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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

For the fiscal year ended DECEMBER 31, 2002

OR

For the transition period from                  to                 

Commission File Number 0-22258

AVIVA PETROLEUM INC.

(Exact name of registrant as specified in its charter)

(214) 691-3464

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act:

Common Stock, without par value

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.

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes ¨ No x .

The aggregate market value of voting and non-voting common equity held by non-affiliates of the Registrant on June 28, 2002 was approximately $2,140,000. As of such date, the last sale price of a share of the Registrant’s common stock, without par value (“Common Stock”), was U.S. $0.05, as quoted on the OTC Bulletin Board.

As of February 28, 2003, the Registrant had 46,900,132 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None.

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TABLE OF CONTENTS TO FORM 10-K

(i)

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TABLE OF CONTENTS TO FORM 10-K (Continued)

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PART I

IMPORTANT INFORMATION

GOING CONCERN RISK

If distributions from Colombia do not resume as discussed herein and the Company is not able to generate additional cash from investing or financing activities, the Company’s liquidity will continue to deteriorate. These factors raise substantial doubt concerning the ability of the Company to continue operating as a going concern. In order to improve the Company’s liquidity, management of the Company is continuing its efforts to raise additional capital through equity issues, issuance of debt, sales of assets and farmout of prospects. The Company’s ability to raise additional capital will be dependent upon the drilling results of the Inchiyaco well, a matter that is beyond the control of management. Accordingly, there can be no assurance that such attempts to raise capital will be successful. 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 trades on the OTC Bulletin Board under the symbol “AVVP”. The Company’s principal executive offices are located in Dallas, Texas.

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 9½% Convertible Subordinated Debentures were acquired and canceled, and the outstanding bank debt of Garnet and the Company was refinanced under a $15 million credit facility which was fully retired in 2000. See “—Debt Restructuring”. As a result of the merger, the Company was able to effect cost savings, particularly in Colombia where each company had an interest in the same properties.

Debt Restructuring

On June 8, 2000, the Company entered into agreements with the Company’s senior secured lender in order to restructure the Company’s senior debt which, including unpaid interest, aggregated $16,103,064 as of May 31, 2000. Pursuant to the agreements, the lender canceled $13,353,064 of such debt and transferred to the Company warrants on 1,500,000 shares of the Company’s common stock in exchange for the general partner rights and an initial 77.5% partnership interest in Argosy Energy International (“Argosy”), a Utah limited partnership which holds the Company’s Colombian properties. Following the transaction, Aviva Overseas, Inc. (“Aviva Overseas”), a wholly owned subsidiary of the Company, owned a 22.1196% limited partnership interest in Argosy. An additional 7.5% limited partnership interest was transferred from the lender to Aviva Overseas effective August 14, 2001, when the lender received in distributions from Argosy an amount equal to $3,500,000 plus interest at the prime rate plus 1%. The Company’s interest in Argosy is 29.6196% after the transfer.

The Company’s remaining debt of $2,750,000 was reacquired from the lender on December 21, 2000, in exchange for a 15% net profits interest in any new production at Breton Sound Block 31 field. This transaction substantially completed the restructuring of the Company and the reorganization of the Company’s wholly owned subsidiary, Aviva America, Inc. (“AAI”).

AAI had filed a voluntary petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code on July 21, 2000. The filing, in the Northern District of Texas, was initiated in order to achieve a comprehensive restructuring of AAI’s debts. Following approval by the court and creditors, the voluntary petition for reorganization became effective on November 17, 2000.

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As a result of the aforementioned transactions, all of the Company’s outstanding senior secured debt has been eliminated.

Current Operations

Colombia. The Company is the owner of interests in, and is engaged in exploration for, and development and production of oil from, four contracts granted by Empresa Colombiana de Petroleos, the Colombian national oil company (“Ecopetrol”).

The Company’s Colombian activities are carried out by Argosy which operates the Colombian properties. Argosy is currently party to four contracts with Ecopetrol called Santana, Guayuyaco, Rio Magdalena and Aporte Putumayo. All contract areas are located in the Putumayo Basin of southwestern Colombia, except for Rio Magdalena which is located in the Upper Magdalena Basin in central Colombia. The Company’s production activities are currently limited to the Santana contract area.

Twenty-one wells have been drilled on the Santana contract area. Of 13 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 block has totaled approximately 18.2 million barrels during the period from April 1992, when production commenced, through December 2002.

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. The block has been relinquished, however Argosy remains obligated for abandonment and restoration operations on the old wells in the block.

Each concession is governed by a separate contract with Ecopetrol. Generally, the contracts cover a specific 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. The Santana contract provides 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. The Rio Magdalena contract and the Guayuyaco contract (see “Item 2. Properties — Significant Properties”) provide for similar royalty payments, however, the amount of royalty is calculated on a sliding scale that ranges from 5% (for production up to 5,000 barrels per day) up to a maximum of 25%. 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 reversionary interest in the field equal to its specified interest and is required to pay its share 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 working interest in the field equal to its specified interest without payment or reimbursement of any historical costs. Exploration costs (as defined in the contracts) incurred by Argosy prior to the declaration of commerciality are recovered by means of retention by Argosy of a portion 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, AAI, has been engaged in the production of oil and gas attributable to its working interests in various wells located in the Gulf of Mexico offshore Louisiana, at Main Pass 41 and Breton Sound 31 fields. Effective November 7, 2000, the Company assigned all of its interest in the Main Pass 41 field to the field operator. AAI continues to operate the Breton Sound 31 field. The Company acquired its interests in these fields through the acquisition of Charterhall Oil North America PLC in 1990. See “Item 2. Properties – Significant Properties” and Note 10 of the Notes to Consolidated Financial Statements contained elsewhere herein.

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.”

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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 or terrorism 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 cost may be required to determine the extent of and to produce the recoverable reserves. Failure to fund certain capital expenditures could result in a decrease in the Company’s ownership interest in Argosy or, possibly, a 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.”

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 a portion of the Company’s property is located, have as recently as August 3, 1998, significantly damaged the Company’s assets. Since that time the Company has been subject to lessor attacks on its pipelines and equipment resulting in only minor interruptions of oil sales. 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. The damages resulting from the 1998 attack were covered by insurance. During 2001 the cost of such insurance became prohibitively high and, accordingly, Argosy has elected to no longer maintain terrorism insurance.

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 12 of the Notes to Consolidated Financial Statements contained elsewhere herein.

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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, 2002, the Company received the majority of its revenue from Ecopetrol. Sales to Ecopetrol accounted for $1,164,000 or 62% of oil and gas revenue for 2002, $1,253,000, or 59% of oil and gas revenue for 2001, and $4,267,000, or 74% of oil and gas revenue for 2000. The foregoing amounts represent 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 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 at Breton Sound 31 is used for field operations and is recorded at spot prices. The Company has not historically hedged any of its domestic production. See “Item 2. Properties – Significant Properties” and Note 10 of the Notes to Consolidated Financial Statements contained elsewhere herein.

During 2002, 2001 and 2000, the Company received more than 10% of its revenue from one domestic purchaser. Such revenue accounted for $643,000, or 34% of oil and gas revenue for 2002, $782,000, or 37% of oil and gas revenue for 2001 and $968,000, or 16.7% of oil and gas revenue for 2000.

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 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 revision or reinterpretation of existing laws and regulations or adoption of new laws and regulations that result in more stringent and costly waste handling, disposal, remedial, drilling, permitting, 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

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liabilities, including administrative, civil and criminal penalties for violations of environmental laws and regulations and cleanup costs for remediation of contaminated properties, will not be incurred. For more information, please read “Item 3. Legal Proceedings.”

Colombia. Any significant exploration or development of the Company’s Colombian properties in which it now holds a non-operating interest, 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 issuance of environmental permits by the Ministry of the Environment. In recent years while it was operator of these Colombian properties, the Company received environmental permits without substantial delay. There can be no assurance, however, that the current operator of these Colombian properties will not experience future delays in obtaining necessary environmental licenses. See also “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. In the past, 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, in order to maintain compliance with these U.S. environmental laws and 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, as amended (“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 a vessel, pipeline, or onshore facility, 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 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.

The Company’s U.S. property at Breton Sound Block 31 field, on state leases offshore Louisiana, is subject to OPA ‘90. Under OPA ‘90 and a final rule implementing OPA ‘90 adopted by the U.S. Minerals Management Service (“MMS”) in August 1998, owners and operators of covered offshore facilities that have a worst case oil spill of more than 1,000 barrels must demonstrate financial responsibility in amounts ranging from $10 million in specified state waters to $35 million in federal outer continental shelf (“OCS”) waters, with higher amounts of up to $150 million in certain limited circumstances where the MMS believes such a level is justified by the risks posed by operations at such covered offshore facilities or if the worst case oil-spill discharge volumes possible at such facilities may exceed the applicable threshold volumes specified under the MMS final rule. The Company believes that it currently has established adequate proof of $10 million in financial responsibility for its covered offshore facilities in Louisiana State waters. However, the Company cannot predict whether these financial responsibility requirements under OPA ‘90 or the MMS 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 Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, and analogous state laws impose 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

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released into the environment. The Company has not received any notification that it is, nor does it otherwise know of circumstances indicating that it will 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.

Other Regulation—Colombia. The Company’s Colombian operations, in which it now holds a non-operating interest, are regulated by Ecopetrol, the Ministry of Mines and Energy, and the Ministry of the Environment, among others. 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 these Colombian operations. 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.

Sales of crude oil, condensate and gas liquids by the Company are not currently regulated and are made at market prices. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to the Federal Energy Regulatory Commission (“FERC”) jurisdiction under the Interstate Commerce Act and the Energy Policy Act of 1992. Certain regulations implemented by the FERC in recent years could result in an increase in the cost of transportation service on certain pipelines. However, the Company does not believe that these regulations affect it any differently than others.

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 industry 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

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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 Papua New Guinea operations, in which it holds a non-operating interest, are currently governed by the Department of Petroleum and Energy, 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 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, 2002, Aviva had 6 full-time employees.

ITEM 2. PROPERTIES

Productive Wells and Drilling Activity

The following table summarizes the Company’s developed acreage and productive wells at December 31, 2002. “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)

Productive Wells (3)

During the period from January 1, 2000 through December 31, 2002, the Company did not drill nor participate in the drilling of any development or exploratory wells.

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Undeveloped Acreage

The Company’s undeveloped acreage in Colombia is held pursuant to the Santana and Rio Magdalena contracts with the Colombian government. No further relinquishments are required for the Santana contract until the expiration of the contract in 2015. The Rio Magdalena contract may, by operation of its terms, require the relinquishment of certain portions of the undeveloped acreage in 2007, 2009 and 2011. 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, 2002. 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.

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 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.

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, 2002, that is not the same as that included in the estimate of proved oil and gas reserves as of December 31, 2002, 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.

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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:

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:

Significant Properties

Colombia.

The Company’s Colombian properties currently consist of four contracts, three of which are located in the Putumayo Basin in southwestern Colombia along the eastern front of the eastern cordillera of the Andes Mountains. The Rio Magdalena contract, covering approximately 145,000 acres, is located in central Colombia in the prolific Upper Magdalena region. 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 four contracts. The program is determined by Argosy and approved by Ecopetrol. The Santana contract, which now consists of approximately 52,000 acres and contains 14 productive wells, has been in effect since 1987 and is the focus of the Company’s current production activities. The Guayuyaco contract, signed in August 2002, overlays the undeveloped acreage in the Santana contract. The Guayuyaco and Rio Magdalena contracts are the focus of the Company’s exploration activities.

The Aporte Putumayo block, which consisted of approximately 77,000 acres and contains three shut-in wells, produced from 1976 to 1995. The block has been relinquished, however Argosy remains obligated for abandonment and restoration operations on the old wells in the block.

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Production from the Santana concession is sold pursuant to a sales contract with Ecopetrol. The contract provides that at least 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%. Payment of the remittance tax may be deferred under certain circumstances if the Company reinvests such income in Colombia.

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 Argosy from Ecopetrol’s share of 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’s revenue interest in the contract declined from 40% to 28% and its share of operating expenses declined from 50% to 35%.

The Santana block 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 five 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. Although the survey confirmed that additional development drilling is not required for the Miraflor field, it did confirm the presence of several prospects and leads previously identified from two-dimensional seismic data. These prospects and leads are now covered by the Guayuyaco contract described below.

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.

All oil produced from the Santana contract area is sold to Ecopetrol pursuant to the terms of the applicable sales contract with Ecopetrol. The contracts applicable to periods prior to December 1, 2001 generally provided that if Ecopetrol exported the oil, the price paid was the export price received by Ecopetrol, adjusted for quality differences, less a marketing fee of $0.165 per barrel. If Ecopetrol did not export the oil, the price paid was 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 marketing fee of $0.165 per barrel.

Argosy entered into a new sales contract with Ecopetrol, effective December 1, 2001, and extended through November 30, 2003, whereby the price paid, adjusted for quality differences, for each barrel of oil sold is determined based on the monthly average of West Texas Intermediate – Cushing (“WTI”) less a variable differential as follows:

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During 2002 the crude sales price averaged $19.65 per barrel.

Rio Magdalena Contract. The Rio Magdalena contract, acquired by Argosy in December 2001, is an “association” contract whereunder Argosy and a 50% co-owner fulfill all exploration obligations without Ecopetrol’s participation until a field is declared commercial by Ecopetrol, whereupon Ecopetrol will earn an initial 30% share in the field and must reimburse its 30% share of successful exploratory wells, seismic and stratigraphic wells, dry step-out exploratory wells and development wells and facilities through its 30% share of production. The contract provides that Ecopetrol’s working interest will be 30% until aggregate oil production from the contract area reaches 60 million barrels. For production in excess of 60 million barrels, Ecopetrol’s interest will increase from 30% to 65% based on a measure of profitability as defined in the contract.

The contract obligations of the Rio Magdalena contract require Argosy and its co-owner to reprocess 40 kilometers of 2D seismic during the initial 18-month exploration phase of the contract. In the following 12-month exploration phase, Argosy and its co-owner are obligated to perform one of the following: (i) a seismic survey to acquire 30 kilometers of 3D seismic; (ii) a seismic survey to acquire 2D seismic at a cost equivalent to the 3D program; or (iii) drill an exploratory well. If Argosy and its co-owner decide to proceed into the third phase of the contract, the drilling of an exploratory well would be required. If a field is discovered, the exploitation period is 22 years in the case of an oil discovery and 30 years, extendable to 40 years under certain circumstances, in the case of a natural gas discovery. Argosy has not yet completed the seismic reprocessing required in the first phase of the contract. Such reprocessing is currently underway.

Guayuyaco Contract. The Guayuyaco contract, signed by Argosy in August 2002, is an “association” contract that overlays the undeveloped acreage contained within the Santana contract area. Under the Guayuyaco contract, Argosy will fulfill all exploration obligations without Ecopetrol’s participation until a field is declared commercial by Ecopetrol, whereupon Ecopetrol will earn an initial 30% share in the field and must reimburse its 30% share of direct exploration costs, as defined in the contract, through payment of 50% of its 30% share of production. The contract provides that Ecopetrol’s working interest will be 30% until aggregate oil production from the contract area reaches 60 million barrels. For production in excess of 60 million barrels, Ecopetrol’s interest will increase from 30% to 65% based on a measure of profitability as defined in the contract.

The obligations of the Guayuyaco contract require Argosy to drill one exploratory well during the initial 12-month exploration phase of the contract. Upon completion of the initial exploration phase, Argosy may relinquish the contract or proceed to the following 18-month exploration phase, whereunder Argosy will be obligated to drill a second exploratory well. The contract will terminate following the second phase if, not having discovered a field, Argosy does not request an extension to the contract. Upon request by Argosy, Ecopetrol may extend the contract an additional three years obligating Argosy to drill one exploration well in each of the three years of the extension. If a field is discovered, the exploitation period is 22 years in the case of an oil discovery and 30 years in the case of a natural gas discovery. Argosy plans to involve industry and service company partners to reduce the cost exposure of the first exploratory well. This well, the Inchiyaco #1, is expected to be a 7,800 foot exploration test of the Villeta U, T, N and Caballos sands in the Inchiyaco structure approximately 500 meters east of the Mary field. Depending on definitive service agreements, rig availability and other contingencies, drilling could commence as early as the second quarter of 2003.

Failure by Argosy to meet the obligations under the proposed contract will result in the loss of the proposed contract terms. The existing Santana production and acreage will not be affected. Failure by the Company to fund its share of Argosy’s obligations under the proposed contract, assuming Argosy funds the obligation, could result in a decrease in the Company’s ownership interest in Argosy.

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United States.

The Company’s remaining oil and gas properties in the United States are located in the Gulf of Mexico offshore Louisiana at Breton Sound 31 field. The Breton Sound 31 field is operated by the Company.

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 2002, six wells averaged 73 barrels of oil per day and 55 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 working interests in the leases comprising the field vary from 73% to 93%.

On January 30, 2003, the Company’s gas well that supplies fuel gas for the Breton Sound field ceased producing and production from the field was suspended. The Company has reviewed the possibility of recompleting an existing oil well into a gas zone capable of producing the necessary gas required to bring the field back onto production. This option, however, was determined to be economically unjustified. Accordingly, the Company is attempting to secure a gas supply from a gas distribution company that has a gas outlet at the Company’s gas platform. This plan would require the Company to install a sales meter and make other improvements to the Company’s gas platform at a cost estimated at $150,000. There can be no assurance, however, that the gas distribution company will agree to sell the requisite gas. If the Company is unable to bring the field back onto production before May 1, 2003, the Company could be required to surrender the leases to the State of Louisiana and abandon the property at a cost of approximately $0.9 million.

The interpretation of 3-D seismic data in 1996 identified two deep and several shallow prospects in the Breton Sound Block 31 field. Since that time management of the Company has attempted unsuccessfully to negotiate an arrangement with various industry partners to explore such prospects. If the Company can overcome the problems mentioned in the preceding paragraph, management plans to continue its efforts to negotiate an exploration arrangement with an industry partner. If, however, such an arrangement cannot be negotiated and funding becomes available, the Company may drill one or more of the shallow prospects without bringing in an industry partner.

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.

In accordance with the terms of the agreement governing PPL-206, the parties have performed surface geological work and completed seismic programs during 1998 and 2000. The 2000 program (the “Okoni Program”) was followed by strike line acquisition in 2001 to determine the drilling location for the Bosavi exploratory well.

Drilling of the Bosavi well commenced on January 22, 2003. The well was drilled to a depth of 1501 meters through the objective Toro, Hedinia and Iagifu sandstones and encountered negligible hydrocarbon shows. Electric logs run across the open-hole interval indicate all sands to be water bearing. On February 20, 2003, the Company was informed by the operator, Santos Niugini Exploration Limited, that they had commenced operations to plug and abandon the well. The operator has not yet informed the Company as to any future plans concerning PPL-206.

Pursuant to the Company’s 2% carried working interest, the Company is not obligated to pay any of the costs relative to the drilling of the Bosavi well, unless such costs exceed $9 million. For such costs in excess of $9 million the Company will have to fund its 2% share. Based on information reported in the drilling reports received from the operator, the cumulative drilling costs of the Bosavi well will approximate $9.5 million, resulting in a net cost of $10,000 to Aviva.

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

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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 that expires in January 2007. The annual lease payments for these offices are approximately $94,000.

ITEM 3. LEGAL PROCEEDINGS

In “Terrebonne Parish School Board v. Quintana Petroleum Corporation, et al.,” Case No. 00-0443, Sect. T (2) in the United States District Court for the Eastern District of Louisiana, the Terrebonne Parish School Board, also referred to as the “Board,” has sued various oil and gas companies, including the Company, alleging that they dredged canals and moved equipment across Board property for the purpose of developing the minerals thereunder, but subsequently failed to restore the surface of the property, thus causing erosion to Louisiana coastal wetlands. The Company’s involvement, as a successor to Jackson Exploration, Inc., with respect to any such Board property was brief, and records from the period are scarce. This lawsuit was stayed by this District Court pending resolution of an appeal made to the United States Court of Appeals for the Fifth Circuit of an unrelated case in which this same District Court granted summary judgment to the defendants for the same type of claims being made in this lawsuit because such claims were barred by Louisiana’s limitation doctrine. On November 13, 2002, the United States Court of Appeals for the Fifth Circuit upheld that ruling made in the unrelated case, finding that the limitations period was not tolled, and that the plaintiff’s failure to take action after knowing of the erosion as early as 1995 was “tantamount to willful neglect.” The appellate court also rejected the theory made by the plaintiffs that the alleged tort was a “continuing tort.” In the current lawsuit involving Aviva, the plaintiff recently moved the court to place the proceedings back on the court’s active docket. Given the Fifth Circuit’s rejection of the plaintiff’s claims in the unrelated case, however, management of Aviva believes there is a reasonable possibility that this lawsuit may be dismissed on limitations grounds. Accordingly, management does not expect this lawsuit to have a materially adverse effect on the Company’s results of operations or financial condition.

There are no other 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

There were no matters submitted to a vote of security holders during the fourth quarter of the Company’s fiscal year ended December 31, 2002.

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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, traded on the OTC Bulletin Board (the “OTCBB”) from May 13, 1999 until April 30, 2001, when the Company discontinued trading of the Depositary Shares. On May 16, 2001, the Common Shares began trading on the OTCBB under the symbol “AVVP”. During 2002, an aggregate of 2,657,000 Common Shares were traded on the OTCBB.

The following table sets forth, for the periods indicated, the high and low prices for the Depositary Shares and the Common Stock on the OTCBB.

As of February 28, 2003, the Company had approximately 4,300 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.

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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, 2002, which should be read in conjunction with the Consolidated Financial Statements included elsewhere herein.

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 (see Note 1 of Notes to Consolidated Financial Statements).

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The following discussion and analysis should be read in conjunction with the Consolidated Financial Statements included elsewhere herein.

Critical Accounting Policies

The Company’s significant accounting policies are included in Note 1 to the Consolidated Financial Statements. These policies, along with the underlying assumptions and judgments made by the Company’s management in their application, have a significant impact on the Company’s consolidated financial statements. The Company identifies its most critical accounting policies as those that are the most pervasive and important to the portrayal of the Company’s financial position and results of operations, and that require the most difficult, subjective and/or complex judgments by management regarding estimates about matters that are inherently uncertain. The Company’s most critical policies are those related to property and equipment and impairment of assets.

Results of Operations

2002 versus 2001

Colombian oil volumes were 59,000 barrels in 2002, a decrease of 2,000 barrels from 2001. Such decrease is due to a 12,000 barrel decrease resulting from normal production declines offset partially by a 10,000 barrel increase resulting from the transfer of a 7.5% partnership interest in Argosy to Aviva from its former lender (see note 3 to the consolidated financial statements included elsewhere herein).

U.S. oil volumes were 27,000 barrels in 2002, down approximately 6,000 barrels from 2001. U.S. gas volumes were 20,000 MCF in 2002, down 4,000 MCF from 2001. Such decreases resulted from weather related production interruptions and normal production declines.

Colombian oil prices averaged $19.65 per barrel during 2002. The average price for the same period of 2001 was $20.67 per barrel. The Company’s average U.S. oil price increased to $24.09 per barrel in 2002, up from $23.93 per barrel in 2001. U.S. gas prices averaged $3.25 per MCF in 2002 compared to $4.27 per MCF in 2001.

Service fees of $97,000 for administering the Colombian assets were received in 2002 compared to $473,000 in 2001. The 2002 amount covered three months at a monthly rate of $46,000. The 2001 amount covered three months at a monthly rate of $71,000 and nine months at a monthly rate of $46,000. The recorded amounts are net of Aviva Overseas’ 22.1196% (29.6196% after August 14, 2001) share of the fees. The service contract was cancelled effective March 31, 2002.

Operating costs decreased approximately 15%, or $209,000, primarily as a result of a decrease in the cost of lease fuel in the U.S. due to lower gas prices and the absence of Colombian crude oil transportation charges in 2002. Such transportation charges (approximately $1.82 per barrel in 2001) are included as a deduction to the oil sales price in 2002 pursuant to the latest oil sales agreement with Ecopetrol.

Depreciation, depletion and amortization (“DD&A”) decreased by 35%, or $111,000, primarily due to a decrease in U.S. DD&A. Such decease resulted from an increase in the U.S. reserve life resulting from higher oil prices.

A provision of $592,000 was recorded in 2002 for abandonment and impairment of the U.S. properties (see note 10 to the consolidated financial statements included elsewhere herein). No similar accrual was recorded in 2001.

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Interest and other income decreased $60,000 from 2001 mainly due to a gain on settlement of a disputed payable of $99,000 in 2001. There was no similar gain during 2002.

Income taxes decreased $45,000 primarily as a result of the expiration of $41,000 in deferred Colombian remittance tax that is no longer payable.

2001 versus 2000

Colombian oil volumes were 61,000 barrels in 2001, a decrease of 96,000 barrels from 2000. Such decrease is due to an 84,000 barrel decrease resulting from the transfer of partnership interests to the Company’s former lender on June 8, 2000 and a 19,000 barrel decrease resulting from production declines, partially offset by a 7,000 barrel increase due to the transfer of a 7.5% partnership interest to Aviva from the lender on August 14, 2001 (see note 3 of the consolidated financial statements included elsewhere herein).

U.S. oil volumes were 33,000 barrels in 2001, down approximately 16,000 barrels from 2000. Such decrease is primarily due to the relinquishment of Main Pass 41 effective November 7, 2000. U.S. gas volumes were 24,000 MCF in 2001, down 1,000 MCF from 2000. Such decrease is due to the relinquishment of Main Pass 41 as discussed above.

Colombian oil prices averaged $20.67 per barrel during 2001. The average price for the same period in 2000 was $27.18 per barrel. The Company’s average U.S. oil price decreased to $23.93 per barrel in 2001, down from $28.94 per barrel in 2000. In 2001 prices were lower than in 2000 due to an overall decrease in world oil prices. U.S. gas prices averaged $4.27 per MCF in 2001 compared to $4.11 per MCF in 2000.

Service fees of $473,000 for administering the Colombian assets were received in 2001 compared to $387,000 in 2000. The 2001 amount covered three months at a monthly rate of $71,000 and nine months at a monthly rate of $46,000. The 2000 amount covered seven months at a monthly rate of $71,000. The recorded amounts are net of Aviva Overseas’ 22.1196% (29.6196% after August 14, 2001) share of the fees.

Operating costs decreased approximately 42%, or $1,005,000, primarily as a result of the transfer of partnership interests to the Company’s former lender.

DD&A decreased by 38%, or $195,000, primarily as a result of the transfer of partnership interests to the Company’s former lender and a decrease in the amount of oil produced.

G&A expenses decreased $151,000 or 13% primarily as a result of the reversal of over accrued public ownership costs, lower state franchise taxes, lower legal fees and lower stock-based compensation.

During 2000, in connection with the restructuring of the Company’s long-term debt, the Company realized a $3,452,000 gain on the transfer of partnership interests to the Company’s former lender and an extraordinary gain of $5,543,000, net of income taxes of $2,855,000, on the extinguishment of a portion of the debt. There were no similar gains during 2001.

Interest expense decreased $802,000 in 2001 due to the extinguishment of the Company’s long-term debt in 2000.

Income taxes were $169,000 lower in 2001 principally as a result of the net transfer of partnership interests to the Company’s former lender.

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Recently Issued Accounting Standards

In June 2001, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires the Company to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development, and/or normal use of the assets. The Company also records a corresponding asset that is depreciated over the life of the asset. Subsequent to the initial measurement of the asset retirement obligation, the obligation will be adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. The Company is required to adopt SFAS No. 143 on January 1, 2003. The Company is currently assessing the impact of adoption of SFAS No. 143.

In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections. SFAS No. 145 amends existing guidance on reporting gains and losses on the extinguishment of debt to prohibit the classification of the gain or loss as extraordinary, as the use of such extinguishments have become part of the risk management strategy of many companies. SFAS No. 145 also amends SFAS No. 13 to require sale-leaseback accounting for certain lease modifications that have economic effects similar to sale-leaseback transactions. The provisions of the Statement related to the rescission of Statement No. 4 is applied in fiscal years beginning after May 15, 2002. Earlier application of these provisions is encouraged. The provisions of the Statement related to Statement No. 13 were effective for transactions occurring after May 15, 2002, with early application encouraged. The adoption of SFAS No. 145 is not expected to have a material effect on the Company’s financial statements.

In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities. SFAS No. 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force (EITF) Issue 94-3, Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity. The provisions of this Statement are effective for exit or disposal activities that are initiated after December 31, 2002, with early application encouraged. The adoption of SFAS No. 146 is not expected to have a material effect on the Company’s financial statements.

In November 2002, the FASB issued Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others, an interpretation of FASB Statements No. 5, 57 and 107 and a rescission of FASB Interpretation No. 34. This Interpretation elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees issued. The Interpretation also clarifies that a guarantor is required to recognize, at inception of a guarantee, a liability for the fair value of the obligation undertaken. The initial recognition and measurement provisions of the Interpretation are applicable to guarantees issued or modified after December 31, 2002 and are not expected to have a material effect on the Company’s financial statements. The disclosure requirements are effective for financial statements of interim or annual periods ending after December 15, 2002.

In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based Compensation – Transition and Disclosure, an amendment of FASB Statement No. 123. This Statement amends FASB Statement No. 123, Accounting for Stock-Based Compensation, to provide alternative methods of transition for a voluntary change to the fair value method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of Statement No. 123 to require prominent disclosures in both annual and interim financial statements. Certain of the disclosure modifications are required for fiscal years ending after December 15, 2002 and are included in the notes to these consolidated financial statements.

In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51. This Interpretation addresses the consolidation by business enterprises of variable interest entities as defined in the Interpretation. The Interpretation applies immediately to variable interests in variable interest entities created after January 31, 2003, and to variable interests in variable interest entities obtained after January 31, 2003. The application of this Interpretation is not expected to have a material effect on the Company’s financial statements. The Interpretation requires certain disclosures in financial statements issued after January 31, 2003 if it is reasonably possible that the Company will consolidate or disclose information about variable interest entities when the Interpretation becomes effective. Based on its initial review, the Company does not believe it has any interests in variable interest entities.

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Liquidity and Capital Resources

Argosy Energy International (“Argosy”), a Utah limited partnership, that holds the Company’s Colombian properties, is required by the Guayuyaco contract to drill an exploratory well by October 2003. Drilling of the proposed well, the Inchiyaco #1, is expected to commence during the second quarter of 2003.

In order to have funds available to drill the Inchiyaco #1, beginning in June 2002 Argosy elected to accumulate all excess cash in Colombia from current sales revenues. Accordingly, Aviva will likely not receive any cash distributions from Colombia until after the Inchiyaco well has been drilled. Even if such an exploratory well was successful, additional funds may be required to equip and complete such a well prior to the resumption of cash distributions.

As of December 31, 2002, approximately $824,000 of cash and cash equivalents included in the Company’s consolidated cash and cash equivalents balance has been accumulated in Colombia principally for Aviva’s share of the drilling cost of the Inchiyaco well. The remaining balance of $884,000 is held in the U.S. and is available for U.S. operations.

The Company’s only source of net cash from operating activities, other than Argosy, is its U.S. Operations. As indicated in note 12 to the consolidated financial statements, the U.S. operations have suffered a net loss of approximately $1,629,000 for the year ended December 31, 2002, and may continue to have net losses in the foreseeable future. Moreover, as described in note 10, the U.S. properties are experiencing operational difficulties that could result in the surrender of the leases and the requirement to abandon the property at a cost of approximately $0.9 million to the Company.

Accordingly, if distributions from Argosy do not resume and the Company is not able to generate additional cash from investing or financing activities, the Company’s liquidity will continue to deteriorate. These factors raise substantial doubt concerning the ability of the Company to continue operating as a going concern.

In order to improve the Company’s liquidity, management of the Company is continuing its efforts to raise additional capital through equity issues, issuance of debt, sales of assets and farmout of prospects. The Company’s ability to raise additional capital will be dependent upon the drilling results of the Inchiyaco well, a matter that is beyond the control of management. Accordingly, there can be no assurance that such attempts to raise additional capital will be successful.

In Colombia, the obligations under the Santana contract have been met; however, Argosy plans to recomplete certain existing wells and engage in various other projects. The first of these recompletions is scheduled during 2004, and the majority of the remaining recompletions are scheduled during 2005. The Company’s share of the estimated future costs of these activities is approximately $0.2 million at December 31, 2002.

The contract obligations of the Rio Magdalena contract require Argosy and its co-owner to perform 40 kilometers of 2D seismic during the initial 18-month exploration phase of the contract. The Company’s current share of the estimated future costs of this phase is approximately $0.1 million at December 31, 2002. Additional expenditures will be required should Argosy decide to enter into the second phase of the contract.

As mentioned above, the obligations of the Guayuyaco contract (signed August 2, 2002) require Argosy to drill one exploratory well during the initial 12-month exploration phase of the contract. Upon completion of the initial exploration phase, Argosy may relinquish the contract or proceed to the following 18-month exploration phase, under which Argosy will be obligated to drill a second exploratory well. Argosy plans to involve industry and service company partners to reduce the cost exposure of the first exploratory well. Depending on definitive service agreements, rig availability and other contingencies, drilling could commence as early as the second quarter of 2003.

Failure by Argosy to meet the obligations under the proposed Guayuyaco contract will result in the loss of the proposed contract terms. The existing Santana production and acreage will not be affected. Failure by the Company to fund its share of Argosy’s obligations, assuming Argosy funds the obligation, could result in a decrease in the Company’s ownership interest in Argosy.

The Company expects to fund its share of the cost of the recompletions on the Santana contract and the seismic commitments on the Rio Magdalena contract using existing cash in Colombia and cash provided from Colombian

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operations. Risks that could adversely affect funding of such activities include, among others, delays in obtaining any required environmental permits, failure to produce the reserves as projected or a decline in the sales price of oil. Any substantial increases in the amounts of these required expenditures could adversely affect the Company’s ability to fund these activities. Any substantial 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 that have not been included in the Company’s cash flow projections may be required.

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, the assessment of geological and geophysical data, 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 commodity prices. 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.

The Company is also exposed to foreign currency exchange rate risk as a result of its international business in Colombia. The Company does not use financial instruments to hedge foreign currency exchange rates.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

See the Financial Statements of Aviva Petroleum Inc. attached hereto and listed in Item 15 herein.

None.

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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. Effective April 6, 2000, Eugene C. Fiedorek resigned from the Board of Directors decreasing the number of directors from three to two.

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.

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.

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 Sepracor, Inc., Film Roman, Inc., Castle Dental Centers, Inc., j2 Global Communications, Inc., Candlewood Hotel Co., Inc., SeraCare Life Sciences, Inc., Learn2 Corporation 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.

Meetings and Committees of the Board of Directors

The Board of Directors of the Company held one formal meeting during 2002. 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. Cresci 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, approves 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 no formal meetings during 2002, however, business was conducted via telephone conferences.

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The Compensation Committee, of which Mr. Cresci is the sole member, 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 formal meetings during 2002.

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, 2002, all of the Reporting Persons complied with their Section 16(a) filing requirements.

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

Directors’ Fees

Beginning January 1, 2002, Mr. Cresci receives $10,000 per year for his services as a director and continues to be 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 receive 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.

Effective June 8, 2000, in connection with the debt restructuring and transfer of partnership interests to the Company’s former lender, 200,000 shares of the Company’s common stock with a market value of $5,000 were transferred to Mr. Robert J. Cresci.

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Option Grants During 2002

The following table provides information related to options granted to the Named Executive Officer during 2002. No stock appreciation rights have been issued by the Company.

Option Exercises During 2002 and Year End Option Values

The following table provides information related to options exercised by the Named Executive Officer during 2002 and the number and value of options held at year-end. No stock appreciation rights have been issued by the Company.

Warrants issued to the Named Executive Officer During 2002

In order to induce the Named Executive Officer to provide the Company with a short-term loan of $50,000 (see note 5 of the consolidated financial statements included elsewhere herein), warrants to purchase 1 million shares of Aviva common stock were issued to the Named Executive Officer effective December 12, 2002. Such warrants have an exercise price of $0.07 per share and expire on December 12, 2004.

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.

Employment Contracts

The Named Executive Officer serves at the discretion of the Board of Directors, except that, effective February 1, 2000, the Company entered into an employment contract with Mr. Suttill. Mr. Suttill’s contract provides for annual compensation of not less than $200,000 and a severance amount of $300,000 if his employment is terminated for any reason other than death, disability or cause, as defined in the contract.

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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 obtaining funding for and overseeing exploration and development activities in Colombia and offshore 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 2002 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 100% of the amount deferred by the employee, up to 6% of an employee’s annual salary.

Compensation Committee

R. J. Cresci

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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.

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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 28, 2003.

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Security Ownership of Management

The following table sets forth certain information as of February 28, 2003, 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:

Securities Authorized for Issuance under Equity Compensation Plans

At December 31, 2002, the Company has two stock option plans which are more fully described in Note 7 of the Notes to Consolidated Financial Statements contained elsewhere herein. The following table sets forth certain information relating to these equity compensation plans as of December 31, 2002:

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

See Note 5 of the Notes to Consolidated Financial Statements contained in Item 15.

PART IV

ITEM 14. CONTROLS AND PROCEDURES

Within the 90 days prior to the date of this report, the Company carried out an evaluation, under the supervision and with participation of the Company’s management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Exchange Act Rule 13a-14. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective in timely alerting them to material information relating to the Company required to be included in the Company’s periodic SEC filings.

There have been no significant changes in the company’s internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

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