliminary crude purchasing program agreed upon by the parties for six (6) month periods, that ECOPETROL could modify, giving previous notice to THE SELLER with at least 30 days anticipation. CLAUSE TWO: QUALITY. The quality of the crude, subject matter of this contract, will have the following specifications: a) the gravity of the crude oil will be that with which said crude oil is obtained, through the operations that are carried out for its production. b) The content of water and sediment in the crude oil, cannot be greater than 0.5% in volume and its determination will be made respectively by means of the ASTM-D4377 methods, "water in crude oil by distillation" (Karl Fisher), last revision, ASTM-D473, "sediments in crude and fuel oil by extraction", last revision. The parties agree that the Karl Fisher method will be implemented within a 90 day period as of the subscription of this contract. Meanwhile, the parties will continue using method ASTM D-95. c)The content of sulphur in the crude oil with which said crude oil is obtained, through the operations carried out for its production; its determination will be made by the ASTM - D2622 method, last revision, "sulphur analysis by X-ray". d) The salt content cannot be greater than 20 pounds for each 1,000 barrels of crude oil and its determination will be made by the ASTM - D3230 method, " crude salts (electrometric method), last revision. When any of the previously mentioned parameters are not fulfilled or the previously mentioned specifications are not within the permitted margin, ECOPETROL reserves the right to reject the crude oil. But should ECOPETROL choose to accept with salinity over the specifications, the price of the crude oil will be penalized in accordance with the following chart:
Salinity Content Penalty in U.S. Charged to Pounds per 1,000 Dollars/Barrel Barrels (US$/Barrel) 20.01 30.0 0.160 THE SELLER 30.1 40.0 0.180 THE SELLER 40.1 60.0 0.200 THE SELLER 60.1 80.0 0.220 THE SELLER 80.1 100.0 0.240 THE SELLER
It is understood that THE SELLER will make every effort possible to deliver the contracted crude oil, with a salt content of less than twenty (20) pounds for each one thousand (1,000) barrels of crude oil. e) Whatever variation referring to the quality specifications mentioned previously, that be accepted by both parties, will be consigned in a document subscribed between ECOPETROL Representatives and THE SELLER. CLAUSE THREE: PLACE OF DELIVERY AND OWNERSHIP. The crude oil, subject of this contract, will be turned over by THE SELLER to ECOPETROL in the Santana terminal where the crude will be later measured and analyzed. Then, from the referred point, it will be transported by ECOPETROL to the terminal in Tumaco. The property and risk title will pass from THE SELLER to ECOPETROL at the moment in which the crude oil passes the exit check point of the measuring system located in the Santana Terminal. PARAGRAPH 1: If the Santana Association constructs the Santana-Orito pipeline, the measurement and transfer of the ownership of the crude oil will be made effective in Orito. Also, as of that date, the sales-purchase value of the crude will be modified, as now the tariff for transport from Santana-Orito will not be taken into account, in accordance with Resolution 6031 of February 8, 1994, from the Ministry of Mines and Energy. PARAGRAPH 2: The capacity for receipt of Santana crude will be limited to the capacity of the pipeline, Santana-Orito that exists at that moment. CLAUSE FOUR: DURATION. This agreement will have an initial duration of eleven (11) months counted from the first of February of 1999 until December 31, 1999, and could be extended for additional periods of one (1) year by written agreement between the parties, before the expiration of this contract. CLAUSE FIVE: TRANSPORTATION. For invoicing purposes, the tariff approved by the Ministry of Mines and Energy will be applied based on the total number of barrels transported. It is understood that the Pipeline Transportation Regulation will be incorporated to this contract once the parties approve it and once it has been submitted to the required official approvals. CLAUSE SIX. PRICE. The price that ECOPETROL will pay THE SELLER for the crude is defined in the following manner: Price = Base price plus or minus quality adjustment less transport less handling and marketing. PARAGRAPH 1: The basic price will be the average weighted of the export shipments invoiced by Ecopetrol during that month. PARAGRAPH 2: The quality adjustment that will be applied in this contract, will be for API Gravity and Sulphur content that will be calculated monthly in accordance with the procedure described in Annex 1. PARAGRAPH 3: The transportation cost, Santana-Tumaco, as well as the respective transport tax will be adjusted to that designated by the statutory clauses in force and remain subject to whatever modification introduced by said provisions during the duration of the contract. In accordance with that established in Resolution number 6031 of May 8, 1998, from the Ministry of Mines and Energy, the Santana-Tumaco transport tariff to January 31, 1999, amounts to 1.6809 US$/BL. The amount of the transport tax corresponds to 2% (two percent) of the rate in accordance with that established in Article 17 of Decree 2140 of 1955, adopted as the permanent norm by Law 10 of 1961. Said tax will be paid according to the Law 141 of 1994, which until January 31, 1999, is of 0.0336 US$/Bl. These rates will be readjusted annually according to that established in the previously mentioned Resolution No. 6031. PARAGRAPH 4: The handling and marketing cost will be of 0.165 US$/BL. PARAGRAPH 5: If during one month or consecutive months, there is no exportation of crude, the price would be that of the preceding month (M-1). This will be adjusted in the following month (M + 1) according to the new price calculated for the exports of said month M + 1. The volume of Santana crude received in the corresponding month will be taken and the adjustment for quality will be calculated with the average of price quotations corresponding to the three months preceding the adjusted month (Month M). PARAGRAPH 6. In the event that there are cabotages from the crude Tumaco blend (South Blend), to the Cartagena refinery, the conditions for sale and pricing that Ecopetrol will recognize to the Seller, will be the same obtained by the International Trade Management for the crude blend (FOB Tumaco) received by the Cartagena refinery plus or minus the quality adjustment, less the cost for Santana-Tumaco transport and the respective tax, less marketing (USD 0.165 per barrel). In the event that the Cartagena Refinery purchases the South Blend, without this resulting from a bidding process, the parties will agree on a method to calculate this crude's price. PARAGRAPH 7. Not withstanding that expressed in Paragraph 2, regarding the quality adjustment procedure, the parties can agree to a revision of the crude supply and of the current method used, and they could resort to a mutual agreement on the crude which should be eliminated or added to the current supply. If an agreement is reached, it will be applied to the entire contract. Additionally, the parties could also hire an external consultant who could determine whether to continue with the current method, or whether a new method should be implemented. In the event that the parties do not reach an agreement, the current method will prevail. CLAUSE SEVEN. BILLING AND FORM OF PAYMENT. THE SELLER will bill ECOPETROL in its Bogota offices, within the ten (10) first days of each month, for the crude oil of its ownership, delivered to ECOPETROL during the preceding month, after having deducted the volume corresponding to royalties, contributions and shares. Within seven (7) days of the before-mentioned deadline, ECOPETROL will supply THE SELLER with the information that he requires to draw up the corresponding invoice. The payment will be made on a monthly basis at thirty (30) days from the date of receipt of the invoice by ECOPETROL, prior to that withheld according to law, if there were occasion for it. Twenty-five percent ( 25% ) of the amount will be paid in Colombian Pesos and seventy-five percent (75%) in United States Dollars. The invoicing will be made on the basis of net volume, free of water and sediment, adjusted to 60 degrees F. For the portion in Colombian Pesos, the representative exchange rate for the market will be used according to the Banking Superintendency, calculated as an arithmetical average, corresponding to crude deliveries. PARAGRAPH 1: In the event of delay in payment of that stipulated in the contract, for the payment in Dollars over invoices not objected to opportunely by ECOPETROL, ECOPETROL will acknowledge to the SELLER as interest paid in Dollars, the equivalent rate to the Prime Rate indicated by the Chase Manhattan Bank of New York, during the days corresponding to the effectual delay elapsed, plus 2.0%.: In the event of delay in payment of that stipulated in the contract, liquidated in Pesos, over the respective quantity in delay in Pesos, Ecopetrol will acknowledge the maximum monthly interest in accordance to the certificate issued by the Banking Superindentency. The invoices for interest charge in Pesos or in Dollars, will be cancelled within ten (10) days following the receipt of the invoice by ECOPETROl. PARAGRAPH 2: If ECOPETROL does not have in its possession and at its disposal, Dollars from the United States of America, or could not obtain from the Colombian Government or from its authorized agencies, Dollars to cover the purchases corresponding to the contracted crude oil, Ecopetrol will quickly notify THE SELLER in writing without detriment to the conditions stipulated in the preceding Paragraph 1, and the parties will prepare for a maximum period of thirty (30) calendar days, counting from the notification from ECOPETROL, as by mutual agreement, arrive at an adequate solution. PARAGRAPH 3: ECOPETROL will dispose of fifteen (15) working days to revise, correct or object to the invoices presented by THE SELLER. Whatever invoice that has not been objected to within this period, will be considered as final and correct. Whatever adjustment or correction that must be made in the invoice, will occasion that the valid date of its presentation be considered from the date in which said adjustment had been effectively made before ECOPETROL. ECOPETROL will inform THE SELLER within the permitted term over whatever invoice that is objected to so that it can be adjusted and corrected, specifying clearly the items that must be adjusted or corrected and the corresponding reason. CLAUSE EIGHT: INSPECTION AND MEASUREMENT. For the purposes of Clause Two, the determination of quality will be made according to the operative procedures that are established by mutual agreement between the parties in accordance with the written record of proceedings. The cost of these procedures will be shared by the parties in proportion to the crude ownership by ECOPETROL and THE SELLER. In Addition to these operative procedures, whichever of the parties could designate when they wish, an independent inspector to certify quality and quantity, carry out examinations on the tanks or the calibration of the volume measuring instruments. In the latter case, the cost will be covered by the party requesting the measurement. CLAUSE NINE: TERMINATION. The Seller or ECOPETROL can terminate the sale/purchase contract by written notice with an advance notice of sixty (60) days. If THE SELLER decides to export his Santana crude directly, he will advice ECOPETROL in writing with an advance notice of sixty (60) days, a term within which Ecopetrol and the Seller can revoke this contract. CLAUSE TEN: DESTINATION. ECOPETROL can give its acquired crude oil, the destination that is considered appropriate for its interests, provided that said destination be permitted by legal applicable arrangements that are in force at that time. CLAUSE ELEVEN: TRANSFERS. Neither of the parties could cede, sell or transfer the totality or any part of their rights and obligations here contracted to a third party, without previous and written consent from the other party. CLAUSE TWELVE: FORCE MAJEURE. Neither ECOPETROL nor THE SELLER will be responsible for lack of compliance of all or any of their obligations according to this agreement, if said failure is caused by events constituted as "force majeure"or act of nature duly proven. Force Majeure is an unforseen event which cannot be controlled, which cannot be blamed on the obliged party and that places said party in a position where it cannot fulfil its obligations, such as: natural phenomena (earthquakes, floods, landslides) or public order events (strikes, Terrorism, mutiny, sabotage, pipeline ruptures). The "force majeure" will not liberate ECOPETROL from its payment obligation to THE SELLER for those invoices for the sale of crude oil that has been delivered by THE SELLER, in conformity with the stipulated terms in Clause Eight of this contract. CLAUSE THIRTEEN: APPLICATION OF COLOMBIAN LAWS. For all the purposes of this contract, the parties confirm their domicile in the City of Santafe de Bogota, D.C., Republic of Colombia. This contract is in force in all of its parts by Colombian law and the parties submit to the jurisdiction of Colombian courts and renounce the intention of diplomatic claims in all that touches upon their rights and obligations proceeding from this contract, except in the case of denial of justice. For all effects of this contract, it is understood that the dispositions incorporated in it from Article 25 of Law 40 of 1993, and that of the Second Chapter of the Title Three of Law 104 of 1993, or from whatever other norm that modifies or adds to them. CLAUSE FOURTEEN: NOTIFICATIONS. All notifications made in accordance with this contract, should make reference to this Clause and to the pertinent Clause. Said notifications should be sent by certified mail, fax, or be delivered at the addresses that follow, are indicated and will be considered as received in the respective address, on the date that appears in the receipt of the letter or on the date in which the fax is sent. EMPRESA COLOMBIANA DE PETROLEOS - ECOPETROL, Calle 37 No. 7-43, Fax No. 3382585, Attn.. International Trade and Gas Vice Presidency. THE SELLER, ARGOSY ENERGY INTERNATIONAL, Avenue 13 (Autopista Norte), No. 122-56, floor 4, Fax No. 6- 195460 , Santafe de Bogota, D.C., Attn.: Santiago Gonzalez A., President. All changes of address should be informed in writing, with anticipation, to the other party. CLAUSE FIFTEEN: TAXES AND EXPENSES. All taxes and expenses that are caused for entering into and performing this contract and its extentions or modifications will be considered the exclusive duty of THE SELLER. CLAUSE SIXTEEN: DISAGREEMENTS. A) In the event of disagreements between the parties concerning legal issues related to the interpretation and performance of the contract, that cannot be arranged in an amicable manner, shall be subjected to the knowledge and decision of the jurisdiction branch of Colombian Sovereign Power. B) Any difference in deed or of a technical character that arises between the parties, with motive for the interruption or enforcement of the contract, that cannot be settled in an amicable manner, will be subjected to the decision of experts, named as follows: one for each party and a third designated by mutual agreement by the principal experts named. If the two experts did not agree on the nominated third party, this will be named by petition of any of the parties, by the Board of Directors of the Colombian Society of Engineers that has its headquarters in Santafe de Bogota, D.C. Any difference of an accounting nature that arises between the parties caused by interpretation and performance of the contract that cannot be arranged in an amicable manner, will be subjected to the opinion of experts, who should be certified accountants, designated as follows: one for each party and a third named by the two principal experts. Lacking an agreement between these and on the petition by either of the parties, said third expert will be named by the Central Board of Accountants of Bogota, and lacking this, by the Colombian Society of Engineers. D) Both parties declare that the decision by the experts will have all the effects of a transaction between them and consequently, such a decision will be definite. E) In the event of a disagreement between the parties over technical quality, countable and/or legal, of the controversy, this is considered as legal and the literal will be applied A) from this Clause, that agreed to in the Clause is understood without damaging the special procedures provided in this contract. As written evidence, duly signed in Santafe de Bogota, D.C., on the Sixteenth day of the month of February of Nineteen Ninety Nine (1999), on safety paper for the original and the copy EMPRESA COLOMBIANA DE PETROLEOS ARGOSY ENERGY INTERNATIONAL ECOPETROL LUIS AUGUSTO YEPES G. SANTIAGO GONZALEZ ANGULO VP International Trade and Gas Legal Representative ANNEX 1 CALCULATION OF THE ADJUSTMENT FOR QUALITY COMPENSATION The procedure for quality adjustment will be applied for the deliveries of the preceding month in accordance with the following procedure: Information required: + Regression equation for the calculation of the referenced prices, according to the information supplied at the end of this annex. + Volume and quality (API & %wtS) of the shipment (s) of crude from the Tumaco terminal for export. + Volume and quality (API & %wtS) of Santana crude delivered to the Santana terminal, as well as the deliveries in the Mary, Miraflor, Toroyaco and Linda fields. + Price base of the South Blend crude delivered in Tumaco, that is exported. Procedure: 1. Calculate the reference price for the South Blend withdrawn in Tumaco and for the Santana crude delivered at the Santana terminal, by using a regression equation according to its respective quality. 2. With the volume of the South Blend oil withdrawn in Tumaco and of the Santana crude delivered at the Santana terminal and the reference prices previously calculated, calculate the amount in US$ of each one. 3. Calculate the fraction of the amount of Santana crude in the South Blend, dividing the US$ for the Santana crude by the US$ of the crude-Blend. 4. Calculate the volume of Santana crude compensated, multiplying the volume of crude Blend withdrawn in Tumaco by the fraction of the cost of the Santana crude. 5. Calculate the compensation factor of the Santana crude, dividing the compensated volume of Santana crude by the Santana crude delivered in the Santana terminal. 6. Calculate the amount of the compensation as follows: Amount of the compensation = Base Price * (compensation factor minus 1) The price is the amount of the export of the South Blend oil FOB Tumaco. Example: All of the information presented as follows, is presented as an example. Required information: 1. Regression Equation: Price=Bo+B1*SG+B2*%wtS. B2 = - 0.7995 B1 =-3.8822 Bo = 20.1712 Where: Bo = Independent Term B1 = Regression coefficient associated with the specific gravity. SGR = Specific gravity of the crude. B2 = Regression coefficient associated with the percentage in weight of sulphur. %wtS = Percentage in crude sulphur weight. 2. South Blend crude withdrawn in the Tumaco terminal. Volume: 400 Net Bls. Quantity: 28.90 deg. API (0.882 SGR), 0.790 %S Base Price of crude-Blend delivered in Tumaco: 16.0000 US$/Bl. 3. Santana crude delivered in Santana terminal. Volume: 150,000 Bls. Quality: 26.50 Deg. API (0.896 SGR). The content of sulphur is obtained using the average of the sulphur content in the crude from the Mary, Miraflor, Linda and Toroyaco fields, weighed by the volume delivered per field, as follows:
CRUDE % Weight of DELIVERED (FIELDS) S FIELDS BLS. MARY 0.579 81.661 MIRAFLOR 0.644 13.454 LINDA 0.481 3.766 TOROYACO 0.527 60.164 TOTAL DELIVERIES 159.045 SULPHUR CONTENT 0.550 WEIGHED Quality of sulphur: 0.550 %S
Note: The sulphur content from the different fields is that supplied by Ecopetrol's Services Management of the Refining and Marketing Vicepresidency, which for this end will be in charge of contracting an independent inspection firm, whose expenses will be cancelled in accordance with Clause Eight of this contract. Procedure for Calculation: 1. Replacing the quality of each of the crudes in the regression equation . CrudeBlend Price=20.1712+(-3.8822)*0.882+(0.7995)*0.790=16.1155 USD/BL. Santana crude Price=20.1712+(-3.8822)*0.896+(-0.7995)*0.550=16.2530 USD/BL 2. Amount in US$ of each crude: Crude Blend=Volume*Price=400.000 Bls*16.1155 USD/BL.=USD 6'446.200.00 Santana crude=Volume*Price=150.000 Bls*16.2530 USD/BL=USD 2'437.950 3. Fraction of Santana crude volume in crude Blend. 2'437.950.00/6'446.200.00=0.3782 4. Volume of the Santana compensated crude 400.000 Bls.*0.3782=151.280 Bls. 5. Compensation factor for Santana crude. 151.280.00 Bls./150.000.00 Bls.=1.0085 6. Amount of compensation = 16.00 USD/BL.*(1.0085-1)=0.1360 USD/BL. INFORMATION REGARDING THE REGRESSION EQUATION For the calculation of the regression equation, the following chart has been drawn up of 14 international crudes. The prices of these crudes correspond to an arithmetical average of their quotations in the three months previous to the quality compensation evaluation. Said information, as much the price as the quality, will be obtained from the monthly report published by Platt's and titled as follows: " PLATT's OILGRAM PRICE REPORT". The chart of the 14 international crudes is as follows:
Price (USD/Bl.) CRUDE API SGR %wtS Month X Year X FATAH 30.70 0.8724 1.90 21.50 ARAB LIGHT 33.40 0.8581 1.77 22.53 ARAB MEDIUM 28.50 0.8844 2.85 21.55
Price (USD/Bl.) CRUDE API SGR %wtS Month X Year X ARAB HEAVY 27.40 0.8905 2.80 20.79 BRENT BLEND 38.00 0.8348 0.30 24.04 BONNY LIGHT 35.70 0.8463 0.14 24.01 CANO LIMON 29.50 0.8789 0.45 24.45 FORCADOS 31.00 0.8708 0.20 24.06 FLOTTA BLEND 36.00 0.8448 1.20 23.49 ISTHMUS 33.00 0.8602 1.30 23.16 KUWAIT 31.40 0.8686 2.52 21.26 MANDJI 30.50 0.8735 1.10 22.08 MAYA 22.00 0.9218 3.40 19.83 ORIENT 29.50 0.8789 0.90 22.06
The preceding international supply of crudes may be modified by mutual agreement between the parties. NOTE 1: When the quality of the crude supplies varies during a month, an average will be taken of the three quality prices corresponding to those same months in which the quotations were taken. NOTE 2: When no quotation appears for one of the crude supplies in one month, an average will be taken of the two previous months instead of the three quotations established for the price calculation of that month and will be agreed upon by the parties in writing if the supply is definitely reduced or it will be replaced by whatever other crude in the price calculation for the following month. This is a fair and accurate English translation of the original document which is in the Colombian language. /s/ James L. Busby ------------------ James L. Busby Secretary and Treasurer of Aviva Petroleum Inc. EX-21.1 3 LIST OF SUBSIDIARIES OF AVIVA PETROLEUM INC. Exhibit 21.1 Subsidiaries of Aviva Petroleum Inc. Place of Company Incorporation - ---------------------------- ------------- Aviva Operating Company Nevada Aviva (USA) Inc. Texas London & Aberdeen Inc. Nevada Aviva Energy Inc. Nevada Aviva America, Inc. Delaware Neo Energy, Inc. Texas Garnet Resources Corporation Delaware Garnet Oil Corporation Delaware Garnet Pakistan Corporation Delaware Garnet Spain Corporation Delaware Garnet Turkey Corporation Delaware Garnet PNG Corporation Delaware Argosy Energy Incorporated Delaware Garnet Energy Corporation Delaware Garnet Acquisition II, Inc. Texas Garnet Sulfur Company Nevada Argosy Energy International Utah limited partnership Argosy Petroleum Company, SA Colombia, South America Garnet Resources Canada Ltd. British Columbia EX-27 4 FINANCIAL DATA SCHEDULE
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE CONSOLIDATED BALANCE SHEET OF AVIVA PETROLEUM INC. AND SUBSIDIARIES AS OF DECEMBER 31, 1998 AND THE RELATED CONSOLIDATED STATEMENT OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 1998 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 YEAR DEC-31-1998 JAN-01-1998 DEC-31-1998 2,129 0 1,923 420 836 5,095 69,248 64,440 11,422 20,639 0 0 0 2,335 (13,418) 11,422 3,332 3,332 6,677 6,677 12,343 420 748 (16,885) (4) (16,881) 0 (197) 0 (17,078) (0.50) (0.50)
-----END PRIVACY-ENHANCED MESSAGE-----