10-K

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. Yes x    No ¨.

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x.

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

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

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

DOCUMENTS INCORPORATED BY REFERENCE

None.

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

5

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.

7

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

EX-10.39

EXHIBIT 10.39

$50,000.00 December 12, 2002

PROMISSORY NOTE

FOR VALUE RECEIVED, the undersigned, Aviva Petroleum Inc., a Texas corporation, (herein called “Borrower”), hereby promises to pay to the order of Ronald Suttill, a resident of Dallas, Texas, (herein called “Lender”), the principal sum of fifty thousand dollars ($50,000), together with interest as provided below. All payments on this Note shall be due and payable in lawful currency of the United States of America at the offices of Lender in Dallas County, Texas, or at such other place within Dallas County as from time to time may be designated by the holder of this Note.

The unpaid principal balance outstanding hereunder shall bear interest at a rate per annum which shall be the lesser of (a) 10% or (b) the maximum rate of interest from time to time permitted under state or federal laws applicable to the indebtedness evidenced hereby. The lesser of (a) and (b) above shall be referenced to herein as the “Maximum Lawful Rate.”

Accrued and unpaid interest shall be due and payable on March 31, 2003. The unpaid principal and remaining accrued and unpaid interest shall be due and payable on May 31, 2003. Privilege is reserved to the Borrower to repay this Note in whole or in part, at any time, without premium or penalty. Any prepayment shall be applied to the payment of principal.

If this Note is placed in the hands of an attorney for collection, or if it is collected through bankruptcy or other judicial proceedings, the Borrower further agrees to pay all expenses of collection, including reasonable attorney’s fees.

Borrower and all sureties, endorsers and guarantors of this Note (i) waive grace, demand, presentment for payment, notice of nonpayment, protest, notice of protest, notice of intent to accelerate and all other notice, bringing of suit and diligence in collecting this Note or enforcing any of the security herefor, (ii) agree to any substitution, exchange or release of any such security or the release of any party primarily or secondarily liable hereon, and (iii) consent to any one or more extensions or postponements of time of payment of this Note on any terms or any other indulgences with respect hereto, without notice thereof to any of them.

No delay or omission on the part of Lender in exercising any right hereunder shall operate as a waiver of such right or of any other right under this Note. A waiver on any one occasion shall not be construed as a bar to or waiver of any right or remedy on any future occasion.

In no event shall the aggregate of the interest on this Note, plus any other amounts paid in connection with this Note which would under applicable law be deemed “interest,” ever

exceed the maximum amount of interest which under applicable law could be lawfully charged on this Note. Lender and Borrower specifically intend and agree to limit contractually the interest payable on this Note to not more than an amount determined at the maximum rate permitted by applicable law. If at any time the rate of interest charged under this Note exceeds the maximum rate permitted by applicable law, the rate of interest to accrue on this Note shall be limited to the maximum rate permitted by applicable law. None of the terms of this Note or any other instruments pertaining to or securing this Note shall ever be construed to create a contract to pay interest at a rate in excess of the maximum rate permitted by applicable law, and neither Borrower nor any other party liable herefor shall ever be liable for interest in excess of that determined at the maximum rate permitted by applicable law, and the provisions of this paragraph shall control over all provisions of this Note. If any amount of interest taken or received by Lender shall be in excess of the maximum amount of interest which, under applicable law, could lawfully have been collected on this Note, then the excess shall be deemed to have been the result of a mathematical error by the parties hereto and shall be refunded promptly to Borrower. All amounts paid or agreed to be paid in connection with the indebtedness evidenced by this Note which would under applicable law be deemed “interest” shall, to the extent permitted by applicable law, be amortized, prorated, allocated and spread throughout the full term of this Note.

Aviva Petroleum Inc.
By:	/s/    James L. Busby
	James L. Busby Chief Financial Officer

EX-10.40

EXHIBIT 10.40

THIS WARRANT AND THE SECURITIES ISSUABLE UPON EXERCISE HEREOF HAVE NOT BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933 OR APPLICABLE STATE LAW, AND NO INTEREST IN SAID SECURITIES MAY BE SOLD, DISTRIBUTED, ASSIGNED, OFFERED, PLEDGED OR OTHERWISE TRANSFERRED UNLESS (i) THERE IS AN EFFECTIVE REGISTRATION STATEMENT UNDER SUCH ACT AND APPLICABLE STATE SECURITIES LAWS COVERING ANY SUCH TRANSACTION INVOLVING SAID SECURITIES, (ii) THE COMPANY RECEIVES AN OPINION OF LEGAL COUNSEL FOR THE HOLDER OF SAID SECURITIES SATISFACTORY TO THE COMPANY STATING THAT SUCH TRANSACTION IS EXEMPT FROM REGISTRATION, OR (iii) THE COMPANY OTHERWISE SATISFIES ITSELF THAT SUCH TRANSACTION IS EXEMPT FROM REGISTRATION.

STOCK PURCHASE WARRANT

to Purchase up to

1,000,000 Shares of Common Stock

of

AVIVA PETROLEUM INC.

Void after December 12, 2004

This is to certify that, for value received and subject to the terms and conditions set forth below, the Warrantholder (hereinafter defined) is entitled to purchase, and the Company promises and agrees to sell and issue to the Warrantholder, at any time on or after the date of this Warrant and on or before December 12, 2004 up to 1,000,000 Shares (hereinafter defined) at the Exercise Price (hereinafter defined).

This Stock Purchase Warrant is issued subject to the following terms and conditions.

1.    Definitions of Certain Terms.    Except as may be otherwise clearly required by the context, the following terms have the following meanings:

(a) “Common Stock” means the common stock, without par value, of the Company.

(b) “Company” means Aviva Petroleum Inc., a Texas corporation, and any successor thereto.

(c) “Exercise Price” means the price at which the Warrantholder may purchase one Share (or Securities obtainable in lieu of one Share) upon exercise of Warrants as determined from time to time pursuant to the provisions hereof. The initial Exercise Price is $0.07 per Share.

(d) “Expiration Time” means 5 p.m. central standard time on December 12, 2004.

(e) “Securities” means the securities obtained or obtainable upon exercise of the Warrant or securities obtained or obtainable upon exercise, exchange, or conversion of such securities.

(f) “Share” shall mean one share of Common Stock for which the Warrant is initially exercisable.

(g) “Warrant Certificate” means a certificate evidencing the Warrant.

(h) “Warrantholder” means a record holder of the Warrant or Securities. The initial Warrantholder is Ronald Suttill.

(i) “Warrant” means the warrant evidenced by this Warrant Certificate or any certificate obtained upon transfer or partial exercise of the Warrant evidenced by any such Warrant Certificate.

2.    Exercise of Warrant.    All or any part of the Warrant may be exercised commencing on the date of this Warrant and ending at the Expiration Time by surrendering this Warrant Certificate, together with appropriate instructions, duly executed by the Warrantholder or by his duly authorized attorney, at the office of the Company, 8235 Douglas Avenue, Suite 400, Dallas, Texas 75225, or at such other office or agency as the Company may designate. Upon receipt of notice of exercise, the Company shall immediately prepare, or instruct its transfer agent to prepare, certificates for the Securities to be received by the Warrantholder upon

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completion of the Warrant exercise. When such certificates are prepared, the Company shall notify the Warrantholder and deliver such certificates to the Warrantholder or in accordance with the Warrantholder’s instructions immediately upon payment in full by the Warrantholder, in lawful money of the United States, of the Exercise Price payable with respect to the Securities being purchased.

If fewer than all the Securities purchasable under the Warrant are purchased, the Company will, upon such partial exercise, execute and deliver to the Warrantholder a new Warrant Certificate (dated the date hereof), in form and tenor similar to this Warrant Certificate, evidencing that portion of the Warrant not exercised. The Securities to be obtained on exercise of the Warrant will be deemed to have been issued, and any person exercising the Warrants will be deemed to have become a holder of record of those Securities, as of the date of the payment of the Exercise Price.

3.    Adjustments in Certain Events.    The number, class, and price of Securities for which this Warrant Certificate may be exercised are subject to adjustment from time to time upon the happening of certain events as follows:

(a)  If the outstanding shares of the Company’s Common Stock are divided into a greater number of shares or a dividend in stock is paid on the Common Stock, the number of shares of Common Stock for which the Warrant is then exercisable will be proportionately increased and the Exercise Price will be proportionately reduced; and, conversely, if the outstanding shares of Common Stock are combined into a smaller number of shares of Common Stock, the number of shares of Common Stock for which the Warrant is then exercisable will be proportionately reduced and the Exercise Price will be proportionately increased. The increases and reductions provided for in this subsection (a) will be made with the intent and, as nearly as practicable, the effect that neither the percentage of the total equity of the Company obtainable on exercise of the Warrants nor the price payable for such percentage upon such exercise will be affected by any event described in this subsection (a).

(b)  In case of (i) any reclassification or change of outstanding shares of Common Stock or other capital stock issuable upon exercise of this Warrant (other than a change in par value, or from par value to no par value, or from no par value to par value or as a result of a subdivision or combination), (ii) any consolidation or merger of the Company with or into another corporation (other than a merger in which the Company is the surviving corporation and which does not result in any reclassification or change of the then outstanding shares of Common Stock or other capital stock issuable upon exercise of this Warrant (other than a change in par value, or from par value to no par value, or from no par value to par value or as a result of subdivision or combination)) or (iii) any sale or conveyance to another corporation of the property of the Company as an entirety or substantially as an entirety, then, as a condition of such reclassification, change, consolidation, merger, sale or conveyance, the Company, or such other successor or purchasing corporation, as the case may be, shall make lawful and adequate provision whereby the Warrantholder shall have the right thereafter to receive on exercise of such Warrant the kind and amount of securities and property receivable upon such reclassification, change, consolidation, merger, sale or conveyance by a holder of the number of securities issuable upon exercise of such Warrant immediately prior to such reclassification, change, consolidation, merger, sale or conveyance. The provisions of this subsection (b) shall

2

similarly apply to successive reclassifications and changes of shares of Common Stock and to successive consolidations, mergers, sales and conveyances.

(c)  Irrespective of any adjustments or changes in the Exercise Price or the Securities purchasable upon exercise of this Warrant pursuant to this Section 3, the Warrant Certificate, whether or not thereafter reissued, may continue to express the Exercise Price per share and the number of shares of Common Stock purchasable thereunder as the Exercise Price per share and the number of shares of Common Stock purchasable thereunder were expressed in the Warrant Certificate when the same was originally issued.

(d)  No fractional shares of Common Stock or other Securities will be issued in connection with the exercise of the Warrant, but the Company will pay, in lieu of fractional shares, a cash payment therefor on the basis of the fair market value of the Shares or other Securities as determined in good faith by the Board of Directors of the Company.

4.    Reservation of Shares.    The Company agrees that the number of shares of Common Stock or other Securities sufficient to provide for the exercise of the Warrant upon the basis set forth above will at all times during the term of the Warrant be reserved for exercise.

5.    Validity of Securities.    All Securities delivered upon the exercise of the Warrant will be duly and validly issued in accordance with their terms and, in the case of Common Stock, will be fully paid and nonassessable. The Company will pay all documentary and transfer taxes, if any, in respect of the original issuance thereof upon exercise of the Warrant.

6.    No Rights as a Shareholder.    The Warrantholder shall not, by virtue hereof, be entitled to any rights of a shareholder in the Company, either at law or in equity, and the rights of the Warrantholder as such are limited to those expressed in the Warrant Certificate and are not enforceable against the Company except to the extent set forth herein. Furthermore, the Warrantholder, by acceptance hereof, consents to and agrees to be bound by and to comply with all the provisions of this Warrant. In addition, the Warrantholder, by accepting this Warrant, agrees that the Company and the transfer agent may deem and treat the person in whose name this Warrant is registered as the absolute, true and lawful owner for all purposes whatsoever, and neither the Company nor its transfer agent, if any, shall be affected by any notice to the contrary.

7.    Notice.    Any notices required or permitted to be given hereunder will be in writing and may be served personally or by mail; and if served will be addressed as follows:

If to the Company:	Aviva Petroleum Inc.
	8235 Douglas Avenue
	Suite 400
	Dallas, Texas 75225
	Attention: Chief Financial Officer
If to the Warrantholder:	Ronald Suttill
	4146 La Place
	Dallas, Texas 75220

3

Any notice so given by mail will be deemed effectively given 48 hours after mailing when deposited in the United States mail, registered or certified mail, return receipt requested, postage prepaid and addressed as specified above. Any party may by written notice to the other specify a different address for notice purposes.

8.    Securities Law Compliance.    By accepting this Warrant, the Warrantholder represents that the Warrantholder is acquiring the Warrant, and will acquire any shares of Common Stock or other Securities that may be acquired upon exercise of this Warrant, solely for the Warrantholder’s own account and not with a view to or for sale in connection with any distribution of the Warrant, the Common Stock, or other Securities of the Company. Unless the issuance of the Common Stock or other Securities issuable upon exercise of this Warrant shall have been registered under the Securities Act of 1933 and applicable state securities laws, as a condition of its delivery of certificates for such Securities, the Company may require the Warrantholder to deliver to the Company, in writing, representations regarding the Warrantholder’s sophistication, investment intent, acquisition for his own account and such other matters as are reasonable and customary for purchasers of securities in an unregistered private offering. The Company may place conspicuously upon each Warrant Certificate and upon each certificate representing the Securities a legend substantially in the following form, the terms of which are agreed to by the Warrantholder:

THESE SECURITIES HAVE NOT BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933 OR APPLICABLE STATE LAW, AND NO INTEREST THEREIN MAY BE SOLD, DISTRIBUTED, ASSIGNED, OFFERED, PLEDGED OR OTHERWISE TRANSFERRED UNLESS (i) THERE IS AN EFFECTIVE REGISTRATION STATEMENT UNDER SUCH ACT AND APPLICABLE STATE SECURITIES LAWS COVERING ANY SUCH TRANSACTION INVOLVING SAID SECURITIES, (ii) THE COMPANY RECEIVES AN OPINION OF LEGAL COUNSEL FOR THE HOLDER OF SAID SECURITIES SATISFACTORY TO THE COMPANY STATING THAT SUCH TRANSACTION IS EXEMPT FROM REGISTRATION, OR (iii) THE COMPANY OTHERWISE SATISFIES ITSELF THAT SUCH TRANSACTION IS EXEMPT FROM REGISTRATION.

9.    Applicable Law.    This Warrant Certificate will be governed by and construed in accordance with the laws of the State of Texas, without reference to conflict of laws principles thereunder.

	AVIVA PETROLEUM INC., a Texas corporation
Dated:  December 12, 2002	By:	/s/  James L. Busby
		James L. Busby Chief Financial Officer

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PURCHASE FORM

Dated:

The undersigned irrevocably elects to exercise the within Warrant to the extent of purchasing              shares of Common Stock and hereby makes payment of $             in payment of the actual exercise price thereof.

INSTRUCTIONS FOR REGISTRATION OF STOCK

Name	(Please type or print in block letters)
Address
Signature

5

IT SHALL BE A CONDITION TO THE VALIDITY OF THIS ASSIGNMENT THAT THE ASSIGNEE DELIVER TO AVIVA PETROLEUM INC. HIS OR ITS WRITTEN AGREEMENT TO ACCEPT AND BE BOUND BY ALL OF THE TERMS AND CONDITIONS OF THIS WARRANT.

ASSIGNMENT FORM

FOR VALUE RECEIVED,                                                   hereby sells, assigns and transfers unto

Name	(Please type or print in block letters)
Address

the right to purchase Common Stock represented by this Warrant to the extent of                      shares as to which such right is exercisable, and does hereby irrevocably constitute and appoint                                          attorney to transfer the same on the books of the Company with full power of substitution in the premises.

Date

Signature

6

EX-10.41

EXHIBIT 10.41

EMPRESA COLOMBIANA DE PETROLEOS ECOPETROL GUAYUYACO ASSOCIATION CONTRACT Pag. 1

ASSOCIATION CONTRACT

ASSOCIATE	:	ARGOSY ENERGY INTERNATIONAL
SECTOR	:	GUAYUYACO
EFFECTIVE DATE	:	September 30, 2002

The contracting parties, namely: on the one hand, Empresa Colombiana de Petróleos, hereinafter ECOPETROL, a State industrial and commercial company, authorized by Law 165 of 1948, currently governed by its by-laws, amended by Decree 1209 of 15 June 1994, and 2933 of 10 December 1997, domiciled in Bogota, represented by VICTOR EDUARDO PEREZ H, of legal age, bearer of Colombian Identity Card No. 19´083.549, issued in Bogota, domiciled in Bogota, who states that: 1. In his capacity as President of ECOPETROL, he acts herein on behalf of said Company and 2. The ECOPETROL Board of Directors authorized him to enter into this Contract, as witnessed by Minutes No. 2263 of 16 November 2001; and on the other hand, ARGOSY ENERGY INTERNATIONAL, a Limited Partnership established pursuant to the laws of the State of UTAH, with its main domicile in the United States of America, hereinafter THE ASSOCIATE, with a duly established Colombian branch and its main domicile in Santafe de Bogota, pursuant to Public Deed No. 5323 of 25 October 1983, granted by the Seventh Public Notary (7th) of the Bogota Circle, represented by ALVARO JOSE CAMACHO RODRIGUEZ, of legal age, bearer of Colombian Identity Card No. 79´142.747 issued in Usaquen, who states that: 1. He acts, in his capacity as legal representative of ARGOSY ENERGY INTERNATIONAL, 2. He is fully authorized to execute this contract, as certified by the certificate of incorporation and legal representation issued by the Chamber of Commerce of Bogota, and 3. THE ASSOCIATE, assures that it has the financial capability, the technical competence, and the necessary professional skills to perform the activities provided for in this contract.

Based on the aforementioned conditions, ECOPETROL and THE ASSOCIATE hereby certify that they have reached an agreement, based on the following clauses:

EMPRESA COLOMBIANA DE PETROLEOS ECOPETROL GUAYUYACO ASSOCIATION CONTRACT Pag. 2

FIRST: That on 27 May 1987, ECOPETROL, ARGOSY ENERGY INTERNATIONAL and NEO ENERGY INC. entered into the Shared Risk Contract for the “SANTANA” sector (hereinafter CPR SANTANA), which was legalized through Public Deed No. 1789 of 3 June 1987, granted by the Tenth (10th) Notary Public of the Bogota Circle.

SECOND: That in exercise of the assignment right established in Clause 27 of the CPR SANTANA, THE ASSOCIATE is currently 100% constituted by ARGOSY ENERGY INTERNATIONAL.

THIRD: That ECOPETROL’s Board of Directors, as certified in Minutes 2251 of 9 February 2001, approved a negotiation scheme to enter into new Association Contracts on Contracted Areas, excluding the reservoirs currently producing under the Association Contracts in force, which meet certain conditions.

FOURTH: That through its note ECP- 60 dated 6 March 2001, ECOPETROL informed The Associates of the various Association Contracts in their Development Phase, the approval that is mentioned in the above clause, and they were requested to report to ECOPETROL their interest to enter into a new Association Contract for Adjacent Prospects.

FIFTH: That through note No. GIO-56 of 26 April 2001, THE ASSOCIATE of CPR Santana stated its interest to accept ECOPETROL’s offer for the exploration of adjacent prospects.

SIXTH: That through note No. GIO-127 of 9 November 2001, THE ASSOCIATE of CPR SANTANA presented the terms of its proposal for the new contract, called “Guayuyaco”.

SEVENTH: That ECOPETROL and THE ASSOCIATE have visualized the Guayuyaco prospect as an Adjacent prospect.

EIGHTH: That THE ASSOCIATE has presented the Inchiyaco prospect with the probability of it being considered adjacent.

NINTH: That ECOPETROL considers that a well on the structure called Inchiyaco by THE ASSOCIATE, has the probability to be considered a development well of the Mary Commercial Field, which is part of the CPR Santana.

TENTH: That notwithstanding the above, for both Parties is important to carry out the exploration and development of the structure called Inchiyaco, and to this effect, they herein establish the conditions under which the wells drilled on such structure shall be

EMPRESA COLOMBIANA DE PETROLEOS ECOPETROL GUAYUYACO ASSOCIATION CONTRACT Pag. 3

treated, depending if it is confirmed as an adjacent prospect or as a development well of the commercial reservoirs in the Mary Commercial Field.

ELEVENTH: That the companies that make up THE ASSOCIATE in this contract and THE ASSOCIATE in the CPR Santana have agreed that ARGOSY ENERGY INTERNATIONAL shall be the Operator in THE CONTRACT.

In view of the foregoing conditions, ECOPETROL and THE ASSOCIATE hereby declare that they have entered into the contract contained in the following Clauses:

CHAPTER I - GENERAL PROVISIONS

CLAUSE 1 - PURPOSE OF THIS CONTRACT

1.1    The purpose of this contract is the exploration of the Contracted Area and the exploitation of Hydrocarbons of Colombian property that may be found in such area, described in Attachment A that is part of this contract.

1.2    In compliance with Article 1 of Decree 2310 of 1974, the exploration and exploitation of Hydrocarbons of Colombian property will be carried out by ECOPETROL, a company that may carry out said activities either directly or through contracts with private parties. Based on the aforementioned provision, ECOPETROL has agreed with THE ASSOCIATE to explore the Contracted Area and exploit the Hydrocarbons that may be found in it, in compliance with the terms and conditions set forth herein, Attachment A, Attachment B (Operations Agreement), and Attachment “C” which become an integral part of this contract.

1.3    Without prejudice of the provisions in this contract, it is understood that THE ASSOCIATE shall have the same rights and obligations before the Colombian law as those who exploit State-owned Hydrocarbons within the country, with regard to the hydrocarbons produced in the Contracted Area and their respective portion.

1.4    ECOPETROL and THE ASSOCIATE agree to carry out Exploration and Exploitation Works on the lands located in the Contracted Area, according to the terms set forth herein, and to split the costs and risks of same in the proportions and pursuant to that provided herein, and that the Hydrocarbons produced shall belong to each of the Parties as per shares established herein.

EMPRESA COLOMBIANA DE PETROLEOS ECOPETROL GUAYUYACO ASSOCIATION CONTRACT Pag. 4

CLAUSE 2 - CONTRACT APPLICATION

This contract is applied to the Contracted Volume, identified in Clause 3 and Attachment “A” hereto.

CLAUSE 3 - CONTRACTED AREA

The Contracted Area is called “GUAYUYACO”, with an area of twenty one thousand one hundred ninety-one (21,191) hectares and five thousand eight hundred (5,800) square meters, which coincides with the Contracted Area of the CPR Santana and is located within the municipal jurisdictions of Villa Garzon, Puerto Guzman, and Mocoa in the Department of Putumayo and Piamonte, in the province of Cauca. The commercial reservoirs of the CPR Santana, Mary, Miraflor, Linda and Toroyaco, are excluded.

This area and the commercial reservoirs are described in Attachment “A”, which is part of this contract.

Paragraph 1.- Should any person file a claim asserting ownership of the Hydrocarbons in the subsurface within the Contracted Area, ECOPETROL shall deal with the case, assuming such obligations as may arise.

Paragraph 2.- In the event of discovering hydrocarbons in the Contracted Area and if, through proven methods in the Oil Industry, it is verified that the discovered reservoirs are an extension of the CPR Santana commercial reservoirs, the Parties agree to implement, prior approval by the Ministry of Mines and Energy, a unified development plan, which must adhere to the hydrocarbon exploitation engineering techniques, as provided for in Clause l6 of the Contract. The foregoing, without prejudice of the special treatment given in this Contract to the wells drilled on the structure called Inchiyaco.

Paragraph 3.- To carry out any activity as the purpose of this contract, which affects or involves the wells, constructions, pipeline, transfer lines and other assets belonging to the Joint Account of the CPR Santana, THE ASSOCIATE shall inform and request authorization from the CPR Santana Parties to carry out such activity, as well as agree on the terms under which it will be performed.

Paragraph 4.- Should the Contracted Area extend into areas that are or have been reserved and declared as included within the National Parks system, THE ASSOCIATE is committed to accept the conditions imposed by the competent authorities, without considering that this Contract has been amended and without this allowing for any claim whatsoever against ECOPETROL, as agreed under Clause 30 (number 30.2) herein.

EMPRESA COLOMBIANA DE PETROLEOS ECOPETROL GUAYUYACO ASSOCIATION CONTRACT Pag. 5

CLAUSE 4 - DEFINITIONS. For purposes of this contract, the terms mentioned below shall have the following meanings:

4.1    Contracted Area is the land defined in Clause 3 above, and described in Attachment “A” hereto.

4.2    Field: Portion of the Contracted Area where there are one or more structures and/or totally or partially superimposed stratigraphic traps with one or more producing Reservoirs, or in which the capacity to produce Hydrocarbons in commercial quantities has been proven. Such Reservoirs can be found separated vertically and/or laterally by geological barriers or impermeable strata, or both.

4.3    Commercial Field: It is the Field that ECOPETROL accepts that is capable of producing Hydrocarbons in economically exploitable quantity and quality in one or more Production Targets defined by ECOPETROL upon acceptance of commerciality, without prejudice of the possibility of other Production Targets being found during the development phase.

4.4    Gas Field: The field which, based on the information supplied by THE ASSOCIATE, is designated by ECOPETROL as a non-associated natural gas (or free natural gas) producer, when determining commerciality thereof.

4.5    Executive Committee: This is the body formed within 30 days following the acceptance of the first Commercial Reservoir to supervise, monitor, and approve all the operations and actions carried out during the term of the contract.

4.6    Exploration Direct Costs: Monetary expenses incurred reasonably by THE ASSOCIATE for the acquisition of seismic data and the drilling of Exploratory Wells, and for locations, termination, equipment and tests for such wells, as well as the costs for workover incurred by THE ASSOCIATE for the exploration of new targets located on the wells of the fields currently being developed within the CPR Santana. The Exploration Direct Costs do not include either administrative or technical support from the home office or the Company central office.

4.7    Joint Account: The records to be kept on accounting books, in accordance with Colombian law, to credit or debit the share of each Party their corresponding share in the Joint Operation of each Commercial Reservoir.

4.8    Budget Execution: Funds actually spent and/or committed in each of the programs and projects approved for a specific calendar year.

EMPRESA COLOMBIANA DE PETROLEOS ECOPETROL GUAYUYACO ASSOCIATION CONTRACT Pag. 6

4.9    Structure: The geometric shape with geological closure (anticlinal, synclinal, etc.) present in the formations, in which fluid accumulations are found.

4.10    Effective Date: The date on which the sixty (60) calendar day term expires, as of the date on which this contract is executed, and starting date for all time limits agreed to herein, regardless of the date of approval thereof, regardless of the date of contract approval by the Ministry of Mines and Energy.

4.11    Cash Flow: Represented by the physical currency transactions (revenue and disbursement) that are to be made by the Joint Account to meet the different obligations acquired by the Association in performance of normal operations.

4.12    Associated Natural Gas: Blend of light Hydrocarbons that exist as a gas layer or solution state gas in the Reservoir, which is produced jointly with liquid Hydrocarbons.

4.13    Non-Associated Natural Gas (Production of): Hydrocarbons produced in gaseous state on the surface and reported at standard conditions, with average values (weighted by production), with an initial gas/oil ratio greater than 15,000 standard cubic feet of gas per barrel of liquid Hydrocarbon, and a molar heptane plus composition plus (C₇ +) below 4.0%.

4.14    Direct Costs: All expenditures charged to the Joint Account on account of personnel expenses related to personnel directly hired by the Association, procurement of materials and supplies, contracting of services with third parties, and other general expenses required by the Joint Operation in the normal development of its activities.

4.15    Indirect Costs: Expenditures charged to the Joint Account, on account of technical and/or administrative support provided by the Operator thorough its own organization to the Joint Operation.

4.16    Interest in Arrears: When dealing with Colombian pesos, it shall mean the rate for payment in arrears on the date the of the default; when dealing with Dollars of the United States of America, it shall mean the LIBOR (London Interbank Borrowing Offered Rate) prime rate on three-month term deposits in USA currency, plus four per cent (LIBOR plus 4%).

4.17    Participating Interest: It is the share in the obligations and rights acquired by each of the Parties in the exploration and exploitation of the Contracted Area.

EMPRESA COLOMBIANA DE PETROLEOS ECOPETROL GUAYUYACO ASSOCIATION CONTRACT Pag. 7

4.18    Development Investment: It refers to the amount of money invested in assets and equipment, to be capitalized as assets for the Joint Operation in a Commercial Field, once the existence thereof has been accepted by the Parties.

4.19    Hydrocarbons: All organic compounds, made up mainly by the natural blend of carbon and hydrogen, as well as all other accompanying substances or their by-products, excepting helium and rare gases.

4.20    Gaseous Hydrocarbons: All those Hydrocarbons produced in gaseous state on the surface and reported at standard conditions (1 atmosphere of absolute pressure and a temperature of 60° F degrees).

4.21    Liquid Hydrocarbons: Crude oil and condensates, as well as those produced in such state as a result of treating the gas, as necessary, reported at standard conditions.

4.22    Production Targets: These are the reservoir(s) located within the discovered Commercial Field, and proved as commercial producers.

4.23    Joint Operation: Activities and works either performed or being performed on behalf and at the expense of the Parties.

4.24    Operator: Person designated by the Parties to directly perform the necessary operations, on their account and without representing them, to explore and exploit the Hydrocarbons found in the Contracted Area.

4.25    Parties: As of the Effective Date, ECOPETROL and THE ASSOCIATE. Subsequently, and at any time, ECOPETROL on the one hand, and THE ASSOCIATE and/or its assignees, on the other.

4.26    Exploration Period: This is the term that THE ASSOCIATE has to fulfill the obligations set forth in Clause 5 hereunder, which shall not exceed five and a half (5.5) years as of the Effective Date, except for the events considered in Clauses 5 (Item 5.4), 9 (number 9.3), and 34.

4.27    Exploitation Period: The period elapsed from the expiration of the Exploration Period, or Retention Period, if any, until the expiration of this contract.

4.28    Retention Period: The period that may be requested by THE ASSOCIATE and granted by ECOPETROL to commence the Exploitation Period of each Gas Field discovered within the Contracted Area, which, due to its specific conditions cannot be

EMPRESA COLOMBIANA DE PETROLEOS ECOPETROL GUAYUYACO ASSOCIATION CONTRACT Pag. 8

developed in the short term and, therefore, requires an additional period to perform feasibility studies for the construction of infrastructure and/or market development.

4.29    Development Plan: This is the guideline document for carrying out the exploitation of each Field in a technical, efficient, and economic manner, and shall contain, among others, the development strategy, environmental considerations, activities to be performed, short and medium-term production forecasts, a five-year forecast of investments and expenses and, specifically, a description of the projects, operations program, and the budget for the rest of the current calendar year or the following calendar year, as the case may be. The guidelines for preparing this Development Plan are described in Annex C of this contract.

4.30    Exploratory Well: This is the well that has been classified as such by THE ASSOCIATE to be drilled or deepened, sidetracked or re-entered, on its own account in the Contracted Area in search for new reservoirs, or to prove the extension of a Reservoir, or to determine the stratigraphy of an area. In order to comply with the obligations agreed in Clause 5 of this contract, the relevant Exploratory Well will be previously qualified by ECOPETROL and THE ASSOCIATE.

4.31    Discovery Well: Is the Exploratory Well in which the existence of one or more Reservoirs is discovered or proven, which may require a further evaluation to determine whether such reservoir or reservoirs may be commercially exploited.

4.32    Exploitation Well (or Development Well): Is the well previously considered as such by the Executive Committee for the production of Hydrocarbons discovered in the Production Targets within the area of each Commercial Field.

4.33    Budget: Is the basic planning instrument, through which resources are allocated to specific projects, to be applied within one calendar year or part of it, to meet the targets and objectives proposed by THE ASSOCIATE or the Operator.

4.34    Long-Term Tests: Are operations performed in one or several producer Exploratory Wells, in order to evaluate the production conditions and reservoir behavior, with temporary production facilities.

4.35    Reimbursement: Is the payment of thirty percent (30%) of the Direct Exploration Costs incurred by THE ASSOCIATE.

4.36    Exploration Works: Are operations performed by THE ASSOCIATE in regard to the prospecting and discovery of Hydrocarbons in the Contracted Area.

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4.37    Reservoir: Is any rock beneath the surface, in which Hydrocarbons are accumulated in the pore or fractured spaces, which is producing, or able to produce Hydrocarbons, and which behaves as an independent unit as to its petrophysical and fluid properties, and has a common pressure system throughout its entire expanse.

4.38    Commercial Field: Is the Reservoir that ECOPETROL accepts that is able to produce Hydrocarbons in economically profitable quantity and quality, as defined by ECOPETROL in the moment of accepting commerciality.

CHAPTER II - EXPLORATION

CLAUSE 5 - TERMS AND CONDITIONS

5.1    THE ASSOCIATE is committed to carry out Exploration Works in accordance with modern standards and practices commonly accepted and used by the international oil industry and in compliance with all legal and regulatory provisions in force. The Exploration Period shall last two and a half (2.5) years, commencing as of the Effective Date and will be divided in two Phases. The first Phase will last twelve (12) months, and the second Phase will commence on the calendar day immediately subsequent to the termination of the first Phase for an eighteen (18) month term.

During the Exploration Period, THE ASSOCIATE is committed to perform, at least, the following Exploration Works, in which the new targets will be entirely independent from the Commercial Reservoirs in the CPR Santana, and can be located on sectors adjacent thereto (deeper, shallower, or lateral), taking into account their interpretation or the existing geological model, jointly validated by THE ASSOCIATE and ECOPETROL on the date of execution of this contract.

The approval, terms and conditions for the use of the wells drilled in performance of the Guayuyaco contract to exploit the commercial reservoirs of the CPR Santana, shall be subjected exclusively to the previous decision of the CPR Santana Executive Committee. Should the new reservoir be derived from a workover on a well that is producing from the CPR Santana commercial reservoirs, THE ASSOCIATE shall establish a differentiated measurement system, accepted by the Oil Industry and previously approved by the Ministry of Mines and Energy.

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During the initial exploration phase (hereinafter “the First Phase”), THE ASSOCIATE is committed to perform, at least, the drilling of one Exploratory Well until penetrating and, as the case may be, proving the formation likely to produce hydrocarbons in the Area.

Upon completion of the First Phase, THE ASSOCIATE will have an option to withdraw from the CONTRACT, after having fulfilled the agreed exploratory commitments. During the Second Phase, whose term is eighteen (18) months, THE ASSOCIATE shall perform the drilling on one Exploratory Well until penetrating and, as the case may be, proving the formations likely to produce hydrocarbons in the Area.

Upon completion of the Second Phase, the CONTRACT shall come to an end, if its extension has not been requested by THE ASSOCIATE and authorized by ECOPETROL, pursuant to number 5.2 in this Clause, or no reservoir has been discovered.

5.2    If THE ASSOCIATE has satisfactorily fulfilled the obligations set forth in Clause 5.1, ECOPETROL, upon request by THE ASSOCIATE, shall extend yearly, for up to three (3) additional years, the Exploration Period; for such purpose, THE ASSOCIATE, shall report its intention to continue exploring the contracted block with an anticipation of not less than thirty (30) calendar days prior to the date of termination of the Exploration period, attaching to this request the proposed schedule for the Exploration Work to be performed in each extension period. Within the thirty (30) calendar days following the date of receipt by ECOPETROL of THE ASSOCIATE’s request, the Parties may agree the Exploration Work program to be performed during these extensions. In the absence of an agreement, THE ASSOCIATE shall be committed to perform Exploration Work in the Contracted Area, comprising the drilling of one Exploratory Well until penetrating and, if applicable, test the formations likely to produce hydrocarbons in the Contracted Area per year. At the end of each extension, each for a one-year term, THE ASSOCIATE shall have the option to rescind the Association Contract, after fulfilling the exploratory commitments agreed for each of them.

Upon expiration of the Exploration Period, the contract will come to an end, if no Reservoir has been discovered.

Paragraph: Taking into account the whereas clauses Eighth, Ninth and Tenth, THE ASSOCIATE, in order to comply with that set forth in this clause, shall be enabled to drill the Inchiyaco well, which will initially be considered an exploratory well. Nevertheless,

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the Parties hereby commit to verify as soon as it is technically possible, the commercial independence of the commercial reservoirs of the Mary field from the Inchiyaco well reservoirs. In the event of proving, through methods accepted within the Petroleum Industry, that any of the Inchiyaco well reservoirs are an extension of the commercial reservoirs of the May Commercial Field in the CPR Santana, these reservoirs shall be subject to the conditions set forth in the CPR Santana, including without limitation, the fact that its production shall be part of the CPR Santana, and the reimbursement that is to be made by ECOPETROL shall be paid in cash, as per the conditions established in the CPR Santana. Notwithstanding the above, this well shall comply with the conditions established herein.

5.3    THE ASSOCIATE may, at its discretion and at its own expense and risk, carry out additional Exploration Work, beyond that agreed for the phase of the ongoing Exploration Period. Nevertheless, if THE ASSOCIATE wishes such additional Exploration Work to be credited to compliance with exploratory commitments of the following phase in the Exploration Period, it must request the appropriate approval from ECOPETROL. If the request is accepted by ECOPETROL, the latter shall determine how and in what amount the transfer of the mentioned obligations shall be made.

5.4    If at the end of the five and a half (5.5) year Exploration Period, THE ASSOCIATE has drilled one or several Discovery Wells that may indicate the possible existence of a Commercial Field, upon written request from THE ASSOCIATE, ECOPETROL may authorize the extension of the Exploration Period for a term not exceeding two (2) years, in order for THE ASSOCIATE to have the opportunity to prove the existence of such Commercial Field. In order to enforce the provisions contained herein, prior to the termination of the Exploration Period and, simultaneously with its request, THE ASSOCIATE shall supply ECOPETROL with the maps and other descriptions of the area that THE ASSOCIATE may consider capable of producing Hydrocarbons, the Exploration Work program, as well as that of other operations to be carried out by THE ASSOCIATE, and the budget for carrying out such work at its own expense and risk, to determine the extension of the Reservoir or Reservoirs that have been discovered and to prove the existence of a Commercial Field. If the proposed work program meets international standards and is aimed at proving the commerciality of the Reservoirs

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discovered within the agreed term, ECOPETROL shall grant its authorization to perform this program.

5.5    Throughout the term of this Contract and pursuant to provisions in Clause 7 herein, THE ASSOCIATE may conduct Exploration Works and THE ASSOCIATE shall be exclusively responsible for the risks and costs of these activities and, thus, it shall have the full and exclusive control of such activities, without changing the maximum term of the contract for this reason.

CLAUSE 6 - SUPPLY OF INFORMATION DURING EXPLORATION

6.1    ECOPETROL will supply THE ASSOCIATE, with all the information available it possesses on the Contracted Area, when THE ASSOCIATE so requests. The costs incurred in the reproduction and delivery of said information shall be borne by THE ASSOCIATE.

6.2    During the Exploration Period, THE ASSOCIATE shall provide ECOPETROL, as it obtains it, and in accordance with ECOPETROL’s information provision manual, all geological and geophysical information, cores, edited magnetic tapes, process seismic sections, and all support field information, magnetic and gravimetric profiles, all in reproducible originals, copies of geophysical reports, reproducible originals of all well logs of the wells drilled by THE ASSOCIATE, including a final composite log of each well and copies of the final drilling report, including core sample analysis, results of production tests and any other information related to the drilling, the study or interpretation of any nature performed by THE ASSOCIATE on the Contracted Area, without any limitation. ECOPETROL is entitled, at all times, to use the procedures it deems appropriate, to witness all operations and verify all the above mentioned data.

6.3    The Parties hereby agree that all geological, geophysical and engineering information obtained in the Contracted Area in performance of this contract will be strictly confidential during the three (3) years following the acquisition date or upon termination of the contract, whatever occurs first. The information released comprises, without limitation, seismic information, potential methods, remote sensors, geochemistry, along with their corresponding supports, surface and subsurface cartography, well reports, electric logs, formation tests, biostratigraphic, petrophysical and fluid analyses, and production records. In spite of confidentiality stated herein, the Parties agree that in

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each case they may exchange such information with companies that are or not associated with ECOPETROL. It is understood that all that is agreed to herein will take place without prejudice to the obligation to submit to the Ministry of Mines and Energy all the information requested by the latter in compliance with the legal and regulatory provisions in force. However, it is hereby understood and agreed that the Parties may supply, as they may deem appropriate, all the information that their affiliates, consultants, contractors, and financial entities may request, required by the relevant authorities having jurisdiction over the Parties or their affiliates, or by regulations from any stock exchange in which the shares of the Parties or related corporations are registered.

6.4    Within the ninety (90) calendar days following completion of the drilling operations of each Exploratory Well, THE ASSOCIATE shall advise ECOPETROL in writing on the status of the respective well, its classification derived from the results obtained (Dry or Discovery) and the type of fluids produced, if any.

CLAUSE 7 - BUDGET AND EXPLORATION PROGRAMS

According to the provisions of this contract, THE ASSOCIATE shall be responsible for preparing the programs, activity schedule, and budget to be executed in the short term (the following calendar year), and the plan for the following two (2) years, under the estimated budget, to carry out the exploration in the Contracted Area. Said plan, programs, schedule, and budget shall be submitted to ECOPETROL, for the first time, within the sixty (60) calendar days following the execution of this contract and, subsequently, no later than 15 December every year. Every six months, THE ASSOCIATE shall deliver to ECOPETROL a technical and financial report listing the different exploratory activities performed, the area’s prospects based on information acquired, the allocated Budget and the exploration costs incurred up to the date of the report, along with the comments on the reasons for any deviations. At ECOPETROL’s request, THE ASSOCIATE will provide explanations on the report at meetings summoned to this end. The information presented by THE ASSOCIATE in the reports and aforementioned explanations shall, in no case, be understood as accepted by ECOPETROL. The financial information will be subject to auditing by ECOPETROL

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within the terms established in Clause 22 of Annex “B” (Operation Agreement) of this contract.

CLAUSE 8—RETENTION PERIOD

8.1    If THE ASSOCIATE has discovered a Gas Field and submits the request for commerciality for such Field mentioned in Clause 9, number 9.1, it may simultaneously request ECOPETROL to grant a Retention Period, fully supporting the reasons for the approval of such Period.

8.2    The Retention Period shall be requested by THE ASSOCIATE and granted by ECOPETROL. Should the Retention Period be granted, it is understood that the term foreseen in Clause 9 (number 9.1) for ECOPETROL to decide whether it accepts or not the existence of a Gas Commercial Field, shall be postponed for the same term of the Retention Period.

8.3    The Retention Period shall not exceed four (4) years. Should the term initially granted as a Retention Period be insufficient, ECOPETROL, prior written and duly supported request by THE ASSOCIATE, may extend the Retention Period for an additional term, without the addition of the initial retention period and the extensions thereof exceeding four (4) years. The Retention Period applies exclusively to the Gas Field area that ECOPETROL in principle determines as able to produce Hydrocarbons.

CHAPTER III - EXPLOITATION

CLAUSE 9—TERMS AND CONDITIONS

9.1    To initiate the Joint Operation under the terms and conditions of this contract, it is understood that the Exploitation Work will begin once the Parties recognize the existence of the first Commercial Field or upon compliance with the provisions of Clause 9 (Item 9.5). The existence of a Commercial Field will be determined by the drilling, carried out by THE ASSOCIATE in the proposed Commercial Field, of a sufficient number of Exploratory Wells so as to allow to reasonably define the area capable of producing Hydrocarbons and the commercial nature of the Field. If, after evaluating the results obtained from the Discovery Wells, THE ASSOCIATE considers that it has discovered a Commercial Field, it shall inform ECOPETROL in writing, providing it with

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the studies on which it has based the conclusion, as well as the relevant Development Plan. ECOPETROL, within a ninety (90) calendar day period, starting on the date on which THE ASSOCIATE supplies all the support documentation and makes a technical presentation to ECOPETROL, the latter must accept or reject the existence of the Commercial Field. ECOPETROL may request all the additional information deemed necessary within the thirty (30) days following the date of submission of the first support documentation.

9.2.    Should ECOPETROL accept the existence of the Commercial Field, it shall inform THE ASSOCIATE thereof, within the period specified in Clause 9, (Item 9.1) and shall specify the area and the Commercial Field, and begin to participate in the exploitation of the Commercial Field discovered by THE ASSOCIATE, as per the terms established herein.

9.2.1    ECOPETROL shall reimburse THE ASSOCIATE for thirty percent (30%) of the Direct Exploration Costs incurred by THE ASSOCIATE, at its own risk and expense, within the Contracted Area and prior to the date of acceptance of commerciality by ECOPETROL for each new Commercial Field discovered, as established in item 9.1 of this Clause, provided such expenses have not been charged previously to another Field.

9.2.2    The amount of these costs will be determined in United States dollars, using as a reference date, the date on which THE ASSOCIATE has made the relevant disbursements; therefore, costs incurred in Colombian currency will be calculated at the representative market exchange rate prevailing on the date established herein and certified by the Banking Superintendence or its substitute agency.

Paragraph: Once the amount of the Direct Exploration Costs to be reimbursed in USA currency has been determined, such amount will be updated monthly according to the average consumer price index of industrialized countries, as of the date of disbursement, in constant U.S. dollars at the rate prevailing on the date on which ECOPETROL disburses as provided for in the Operation Agreement (Attachment B) of this contract. Balances to be reimbursed shall also be updated up to the date in which ECOPETROL reimburses its total share in the respective Commercial Field.

9.2.3    Reimbursement of Direct Exploration Costs, according to Clause 9 (Item 9.2.1) will be made by ECOPETROL to THE ASSOCIATE as of the date on which the Commercial Field is put on line by the Operator, through payment of the dollar equivalent to fifty

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percent (50%) of its direct share in the total production of the Commercial Field, after deducting the corresponding royalties.

Paragraph: If dealing with a Commercial Gas Field, such reimbursement shall be made by ECOPETROL to THE ASSOCIATE, as of the date on which the Commercial Field is put on line by the Operator, through payment of the dollar equivalent to one hundred percent (100%) of its direct share in the total production of the respective Commercial Field, after deducting the corresponding royalties.

9.3    Should ECOPETROL, based on the information supplied, not accept the existence of the Commercial Field as stated in Clause 9 (Item 9.1), it may request that THE ASSOCIATE to submit and carry out an additional work program, to demonstrate Field commerciality. Such work shall be performed at THE ASSOCIATE’S risk and expense and its duration may not exceed two (2) years. In such case, the Exploration Period for the Contracted Area will be automatically extended for a period equal to that agreed between the Parties as required for performing the additional work provided for in this Clause. THE ASSOCIATE may submit and carry out a work program that complies with the requested objective, or request the opinion of an expert, according to Clause 28 of this contract, upon request for additional information. Should the expert opinion favor ECOPETROL, THE ASSOCIATE shall meet the requirements and, once again, submit the commerciality studies and a revised Development Plan to ECOPETROL’s consideration. Should the expert opinion favor THE ASSOCIATE, it shall be understood that ECOPETROL has the necessary information and, hence, the ninety (90) calendar day term, as provided for in Clause 9.1, to accept or reject the existence of the Commercial Field, shall begin to count as of the date in which ECOPETROL is provided with the expert’s decision.

9.4    If, after performance of the additional works or if the disagreement has been resolved by an expert, as mentioned in the previous number herein, ECOPETROL accepts the existence of the Commercial Field referred to in Clause 9 (Item 9.1), it shall commence participating in the Commercial field development operations, as per the terms established herein, and shall reimburse THE ASSOCIATE as provided for in Clause 9 (items 9.2.2 and 9.2.3), thirty percent (30%) of the cost of the additional work requested, referred to in Clause 9 (Item 9.3), and the works performed shall become property of the Joint Account.

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9.5    Sole Risk Method: If ECOPETROL does not accept the existence of a Commercial Field, even after the additional work described in Clause 9 (Item 9.3) has been completed, THE ASSOCIATE shall be entitled to perform, at its own account and risk, the work deemed necessary for the exploitation of said Field, according to the Development Plan presented to ECOPETROL and following good practices of the international petroleum industry, and to recover the cost of such works, and the Direct Exploration Costs incurred by THE ASSOCIATE prior to the date in which ECOPETROL takes a decision with respect to the commerciality of the respective Field, that have not been charged previously to another Field. For purposes of this Clause, the recovery of the aforementioned costs will be achieved through THE ASSOCIATE’s participation in the Hydrocarbons produced in the respective Field, minus the royalties referred to in Clause 13, as provided in Clause 14 (Item 14.2.3) of this contract for exploitation under the sole risk method.

9.5.1.1.1.1    For purposes of calculating the dollar amount of disbursements made in pesos, the representative market rate of exchange will be used, as certified by the Bank Superintendence or the agency replacing it, on the date on which THE ASSOCIATE made the disbursements. For purposes of this clause, the value of each barrel of Hydrocarbon produced in said Field during a calendar month shall be the price of reference agreed on by the Parties. If THE ASSOCIATE wishes to use the right to develop the Reservoir under the sole risk method, it should expressly state so at the latest during the one hundred and twenty (120) calendar days following the date in which ECOPETROL informs about the non-acceptance of the Commercial Field existence. Should THE ASSOCIATE fail to use this right, the Field and its reserve zone shall be subjected to the contractual conditions of the CPR Santana.

9.6    In order to define the limits of a Commercial Field, all geological, geophysical and data related to wells drilled in said Field, or related thereto, will be taken into consideration.

9.7    If upon acceptance of one or more Commercial Fields, or after having commenced the sole risk method as per Clause 9 number 9.5, THE ASSOCIATE continues fulfilling its exploratory obligations agreed in Clause 5, it may simultaneously exploit such Fields before the end of the Exploration Period defined in Clause 4, but the Exploitation Period shall not be considered to have commenced until the expiration date of the former. If

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dealing with Gas Fields on which ECOPETROL has granted a Retention Period, the Exploitation Period for each Field shall commence as of the expiration date of the respective Retention Period.

9.8    If, as a result of the drilling of Exploration Wells after a decision has been made regarding the existence of a Commercial Field, THE ASSOCIATE proves the presence of additional Hydrocarbon accumulations associated with such Field, it must request that ECOPETROL expand the Commercial Field area and its commerciality, following the procedure provided for in Clause 9 (Item 9.1). If ECOPETROL accepts commerciality, it shall reimburse THE ASSOCIATE thirty percent (30%) of the Direct Exploration Costs exclusively related to the expansion of the Commercial Field area, under the terms provided for in items 9.2.2 and 9.2.3. If ECOPETROL does not accept the existence of a Commercial Field, THE ASSOCIATE shall be entitled to a reimbursement of up to two hundred percent (200%) of the total cost of the work performed at its own account and risk for the exploitation of the Exploratory Wells classified as producers, and up to thirty percent (30%) of the Direct Exploration Costs incurred by THE ASSOCIATE, related exclusively to the upgrade of the requested area prior to the date in which ECOPETROL makes a decision in this regard. Such reimbursement shall be effected through the production from Exploratory Wells classified as producers, minus the royalty, following the procedure established in Clause 21 (Item 21.2) up to the percentages stipulated herein.

CLAUSE 10 - OPERATOR

10.1    The Parties hereby agree that ARGOSY ENERGY INTERNATIONAL is the Operator and, as such, and with the limitations contained herein, shall have full control of all operations and activities deemed necessary for the technical, efficient, and economic exploitation of the Hydrocarbons that may be found in the area of the Commercial Field. They further agree that, despite the fact that this Contract—entered into for the commercial purposes provided in Clause 1—ARGOSY ENERGY INTERNATIONAL is the Operator, it is hereby understood by the Parties who have so decided, that for all legal purposes of a labor nature, ARGOSY ENERGY INTERNATIONAL does not act as a representative of the Parties, but rather as the sole and true employer of the workers it contracts for the operation of a commercial field and,

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consequently, it shall be responsible for all labor obligations arising from the associated relations or labor contracts, such as payment of wages and fringe benefits, parafiscal contributions, affiliation and payments on account of pensions, health, and professional risks to the Social Security Integral System as provided for in Law 100 of 1993 and its regulatory decrees or other regulations which may substitute or amend it.

10.2    The Operator is committed to carry out all development and production operations in compliance with the known standards and practices, to which end it shall use the best technical methods and systems required for the economic and efficient exploitation of the Hydrocarbons and to apply all relevant legal and regulatory provisions. Likewise, it shall, in a timely manner, provide the Parties with the reports and documents set forth in the contract, as well as any other information required by the Executive Committee with regard to the Joint Account and/or Operation.

10.3    In view of the above and, considering that for the performance of and compliance with the Commercial Field operation, ARGOSY ENERGY INTERNATIONAL will perform all its activities using its own resources, with technical and administrative autonomy, such Operator shall be considered an entity different from the Parties for all purposes of this contract, as well as for the application of civil, labor, and administrative law, and for its relations with the personnel hired in accordance with Clause 32.

10.4    The Operator shall have the right to resign from its position, by means of a written notice given to the Parties at least six (6) months prior to its effective date of resignation. The Executive Committee shall designate the new Operator in compliance with Clause 19 (Item 19.3.5). In the event that the Operator designated by the Executive Committee were a third party, other than the Parties hereto, a contract must be executed between the Parties and the new Operator.

10.5    The Operator shall carry out the operations provided for in this contract in a diligent, responsible, efficient, technically and economically appropriate, whereby it is understood that it shall, in no way be responsible for errors of judgment, or losses or damage not resulting from the Operator’s gross negligence.

10.6    The Operator shall be entitled to perform any work through a contractor, subject to the powers of the Executive Committee, according to Clause 11 (Item 11.1). For purposes of compliance herewith, the Operator shall enter into contracts following the procedure described in Attachment B, and subject to the principles of good faith,

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transparency, economy, equity, responsibility, planning, quality, expeditiousness, and social and environmental responsibility that should govern all contracting.

10.7    THE ASSOCIATE shall have the option to agree with ECOPETROL the conditions for providing its services for the operation of the fields and facilities returned in the CPR Santana, after its termination date.

CLAUSE 11 - EXPLOITATION PROGRAMS AND BUDGETS

11.1    Within three (3) months following the acceptance of a Commercial Field in the Contracted Area, the Operator shall submit to the Parties the proposed projects, programs, and Budget for the Development Plan of the Commercial Field, for the rest of the respective calendar year, to be approved by the Executive Committee. In the event that less than six and a half (6½) months remain before the end of said year, the Operator shall prepare and submit the proposed projects, programs, and budget for the following calendar year, within a three-month period.

11.1.1.    The projects, programs and Budget contained in the Development Plan for the Commercial Field shall be reviewed and revised annually, and submitted to the Parties by the Operator during the month of May, each calendar year, to which end, the Operator shall submit its proposal within the first ten (10) days of May. Within twenty (20) days following the receipt of the proposed projects, programs, and Budget of the Development Plan for the Commercial Field, the Parties shall inform in writing to the Operator in regards to the changes they wish to propose. When this occurs, the Operator shall take into consideration the remarks and amendments proposed by the Parties in the preparation of the revised Development Plan that will be submitted to the Executive Committee for final approval in the ordinary meeting of July of each year. In case that the total budget of the Commercial Field has not been approved before July, those aspects of the Budget on which an agreement has been reached will be approved by the Executive Committee, and those aspects not approved will be immediately submitted to the Parties for further approval and final decision as provided for in Clause 20.

11.2    The Parties may propose additions or revisions to the projects, programs, and annual budget approved for every Commercial Field, but except for emergency cases, they should not be suggested with a frequency less than three (3) months. The

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Executive Committee will decide about the additions and revisions proposed in a meeting, which will be summoned within the 30 days following the submission of the proposals.

11.3    The main objectives of projects, programs, and budgets are the following:

11.3.1    To determine the operations to be carried out, and the expenses and investments (Budget), which the Operator is authorized to execute in each Commercial Field during the following calendar year.

11.3.2    To keep a mid and long-term view on the development of every Field.

11.4    The projects, programs, and annual budget approved by the Executive Committee and contemplated in the Development Plan are the scheduled working plan, as well as the estimated expenses and investments to be made by the Operator in the different aspects of the operation, such as:

11.4.1    Capital investment for production: Reservoir development drilling, reconditioning or workover of wells, and specific production facilities.

11.4.2    General construction and equipment: industrial and camp facilities, transportation and construction equipment, drilling and production equipment. Other construction and equipment.

11.4.3    Maintenance and operating expenses: production, geological, and administrative operating expenses.

11.4.4    Working capital requirements

11.4.5    Contingency funds

11.5    The Operator shall incur all expenses and investments and shall carry out all development and production operations in accordance with the project, programs and the annual budget approved in the Development Plan for each Commercial Field to which Clause 11 (Item 11.1), refers, as per the Operating Agreement (Attachment B) that is an integral part of this Contract, without exceeding the total Budget for each year, except for authorization from the parties in special cases.

11.6    The Operator is fully authorized to make disbursements which are not expressly included in each Commercial Field’s Budget and charge them to the Joint Account without the Executive Committee’s prior authorization, in the event of emergency measures intended to protect the Parties’ personnel or property; emergency expenses caused by fires, floods, storms or other disasters; emergency expenses considered

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essential to the operation and maintenance of production facilities, including all maintenance works for producing wells to work with maximum efficiency; emergency expenses essential to the protection and preservation of materials and equipment required in the operations. In such cases, the Operator must summon, as soon as possible, a special Executive Committee meeting, to obtain its approval of carrying on with the emergency measures.

11.7    The Operator shall be solely responsible for the expenses incurred and the contracts executed by the Operator for amounts above the Annual Budget not timely authorized by the Executive Committee for each Commercial Field, in accordance with Clause 19 (Item 19.3.9) except for the assumptions regulated by Clause 11 (Item 11.6). Therefore, the Operator shall assume the corresponding total value at its sole expense. When the Executive Committee ratifies such expense or contract, the Operator will be reimbursed with the corresponding value, in accordance with the guidelines to be approved by the Executive Committee. In the event that the expenditure or the contract are not approved by the Executive Committee, the Operator, whenever it is possible, will be entitled to withdraw the asset by reimbursing the Parties for any expenditure that its withdrawal may cause. In the event that the Operator cannot withdraw such asset, or if he decides not to do so, the benefit or patrimony increase resulting from such expenditures or contracts will become the property of the Parties in a proportion equal to their share in the operation.

CLAUSE 12 - PRODUCTION

12.1    Subject to the approval of the Executive Committee, the Operator will determine with the necessary frequency, the Maximum Efficiency Rate (MER) for each Commercial Field. This Maximum Efficiency Rate (MER) for each producing well will be the hydrocarbon maximum production rate that can be extracted from a reservoir to obtain the maximum economic benefit in the final recovery of reserves, in accordance with the economic and engineering principles and the practices and procedures generally employed and in use within the international petroleum industry, under conditions and circumstances similar to the activities performed under this contract. The estimated production shall be adjusted as necessary to compensate the actual or anticipated

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operational conditions, such as wells being repaired that are not producing, capacity limitations in collecting lines, pumps, separators, tanks, pipelines, and other facilities.

12.2    The Operator will determine periodically, at least once a year, upon approval of the Executive Committee, the area considered capable of producing hydrocarbons in commercial quantities in each Commercial Field.

12.3    The Operator shall prepare and deliver to each of the Parties, at regular three (3) month intervals, a program indicating each Party’s share of production, and another one indicating the share of production for each Party for the following six (6) months. The production forecast will be based on the Maximum Efficiency Rate (MER) as stipulated in Clause 12 (Item 12.1) and adjusted to the rights of each Party, in accordance with this contract. The production sharing program will be determined based on the periodic request of each Party, and in accordance with Clause 14 (Item 14.2) with the necessary corrections to ensure that none of the Parties, entitled to a share, will receive less than the amount it is entitled to in accordance with the provisions in Clause 14, and without prejudice to the provisions in Clauses 21 (Item 21.2), and 22 (Item 22.5).

12.4    If any of the Parties foresees a reduction in its capacity to lift hydrocarbons with respect to the forecast submitted to the Operator, it must so inform him as soon as possible, and if such reduction is due to an emergency situation, it shall notify the Operator within twelve (12) hours immediately following the event causing the reduction. Consequently, said Party will submit the new lift program taking into account the pertinent reduction.

12.5    The Operator may use the hydrocarbons that are necessary in performance of production operations in the Contracted Area, and such consumption shall be exempt from the royalties mentioned in Clause 13 (number 13.1).

CLAUSE 13. ROYALTIES

13.1    For purposes of paying royalties for the exploitation of State-owned Hydrocarbons, the Operator shall pay ECOPETROL a production percentage as determined by Law, which will be measured in accordance with the oil industry practice and previously accepted by the Ministry of Mines and Energy The delivery of said production shall take place at the same point and in the same moment in which the Parties distribute their production share pursuant to Clause 14 herein. In the case of Fields being exploited

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under the Sole Risk method, THE ASSOCIATE will deliver to ECOPETROL the percentage of production corresponding to royalties at the point agreed by the Parties.

13.2    From the percentage of production delivered to ECOPETROL under the above numbered terms, ECOPETROL, in the manner and under the terms established by Law, shall pay to those agencies established by Law, the royalties caused in favor of the State over the Field’s total production and, in no event, will THE ASSOCIATE be responsible for any payment to such agencies.

CLAUSE 14 - HYDROCARBON DISTRIBUTION AND AVAILABILITY

14.1    The Hydrocarbons produced, excepting those which may have been used in benefit of the operations under this contract, and those which will inevitably be wasted throughout the operation, will be transported to the jointly owned tanks of the Parties or to other measuring facilities agreed by the Parties. Should no agreement be reached, it shall be the metering location nearest to the inspection site determined by the Ministry of Mines and Energy. Hydrocarbons will be measured in compliance with the standards and methods accepted by the petroleum industry and, based on such measurement, the volumes referred to in Clause 13 will be determined. As of that moment, the remaining Hydrocarbons will be the property of each Party, in the proportions specified in this contract.

14.2    Production Distribution

14.2.1 After deducting the percentage that corresponds to royalties, the rest of the hydrocarbons produced from each Commercial Reservoir is the property of the Parties in a proportion of thirty per cent (30%) for ECOPETROL and seventy per cent (70%) for THE ASSOCIATE, until the time in which the audited accumulated production in the respective Commercial Reservoir reaches an amount of five (5) million barrels of standard condition liquid hydrocarbons or seventy-five (75) cubic giga feet of standard condition gaseous hydrocarbons, whatever occurs first. (1 cubic giga feet = 1x10⁹ cubic feet). For Reservoirs exploited under the Sole Risk mechanism, the distribution of the production, after deducting the royalty percentage, is the property of the Parties in a proportion of (100%) for THE ASSOCIATE and zero per cent (0%) for ECOPETROL, until the audited accumulated production from the respective Reservoir first reaches either one of the aforementioned production limits.

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14.2.2 Regardless of the classification of the Commercial Reservoir granted by ECOPETROL upon declaring commerciality, above the limits defined in number 14.2.1 hereunder, the distribution of the production in each Commercial Reservoir (after deducting the percentage that corresponds to royalties) is the property of the Parties in the proportion resulting from applying the Factor R, as explained herein below:

14.2.2.1 If the Hydrocarbon that first reached the limit stated in number 14.2.1 in this Clause was the liquid hydrocarbon, the following table will apply:

R Factor	Production Distribution after Royalties (%)
	THE ASSOCIATE	ECOPETROL
0.0 to 1.0	70	30
1.0 to 2.0	70 / R	100 - (70 / R)
2.0 or more	35	65

14.2.2.2 If the Hydrocarbon that first reached the limit stated in number 14.2.1 in this Clause was the gaseous hydrocarbon, the following table will apply:

R Factor	Production Distribution after Royalties (%)
	THE ASSOCIATE	ECOPETROL
0.0 to 1.5	70	30
1.5 to 2.5	70 / (R - 0.5)	100 -[70 /(R - 0.5)]
2.5 or more	35	65

14.2.3 Regardless of the classification of the Reservoir granted by ECOPETROL when the commerciality is defined, above the limits set in number 14.2.1 hereunder, the production from each Commercial Reservoir exploited under the Sole Risk mechanism, as per Clause 9 (number 9.5), after deducting the percentage that corresponds to royalties, is the property of the Parties in the proportion resulting from applying the R Factor, as explained herein below:

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14.2.3.1 If the Hydrocarbon that first reached the limit stated in number 14.2.1 in this Clause was the liquid hydrocarbon, the following table will apply:

R Factor	Production Distribution after Royalties (%)
	THE ASSOCIATE	ECOPETROL
0.0 to 1.5	100	0
1.5 to 2.5	197.5 - (65R)	100 - [197.5 - (65R)]
2.5 or over	35	65

14.2.3.2 If the Hydrocarbon that first reached the limit stated in number 14.2.1 in this Clause was the gaseous hydrocarbon, the following table will apply

R Factor	Production Distribution after Royalties (%)
	THE ASSOCIATE	ECOPETROL
0.0 to 2.0	100	0
2.0 to 3.0	230 - (65R)	100 - [230 - (65R)]
3.0 or over	35	65

14.2.4 For purposes of the above tables, R Factor shall be defined as the relation of accumulated income expressed in constant terms, over accumulated expenses, also expressed in constant terms, which correspond to THE ASSOCIATE for every Commercial Field in the following terms:

R =	IA
	ID + A - B + GO

For calculating accumulated Income and Expenses per reservoir, the PARTIES shall agree the procedure to follow in accordance with the Petroleum Industry techniques. Where:

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IA (THE ASSOCIATE’s ACCUMULATED INCOME): This is the valuation of the accumulated income corresponding to THE ASSOCIATE’s Hydrocarbons produced after royalties, at the reference price agreed between the Parties except for Hydrocarbons reinjected in the Fields of the Contracted Area, those consumed in the operation, and the burned gas.

Hydrocarbons average price will be mutually agreed between the Parties.

Monthly income will be the basis to determine the accumulated income that will be determined as the result of multiplying the average monthly reference price for the monthly production, in accordance with the forms that have been issued by the Ministry of Mines and Energy for such purpose.

ID (Accumulated Development Investments): Seventy percent (70%) of the accumulated Development Investments approved by the Association’s Executive Committee for each Commercial Field.

A: These are the Exploration Direct Costs incurred by THE ASSOCIATE, in accordance with Clause 9 of this contract and adjusted in accordance to Clause 9 (Item 9.2.2), Paragraph.

B: This is the accumulated reimbursement of the aforementioned exploration direct costs, according to Clause 9 of this contract.

GO (Accumulated Operation Expenses): These are the accumulated operation expenses approved by the Association’s Executive Committee, in the proportion that corresponds to THE ASSOCIATE, plus THE ASSOCIATE’s accumulated transportation expenses. It is understood as transportation costs the investment and operation costs of Hydrocarbons produced in the Commercial Fields located in the Contracted Area, from the Contracted Area to the exportation port or the place that has been agreed to use the IA income calculation. The Parties will agree such transportation costs by mutual consent upon commencement of the development phase of the Reservoirs, whose commerciality has been accepted by ECOPETROL.

Special contributions or the like that can be applied over Hydrocarbons production in the Contracted Area are included in the operation’s expenses.

All values included in the equation to determine R Factor will be taken in constant terms and to such effect they will be updated monthly with the average consumer index prices

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in industrialized countries as of its execution date to the last day of the month to which the R Factor is being applied. For the monthly update, 1/12 of the value resulting of averaging the annual percentage variation during the last two years of the consumer index prices in industrialized countries will be used, taken from “International Financial Statistics” of the International Money Market Fund (page S63 or its substitute), or in absence thereof, the publication agreed by the Parties.

To such effect, expenses in Colombian currency must be exchanged to U.S. dollars at the representative rate in the market, duly approved by the Banking Superintendence, or its substitute, that is in force on the date that the respective reimbursements are made.

Paragraph:    For Fields exploited under the Sole Risk method, according to Clause 9 (Item 9.5) of this contract, for purposes of applying the equation to calculate factor R, the following will be considered:

The ID corresponds to 100% of the accumulated development investment made by THE ASSOCIATE.

The value of the accumulated Reimbursement of the Exploration Direct costs (B) will equal zero (0).

The GO refers to accumulated operation expenses incurred by THE ASSOCIATE, including the transport costs incurred by THE ASSOCIATE for the transport of Hydrocarbons produced in the Field to the export port or the place where it is agreed to take the price to be used in calculating the IA income.

Calculation of R Factor : The distribution of production based on R Factor will start being applied as of the first day in the third calendar month following that in which the accumulated production of the respective Commercial Reservoir reached (5) million barrels of liquid hydrocarbon or an amount of seventy-five (75) cubic giga feet gaseous hydrocarbon, at standard conditions, as per above number 14.2.1.

The calculation of the R Factor in the respective Commercial Reservoir shall be based on the accounting close corresponding to the calendar month in which the audited accumulated production of five (5) million barrels of liquid hydrocarbon or the amount of seventy five cubic giga feet, at standard conditions, as per above number 14.2.1.

Resulting production distribution will be applied until June 30^th of the next year. From that moment on, production distribution to which R Factor has been applied will be made for one-year terms (from July 1^st to June 30^th) over R factor’s liquidation based on the

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accumulated values as of December 31^st of the previous year, in accordance with the corresponding accounting closing term.

Provisions contained herein also apply for the Fields developed under the Sole Risk method.

14.3    In addition to the tanks and other jointly-owned facilities, each Party will be entitled to build its own production facilities in the Contracted Area for its own and exclusive use, previous fulfilling of legal regulations. Transportation and delivery of Hydrocarbons by each Party to the pipeline and other receivers different from the jointly owned ones will be made on the sole account and risk of the Party receiving the Hydrocarbons.

14.4    In case that production is obtained in places not connected to pipelines, the Parties will be able to agree the installation of pipelines up to a hydrocarbon point of sale, or to a location connected to the pipeline. If the Parties agree to the construction of such pipelines, they shall enter into the contracts they deem appropriate to this end, and shall designate the Operator in keeping with the legal provisions in force.

14.5    Each Party will be the owner of the Hydrocarbons that have been yielded and stored as a result of the Operation and that have been made available to it, as provided for herein, and, at its expense, it should receive them in kind, sell them, or dispose of them separately, pursuant to Clause 14 (Item 14.3).

14.6    If any of the Parties, for any reason, cannot dispose of separately or withdraw from the Joint Account’s tanks, partially or totally, its share of the Hydrocarbons, the following procedure will apply, pursuant to this Contract:

14.6.1 1 If ECOPETROL is the party that cannot withdraw, partially or totally, its Hydrocarbon share (share plus royalties), according to Clause 12 (Item 12.3), the Operator will be able to go ahead with the Field’s production and deliver to THE ASSOCIATE in addition to the portion represented by THE ASSOCIATE’s share in the operation, based on one hundred percent (100%) of the MER, all those Hydrocarbons that THE ASSOCIATE opts for and is capable of withdrawing up to a limit of one hundred per cent (100%) of the Maximum Efficiency Rate and crediting ECOPETROL, for further delivery, the amount of Hydrocarbons that ECOPETROL was entitled to withdraw but did not. However, with regard to the amount of not-withdrawn Hydrocarbons corresponding to ECOPETROL’s monthly royalties, the ASSOCIATE,

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upon request from ECOPETROL, shall pay to ECOPETROL, in U.S. Dollars, the difference between the volume of Hydrocarbons it is entitled to on account of royalties, to which Clause 13 refers to and the amount of Hydrocarbons that, on account of royalties, ECOPETROL has withdrawn, it being understood that any withdrawal made by ECOPETROL shall apply, in the first place, to the payment of the royalties in kind and, when it has been canceled, the additional Hydrocarbon withdrawals will be applied to its corresponding share, according to Clause 14 (Item 14.2).

14.6.2. In the event that THE ASSOCIATE is the Party which cannot take all or part of its share designated under Clause 12 (Item 12.3), the Operator shall deliver to ECOPETROL, on the basis of one hundred percent (100%) of the MER, not only its own share and quota, but also all the hydrocarbons that ECOPETROL is capable of taking up to a limit of one hundred percent (100%) of the MER, crediting THE ASSOCIATE for later delivery, with the portion that corresponds to its quota and that it has not been able to take.

14.7    When both Parties are able to take the hydrocarbons designated as per Clause 12 (Item 12.3), the Operator will deliver to the Party that has previously been unable to take its share of the production, and upon its request, and in addition to its participation in the operation, a minimum of ten percent (10%) per month of the production belonging to the other Party, and by mutual agreement, until one hundred percent (100%) of the quota not taken, up to the point in which the total amount that had been credited to the Party that was unable to take its hydrocarbon share has been canceled.

14.8    Without prejudice of legal regulations on the subject, each Party shall be free, at any time, to sell or export its share of the hydrocarbons obtained, according to this contract, or dispose of same in any manner.

CLAUSE 15 - UTILIZATION OF ASSOCIATED NATURAL GAS

In the event that one or more Associated Natural Gas Fields are discovered, the Operator within the three (3) years following the date of commencement of Field exploitation as defined by the Ministry of Mines and Energy, shall submit a project for utilization of Natural Gas for the benefit of the Joint Operation. The Executive Committee will decide on the project, and if that is the case, it shall determine the timing for execution of same. If the Operator does not submit any project within the three (3) years

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or does not perform the project approved in the terms determined by the Executive Committee, ECOPETROL may take, gratuitously, all the Associated Natural Gas available from the Reservoirs being developed, as long as it is not required for the efficient development of the field.

CLAUSE 16 - UNIFICATION

When an economically exploitable field extends continuously into another area or areas out of the Contracted Area, the Operator, in agreement with the Parties, and other interested Parties, subject to prior approval of the Ministry of Mines and Energy, shall formulate a unified exploitation plan, which must conform to the engineering techniques for hydrocarbon exploitation, applying without limitation thereto, any of the following methods:

· Definition among the Parties of a basic production curve for the affected CPR Santana commercial field and, in the event of the production decreasing below this curve, it shall be replaced with production from the new prospect.

· Distribution of production in proportion to the reservoir yield corresponding to the area on surface of each field.

CLAUSE 17 - INFORMATION SUPPLY AND INSPECTION DURING EXPLOITATION

17.1    The Operator shall deliver to the Parties, as they are obtained, reproducible originals (sepias) and copies of the drilled wells’ electric, radioactive, and sonic logs, history, core analyses, cores, production tests, reservoir studies, and other relevant technical data, as well as routine data produced or received in relation with the operations and activities performed in the Contracted Area.

17.2    Each of the Parties, at its own risk and expense, shall be entitled, through authorized representatives, to inspect the wells and facilities in the Contracted Area, as well as all the activities related thereto. Such representatives shall have the right to examine cores, samples, maps, records of drilled wells, surveys, books, and any other source of information related to performance of this contract.

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17.3    In order for ECOPETROL to comply with the provisions of Clause 29, the Operator shall prepare and deliver to ECOPETROL all the reports required by the National Government.

17.4    All information and data related to exploitation works must be held as confidential pursuant to the same conditions of Clause 6 (Item 6.3) of this contract.

CHAPTER IV - EXECUTIVE COMMITTEE

CLAUSE 18. CONSTITUTION

18.1    Within the first thirty (30) calendar days following the acceptance of the first Commercial Field, each Party must appoint a representative and its respective first and second alternates, to form the Executive Committee and shall notify the other Party in writing the names and addresses of its representative and alternates. The Parties may change their representative or alternates at any time, but must so advise the other Party in writing. The vote or decision of each Party representative is binding on said Party. Should the main representative of one of the Parties not be able to attend a Committee meeting, his first or second alternates, in order, may attend and will have the same authority as the principal.

18.2    The Executive Committee shall hold ordinary meetings in the months of March, July, and November, at which the Operator’s development program, development plan, and immediate plans will be reviewed. Annually, in the ordinary meeting held in July, the Operator shall submit to the Executive Committee for its approval, the annual operations program and the expense and investment Budget for each Commercial Field for the next calendar year, and if such is the case, the reviewed Development Plan.

18.3    The Parties and the Operator may request special meetings of the Executive Committee, to analyze specific operating conditions. The representative of the interested Party shall notify ten (10) calendar days in advance about the date of the meeting and the topics that will be dealt in them. Any matter not included in the meeting agenda may be dealt during such meeting, after acceptance by the representatives of the Parties in the Committee.

18.4    The representative of each of the Parties will have a right to vote equivalent to the percentage of his total interest in the Joint Operation when discussing all matters

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discussed in the Executive Committee. However, Executive Committee’s decisions related to items contained in clauses 19.3.4 to 19.3.9 herein, will be adopted by unanimous vote of the Parties.

All Executive Committee’s decisions, in accordance with the aforementioned procedure, will be mandatory and final for the Parties and for the Operator.

CLAUSE 19 - FUNCTIONS

19.1    The representatives of the Parties will form the Executive Committee, having full authority and responsibility to set and adopt exploitation, development, operations and budgets related to this contract. One representative of the Operator will attend the meetings of the Executive Committee.

19.2    The Executive Committee will appoint a Secretary for every session. This Secretary will draft the corresponding Minutes containing a summary of all the discussions and determinations adopted by the Committee. The Minutes must be approved and signed by the representatives of the Parties within ten (10) working days following the closing of the meeting and delivered to them as soon as possible.

19.3    The functions of the Executive Committee are, among others, the following:

19.3.1 Adopt its own regulations.

19.3.2 Decide about the matters submitted by the Operator for its consideration.

19.3.3 Supervise the operation of the Joint Account and the Joint Operation.

19.3.4 Create the subcommittees deemed necessary and assign their functions under its direction.

19.3.5 Appoint the Operator in case of resignation or removal, and write the regulations to be followed by the Operator, when it is a third party other than the Parties, indicating in detail the reasons for his removal.

19.3.6 Appoint the external auditor of the Joint Account.

19.3.7 Approve or reject development plans, and any subsequent change or revision.

19.3.8 Determine the expense regulations and policies.

19.3.9 Approve or reject projects, programs and annual Budgets of each Commercial Field and authorize extra expenses that have not been included in the approved Budgets.

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19.3.10 In general, perform all the functions authorized by this contract and not corresponding to the Operator or another entity or individual, based on an express clause or by legal or regulatory provision.

19.3.11 Determine the economic limits of the new Reservoirs discovered.

CLAUSE 20 - DECISION IN CASE OF DISAGREEMENT IN OPERATION

20.1.    Any disagreement that cannot be resolved in the Executive Committee will be directly submitted to the highest executive of each of the Parties who resides in Colombia, so as to take a joint decision. If in the sixty (60) calendar days following the submission of the consultation, the parties agree on a decision in regards to the matter in question, they will so inform the Operator, who should call for an extraordinary meeting of the Executive Committee, within the fifteen (15) calendar days following the receipt of the communication, where the agreement or decision will be approved.

20.2    If within sixty (60) calendar days following the date of consultation to the highest executive of each of the Parties who resides in Colombia, an agreement is not reached, the procedure will be as provided for in Clause 28 of this contract, except for differences related to the operations, in which case they could be executed in accordance with Clause 21.

CLAUSE 21. OPERATIONS AT THE RISK OF ONE OF THE PARTIES

21.1    If at any time one of the Parties wishes to drill a Development Well not approved in the operating program, it shall notify the other Party in writing, at least thirty (30) calendar days prior to the following meeting of the Executive Committee, of its desire to drill such well and include information, such as location, drilling recommendation, depth and estimated costs. The Operator shall include this proposal among the items to be discussed at the following Executive Committee meeting. Should the proposal be approved by the Executive Committee, said well will be drilled with charge to the Joint Account. Should the proposal not be accepted by the Executive Committee, the Party wishing to drill such well, hereinafter the “Participating Party”, shall have the right to drill,

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complete, produce, or abandon such well at its own risk and expense. The Party not wishing to participate in the above-mentioned operation shall be known as the “Non Participating Party”. The Participating Party must commence drilling of the well within one hundred eighty (180) days following the refusal of the Executive Committee. Should drilling not be commenced within this period, it must be submitted to the Executive Committee’s consideration once again. At the request of the Participating Party, the Operator shall drill the aforementioned well at the risk and expense of the Participating Party, provided that in the Operator’s opinion, such operation does not interfere with the normal operation of the Field, whereby the Participating Party shall have advanced to the Operator the amount that the Operator deems necessary to drill the well. In the event that such well cannot be drilled by the Operator without interfering with the normal operation of the field, the Participating Party shall have the right to drill such well by itself, or through a service company that is competent and, in such event, the Participating Party shall be responsible for such operation, without interfering with the normal development of field operations.

21.2    Should the well referred to in Clause 21 (Item 21.1), be completed as producer, it shall be administered by the Operator and the production from such well, after deducting the royalties referred to in Clause 13, shall be the property of the Participating Party, which will bear all costs of operating such well until the net value of production, after deducting production, collection, storage, transport and other similar costs, as well as the cost of sale, equal to two hundred percent (200%) of the costs of drilling and completing such well. As of that moment, and for the purposes of this contract, such well shall become the property of the Joint Account holders, in the proportion established, as though it had been drilled with the approval of the Executive Committee at the Parties’ risk and expense. To this effect, the investments made and costs incurred in the development of this well shall be part of the R Factor of the Commercial Field. For purposes of this clause, the value of each barrel of Hydrocarbon produced from such well, during a calendar month, before deducting the aforementioned costs, shall be the reference price agreed on by the Parties.

21.3    If at any time, one of the Parties wishes to workover, deepen to reach the production targets, or plug a well that is not producing commercial quantities, or if that is a dry hole that was drilled by the Joint Account, and if such operations have not been

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included in a program approved by the Executive Committee, such Party must notify the other Party of its intention to workover, deepen, or plug such well. Should there be no equipment on site, the procedure described in Clause 21 (Items 21.1 and 21.2) shall be followed. Should there be adequate equipment to conduct the proposed operations at the wellsite, the Party receiving the notice of the operations that the other Party wishes to conduct, shall have forty-eight (48) hours, as of the time it received the notice, within which to approve or disapprove the operation and, if during this term no reply is received, it is understood that the operation will be carried out at the risk and expense of the Joint Account. Should the proposed work be carried out at the sole risk and expense of a Participating Party, the well shall be managed subject to Clause 21 (Item 21.2).

21.4    If at any time, one of the Parties wishes to build new facilities for the extraction of gaseous Hydrocarbon liquids and for the transport and export of the Hydrocarbons produced, hereinafter additional facilities, said Party shall notify the other Party in writing and provide the following information:

21.4.1 General description, design, specifications, and estimated costs of the additional facilities.

21.4.2 Projected capacity

21.4.3 Approximate date of commencement of the construction and duration thereof. Within ninety (90) days starting on the date of notification, the other Party shall have the right to decide whether it intends to participate in the projected additional facilities, by giving written notice. In the event that such Party should elect to not participate in the additional facilities, or does not reply to the Participating Party’s proposal, hereinafter “the Constructing Party”, the latter may proceed with the additional facilities and will instruct the Operator to build, operate, and maintain such facilities at the exclusive risk and expense of the Constructing Party, without prejudice to the normal development of the Joint Operation. The Constructing Party may negotiate the use of such facilities for the Joint Operations, with the other Party. During the time the facilities are operated at the risk and expense of the Constructing Party, the Operator shall charge such Party for all operating and maintenance costs of the additional facilities, in accordance with generally accepted accounting practices.

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CHAPTER V - JOINT ACCOUNT

CLAUSE 22. MANAGEMENT

22.1    Without prejudice to the provisions of other clauses in this contract, the expenses attributable to exploration works will be at the risk and expense of THE ASSOCIATE.

22.2    From the moment ECOPETROL accepts the existence of a Commercial Field and subject to the provisions of Clause 5 (Item 5.2) and of Clause 13 (Items 13.1 and 13.2), the ownership of the rights or interests in the Contracted Area shall be divided as follows: ECOPETROL, thirty percent (30%), THE ASSOCIATE, seventy percent (70%). From that point on, all the expenses, payments, investments, costs, and obligations performed and assumed for development of the Joint Operation, in compliance with this contract, shall be charged to the Joint Account and the Exploration Direct Costs incurred by THE ASSOCIATE before and after acceptance of the existence of each Commercial Field and its extensions, in compliance with Clause 9 (Item 9.8), shall be entered into the Joint Account. Except as provided for in Clauses 14 (Item 14.3) and 21, all the property acquired or used from that moment on for the fulfillment of operating activities of the Commercial Field, shall be paid for and belong to the Parties, in the same proportions described in this clause.

22.3    Within the first five (5) days of each month, the Parties shall tender to the Operator in the Joint Account’s banking account their corresponding share of each Commercial field Budget, as needed and in the same currency in which the expenses must be made, that is, in Colombian pesos, or in USA dollars, as requested by the Operator, in accordance with the programs and budgets approved by the Executive Committee. When THE ASSOCIATE does not have the necessary pesos to cover its portion of this currency, ECOPETROL shall have the right to furnish such pesos and be credited for the contribution that is to be made in dollars, converted at the official rate for purchase of exchange certified by the Banking Superintendence, or the official agency in charge, on the day in which ECOPETROL should make the corresponding contribution, provided such transaction does not violate any legal provision.

22.4    The Operator shall submit to the Parties, within the ten (10) calendar days following the end of each month, a monthly statement showing the anticipated amounts, the expenses made, the outstanding obligations, and a report of all charges and credits to

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the Joint Account. Such report shall be prepared in compliance with Attachment B and in a separate attachment, the parameters and R Factor calculation referred to in Clause 14 (Items 14.2.4 and 14.2.5). If the payments referred to in Clause 22 (Item 22.3) are not made within the agreed term and the Operator decides to make them, the delinquent Party shall pay the commercial interest, in the same currency during the delinquency period.

22.5    Should one of the Parties fail to pay to the Joint Account the corresponding amounts on time, from that date on said Party shall be considered a Delinquent Party and the other Party the Performing Party. If the Performing Party should make the payment belonging to the Delinquent Party, in addition to its own, said party shall have the right, after sixty (60) calendar days of delinquency, to have the Operator deliver to it the total of the Delinquent Party’s participation in the Contracted Area (excluding the percentage corresponding to royalties), up to a production amount such that permits the Performing Party a net income from the sales made equal to the amount the Delinquent Party failed to pay, plus an annual interest equal to the Commercial Interest for Payment in Arrears on the initial date of the delinquency. “Net income” is understood as the difference between the sale price of the Hydrocarbons taken by the Performing Party, less the cost of transport, storage, loading and other reasonable expenses incurred by the Performing Party from the sale of the products taken. The right of the Performing Party may be exercised at any time thirty (30) calendar days after written notification to the Delinquent Party of its intention to take part or all of the production corresponding to the Delinquent Party.

22.6    Direct and Indirect costs

22.6.1 All Direct Costs of the Joint Operation shall be charged to the Parties in the same proportion that the production is allocated after royalties.

22.6.2 Indirect Costs shall be charged to the Parties in the same proportion that has been established for Direct Costs in Item 22.6.1 of this Clause. The amount of such costs shall be the result of taking the total annual investment value and direct expenses (excepting technical and administrative support) and applying the equation “a + m (X-b)” In such equation, “X” is the total value for investments and annual expenses and “a”, “m”, and “b” are constants whose values are indicated in the following table in relation with the amount of investment and annual expenses:

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INVESTMENT AND EXPENSES			VALUE OF THE CONSTANTS
“X” (US$)			“a” (US$)	m (fracc.)	“b” (US$)
1.	0	to   25,000,000	0	0.10	0
2.	25,000,001	to   50,000,000	2,500,000	0.08	25,000,000
3.	50,000,001	to 100,000,000	4,500,000	0.07	50,000,000
4.	100,000,001	to 200,000,000	8,000,000	0.06	100,000,000
5.	200,000,001	to 300,000,000	14,000,000	0.04	200,000,000
6.	300,000,001	to 400,000,000	18,000,000	0.02	300,000,000
7.	400,000,001	and over	20,000,000	0.01	400,000,000

The equation will be applied once a year in each case with the value of the constants corresponding to the total value of annual investment and expenses.

22.7    The monthly statements referred to in Clause 22 (Item 22.4) may be reviewed or objected to by either of the Parties from the moment they receive them, up to two (2) years after the end of the calendar year to which they pertain, specifying clearly the entries corrected or objected to and the reason therefor. Any account that has not been corrected or objected to within such period shall be considered final and correct.

22.8    The Operator shall keep accounting records, vouchers and reports for the Joint Account in Colombian pesos in accordance with Colombian law, and all charges and credits to the Joint Account shall be made following the accounting procedure described in Attachment B, which is part of this contract. In the event of discrepancy between such Accounting Procedure and the provisions of this contract, the provisions of the latter shall prevail.

22.9    The Operator may perform sales of materials or equipment during the first twenty (20) years of the Exploitation Period, or the first twenty-eight (28) years of the Exploitation Period, in the case of a Gas Field, for the benefit of the Joint Account, when the value of the sold items does not exceed five thousand USA dollars (US$5,000) or its equivalent in Colombian pesos. This type of operation, per calendar year, may not exceed fifty thousand USA dollars (US$50,000) or its equivalent in Colombian pesos. The sales exceeding these amounts or those of real estate property are subject to the

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Executive Committee’s approval. The sale of such materials or equipment will be made at a reasonable commercial price in accordance with the conditions of use of the item.

22.10    All the machinery, equipment, or other goods or property acquired by the Operator for the execution of this contract and charged to the Joint Account, will be the property of the Parties in equal shares, in the same proportion of their share in the operation. However, in the event that one of the Parties should decide to terminate its interest in the contract before the end of the first seventeen (17) years of the Exploitation Period, except as foreseen in Clause 25, said Party agrees to sell to the other Party, either its interest in said assets, at a reasonable commercial price or their book value, whichever is lower. In the event that the other Party does not wish to buy such assets within ninety (90) days following the formal offer to sell, the Party wishing to withdraw shall have the right to assign to a third party the interest corresponding it in such machinery, equipment and items. If THE ASSOCIATE decides to withdraw after seventeen (17) years of the Exploitation Period, its right in the Joint Operations will pass free of charge to ECOPETROL upon its acceptance.

CHAPTER VI - DURATION OF THE CONTRACT

CLAUSE 23 - MAXIMUM TERM

This contract shall have a maximum term, as of its Effective Date, of twenty-seven and a half (27.5) years, distributed as follows: up to five and a half (5.5) years as the Exploration Period, pursuant to Clause 5 without prejudice of that stipulated in Clause 5 (number 5.4) and Clause 9 (number 9.3); and up to twenty-two (22) years as the Development Period, as of the date of expiration of the Exploration Period. Nevertheless, the Development Period will end before the 22 years if the new Commercial Fields discovered reach their economic limit, as decided by the Executive Committee, pursuant to number 19.3.11. of Clause 19 in this contract. It is understood that the events contemplated hereunder, in which the Exploration Period is extended, shall not extend the total twenty-seven and a half (27.5) year total term.

Paragraph 1: The Exploitation Period for the Gas Fields discovered within the Contracted Area shall have a maximum duration of thirty (30) years as of the date of expiration of the Exploration Period or Retention Period granted. Nevertheless, the

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Development Period will end before the 30 years if the new Commercial Reservoir discovered reaches its economic limit, as decided by the Executive Committee, pursuant to number 19.3.11 in Clause 19 hereunder. Anyhow, the total contract term for such Reservoirs shall not exceed thirty-nine and a half (39.5) years, as of the Effective Date.

Paragraph 2: Notwithstanding the above, ECOPETROL and THE ASSOCIATE, with no less than five (5) years in advance of the expiration date of the Development Period of each Reservoir, if the economic limit of the new field discovered has not been reached before the end of the 22 years, or 30 years when dealing with Gas fields, will undertake the study of conditions to continue exploitation thereof after the expiration mentioned in this Clause. Should the Parties agree to pursue such development, they shall define the terms and conditions for performance thereof.

CLAUSE 24 - TERMINATION

This contract shall terminate in each of the following cases on which THE ASSOCIATE’s rights contained within this contract shall cease, either in its capacity as ASSOCIATE or as Operator, provided both mentioned capacities concur at the termination time:

24.1    Upon expiration of the Exploration Period if THE ASSOCIATE has not discovered a Commercial Field, except as provided in Clauses 5 (Item 5.4), 9 (Item 9.5), and 34.

24.2    When the contract term established in Clause 23 expires.

24.3    At any time and at THE ASSOCIATE’s will, after having complied with its obligations referred to in Clause 5, and the other obligations acquired in compliance with this contract up to the date of termination.

24.4    Should THE ASSOCIATE assign this contract, in whole or in part, without complying with the provisions in Clause 27.

24.5    Due to breach of the obligations assumed by THE ASSOCIATE in accordance with this contract.

24.5.1 ECOPETROL shall not be able to terminate this contract until sixty (60) calendar days after having notified THE ASSOCIATE or its assignees in writing, clearly specifying the causes for making such a declaration and only if the other Party has not submitted explanations that are satisfactory to ECOPETROL, or if THE ASSOCIATE has not corrected the fault in complying with the contract, without prejudice to THE ASSOCIATE’s right to file the legal actions it deems convenient.

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24.5.2 If, within the period mentioned above, THE ASSOCIATE submits explanations that are satisfactory to ECOPETROL and in the remaining term for completing the period of sixty (60) days it is insufficient to meet the obligations pending according to good petroleum industry practice, the Parties may agree to an additional term to allow said compliance, without prejudice to ECOPETROL’s right to demand the guarantees necessary for backing it. If, after this time has elapsed, all of the works agreed to have still not been performed, ECOPETROL shall terminate the contract.

24.6    At any time upon mutual agreement between the Parties.

24.7    Due to the unilateral termination causes contemplated in Clause 25.

Paragraph: Upon termination of the contract for any of the reasons mentioned in this clause, except for number 24.5, the Contract areas shall be under the application of the CPR Santana.

CLAUSE 25 - CAUSES OF UNILATERAL TERMINATION

25.1    Unilaterally, ECOPETROL may terminate this contract at any time before the period agreed in Clause 23 expires, in the following cases:

25.1.1 Death or permanent physical disability or legal interdiction of THE ASSOCIATE in the case of an individual.

25.1.2 Due to initiation of a wind-up process of THE ASSOCIATE, if it is a company.

25.1.3 Due to legal embargo of THE ASSOCIATE that seriously affects contract performance.

25.1.4 When THE ASSOCIATE is made up of several companies and/or individuals, the reasons given in items 25.1.1 and 25.1.2 shall be applied when they seriously affect contract performance.

25.2    In the event of a declaration of unilateral termination, the rights of THE ASSOCIATE stated in this contract shall cease, not only as an ASSOCIATE, but also as Operator, if at the moment of the declaration of unilateral termination, THE ASSOCIATE acts in both capacities.

Paragraph: Upon termination of the Contract, for any of the reasons mentioned in this clause, ECOPETROL shall have the right to carry out the exploration and production activities, whether directly or with a third party other than THE ASSOCIATE, in order to make the Guayuyaco prospect viable.

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CLAUSE 26 - OBLIGATIONS IN CASE OF TERMINATION

26.1    If the contract is terminated as per the provisions in Clause 24, during its Exploration, Retention, or Exploitation Period, THE ASSOCIATE shall leave in production those wells which on that date are producing and shall deliver the facilities, pipelines, transfer lines and other real estate property belonging to the Joint Account (located in the Contracted Area), all of which shall pass, free of charge, to ECOPETROL’s ownership, together with the rights of way and assets acquired exclusively for the benefit of the contract, regardless of whether or not these assets are located outside the Contracted Area.

26.2    If the contract is terminated for any reason after the first seventeen (17) years of its Exploitation Period, all of THE ASSOCIATE’s machinery, equipment or other assets or items used or acquired by THE ASSOCIATE or by the Operator in performance of this contract shall pass, free of charge, to ECOPETROL.

26.3    If the contract is terminated before the end of the seventeen (17) year Exploitation Period, the provisions of Clause 22 (Item 22.10) shall apply.

26.4    If the contract is terminated through a declaration of unilateral termination issued at any time, all current assets and fixed assets acquired for the exclusive benefit of the Joint Account, shall pass, free of charge, to ECOPETROL’s ownership.

26.5    If the contract is terminated for any reason and at any time, ECOPETROL will be the sole owner of all Environmental Impact Studies, Environmental Management Plans, Environmental Diagnoses, and any other document, study and/or social nature study and/or environmental study prepared in performance of the contract. As of that moment, it is understood that THE ASSOCIATE transfers at once all the intellectual property rights, or those of any other nature, to ECOPETROL on the aforementioned documents, without requiring any additional process. Without prejudice of the foregoing, THE ASSOCIATE commits to undertake any action that, from an operational or juridical standpoint, would be required to fully consolidate those rights in ECOPETROL. Anyhow, THE ASSOCIATE shall continue to be responsible to fulfill any obligation derived form the Environmental License, until the ownership title of same has been changed by the Ministry of the Environment.

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26.6    Once this contract is terminated for any reason and at any time, the Parties are committed to fulfill satisfactorily their legal obligations, both mutually and before third parties, as well as those acquired hereunder.

CHAPTER VII - MISCELLANEOUS PROVISIONS

CLAUSE 27 - ASSIGNMENT RIGHTS

27.1    Upon prior written authorization from ECOPETROL,THE ASSOCIATE is entitled to assign or transfer, either partially or totally, its interests, rights and obligations in this contract to another individual, company or group that has the economic capacity, the technical competence, the professional skills necessary, and the legal capacity to operate in Colombia.

For such purpose, THE ASSOCIATE shall submit a written request to ECOPETROL, indicating the main elements of the negotiation, such as the name of the possible assignee, information on its legal, financial, technical, and operational capacities, value of the rights and obligations to be assigned, scope of the operation, etc. Within sixty (60) workdays following receipt of the complete request, ECOPETROL shall exercise the discretional faculty of analyzing the information furnished by THE ASSOCIATE, after which it shall make its decision, without the obligation of expressing its reasons for it.

Should THE ASSOCIATE, or any of its individual members be subjected to a merger, take-over, split or corporate transformation process of a different nature, it shall not require prior authorization from ECOPETROL. In any event, ECOPETROL reserves the right to assess the new conditions of THE ASSOCIATE, or of any of its members, regarding their economic capacity, technical competence, professional skills required, and the legal capacity to operate, and if deemed necessary, it shall apply the provisions in Clause 39.

The actions taken to develop this clause that might be taxable, according to the Colombian tax legislation, shall cause payment of the corresponding taxes.

Paragraph 1: If as the result of any partial or total assignment of interests, rights and obligations in this contract, THE ASSOCIATE is different than THE ASSOCIATE of the CPR Santana, THE ASSOCIATE is thus committed to agree with THE ASSOCIATE of the CPR Santana on a plan and program for the performance of exploration and/or

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development activities on the surface of the Contracted Area, to allow for the regular performance of their operations, without any mutual interference.

CLAUSE 28 - DISAGREEMENTS

28.1    In any case where a discrepancy or contradiction arises in the interpretation of the clauses of this Contract relative to the contents in Attachment B called “Operation Agreement”, or in Attachment “C” called “Guidelines for the Preparation of the Development Plan”, the stipulations of the former shall prevail. Likewise, should a conflict arise between the terms of Attachment B and Attachment C, the terms of the former shall prevail.

28.2    Disagreements between the Parties as to legal matters related to the interpretation and performance of the contract, which cannot be resolved amicably, shall be submitted for examination and determination by the proper Colombian legal public authority.

28.3    Any factual or technical difference between the Parties, related to the interpretation and application of this contract, which cannot be resolved amicably, shall be submitted to the final decision of experts in the following manner: each Party shall appoint an expert representative, one for each Party, and a third one mutually agreed by the main experts appointed. If they cannot agree as to the naming of the third expert, the Board of Directors of the “Colombian Association of Engineers—SCI,” with headquarters in Bogota, will choose the third candidate, upon the request by either Party.

28.4    Any difference concerning the accounting which may arise between the Parties by reason of the interpretation and performance of this contract, which cannot be resolved amicably, shall be submitted to a decision taken by experts. Such experts shall be sworn Certified Public Accountants, and shall be appointed as follows: one by each of the Parties and a third one mutually agreed by the two main experts. Upon failure of the former two to reach an agreement and, at the request of either of the Parties, said third expert shall be appointed by the Central Board of Accountants (Junta Central de Contadores) in Bogota.

28.5    Both parties accept that the decision of the experts shall have the same effect as a transaction between themselves and, consequently, said decision shall be binding.

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28.6    In the event of a disagreement between the Parties concerning the technical, accounting or legal aspects of the controversy, said disagreement shall be considered legal and Clause 28 (Item 28.2) shall apply.

CLAUSE 29. LEGAL REPRESENTATION

Without prejudice to the rights that THE ASSOCIATE may legally have, as a consequence of legal regulations or pursuant to the provisions of this contract, ECOPETROL shall represent the Parties before the Colombian authorities with respect to the exploitation of the Contracted Area as required, and it shall submit to governmental officials and entities all the data and information which may be legally required. The Operator shall be obliged to prepare and furnish ECOPETROL with the pertinent information. Any expense that ECOPETROL may incur pursuant to any matter referred to herein, shall be at the expense of the Joint Account, and when such expenses exceed five thousand USA dollars (US$5,000) or its equivalent in Colombian pesos, THE ASSOCIATE or Operator prior approval shall be required. The Parties declare that, insofar as any relationship with third Parties is concerned, neither the conditions of this clause nor of any other clause hereunder, shall imply the granting of a General Power of Attorney, or that the Parties have established a joint civil or commercial venture or other relationship under which any of the Parties may be considered jointly and severally responsible for the other Party’s acts or omissions, or to have the power or mandate which could commit the other Party with regard to any obligation whatsoever. This contract refers to operations within the territory of the Republic of Colombia, and even though ECOPETROL is a Colombian State-owned industrial and commercial company, the parties agree that THE ASSOCIATE, if necessary, may elect to be excluded from the application of all the provisions in Subchapter K, entitled PARTNERS AND PARTNERSHIPS of the Internal Revenue Code of the United States of America. THE ASSOCIATE shall make this election on its behalf in a proper manner.

CLAUSE 30. RESPONSIBILITIES

30.1    The responsibilities acquired by ECOPETROL and THE ASSOCIATE in connection with this contract before third parties shall not be joint liabilities and, therefore, each

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Party shall be solely responsible for its share of the expenses, investment, and obligations derived from such responsibilities.

30.2    Environmental Management: THE ASSOCIATE or the Operator, in performance of all contract activities, must timely comply with that set forth in the National Code of Renewable Natural Resources and Protection of the Environment and other legal provisions on the subject. Likewise, they shall promote amongst their contractors, suppliers, intermediaries and/or workers working in benefit of the contract, the conservation of a healthy environment, taking the necessary precautions to protect the environment, human life and property of others and prevent contamination of the Contracted Area. As of contract initiation, THE ASSOCIATE shall prepare a general diagnosis of the environmental and social reality of the zones where the Exploration Works shall be performed, and shall establish the communication channels with the local authorities and communities.

THE ASSOCIATE agrees to implement a permanent plan, of a preventive nature, to ensure the conservation and restoration of the natural resources within the zones where the Exploration, exploitation and transportation works that are the subject-matter of this contract are performed.

THE ASSOCIATE must convey said plans and programs to the communities and national and regional order agencies that are related to this subject.

Likewise, specific contingency plans must be established to take care of the emergencies that may arise and to perform the remedying actions called for. For such purpose, THE ASSOCIATE must coordinate said plans and actions with the competent agencies.

THE ASSOCIATE, in accordance with the pertinent Clauses of this contract, must prepare the respective plans and budgets.

All costs caused shall be borne by THE ASSOCIATE during the Exploration Period and Exploitation under the Sole Risk method, and by both Parties, charged to the Joint Account in the Exploitation Period.

CLAUSE 31. TAXES, LIENS, AND OTHERS

All taxes and liens caused after establishing the Joint Account and before the Parties receive their production shares in and that are chargeable to oil exploitation, shall be

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charged to the Joint Account. The income and complementary taxes, or presumed income taxes, will be solely at the expense of each of the Parties, accordingly.

CLAUSE 32. PERSONNEL

32.1    When THE ASSOCIATE is the Operator, the Operator Manager’s appointment will be consulted previously with ECOPETROL.

32.2    Pursuant to the terms of this contract and subject to the regulations established herein, the Operator, as the sole and actual employer, shall have autonomy to designate personnel required for the operations under this contract, and may establish their salaries, functions, categories, and conditions. The Operator will adequately and diligently train the Colombian personnel required to substitute the foreign personnel that the Operator may consider required for the performance of the operations of this contract. In all cases, the Operator shall comply with any legal provisions that set forth the proportion of local and expatriate employees and workers.

32.3    TECHNOLOGY TRANSFER

THE ASSOCIATE agrees to implement, at its expense, a training program for ECOPETROL professionals in areas related to the development of the contract.

For compliance with this obligation in the Exploration Period, training may be, among others, in the areas of geology, geophysics and related areas, evaluation and definition of characteristics of reservoirs, drilling and production. Training shall take place throughout the two and a half (2.5) years Exploration Period and extensions thereof, through the integration of the professionals appointed by ECOPETROL to the work group THE ASSOCIATE organizes for the Contracted Area or for other similar activities of THE ASSOCIATE.

To opt for the waiver mentioned in Clause 5 of this contract, THE ASSOCIATE must have previously complied with the training programs provided for hereunder.

In the Exploitation Period, the scope, duration, place, participants, training conditions, and other aspects shall be established by the Association’s Executive Committee.

All of the costs of supervised training, with the exception of labor-related ones caused in favor of the professionals who receive said training, shall be borne by THE ASSOCIATE

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in the Exploration Period and by both Parties charged to the Joint Account in the Exploitation Period.

PARAGRAPH: For fulfillment of obligations regarding Technology Transfer, as per provisions contained herein, THE ASSOCIATE hereby commits to carry out training programs directed to ECOPETROL officials for a value up to twenty five thousand U.S. Dollars (US$25,000.oo), for each phase of the Exploration Period. The subject and type of program shall be agreed in advance between ECOPETROL and THE ASSOCIATE. Should the Exploration period be extended, the supervised training shall consist in programs similar to the one foreseen herein for each extended year.

CLAUSE 33. INSURANCE

THE ASSOCIATE or the Operator will take all the insurance policies required by the Colombian laws. Likewise, it will require each contractor performing any job in performance of this contract to acquire and keep in effect all the insurance policies that the Operator may consider necessary. Also the Operator will take all the insurance policies that the Executive Committee may consider advisable.

Upon termination of this contract, at any time during the Exploitation period or due to expiration of the term set forth in Clause 23, the Operator and/or THE ASSOCIATE shall take out an insurance policy to guarantee payment of salaries, benefits and indemnities and other labor obligations due to eventual legal sentences derived from claims from the workers hired by the Operator in its condition as their sole and true employer and during the time of operation of the Commercial Field. The policy term shall not be less than three (3) years counted as of the date of termination of the Association Contract and the insured value shall be defined by the Executive Committee, subject to that set forth in the labor provisions applicable to the respective employment contracts.

CLAUSE 34 - FORCE MAJEURE OR ACTS OF GOD

The obligations of this contract shall be suspended for as long as the Parties are unable to fulfill them totally or partially, due to unforeseen events that constitute force majeure or acts of God such as strikes, shutdowns, war, earthquakes, floods or other catastrophes, governmental laws, regulations or decrees that prevent obtainment of essential material and, in general, any non-financial cause which may actually obstruct

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the works, even if not mentioned above, but affecting the Parties beyond their control. If one of the Parties is not able, due to force majeure or acts of God, to fulfill its obligations under this contract, it must immediately notify the other Party for its consideration, specifying the causes of such impediment. In no event shall the occurrences of force majeure or acts of God extend the total Exploration and Exploitation Periods beyond of the maximum term of the contract, as per provisions in Clause 23, but any impediment due to force majeure during the two and a half (2.5) year Exploration Period mentioned in Clause 5, which lasts longer than sixty (60) consecutive days, will extend this two and a half (2.5) year period for the same period that the impediment lasts.

CLAUSE 35 - APPLICATION OF COLOMBIAN LAW

For all the purposes of this contract, the Parties set as their domicile the city of Bogota, Republic of Colombia. This contract is fully in force under Colombian Law and THE ASSOCIATE is subject to the jurisdiction of the Colombian Courts and waives any attempt to make any diplomatic claim in regards to the rights and obligations arising from this contract, except in the event that justice is denied. It is understood that justice will not be denied when THE ASSOCIATE, in its capacity as Operator or Party, has exhausted all the resources and actions that, in compliance with Colombian Law, may be used before Colombian legal authorities.

CLAUSE 36. NOTICES

The services or communications between the Parties in regards to this contract will require to be valid, the mention of the relevant clauses, and should be sent to the representatives or delegates designated by the Parties to the following addresses:

To ECOPETROL: Cra 13 #36-24, Santa Fe de Bogota, D.C., Colombia. To THE ASSOCIATE: Diagonal 108 No. 7—54, Bogota, D.C., Colombia Any change of address and representatives should be duly notified in advance to the other Party.

CLAUSE 37. HYDROCARBON VALUATION

The payments or reimbursements referred to in Clauses 9 (Items 9.2 and 9.4) and 22 (Item 22.5), will be made in USA dollars, or in Hydrocarbon, based on its current market

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price and the limitations established by Colombian Law for the sale of the portion payable in USA dollars, of Hydrocarbons coming from the Contracted Area to be used in refining in the Colombian territory.

CLAUSE 38. HYDROCARBON PRICES

38.1    The Hydrocarbons corresponding to THE ASSOCIATE in performance of this contract, destined to the refinery or to domestic supply, shall be paid placed at the refinery that must process them or at the receiving station agreed to by the Parties, in accordance with the governmental provisions or rules in force, or those that replace them.

38.2 The differences arising from the application of this clause will be settled in the manner provided for in this contract.

CLAUSE 39. PERFORMANCE BOND

At ECOPETROL´s discretion, in order to ensure completion of the Exploration Works corresponding to each phase of the Exploration Period, in accordance with Clause 5, THE ASSOCIATE, at its expense, agrees to submit in favor of ECOPETROL one or more irrevocable Stand-By Letters of Credit or Bank Bonds issued by a financial corporation acceptable to ECOPETROL, for an amount in dollars of the United States of America equal to one hundred per cent (100%) of the value of works to be guaranteed, according to ECOPETROL’s opinion, with a validity to cover the estimated time for performance of the guaranteed work, and ninety (90) calendar days more, counted as of the date on which it is issued. Should ECOPETROL request the bond, THE ASSOCIATE shall present it within fifteen (15) workdays counted as of the date of ECOPETROL’s communication making such request. Upon request of THE ASSOCIATE, the value of this bond may be reduced every six (6) months, in proportion to the value of the guaranteed Works actually performed, as agreed to in Clause 5.

Should ECOPETROL request such bond, THE ASSOCIATE may substitute it by establishing a trust fund for an amount in USA dollars equivalent to one hundred per cent (100%) of the works value. The trust contract shall be previously approved by ECOPETROL and shall provide for disbursements to be made upon obtaining approval

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from ECOPETROL for the activity timetable and the mechanism approved by the Parties at that time.

CLAUSE 40. DELEGATION AND ADMINISTRATION

The President of EMPRESA COLOMBIANA DE PETROLEOS—ECOPETROL—delegates to the Exploration and Production Vice-President the administration of this contract, according to ECOPETROL’s standards and regulatory provisions, empowering him to execute all transactions and processes inherent in Contract performance. The Vice-President of Exploration and Production may exercise this delegation through the Joint Exploration and Production Vice-Presidents.

CLAUSE 41. LANGUAGE

For all purposes and actions regarding this contract, the official language is Spanish.

CLAUSE 42. VALIDITY

This contract requires approval from the Ministry of Mines and Energy .

In witness whereof, this is signed in Bogota, D.C., in the presence of witnesses, on the second (2) day of the month of August of the year two thousand two (2002).

EMPRESA COLOMBIANA DE PETROLEOS

ECOPETROL

/s/ Victor Eduardo Perez H.

VICTOR EDUARDO PEREZ H.

PRESIDENT IN CHARGE

EMPRESA COLOMBIANA DE PETROLEOS ECOPETROL GUAYUYACO ASSOCIATION CONTRACT Pag. 53

ARGOSY ENERGY INTERNATIONAL

/s/ Alvaro Jose Camacho Rodriquez

ALVARO JOSE CAMACHO RODRIQUEZ

LEGAL REPRESENTATIVE

Witnesses

/s/ Edgar L. Dyes

/s/ R. Suttill

/s/ Victor Hugo Franco

/s/ (Illegible Signature)

This is a fair and accurate English translation of the original document which is in the Colombian language (Spanish).

/s/ James L. Busby

James L. Busby

Secretary and Treasurer

of Aviva Petroleum Inc.

EX-99.1

EXHIBIT 99.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

(18 U.S.C. 1350)

The undersigned, Ronald Suttill, President and Chief Executive Officer of Aviva Petroleum Inc. (the “Company”), has executed this certification in connection with the filing with the Securities and Exchange Commission of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2002 (the “Report”).

The undersigned hereby certifies that to the knowledge of the undersigned:

1.    The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.    The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

IN WITNESS WHEREOF, the undersigned has executed this certification as of the 25th day of March, 2003.

/s/    Ronald Suttill

Ronald Suttill

President and Chief Executive Officer

EX-99.2

EXHIBIT 99.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

(18 U.S.C. 1350)

The undersigned, James L. Busby, Secretary, Treasurer and Chief Financial Officer of Aviva Petroleum Inc. (the “Company”), has executed this certification in connection with the filing with the Securities and Exchange Commission of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2002 (the “Report”).

The undersigned hereby certifies that to the knowledge of the undersigned:

1.    The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.    The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

IN WITNESS WHEREOF, the undersigned has executed this certification as of the 25th day of March, 2003.

/s/    James L. Busby

James L. Busby

Secretary, Treasurer and Chief Financial Officer