Aviva Petroleum (AVVP) 10-K 2002 FY Annual report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended DECEMBER 31, 2002

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                to                

Commission File Number 0-22258

AVIVA PETROLEUM INC.

(Exact name of registrant as specified in its charter)

Texas	75-1432205
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)
8235 Douglas Avenue,	75225
Suite 400, Dallas, Texas	(Zip Code)
(Address of principal executive offices)

(214) 691-3464

(Registrant’s telephone number, including area code)

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

Title of each class	Names of each exchange on which registered
Common Stock, without par value	None – Common Stock quoted onOTC Bulletin Board

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. Yesx    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¨ Nox .

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.

TABLE OF CONTENTS TO FORM 10-K

			Page
Part I
	Important Information – Going Concern Risk		1
	Item 1.	Business
		General	1
		Garnet Merger	1
		Debt Restructuring	1
		Current Operations	2
		Risks Associated with the Company’s Business	3
		Products, Markets and Methods of Distribution	4
		Regulation	4
		Competition	7
		Employees	7
	Item 2.	Properties
		Productive Wells and Drilling Activity	7
		Undeveloped Acreage	8
		Title to Properties	8
		Reserves and Future Net Cash Flows	8
		Production, Sales Prices and Costs	9
		Significant Properties
		Colombia	9
		United States	12
		Papua New Guinea	12
	Item 3.	Legal Proceedings	13
	Item 4.	Submission of Matters to a Vote of Security Holders	13
Part II
	Item 5.	Market for Registrant’s Common Equity and Related Stockholder Matters	14
		Price Range of Depositary Shares and Common Stock	14
		Dividend History and Restrictions	14
	Item 6.	Selected Financial Data	15
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
		Critical Accounting Policies	16
		Results of Operations	16
		Recently Issued Accounting Standards	18
		Liquidity and Capital Resources	19
	Item 7A.	Quantitative and Qualitative Disclosure about Market Risk	20
	Item 8.	Financial Statements and Supplementary Data	20
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	20
Part III
	Item 10.	Directors and Executive Officers of the Registrant
		Directors of the Company	21
		Executive Officers of the Company	21
		Meetings and Committees of the Board of Directors	21
		Compliance with Section 16(a) of the Securities Exchange Act of 1934	22
	Item 11.	Executive Compensation
		Summary Compensation Table	22
		Directors’ Fees	22
		Option Grants During 2002	23
		Option Exercises During 2002 and Year End Option Values	23

(i)

TABLE OF CONTENTS TO FORM 10-K (Continued)

			Page
		Warrants Issued to Named Executive Officer During 2002	23
		Compensation Committee Interlocks and Insider Participation in Compensation Decisions	23
		Employment Contracts	23
		Compensation Committee Report on Executive Compensation	24
		Performance Graph	25
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
		Security Ownership of Certain Beneficial Owners	26
		Security Ownership of Management	27
		Securities Authorized for Issuance under Equity Compensation Plans	27
	Item 13.	Certain Relationships and Related Transactions	28
Part IV
	Item 14.	Controls and Procedures	28
	Item 15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K	28
Signatures			32
Certifications			33

(ii)

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)

	Gross	Net
United States	1,387	1,140
Colombia (2)	3,706	384
	5,093	1,524

Productive Wells (3)

	Oil		Gas
	Gross	Net	Gross	Net
United States (4)	7	5.67	3	2.57
Colombia	14	1.45	—	—
	21	7.12	3	2.57

(1) Developed acreage is acreage assignable to productive wells.

(2) Excludes Aporte Putumayo acreage pending abandonment operations.

(3) Productive wells represent producing wells and wells capable of producing.

(4) As described in Note 10 to the consolidated financial statements, 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.

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.

	Undeveloped Acres
	Gross	Net
Colombia
Santana/Guayuyaco	48,636	14,406
Rio Magdalena	144,609	14,991
Papua New Guinea	1,228,187	24,564
	1,421,432	53,961

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.

8

Production, Sales Prices and Costs

The following table summarizes the Company’s oil production in thousands of barrels and natural gas production in millions of cubic feet for the years indicated:

		Year ended December 31,
		2002	2001	2000
Oil (1)	United States	27	33	49
	Colombia	59	61	157
Gas	United States	20	24	25
	Colombia	—	—	—

(1) Includes crude oil and condensate.

The average sales price per barrel of oil and per thousand cubic feet (“MCF”) of gas produced by the Company and the average production (lifting) cost per dollar of oil and gas revenue and per barrel of oil equivalent (6 MCF: 1 barrel) were as follows for the years indicated:

		Year ended December 31, (1)
		2002		2001		2000
Average sales price per barrel of oil (2)	United States	$	24.09	$	23.93	$	28.94
	Colombia	$	19.65	$	20.67	$	27.18
Average sales price per MCF of gas	United States	$	3.25	$	4.27	$	4.11
	Colombia	$	—	$	—	$	—
Average production cost per dollar of oil and gas revenue	United States	$	1.09	$	0.89	$	0.72
	Colombia	$	0.36	$	0.49	$	0.31
Average production cost per barrel of oil equivalent	United States	$	25.68	$	21.41	$	20.59
	Colombia	$	7.13	$	10.18	$	8.33

(1) All amounts are stated in United States dollars.

(2) Includes crude oil and condensate.

Significant Properties

Colombia.

The Company’s Colombian properties currently consist of 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.

9

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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Average WTI (“US$/bbl.”)	Contract Sales Price
$15 or less	Ave. WTI less $4.38 per bbl.
$15.01 to $20.00	Ave. WTI less $4.88 per bbl.
$20.01 to $25.00	Ave. WTI less $5.38 per bbl.
$25.01 to $30.00	Ave. WTI less $6.38 per bbl.
Over $30	Ave. WTI less $7.38 per bbl.

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.

11

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

12

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.

13

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.

	2002				2001
	High		Low		High		Low
OTC Bulletin Board:
Common Stock
First Quarter	$	0.11	$	0.05	$	n/a	$	n/a
Second Quarter	$	0.10	$	0.04	$	0.17	$	0.06
Third Quarter	$	0.12	$	0.04	$	0.10	$	0.05
Fourth Quarter	$	0.10	$	0.02	$	0.11	$	0.05
Depositary Shares(1)
First Quarter	$	n/a	$	n/a	$	0.38	$	0.15
Second Quarter	$	n/a	$	n/a	$	0.40	$	0.20
Third Quarter	$	n/a	$	n/a	$	n/a	$	n/a
Fourth Quarter	$	n/a	$	n/a	$	n/a	$	n/a

(1) Representing five shares of Common Stock.

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.

	For the Years Ended December 31,
	2002			2001		2000		1999			1998
	(in thousands, except per share, per barrel and per MCF data)
For the period
Revenues	$	1,968		$	2,609	$	6,183	$	6,797		$	3,332
Earnings (loss) before extraordinary item	$	(1,005	)	$	77	$	4,961	$	(403	)	$	(16,881	)
Extraordinary item—debt extinguishment	$	—		$	—	$	5,543	$	—		$	(197	)
Net earnings (loss)	$	(1,005	)	$	77	$	10,504	$	(403	)	$	(17,078	)
Earnings (loss) before extraordinary item per common share	$	(0.02	)	$	0.00	$	0.10	$	(0.01	)	$	(0.49	)
Basic and diluted net earnings (loss) per common share	$	(0.02	)	$	0.00	$	0.22	$	(0.01	)	$	(0.50	)
Weighted average shares outstanding		46,900			46,900		46,900		46,813			34,279
Cash dividends per common share	$	—		$	—	$	—	$	—		$	—
Total annual net oil production (barrels)
Colombia		59			61		157		365			255
United States		27			33		49		57			44
Total		86			94		206		422			299
Total annual net gas production (MCF)
United States		20			24		25		53			68
Average price per barrel of oil
Colombia	$	19.65		$	20.67	$	27.18	$	15.57		$	10.31
United States	$	24.09		$	23.93	$	28.94	$	17.13		$	12.03
Average price per MCF of Gas—United States	$	3.25		$	4.27	$	4.11	$	2.42		$	2.42
At period end
Total assets	$	3,078		$	3,134	$	3,311	$	8,986		$	11,422
Long term debt, including current portion	$	—		$	—	$	—	$	14,495		$	14,805
Stockholders’ equity (deficit)	$	948		$	1,953	$	1,876	$	(11,483	)	$	(11,083	)

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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ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
	OPERATIONS.

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

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

	United States						Colombia
	Oil			Gas			Oil			Total
	(Thousands)
Oil and gas sales—2001	$	782		$	101		$	1,253		$	2,136
Volume variance		(144	)		(16	)		(11	)		(171	)
Price variance		4			(20	)		(78	)		(94	)
Oil and gas sales—2002	$	642		$	65		$	1,164		$	1,871

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.

16

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

	United States						Colombia
	Oil			Gas			Oil			Total
	(Thousands)
Oil and gas sales—2000	$	1,428		$	100		$	4,268		$	5,796
Volume variance		(482	)		(28	)		(2,584	)		(3,094	)
Price variance		(164	)		29			(431	)		(566	)
Oil and gas sales—2001	$	782		$	101		$	1,253		$	2,136

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.

ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL .
	DISCLOSURE

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.

Name	Age	Positions	Director Since
Ronald Suttill	71	President, Chief Executive Officer and Director	1985
Robert J. Cresci	59	Director	1998

The following sets forth the periods during which directors have served as such and a brief account of the business experience of such persons during at least the past five years.

Ronald Suttill has been a director of the Company since August 1985 and has been President and Chief Executive Officer of the Company since January 1992.

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.

Name and Age	Positions
Ronald Suttill, 71	President and Chief Executive Officer since January 1992.
James L. Busby, 42	Chief Financial Officer since February 2000, Treasurer since May 1994, Secretary since June 1996, Controller since November 1993.

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

					Long Term Compensation
	Annual Compensation				Awards		Payouts
Name and Principal Position	Year	Salary ($)	Bonus ($)	Other Annual Compensation ($)	Restricted Stock Award(s) ($)	Securities Underlying Options/ SARs (#)	LTIP Payouts ($)	All Other Compensation ($)
Ronald Suttill(1)
President and CEO	2002	150,000	—	—	—	—	—	9,000
President and CEO	2001	150,000	—	—	—	—	—	9,000
President and CEO	2000	150,000	7,500	—	—	—	—	9,000

(1) The amount recorded under bonus represents the market value of 300,000 shares of the Company’s common stock transferred to Mr. Suttill in connection with the debt restructuring and transfer of partnership interests to the Company’s former lender, effective June 8, 2000. The amounts reported for all other compensation for Mr. Suttill represent matching contributions made under the Aviva Petroleum Inc. 401(k) Retirement Plan (the “401(k) Plan”).

Directors’ Fees

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.

	Options Granted (#) (1)	% of Total Options Granted to Employees in Fiscal Year	Exercise or Base Price per share	Expiration Date	Potential Realizable Valued at Assumed Annual Rates of Stock Price Appreciation for Option Term (2)
Name					5%	10%
Ronald Suttill	100,000	33%	$0.08	January 16, 2012	$5,030	$12,750

(1) These options were granted pursuant to the Aviva Petroleum Inc. 1995 Stock Option Plan, as amended. The exercise price of the options was equal to the fair market value of a share of the Company’s Common Stock on the date of grant. The right to exercise each of the above options vests over a three-year period. The options are exercisable for a period of 10 years after the date of grant unless the optionee resigns, retires or dies, in which case the right to exercise the option is limited.

(2) The values set forth in this column represent the gain which would be realized by the Named Executive Officer assuming (i) the option granted in 2002 is exercised on January 16, 2012; and (ii) the value of a share of the Company’s Common Stock has increased annually by a rate of 5% and 10% respectively, during the term of the option. These growth rates are prescribed by the rules of the SEC and are not intended to forecast possible future appreciation for the Company’s Common Stock.

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.

	Shares Acquired on Exercise (#)	Value Realized ($)	Number of Securities Underlying Unexercised Options at FY-End (#)		Value of Unexercised In-the-Money Options at FY-End ($) (1)
Name			Exercisable	Unexercisable	Exercisable	Unexercisable
Ronald Suttill	none	none	223,334	—	—	—

(1) No values are ascribed to unexercised options of the Named Executive Officer at December 31, 2002 because the fair market value of a share of the Company’s Common Stock at December 31, 2002 ($0.06) did not exceed the exercise price of any such options.

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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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

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.

Name and Address of Beneficial Owner or Group	Amount and Nature of Beneficial Ownership (1)	Percent of Class (2)
Ramat Securities Ltd.(3) Chagrin Plaza East 23811 Chagrin Blvd., Suite 200 Beachwood, Ohio 44122	10,632,470	22.67%
Ronald Suttill (4)(5) 8235 Douglas Avenue, Suite 400 Dallas, Texas 75225	4,070,106	8.32%(6)
Lehman Brothers Inc. (7) 745 Seventh Avenue New York, New York 10019	2,968,576	6.33%
Yale University (8) 230 Prospect Street New Haven, Connecticut 06511	2,551,886	5.44%

(1) Except as set forth below, to the knowledge of the Company, each beneficial owner has sole voting and sole investment power.

(2) Based on 46,900,132 shares of the Common Stock issued and outstanding on February 28, 2003.

(3) Information regarding Ramat Securities Ltd. (“Ramat”) is based on a Schedule 13D/A filed on May 17, 2001, as a joint filing for Ramat, David Zlatin, Howard Amster, Amster Trading Company Charitable Remainder Unitrusts (“Amster Unitrusts”), and Amster Trading Company. Ramat owns 6,577,370 shares (14.02% of the outstanding) and has shared voting and dispositive power as to those shares. Through his ownership in Ramat, David Zlatin beneficially owns an aggregate of 6,577,370 shares and has shared voting and dispositive power over those shares. The Amster Unitrusts own 4,055,100 shares (8.65% of the outstanding) and have shared voting and dispositive power as to those shares. Howard Amster is the trustee of the Amster Unitrusts. Howard Amster beneficially owns an aggregate of 6,577,370 shares and has shared voting and dispositive power as to 4,055,100 shares. The Amster Unitrusts have been funded 100% by Amster Trading Company. Howard Amster is the 100% owner of Amster Trading Company. Because Amster Trading Company has the right to change the trustee of the trusts, it can be deemed to have the right to shared voting and dispositive power as to the 4,055,100 shares owned by the Amster Unitrusts. Amster Trading Company disclaims beneficial ownership of the securities owned by the Amster Unitrusts.

(4) Included are warrants for 1,000,000 shares and options for 256,667 shares exercisable on or within 60 days of February 28, 2003.

(5) Includes the entire ownership of AMG Limited, a limited liability company of which Mr. Suttill is a member, as of February 28, 2003, of 935,550 shares of Common Stock.

(6) Treated as outstanding for purposes of computing the percentage ownership of Mr. Suttill are 1,000,000 shares pursuant to outstanding warrants and 1,026,500 shares issuable to all participants upon exercise of vested stock options granted pursuant to the Company’s stock option plans.

(7) Information regarding Lehman Brothers Inc. is based on a Schedule 13G dated February 14, 2003 filed by Lehman Brothers Inc. with the SEC.

(8) Information regarding Yale University is based on a Schedule 13G dated March 11, 1994 filed by Yale University with the SEC.

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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:

Name and Address of Beneficial Owner	Amount and Nature of Beneficial Ownership (1)	Percent of Class (2)
Ronald Suttill 8235 Douglas Avenue, Suite 400 Dallas, TX 75225	4,070,106 (3)(4)	8.32%
Robert J. Cresci Pecks Management Partners Ltd. One Rockefeller Plaza New York, NY 10020	237,500 (5)	*
All directors and executive officers as a group (3 persons)	5,613,691 (6)	11.47%

(1) Except as noted below, each beneficial owner has sole voting power and sole investment power.

(2) Based on 46,900,132 shares of Common Stock issued and outstanding on February 28, 2003. Treated as outstanding for purposes of computing the percentage ownership of each director, the Named Executive Officer and all directors and executive officers as a group are 1,026,500 shares issuable upon exercise of vested stock options granted pursuant to the Company’s stock option plans and 1,000,000 shares represented by warrants issued to Ronald Suttill.

(3) Included are warrants for 1,000,000 shares and options for 256,667 shares exercisable on or within 60 days of February 28, 2003.

(4) Includes the entire ownership of AMG Limited, a limited liability company of which Mr. Suttill is a member, as of February 28, 2003, of 935,550 shares of Common Stock.

(5) Included are options for 37,500 shares exercisable on or within 60 days of February 28, 2003.

(6) Included are 935,550 shares beneficially owned through AMG Limited, warrants for 1,000,000 shares and options for 487,500 shares exercisable on or within 60 days of February 28, 2003.

* Less than 1% of the outstanding Aviva Common Stock.

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:

Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)	Weighted-average exercise price of outstanding options, warrants and rights (b)	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)
Equity compensation plans approved by security holders	1,134,000	$0.25	56,000
Equity compensation plans not approved by security holders	—	—	—
Total	1,134,000	$0.25	56,000

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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

a. The following documents are filed as part of this report:

(1) Financial Statements: The Financial Statements of Aviva Petroleum Inc. filed as part of this report are listed in the “Index to Financial Statements” included elsewhere herein.

(2) Financial Statement Schedules: All schedules called for under Regulation S-X have been omitted because they are not applicable, the required information is not material or the required information is included in the consolidated financial statements or notes thereto.

(3) Exhibits:

*2.1	Loan, Settlement and Acquisition Agreement dated effective May 31, 2000, by and among Crosby Capital, LLC, Aviva Petroleum Inc., Aviva America, Inc., Aviva Operating Company, Aviva Overseas, Inc., Neo Energy, Inc., Garnet Resources Corporation, Argosy Energy, Inc., and Argosy Energy International (filed as exhibit 2.1 to the Company’s Form 8-K dated June 8, 2000, File No. 0-22258, and incorporated herein by reference).
*2.2	Confirmed Plan of Reorganization of Aviva America, Inc. (filed as exhibit 2.4 to the Company’s annual report on Form 10-K for the year ended December 31, 2000, File No. 0-22258, and incorporated by reference).
*3.1	Restated Articles of Incorporation of the Company dated July 25, 1995 (filed as exhibit 3.1 to the Company’s annual report on Form 10-K for the year ended December 31, 1995, File No. 0-22258, and incorporated herein by reference).
*3.2	Amended and Restated Bylaws of the Company, as amended as of January 23, 1995 (filed as exhibit 3.2 to the Company’s annual report on Form 10-K for the year ended December 31, 1994, File No. 0-22258, and incorporated herein by reference).
*10.1	Risk Sharing Contract between Empresa Colombiana de Petroleos (“Ecopetrol”), Argosy Energy International (“Argosy”) and Neo Energy, Inc. (“Neo”) (filed as exhibit 10.1 to the Company’s Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference).
*10.2	Contract for Exploration and Exploitation of Sector Number 1 of the Aporte Putumayo Area (“Putumayo”) between Ecopetrol and Cayman Corporation of Colombia dated July 24, 1972 (filed as exhibit 10.2 to the Company’s Registration Statement on Form 10, File No. 0-22258, and incorporated herein by reference).

28

*10.3	Operating Agreement for Putumayo between Argosy and Neo dated September 16, 1987 and amended on January 4, 1989 and February 23, 1990 (filed as exhibit 10.3 to the Company’s Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference).
*10.4	Operating Agreement for the Santana Area (“Santana”) between Argosy and Neo dated September 16, 1987 and amended on January 4, 1989, February 23, 1990 and September 28, 1992 (filed as exhibit 10.4 to the Company’s Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference).
*10.5	Santana Block A Relinquishment dated March 6, 1990 between Ecopetrol, Argosy and Neo (filed as exhibit 10.8 to the Company’s Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference).
*10.6	Employee Stock Option Plan of the Company (filed as exhibit 10.13 to the Company’s Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference).
*10.7	Santana Block B 50% relinquishment dated September 13, 1993 between Ecopetrol, Argosy and Neo (filed as exhibit 10.26 to the Company’s annual report on Form 10-K for the year ended December 31, 1993, File No. 0-22258, and incorporated herein by reference).
*10.8	Aviva Petroleum Inc. 401(k) Retirement Plan effective March 1, 1992 (filed as exhibit 10.29 to the Company’s annual report on Form 10-K for the year ended December 31, 1993, File No. 0-22258, and incorporated herein by reference).
*10.9	Relinquishment of Putumayo dated December 1, 1993 (filed as exhibit 10.30 to the Company’s annual report on Form 10-K for the year ended December 31, 1993, File No. 0-22258, and incorporated herein by reference).
*10.10	Deposit Agreement dated September 15, 1994 between the Company and Chemical Shareholder Services Group, Inc. (filed as exhibit 10.29 to the Company’s Registration Statement on Form S-1, File No. 33-82072, and incorporated herein by reference).
*10.11	Letter from Ecopetrol dated December 28, 1994, accepting relinquishment of Putumayo (filed as exhibit 10.38 to the Company’s annual report on Form 10-K for the year ended December 31, 1994, File No. 0-22258, and incorporated herein by reference).
*10.12	Amendment to the Incentive and Nonstatutory Stock Option Plan of the Company (filed as exhibit 10.4 to the Company’s quarterly report on Form 10-Q for the quarter ended September 30, 1995, File No. 0-22258, and incorporated herein by reference).
*10.13	Santana Block B 25% relinquishment dated October 2, 1995 (filed as exhibit 10.51 to the Company’s annual report on Form 10-K for the year ended December 31, 1995, File No. 0-22258, and incorporated herein by reference).
*10.14	Aviva Petroleum Inc. 1995 Stock Option Plan, as amended (filed as Appendix A to the Company’s definitive Proxy Statement for the Annual Meeting of Shareholders dated June 10, 1997, and incorporated herein by reference).
*10.15	Restated Credit Agreement dated as of October 28, 1998, between Neo Energy, Inc., Aviva Petroleum Inc. and ING (U.S.) Capital Corporation (filed as exhibit 99.1 to the Company’s Form 8-K dated October 28, 1998, File No. 0-22258, and incorporated herein by reference).
*10.16	Joint Finance and Intercreditor Agreement dated as of October 28, 1998, between Neo Energy, Inc., Aviva Petroleum Inc., ING (U.S.) Capital Corporation, Aviva America, Inc., Aviva Operating Company, Aviva Delaware Inc., Garnet Resources Corporation, Argosy Energy Incorporated, Argosy Energy International, Garnet PNG Corporation, the Overseas Private Investment Corporation, Chase Bank of Texas, N.A. and ING (U.S.) Capital Corporation as collateral agent for the creditors (filed as exhibit 99.2 to the Company’s Form 8-K dated October 28, 1998, File No. 0-22258, and incorporated herein by reference).
*10.17	Amended and Restated Aviva Petroleum Inc. Severance Benefit Plan dated December 31, 1999 (filed as exhibit 10.18 to the Company’s annual report on Form 10-K for the year ended December 31, 1999, File No. 0-22258, and incorporated herein by reference).
*10.18	Santana Crude Sale and Purchase Agreement dated January 3, 2000 (filed as exhibit 10.19 to the Company’s annual report on Form 10-K for the year ended December 31, 1999, File No. 0-22258, and incorporated herein by reference).
*10.19	Employment Agreement between the Company and Ronald Suttill dated February 1, 2000 (filed as exhibit 10.20 to the Company’s annual report on Form 10-K for the year ended December 31, 1999, File No. 0-22258, and incorporated herein by reference).
*10.20	Employment Agreement between the Company and James L. Busby dated February 1, 2000 (filed as exhibit 10.21 to the Company’s annual report on Form 10-K for the year ended December 31, 1999, File No. 0-22258, and incorporated herein by reference).

29

*10.21	Service Agreement between Argosy Energy International and Aviva Overseas, Inc. dated as of June 1, 2000 (filed as exhibit 10.1 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2000, File No. 0-22258, and incorporated herein by reference).
*10.22	Letter Agreement dated June 8, 2000 between Crosby Capital, LLC and Aviva America, Inc. (filed as exhibit 10.2 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2000, File No. 0-22258, and incorporated herein by reference).
*10.23	Guaranty dated May 31, 2000 made by Aviva Overseas, Inc. in favor of Crosby Capital, LLC (filed as exhibit 10.3 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2000, File No. 0-22258, and incorporated herein by reference).
*10.24	Assignment and Assumption Agreement dated June 1, 2000, between Crosby Capital, LLC and Neo Energy, Inc. (filed as exhibit 10.4 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2000, File No. 0-22258, and incorporated herein by reference).
*10.25	Assignment and Assumption Agreement dated June 1, 2000 between Crosby Acquisition LLC and Argosy Energy, Inc. (filed as exhibit 10.5 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2000, File No. 0-22258, and incorporated herein by reference).
*10.26	Assignment and Assumption Agreement dated June 1, 2000 between Crosby Capital, LLC and Garnet Resources Corp. (filed as exhibit 10.6 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2000, File No. 0-22258, and incorporated herein by reference).
*10.27	Assignment and Assumption Agreement dated June 1, 2000 between Crosby Capital, LLC and Aviva Overseas, Inc. (filed as exhibit 10.7 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2000, File No. 0-22258, and incorporated herein by reference).
*10.28	Assignment and Assumption Agreement dated June 1, 2000 between Argosy Energy, Incorporated and Crosby Acquisition, LLC (filed as exhibit 10.8 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2000, File No. 0-22258, and incorporated herein by reference).
*10.29	Assignment and Assumption Agreement dated June 1, 2000 between Crosby Capital, LLC and Aviva Overseas, Inc. (filed as exhibit 10.9 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2000, File No. 0-22258, and incorporated herein by reference).
*10.30	Pledge Agreement dated May 31, 2000 executed by Aviva Overseas, Inc. (Debtor) in favor of Crosby Capital, LLC (Secured Party) (filed as exhibit 10.10 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2000, File No. 0-22258, and incorporated herein by reference).
*10.31	Third Amendment to Second Amended and Restated Limited Partnership Agreement of Argosy Energy International dated May 31, 2000 (filed as exhibit 10.11 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2000, File No. 0-22258, and incorporated herein by reference).
*10.32	Fourth Amendment to Second Amended and Restated Limited Partnership Agreement of Argosy Energy International dated June 1, 2000 (filed as exhibit 10.12 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2000, File No. 0-22258, and incorporated herein by reference).
*10.33	Assignment of Stock Warrant Rights dated May 31, 2000 executed by Crosby Capital, LLC in favor of Aviva Petroleum Inc. (filed as exhibit 10.13 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2000, File No. 0-22258, and incorporated herein by reference).
*10.34	Assignment of Neo Debt and Collateral, dated December 21, 2000 from Crosby Capital, LLC to Aviva Operating Company (filed as exhibit 10.34 to the Company’s annual report on Form 10-K for the year ended December 31, 2000, File No. 0-22258, and incorporated herein by reference).
*10.35	Conveyance of Net Profits Interest, dated December 21, 2000 from Aviva America, Inc. to Crosby Capital, LLC (filed as exhibit 10.35 to the Company’s annual report on Form 10-K for the year ended December 31, 2000, File No. 0-22258, and incorporated herein by reference).
*10.36	Santana Crude Sale and Purchase Agreement dated January 3, 2001 (filed as exhibit 10.1 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2001, File No. 0-22258, and incorporated herein by reference).

30

*10.37	Santana Crude Sale and Purchase Agreement dated January 30, 2002 (filed as exhibit 10.37 to the Company’s annual report on Form 10-K for the year ended December 31, 2001, File No. 0-22258, and incorporated herein by reference).
*10.38	Rio Magdalena Association Contract dated December 10, 2001 between Ecopetrol and Argosy (filed as exhibit 10.38 to the Company’s annual report on Form 10-K for the year ended December 31, 2001, File No. 0-22258, and incorporated herein by reference).
**10.39	Promissory note dated December 12, 2002 issued to Ronald Suttill.
**10.40	Stock purchase warrant dated December 12, 2002, issued to Ronald Suttill.
**10.41	Guayuyaco Association Contract dated August 2, 2002 between Ecopetrol and Argosy.
*21.1	List of subsidiaries of Aviva Petroleum Inc. (filed as exhibit 21.1 to the Company’s annual report on Form 10-K for the year ended December 31, 2000, File No. 0-22258, and incorporated herein by reference).
**99.1	Certification by Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act (18 U.S.C. Section 1350)
**99.2	Certification by Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act (18 U.S.C. Section 1350)

* Previously Filed

** Filed Herewith

b. Reports on Form 8-K

The Company did not file any Current Reports on Form 8-K during and subsequent to the end of the fourth quarter.

31

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	AVIVA PETROLEUM INC.
By:	/s/  Ronald Suttill
	Ronald Suttill
	Chief Executive Officer and Director

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Ronald Suttill Ronald Suttill	President, Chief Executive Officer and Director (principal executive officer)	March 25, 2003
/s/ James L. Busby James L. Busby	Secretary, Treasurer and Chief Financial Officer (principal financial and accounting officer)	March 25, 2003
/s/ Robert J. Cresci Robert J. Cresci	Director	March 25, 2003

32

CERTIFICATIONS

I, Ronald Suttill, President and Chief Executive Officer of Aviva Petroleum Inc., certify that:

1. I have reviewed this annual report on Form 10-K of Aviva Petroleum Inc.;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: March 25, 2003

/s/ Ronald Suttill                             

Ronald Suttill

President and

Chief Executive Officer

33

I, James L. Busby, Secretary, Treasurer and Chief Financial Officer of Aviva Petroleum Inc., certify that:

1. I have reviewed this annual report on Form 10-K of Aviva Petroleum Inc.;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: March 25, 2003

/s/ James L. Busby                        

James L. Busby

Secretary, Treasurer and

Chief Financial Officer

34

INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

	Page
Independent Auditors’ Report	36
Consolidated Balance Sheet as of December 31, 2002 and 2001	37
Consolidated Statement of Operations for the years ended December 31, 2002, 2001 and 2000	38
Consolidated Statement of Cash Flows for the years ended December 31, 2002, 2001 and 2000	39
Consolidated Statement of Stockholders’ Equity (Deficit) for the years ended December 31, 2002, 2001 and 2000	40
Notes to Consolidated Financial Statements	41
Supplementary Information Related to Oil and Gas Producing Activities (Unaudited)	53

All schedules called for under Regulation S-X have been omitted because they are not applicable, the required information is not material or the required information is included in the consolidated financial statements or notes thereto.

35

INDEPENDENT AUDITORS’ REPORT

The Board of Directors

Aviva Petroleum Inc.:

We have audited the accompanying consolidated financial statements of Aviva Petroleum Inc. and subsidiaries as listed in the accompanying index. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Aviva Petroleum Inc. and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the financial statements, the Company has incurred a net loss of $1,005,000 for the year ended December 31, 2002, has limited available financial resources to support its ongoing operations and is dependent upon distributions from its Colombia operations. These factors raise substantial doubt concerning the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 2. The consolidated financial statements do not include any adjustments relating to the recoverability and classification of asset carrying amounts or the amount and classification of liabilities that might result should the Company be unable to continue as a going concern.

/s/ KPMG LLP                         

Dallas, Texas

March 7, 2003

36

AVIVA PETROLEUM INC. AND SUBSIDIARIES

Consolidated Balance Sheet

December 31, 2002 and 2001

(in thousands, except number of shares)

	2002			2001
ASSETS
Current assets:
Cash and cash equivalents	$	1,708		$	1,010
Accounts receivable (note 9):
Oil and gas revenue		61			42
Trade		42			66
Other		20			79
Inventories		193			209
Prepaid expenses and other		116			140
Total current assets		2,140			1,546
Property and equipment, at cost:
Oil and gas properties and equipment (full cost method)		20,370			20,244
Other		337			334
		20,707			20,578
Less accumulated depreciation, depletion and amortization		(19,874	)		(19,981	)
		833			597
Other assets (note 4)		105			991
	$	3,078		$	3,134
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	916		$	776
Accrued liabilities		163			37
Accrued abandonment liability (note 10)		908			—
Short-term debt (note 5)		50			—
Total current liabilities		2,037			813
Other liabilities		93			368
Stockholders’ equity (note 7):
Common stock, no par value, authorized 348,500,000 shares; issued 46,900,132 shares		2,345			2,345
Additional paid-in capital		37,710			37,710
Accumulated deficit*		(39,107	)		(38,102	)
Total stockholders’ equity		948			1,953
Commitments and contingencies (note 10)
	$	3,078		$	3,134

*Accumulated deficit of $70,057 was eliminated at December 31, 1992 in connection with a quasi-reorganization.

See note 7.

See accompanying notes to consolidated financial statements.

37

AVIVA PETROLEUM INC. AND SUBSIDIARIES

Consolidated Statement of Operations

Years Ended December 31, 2002, 2001 and 2000

(in thousands, except per share data)

	2002			2001			2000
Revenue:
Oil and gas sales (note 9)	$	1,871		$	2,136		$	5,796
Service fees (note 3)		97			473			387
Total revenue		1,968			2,609			6,183
Expense:
Production		1,193			1,402			2,407
Depreciation, depletion and amortization		209			320			515
Provision for abandonment and impairment (note 10)		592			—			—
General and administrative		1,086			1,006			1,157
Recovery of losses on accounts receivable		(4	)		(48	)		(256	)
Total expense		3,076			2,680			3,823
Other income (expense):
Gain on transfer of partnership interests (note 3)		—			—			3,452
Interest and other income (expense), net (note 6)		175			235			207
Interest expense		(33	)		(3	)		(805	)
Total other income (expense)		142			232			2,854
Earnings (loss) before income taxes and extraordinary item		(966	)		161			5,214
Income taxes (note 8)		(39	)		(84	)		(253	)
Earnings (loss) before extraordinary item		(1,005	)		77			4,961
Extraordinary item – debt extinguishment, net of income taxes of $2,855 (notes 3 and 11)		—			—			5,543
Net earnings (loss)	$	(1,005	)	$	77		$	10,504
Weighted average common shares outstanding—basic and diluted		46,900			46,900			46,900
Basic and diluted net earnings (loss) per common share:
Before extraordinary item	$	(0.02	)	$	0.00		$	0.10
Extraordinary item		—			—			0.12
Net earnings (loss)	$	(0.02	)	$	0.00		$	0.22

See accompanying notes to consolidated financial statements.

38

AVIVA PETROLEUM INC. AND SUBSIDIARIES

Consolidated Statement of Cash Flows

Years Ended December 31, 2002, 2001 and 2000

(in thousands)

	2002			2001			2000
Net earnings (loss)	$	(1,005	)	$	77		$	10,504
Adjustments to reconcile net earnings (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		209			320			515
Provision for abandonment and impairment		592			—			—
Recovery of losses on accounts receivable		(4	)		(48	)		(256	)
Gain on transfer of partnership interests		—			—			(3,452	)
Gain on debt extinguishment		—			—			(5,543	)
Loss (gain) on sale of assets, net		—			(4	)		4
Foreign currency exchange gain, net		(29	)		(11	)		(44	)
Other		(94	)		(127	)		(357	)
Changes in assets and liabilities, net of effects of transfer of partnership interests:
Escrow account		—			—			4
Accounts receivable		5			155			204
Inventories		17			8			10
Prepaid expenses and other		25			51			27
Accounts payable and accrued liabilities		216			(231	)		106
Net cash provided by (used in) operating activities		(68	)		190			1,722
Cash flows from investing activities:
Transfer from abandonment fund		902			—			—
Costs of and cash balances acquired (surrendered) in connection with the transfer of partnership interests from (to) former lender		—			41			(1,414	)
Property and equipment expenditures		(230	)		(135	)		(382	)
Proceeds from sale of assets		—			4			—
Other		—			80			—
Net cash provided by (used in) investing activities		672			(10	)		(1,796	)
Cash flows from financing activities-     Proceeds from issuance of short term debt		50			—			—
Effect of exchange rate changes on cash and cash equivalents		44			10			48
Net increase (decrease) in cash and cash equivalents		698			190			(26	)
Cash and cash equivalents at beginning of year		1,010			820			846
Cash and cash equivalents at end of year	$	1,708		$	1,010		$	820

See accompanying notes to consolidated financial statements.

39

AVIVA PETROLEUM INC. AND SUBSIDIARIES

Consolidated Statement of Stockholders’ Equity (Deficit)

Years Ended December 31, 2002, 2001 and 2000

(in thousands, except number of shares)

	Common Stock
	Number of Shares	Amount		Additional Paid-in Capital		Accumulated Deficit			Total Stockholders’ Equity (Deficit)
Balances at December 31, 1999	46,900,132	$	2,345	$	34,855	$	(48,683	)	$	(11,483	)
Tax benefits relating to January 1, 1993 valuation allowance (note 8)	—		—		2,855		—			2,855
Net earnings	—		—		—		10,504			10,504
Balances at December 31, 2000	46,900,132		2,345		37,710		(38,179	)		1,876
Net earnings	—		—		—		77			77
Balances at December 31, 2001	46,900,132		2,345		37,710		(38,102	)		1,953
Net loss	—		—		—		(1,005	)		(1,005	)
Balances at December 31, 2002	46,900,132	$	2,345	$	37,710	$	(39,107	)	$	948

See accompanying notes to consolidated financial statements.

40

AVIVA PETROLEUM INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

(1) Summary of Significant Accounting Policies

General

Aviva Petroleum Inc. and its subsidiaries (the “Company”) are engaged in the business of exploring for, developing and producing oil and gas in Colombia and in the United States. The Company’s Colombian oil production is sold to Empresa Colombiana de Petroleos, the Colombian national oil company (“Ecopetrol”), while the Company’s U.S. oil and gas production is sold to principally one U.S. purchaser (See notes 9 and 12).

Oil and gas are the Company’s only products, and there is substantial uncertainty as to the prices that the Company may receive for its production. A decrease in these prices would affect operating results adversely.

Basis of Presentation

The Company’s consolidated financial statements have been presented on a going concern basis which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. As discussed in note 2 below, there is substantial doubt concerning the Company’s ability to continue operating as a going concern. The consolidated financial statements do not include any adjustments relating to the recoverability and classification of asset carrying amounts or the amount and classification of liabilities that might result should the Company be unable to continue as a going concern.

Principles of Consolidation

The consolidated financial statements include the accounts of Aviva Petroleum Inc. and its subsidiaries. The Company proportionately consolidates less than 100% owned oil and gas partnerships in accordance with industry practice. All significant intercompany accounts and transactions have been eliminated in consolidation.

Inventories

Inventories consist primarily of tubular goods, oilfield equipment and spares and are stated at the lower of average cost or market.

Property and Equipment

Under the full cost method of accounting for oil and gas properties, all productive and nonproductive property acquisition, exploration and development costs are capitalized in separate cost centers for each country. Such capitalized costs include lease acquisition costs, delay rentals, geophysical, geological and other costs, drilling, completion and other related costs and direct general and administrative expenses associated with property acquisition, exploration and development activities. Capitalized general and administrative costs include internal costs such as salaries and related benefits paid to employees to the extent that they are directly engaged in such activities, as well as all other directly identifiable general and administrative costs associated with such activities, including rent, utilities and insurance and do not include any costs related to production, general corporate overhead, or similar activities. Capitalized internal general and administrative costs were $101,000 in 2002, $66,000 in 2001 and $57,000 in 2000.

Evaluated capitalized costs of oil and gas properties and the estimated future development, site restoration, dismantlement and abandonment costs are amortized by cost center, using the units-of-production method. Total net future site restoration, dismantlement and abandonment costs are estimated to be $1,052,000.

Depreciation, depletion and amortization expense per equivalent barrel of production was as follows:

	2002		2001		2000
United States	$	3.26	$	5.24	$	2.62
Colombia	$	1.49	$	1.66	$	2.29

In accordance with the full cost method of accounting, the net capitalized costs of oil and gas properties less related deferred income taxes for each cost center are limited to the sum of the estimated future net revenues from the properties at current prices less estimated future expenditures, discounted at 10%, and unevaluated costs not being amortized, less income tax effects related to differences between the financial and tax bases of

41

AVIVA PETROLEUM INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

the properties, computed on a quarterly basis. An excess of the capitalized costs relating to the U.S. cost center over the limitation at December 31, 2001 was not charged against earnings because of a price increase subsequent to year-end. As discussed more fully in Note 10, during the fourth quarter of 2002 the Company recorded a charge of $592,000 to fully accrue for the abandonment of the Breton Sound field and to write off the remaining undeveloped leasehold costs associated with this field.

Depletion expense and limits on capitalized costs are based on estimates of oil and gas reserves which are inherently imprecise and assume current prices for future net revenues. Accordingly, it is reasonably possible that the estimates of reserves quantities and future net revenues could differ materially in the near term from amounts currently estimated. Moreover, a future decrease in the prices the Company receives for its oil and gas production or downward reserve adjustments could result in a ceiling test write-down that is significant to the Company’s operating results.

Gains and losses on sales of oil and gas properties are not recognized in income unless the sale involves a significant portion of the reserves associated with a particular cost center. Capitalized costs associated with unevaluated properties are excluded from amortization until it is determined whether proved reserves can be assigned to such properties or until the value of the properties is impaired. Unevaluated costs of $246,000 and $303,000 were excluded from amortization at December 31, 2002 and 2001, respectively. Unevaluated properties are assessed quarterly to determine whether any impairment has occurred. The unevaluated costs at December 31, 2002 represent exploration costs and were incurred primarily during the six-year period ended December 31, 2002. Such costs are expected to be evaluated and included in the amortization computation within the next three years.

Other property and equipment is depreciated using the straight-line method over the estimated useful lives of the assets.

Gas Balancing

The Company uses the entitlements method of accounting for gas sales. Gas production taken by the Company in excess of amounts entitled is recorded as a liability to the other joint owners. Excess gas production taken by others is recognized as income to the extent of the Company’s proportionate share of the gas sold and a related receivable is recorded from the other joint owners. At December 31, 2002, the Company had gas imbalance receivables of $2,000.

Interest Expense

The Company capitalizes interest costs on qualifying assets, principally unevaluated oil and gas properties. During 2000 the Company capitalized $43,000 of interest. No interest was capitalized in 2002 and 2001.

Earnings Per Common Share

Basic earnings per share (“EPS”) is computed by dividing income available to common shareholders by the weighted-average number of common shares outstanding for the period. Diluted EPS reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock or resulted in the issuance of common stock that then shared in the earnings of the entity. For the years presented herein, basic and diluted EPS are the same since the effects of potential common shares (note 7) are either antidilutive or insignificant. For fiscal year 2001, options for 599,000 common shares were not included in the computation of diluted earnings per share, because their exercise price approximated the average market price of the common shares and the effect would be insignificant. For fiscal year 2000, options for 1,024,000 common shares were not included in the computation of diluted earnings per share because their exercise price was greater than the average market price of the common shares and, therefore, the effect would be antidilutive.

Income Taxes

The Company accounts for income taxes in accordance with Statement of Financial Accounting Standards No. 109 (“Statement 109”) which requires recognition of deferred tax assets in certain circumstances and deferred tax liabilities for the future tax consequences of temporary differences between the financial statement carrying amounts and the tax bases of assets and liabilities.

42

AVIVA PETROLEUM INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

Statement of Cash Flows

The Company considers all highly liquid debt instruments with original maturities of three months or less to be cash equivalents. The Company paid interest, net of amounts capitalized, of $1,000 in 2002, $3,000 in 2001 and $(37,000) in 2000 and paid income taxes of $4,000 in 2002, $107,000 in 2001 and $267,000 in 2000.

Stock Option Plan

The Company applies the intrinsic-value-based method of accounting prescribed by Accounting Principles Board (APB) Opinion No. 25,Accounting for Stock Issued to Employees, and related interpretations including FASB Interpretation No. 44,Accounting for Certain Transactions involving Stock Compensation, an interpretation of APB Opinion No. 25, issued in March 2000, to account for its fixed-plan stock options. Under this method, compensation expense is recorded on the date of grant only if the current market price of the underlying stock exceeded the exercise price. SFAS No. 123,Accounting for Stock-Based Compensation, established accounting and disclosure requirements using a fair-value-based method of accounting for stock-based employee compensation plans. As allowed by SFAS No. 123, the Company has elected to continue to apply the intrinsic-value-based method of accounting described above, and has adopted only the disclosure requirements of SFAS No. 123. The following table illustrates the effect on net income if the fair-value-based method had been applied to all outstanding and unvested awards in each period.

	2002			2001
	(In thousands, except per share data)
Net earnings (loss), as reported	$	(1,005	)	$	77
Add stock-based employee compensation expense included in reported net income, net of tax		—			—
Deduct total stock-based employee compensation expense determined under fair-value-based method for all rewards, net of tax		(14	)		0
Pro forma net earnings (loss)	$	(1,019	)	$	77
As reported and pro forma net earnings (loss) per common share	$	(0.02	)	$	0.00

Fair Value of Financial Instruments

The reported values of cash, cash equivalents, accounts receivable and accounts payable approximate fair value due to their short maturities.

Foreign Currency Translation

The accounts of the Company’s foreign operations are translated into United States dollars in accordance with Statement of Financial Accounting Standards No. 52. The United States dollar is used as the functional currency. Exchange adjustments resulting from foreign currency transactions are recognized in expense or income in the current period.

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Comprehensive Income

Comprehensive income includes net income and other comprehensive income which is generally comprised of changes in the fair value of available-for-sale marketable securities, derivative instruments accounted for as hedges, foreign currency translation adjustments and adjustments to recognize additional minimum pension liabilities. For each period presented in the accompanying consolidated statement of operations, comprehensive income and net income are the same amount.

43

AVIVA PETROLEUM INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(2) Liquidity

As discussed in note 10, 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, 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.

(3) Debt Restructuring and Transfer of Partnership Interests

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 for 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. 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 when the lender had received in distributions from Argosy an amount equal to $3,500,000 plus interest at the prime rate plus 1% on the outstanding balance thereof.

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”) (see note 11).

In order to assist the lender in maximizing the value of its interest in Argosy, the lender entered into a Service Agreement with Aviva Overseas pursuant to which Aviva Overseas would provide certain services in administering the Colombian assets in exchange for a monthly fee. The fee was $71,000 per month for the period June 1, 2000 through March 31, 2001, $46,000 per month for the period April 1, 2001 through March

44

AVIVA PETROLEUM INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

31, 2002, and $21,000 per month thereafter if the contract continued in effect. The Service Agreement provided for a term of 22 months and allowed termination with a 30-day written notice by either party. The Service Agreement was cancelled by the lender effective March 31, 2002.

The Company recognized a gain of $3,452,000 on the transfer of the partnership interests to the lender, representing the excess of the fair value over the book value of the interests transferred. The Company recognized an extraordinary gain of $4,888,000 on the extinguishment of the debt due to the lender, net of income taxes of $2,517,000.

In connection with the above-referenced transaction, 1,000,000 shares of the Company’s common stock which were held by the lender prior to the transaction, were transferred to members of management and the Board of Directors of the Company, effective June 8, 2000. As of such date, the aggregate market value of the common stock transferred to members of management and the Board of Directors was approximately $25,000 based on the last sale price on the OTC Bulletin Board of a depositary share representing five shares of the Company’s common stock. Additionally, 200,000 shares of the Company’s common stock which were held by the lender prior to the transaction were transferred to a consultant of the Company effective on the same date.

(4) Other Assets

Other assets consist principally of abandonment funds for U.S. offshore properties of $100,000 and $989,000 as of December 31, 2002 and 2001, respectively.

(5) Short-Term Debt

On December 12, 2002, the Company borrowed $50,000 in cash from Ronald Suttill, President and Chief Executive Officer of Aviva. Pursuant to such borrowing, the Company issued to Mr. Suttill a promissory note in the amount of $50,000, bearing interest at 10% per year, due May 31, 2003. Additionally, in order to induce Mr. Suttill to provide the Company with such loan, warrants to purchase 1 million shares of Aviva common stock were issued to Mr. Suttill effective December 12, 2002. Such warrants have an exercise price of $0.07 per share and expire on December 12, 2004. On the date of issuance, the warrants had a value of approximately $10,000 using the Black-Scholes option-pricing model.

(6) Interest and Other Income (Expense)

A summary of interest and other income (expense) follows:

	2002		2001		2000
	(thousands)
Interest income	$	26	$	56	$	97
Gain on settlement of disputed payable		—		99		—
Foreign currency exchange gain (loss)		29		11		44
Gain (loss) on sale of assets, net		—		4		(4	)
Other, net		120		65		70
	$	175	$	235	$	207

(7) Stockholders’ Equity

Quasi-Reorganization

Effective December 31, 1992, the Board of Directors of the Company approved a quasi-reorganization which resulted in a reclassification of the accumulated deficit of $70,057,000 at that date to paid-in capital. No adjustments were made to the Company’s assets and liabilities since the historical carrying values approximated or did not exceed the estimated fair values.

Stock Option Plans

At December 31, 2002, the Company has two stock option plans, which are described below. The Company applies APB Opinion No. 25 and related Interpretations in accounting for its plans. Accordingly, no compensation cost has been recognized for its stock option plans.

45

AVIVA PETROLEUM INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

The Aviva Petroleum Inc. 1995 Stock Option Plan, as amended (the “Current Plan”) is administered by a committee (the “Committee”) composed of outside directors of the Company. Except as indicated below and except for non-discretionary grants to non-employee directors, the Committee has authority to determine all terms and provisions under which options are granted pursuant to the Current Plan. An aggregate of up to 1,000,000 shares of the Company’s common stock may be issued upon exercise of stock options or in connection with restricted stock awards that may be granted under the Current Plan. The Current Plan also provides for the grant, on July 1, each year, to each non-employee director who has served in such capacity for at least the entire preceding calendar year of an option to purchase 5,000 shares of the Company’s common stock (the “Annual Option Awards”), exercisable as to 2,500 shares on the first anniversary of the date of grant and as to the remaining shares on the second anniversary thereof.

The aggregate fair market value (determined at the time of grant) of shares issuable pursuant to incentive stock options which first become exercisable in any calendar year by a participant in the Current Plan may not exceed $100,000. The maximum number of shares of common stock which may be subject to an option or restricted stock grant awarded to a participant in a calendar year cannot exceed 100,000. Incentive stock options granted under the Current Plan may not be granted at a price less than 100% of the fair market value of the common stock on the date of grant (or 110% of the fair market value in the case of incentive stock options granted to participants in the Current Plan holding 10% or more of the voting stock of the Company). Non-qualified stock options may not be granted at a price less than 50% of the fair market value of the common stock on the date of grant.

As a result of the adoption of the Current Plan, during 1995 the Company’s former Incentive and Non-Statutory Stock Option Plan was terminated as to the grant of new options, but options then outstanding for 190,000 shares of the Company’s common stock remain in effect as of December 31, 2002.

The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions:

	2002		2001		2000
Expected life (years)	10.0		10.0		10.0
Risk-free interest rate	4.92	%	5.42	%	6.03	%
Volatility	100.4	%	103.0	%	124.0	%
Dividend yield	0.0	%	0.0	%	0.0	%

A summary of the status of the Company’s two fixed stock option plans as of December 31, 2002, 2001 and 2000, and changes during the years ended on those dates is presented below:

	2002					2001					2000
Fixed Options	Shares (000)			Weighted- Average Exercise Price		Shares (000)			Weighted- Average Exercise Price		Shares (000)			Weighted- Average Exercise Price
Outstanding at beginning of year		889		$	.45		1,024		$	.51		1,072		$	.51
Granted		305			.08		5			.07		5			.08
Forfeited		(60	)		2.41		(140	)		.81		(53	)		.17
Outstanding at end of year		1,134			.25		889			.45		1,024			.51
Options exercisable at year-end		927					882					1,007
Weighted-average fair value of options granted during the year	$	.07				$	.06				$	.07

46

AVIVA PETROLEUM INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

The following table summarizes information about fixed stock options outstanding at December 31, 2002:

	Options Outstanding			Options Exercisable
Range of Exercise Prices	Number Outstanding at 12/31/02	Weighted-Avg. Remaining Contractual Life	Weighted-Avg. Exercise Price	Number Exercisable at 12/31/02	Weighted-Avg. Exercise Price
$  .01 to .06	604,000	5.83 years	$  .06	599,000	$  .06
.07 to .08	310,000	9.02	.08	107,500	.08
.52 to 1.08	220,000	0.54	1.00	220,000	1.00
$.01 to 1.08	1,134,000	5.67	.25	926,500	.29

(8) Income Taxes

Income tax expense includes current Colombian income taxes of $39,000 in 2002, $74,000 in 2001 and $241,000 in 2000. Income tax expense also includes state income taxes of $10,000 in 2001 and $12,000 in 2000.

Income tax expense for the years ended December 31, 2002, 2001 and 2000, differed from the amount computed by applying the statutory U.S. federal income tax rate (34%) to income before income taxes as a result of the following (in thousands):

	2002			2001			2000
Computed expected tax expense (benefit)	$	(342	)	$	55		$	1,773
Decrease in valuation allowance		(676	)		(5,362	)		(17,856	)
Expiration of net operating loss carryforwards		1,085			3,555			15,467
Foreign income taxes and other		(28	)		1,836			869
	$	39		$	84		$	253

The Company has deferred tax assets of $17,342,000 and $18,259,000 at December 31, 2002 and 2001, respectively, consisting principally of net operating loss carryforwards. The valuation allowance for deferred tax assets at January 1, 2000 was $44,332,000. The net change in the valuation allowance was a $917,000 decrease in 2002, a $5,362,000 decrease in 2001 and a $20,711,000 decrease in 2000. Subsequently recognized tax benefits relating to the valuation allowance of $9,327,000 for deferred tax assets at January 1, 1993 will be credited to additional paid in capital. Such benefits were $2,855,000 during the year ended December 31, 2000.

At December 31, 2002, the Company and its subsidiaries have aggregate net operating loss carryforwards for U.S. federal income tax purposes of approximately $46,000,000, expiring from 2003 through 2022, which are available to offset future federal taxable income. The utilization of a portion of these net operating losses is subject to an annual limitation of approximately $2,400,000 and a portion may only be utilized by certain subsidiaries of the Company.

(9) Financial Instruments and Credit Risk Concentrations

Financial instruments which are subject to risks due to concentrations of credit consist principally of cash and cash equivalents and receivables. Cash and cash equivalents are placed with high credit quality financial institutions to minimize risk. Receivables are typically unsecured. Historically, the Company has not experienced any material collection difficulties from its customers.

The carrying values of cash equivalents, accounts receivable and accounts payable approximate fair value due to the current maturities of these financial instruments.

47

AVIVA PETROLEUM INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

Ecopetrol has an option to purchase all of the Company’s production in Colombia. For the years ended December 31, 2002, 2001 and 2000, Ecopetrol exercised that option and sales to Ecopetrol accounted for $1,164,000 (62%), $1,253,000 (59%), and $4,267,000 (74%) respectively, of the Company’s aggregate oil and gas sales.

For the years ended December 31, 2002, 2001 and 2000, sales to one U.S. purchaser accounted for $643,000 (34%), $782,000 (37%) and $968,000 (17%), respectively, of oil and gas sales.

(10) Commitments and Contingencies

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 to the Company. 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 2002 financial statements include an abandonment provision of $410,000 to fully accrue for this contingency, and an impairment provision of $182,000 related to the contingency.

At December 31, 2002, the Company had $908,000 recorded as an abandonment liability to fully provide for the estimated costs to abandon the property.

The Company is also engaged in ongoing operations 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.

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 operations. Any substantial increase in the amount of the above referenced expenditures could adversely affect the Company’s ability to fund these activities. Risks that could adversely affect funding of such activities include, among others, delays in obtaining any required environmental permits, cost overruns, failure to produce the reserves as projected or a decline in the sales price of oil. Depending on the results of future exploration and development activities, substantial expenditures that have not been included in the Company’s projections may be required.

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. 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.

48

AVIVA PETROLEUM INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

Failure by Argosy to meet the obligations under the Guayuyaco contract will result in the loss of the proposed contract terms. The existing Santana production 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.

During 1998, leftist Colombian guerrillas inflicted significant damage on Argosy’s oil processing and storage facilities. Since that time Argosy has been subject to lesser 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 such operations will not be the target of additional 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.

Under the terms of the contracts with Ecopetrol, a minimum of 25% of all revenues from oil sold to Ecopetrol is paid in Colombian pesos which may only be utilized in Colombia. To date, the Company has experienced no difficulty in repatriating the remaining 75% of such payments, which are payable in U.S. dollars.

Activities of the Company with respect to the exploration, development and production of oil and natural gas are subject to stringent foreign, federal, state and local environmental laws and regulations, including but not limited to the Oil Pollution Act of 1990, the Outer Continental Shelf Lands Act, the Federal Water Pollution Control Act, the Resource Conservation and Recovery Act and the Comprehensive Environmental Response, Compensation, and Liability Act. Such laws and regulations have increased the cost of planning, designing, drilling, operating and abandoning wells. In most instances, the statutory and regulatory requirements relate to air and water pollution control procedures and the handling and disposal of drilling and production wastes. Although the Company believes that compliance with environmental laws and regulations will not have a material adverse effect on the Company’s future operations or earnings, risks of substantial costs and liabilities are inherent in oil and gas operations and there can be no assurance that significant costs and liabilities, including administrative, civil or criminal penalties for violations of environmental laws and regulations, will not be incurred. Moreover, it is possible that other developments, such as stricter environmental laws and regulations or claims for damages to property or persons resulting from the Company’s operations, could result in substantial costs and liabilities. The Company’s policy is to accrue environmental and restoration related costs once it is probable that a liability has been incurred and the amount can be reasonably estimated.

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.

49

AVIVA PETROLEUM INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

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.

The Company has one lease for office space in Dallas, Texas, which expires in January 2007. Rent expense relating to the lease was $84,000, $90,000, and $88,000 for 2002, 2001 and 2000, respectively. Future minimum payments under the lease are approximately $94,000 for each year through 2006 and $8,000 for 2007.

(11) Subsidiary’s Reorganization under Chapter 11

On July 21, 2000, AAI, a wholly-owned subsidiary of the Company, filed a voluntary petition for reorganization under Chapter 11 of the U.S. Bankruptcy code. AAI is a Delaware corporation which holds the Company’s interests in oil and gas properties located offshore Louisiana. 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. In connection with the reorganization, the Company recognized an extraordinary gain of $655,000 on the extinguishment of certain AAI debts, net of income taxes of $338,000.

(12) Geographic Area Information

The Company is engaged in the business of exploring for, developing and producing oil and gas in the United States and Colombia. Information about the Company’s operations in different geographic areas as of and for the years ended December 31, 2002, 2001 and 2000 follows:

	United States			Colombia			Total
	(Thousands)
2002
Revenue:
Oil and gas sales	$	707		$	1,164		$	1,871
Service fees		97			—			97
		804			1,164			1,968
Expense:
Production		770			423			1,193
Depreciation, depletion and amortization		121			88			209
Provision for abandonment and impairment (see note 10)		592			—			592
General and administrative		951			135			1,086
Recovery of losses on accounts receivable		(4	)		—			(4	)
		2,430			646			3,076
Interest and other income (expense), net		30			145			175
Interest expense		(33	)		—			(33	)
Earnings (loss) before income taxes		(1,629	)		663			(966	)
Income taxes		—			(39	)		(39	)
Net earnings (loss)	$	(1,629	)	$	624		$	(1,005	)
Total assets	$	1,206		$	1,872		$	3,078

50

AVIVA PETROLEUM INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

	United States			Colombia			Total
	(Thousands)
2001
Revenue:
Oil and gas sales	$	883		$	1,253		$	2,136
Service fees		473			—			473
		1,356			1,253			2,609
Expense:
Production		785			617			1,402
Depreciation, depletion and amortization		219			101			320
General and administrative		904			102			1,006
Recovery of losses on accounts receivable		(48	)		—			(48	)
		1,860			820			2,680
Interest and other income (expense), net		56			179			235
Interest expense		(3	)		—			(3	)
Earnings (loss) before income taxes and extraordinary item		(451	)		612			161
Income taxes		(10	)		(74	)		(84	)
Net earnings (loss)	$	(461	)	$	538		$	77
Total assets	$	1,602		$	1,532		$	3,134
2000
Revenue:
Oil and gas sales	$	1,528		$	4,268		$	5,796
Service fees		387			—			387
		1,915			4,268			6,183
Expense:
Production		1,099			1,308			2,407
Depreciation, depletion and amortization		131			384			515
General and administrative		1,077			80			1,157
Recovery of losses on accounts receivable		(256	)		—			(256	)
		2,051			1,772			3,823
Gain on transfer of partnership interests		—			3,452			3,452
Interest and other income (expense), net		39			168			207
Interest expense		(183	)		(622	)		(805	)
Earnings (loss) before income taxes and extraordinary item		(280	)		5,494			5,214
Income taxes		(12	)		(241	)		(253	)
Earnings (loss) before extraordinary item		(292	)		5,253			4,961
Extraordinary item – debt extinguishment		655			4,888			5,543
Net earnings	$	363		$	10,141		$	10,504
Total assets	$	1,662		$	1,649		$	3,311

51

AVIVA PETROLEUM INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

(13)    Quarterly Financial Data (Unaudited)

Quarterly operating results for 2002 and 2001 are summarized as follows (in thousands, except per share data):

	Quarter Ended
	March 31			June 30			September 30			December 31 (1)
2002
Revenues	$	460		$	534		$	507		$	467
Operating earnings		(136	)		(101	)		(129	)		(742	)
Net earnings (loss)		(100	)		(88	)		(84	)		(733	)
Basic and diluted earnings (loss) per common share	$	(0.00	)	$	(0.00	)	$	(0.00	)	$	(0.02	)
2001
Revenues	$	766		$	682		$	654		$	507
Operating earnings		77			(26	)		35			(157	)
Net earnings (loss)		229			(44	)		40			(148	)
Basic and diluted earnings (loss) per common share	$	0.00		$	(0.00	)	$	0.00		$	(0.00	)

(1) In the fourth quarter, the Company recorded an abandonment provision of $410,000 and an impairment provision of $182,000 related to the Breton Sound field as more fully discussed in Note 10.

52

AVIVA PETROLEUM INC. AND SUBSIDIARIES

Supplementary Information Related to Oil and Gas Producing Activities

(Unaudited)

The following information relating to the Company’s oil and gas activities is presented in accordance with Statement of Financial Accounting Standards No. 69. The Financial Accounting Standards Board has determined the information is necessary to supplement, although not required to be a part of, the basic financial statements.

Capitalized costs and accumulated depreciation, depletion and amortization relating to oil and gas producing activities were as follows:

	United States			Colombia		Total
	(Thousands)
December 31, 2002
Unevaluated oil and gas properties	$	—		$	246	$	246
Proved oil and gas properties		4,150			15,974		20,124
Total capitalized costs		4,150			16,220		20,370
Less accumulated depreciation, depletion and amortization		4,150			15,423		19,573
Capitalized costs, net, excluding U.S. abandonment liability of $908	$	—		$	797	$	797
December 31, 2001
Unevaluated oil and gas properties	$	184		$	119	$	303
Proved oil and gas properties		4,008			15,933		19,941
Total capitalized costs		4,192			16,052		20,244
Less accumulated depreciation, depletion and amortization		4,368			15,335		19,703
Capitalized costs, net	$	(176	)	$	717	$	541

53

AVIVA PETROLEUM INC. AND SUBSIDIARIES

Supplementary Information Related to Oil and Gas Producing Activities

(Unaudited) (Continued)

Costs incurred in oil and gas property acquisition, exploration and development activities were as follows:

	United States		Colombia		Total
	(Thousands)
2002
Exploration	$	—	$	124	$	124
Development		52		44		96
Acquisition of producing properties		6		—		6
Total costs incurred	$	58	$	168	$	226
2001
Exploration	$	—	$	—	$	—
Development		72		19		91
Total costs incurred	$	72	$	19	$	91
2000
Exploration	$	10	$	4	$	14
Development		238		110		348
Total costs incurred	$	248	$	114	$	362

54

AVIVA PETROLEUM INC. AND SUBSIDIARIES

Supplementary Information Related to Oil and Gas Producing Activities

(Unaudited) (Continued)

The following schedule presents the Company’s estimate of its proved oil and gas reserves. The proved oil and gas reserves in Colombia and the United States were determined by independent petroleum engineers, Huddleston & Co., Inc. and Netherland, Sewell & Associates, Inc., respectively. The figures presented are estimates of reserves which may be expected to be recovered commercially at current prices and costs. Estimates of proved developed reserves include only those reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. Estimates of proved undeveloped reserves include only those reserves which are expected to be recovered on undrilled acreage from new wells which are reasonably certain of production when drilled or from presently existing wells which could require relatively major expenditures to effect recompletion.

	Changes in the Estimated Quantities of Reserves
	United States(1)		Colombia		Total
Year ended December 31, 2002
Oil (Thousands of barrels)
Proved reserves:
Beginning of period	80		638		718
Revisions of previous estimates	46		1		47
Purchase of reserves	13		—		13
Production	(27	)	(59	)	(86	)
End of period	112		580		692
Proved developed reserves, end of period	112		580		692
Gas (Millions of cubic feet)
Proved reserves:
Beginning of period	25		—		25
Revisions of previous estimates	60		—		60
Purchase of reserves	9		—		9
Production	(20	)	—		(20	)
End of period	74		—		74
Proved developed reserves, end of period	74		—		74

(1) The reserve estimates for the United States were prepared as of December 31, 2002, prior to the operational difficulties described in note 10 to the consolidated financial statements. If the operational difficulties are not satisfactorily resolved, then the reserve quantities for the United States would be substantially eliminated.

55

AVIVA PETROLEUM INC. AND SUBSIDIARIES

Supplementary Information Related to Oil and Gas Producing Activities

(Unaudited) (Continued)

	Changes in the Estimated Quantities of Reserves
	United States		Colombia		Total
Year ended December 31, 2001
Oil (Thousands of barrels)
Proved reserves:
Beginning of period	174		696		870
Revisions of previous estimates	(66	)	3		(63	)
Purchase of reserves	5		—		5
Production	(33	)	(61	)	(94	)
End of period	80		638		718
Proved developed reserves, end of period	80		638		718
Gas (Millions of cubic feet)
Proved reserves:
Beginning of period	114		—		114
Revisions of previous estimates	(67	)	—		(67	)
Purchase of reserves	2		—		2
Production	(24	)	—		(24	)
End of period	25		—		25
Proved developed reserves, end of period	25		—		25

56

AVIVA PETROLEUM INC. AND SUBSIDIARIES

Supplementary Information Related to Oil and Gas Producing Activities

(Unaudited) (Continued)

	Changes in the Estimated Quantities of Reserves
	United States		Colombia		Total
Year ended December 31, 2000
Oil (Thousands of barrels)
Proved reserves:
Beginning of period	144		2,208		2,352
Revisions of previous estimates	79		259		338
Sales of reserves	—		(1,614	)	(1,614	)
Production	(49	)	(157	)	(206	)
End of period	174		696		870
Proved developed reserves, end of period	174		696		870
Gas (Millions of cubic feet)
Proved reserves:
Beginning of period	101		—		101
Revisions of previous estimates	38		—		38
Production	(25	)	—		(25	)
End of period	114		—		114
Proved developed reserves, end of period	114		—		114

57

AVIVA PETROLEUM INC. AND SUBSIDIARIES

Supplementary Information Related to Oil and Gas Producing Activities

(Unaudited) (Continued)

The following schedule is a standardized measure of the discounted net future cash flows applicable to proved oil and gas reserves. The future cash flows are based on estimated oil and gas reserves utilizing prices and costs in effect as of the applicable year end, discounted at ten percent per year and assuming continuation of existing economic conditions. The standardized measure of discounted future net cash flows, in the Company’s opinion, should be examined with caution. The schedule is based on estimates of the Company’s proved oil and gas reserves prepared by independent petroleum engineers. Reserve estimates are, however, inherently imprecise and estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, the estimates are expected to change as future information becomes available. Therefore, the standardized measure of discounted future net cash flows does not necessarily reflect the fair value of the Company’s proved oil and gas properties.

	United States (1)			Colombia			Total
	(Thousands)
At December 31, 2002:
Future gross revenues	$	3,661		$	14,895		$	18,556
Future production costs		(3,205	)		(6,972	)		(10,177	)
Future development costs, including abandonment of U.S. offshore platforms		(908	)		(347	)		(1,255	)
Future net cash flows before income taxes		(452	)		7,576			7,124
Future income taxes		—			(313	)		(313	)
Future net cash flows after income taxes		(452	)		7,263			6,811
Discount at 10% per annum		285			(2,721	)		(2,436	)
Standardized measure of discounted future net cash flows	$	(167	)	$	4,542		$	4,375
At December 31, 2001:
Future gross revenues	$	1,436		$	10,519		$	11,955
Future production costs		(1,288	)		(6,335	)		(7,623	)
Future development costs, including abandonment of U.S. offshore platforms		(799	)		(354	)		(1,153	)
Future net cash flows before income taxes		(651	)		3,830			3,179
Future income taxes		—			—			—
Future net cash flows after income taxes		(651	)		3,830			3,179
Discount at 10% per annum		236			(1,130	)		(894	)
Standardized measure of discounted future net cash flows	$	(415	)	$	2,700		$	2,285

(1) The standardized measure of the discounted net future cash flows applicable to proved oil and gas reserves for the United States was prepared as of December 31, 2002, prior to the operational difficulties described in note 10 to the consolidated financial statements. If the operational difficulties are not satisfactorily resolved, then the standardized measure of the discounted net future cash flows applicable to proved oil and gas reserves would be approximately $(1.0) million.

58

AVIVA PETROLEUM INC. AND SUBSIDIARIES

Supplementary Information Related to Oil and Gas Producing Activities

(Unaudited) (Continued)

	United States			Colombia			Total
	(Thousands)
At December 31, 2000:
Future gross revenues	$	5,520		$	12,501		$	18,021
Future production costs		(3,887	)		(5,994	)		(9,881	)
Future development costs, including abandonment of U.S. offshore platforms		(745	)		(390	)		(1,135	)
Future net cash flows before income taxes		888			6,117			7,005
Future income taxes		—			—			—
Future net cash flows after income taxes		888			6,117			7,005
Discount at 10% per annum		120			(1,942	)		(1,822	)
Standardized measure of discounted future net cash flows	$	1,008		$	4,175		$	5,183

The following schedule summarizes the changes in the standardized measure of discounted future net cash flows.

	2002			2001			2000
	(Thousands)
Sales of oil and gas, net of production costs	$	(678	)	$	(735	)	$	(3,389	)
Sales of reserves in place		—			—			(20,094	)
Development costs incurred that reduced future development costs		8			35			36
Accretion of discount		229			518			2,826
Discoveries and extensions		—			—			—
Purchase of reserves in place		(23	)		(32	)		—
Revisions of previous estimates:
Changes in price		3,184			(2,561	)		(1,921	)
Changes in quantities		142			(146	)		1,422
Changes in future development costs		69			(78	)		(236	)
Changes in timing and other changes		(645	)		101			(1,721	)
Changes in estimated income taxes		(196	)		—			—
Net increase (decrease)		2,090			(2,898	)		(23,077	)
Balances at beginning of year		2,285			5,183			28,260
Balances at end of year	$	4,375		$	2,285		$	5,183

59

INDEX TO EXHIBITS

Number	Description of Exhibit
*2.1	Agreement and Plan of Merger dated as of June 24, 1998, by and among Aviva Petroleum Inc., Aviva Merger Inc. and Garnet Resources Corporation (filed as exhibit 2.1 to the Registration Statement on Form S-4, File No. 333-58061, and incorporated herein by reference).
*2.2	Debenture Purchase Agreement dated as of June 24, 1998, between Aviva Petroleum Inc. and the Holders of the Debentures named therein (filed as exhibit 2.2 to the Registration Statement on Form S-4, file No. 333-58061, and incorporated herein by reference).
*3.1	Restated Articles of Incorporation of the Company dated July 25, 1995 (filed as exhibit 3.1 to the Company’s annual report on Form 10-K for the year ended December 31, 1995, File No. 0-22258, and incorporated herein by reference).
*3.2	Amended and Restated Bylaws of the Company, as amended as of January 23, 1995 (filed as exhibit 3.2 to the Company’s annual report on Form 10-K for the year ended December 31, 1994, File No. 0-22258, and incorporated herein by reference).
*10.1	Risk Sharing Contract between Empresa Colombiana de Petroleos (“Ecopetrol”), Argosy Energy International (“Argosy”) and Neo Energy, Inc. (“Neo”) (filed as exhibit 10.1 to the Company’s Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference).
*10.2	Contract for Exploration and Exploitation of Sector Number 1 of the Aporte Putumayo Area (“Putumayo”) between Ecopetrol and Cayman Corporation of Colombia dated July 24, 1972 (filed as exhibit 10.2 to the Company’s Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference).
*10.3	Operating Agreement for Putumayo between Argosy and Neo dated September 16, 1987 and amended on January 4, 1989 and February 23, 1990 (filed as exhibit 10.3 to the Company’s Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference).
*10.4	Operating Agreement for the Santana Area (“Santana”) between Argosy and Neo dated September 16, 1987 and amended on January 4, 1989, February 23, 1990 and September 28, 1992 (filed as exhibit 10.4 to the Company’s Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference).
*10.5	Santana Block A Relinquishment dated March 6, 1990 between Ecopetrol, Argosy and Neo (filed as exhibit 10.8 to the Company’s Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference).
*10.6	Employee Stock Option Plan of the Company (filed as exhibit 10.13 to the Company’s Registration Statement on Form10, File No. 0-22258, and incorporated herein by reference).
*10.7	Santana Block B 50% relinquishment dated September 13, 1993 between Ecopetrol, Argosy and Neo (filed as exhibit 10.26 to the Company’s annual report on Form 10-K for the year ended December 31, 1993, File No. 0-22258, and incorporated herein by reference).
*10.8	Aviva Petroleum Inc. 401(k) Retirement Plan effective March 1, 1992 (filed as exhibit 10.29 to the Company’s annual report on Form 10-K for the year ended December 31, 1993, File No. 0-22258, and incorporated herein by reference).
*10.9	Relinquishment of Putumayo dated December 1, 1993 (filed as exhibit 10.30 to the Company’s annual report on Form 10-K for the year ended December 31, 1993, File No. 0-22258, and incorporated herein by reference).
*10.10	Deposit Agreement dated September 15, 1994 between the Company and Chemical Shareholder Services Group, Inc. (filed as exhibit 10.29 to the Company’s Registration Statement on Form S-1, File No. 33-82072, and incorporated herein by reference).
*10.11	Letter from Ecopetrol dated December 28, 1994, accepting relinquishment of Putumayo (filed as exhibit 10.38 to the Company’s annual report on Form 10-K for the year ended December 31, 1994, File No. 0-22258, and incorporated herein by reference).
*10.12	Amendment to the Incentive and Nonstatutory Stock Option Plan of the Company (filed as exhibit 10.4 to the Company’s quarterly report on Form 10-Q for the quarter ended September 30, 1995, File No. 0-22258, and incorporated herein by reference).
*10.13	Santana Block B 25% relinquishment dated October 2, 1995 (filed as exhibit 10.51 to the Company’s annual report on Form 10-K for the year ended December 31, 1995, File No. 0-22258, and incorporated herein by reference).

Number	Description of Exhibit
*10.14	Aviva Petroleum Inc. 1995 Stock Option Plan, as amended (filed as Appendix A to the Company’s definitive Proxy Statement for the Annual Meeting of Shareholders dated June 10, 1997, and incorporated herein by reference).
*10.15	Restated Credit Agreement dated as of October 28, 1998, between Neo Energy, Inc., Aviva Petroleum Inc. and ING (U.S.) Capital Corporation (filed as exhibit 99.1 to the Company’s Form 8-K dated October 28, 1998, File No. 0-22258, and incorporated herein by reference).
*10.16	Joint Finance and Intercreditor Agreement dated as of October 28, 1998, between Neo Energy, Inc., Aviva Petroleum Inc., ING (U.S.) Capital Corporation, Aviva America, Inc., Aviva Operating Company, Aviva Delaware Inc., Garnet Resources Corporation, Argosy Energy Incorporated, Argosy Energy International, Garnet PNG Corporation, the Overseas Private Investment Corporation, Chase Bank of Texas, N.A. and ING (U.S.) Capital Corporation as collateral agent for the creditors (filed as exhibit 99.2 to the Company’s Form 8-K dated October 28, 1998, File No. 0-22258, and incorporated herein by reference).
*10.17	Amended and Restated Aviva Petroleum Inc. Severance Benefit Plan dated December 31, 1999 (filed as exhibit 10.18 to the Company’s annual report on Form 10-K for the year ended December 31, 1999, File No. 0-22258, and incorporated herein by reference).
*10.18	Santana Crude Sale and Purchase Agreement dated January 3, 2000 (filed as exhibit 10.19 to the Company’s annual report on Form 10-K for the year ended December 31, 1999, File No. 0-22258, and incorporated herein by reference).
*10.19	Employment Agreement between the Company and Ronald Suttill dated February 1, 2000 (filed as exhibit 10.20 to the Company’s annual report on Form 10-K for the year ended December 31, 1999, File No. 0-22258, and incorporated herein by reference).
*10.20	Employment Agreement between the Company and James L. Busby dated February 1, 2000 (filed as exhibit 10.21 to the Company’s annual report on Form 10-K for the year ended December 31, 1999, File No. 0-22258, and incorporated herein by reference).
*10.21	Service Agreement between Argosy Energy International and Aviva Overseas, Inc. dated as of June 1, 2000 (filed as exhibit 10.1 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2000, File No. 0-22258, and incorporated herein by reference).
*10.22	Letter Agreement dated June 8, 2000 between Crosby Capital, LLC and Aviva America, Inc. (filed as exhibit 10.2 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2000, File No. 0-22258, and incorporated herein by reference).
*10.23	Guaranty dated May 31, 2000 made by Aviva Overseas, Inc. in favor of Crosby Capital, LLC (filed as exhibit 10.3 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2000, File No. 0-22258, and incorporated herein by reference).
*10.24	Assignment and Assumption Agreement dated June 1, 2000, between Crosby Capital, LLC and Neo Energy, Inc. (filed as exhibit 10.4 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2000, File No. 0-22258, and incorporated herein by reference).
*10.25	Assignment and Assumption Agreement dated June 1, 2000 between Crosby Acquisition LLC and Argosy Energy, Inc. (filed as exhibit 10.5 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2000, File No. 0-22258, and incorporated herein by reference).
*10.26	Assignment and Assumption Agreement dated June 1, 2000 between Crosby Capital, LLC and Garnet Resources Corp. (filed as exhibit 10.6 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2000, File No. 0-22258, and incorporated herein by reference).
*10.27	Assignment and Assumption Agreement dated June 1, 2000 between Crosby Capital, LLC and Aviva Overseas, Inc. (filed as exhibit 10.7 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2000, File No. 0-22258, and incorporated herein by reference).
*10.28	Assignment and Assumption Agreement dated June 1, 2000 between Argosy Energy, Incorporated and Crosby Acquisition, LLC (filed as exhibit 10.8 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2000, File No. 0-22258, and incorporated herein by reference).
*10.29	Assignment and Assumption Agreement dated June 1, 2000 between Crosby Capital, LLC and Aviva Overseas, Inc. (filed as exhibit 10.9 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2000, File No. 0-22258, and incorporated herein by reference).
*10.30	Pledge Agreement dated May 31, 2000 executed by Aviva Overseas, Inc. (Debtor) in favor of Crosby Capital, LLC (Secured Party) (filed as exhibit 10.10 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2000, File No. 0-22258, and incorporated herein by reference).

Number	Description of Exhibit
*10.31	Third Amendment to Second Amended and Restated Limited Partnership Agreement of Argosy Energy International dated May 31, 2000 (filed as exhibit 10.11 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2000, File No. 0-22258, and incorporated herein by reference).
*10.32	Fourth Amendment to Second Amended and Restated Limited Partnership Agreement of Argosy Energy International dated June 1, 2000 (filed as exhibit 10.12 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2000, File No. 0-22258, and incorporated herein by reference).
*10.33	Assignment of Stock Warrant Rights dated May 31, 2000 executed by Crosby Capital, LLC in favor of Aviva Petroleum Inc. (filed as exhibit 10.13 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2000, File No. 0-22258, and incorporated herein by reference).
*10.34	Assignment of Neo Debt and Collateral, dated December 21, 2000 from Crosby Capital, LLC to Aviva Operating Company (filed as exhibit 10.34 to the Company’s annual report on Form 10-K for the year ended December 31, 2000, File No. 0-22258, and incorporated herein by reference).
*10.35	Conveyance of Net Profits Interest, dated December 21, 2000 from Aviva America, Inc. to Crosby Capital, LLC (filed as exhibit 10.35 to the Company’s annual report on Form 10-K for the year ended December 31, 2000, File No. 0-22258, and incorporated herein by reference).
*10.36	Santana Crude Sale and Purchase Agreement dated January 3, 2001 (filed as exhibit 10.1 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2001, File No. 0-22258, and incorporated herein by reference).
*10.37	Santana Crude Sale and Purchase Agreement dated January 30, 2002 (filed as exhibit 10.37 to the Company’s annual report on Form 10-K for the year ended December 31, 2001, File No. 0-22258, and incorporated herein by reference).
*10.38	Rio Magdalena Association Contract dated December 10, 2001 between Ecopetrol and Argosy (filed as exhibit 10.38 to the Company’s annual report on Form 10-K for the year ended December 31, 2001, File No. 0-22258, and incorporated herein by reference).
**10.39	Promissory note dated December 12, 2002, issued to Ronald Suttill.
**10.40	Stock purchase warrant dated December 12, 2002, issued to Ronald Suttill.
**10.41	Guayuyaco Association Contract dated August 2, 2002 between Ecopetrol and Argosy.
*21.1	List of subsidiaries of Aviva Petroleum Inc. (filed as exhibit 21.1 to the Company’s annual report on Form 10-K for the year ended December 31, 2000, File No. 0-22258, and incorporated herein by reference).
**99.1	Certification by Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act (18 U.S.C. Section 1350)
**99.2	Certification by Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act (18 U.S.C. Section 1350)

* Previously Filed

** Filed Herewith