<PAGE>
 
               UNITED STATES SECURITIES AND EXCHANGE COMMISSION
                            WASHINGTON, D.C. 20549

                                   FORM 10-K

[ X ]           ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                   SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]

               For the fiscal year ended      DECEMBER 31, 1996
                                           ------------------------

                                      OR

[   ]         TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                  SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]

                   For the transition period from        to
                                                  ------    ------

                        Commission File Number  0-22258

                             AVIVA PETROLEUM INC.
            (Exact name of registrant as specified in its charter)
TEXAS                                                           75-1432205
(State or other jurisdiction of                              (I.R.S. Employer
incorporation or organization)                            Identification Number)

8235 DOUGLAS AVENUE,                                              75225
SUITE 400, DALLAS, TEXAS                                        (Zip Code)
(Address of principal executive offices)

                                (214) 691-3464
             (Registrant's telephone number, including area code)

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

                                                Names of each exchange
                                                ----------------------
        Title of each class                     on which registered
        -------------------                     -------------------
        Depositary Receipts,                    American Stock Exchange
        each representing five shares of
        Common Stock, without par value

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

                        Common Stock, without par value

Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.  Yes   x   No      .
                                        -----    -----

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

The aggregate market value of voting securities held by non-affiliates of the
Registrant on February 28, 1997 was approximately $19,153,000.  As of such date,
the last sale price on the American Stock Exchange of a Depositary Share
representing five shares of Common Stock, without par value ("Common Stock"),
was U.S. $3.38, and the middle market price of Common Stock on the London Stock
Exchange Limited was U.K. 34 pence.

As of February 28, 1997, 31,482,716 shares of Registrant's Common Stock were
outstanding, of which 10,324,615 shares of Common Stock were represented by
Depositary Shares.

                      DOCUMENTS INCORPORATED BY REFERENCE

Certain portions of the Registrant's definitive Proxy Statement for the 1997
Annual Meeting of Shareholders are incorporated in Part III by reference.
<PAGE>
 
                         TABLE OF CONTENTS TO FORM 10-K

<TABLE>
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                                                                            Page
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Part I
<S>                                                                        <C> 

  Item 1.  Business
              General......................................................    1
              Current Operations...........................................    1
              Risks Associated with the Company's Business.................    2
              Products, Markets and Methods of Distribution................    4
              Regulation...................................................    5
              Competition..................................................    9
              Employees....................................................    9
  Item 2.  Properties
              Productive Wells and Drilling Activity.......................   10
              Undeveloped Acreage..........................................   11
              Title to Properties..........................................   11
              Federal Leases...............................................   11
              Reserves and Future Net Cash Flows...........................   12
              Production, Sales Prices and Costs...........................   12
              Significant Properties
                  Colombia.................................................   13
                  United States............................................   16
  Item 3.  Legal Proceedings...............................................   17
  Item 4.  Submission of Matters to a Vote of Security Holders.............   17

Part II

  Item 5.  Market for Registrant's Common Equity and Related Stockholder 
              Matters Price Range of Depositary Shares and Common Stock....   18
              Dividend History and Restrictions............................   19
  Item 6.  Selected Financial Data.........................................   20
  Item 7.  Management's Discussion and Analysis of Financial Condition and
              Results of Operations
              Results of Operations........................................   21
              Liquidity and Capital Resources..............................   23
  Item 8.  Financial Statements and Supplementary Data.....................   26
  Item 9.  Changes in and Disagreements with Accountants on Accounting
              and Financial Disclosure.....................................   26

Part III

  Item 10. Directors and Executive Officers of the Registrant..............   27
  Item 11. Executive Compensation..........................................   27
  Item 12. Security Ownership of Certain Beneficial Owners and Management..   27
  Item 13. Certain Relationships and Related Transactions..................   27

Part IV

  Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.   28

Signatures.................................................................   34

</TABLE>

                                      (i)
<PAGE>
 
                                    PART I

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 and offshore in the United States. The Company was incorporated in
1973 and the common stock, without par value ("Common Stock"), of the Company
has been traded on the London Stock Exchange Limited (the "London Stock
Exchange") since 1982. Depositary shares ("Depositary Shares"), each
representing the beneficial ownership of five shares of Common Stock, have
traded on the Primary List of the American Stock Exchange since May 31, 1995,
and prior to that on the Emerging Company Marketplace of the American Stock
Exchange since November 14, 1994.  The Company's principal executive offices are
located in Dallas, Texas, and the Company maintains a field office in Venice,
Louisiana.

Current Operations

  Colombia. Through a wholly owned subsidiary, the Company is the owner of
  --------                                                                
interests in, and is engaged in exploration for, and development and production
of oil from, four concessions granted by Empresa Colombiana de Petroleos, the
Colombian national oil company ("Ecopetrol").

  The Company's Colombian activities are carried out pursuant to four joint
operating agreements between the Company's wholly owned subsidiary, Neo Energy,
Inc. ("Neo"), and co-owner Argosy Energy International ("Argosy"), which
operates the Colombian properties and is an affiliate of Garnet Resources
Corporation ("Garnet").  Neither Garnet nor Argosy is affiliated with the
Company.  Neo has a 45% interest and Argosy has the remaining 55% interest in
properties covered by the four joint operating agreements.  Neo and Argosy are
parties to four concession agreements with Ecopetrol called Santana, La Fragua,
Yuruyaco and Aporte Putumayo.  All four concessions are located in the Putumayo
Basin of southwestern Colombia.  The Company's exploration and development
activities are currently concentrated in the Santana and Yuruyaco concessions.

  Twenty wells have been drilled on the Santana concession.  Of the thirteen
exploratory wells, seven have been productive and six were dry holes. Of the
seven development wells, five have been productive.  Drilling of an eighth
development well commenced on February 25, 1997.  Four fields have been
discovered and have been declared commercial by Ecopetrol.  Gross production
from the Santana concession has totaled approximately 8.8 million barrels during
the period from April 1992, when production commenced, through December 1996.
The Company's share of this production totaled approximately 1.5 million
barrels.

  The contract for the La Fragua concession, which adjoins Santana to the north,
was approved by Ecopetrol in June 1992.  The acquisition of seismic data
required in the first two years of the contract has been completed.  The Company
has determined, however, that further exploration on this concession is not
technically justified and the concession will likely be surrendered.  See "Item
2.  Properties -- Significant Properties -- Colombia."

  The contract for the Yuruyaco concession, which is adjacent to the eastern
boundaries of the Santana and La Fragua concessions, was approved by Ecopetrol
in September 1995.  The Yuruyaco contract requires in the first and second
contract years seismic surveys totaling 19 and 12 miles, respectively.  A 2-D
seismic program was initiated in late December 1996 that will satisfy such
obligations.  If the Company decides to proceed into the third year, the
drilling of a test well would be required.

                                       1
<PAGE>
 
  The Aporte Putumayo block has produced since 1976.  Declining production has,
however, caused the block to be unprofitable under the terms of the contract.
Neo and Argosy have, accordingly, notified Ecopetrol that they intend to
relinquish this block pursuant to the terms of the concession agreement.
Production from the Aporte Putumayo block was shutin effective March 31, 1995,
and abandonment and restoration operations are continuing.

  Each concession is governed by a separate contract with Ecopetrol.  Generally,
the contracts cover a 28-year period and require certain exploration
expenditures in the early years of the contract and, in the later years of the
contract, permit exploitation of reserves that have been found.  All of the
contracts provide that Ecopetrol shall receive, on behalf of the Colombian
Ministry of Mines, royalty payments in the amount of 20% of the gross proceeds
of the oil produced pursuant to the respective contract, less certain costs of
transporting the oil to the point of sale.  Under each of the contracts,
application must be made to Ecopetrol for a declaration of commerciality for
each discovery. If Ecopetrol declares the discovery commercial, it has the right
to a 50% reversionary interest in the field and is required to pay 50% of all
future costs.  If, alternatively, Ecopetrol declines to declare the discovery
commercial, Neo and Argosy have the right to proceed with development and
production at their own expense until such time as they have recovered 200% of
the costs incurred, at which time Ecopetrol is entitled to back in for a 50%
working interest in the field without payment or reimbursement of any historical
costs. Exploration costs (as defined in the concession agreements) incurred by
the co-owners prior to the declaration of commerciality are recovered by means
of retention by the co-owners of all of the non-royalty proceeds of production
from each well until costs relating to that well are recovered.

  United States.  In the United States the Company, through its wholly owned
  -------------                                                             
subsidiary, Aviva America, Inc. ("AAI"), is engaged in the production of oil and
gas attributable to its working interests in 16 offshore wells and, until
December 23, 1996, approximately 350 onshore wells which were sold for
$2,702,000 in cash, net of closing adjustments. For further information as to
the sale of these assets, see Notes 1 and 10 of Notes to Consolidated Financial
Statements. The Company acquired its interests in most of these wells through
the acquisition of producing properties.

  On December 23, 1996, the Company completed the sale of all of its U.S.
onshore oil and gas properties which were located primarily in Pennsylvania,
Oklahoma and Wyoming. The Company now operates its remaining U.S. oil and gas
properties, which are in the Gulf of Mexico offshore Louisiana, at Main Pass 41
and Breton Sound 31 fields.

Risks Associated with the Company's Business

  General.    The Company's operations are subject to oil field operating
  -------                                                                
hazards such as fires, explosions, blowouts, cratering and oil spills, any of
which can cause loss of hydrocarbons, personal injury and loss of life, and can
severely damage or destroy equipment, suspend drilling operations and cause
substantial damage to subsurface structures, surrounding areas or property of
others.  As protection against operating hazards, the Company maintains broad
insurance coverage, including indemnity insurance covering well control,
redrilling and cleanup and containment expenses, Outer Continental Shelf Lands
Act coverage, physical damage on certain risks, employers' liability,
comprehensive general liability, appropriate auto and marine liability and
workers' compensation insurance.  The Company believes that such insurance
coverage is customary for companies engaged in similar operations, but the
Company may not be fully insured against various of the foregoing risks, because
such risks are either not fully insurable or the cost of insurance is
prohibitive.  The Company does not carry business interruption insurance because
of the prohibitively high cost.  The occurrence of an uninsured hazardous event
could have a material adverse effect on the financial condition of the Company.

  Colombia.    The Company has expended significant amounts of capital for the
  --------                                                                    
acquisition, exploration and development of its Colombian properties and plans
to expend additional capital for exploration and 

                                       2
<PAGE>
 
development of such properties. Even if the results of such activities are
favorable, further drilling at significant costs must be conducted to determine
the extent of the recoverable reserves. Failure to fund capital expenditures
could result in forfeiture of all or part of the Company's interests in the
applicable property. For additional information on the Company's concession
obligations, see "-- Current Operations," and regarding its cash requirements,
see "Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Liquidity and Capital Resources."

  In addition, the Company's ability to continue its Colombian exploration and
development programs is dependent upon the ability of its co-owner to finance
its portion of such costs and expenses.  There can be no assurance that the
Company's co-owner will be in a position to pay, or provide for the payment of,
its costs and expenses of joint projects.  If the Company's co-owner cannot fund
its obligations, the Company may be required to accept an assignment of the co-
owner's interest therein and assume those funding obligations.  If, thereafter,
the Company were to be unable to raise sufficient funds to meet such
obligations, the Company's interests in the affected properties may be
forfeited.  Moreover, even if the Company were to be able to raise sufficient
funds, there could be no assurance that the Company would be able to discover,
develop and produce sufficient reserves to recover the costs and expenses
incurred in connection with the exploration and development thereof.  In reports
filed with the Securities and Exchange Commission, which are publicly available,
Garnet has expressed its belief that it will be able to fund its share of
capital expenditures relating to these properties through cash flow from
production in Colombia and its existing working capital.

  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 local
insurgents.  In late 1990, the Colombian Government Armed Forces launched an
aggressive effort to confront the leftist guerrillas who have operated within
Colombia for many years.  This military operation occurred on several fronts
throughout the country.  The guerrillas in the Putumayo area, where the
Company's property is located, responded to these attacks by retaliating against
several private companies.  As a result of these retaliatory raids, the Company
experienced two incidents in which damage to its drilling rig was sustained and
a contractor's helicopter was destroyed.  Although the Company's losses on those
occasions were substantially recovered through insurance, there can be no
assurance that such coverage will remain available or affordable.  Although
unrelated incidents have continued to occur in the vicinity of the Company's
operations, including political protests by local residents that temporarily
suspended production for approximately eight days during December 1994 and
approximately nine days in August 1996, the level of guerrilla activity subsided
in the first quarter of 1991 and the Company has not been the target of any
significant guerrilla activity since then.  Nonetheless, the Colombian army
guards the Company's operations and there can be no assurance that the Company's
operations in Colombia will not be the target of similar attacks in the future.

  United States.    The Company's activities in the United States are subject to
  -------------                                                                 
a variety of risks.  The  U.S. properties could, in certain circumstances,
require expenditure of significant amounts of capital.  Failure to fund its
share of such costs could result in a diminution of value of, or under
applicable operating agreements  forfeiture of, the Company's interest.  The
Company's ability to fund such expenditures is also 

                                       3
<PAGE>
 
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 11 of the Notes to Consolidated Financial Statements contained elsewhere
herein.

Products, Markets and Methods of Distribution

  Colombia.    The Company's oil is sold pursuant to sales contracts with
  --------                                                               
Ecopetrol. The contracts generally provide 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, 1996, the Company received
more than 10% of its revenue from Ecopetrol.  Sales to Ecopetrol accounted for
$9,437,000, or 68.6% of oil and gas revenue for 1996, $7,132,000, or 65.3% of
oil and gas revenue for 1995 and $3,404,000, or 39.8% of oil and gas revenue for
1994, representing the Company's entire Colombian oil revenue.  If Ecopetrol
were to elect not to purchase the Company's Colombian oil production, the
Company believes that other purchasers could be found for such production.

  United States.   The Company does not refine or otherwise process domestic
  -------------                                                             
crude oil and condensate production. The domestic oil and condensate it produces
are sold to refineries and oil transmission companies at posted field prices in
the area where production occurs. The Company does not have long term contracts
with purchasers of its domestic oil and condensate production. The Company's
domestic gas production is primarily sold under short term arrangements at or
close to spot prices. Some gas is committed to be processed through certain
plants. The Company has not historically hedged any of its domestic production.

  During 1996, 1995 and 1994, the Company received more than 10% of its revenue
from one domestic purchaser.  Such revenue accounted for $1,609,000, or 11.7% of
oil and gas revenue for 1996, $1,422,000, or 13.0% of oil and gas revenue for
1995 and $1,144,000, or 13.4% of oil and gas revenue for 1994.  If this
purchaser were to elect not to purchase the Company's oil and gas production,
the Company believes that other purchasers could be found for such production.

  General.  Oil and gas are the Company's only products.  There is substantial
  -------                                                                     
uncertainty as to the prices that the Company may receive for production from
its existing oil and gas reserves or from oil and gas reserves, if any, which
the Company may discover or purchase.  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.

                                       4
<PAGE>
 
Regulation

  Environmental Regulation.  The Company's operations are subject to foreign,
  ------------------------                                                   
federal, state, and local laws and regulations governing the discharge of
materials into the environment or otherwise relating to environmental
protection.  These laws and regulations may require the acquisition of a permit
by operators before drilling commences, restrict the types, quantities, and
concentration of various substances that can be released into the environment in
connection with drilling and production activities, limit or prohibit drilling
activities on certain lands lying within wilderness areas, wetlands, and other
protected areas, require remedial measures to mitigate pollution from former
operations, such as plugging and abandoning wells, and impose substantial
liabilities for pollution resulting from the Company's operations.  The
regulatory burden on the oil and gas industry increases the cost of doing
business and consequently affects its profitability.  Changes in environmental
laws and regulations occur frequently, and any changes that result in more
stringent and costly waste handling, disposal, remedial, drilling, or
operational requirements could have a significant 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 impact on the Company's operations, capital expenditures,
and earnings.  Management further believes, however, that risks of substantial
costs and liabilities are inherent in oil and gas operations, and there can be
no assurance that significant costs and liabilities will not be incurred.

       Colombia.  Any significant exploration or development of the Company's
       --------                                                              
Colombian concessions, such as conducting a seismic program, the drilling of an
exploratory or developmental well or the construction of a pipeline, requires
environmental review and the advance issuance of environmental permits by the
Colombian government. In 1993, Instituto de Recursos Naturales y Ambiente
("Inderena"), the Colombian federal environmental agency, began reviewing the
environmental standards and permitting processes for the oil industry in
general, and in 1994 a new Ministry of the Environment was organized. In
connection with its review, Inderena requested that additional environmental
studies be submitted for the Company's area of operations north of the Caqueta
River. See "Item 2. Properties -- Significant Properties -- Colombia -- Santana
Concession." As a result of the review and requests for additional environmental
studies, the Company's operations north of the Caqueta River were suspended
pending review and approval of additional environmental studies submitted by the
Company in January 1994 and the issuance of environmental licenses by the
Ministry of the Environment. In May 1994, the suspension was lifted and certain
of the required environmental licenses were issued, including a permit allowing
the co-owners of the concession to conduct a seismic program in that area. Since
the lifting of the above referenced suspension, the co-owners have received
subsequent permits, without substantial delay, to drill development and
exploratory wells, construct related production facilities and construct a 10-
mile pipeline. There can be, however, no assurance that the Company will not
experience future delays in obtaining necessary environmental licenses. See also
"Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations -- Liquidity and Capital Resources" and "Item 2. Properties --
Significant Properties -- Colombia."

          United States.   The Company believes that it is currently in
          -------------                                                
substantial compliance with U.S. federal, state, and local environmental laws
and regulations.  The Company has experienced no material financial effects to
date from compliance with these U.S. environmental laws or regulations and does
not currently plan any significant capital expenditures for U.S. environmental
control efforts.

  The Oil Pollution Act of 1990 ("OPA '90") and regulations thereunder impose a
variety of requirements on "responsible parties" related to the prevention of
oil spills and liability for damages resulting from such spills in waters of the
United States. A "responsible party" includes the owner or operator of a
facility or vessel, 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 

                                       5
<PAGE>
 
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.

  With recent amendments to OPA '90 signed into law by President Clinton on
October 19, 1996, OPA '90 now requires responsible parties to establish and
maintain $35 million in financial responsibility to cover environmental cleanup
and restoration costs that might be incurred in connection with an oil spill in
waters of the United States, including the waters of the Gulf of Mexico where
the Company has its operations, unless a formal risk assessment indicates that
increased financial responsibility coverage is warranted.  The Company's two
U.S. properties, Main Pass Block 41 field, a federal lease on the outer
continental shelf ("OCS") offshore Louisiana, and Breton Sound Block 31 field,
on state leases offshore Louisiana, are subject to OPA '90 as amended.
Management of the Company believes that these two properties comply in all
material respects with the amended OPA '90 requirements.

  The Outer Continental Shelf Lands Act ("OCSLA") imposes a variety of
requirements relating to safety and environmental protection on lessees and
permittees operating on the OCS.  Specific design and operational standards may
apply to OCS vessels, rigs, platforms, vehicles, and structures.  Violations of
lease conditions or regulations issued pursuant to OCSLA can result in
substantial civil and criminal penalties, as well as potential court injunctions
curtailing operations and the cancellation of leases.  Such enforcement
liabilities can result from either governmental or private prosecution.

  With respect to the Federal Water Pollution Control Act, the United States
Environmental Protection Agency ("EPA") issued regulations prohibiting the
discharge of produced water and produced sand derived from oil and gas
operations in certain coastal areas (primarily state waters) of Louisiana and
Texas, effective February 8, 1995.  In connection with these regulations,
however, the EPA also issued an administrative order that effectively delayed
compliance with the no discharge requirement for produced water until January 1,
1997.  Effective August 27, 1996, the Louisiana Department of Environmental
Quality ("LDEQ") officially assumed responsibility for compliance and
enforcement issues for produced water as they relate to the Company's Breton
Sound Block 31 facilities with the EPA operating in an oversight capacity.  On
December 30, 1996, the LDEQ adopted an emergency rule which, among other things,
provided an extension of time, to July 1, 1997, to achieve compliance with the
prohibitions against produced water discharges.  The Company has filed an
application pursuant to the emergency rule that, if approved, would allow the
Company to continue with its current operations until January 1, 1999.  Failing
approval, or further extension of the deadline, the Company will be required to
reinject the produced water into a suitable underground formation.  Management
of the Company does not expect the incremental cost to prepare and operate a
reinjection well to have a material adverse effect on the Company's operating
results.  See "Item 2. Properties -- Significant Properties -- United States."

  The Comprehensive Environmental Response, Compensation, and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without regard
to fault or the legality of the original conduct, on certain classes of persons
that are considered responsible for the release of a "hazardous substance" into
the environment.  These persons include the owner or operator of the disposal
site or sites where the release occurred and companies that disposed or arranged
for the disposal of hazardous substances found at the site.  Persons who are or
were responsible for releases of hazardous substances under CERCLA may be
subject to joint and several liability for the costs of cleaning up the
hazardous substances that have been released into the environment and for
damages to natural resources, and it is not uncommon for neighboring landowners
and other third parties to file claims for personal injury and 

                                       6
<PAGE>
 
property damage allegedly caused by the hazardous substances released into the
environment. The Company has not received any notification nor is it otherwise
aware of circumstances indicating that it may be potentially responsible for
cleanup costs under CERCLA.

  The federal Resource Conservation and Recovery Act ("RCRA") and comparable
state statutes regulate the storage, treatment and disposal of wastes, including
hazardous wastes.  The EPA and various state agencies have limited the approved
methods of disposal for certain hazardous and nonhazardous wastes, thereby
making such disposal more costly.  Furthermore, certain wastes generated by the
Company's oil and natural gas operations that are currently exempt from
treatment as hazardous wastes may in the future be designated as hazardous
wastes and therefore be subject to more rigorous and costly operating and
disposal requirements.

  Other Regulation - Colombia.  The Company's Colombian operations are regulated
  ---------------------------                                                   
by Ecopetrol, the Ministry of Mines and Energy, and the Ministry of the
Environment, among others.  The review of current environmental laws,
regulations and the administration and enforcement thereof, or the passage of
new environmental laws or regulations in Colombia, could result in substantial
costs and liabilities in the future or in delays in obtaining the necessary
permits to conduct the Company's operations in that country.  These operations
may also be affected from time to time in varying degrees by political
developments in Colombia.  Such political developments could result in
cancellation or significant modification of the Company's contract rights with
respect to such properties, or could result in tax increases and/or retroactive
tax claims being assessed against the Company.

  Other Regulation - United States.  Domestic exploration for and production and
  --------------------------------                                              
sale of oil and gas are extensively regulated at both the national and local
levels.  Legislation affecting the oil and gas industry is under constant review
for amendment or expansion, frequently increasing the regulatory burden.  Also,
numerous departments and agencies, both federal and state, are authorized by
statute to issue, and have issued, rules and regulations applicable to the oil
and gas industry that are often difficult and costly to comply with and that may
carry substantial penalties for failure to comply.  The regulations also
generally specify, among other things, the extent to which acreage may be
acquired or relinquished, permits necessary for drilling of wells, spacing of
wells, measures required for preventing waste of oil and gas resources and, in
some cases, rates of production and sales prices to be charged to purchasers.
The heavy and increasing regulatory burdens on the oil and gas industry increase
the costs of doing business and, consequently, affect profitability.

  Sales of domestic crude oil and condensate can be made by the Company at
market prices not subject to price controls at this time.  Prior to January 1,
1993, the sale of certain categories of domestic natural gas by the Company was
subject to regulation under the Natural Gas Act ("NGA"), as amended, and the
Natural Gas Policy Act of 1978, as amended.  The  Natural Gas Wellhead Decontrol
Act of 1989 removed all NGA price and non-price controls which affected wellhead
sales of natural gas.

  Commencing in April 1992, the Federal Energy Regulatory Commission ("FERC")
issued Orders numbered 636, 636-A, and 636-B ("Order No. 636"), which require
interstate pipelines to provide transportation separate,  or "unbundled," from
the pipelines' sales of gas.  Also, Order No. 636 requires pipelines to provide
open-access transportation on a basis that is equal for all gas supplies.
Although Order No. 636 does not directly regulate the Company's activities, the
FERC has stated that it intends for Order No. 636 to foster increased
competition within all phases of the natural gas industry.  It is unclear what
impact, if any, increased competition within the natural gas industry under
Order No. 636 will have on the Company's activities.  Although Order No. 636,
assuming it is upheld in its entirety in litigation initiated by parties not
affiliated with the Company, could provide the Company with additional market
access and more fairly applied transportation service rates, Order No. 636 could
also subject the Company to more restrictive pipeline imbalance tolerances and
greater penalties for violation of those tolerances.  The FERC has issued final
orders in all Order No. 636 pipeline restructuring proceedings.  The United
States Court of Appeals for the District of Columbia Circuit ("D.C. Circuit")
has generally affirmed Order 

                                       7
<PAGE>
 
No. 636 and remanded certain issues for further explanation or clarification.
The issues remanded for further action do not appear to materially affect the
Company. Numerous petitions for review of the individual pipeline restructuring
orders are currently pending in that court. Although it is difficult to predict
when all appeals of pipeline restructuring orders will be completed or their
impact on the Company, the Company does not believe that it will be affected by
the restructuring rule and orders any differently than other natural gas
producers and marketers with which it competes.

  The FERC has announced several important transportation-related policy
statements and proposed rule changes, including the appropriate manner in which
interstate pipelines release capacity under Order No. 636 and, more recently,
the price that shippers can charge for their released capacity.  In addition, in
1995, the FERC issued a policy statement on how interstate natural gas pipelines
can recover the costs of new pipeline facilities.  In January 1996, the FERC
issued a policy statement and a request for comments concerning alternatives to
its traditional cost-of-service ratemaking methodology.  A number of pipelines
have obtained FERC authorization to charge negotiated rates as one such
alternative.  While any additional FERC action on these matters would affect the
Company only indirectly, any new rules and policy statements may have the effect
of enhancing competition in natural gas markets by, among other things,
encouraging non-producer natural gas marketers to engage in certain purchase and
sale transactions.  The Company cannot predict what action the FERC will take on
these matters, nor can it accurately predict whether the FERC's actions will
achieve the goal of increasing competition in markets in which the Company's
natural gas is sold.  However, the Company does not believe that it will be
affected by any action taken materially differently than other natural gas
producers with which it competes.

  The Outer Continental Shelf Lands Act ("OCSLA") requires that all pipelines
operating on or across the Outer Continental Shelf ("OCS") provide open-access,
non-discriminatory service.  Although the FERC has chosen not to impose the
regulations of Order No. 509, in which the FERC implemented The OCSLA, with
respect to gatherers and other non-jurisdictional entities, the FERC has
retained the authority to exercise jurisdiction over those entities if necessary
to permit non-discriminatory access to service on the OCS.

  A portion of the Company's operations are located on federal oil and gas
leases, which are administered by the United States Department of the Interior
Minerals Management Service ("MMS").  Such leases are issued through competitive
bidding, contain relatively standardized terms and require compliance with
detailed MMS regulations and orders pursuant to the OCSLA.  In addition to
permits required from other agencies, lessees must obtain a permit from the MMS
prior to commencement of drilling.  To cover the various obligations of lessees
on the OCS, the MMS generally requires that lessees have substantial net worth
or post substantial bonds or other acceptable assurances that such obligations
will be met.  The cost of such bonds or other surety can be substantial and
there is no assurance that bonds or other surety can be obtained in all cases.

  The MMS is conducting an inquiry into certain agreements from which producers
on MMS leases have received settlement proceeds that are royalty bearing and the
extent to which producers have paid the appropriate royalties on those proceeds.
The Company believes that this inquiry will not have a material impact on its
financial condition, liquidity or results of operations.

  The MMS issued a notice of proposed rulemaking in which it proposes to amend
its regulations governing the calculation of royalties and the valuation of
natural gas produced from federal leases.  The principal feature in this
proposed rule would establish an alternative market-index based method to
calculate royalties on certain natural gas production sold pursuant to non-
arm's-length sales contracts.  In addition, the MMS recently issued a notice of
proposed rulemaking in which it proposes to amend its regulations governing the
calculation of royalties and the valuation of crude oil produced from federal
leases.  The principal features in this proposed rule would modify the valuation
procedures for both arm's-length and non-arm's-length crude oil transactions to
decrease reliance on crude oil posted prices and assign a value to crude oil
that better reflects market value, establish a new MMS form for collecting value
differential data, and amend the valuation procedure for the sale of federal
royalty oil.  The Company 

                                       8
<PAGE>
 
cannot predict what action the MMS will take on these matters, nor can it
predict at this stage in the rulemaking proceeding how the Company might be
affected by these amendments to the MMS' regulations.

  Sales of crude oil, condensate and gas liquids by the Company are not
currently regulated and are made at market prices.  Effective as of January 1,
1995, the FERC implemented regulations establishing an indexing system for
transportation rates for oil that could increase the cost of transporting oil to
the purchaser.  The Company is not able to predict what effect, if any, this
order will have on it, but other factors being equal, it may tend to increase
transportation costs or reduce wellhead prices for oil.

  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.  Certain state regulatory
authorities also regulate the amount of oil and gas produced by assigning
allowable rates of production to each well or proration unit.

  The Company cannot accurately predict the effect that any of the
aforementioned orders or the challenges to the orders will have on the Company's
operations.  Additional proposals and proceedings that might affect the oil and
natural gas industries are pending before Congress, the FERC and the courts.
These include Congressional energy bills and executive branch energy initiatives
which have as their goal the decreased reliance by the United States on foreign
energy supplies.  The Company cannot accurately predict when or whether any such
proposals or proceedings may become effective.

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, 1996, Aviva had 10 full-time employees, all in the United
States.

                                       9
<PAGE>
 
ITEM 2. PROPERTIES


Productive Wells and Drilling Activity

  The following table summarizes the Company's developed acreage and productive
wells at December 31, 1996.  "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.
<TABLE> 
<CAPTION> 

Developed Acreage /(1)/
                                               Gross          Net
                                            --------     --------
             <S>                            <C>          <C>
             United States                     3,240        1,482
             Colombia                         79,965       35,118
                                            --------     --------
                                              83,205       36,600
                                            ========     ========
</TABLE> 
<TABLE> 
<CAPTION> 
 
Productive Wells /(2)/
                                            Oil             Gas
                                      --------------  --------------
 
                                       Gross     Net   Gross     Net
                                      ------  ------  ------  ------
             <S>                      <C>     <C>     <C>     <C>
             United States /(3)/          10    5.21       6    2.69
             Colombia                     12    1.89       -       -
                                      ------  ------  ------  ------
                                          22    7.10       6    2.69
                                      ======  ======  ======  ======
</TABLE> 
(1)  Developed acreage is acreage assignable to productive wells.
(2)  Productive wells represent producing wells and wells capable of producing.
(3)  Two of the oil wells and one of the gas wells are dually completed.


  During the periods indicated, the Company drilled or participated in the
drilling of the following development and exploratory wells.
<TABLE> 
<CAPTION> 
                                           Net Wells Drilled
                                       -------------------------
 
                                  Development               Exploratory
                           -----------------------   -----------------------
 
                           Productive          Dry   Productive          Dry
                           ----------   ----------   ----------   ----------   
   <S>                     <C>          <C>          <C>          <C>  
   1996   United States           0.4            -            -            -
          Colombia                0.3            -            -          0.3
                           ----------   ----------   ----------   ----------   
          Total                   0.7            -            -          0.3
                           ==========   ==========   ==========   ==========   
                                                          
   1995   United States           0.1            -            -            -
          Colombia                0.5          0.2            -          0.3
                           ----------   ----------   ----------   ----------   
          Total                   0.6          0.2            -          0.3
                           ==========   ==========   ==========   ==========   
                                                          
   1994   United States           0.1            -            -            -
          Colombia                  -            -            -          0.3
                           ----------   ----------   ----------   ----------   
          Total                   0.1            -            -          0.3
                           ==========   ==========   ==========   ==========   
</TABLE> 
 
  In addition, at March 17, 1997, there was one gross (0.2 net) development well
in progress in Colombia.

                                       10
<PAGE>
 
  In the above table, a productive well is an exploratory or development well
that is not a dry well. A dry well is an exploratory or a development well found
to be incapable of producing either oil or gas in commercial quantities. A
development well is a well drilled within the proved area of an oil and gas
reservoir to the depth of a stratigraphic horizon known to be productive. An
exploratory well is any well that is not a development well.

Undeveloped Acreage

  The Company's undeveloped acreage in Colombia is held pursuant to concession
agreements with the Colombian government.  These agreements may, by operations
of their terms, require the relinquishment of certain portions of the
undeveloped acreage in 1997.  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 in
Colombia at December 31, 1996.  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.
<TABLE> 
<CAPTION> 
                                               Undeveloped Acres
                                             ---------------------

                                               Gross           Net
                                             -------       -------
                        <S>                  <C>           <C> 
                        Colombia             153,987        69,295
</TABLE> 
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.

Federal Leases

  The Company conducts a portion of its operations on federal oil and gas leases
and therefore must comply with numerous additional regulatory restrictions,
including certain nondiscrimination statutes.  Certain of the Company's
operations on federal leases must be conducted pursuant to appropriate permits
or approvals issued by various federal agencies.  Pursuant to certain federal
leases, approval of certain operations must be obtained from one or more
government agencies prior to the commencement of such operation.  Federal leases
are subject to extensive regulation.  See "Item 1. Business -- Regulation."

                                       11
<PAGE>
 
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, 1996, that is not the same as that included in the estimate of
proved oil and gas reserves as of December 31, 1996, as set forth in "Item 8.
Financial Statements and Supplementary Data" elsewhere herein.  The information
filed with the DOE includes the estimated proved reserves of the properties of
which the Company is the operator, whereas the estimated proved reserves
contained in Item 8 hereof include only the Company's percentage share of the
estimated proved reserves of all properties in which the Company has an
interest.

Production, Sales Prices and Costs

  The following table summarizes the Company's oil production in thousands of
barrels and natural gas production in millions of cubic feet for the years
indicated:
<TABLE> 
<CAPTION> 
 
                                              Year ended December 31,
                                            ---------------------------
 
                                               1996      1995      1994
                                            -------   -------   -------
<S>                                         <C>       <C>       <C> 
Oil /(1)/    United States                       94       106        99
             Colombia                           476       435       250
                                                                 
Gas          United States                    1,146     1,184     1,839
             Colombia                             -         -         -
</TABLE> 
                                                                 
(1)  Includes crude oil and condensate.

                                       12
<PAGE>
 
  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:

<TABLE>
<CAPTION>
                                                                             Year ended December 31, /(1)/
                                                                        --------------------------------------
                                                                  
                                                                          1996            1995            1994
                                                                        ------          ------          ------
<S>                                                <C>                  <C>             <C>             <C>
Average sales price per barrel of oil /(2)/        United States        $20.68          $16.78          $15.40
                                                   Colombia             $19.82          $16.39          $13.60
                                                                                                
Average sales price per MCF of gas                 United States        $ 2.07          $ 1.70          $ 1.97
                                                   Colombia             $    -          $    -          $    -
                                                                                                
Average production cost per dollar of                                                           
  oil and gas revenue                              United States        $ 0.45          $ 0.52          $ 0.43
                                                   Colombia             $ 0.31          $ 0.44          $ 0.67
Average production cost per barrel of                                                           
  oil equivalent                                   United States        $ 6.76          $ 6.46          $ 5.50
                                                   Colombia             $ 6.11          $ 7.15          $ 9.15
</TABLE>

(1)  All amounts are stated in United States dollars.
(2)  Includes crude oil and condensate.

Significant Properties

  Colombia.
  -------- 
  The Company's Colombian properties consist of four concessions, all of which
are located in the Putumayo Basin in southwestern Colombia along the eastern
front of the eastern cordillera of the Andes Mountains.  The Company has a 45%
working interest in each of the concessions, which is subject to various
reversionary interests in favor of Ecopetrol as described below.  Argosy, as
operator of the properties, carries out the program of operations for the four
concessions.  The program is determined, with consideration of the obligations
contained in the concession agreements, by an operating committee comprised of
two representatives from each of Argosy and Neo.  The Aporte Putumayo
concession, which consists of approximately 77,000 acres and contains three
shutin wells, has been in effect since 1972 and is currently being abandoned.
The Santana concession, which consists of approximately 86,000 acres and
contains 12 producing wells, has been in effect since 1987.  No wells have yet
been drilled on the La Fragua or Yuruyaco concessions, which consist of
approximately 32,000 acres and 39,000 acres, respectively.  The La Fragua
concession has been in effect since 1992, whereas the Yuruyaco concession was
acquired in 1995.  The Santana, La Fragua and Yuruyaco concessions are
contiguous, while the Aporte Putumayo concession is approximately 50 kilometers
to the southwest of the Santana concession.

  Production from the concessions is sold pursuant to sales contracts with
Ecopetrol.  Although sales prices vary between concessions, the contracts
generally provide that 25% of the sales proceeds will be paid in Colombian
pesos.  As a result of certain currency restrictions, pesos resulting from these
payments must generally remain in Colombia and are used by the Company to pay
local expenses.

  Neo's pretax income from Colombian sources, as defined under Colombian law, is
subject to Colombian income taxes at a statutory rate of 35% (37.5% prior to
1996), 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.
Neo's income after Colombian income taxes is subject to a Colombian remittance
tax that accrues at a rate of 12% (10% for 1997 and 7% thereafter).  Payment of
the remittance tax may be deferred under certain 

                                       13
<PAGE>
 
circumstances if Neo reinvests such income in Colombia. See Note 7 of the Notes
to Consolidated Financial Statements contained elsewhere herein.

  The Colombian government also imposes a production tax which averaged
approximately $1.33 per barrel during 1996 and is equal to 7% of the oil price
in effect through December 1997 for three of the four fields in the Santana
concession.  For the remaining field, the production tax is effective through
2000 at 7%, 5.5%, 4% and 2.5% of the oil price for 1997, 1998, 1999 and 2000,
respectively.  Any new discoveries declared commercial by Ecopetrol will be
exempt from the production tax.

     Santana Concession.         The Santana concession is subject to a "risk-
     ------------------                                                      
sharing" contract pursuant to which Ecopetrol has the option to participate on
the basis of a 30% working interest in exploration activities in the concession.
If a commercial field is discovered,  Ecopetrol's working interest increases to
50% and the costs theretofore incurred and attributable to the 20% working
interest differential will be recouped by the co-owners 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 mid-June
1996, the 7 million barrel threshold was reached.  At that time, the Company's
revenue interest in the concession declined from 18% to 12.6% and its share of
operating expenses declined from 22.5% to 15.75%.

  The Santana concession is divided by the Caqueta River.  Two fields located
south of the river, the Toroyaco and Linda fields, were declared commercial by
Ecopetrol and commenced production in 1992.  There are currently four producing
wells in the Toroyaco field and three 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 location for each field has been identified for
drilling in 1997.

  The Company and its co-owner ("Co-owners") 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.  The
Uchupayaco Pipeline replaced a trucking operation that transported oil
production from the fields to the Trans-Andean Pipeline.

  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 shutin until the first quarter of 1995 when construction of a
pipeline was completed and commercial production began.  With the completion of
this pipeline, the Co-owners have direct pipeline access from all four 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 has recently been completed over the Mary and Miraflor fields and such
data is currently being interpreted.  This survey is expected to define the
limits of these fields, identify possible locations for additional development
wells, and ascertain the prospectivity of areas adjacent to the Mary and
Miraflor fields.  At the present time, the Co-owners anticipate drilling at
least one additional development well in the Miraflor field during the fourth
quarter of 1997.

  During 1996 the Co-owners drilled one exploratory well, the Palmera #1, on the
Santana concession.  The well encountered water-bearing sands in the principal
zones of interest and was plugged and abandoned.

  The Co-owners have fulfilled all the initial exploration obligations required
by the Santana risk-sharing contract.  The contract requires that the Co-owners
submit work programs for approval by Ecopetrol for each of the next two years of
the contract.  The current work program contemplates the drilling of certain

                                       14
<PAGE>
 
development wells (one of which is currently in progress) and completing the
above referenced 3-D seismic program.

  In 1993, the Co-owners relinquished 50% of the original Santana concession
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 is
required in 1997 such that all remaining contract areas except for those areas
within five kilometers of a commercial field or an area under development must
be relinquished.

  Production from the Santana concession has been sold to Ecopetrol pursuant to
a sales contract that became effective January 1, 1995 and was extended through
January 31, 1997 (the "1996 Sales Contract").  Prices under the contract are
determined differently depending on whether (in the discretion of Ecopetrol) the
produced crude is exported.  If the crude is exported, the price received by the
Company is the export price less specified handling and commercialization
charges and subject to an adjustment (specified in the contract) for the quality
of the produced crude as compared with the overall pipeline blend at the point
of export (the "Pipeline Blend Adjustment").  If the crude is not exported, the
price received by the Company is the previous month's average posted price for
Cano Limon crude less specified handling and transportation charges and subject
to (i) the Pipeline Blend Adjustment and (ii) an adjustment for the quality of
the overall pipeline blend at the point of sale as compared with the quality of
Cano Limon crude (the "Cano Limon Adjustment").  Under the contract, the Cano
Limon Adjustment is based on a comparative analysis performed by a specified
independent engineer.  That analysis, which was performed in March of 1996,
determined that the Cano Limon Adjustment is a decrease of $0.56 per barrel.  In
1996, Ecopetrol exported the crude each month, with the exception of November,
and the sales price averaged $19.82 per barrel.

  At December 31, 1996, the date as of which the standardized measure of
discounted future net cash flows applicable to the Company's proved oil and gas
reserves was prepared, Ecopetrol was exporting the crude oil.    Accordingly,
for purposes of determining the standardized measure applicable to the Company's
Colombian reserves, the Company used the export price of $22.60 per barrel
(which does not include the Cano Limon adjustment).

  If Ecopetrol had not been exporting the crude oil at December 31, 1996,  the
standardized measure applicable to the Company's Colombian reserves at December
31, 1996 would have been approximately $37.8 million rather than $38.7 million.
Such decrease would not have resulted in a ceiling test write-down of the
Company's Colombian oil and gas properties.

  During February 1997, the Company entered into a new sales contract (the "1997
Sales Contract") with Ecopetrol that became effective February 1, 1997 and
continues through December 31, 1997.  The terms of the 1997 Sales Contract are
similar to the 1996 Sales Contract.

     La Fragua Concession. The La Fragua concession is subject to an
     --------------------                                           
"association" contract whereunder the Co-owners fulfill all exploration
obligations without Ecopetrol's participation until a field is declared
commercial, as described above.  The association contract also provides that
Ecopetrol's working interest increases on a sliding scale from 50% to 70% as
cumulative production from the concession increases from 60 million barrels to
150 million barrels.

  The Co-owners have completed their seismic obligations for the first two years
of the La Fragua concession and were obligated to acquire additional seismic
data for the third year.  The Co-owners have determined, however, that it was
not technically justified to explore this concession further and, accordingly,
requested and received from Ecopetrol a change of commitment that would allow
the Co-owners to substitute certain exploratory expenditures within the Santana
concession for the remaining seismic commitment on the La Fragua concession.
The indigenous people of the new commitment area, however, have objected to the
proposed exploratory work and it appears unlikely that the Co-owners will be
able to comply with the new commitment.  Management of the Company believes that
the Co-owners have no further obligation with respect to this concession and,
accordingly, have requested that Ecopetrol 

                                       15
<PAGE>
 
allow the Co-owners to surrender the concession without further expenditure.
Management of the Company believes that Ecopetrol will agree to such request,
although there can be no assurance of that.

     Yuruyaco Concession.  The Yuruyaco concession, acquired by the Company in
     --------------------                                                     
September 1995,  is an "association" contract whereunder the Company and its co-
owner fulfill all exploration obligations without Ecopetrol's participation
until a field is declared commercial by Ecopetrol.  At such time, Ecopetrol will
earn a 50% share in the commercial field and must reimburse its 50% share of
successful exploratory wells, seismic and stratigraphic wells, dry step-out
exploratory wells and development wells and facilities through its 50% share of
production.  The contract also provides that Ecopetrol's working interest will
be 50% up to 60 million barrels.  For production in excess of 60 million
barrels, Ecopetrol's interest will increase from 50% to 75%,  based on a measure
of profitability as defined in the contract.

  The contract obligations of the Yuruyaco association contract require the Co-
owners to perform in the first and second contract years seismic surveys
totaling 19 and 12 miles, respectively.  A 2-D seismic program was initiated in
late December 1996 that will satisfy such obligations.  If the Co-owners decide
to proceed into the third year, the drilling of a test well would be required.

     Aporte Putumayo Concession.  The discoveries on the Aporte Putumayo
     --------------------------                                         
concession were not declared commercial by Ecopetrol and the properties have
been operated by Argosy and Neo without participation by Ecopetrol.  There are
no remaining exploration obligations under this contract.  In a letter dated
December 1, 1993, the Company and its co-owner notified Ecopetrol of their
intention to relinquish the concession to Ecopetrol as provided in the contract.
Ecopetrol has accepted the relinquishment, which is pending the completion of
abandonment and restoration operations.

  United States.
  ------------- 
  The Company's oil and gas properties in the United States are located in the
Gulf of Mexico offshore Louisiana at Main Pass 41 and Breton Sound 31 fields.
Both of these properties are operated by the Company.

  Main Pass Block 41 is a federal lease located approximately 25 miles east of
Venice, Louisiana, in 50 feet of water. During 1996, the Company successfully
completed one development well and recompleted one existing well bringing the
number of productive wells in the field up to six.  The field's 1996 production
averaged 58 barrels of oil per day and 685 MCF per day, net to the Company's
interest, from eight completions in four sands between 6,000 and 7,500 feet.
The Company owns a 35% interest in this field.  Main Pass Block 41 represents
approximately 67% of the Company's total net U.S. proved reserves at January 1,
1997.

  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 1996, seven wells averaged 153 barrels of oil per day and 85 MCF
of gas per day, net to the Company's interest, from two sands completed between
5,500 feet and 6,500 feet. The Company's interests in the leases comprising the
field vary from 41% to 67%.  Breton Sound Block 31 Field represents
approximately 33% of the Company's total net proved U.S. reserves at January 1,
1997.

  The interpretation of 3-D seismic data in 1996 has identified two deep and
several shallow prospects in the Breton Sound 31 field.  The Company is
currently discussing plans with prospective industry partners to farm-in to the
Company's acreage by drilling one or more exploratory wells that would test the
deep prospects.  As for the shallow prospects, the Company anticipates that it
will drill at least one exploratory well; however, formal plans have not been
finalized.

  The Company leases corporate office space in Dallas, Texas containing
approximately 5,100 square feet pursuant to a lease which expires in January
1999.  The lease is cancelable in January 1998.  The annual lease payments for
these offices are $77,000.

                                       16
<PAGE>
 
ITEM 3. LEGAL PROCEEDINGS


  There are no legal proceedings to which the Company is a party or to which its
properties are subject which are, in the opinion of management, likely to have a
material adverse effect on the Company's results of operations or financial
condition.



ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS


  There were no matters submitted to a vote of security holders during the
fourth quarter of the Company's fiscal year ended December 31, 1996.

                                       17
<PAGE>
 
                                    PART II

ITEM 5.  MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
         MATTERS.


Price Range of Depositary Shares and Common Stock

  The Company's Depositary Shares, each representing the beneficial ownership of
five shares of Common Stock, have been admitted to trading on the American Stock
Exchange Emerging Company Marketplace since November 14, 1994 and on the Primary
List of the American Stock Exchange since May 31, 1995 (collectively the "ASE").
In addition, the Company's Common Stock has been traded on the London Stock
Exchange since 1982 and has been quoted in the National Quotation Bureau's Daily
Quotation Sheets (known as the "pink sheets") since December 1993.

  The following table sets forth, for the periods indicated and subject to the
following qualifications, the high and low prices for the Depositary Shares on
the ASE and the high and low prices for the Common Stock on the London Stock
Exchange.

  In the United States, trading of Depositary Shares on the ASE and of Common
Stock through the pink sheets has been limited. During 1996, only an aggregate
of 812,500 Depositary Shares were traded on the ASE.

  In the United Kingdom, the average daily trading volume of the Common Stock on
the London Stock Exchange during 1996 was approximately 65,000 shares.  The
London Stock Exchange prices indicated in the table are the middle market prices
for the Common Stock as published in the Daily Official List and do not
represent actual transactions.  Prices on the London Stock Exchange are
expressed in British pounds sterling, and, accordingly, the prices for the
Common Stock traded on the London Stock Exchange included in the following table
are similarly expressed.  For ease of reference, these prices are also expressed
in U.S. dollars, having been converted using the exchange rate in effect on the
first day on which the stock price attained the high or low price indicated.

                                       18
<PAGE>
 
<TABLE>
<CAPTION>
                                              1996                               1995                             1994
                                     -----------------------           -----------------------           -----------------------
                                       High              Low             High              Low             High              Low
                                     ------           ------           ------           ------           ------           ------
<S>                                  <C>              <C>              <C>              <C>              <C>              <C>
 
ASE
---
Depositary Shares /(1)/
-----------------------
First Quarter                        $ 4.38            $3.88            $6.13            $5.13            $   -            $   -
Second Quarter                       $11.38            $3.50            $7.38            $5.13            $   -            $   -
Third Quarter                        $ 6.25            $3.00            $5.38            $4.00            $   -            $   -
Fourth Quarter                       $ 5.75            $3.00            $4.88            $4.25            $5.13            $4.75
 
London Stock Exchange
---------------------
Common Stock
------------
 
First Quarter
     (Pounds)              (Pounds)    0.46  (Pounds)   0.34  (Pounds)   0.55  (Pounds)   0.47  (Pounds)   0.66  (Pounds)   0.51
     US$                             $ 0.71            $0.52            $0.87            $0.73            $0.98            $0.76
 
Second Quarter
     (Pounds)              (Pounds)    0.41  (Pounds)   0.25  (Pounds)   0.58  (Pounds)   0.53  (Pounds)   0.58  (Pounds)   0.50
     US$                             $ 0.63            $0.38            $0.93            $0.84            $0.86            $0.75
 
Third Quarter
     (Pounds)              (Pounds)    0.34  (Pounds)   0.25  (Pounds)   0.53  (Pounds)   0.45  (Pounds)   0.50  (Pounds)   0.43
     US$                             $ 0.53            $0.38            $0.85            $0.71            $0.77            $0.66
 
Fourth Quarter
     (Pounds)              (Pounds)    0.41  (Pounds)   0.28  (Pounds)   0.55  (Pounds)   0.38  (Pounds)   0.65  (Pounds)   0.46
     US$                             $ 0.67            $0.43            $0.85            $0.59            $1.06            $0.73
</TABLE>

(1) Representing five shares of Common Stock.

  As of February 28, 1997, the Company had approximately 5,800 shareholders of
record, including nominees for an undetermined number of beneficial holders.
 
Dividend History and Restrictions

  No dividends have been paid since June 1983, nor is there any current
intention on the part of the directors of the Company to pay dividends in the
future.
 
  Furthermore, in July 1993, the Company entered into a credit agreement
pursuant to which the Company is prohibited from paying dividends.  See "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources."

                                       19
<PAGE>
 
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,
1996, which should be read in conjunction with the Consolidated Financial
Statements included elsewhere herein.

<TABLE> 
<CAPTION> 
                                            For the Years Ended
                                                December 31,
                             ------------------------------------------------
                              1996      1995      1994      1993       1992
                             -------   -------   -------   -------   --------
                                      (in thousands, except per share, 
                                        per barrel and per MCF data)
<S>                          <C>       <C>       <C>       <C>       <C>
For the period
  Revenues                   $13,750   $10,928   $ 8,546   $10,682   $ 10,418   
  Loss before extraordinary                                          
    item and cumulative                                              
    effect of accounting
    change                   $  (937)  $(2,689)  $(2,460)  $(1,963)  $(10,226)
  Extraordinary item -                                               
    debt extinguishment      $     -   $     -   $     -   $  (341)  $      -
  Cumulative effect to                                               
    January 1, 1993 of                                               
    change in accounting
    for taxes                $     -   $     -   $     -   $  (330)  $      -
  Net loss                   $  (937)  $(2,689)  $(2,460)  $(2,634)  $(10,226)
  Loss before extraordinary                                          
    item and cumulative                                              
    effect of accounting                                             
     change                                                          
    per common share         $ (0.03)  $ (0.09)  $ (0.08)  $ (0.08)  $  (1.24)
  Net loss                                                           
    per common share         $ (0.03)  $ (0.09)  $ (0.08)  $ (0.11)  $  (1.24)
  Weighted average                                                   
    shares outstanding        31,483    31,483    31,483    24,756      8,277
  Cash dividends per                                                 
    common share             $     -   $     -   $     -   $     -   $      -
  Total annual net oil                                             
    production (barrels)                                           
      Colombia                   476       435       250       279        181
      United States               94       106        99       109        130
      Canada                       -         -         -         -         17
                             -------   -------   -------   -------   --------
       Total                     570       541       349       388        328
                             -------   -------   -------   -------   --------
                                                                   
  Total annual net gas                                             
    production (MCF)                                               
      United States            1,146     1,184     1,839     2,324      2,469
      Canada                       -         -         -         -         82
                             -------   -------   -------   -------   --------
       Total                   1,146     1,184     1,839     2,324      2,551
                             -------   -------   -------   -------   --------
                                                                   
  Average price per barrel                                         
    of oil                                                         
      Colombia               $ 19.82   $ 16.39   $ 13.60   $ 14.02   $  14.88
      United States          $ 20.68   $ 16.78   $ 15.40   $ 16.90   $  19.44  
      Canada                 $     -   $     -   $     -   $     -   $  19.45  
  Average price per MCF of                                         
    gas                                                            
      United States          $  2.07   $  1.70   $  1.97   $  2.12   $   1.92   
      Canada                 $     -   $     -   $     -   $     -   $   1.56   
                                                                   
At period end                                                      
  Total assets               $42,944   $45,460   $42,383   $45,017   $ 45,688 
  Long term debt, including                                        
    current portion          $ 7,990   $13,067   $ 6,640   $ 5,476   $ 17,217 
  Stockholders' equity       $26,230   $27,167   $29,856   $32,316   $ 23,805 
</TABLE>

                                       20
<PAGE>
 
  Effective January 1, 1993, the Company adopted Statement of Financial
Accounting Standards No. 109 ("Statement 109"), without restatement of prior
periods. Statement 109 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. In connection with the application of the
full cost method, the Company recorded a ceiling test write-down of oil and gas
properties of $6,471,000 in 1992 (see Note 1 of Notes to Consolidated Financial
Statements). The Company's Canadian operations were sold in 1991 and 1992.



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


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

1996 versus 1995
----------------
 
<TABLE> 
<CAPTION> 
                                  United States    Colombia
                                   Oil     Gas        Oil     Total
                                 ------   ------   --------  -------
       (Thousands)                                         
<S>                              <C>      <C>       <C>      <C>
                                                           
       Revenue - 1995            $1,781   $2,015    $7,132   $10,928
                                                           
       Volume variance             (206)     (99)      671       366
                                                           
       Price variance               365      422     1,634     2,421
                                                           
       Other                          -       35         -        35
                                 ------   ------    ------   -------
                                                           
       Revenue - 1996            $1,940   $2,373    $9,437   $13,750
                                 ======   ======    ======   =======
</TABLE>

  Colombian oil volumes were 476,000 barrels in 1996, an increase of 41,000
barrels over 1995.  Of such increase, approximately 110,000 barrels resulted
from a fracture stimulation program involving eight wells that was completed in
February 1996, net of normal production declines, and approximately 20,000
barrels resulted from the completion of two development wells in the latter part
of 1996, offset by a decrease of approximately 90,000 barrels resulting from the
Company's net revenue interest declining from 18% to 12.6% in mid-June 1996 when
cumulative production from the concession reached the 7 million barrel threshold
specified in the Santana risk-sharing contract.

  U.S. oil volumes were 94,000 barrels in 1996, down approximately 12,000
barrels from 1995. This decrease resulted primarily from normal production
declines. U.S. gas volumes before gas balancing adjustments were 1,136,000
thousand cubic feet ("MCF") in 1996, a decrease of 62,000 MCF from 1995,
resulting primarily from normal production declines, partially offset by new
production from a development well completed at Main Pass 41 during October
1996.

  Included in 1996 results of operations are revenue and operating costs of
$1,998,000 and $845,000, respectively, relating to the Company's U.S. onshore
properties which were sold on December 23, 1996.  During 1996, oil and gas
volumes for such properties were approximately 17,000 barrels and 864,000 MCF,
respectively, net to the Company.

                                       21
<PAGE>
 
  Colombian oil prices averaged $19.82 per barrel during 1996.  The average for
the same period in 1995 was $16.39.  The Company's average U.S. oil price
increased to $20.68 per barrel in 1996, up from $16.78 in 1995.  U.S. gas prices
averaged $2.07 per MCF in 1996 compared to $1.70 in 1995.

  Operating costs decreased $238,000, or 5%, mainly due to cost reductions in
the Colombian operations. Depletion, depreciation and amortization ("DD&A")
increased by 28%, or $1,584,000, primarily due to higher Colombian and U.S. DD&A
rates per barrel and higher Colombian production. U.S. DD&A expenses increased
on a per barrel basis to $5.93 in 1996 from $4.12 in 1995, primarily due to an
increase in costs subject to amortization resulting from development costs
incurred in 1996. Colombian DD&A expenses increased on a per barrel basis to
$11.49 in 1996 from $9.79 in 1995, primarily due to an increase in costs subject
to amortization resulting from development and exploratory costs incurred in
1996 and the transfer of unevaluated costs into the amortization base during
1996.

  General and administrative ("G&A") expense decreased $762,000, or 33%, as a
result of a cost reduction program implemented by the Company during the first
quarter of 1996.  This program has targeted all categories of G&A.

  The Company incurred $196,000 of severance expense during 1996 relating to the
termination of the employment of the Executive Vice President and Chief
Operating Officer of the Company and certain other employees.  For more
information regarding such terminations, see Note 6 of Notes to Consolidated
Financial Statements.

  Interest and other income (expense) increased $566,000 mainly due to a gain of
$641,000 on the sale of the U.S. onshore oil and gas properties on December 23,
1996.

  Interest expense was $256,000 higher, primarily as a result of higher average
balances outstanding in 1996. Debt refinancing expense of $100,000 represents a
fee paid to ING (U.S.) Capital Corporation in consideration for certain
modifications to the Company's credit agreement in March 1996.

  Income taxes were $500,000 higher in 1996 primarily as a result of an increase
in Colombian taxable income and an increase in the valuation allowance for
deferred Colombian tax assets.

1995 versus 1994
----------------

<TABLE> 
<CAPTION> 
                                  United States   Colombia
                                   Oil     Gas      Oil     Total
                                 ------  ------   --------  -------
       (Thousands)                              
<S>                              <C>     <C>      <C>       <C>
                                                
       Revenue - 1994            $1,521  $3,621    $3,404   $ 8,546
                                                
       Volume variance              113  (1,118)    2,514     1,509
                                                
       Price variance               147    (375)    1,214       986
                                                
       Other                          -    (113)        -      (113)
                                 ------  ------   --------  -------
       Revenue - 1995            $1,781  $2,015    $7,132   $10,928
                                 ======  ======   ========  =======
</TABLE>

  Colombian oil volumes were 435,000 barrels in 1995, an increase of 185,000
barrels over 1994.  Of such increase, approximately 210,000 barrels resulted
from production from three wells in the Mary field and one well in the Miraflor
field that did not produce during 1994 and one well in the Mary field that
produced during only part of 1994, and approximately 28,000 barrels resulted
from the hydraulic fractionation of the Toroyaco #3 well, offset by a decrease
of approximately 35,000 barrels from the Aporte Putumayo concession and a
decrease of approximately 18,000 barrels from the remaining wells in the
Toroyaco and 

                                       22
<PAGE>
 
Linda fields due to normal production declines. Production from the Aporte
Putumayo concession was shutin effective March 31, 1995, pending abandonment of
the concession.

  U.S. oil volumes were 106,000 barrels in 1995, an increase of 7,000 barrels
from 1994.  This increase resulted primarily from an increase of approximately
13,000 barrels due to the installation of a larger gas lift compressor at Breton
Sound 31, partially offset by a decrease of approximately 5,000 barrels related
to the sale of Ewing Bank 947, effective July 1, 1994.  U.S. gas volumes before
gas balancing adjustments were 1,198,000 MCF in 1995, a decrease of 585,000 MCF
from 1994.  Of such decrease, 217,000 MCF resulted from the sale of Ewing Bank
947 and 128,000 MCF resulted from decreased production from Main Pass 41 that
was primarily due to the loss of one well, which ceased production in July 1994.
The remaining decrease in gas volumes was primarily due to normal production
declines.

  Colombian oil prices averaged $16.39 per barrel during 1995.  The average
price for the same period in 1994 was $13.60 per barrel.  1994 oil sales were
subject to a sales contract with Ecopetrol, and the sales were based on a
"netback" price as specified in the sales contract.  During 1995 a new sales
contract with Ecopetrol was in effect pursuant to which the crude was either
exported or sold to a Colombian refinery.  In 1995, the crude was generally
exported and prices were higher due to a general increase in world oil prices.

  In addition to the above-mentioned variances, U.S. gas revenue decreased
approximately $113,000 as a result of gas balancing adjustments.

  Operating costs increased by $552,000, or 12%, due primarily to an increase in
Colombian production expense associated with the Mary and Miraflor fields.  Such
fields had minimal production during 1994.

  DD&A increased $1.8 million, or 44%, primarily due to higher Colombian volumes
and to a higher Colombian DD&A rate per barrel.  Colombian DD&A expenses
increased on a per barrel basis to $9.79 in 1995 from $7.90 in 1994, as a result
of a downward revision in Colombian reserve volumes and an increase in costs
subject to amortization.

  G&A expense increased $233,000 due primarily to an increase in public
ownership costs of $221,000 principally associated with being listed on the
American Stock Exchange during 1995. In addition, $125,000 of fees were paid to
an investment banking firm during 1995 to investigate and evaluate existing
alternatives to enhance shareholder value. These costs were partially offset by
a decrease in legal fees of $145,000.

  Interest and other income (expense) during 1995 increased primarily due to a
$167,000 increase in foreign exchange gains from 1994 to 1995 and the absence in
1995 of a $156,000 charge incurred in 1994 relating to the settlement of
litigation regarding the validity of a lease for vacated office space in London.

  Interest expense was $283,000 higher, primarily as a result of higher average
balances outstanding.

  Income taxes increased $125,000 primarily due to the threshold for "commercial
income" being reached in Colombia during 1995 resulting in the 12% remittance
tax thereon.  In 1994 the Company did not achieve commercial income in Colombia.

Liquidity and Capital Resources

  During the period 1994 through 1996, costs incurred in oil and gas property
acquisition, exploration and development activities by the Company totaled
approximately $23.6 million.  Of this figure, approximately $23.5 million was
for exploration and development costs and $0.1 million pertained to acquisitions
of proved properties in the United States.  Approximately 83% of the exploration
and development expenditures were incurred in Colombia, while the remainder was
primarily development costs incurred in the United States.  The Company's
sources of funds during this period were: (i) cash 

                                       23
<PAGE>
 
provided by operating activities - 1996 - $8.9 million; 1995 - $2.9 million; and
1994 - $3.1 million; (ii) net cash provided by investing activities (before
property and equipment expenditures) - 1996 - $2.7 million; 1995 - $0.1 million;
and 1994 - $2.5 million; and (iii) net cash provided by (used in) financing
activities - 1996 - $(5.1) million; 1995 - $6.4 million; and 1994 - $1.2
million.

  The Company is engaged in the drilling of certain development wells and the
recompletion of certain existing wells in Colombia.  See "Item 2. Properties --
Significant Properties."  The Company's share of the estimated future costs of
these development activities is approximately $2.9 million at December 31, 1996.
In addition, the Company is currently completing a 3-D seismic program on the
Santana concession and a 2-D seismic program on the Yuruyaco concession.  The
Company's estimated share of these future seismic and certain other
miscellaneous costs is approximately $1.0 million.  Failure to fund certain
capital expenditures could result in the forfeiture of all or part of the
Company's interest in the concessions.

  The aggregate remaining estimated exploratory and development expenditures for
1997 and 1998 were $3.9 million at December 31, 1996.  The Company plans to fund
these obligations through cash provided from operations.  Any substantial
decreases in the borrowing base as hereinafter defined or increases in the
amounts of these required expenditures could adversely affect the Company's
ability to meet the obligations.  Delays in obtaining the required environmental
approvals and permits on a timely basis, as described above under "Item 1.
Business -- Regulation," and construction delays could both, 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
20-30% 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 trend will not continue 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 the exploration and development activities,
substantial expenditures which have not been included in the Company's cash flow
projections may be required.  Although the ultimate outcome of these matters
cannot be projected with certainty, management believes that its existing
capital resources are adequate to fund its present obligations or that
sufficient capital can be obtained by means of sales of assets or revision of
current debt repayment terms to meet those obligations.

  The Company is a party to a credit agreement with ING (U.S.) Capital
Corporation ("ING Capital") pursuant to which the borrower thereunder may borrow
up to $25 million, subject to a borrowing base the determination of which is
predicated on the Company's U.S. and Colombian reserves and which is
redetermined annually.  As of December 31, 1996, the borrowing base permitted,
and the outstanding loan balance was, $7,990,000.  Borrowings under the credit
agreement bear interest at the prime commercial rate of the lender in effect
from time to time for its most creditworthy customers plus 1% per annum or, at
the Company's option, a fixed rate based on the London Interbank Offered Rate
for a portion or portions of the outstanding indebtedness.  The borrower under
the credit agreement is Neo Energy, Inc., a wholly owned subsidiary of the
Company and the owner of the Company's interests in the Colombian concessions.
The indebtedness under the credit agreement is guaranteed by the parent company
and certain other subsidiaries, including the wholly owned subsidiary that is
the owner of all the Company's domestic oil and gas properties.  The loan
prohibits the payment of dividends by the Company and requires the maintenance
of certain financial ratios. In December 1996, the Company entered into an
agreement with ING Capital pursuant to which the outstanding loan balance was
paid down to $7,990,000 from 

                                       24
<PAGE>
 
$10,790,000 and the repayment schedule was amended to require monthly payments
of $25,000 for the first seven months of 1997 and $521,000 for the last five
months of 1997 and the first ten months of 1998.

  The Company's internal projections of its consolidated cash flow through
December 31, 1998 indicate that the Company's consolidated cash flow and working
capital will be adequate to fund both the estimated exploratory and development
expenditures for 1997 and 1998 and the debt service relating to the ING Capital
credit agreement as rescheduled through October 1998.  These internal cash flow
projections assume (i) crude oil sales prices of $20.66 per barrel for Colombian
production and $21.52 per barrel for United States production and natural gas
sales prices of $2.10 per MCF for United States production, (ii) successful
completion of three development wells on the Santana Concession in Colombia,
(iii) production decline curves commensurate with those assumed by the Company's
independent petroleum engineers, (iv) certain reductions in general and
administrative costs and (v) interest rates and operating costs at current
levels.  Any significant inaccuracy in any of these assumptions, as well as
interruptions of production, increases in required expenditures as a result of
inflation or cost overruns or delays in the Company's development program, may
adversely affect the Company's ability to fund such exploratory and development
expenditures or to meet its existing debt service obligations.  Depending on the
results of the Company's exploration and development activities, substantial
expenditures that have not been included in such cash flow projections may be
required.  For information regarding the risks relating to the Company's
business, see "Item 1. Business -- Risks Associated with the Company's
Business".

  During late 1995, the Company engaged in discussions with Garnet Resources
Corporation, the parent of the co-owner of the Company's Colombian concessions,
regarding a possible merger of the Company and Garnet Resources Corporation.  In
December 1995, these discussions were terminated as a result of the inability of
the parties to reach agreement on terms and conditions of the proposed merger.
At that time, the Board of Directors of the Company empowered a committee of
directors to investigate and evaluate other strategic alternatives for the
Company.  That committee was dissolved on July 25, 1996 and its function was
assumed by the entire Board of Directors.

  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 the
timing and extent of changes in commodity prices for oil and gas, the extent of
the Company's success in discovering, developing and producing reserves,
political conditions in Colombia and conditions of the capital markets and
equity markets 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."

                                       25
<PAGE>
 
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


  See the Financial Statements of Aviva Petroleum Inc. attached hereto and
listed in Item 14 herein.



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


  None.

                                       26
<PAGE>
 
                                   PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT


  The information required with respect to directors is set forth under the
caption "Election of Directors" and "Beneficial Ownership of Securities" in the
Company's definitive Proxy Statement to be filed pursuant to Regulation 14A and
is incorporated herein by reference.



ITEM 11. EXECUTIVE COMPENSATION


  The information required is set forth under the caption "Executive
Compensation" in the Company's definitive Proxy Statement to be filed pursuant
to Regulation 14A and is incorporated herein by reference.



ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT


  The information required is set forth under the caption "Beneficial Ownership
of Securities" in the Company's definitive Proxy Statement to be filed pursuant
to Regulation 14A and is incorporated herein by reference.



ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS


  The information required is set forth under the caption "Certain Relationships
and Related Transactions" in the Company's definitive Proxy Statement to be
filed pursuant to Regulation 14A and is incorporated herein by reference.

                                       27
<PAGE>
 
                                    PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K


a.   The following documents are filed as part of this report:
 
     (1)  Financial Statements: The Financial Statements of Aviva Petroleum Inc.
          filed as part of this report are listed in the "Index to Financial
          Statements" included elsewhere herein.
     (2)  Financial Statement Schedules:  All schedules called for under
          Regulation S-X have been omitted because they are not applicable, the
          required information is not material or the required information is
          included in the consolidated financial statements or notes thereto.

     (3)  Exhibits:

          *3.1  Restated Articles of Incorporation of the Company dated July 25,
                1995 (filed as exhibit 3.1 to the Company's annual report on
                Form 10-K for the year ended December 31, 1995, File No. 0-
                22258, and incorporated herein by reference).

          *3.2  Amended and Restated Bylaws of the Company, as amended as of
                January 23, 1995 (filed as exhibit 3.2 to the Company's annual
                report on Form 10-K for the year ended December 31, 1994, File
                No. 0-22258, and incorporated herein by reference).

          *10.1 Risk Sharing Contract between Empresa Colombiana de Petroleos
                ("Ecopetrol"), Argosy Energy International ("Argosy") and Neo
                Energy, Inc. ("Neo") (filed as exhibit 10.1 to the Company's
                Registration Statement on Form10, File No. 0-22258, and
                incorporated herein by reference).

          *10.2 Contract for Exploration and Exploitation of Sector Number 1
                of the Aporte Putumayo Area ("Putumayo") between Ecopetrol and
                Cayman Corporation of Colombia dated July 24, 1972 (filed as
                exhibit 10.2 to the Company's Registration Statement on Form10,
                File No. 0-22258, and incorporated herein by reference).

          *10.3 Operating Agreement for Putumayo between Argosy and Neo dated
                September 16, 1987 and amended on January 4, 1989 and February
                23, 1990 (filed as exhibit 10.3 to the Company's Registration
                Statement on Form10, File No. 0-22258, and incorporated herein
                by reference).

          *10.4 Operating Agreement for the Santana Area ("Santana") between
                Argosy and Neo dated September 16, 1987 and amended on January
                4, 1989, February 23, 1990 and September 28, 1992 (filed as
                exhibit 10.4 to the Company's Registration Statement on Form10,
                File No. 0-22258, and incorporated  herein by reference).

          *10.5 Agreement of Withdrawal from Argosy dated September 16, 1987
                by and among Argosy, Neo, and Argosy Energy Incorporated, as
                general partners; and Parkside Investments, Richard Shaner
                McKnight, Douglas W. Fry, P-5 Ltd., GO-DEO, Inc., Dale E.
                Armstrong, Richard Shane McKnight, The Yvonne McKnight Trust,
                and William Gaskin, as limited partners (filed as exhibit 10.5
                to the Company's Registration Statement on Form10, File No. 0-
                22258, and incorporated herein by reference).

          *10.6 Option Agreement dated September 16, 1987 between the general
                and limited partners of Argosy and Neo (filed as exhibit 10.6 to
                the Company's Registration Statement on Form10, File No. 0-
                22258, and incorporated herein by reference).

          *10.7 Escrow Agreement between Argosy, Neo, Overseas Private
                Investment Corporation and The Chase Manhattan Bank dated March
                15, 1988 and amended on May 31, 1990 (filed as exhibit 10.7 to
                the Company's Registration Statement on Form10, File No. 0-
                22258, and incorporated herein by reference).

          *10.8 Santana Block A Relinquishment dated March 6, 1990 between
                Ecopetrol, Argosy and Neo (filed as exhibit 10.8 to the
                Company's Registration Statement on Form10, File No. 0-22258,
                and incorporated herein by reference).

                                       28
<PAGE>
 
          *10.9  Purchase Sale - Transportation and Commercialization of the
                 Santana Crude between Ecopetrol, Argosy and Neo (filed as
                 exhibit 10.9 to the Company's Registration Statement on Form
                 10, File No. 0-22258, and incorporated herein by reference).

          *10.10 La Fragua Association Contract dated June 1, 1992 between
                 Ecopetrol, Argosy and Neo (filed as exhibit 10.10 to the
                 Company's Registration Statement on Form 10, File No. 0-22258,
                 and incorporated herein by reference).

          *10.11 Operating Agreement for the La Fragua Area between Argosy
                 and Neo dated April 15, 1992 (filed as exhibit 10.11 to the
                 Company's Registration Statement on Form 10, File No. 0-22258,
                 and incorporated herein by reference).

          *10.12 Employment Agreement between the Company and Ronald Suttill
                 dated November 29, 1991 (filed as exhibit 10.12 to the
                 Company's Registration Statement on Form 10, File No. 0-22258,
                 and incorporated herein by reference).

          *10.13 Employee Stock Option Plan of the Company (filed as exhibit
                 10.13 to the Company's Registration Statement on Form 10, File
                 No. 0-22258, and incorporated herein by reference).
 
          *10.14 Letter agreement dated January 6, 1993 between NationsBank
                 Investment Banking and the Company (filed as exhibit 10.14 to
                 the Company's Registration Statement on Form 10, File No. 0-
                 22258, and incorporated herein by reference).

          *10.15 Letter agreement dated March 3, 1993 between EnCap
                 Investments L.C. and the Company (filed as exhibit 10.15 to the
                 Company's Registration Statement on Form 10, File No. 0-22258,
                 and incorporated herein by reference).

          *10.16 Credit Agreement dated August 6, 1993 between the Company,
                 Aviva America, Inc. ("Aviva America"), Neo and Internationale
                 Nederlanden Bank N.V., New York Branch ("ING Capital") (filed
                 as exhibit 10.16 to the Company's Registration Statement on
                 Form 10, File No. 0-22258, and incorporated herein by
                 reference).

          *10.17 Subordination Agreement dated August 6, 1993 between the
                 Company, Aviva America, Aviva Operating Company ("Aviva
                 Operating"), Neo and ING Capital (filed as exhibit 10.17 to the
                 Company's Registration Statement on Form 10, File No. 0-22258,
                 and incorporated herein by reference).

          *10.18 Stock Pledge Agreement dated August 6, 1993 between the Company
                 and ING Capital (filed as exhibit 10.18 to the Company's
                 Registration Statement on Form 10, File No. 0-22258, and
                 incorporated herein by reference).

          *10.19 Stock Pledge Agreement dated August 6, 1993 between Aviva
                 America and ING Capital (filed as exhibit 10.19 to the
                 Company's Registration Statement on Form 10, File No. 0-22258,
                 and incorporated herein by reference).

          *10.20 Guaranty dated August 6, 1993 made by the Company in favor of
                 ING Capital (filed as exhibit 10.20 to the Company's
                 Registration Statement on Form 10, File No. 0-22258, and
                 incorporated herein by reference).

          *10.21 Guaranty dated August 6, 1993 made by Aviva America in favor of
                 ING Capital (filed as exhibit 10.21 to the Company's
                 Registration Statement on Form 10, File No. 0-22258, and
                 incorporated herein by reference).

          *10.22 Guaranty dated August 6, 1993 made by Aviva Operating in favor
                 of ING Capital (filed as exhibit 10.22 to the Company's
                 Registration Statement on Form 10, File No. 0-22258, and
                 incorporated herein by reference).

          *10.23 Form of Subscription Agreement dated June 18, 1993 between the
                 Company and purchasers of 12,884,207 shares of common stock
                 ("Purchasers") (filed as exhibit 10.23 to the Company's
                 Registration Statement on Form 10, File No. 0-22258, and
                 incorporated herein by reference).

          *10.24 Option Agreement between RBS and Aviva Energy Inc. ("Aviva
                 Energy") dated July 1, 1993 (filed as exhibit 10.24 to the
                 Company's Registration Statement on Form 10, File No. 0-22258,
                 and incorporated herein by reference).

                                       29
<PAGE>
 
            *10.25  Option Agreement between Aviva Energy and Purchasers dated
                    July 1, 1993 (filed as exhibit 10.25 to the Company's
                    Registration Statement on Form 10, File No. 0-22258, and
                    incorporated herein by reference).

            *10.26  Santana Block B 50% relinquishment dated September 13, 1993
                    between Ecopetrol, Argosy and Neo (filed as exhibit 10.26 to
                    the Company's annual report on Form 10-K for the year ended
                    December 31, 1993, File No. 0-22258, and incorporated herein
                    by reference).

            *10.27  Amendment to La Fragua Association contract dated December
                    2, 1993 between Ecopetrol, Argosy and Neo (filed as exhibit
                    10.27 to the Company's annual report on Form 10-K for the
                    year ended December 31, 1993, File No. 0-22258, and
                    incorporated herein by reference).

            *10.28  Letter from Ecopetrol dated February 24, 1994 and Resolution
                    dated February 18, 1994 revising pipeline tariff (filed as
                    exhibit 10.28 to the Company's annual report on Form 10-K
                    for the year ended December 31, 1993, File No. 0-22258, and
                    incorporated herein by reference).

            *10.29  Aviva Petroleum Inc. 401(k) Retirement Plan effective March
                    1, 1992 (filed as exhibit 10.29 to the Company's annual
                    report on Form 10-K for the year ended December 31, 1993,
                    File No. 0-22258, and incorporated herein by reference).

            *10.30  Relinquishment of Putumayo dated December 1, 1993 (filed as
                    exhibit 10.30 to the Company's annual report on Form 10-K
                    for the year ended December 31, 1993, File No. 0-22258, and
                    incorporated herein by reference).

            *10.31  Amendment to ING Capital agreement dated March 28, 1994
                    (filed as exhibit 10.31 to the Company's annual report on
                    Form 10-K for the year ended December 31, 1993, File No. 0-
                    22258, and incorporated herein by reference).

            *10.32  Deposit Agreement dated September 15, 1994 between the
                    Company and Chemical Shareholder Services Group, Inc. (filed
                    as exhibit 10.29 to the Company's Registration Statement on
                    Form S-1, File No. 33-82072, and incorporated herein by
                    reference).

            *10.33  Form of Registration Agreement dated as of September 15,
                    1994 between the Company and Shearson Lehman Brothers Inc.
                    (filed as exhibit 10.30 to the Company's Registration
                    Statement on Form S-1, File No. 33-82072, and incorporated
                    herein by reference).

            *10.34  Form of Registration Agreement and Limited Power of Attorney
                    dated as of September 15, 1994 between the Company and all
                    other Selling Shareholders (filed as exhibit 10.31 to the
                    Company's Registration Statement on Form S-1, File No. 33-
                    82072, and incorporated herein by reference).

            *10.35  Form of Broker-Dealer Agreement dated as of October 19, 1994
                    between the Company and Petrie Parkman & Co. (filed as
                    exhibit 10.32 to the Company's Registration Statement on
                    Form S-1, File No. 33-82072, and incorporated herein by
                    reference).

            *10.36  Purchase and Sale Agreement dated July 22, 1994 by and
                    between Newfield Exploration Company and Aviva America
                    (filed as exhibit 10.33 to the Company's Registration
                    Statement on Form S-1, File No. 33-82072, and incorporated
                    herein by reference).

            *10.37  Letter from ING Capital dated October 27, 1994, amending
                    Section 5.2(n) of the Credit Agreement (filed as exhibit
                    10.37 to the Company's annual report on Form 10-K for the
                    year ended December 31, 1994, File No. 0-22258, and
                    incorporated herein by reference).

            *10.38  Letter from Ecopetrol dated December 28, 1994, accepting
                    relinquishment of Putumayo (filed as exhibit 10.38 to the
                    Company's annual report on Form 10-K for the year ended
                    December 31, 1994, File No. 0-22258, and incorporated herein
                    by reference).

                                       30
<PAGE>
 
        *10.39  Letter from Ecopetrol dated February 28, 1995, accepting
                modifications to the La Fragua Association Contract (filed
                as exhibit 10.39 to the Company's annual report on Form 10-K
                for the year ended December 31, 1994, File No. 0-22258, and
                incorporated herein by reference).

        *10.40  Amendment to ING Capital Credit Agreement dated March 7, 1995
                (filed as exhibit 10.40 to the Company's annual report on Form
                10-K for the year ended December 31, 1994, File No. 0-22258, and
                incorporated herein by reference).

        *10.41  Santana Crude Oil Sale Contract dated March 19, 1995 (filed
                as exhibit 10.41 to the Company's annual report on Form 10-K for
                the year ended December 31, 1994, File No. 0-22258, and
                incorporated herein by reference).

        *10.42  Employment Agreement between the Company and Ronald Suttill
                effective January 1, 1995 (filed as exhibit 10.1 to the
                Company's quarterly report on Form 10-Q for the quarter ended
                March 31, 1995, File No. 0-22258, and incorporated herein by
                reference).

        *10.43  Employment Agreement between the Company and Robert C. Boyd
                effective January 1, 1995 (filed as exhibit 10.2 to the
                Company's quarterly report on Form 10-Q for the quarter ended
                March 31, 1995, File No. 0-22258, and incorporated herein by
                reference).

        *10.44  Amendment to ING Capital Credit Agreement dated June 9, 1995
                (filed as exhibit 10.3 to the Company's quarterly report on Form
                10-Q for the quarter ended June 30, 1995, File No. 0-22258, and
                incorporated herein by reference).

        *10.45  Amendment to the Incentive and Nonstatutory Stock Option
                Plan of the Company (filed as exhibit 10.4 to the Company's
                quarterly report on Form 10-Q for the quarter ended September
                30, 1995, File No. 0-22258, and incorporated herein by
                reference).

        *10.46  Aviva Petroleum Inc. 1995 Stock Option Plan (filed as
                exhibit 10.5 to the Company's quarterly report on Form 10-Q for
                the quarter ended September 30, 1995, File No. 0-22258, and
                incorporated herein by reference).

        *10.47  Yuruyaco Association Contract dated September 20, 1995
                between Ecopetrol, Argosy and Neo (filed as exhibit 10.6 to the
                Company's quarterly report on Form 10-Q for the quarter ended
                September 30, 1995, File No. 0-22258, and incorporated herein by
                reference).

        *10.48  Letter from ING Capital dated November 3, 1995, amending
                Section 5.2 (n) of the Credit Agreement (filed as exhibit 10.7
                to the Company's quarterly report on Form 10-Q for the quarter
                ended September 30, 1995, File No. 0-22258, and incorporated
                herein by reference).

        *10.49  Amendment to the Santana Crude Oil Sale Contract (filed as
                exhibit 10.49 to the Company's annual report on Form 10-K for
                the year ended December 31, 1995, File No. 0-22258, and
                incorporated herein by reference).

        *10.50  Amendment to the La Fragua Association Contract dated April
                27, 1995 (filed as exhibit 10.50 to the Company's annual report
                on Form 10-K for the year ended December 31, 1995, File No. 0-
                22258, and incorporated herein by reference).

        *10.51  Santana Block B 25% relinquishment dated October 2, 1995
                (filed as exhibit 10.51 to the Company's annual report on Form
                10-K for the year ended December 31, 1995, File No. 0-22258, and
                incorporated herein by reference).

        *10.52  Amendment to the La Fragua Association Contract dated August
                1, 1995 (filed as exhibit 10.52 to the Company's annual report
                on Form 10-K for the year ended December 31, 1995, File No. 0-
                22258, and incorporated herein by reference)

        *10.53  Operating Agreement for the Yuruyaco Area between Argosy and
                Neo dated November 7, 1995 (filed as exhibit 10.53 to the
                Company's annual report on Form 10-K for the year ended December
                31, 1995, File No. 0-22258, and incorporated herein by
                reference).

                                       31
<PAGE>
 
        *10.54  Letter from ING Capital dated March 19, 1996, amending the
                borrowing base, schedule of principal repayments and Section 5.2
                (m) of the Credit Agreement (filed as exhibit 10.54 to the
                Company's annual report on Form 10-K for the year ended December
                31, 1995, File No. 0-22258, and incorporated herein by
                reference).

        *10.55  Amendment to the ING Capital Credit Agreement dated March
                29, 1996 (filed as exhibit 10.1 to the Company's quarterly
                report on Form 10-Q for the quarter ended March 31, 1996, File
                No. 0-22258, and incorporated herein by reference).

        *10.56  Aviva Petroleum Inc. Severance Benefit Plan (filed as
                exhibit 10.2 to the Company's quarterly report on Form 10-Q for
                the quarter ended March 31, 1996, File No. 0-22258, and
                incorporated herein by reference).

       **10.57  Amendment to the ING Capital Credit Agreement dated
                November 22, 1996.
  
       **10.58  Purchase and Sale Agreement dated November 22, 1996 between
                BWAB Incorporated and Aviva America.
 
       **10.59  Purchase and Sale Agreement dated December 6, 1996 between
                Lomak Petroleum Inc. and Aviva America.
 
       **10.60  Santana Crude Sale and Purchase Agreement dated February
                10, 1997.

        *21.1   List of subsidiaries of Aviva Petroleum Inc.
 
       **27.1   Financial Data Schedule

       ---------------------
 
       *        Previously Filed
       **       Filed Herewith

                                       32
<PAGE>
 
b. Reports on Form 8-K
   -------------------

   The Company filed the following Current Reports on Form 8-K during and
   subsequent to the end of the fourth quarter:

   Date of 8-K                Description of 8-K
   -----------                ------------------

   October 2, 1996            Submitted a copy of the Company's Press Release
                              dated October 2, 1996 reporting on the Company's
                              progress on U.S. operations.

   November 12, 1996          Submitted a copy of the Company's Press Release
                              dated November 12, 1996 announcing production
                              increases in the Gulf of Mexico.

   November 20, 1996          Submitted a copy of the Company's Press Release
                              dated November 20, 1996 reporting industry
                              discussions on Breton Sound in the Gulf of Mexico.

   November 26, 1996          Submitted a copy of the Company's Press release
                              dated November 26, 1996 reporting agreement to
                              sell U.S. onshore properties.

   December 3, 1996           Submitted a copy of the Company's Press release
                              dated December 3, 1996 reporting on the Company's
                              Colombian development program.

   January 7, 1997            Submitted a copy of the Company's Press release
                              dated January 7, 1997 reporting on the closing of
                              the U.S. onshore properties sale.

   January 8, 1997            Submitted a copy of the Company's Press release
                              dated January 8, 1997 reporting on the Company's
                              Colombian exploration and development operations.

 

                                       33
<PAGE>
 
                                  SIGNATURES

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

 
                                       By:  /s/ Ronald Suttill
                                            ------------------------------------
                                            Ronald Suttill
                                            Chief Executive Officer and Director

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

SIGNATURE                       TITLE                                 DATE

/s/ Ronald Suttill          President, Chief Executive Officer    March 17, 1997
--------------------------  and Director (principal executive     --------------
Ronald Suttill              officer) 


/s/ James L. Busby          Treasurer and Secretary               March 17, 1997
--------------------------  (principal financial and accounting   --------------
James L. Busby              officer)


/s/ John J. Lee             Director                              March 13, 1997
--------------------------                                        --------------
John J. Lee


/s/ Elliott Roosevelt, Jr.  Director                              March 17, 1997
--------------------------                                        --------------
Elliott Roosevelt, Jr.


/s/ James E. Tracey         Director                              March 17, 1997
--------------------------                                        --------------
James E. Tracey

                                       34
<PAGE>
 
        INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
 
                                                                Page
                                                                ----
 
Independent Auditors' Report..................................    36
 
Consolidated Balance Sheet as of December 31, 1996 and 1995...    37
 
Consolidated Statement of Operations for the years
     ended December 31, 1996, 1995 and 1994...................    38
 
Consolidated Statement of Cash Flows for the years
     ended December 31, 1996, 1995 and 1994...................    39
 
Consolidated Statement of Stockholders' Equity for the years
     ended December 31, 1996, 1995 and 1994...................    40
 
Notes to Consolidated Financial Statements....................    41
 
Supplementary Information Related to Oil and Gas Producing
     Activities (Unaudited)...................................    54
 

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
<PAGE>
 
                          INDEPENDENT AUDITORS' REPORT
                          ----------------------------

The Board of Directors
Aviva Petroleum Inc.:

We have audited the accompanying consolidated balance sheet of Aviva Petroleum
Inc. and subsidiaries as of December 31, 1996 and 1995 and the related
consolidated statements of operations, stockholders' equity and cash flows for
each of the years in the three-year period ended December 31, 1996. These
consolidated financial statements are the responsibility of the Company's
management.  Our responsibility is to express an opinion on these consolidated
financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Aviva Petroleum Inc.
and subsidiaries as of December 31, 1996 and 1995, and the results of their
operations and their cash flows for each of the years in the three-year period
ended December 31, 1996, in conformity with generally accepted accounting
principles.





                                         /s/ KPMG Peat Marwick LLP



Dallas, Texas
February 28, 1997

                                       36
<PAGE>
 
                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEET
                           DECEMBER 31, 1996 AND 1995
                    (in thousands, except number of shares)

<TABLE>
<CAPTION>
                                                            1996       1995
                                                          ---------  ---------
<S>                                                       <C>        <C>
ASSETS                                                    
                                                          
Current assets:                                           
 Cash and cash equivalents                                $  2,041   $  4,200
 Accounts and notes receivable (notes 2 and 8):           
   Oil and gas revenue                                       1,699      1,881
   Trade                                                     1,674        388
   Other                                                       377        487
 Inventories                                                   721        809
 Prepaid expenses and other                                    282        667
                                                          --------   --------
                                                          
   Total current assets                                      6,794      8,432
                                                          --------   --------
                                                          
Property and equipment, at cost (note 3):                 
 Oil and gas properties and equipment (full cost method)    58,324     80,544
 Other                                                         613        626
                                                          --------   --------
                                                            58,937     81,170
 Less accumulated depreciation, depletion                 
   and amortization                                        (23,991)   (45,663)
                                                          --------   --------
                                                            34,946     35,507
Other assets (note 2)                                        1,204      1,521
                                                          --------   --------
                                                          
                                                          $ 42,944   $ 45,460
                                                          ========   ========
                                                          
LIABILITIES AND STOCKHOLDERS' EQUITY                      
                                                          
Current liabilities:                                      
 Current portion of long term debt (note 3)               $  2,780   $  2,397
 Accounts payable                                            6,271      2,783
 Accrued liabilities                                           357        217
                                                          --------   --------
   Total current liabilities                                 9,408      5,397
                                                          --------   --------
                                                          
Long term debt, excluding current portion (note 3)           5,210     10,670
Gas balancing obligations and other (note 10)                1,404      1,729
Deferred foreign income taxes (note 7)                         692        497
Stockholders' equity (notes 3 and 5):                     
 Common stock, no par value, authorized 348,500,000       
   shares; issued 31,482,716 shares                          1,574      1,574
 Additional paid-in capital                                 33,376     33,376
 Accumulated deficit*                                       (8,720)    (7,783)
                                                          --------   --------
                                                          
   Total stockholders' equity                               26,230     27,167
                                                          
Commitments and contingencies (note 9)                    
                                                          --------   --------
                                                          $ 42,944   $ 45,460
                                                          ========   ========
</TABLE>
*Accumulated deficit of $70,057 was eliminated at December 31, 1992 in
 connection with a quasi-reorganization. See note 5.

See accompanying notes to consolidated financial statements.

                                       37
<PAGE>
 
                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
                      CONSOLIDATED STATEMENT OF OPERATIONS
                  YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
                     (in thousands, except per share data)
<TABLE>
<CAPTION>
 
                                                 1996      1995      1994
                                               --------  --------  --------
<S>                                            <C>       <C>       <C>
                                               
Oil and gas sales (note 8)                     $13,750   $10,928   $ 8,546
                                               -------   -------   -------
                                               
Expense:                                       
 Production                                      4,834     5,072     4,520
 Depreciation, depletion and amortization        7,339     5,755     3,984
 General and administrative                      1,554     2,316     2,083
 Severance (note 6)                                196         -         -
                                               -------   -------   -------
                                               
   Total expense                                13,923    13,143    10,587
                                               -------   -------   -------
                                               
Other income (expense):                        
 Interest and other income (expense),          
   net (note 4)                                  1,061       495       142
 Interest expense                                 (814)     (558)     (275)
 Debt refinancing expense (note 3)                (100)        -         -
                                               -------   -------   -------
                                               
   Total other income (expense)                    147       (63)     (133)
                                               -------   -------   -------
                                               
   Loss before income taxes                        (26)   (2,278)   (2,174)
Income taxes (note 7)                             (911)     (411)     (286)
                                               -------   -------   -------
                                               
   Net loss                                    $  (937)  $(2,689)  $(2,460)
                                               =======   =======   =======

Weighted average common shares outstanding      31,483    31,483    31,483
                                               =======   =======   =======
                                               
                                               
Net loss per common share                      $ (0.03)  $ (0.09)  $ (0.08)
                                               =======   =======   =======
</TABLE>                                       
See accompanying notes to consolidated financial statements.

                                       38
<PAGE>
 
                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
                      CONSOLIDATED STATEMENT OF CASH FLOWS
                  YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
                                 (in thousands)
<TABLE>
<CAPTION>
                                                      1996      1995     1994
                                                     -------   -------  -------
<S>                                                  <C>       <C>      <C>
Net loss                                             $  (937)  $(2,689) $(2,460)
Adjustments to reconcile net loss to
 net cash provided by operating activities:
  Depreciation, depletion and amortization             7,339     5,755    3,984
  Deferred foreign income taxes                          195        (5)      37
  Loss (gain) on sale of assets, net                    (651)        2        -
  Foreign currency exchange loss (gain), net              16      (164)       3
  Other                                                 (253)     (168)     (57)
  Changes in assets and liabilities:
   Accounts and notes receivable                        (916)      767    2,843
   Inventories                                            88       212      231
   Prepaid expenses and other                            406        (6)    (291)
   Accounts payable and accrued liabilities            3,656      (843)  (1,230)
                                                     -------   -------  -------
 
     Net cash provided by operating activities         8,943     2,861    3,060
                                                     -------   -------  -------
 
Cash flows from investing activities:
 Property and equipment expenditures                  (8,667)   (7,457)  (7,503)
 Proceeds from sale of assets                          2,729        73    2,198
 Other                                                   (46)        -      313
                                                     -------   -------  -------
 
     Net cash used in investing activities            (5,984)   (7,384)  (4,992)
                                                     -------   -------  -------
Cash flows from financing activities:
 Proceeds from long term debt                              -     7,100    4,801
 Principal payments on long term debt                 (5,077)     (673)  (3,637)
                                                     -------   -------  -------
      Net cash provided by (used in) financing
       activities                                     (5,077)    6,427    1,164
                                                     -------   -------  -------
 
Effect of exchange rate changes on cash and
 cash equivalents                                        (41)      314       (4)
                                                     -------   -------  -------
 
Net increase (decrease) in cash and cash 
  equivalents                                         (2,159)    2,218     (772)
Cash and cash equivalents at beginning of year         4,200     1,982    2,754
                                                     -------   -------  -------

Cash and cash equivalents at end of year             $ 2,041   $ 4,200  $ 1,982
                                                     =======   =======  =======
</TABLE>
See accompanying notes to consolidated financial statements.

                                       39
<PAGE>
 
                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
                 CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
                  YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
                    (in thousands, except number of shares)
<TABLE>
<CAPTION>
                         Common Stock      
                      ------------------  Additional                 Total
                      Number of             Paid-in   Accumulated  Stockholders'
                        Shares     Amount   Capital     Deficit      Equity
                      ----------  ------- ----------- ----------- -------------
<S>                   <C>         <C>     <C>         <C>         <C>
Balances at
 December 31,1993     31,482,716   $1,574   $33,376     $(2,634)     $32,316
 
Net loss                       -        -         -      (2,460)      (2,460)
                      ----------   ------   -------     -------      -------
 
Balances at
 December 31, 1994    31,482,716    1,574    33,376      (5,094)      29,856
 
Net loss                       -        -         -      (2,689)      (2,689)
                      ----------   ------   -------     -------      -------
 
Balances at
 December 31, 1995    31,482,716    1,574    33,376      (7,783)      27,167
 
Net loss                       -        -         -        (937)        (937)
                      ----------   ------   -------     -------      -------
 
Balances at
 December 31, 1996    31,482,716   $1,574   $33,376     $(8,720)     $26,230
                      ==========   ======   =======     =======      =======
</TABLE>
See accompanying notes to consolidated financial statements.

                                       40
<PAGE>
 
                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

     General
     Aviva Petroleum Inc. and its subsidiaries (the "Company") are engaged in
     the business of exploring for, developing and producing oil and gas in
     Colombia and in the United States.  The Company's Colombian oil production
     is sold to Empresa Colombiana de Petroleos, the Colombian national oil
     company ("Ecopetrol"), while the Company's U.S. oil and gas production is
     sold to numerous U.S. purchasers. (See notes 8 and 11.)

     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.

     Principles of Consolidation
     The consolidated financial statements include the accounts of Aviva
     Petroleum Inc. and its subsidiaries. All significant intercompany accounts
     and transactions have been eliminated in consolidation.

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

     Property and Equipment
     Under the full cost method of accounting for oil and gas properties, all
     productive and nonproductive property acquisition, exploration and
     development costs are capitalized in separate cost centers for each
     country.  Such capitalized costs include lease acquisition costs, delay
     rentals, geophysical, geological and other costs, drilling, completion and
     other related costs and direct general and administrative expenses
     associated with property acquisition, exploration and development
     activities.  Capitalized general and administrative costs include internal
     costs such as salaries and related benefits paid to employees to the extent
     that they are directly engaged in such activities, as well as all other
     directly identifiable general and administrative costs associated with such
     activities, including rent, utilities and insurance and do not include any
     costs related to production, general corporate overhead, or similar
     activities.  Capitalized internal general and administrative costs were
     $129,000 in 1996, $156,000 in 1995 and $142,000 in 1994.

     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 $1,140,000  of which $723,000 has been provided through
     December 31, 1996.

     Depreciation, depletion and amortization expense per equivalent barrel of
     production was as follows:
     
     <TABLE> 
     <CAPTION> 
                                     1996        1995        1994
                                   ------       -----       -----
               <S>                 <C>          <C>         <C> 
               United States       $ 5.93       $4.12       $4.05
 
               Colombia            $11.49       $9.79       $7.90

     </TABLE> 
                                       41
<PAGE>
 
                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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

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

     Gains and losses on sales of oil and gas properties are not recognized in
     income unless the sale involves a significant portion of the reserves
     associated with a particular cost center.  Capitalized costs associated
     with unevaluated properties are excluded from amortization until it is
     determined whether proved reserves can be assigned to such properties or
     until the value of the properties is impaired.  Unevaluated costs of
     $1,066,000 and $3,012,000 were excluded from amortization at December 31,
     1996 and 1995, respectively.  Unevaluated properties are assessed quarterly
     to determine whether any impairment has occurred.  The unevaluated costs at
     December 31, 1996 represent exploration costs and were incurred primarily
     during the four-year period ended December 31, 1996. Such costs are
     expected to be evaluated and included in the amortization computation
     within the next three years.

     The Company sold, on December 23, 1996, all of its remaining U.S. onshore
     oil and gas properties for $2,702,000 in cash, net of closing adjustments.
     The sale involved a significant portion of the reserves associated with the
     U.S. cost center and, accordingly, the resultant gain on the sale has been
     recognized in the accompanying Consolidated Statement of Operations for
     1996. (See note 4.)

     In July 1994, the Company sold its entire interest in one of its offshore
     properties, Ewing Bank 947, for $2,325,000 in cash.  The sale proceeds
     reduced the carrying value of the Company's oil and gas properties.

     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.

                                       42
<PAGE>
 
                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     Interest Expense
     The Company capitalizes interest costs on qualifying assets, principally
     unevaluated oil and gas properties.  During 1996, 1995 and 1994, the
     Company capitalized $189,000, $295,000 and $238,000 of interest,
     respectively.
 
     Loss Per Common Share
     Loss per common share is based on the weighted average common shares
     outstanding. The effects of common stock equivalents (note 5) are
     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.

     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 $834,000 in 1996, $591,000 in
     1995 and $183,000 in 1994 and paid income taxes of $111,000 in 1996,
     $178,000 in 1995 and $163,000 in 1994.

     Fair Value of Financial Instruments
     The reported values of cash, cash equivalents, accounts receivable and
     accounts payable approximate fair value due to their short maturities.  The
     reported value of long-term debt approximates its fair value since the
     applicable interest rate approximates market rates.

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

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

                                       43
<PAGE>
 
                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
 
 
(2) OTHER ASSETS
 
A summary of other assets follows:
<TABLE>
<CAPTION>

                                                        December 31
                                                    --------------------
                                                        (thousands)
                                                      1996          1995
                                                    ------        ------
<S>                                                 <C>           <C>

 Deferred financing charges                         $  225        $  344
 Gas balancing (note 10)                                 4           624
 Ecopetrol receivable, excluding current portion        76           180
 Abandonment funds for U.S. offshore properties        853           373
 Other                                                  46             -
                                                    ------        ------
 
                                                    $1,204        $1,521
                                                    ======        ======
</TABLE>

     Amounts due from Ecopetrol represent estimated costs which the Company is
     entitled to recover from Ecopetrol's share of oil production in Colombia.
     Accounts receivable - other include $85,000 and $341,000 for 1996 and 1995,
     respectively, representing the current portion of such costs.
 
(3)  LONG TERM DEBT
 
     A summary of long term debt follows:
<TABLE>
<CAPTION>
                                                   December 31
                                                -----------------
                                                    (thousands)
                                                   1996      1995
                                                -------   -------
<S>                                             <C>       <C>
 
 Note payable to ING Capital                    $ 7,990   $13,000
 
 Other obligation                                     -        67
                                                -------   -------
                                                  7,990    13,067
 Less current portion                             2,780     2,397
                                                -------   -------
                                                $ 5,210   $10,670
                                                =======   =======
</TABLE>

     On August 6, 1993, the Company entered into a credit agreement with ING
     (U.S.) Capital Corporation ("ING Capital"), secured by a mortgage on
     substantially all U.S. oil and gas assets, a pledge of Colombian assets and
     the stock of three subsidiaries, pursuant to which ING Capital agreed to
     loan to the Company up to $25 million, subject to an annually redetermined
     borrowing base which is predicated on the Company's U.S. and Colombian
     reserves. As of December 31, 1996, the borrowing base permitted, and the
     outstanding loan balance was, $7,990,000. The outstanding loan balance
     bears interest at the ING Capital prime rate (8.25% at December 31, 1996)
     plus 1% or, at the option of the Company, a fixed rate, based on the London
     Interbank Offered Rate, for a portion or portions of the outstanding debt
     from time to time. Commitment fees of .5% on the unused credit were payable
     quarterly until December 31, 1995, at which time the credit facility
     converted from a revolving credit facility to a term loan. The terms of the
     loan, among other things, prohibit the Company from merging with another
     company or paying dividends, limit additional indebtedness, general and
     administrative expense, sales of assets and investments and require the
     maintenance of certain minimum financial ratios. The agreement also
     requires the Company to maintain a minimum consolidated tangible net worth
     of $22,000,000.

                                       44
<PAGE>
 
                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                                        

     In December 1996, the Company entered into an agreement with ING Capital
     pursuant to which the outstanding loan balance was paid down to $7,990,000
     from $10,790,000 concurrent with the sale of the U.S. onshore properties
     and the repayment schedule was amended to require monthly payments of
     $25,000 for the first seven months of 1997 and $521,000 for the last five
     months of 1997 and the first ten months in 1998.

     The aggregate maturities of long term debt at December 31, 1996 are: 1997 -
     $2,780,000 and 1998 - $5,210,000.

     In consideration of certain modifications to the above referenced credit
     agreement in March 1996 the Company paid a fee of $100,000 to ING Capital.

(4)  INTEREST AND OTHER INCOME (EXPENSE)

     A summary of interest and other income (expense) follows:
<TABLE>
<CAPTION>
                                                        (thousands)
                                                  1996      1995      1994
                                                ------  -----------  ------
<S>                                             <C>    <C>          <C>
        Gain (loss) on sale of assets, net      $  651      $ (2)     $  -
        Interest income                            231       157       166
        Foreign currency exchange gain (loss)      (16)      164        (3)
        Other, net                                 195       176       (21)
                                                ------      ----      ----
                                                $1,061      $495      $142
                                                ======      ====      ====
</TABLE>
(5)  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, 1996, the Company has two stock option plans, which are
     described below.  The Company applies APB Opinion No. 25 and related
     Interpretations in accounting for its plans.  Accordingly, no compensation
     cost has been recognized for its stock option plans.  Had compensation cost
     for the Company's stock option plans been determined consistent with FASB
     Statement No. 123, the Company's net loss and loss per share would have
     been increased to the pro forma amounts indicated below (in thousands,
     except per share data):
<TABLE>
<CAPTION>
                                                 1996          1995
                                                ------        -------
<S>                          <C>                <C>           <C>
 
          Net loss           As reported        $ (937)       $(2,689)
                                                        
                             Pro forma          $ (947)       $(2,805)
                                                        
          Loss per share     As reported        $(0.03)       $ (0.09)
                                                        
                             Pro forma          $(0.03)       $ (0.09)
</TABLE>

                                       45
<PAGE>
 
                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     At the Annual Meeting of Shareholders held on June 6, 1995, the Company's
     shareholders approved the adoption of the Aviva Petroleum Inc. 1995 Stock
     Option Plan (the "Current Plan"). The Current Plan is administered by a
     committee (the "Committee") composed of two or more outside directors of
     the Company, who are disinterested within the meaning of Rule 16b-3(c)
     under the Securities Exchange Act of 1934, as amended (the "Exchange Act").
     Except as indicated below and except for non-discretionary grants to non-
     employee directors, the Committee has authority to determine all terms and
     provisions under which options are granted pursuant to the Current Plan,
     including (i) the determination of which employees shall be eligible to
     receive options, (ii) the number of shares for which an option shall be
     granted and (iii) the terms and conditions upon which options may be
     granted.  Options will vest at such times and under such conditions as
     determined by the Committee, as permitted under the Current Plan.  An
     aggregate of up to 1,000,000 shares of the Company's common stock may be
     issued upon exercise of stock options or in connection with restricted
     stock awards that may be granted under the Current Plan.

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

     In 1995, upon adoption of the Current Plan, each of the non-employee
     directors of the Company was granted non-qualified stock options to
     purchase 30,000 shares of the Company's common stock.  These non-
     discretionary options are for a term of 10 years and become exercisable as
     to 10,000 shares of common stock on each of the first three anniversaries
     of the date of grant.  Non-discretionary options representing no more than
     200,000 shares of common stock may be granted under the Current Plan.

     As a result of the adoption of the Current Plan, the Company's former
     Incentive and Non-Statutory Stock Option Plan (the "1987 Plan") has been
     terminated as to the grant of new options, but options then outstanding for
     360,000 shares of the Company's common stock remain in effect.

     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 used for grants in 1996 and 1995: no dividend yield for either
     year; expected volatility of 77%; a risk-free interest rate of 7.0%; and
     expected lives of 5.0 and 7.3 years, respectively.

                                       46
<PAGE>
 
                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     A summary of the status of the Company's two fixed stock option plans as of
     December 31, 1996, 1995, and 1994, and changes during the years ended on
     those dates is presented below:
<TABLE>
<CAPTION>
                                      1996                1995                1994
                              -------------------  ------------------  ----------------
                                        Weighted-          Weighted-          Weighted-
                                         Average            Average            Average
                               Shares   Exercise   Shares  Exercise   Shares  Exercise
     Fixed Options             (000)     Price     (000)    Price      (000)    Price
     -------------            --------  ---------  ------  ---------  ------  ---------
<S>                           <C>       <C>        <C>     <C>        <C>     <C>
  
     Outstanding at
       beginning of year         716     $1.60       543     $1.82       831    $1.62
     Granted                      20       .74       173       .95         -        -
     Exercised                     -         -         -         -         -        -
     Forfeited                  (206)     1.25         -         -      (288)    1.24
                               -----                ----               -----
     Outstanding at                                                          
       end of year               530      1.80       716      1.60       543     1.82
                               =====                ====               =====    
     Options exercisable                                                     
       at year-end               401                 403                 263 
     Weighted-average fair                                                   
       value of options                                                      
       granted during                                                        
       the year                 $.50                $.72               $   - 
</TABLE>
     The following table summarizes information about fixed stock options
     outstanding at December 31, 1996:
<TABLE>
<CAPTION>
                              Options Outstanding                       Options Exercisable
                  -----------------------------------------------   ---------------------------
     Range          Number       Weighted-Avg.                        Number
      of          Outstanding      Remaining       Weighted-Avg.    Exercisable   Weighted-Avg.
Exercise Prices   at 12/31/96   Contractual Life   Exercise Price   at 12/31/96   Exercise Price
---------------   -----------   ----------------   --------------   -----------   --------------
<S>               <C>           <C>                <C>              <C>           <C>   
$ .74 to  1.08      423,000         6.8 years          $ 1.01         294,333          $ 1.05
 2.88 to  5.99       85,000         4.0                  3.61          85,000            3.61
 9.42 to 10.28       21,500         1.4                 10.22          21,500           10.22
--------------      -------                                           ------- 
$ .74 to 10.28      529,500         6.2                  1.80         400,833            2.08
==============      =======                                           =======   
</TABLE>
(6)  SEVERANCE EXPENSE

     The Board of Directors had charged a committee of the Board with the task
     of reviewing the Company's general and administrative expenses and making
     recommendations as to the reduction of such expenses.  On March 18, 1996,
     the Board, acting on one of such committee's recommendations, determined to
     terminate the employment of the Executive Vice President and Chief
     Operating Officer of the Company (the "Officer") effective on June 1, 1996.
     In connection with the severance arrangements between the Company and the
     Officer, the Company incurred costs of $172,000.

                                       47
<PAGE>
 
                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     On July 25, 1996, the above mentioned committee was dissolved and its
     function was assumed by the entire Board of Directors.  In the third
     quarter of 1996, the Company incurred an additional $24,000 of severance
     expense relating to the termination of certain employees affected by the
     program.

(7)  INCOME TAXES
 
     Income tax expense includes current Colombian income taxes of $709,000 in
     1996, $398,000 in 1995 and $249,000 in 1994 and deferred Colombian income
     taxes (benefit) of $195,000 in 1996, $(5,000) in 1995 and $37,000 in 1994.
     Income tax expense also includes $7,000 and $18,000 of state income taxes
     in 1996 and 1995, respectively.

     The Company's effective tax rate differs from the U.S. statutory rate
     each year principally due to losses without tax benefit.

     The tax effects of temporary differences that give rise to significant
     portions of the deferred tax assets and deferred tax liabilities at
     December 31, 1996 and 1995 follow:
<TABLE>
<CAPTION>
                                                                 (thousands)
                                                                 1996       1995
                                                              -------    -------
<S>                                                           <C>        <C>
 
         Deferred tax assets - principally net operating 
           loss carryforwards                                 $41,604    $44,116
          Less valuation allowance                             36,126     39,124
                                                              -------    -------
 
          Net deferred tax assets                               5,478      4,992
 
         Deferred tax liabilities - property and equipment      6,170      5,489
                                                              -------    -------
 
          Net deferred tax liability                          $   692    $   497
                                                              =======    =======
</TABLE>

     The Company believes that the net deferred tax assets at December 31, 1996
     are realizable primarily through future reversals of existing taxable
     temporary differences. The valuation allowance for deferred tax assets at
     January 1, 1994 was $33,983,000. The net change in the valuation allowance
     was a $2,998,000 decrease in 1996, a $3,581,000 increase in 1995, and a
     $1,560,000 increase in 1994. Subsequently recognized tax benefits relating
     to the valuation allowance of $33,318,000 for deferred tax assets at
     January 1, 1993 will be credited to additional paid in capital.

     At December 31, 1996, the Company and its subsidiaries have aggregate net
     operating loss carryforwards for U.S. federal income tax purposes of
     approximately $117,000,000, expiring from 1997 through 2011, 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.

(8)  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.

                                       48
<PAGE>
 
                     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, 1996, 1995 and 1994, Ecopetrol
     exercised that option and sales to Ecopetrol accounted for $9,437,000
     (68.6%), $7,132,000 (65.3%) and $3,404,000 (39.8%), respectively, of the
     Company's aggregate oil and gas sales.

     For the years ended December 31, 1996, 1995 and 1994, sales to one U.S.
     purchaser accounted for $1,609,000 (11.7%), $1,422,000 (13.0%) and
     $1,144,000 (13.4%), respectively, of oil and gas sales.

(9)  COMMITMENTS AND CONTINGENCIES

     The Company, along with its co-owner (referred to collectively as the "Co-
     owners"), is engaged in an ongoing development and exploration program on
     concessions in Colombia.

     The contract obligations of the Santana concession have been met.  The Co-
     owners currently anticipate, however, completing one development well that
     is currently drilling, drilling two additional development wells and
     recompleting certain existing wells on the Santana concession.  As of
     December 31, 1996, future development costs included in the supplementary
     information related to oil and gas producing activities pursuant to SFAS 69
     include approximately $2.9 million, net to the Company's interest, for
     these expenditures.

     The Co-owners have completed a 3-D seismic survey over the Mary and
     Miraflor fields in the Santana concession and such data is currently being
     interpreted.  Additionally, a 2-D seismic program was initiated on the
     Yuruyaco concession in late December 1996.  As of December 31, 1996, the
     aggregate remaining future expenditures for these and certain other
     miscellaneous projects were approximately $1.0 million, net to the
     Company's interest.

     The Co-owners have completed their seismic obligations for the first two
     years of the La Fragua concession and were obligated to acquire additional
     seismic data for the third year.  The Co-owners determined, however, that
     it was not technically justified to explore this concession further and,
     accordingly, requested and received from Ecopetrol a change of commitment
     that would allow the Co-owners to substitute certain exploratory
     expenditures within the Santana concession for the remaining seismic
     commitment on the La Fragua concession.  The indigenous people of the new
     commitment area, however, have objected to the proposed exploratory work
     and it appears unlikely that the Co-owners will be able to comply with the
     new commitment.  Management of the Company believes that the Co-owners have
     no further obligation with respect to the La Fragua concession and,
     accordingly, have requested that Ecopetrol allow the Co-owners to surrender
     the concession without further expenditure.  Management of the Company
     believes that Ecopetrol will agree to such request, although there can be
     no assurance that this will be the case.  All unevaluated costs relating to
     the La Fragua concession have been transferred into the Colombian
     amortization base.

     The Company's aggregate remaining estimated exploratory and development
     expenditures for 1997 and 1998 were $3.9 million at December 31, 1996.  Any
     substantial increases in the amounts of the above referenced expenditures
     could adversely affect the Company's ability to meet these obligations.

     Failure to fund certain of these capital expenditures could, under either
     the concession agreements or joint operating agreements with the Company's
     co-owner, or both, result in the forfeiture of all or part of the Company's
     interest in these Colombian concessions.

                                       49
<PAGE>
 
                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     The Company plans to fund these obligations using cash provided from
     operations.  Risks that could adversely affect funding of the Company's
     obligations include, among others, a decrease in the Company's borrowing
     base, delays in obtaining the required environmental approvals and permits,
     cost overruns, failure to produce the reserves as projected or a decline in
     the sales price of oil.  Depending on the results of the exploration and
     development activities, substantial expenditures which have not been
     included in the Company's cash flow projections may be required.  Although
     the ultimate outcome of these matters cannot be projected with certainty,
     management believes that its existing capital resources are adequate to
     fund its present obligations or that sufficient capital can be obtained by
     means of sales of assets or revision of current debt repayment terms to
     meet those obligations.

     Under the terms of the contracts with Ecopetrol, 25% of all revenues from
     oil sold to Ecopetrol is paid in Colombian pesos which may only be utilized
     in Colombia.  To date, the Company has experienced no difficulty in
     repatriating the remaining 75% of such payments, which are payable in U.S.
     dollars.
 
     Activities of the Company with respect to the exploration, development and
     production of oil and natural gas are subject to stringent environmental
     regulation by state and federal authorities, including the U.S.
     Environmental Protection Agency. Such regulation has increased the cost of
     planning, designing, drilling, operating and abandoning wells. In most
     instances, the 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
     regulations will not have a material adverse effect on operations or
     earnings, risks of substantial costs and liabilities are inherent in oil
     and gas operations and there can be no assurance that significant costs and
     liabilities, including civil or criminal penalties for violations of
     environmental regulations, will not be incurred. Moreover, it is possible
     that other developments, such as stricter environmental laws and
     regulations or claims for damages to property or persons resulting from the
     Company's operations, could result in substantial costs and liabilities.
     The Company's policy is to accrue environmental and restoration related
     costs once it is probable that a liability has been incurred and the amount
     can be reasonably estimated.

     The Oil Pollution Act of 1990 ("OPA '90") and regulations thereunder impose
     a variety of requirements on "responsible parties" related to the
     prevention of oil spills and liability for damages resulting from such
     spills in waters of the United States. A "responsible party" includes the
     owner or operator of a facility or vessel, 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.

                                       50
<PAGE>
 
                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     With recent amendments to OPA '90 signed into law by President Clinton on
     October 19, 1996, OPA '90 now requires responsible parties to establish and
     maintain $35 million in financial responsibility to cover environmental
     cleanup and restoration costs that might be incurred in connection with an
     oil spill in waters of the United States, including the waters of the Gulf
     of Mexico where the Company has its operations, unless a formal risk
     assessment indicates that increased financial responsibility coverage is
     warranted.  The Company's two U.S. properties, Main Pass Block 41 field, a
     federal lease on the outer continental shelf ("OCS") offshore Louisiana,
     and Breton Sound Block 31 field, on state leases offshore Louisiana, are
     subject to OPA '90 as amended.  Management of the Company believes that
     these two properties comply in all material respects with the amended OPA
     '90 requirements.

     The Outer Continental Shelf Lands Act ("OCSLA") imposes a variety of
     requirements relating to safety and environmental protection on lessees and
     permittees operating in the OCS. Specific design and operational standards
     may apply to OCS vessels, rigs, platforms, vehicles and structures.
     Violation of lease conditions or regulations issued pursuant to OCSLA can
     result in substantial civil and criminal penalties, as well as potential
     court injunctions curtailing operations and the cancellation of leases.
     Such enforcement liabilities can result from either governmental or private
     prosecution. The Company believes it is in material compliance with
     applicable OCSLA requirements.

     The Company is involved in certain litigation involving its oil and gas
     activities, but unrelated to environmental contamination issues.
     Management of the Company believes that these litigation matters will not
     have any material adverse effect on the Company's financial condition or
     results of operations.

     The Company has one lease for office space in Dallas, Texas, which expires
     in January 1999.  Rent expense relating to the lease was $84,000, $90,000
     and $88,000 for 1996, 1995 and 1994, respectively.  The lease is cancelable
     in January of 1998.  Future minimum payments under the lease are $109,000,
     primarily due in 1997.

(10) GAS BALANCING

     As of December 31, 1996 and 1995, other joint owners had sold net gas with
     a volume equivalent of approximately 2,000 thousand cubic feet ("MCF") and
     416,000 MCF (with an estimated value of $4,000 and $624,000 included in
     other assets), respectively, for which the Company is generally entitled to
     be repaid in volumes ("underproduced"). As of December 31, 1996 and 1995,
     the Company had sold net gas with a volume equivalent of approximately
     353,000 MCF and 741,000 MCF (with an estimated value of $724,000 and
     $1,300,000 included in gas balancing obligations and other), respectively,
     for which the other joint owners are entitled generally to be repaid in
     volumes ("overproduced"). In certain instances the parties have the option
     of requesting payment in cash.

     In connection with the sale of the Company's U.S. onshore properties,
     approximately 384,000 MCF for which the Company was underproduced and
     approximately 337,000 MCF for which the Company was overproduced were
     assumed by the buyer of such properties.

                                       51
<PAGE>
 
                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

 

(11) 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, 1996, 1995 and 1994 follows:
<TABLE>
<CAPTION>
(Thousands)
                                                    United
                                                    States   Colombia    Total
                                                    ------   --------   -------
     1996
     ----
     <S>                                            <C>       <C>       <C>
     Oil and gas sales                              $4,313    $ 9,437   $13,750
                                                    ------    -------   -------
 
     Expense:
      Production                                     1,926      2,908     4,834
      Depreciation, depletion and amortization       1,750      5,589     7,339
      General and administrative                     1,539         15     1,554
      Severance                                        196          -       196
                                                    ------    -------   -------
                                                     5,411      8,512    13,923
                                                    ------    -------   -------
 
 
     Interest and other income (expense), net          894        167     1,061
     Interest expense                                 (355)      (459)     (814)
     Debt refinancing expense                            -       (100)     (100)
                                                    ------    -------   -------
 
     Loss before income taxes                         (559)       533       (26)
     Income taxes                                       (7)      (904)     (911)
                                                    ------    -------   -------
 
     Net loss                                       $ (566)   $  (371)  $  (937)
                                                    ======    =======   =======
 
     Identifiable assets                            $6,838    $34,065   $40,903
                                                    ======    =======   
  
     Corporate assets-cash and cash equivalents                           2,041
                                                                        -------
 
     Total assets                                                       $42,944
                                                                        =======
</TABLE>

                                       52
<PAGE>
 
                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

<TABLE>
<CAPTION>
(Thousands)

                                                  United
                                                  States   Colombia     Total
                                                 -------   --------   ---------
     1995
     ----
<S>                                              <C>       <C>        <C>
     Oil and gas sales                           $ 3,796     $7,132     $10,928
                                                 -------    -------     -------
     Expense:
      Production                                   1,960      3,112       5,072
      Depreciation, depletion and amortization     1,349      4,406       5,755
      General and administrative                   2,306         10       2,316
                                                 -------    -------     -------
                                                   5,615      7,528      13,143
                                                 -------    -------     -------

     Interest and other income (expense), net        100        395         495
     Interest expense                               (371)      (187)       (558)
                                                 -------    -------     -------

     Loss before income taxes                     (2,090)      (188)     (2,278)
     Income taxes                                    (18)      (393)       (411)
                                                 -------    -------     -------

     Net loss                                    $(2,108)     $(581)    $(2,689)
                                                 =======    =======     =======

     Identifiable assets                         $ 7,398    $33,862     $41,260
                                                 =======    =======     

     Corporate assets-cash and cash equivalents                           4,200
                                                                        -------

     Total assets                                                       $45,460
                                                                        =======

     1994
     ----
     Oil and gas sales                           $ 5,142    $ 3,404     $ 8,546
                                                 -------    -------     -------
     Expense:
      Production                                   2,230      2,290       4,520
      Depreciation, depletion and amortization     1,839      2,145       3,984
      General and administrative                   2,072         11       2,083
                                                 -------    -------     -------

                                                   6,141      4,446      10,587
                                                 -------    -------     -------

     Interest and other income (expense), net        (11)       153         142
     Interest expense                               (275)         -        (275)
                                                 -------    -------     -------

     Loss before income taxes                     (1,285)      (889)     (2,174)
     Income taxes                                      -       (286)       (286)
                                                 -------    -------     -------

     Net loss                                    $(1,285)   $(1,175)    $(2,460)
                                                 =======    =======     =======

     Identifiable assets                         $ 8,366    $32,035     $40,401
                                                 =======    =======     

     Corporate assets-cash and cash equivalents                           1,982
                                                                        -------

     Total assets                                                       $42,383
                                                                        =======
</TABLE>

                                       53
<PAGE>
 
                     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:
<TABLE>
<CAPTION>
(Thousands)
                                           United
                                           States       Colombia        Total
                                           ------       --------       -------
<S>                                        <C>          <C>            <C>
December 31, 1996
-----------------
 
Unevaluated oil and gas properties         $   182       $   884       $ 1,066
Proved oil and gas properties               11,835        45,423        57,258
                                           -------       -------       -------
                                                                 
 Total capitalized costs                    12,017        46,307        58,324
                                                                 
Less accumulated depreciation,                                   
 depletion and amortization                  7,508        15,971        23,479
                                           -------       -------       -------
                                                                 
 Capitalized costs, net                    $ 4,509       $30,336       $34,845
                                           =======       =======       =======
                                                                 
                                                                 
December 31, 1995                                                
-----------------                             
                                                                 
Unevaluated oil and gas properties         $     -       $ 3,012       $ 3,012
Proved oil and gas properties               39,649        37,883        77,532
                                           -------       -------       -------
                                                                 
 Total capitalized costs                    39,649        40,895        80,544
                                                                 
Less accumulated depreciation,                                   
 depletion and amortization                 34,646        10,501        45,147
                                           -------       -------       -------
                                                                 
 Capitalized costs, net                    $ 5,003       $30,394       $35,397
                                           =======       =======       =======
 
</TABLE>

                                       54
<PAGE>
 
                     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:
<TABLE>
<CAPTION>
(Thousands)
                                          United
                                          States       Colombia        Total
                                          ------       --------       ------
<S>                                       <C>          <C>            <C>
1996                                                
----                                             
                                                 
Exploration                               $    -        $1,382        $1,382
Development                                3,239         4,030         7,269
                                          ------        ------        ------
   Total costs incurred                   $3,239        $5,412        $8,651
                                          ======        ======        ======
                                                               
1995                                                           
----                                                                 
                                                                     
Exploration                               $    -        $1,477        $1,477
Development                                  172         5,784         5,956
                                          ------        ------        ------
   Total costs incurred                   $  172        $7,261        $7,433
                                          ======        ======        ======
                                                               
1994                                                           
----                                                                 
                                                                     
Exploration                               $    -        $2,037        $2,037
Development                                  535         4,848         5,383
Acquisition of proved properties              51             -            51
                                          ------        ------        ------
   Total costs incurred                   $  586        $6,885        $7,471
                                          ======        ======        ======
                                                               
</TABLE>                                                             
                                                                     

                                       55
<PAGE>
 
                     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 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.
<TABLE>
<CAPTION>
                                        Changes in the Estimated Quantities
                                                   of Reserves
                                   --------------------------------------------
                                     United
                                     States            Colombia          Total
                                   ----------          --------         -------
<S>                                <C>                 <C>                <C>
Year ended December 31, 1996       
----------------------------       
                                   
Oil (Thousands of barrels)         
Proved reserves:                   
 Beginning of period                    564              3,255           3,819
 Revisions of previous estimates        (74)                38             (36)
 Discoveries and extensions               6                  -               6
 Sales of reserves                      (97)                 -             (97)
 Production                             (94)              (476)           (570)
                                     ------              -----          ------
                                   
 End of period                          305              2,817           3,122
                                     ======              =====          ======
                                   
Proved developed reserves, end     
  of period                             305              2,008           2,313
                                     ======              =====          ======
                                   
                                   
                                   
Gas (Millions of cubic feet)       
Proved reserves:                   
 Beginning of period                  7,037                  -           7,037
 Revisions of previous estimates       (770)                 -            (770)
 Discoveries and extensions              23                  -              23
 Sales of reserves                   (3,462)                 -          (3,462)
 Production                          (1,146)                 -          (1,146)
                                     ------              -----          ------
                                   
 End of period                        1,682                  -           1,682
                                     ======              =====          ======
                                   
Proved developed reserves,         
  end of period                       1,682                  -           1,682
                                     ======              =====          ======
</TABLE>

                                       56
<PAGE>
 
                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
     SUPPLEMENTARY INFORMATION RELATED TO OIL AND GAS PRODUCING ACTIVITIES
                            (UNAUDITED) (CONTINUED)
<TABLE>
<CAPTION>
                                    Changes in the Estimated Quantities
                                                 of Reserves
                                   --------------------------------------
                                     United
                                     States      Colombia          Total
                                   ----------    --------         -------
<S>                                <C>           <C>                <C>
Year ended December 31, 1995                 
----------------------------                 
                                             
Oil (Thousands of barrels)                   
Proved reserves:                             
 Beginning of period                  678          4,003           4,681
 Revisions of previous estimates       (3)          (743)           (746)
 Discoveries and extensions             -            430             430
 Sales of reserves                     (5)             -              (5)
 Production                          (106)          (435)           (541)
                                   ------          -----          ------
                                             
 End of period                        564          3,255           3,819
                                   ======          =====          ======
                                             
Proved developed reserves,                   
  end of period                       460          1,601           2,061
                                   ======          =====          ======
                                             
                                             
                                             
Gas (Millions of cubic feet)                 
Proved reserves:                             
 Beginning of period                8,552              -           8,552
 Revisions of previous estimates     (257)             -            (257)
 Sales of reserves                    (74)             -             (74)
 Production                        (1,184)             -          (1,184)
                                   ------          -----          ------
                                             
 End of period                      7,037              -           7,037
                                   ======          =====          ======
                                             
Proved developed reserves,                   
  end of period                     6,779              -           6,779
                                   ======          =====          ======
</TABLE>

                                       57
<PAGE>
 
                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
     SUPPLEMENTARY INFORMATION RELATED TO OIL AND GAS PRODUCING ACTIVITIES
                            (UNAUDITED) (CONTINUED)
<TABLE>
<CAPTION>
                                    Changes in the Estimated Quantities
                                                 of Reserves
                                   --------------------------------------
                                     United
                                     States         Colombia       Total
                                   ----------       --------      -------
<S>                                <C>              <C>           <C>
Year ended December 31, 1994
----------------------------
 
Oil (Thousands of barrels)
Proved reserves:
 Beginning of period                   548            4,612        5,160
 Revisions of previous estimates       253             (359)        (106)
 Sales of reserves                     (24)               -          (24)
 Production                            (99)            (250)        (349)
                                    ------            -----       ------
                                                                  
 End of period                         678            4,003        4,681
                                    ======            =====       ======
                                                                  
Proved developed reserves,                                        
  end of period                        426            1,797        2,223
                                    ======            =====       ======
                                                                  
                                                                  
                                                                  
Gas (Millions of cubic feet)                                      
Proved reserves:                                                  
 Beginning of period                11,946                -       11,946
 Revisions of previous estimates      (359)               -         (359)
 Sales of reserves                  (1,196)               -       (1,196)
 Production                         (1,839)               -       (1,839)
                                    ------            -----       ------
                                                                  
 End of period                       8,552                -        8,552
                                    ======            =====       ======
                                                                  
Proved developed reserves,                                        
  end of period                      6,741                -        6,741
                                    ======            =====       ======        
</TABLE>

                                       58
<PAGE>
 
                     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.
<TABLE>
<CAPTION>
(Thousands)                            United
                                       States      Colombia       Total
                                      -------      --------      --------
<S>                                   <C>          <C>        <C>
At December 31, 1996:
---------------------
 
Future gross revenues                 $14,070      $ 63,666      $ 77,736
Future production costs                (6,128)      (11,362)      (17,490)
Future development costs                 (970)       (3,067)       (4,037)
                                      -------      --------      --------
Future net cash flows before                                   
 income taxes                           6,972        49,237        56,209
Future income taxes                       (51)       (1,052)       (1,103)
                                      -------      --------      --------
Future net cash flows after                                    
 income taxes                           6,921        48,185        55,106
                                                               
Discount at 10% per annum                (993)       (9,513)      (10,506)
                                      -------      --------      --------
Standardized measure of discounted                             
 future net cash flows                $ 5,928      $ 38,672      $ 44,600
                                      =======      ========      ========
</TABLE>

                                       59
<PAGE>
 
                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
     SUPPLEMENTARY INFORMATION RELATED TO OIL AND GAS PRODUCING ACTIVITIES
                            (UNAUDITED) (CONTINUED)
<TABLE>
<CAPTION>
(Thousands)                          United
                                     States        Colombia         Total
                                   ----------      --------        --------
<S>                                   <C>          <C>             <C>
At December 31, 1995:
---------------------
 
Future gross revenues              $ 24,720        $ 57,258        $ 81,978
Future production costs             (11,371)        (14,881)        (26,252)
Future development costs             (2,153)         (4,529)         (6,682)
                                   --------        --------        --------
Future net cash flows before                                    
 income taxes                        11,196          37,848          49,044
Future income taxes                    (121)           (376)           (497)
                                   --------        --------        --------
Future net cash flows after                                     
 income taxes                        11,075          37,472          48,547
                                                                
Discount at 10% per annum            (2,930)        (10,182)        (13,112)
                                   --------        --------        --------
Standardized measure of discounted                              
 future net cash flows             $  8,145        $ 27,290        $ 35,435
                                   ========        ========        ========
                                                                
                                                                
                                                                
At December 31, 1994:                                           
---------------------                                           
                                                                
Future gross revenues              $ 25,996        $ 62,194        $ 88,190
Future production costs             (12,348)        (13,446)        (25,794)
Future development costs             (2,323)         (7,131)         (9,454)
                                   --------        --------        --------
Future net cash flows before                                    
 income taxes                        11,325          41,617          52,942
Future income taxes                    (104)         (3,320)         (3,424)
                                   --------        --------        --------
Future net cash flows after                                     
 income taxes                        11,221          38,297          49,518
                                                                
Discount at 10% per annum            (3,011)         (8,998)        (12,009)
                                   --------        --------        --------
Standardized measure of discounted                               
 future net cash flows             $  8,210        $ 29,299        $ 37,509
                                   ========        ========        ========
</TABLE>

                                       60
<PAGE>
 
                     AVIVA PETROLEUM INC. AND SUBSIDIARIES
     SUPPLEMENTARY INFORMATION RELATED TO OIL AND GAS PRODUCING ACTIVITIES
                            (UNAUDITED) (CONTINUED)


The following schedule summarizes the changes in the standardized measure of
discounted future net cash flows.
<TABLE>
<CAPTION>
(Thousands)
                                                   1996      1995      1994
                                                 --------  --------  --------
<S>                                              <C>       <C>       <C>
 
Sales of oil and gas, net of production costs    $(8,916)  $(5,856)  $(4,026)
Sales of reserves in place                        (3,924)      (44)   (3,045)
Development costs incurred that reduced
 future development costs                          3,043     3,713     4,127
Accretion of discount                              3,577     4,009     3,438
Discoveries and extensions                            87     4,521         -
Revisions of previous estimates:
 Changes in price                                 13,468     2,263     9,395
 Changes in quantities                               153    (7,582)   (2,184)
 Changes in future development costs                 (86)     (723)     (581)
 Changes in timing and other changes               2,303    (4,623)   (1,414)
 Changes in estimated income taxes                  (540)    2,248    (2,084)
                                                 -------   -------   -------
 
 Net increase (decrease)                           9,165    (2,074)    3,626
 
Balances at beginning of year                     35,435    37,509    33,883
                                                 -------   -------   -------
 
Balances at end of year                          $44,600   $35,435   $37,509
                                                 =======   =======   =======
</TABLE>

                                       61
<PAGE>
 
                               INDEX TO EXHIBITS
                                        
                                                                    Sequentially
                                                                      Numbered
Number                      Description of Exhibit                       Page
------                      ----------------------                  ------------

  *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 
         Form 10, 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).

 *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 Form 10, 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 Form 10, File No. 
         0-22258, and incorporated herein by reference).

 *10.5   Agreement of Withdrawal from Argosy dated September 16, 
         1987 by and among Argosy, Neo, and Argosy Energy 
         Incorporated, as general partners; and Parkside 
         Investments, Richard Shaner McKnight, Douglas W. Fry, P-5
         Ltd., GO-DEO, Inc., Dale E. Armstrong, Richard Shane 
         McKnight, The Yvonne McKnight Trust, and William Gaskin, 
         as limited partners (filed as exhibit 10.5 to the Company's 
         Registration Statement on Form 10, File No. 0-22258, and 
         incorporated herein by reference).

 *10.6   Option Agreement dated September 16, 1987 between the 
         general and limited partners of Argosy and Neo (filed as 
         exhibit 10.6 to the Company's Registration Statement on 
         Form 10, File No. 0-22258, and incorporated herein by 
         reference).

 *10.7   Escrow Agreement between Argosy, Neo, Overseas Private 
         Investment Corporation and The Chase Manhattan Bank dated 
         March 15, 1988 and amended on May 31, 1990 (filed as 
         exhibit 10.7 to the Company's Registration Statement on 
         Form 10, File No. 0-22258, and incorporated herein by 
         reference).

 *10.8   Santana Block A Relinquishment dated March 6, 1990 between
         Ecopetrol, Argosy and Neo (filed as exhibit 10.8 to the 
         Company's Registration Statement on Form 10, File No. 
         0-22258, and incorporated herein by reference).

 *10.9   Purchase Sale - Transportation and Commercialization of 
         the Santana Crude between Ecopetrol, Argosy and Neo 
         (filed as exhibit 10.9 to the Company's Registration 
         Statement on Form 10, File No. 0-22258, and incorporated 
         herein by reference).

 *10.10  La Fragua Association Contract dated June 1, 1992 between
         Ecopetrol, Argosy and Neo (filed as exhibit 10.10 to the 
         Company's Registration Statement on Form 10, File No. 
         0-22258, and incorporated herein by reference).

                                       62
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                                                                      Numbered
Number                      Description of Exhibit                       Page
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*10.11   Operating Agreement for the La Fragua Area between Argosy 
         and Neo dated April 15, 1992 (filed as exhibit 10.11 to 
         the Company's Registration Statement on Form 10, File No. 
         0-22258, and incorporated herein by reference).

*10.12   Employment Agreement between the Company and Ronald Suttill 
         dated November 29, 1991 (filed as exhibit 10.12 to the 
         Company's Registration Statement on Form 10, File No. 
         0-22258, and incorporated herein by reference).

*10.13   Employee Stock Option Plan of the Company (filed as exhibit 
         10.13 to the Company's Registration Statement on Form 10, 
         File No. 0-22258, and incorporated herein by reference).

*10.14   Letter agreement dated January 6, 1993 between NationsBank
         Investment Banking and the Company (filed as exhibit 10.14 
         to the Company's Registration Statement on Form 10, File No. 
         0-22258, and incorporated herein by reference).

*10.15   Letter agreement dated March 3, 1993 between EnCap 
         Investments L.C. and the Company (filed as exhibit 10.15 
         to the Company's Registration Statement on Form 10, File No. 
         0-22258, and incorporated herein by reference).

*10.16   Credit Agreement dated August 6, 1993 between the Company, 
         Aviva America, Inc. ("Aviva America"), Neo and 
         Internationale Nederlanden Bank N.V., New York Branch 
         ("ING Capital") (filed as exhibit 10.16 to the Company's 
         Registration Statement on Form 10, File No. 0-22258, and
         incorporated herein by reference).

*10.17   Subordination Agreement dated August 6, 1993 between the 
         Company, Aviva America, Aviva Operating Company ("Aviva 
         Operating"), Neo and ING Capital (filed as exhibit 10.17 to 
         the Company's Registration Statement on Form 10, File No. 
         0-22258, and incorporated herein by reference).

*10.18   Stock Pledge Agreement dated August 6, 1993 between the 
         Company and ING Capital (filed as exhibit 10.18 to the 
         Company's Registration Statement on Form 10, File No. 
         0-22258, and incorporated herein by reference).

*10.19   Stock Pledge Agreement dated August 6, 1993 between Aviva 
         America and ING Capital (filed as exhibit 10.19 to the 
         Company's Registration Statement on Form 10, File No. 
         0-22258, and incorporated herein by reference).

*10.20   Guaranty dated August 6, 1993 made by the Company in favor 
         of ING Capital (filed as exhibit 10.20 to the Company's 
         Registration Statement on Form 10, File No. 0-22258, 
         and incorporated herein by reference).

*10.21   Guaranty dated August 6, 1993 made by Aviva America in 
         favor of ING Capital (filed as exhibit 10.21 to the Company's 
         Registration Statement on Form 10, File No. 0-22258, and 
         incorporated herein by reference).

*10.22   Guaranty dated August 6, 1993 made by Aviva Operating in 
         favor of ING Capital (filed as exhibit 10.22 to the Company's 
         Registration Statement on Form 10, File No. 0-22258, and 
         incorporated herein by reference).

*10.23   Form of Subscription Agreement dated June 18, 1993 between 
         the Company and purchasers of 12,884,207 shares of common 
         stock ("Purchasers") (filed as exhibit 10.23 to the Company's 
         Registration Statement on Form 10, File No. 0-22258, and 
         incorporated herein by reference).

*10.24   Option Agreement between RBS and Aviva Energy Inc. ("Aviva
         Energy") dated July 1, 1993 (filed as exhibit 10.24 to the 
         Company's Registration Statement on Form 10, File No. 0-22258, 
         and incorporated herein by reference).

                                       63
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                                                                      Numbered
Number                      Description of Exhibit                       Page
------                      ----------------------                  ------------

*10.25   Option Agreement between Aviva Energy and Purchasers dated 
         July 1, 1993 (filed as exhibit 10.25 to the Company's 
         Registration Statement on Form 10, File No. 0-22258, and 
         incorporated herein by reference).

*10.26   Santana Block B 50% relinquishment dated September 13, 1993
         between Ecopetrol, Argosy and Neo (filed as exhibit 10.26 
         to the Company's annual report on Form 10-K for the year 
         ended December 31, 1993, File No. 0-22258, and incorporated 
         herein by reference).

*10.27   Amendment to La Fragua Association contract dated December 
         2, 1993 between Ecopetrol, Argosy and Neo (filed as exhibit 
         10.27 to the Company's annual report on Form 10-K for the 
         year ended December 31, 1993, File No. 0-22258, and 
         incorporated herein by reference).

*10.28   Letter from Ecopetrol dated February 24, 1994 and 
         Resolution dated February 18, 1994 revising pipeline tariff 
         (filed as exhibit 10.28 to the Company's annual report on 
         Form 10-K for the year ended December 31, 1993, File No. 
         0-22258, and incorporated herein by reference).

*10.29   Aviva Petroleum Inc. 401(k) Retirement Plan effective 
         March 1, 1992 (filed as exhibit 10.29 to the Company's 
         annual report on Form 10-K for the year ended December 31, 
         1993, File No. 0-22258, and incorporated herein by 
         reference).

*10.30   Relinquishment of Putumayo dated December 1, 1993 (filed as
         exhibit 10.30 to the Company's annual report on Form 10-K 
         for the year ended December 31, 1993, File No. 0-22258, and 
         incorporated herein by reference).

*10.31   Amendment to ING Capital agreement dated March 28, 1994 (filed 
         as exhibit 10.31 to the Company's annual report on Form 
         10-K for the year ended December 31, 1993, File No. 
         0-22258, and incorporated herein by reference).

*10.32   Deposit Agreement dated September 15, 1994 between the 
         Company and Chemical Shareholder Services Group, Inc. 
         (filed as exhibit 10.29 to the Company's Registration 
         Statement on Form S-1, File No. 33-82072, and incorporated 
         herein by reference).

*10.33   Form of Registration Agreement dated as of September 15, 
         1994 between the Company and Shearson Lehman Brothers Inc. 
         (filed as exhibit 10.30 to the Company's Registration 
         Statement on Form S-1, File No. 33-82072, and incorporated 
         herein by reference).

*10.34   Form of Registration Agreement and Limited Power of 
         Attorney dated as of September  15, 1994 between the  
         Company and all other Selling Shareholders (filed as 
         exhibit 10.31 to the Company's Registration Statement on 
         Form S-1, File No. 33-82072, and incorporated herein by
         reference).

*10.35   Form of Broker-Dealer Agreement dated as of October 19, 1994
         between the Company and Petrie Parkman & Co. (filed as 
         exhibit 10.32 to the Company's Registration Statement on 
         Form S-1, File No. 33-82072, and incorporated herein by 
         reference).

*10.36   Purchase and Sale Agreement dated July 22, 1994 by and 
         between Newfield Exploration Company and Aviva America 
         (filed as exhibit 10.33 to the Company's Registration 
         Statement on Form S-1, File No. 33-82072, and incorporated 
         herein by reference).

*10.37   Letter from ING Capital dated October 27, 1994, amending 
         Section 5.2(n) of the Credit Agreement (filed as exhibit 
         10.37 to the Company's annual report on Form 10-K for the 
         year ended December 31, 1994, File No. 0-22258, and 
         incorporated herein by reference).

                                       64
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                                                                      Numbered
Number                      Description of Exhibit                       Page
------                      ----------------------                  ------------

*10.38   Letter from Ecopetrol dated December 28, 1994, accepting
         relinquishment of Putumayo (filed as exhibit 10.38 to the 
         Company's annual report on Form 10-K for the year ended 
         December 31, 1994, File No. 0-22258, and incorporated 
         herein by reference).

*10.39   Letter from Ecopetrol dated February 28, 1995, accepting
         modifications to the La Fragua Association Contract (filed 
         as exhibit 10.39 to the Company's annual report on Form 
         10-K for the year ended December 31, 1994, File No. 0-22258, 
         and incorporated herein by reference).

*10.40   Amendment to ING Capital Credit Agreement dated March 7, 1995 
         (filed as exhibit 10.40 to the Company's annual report on 
         Form 10-K for the year ended December 31, 1994, File No. 
         0-22258, and incorporated herein by reference).

*10.41  Santana Crude Oil Sale Contract dated March 19, 1995 (filed 
        as exhibit 10.41 to the Company's annual report on Form 10-K 
        for the year ended December 31, 1994, File No. 0-22258, and 
        incorporated herein by reference).

*10.42  Employment Agreement between the Company and Ronald Suttill
        effective January 1, 1995 (filed as exhibit 10.1 to the 
        Company's quarterly report on Form 10-Q for the quarter 
        ended March 31, 1995, File No. 0-22258, and incorporated 
        herein by reference). 

*10.43  Employment Agreement between the Company and Robert C. Boyd
        effective January 1, 1995 (filed as exhibit 10.2 to the 
        Company's quarterly report on Form 10-Q for the quarter 
        ended March 31, 1995, File No. 0-22258, and incorporated 
        herein by reference).

*10.44  Amendment to ING Capital Credit Agreement dated June 9, 1995 
        (filed as exhibit 10.3 to the Company's quarterly report on 
        Form 10-Q for the quarter ended June 30, 1995, File No. 
        0-22258, and incorporated herein by reference).

*10.45  Amendment to the Incentive and Nonstatutory Stock Option 
        Plan of the Company (filed as exhibit 10.4 to the Company's 
        quarterly report on Form 10-Q for the quarter ended 
        September 30, 1995, File No. 0-22258, and incorporated 
        herein by reference).

*10.46  Aviva Petroleum Inc. 1995 Stock Option Plan (filed as 
        exhibit 10.5 to the Company's quarterly report on Form 10-Q 
        for the quarter ended September 30, 1995, File No. 0-22258, 
        and incorporated herein by reference).

*10.47  Yuruyaco Association Contract dated September 20, 1995 
        between Ecopetrol, Argosy and Neo (filed as exhibit 10.6 to 
        the Company's quarterly report on Form 10-Q for the quarter 
        ended September 30, 1995, File No. 0-22258, and incorporated 
        herein by reference).

*10.48  Letter from ING Capital dated November 3, 1995, amending 
        Section 5.2(n) of the Credit Agreement (filed as exhibit 
        10.7 to the Company's quarterly report on Form 10-Q for the 
        quarter ended September 30, 1995, File No. 0-22258, and 
        incorporated herein by reference).

*10.49  Amendment to the Santana Crude Oil Sale Contract (filed as 
        exhibit 10.49 to the Company's annual report on Form 10-K 
        for the year ended December 31, 1995, File No. 0-22258, and 
        incorporated herein by reference).

*10.50  Amendment to the La Fragua Association Contract dated 
        April 27, 1995 (filed as exhibit 10.50 to the Company's 
        annual report on Form 10-K for the year ended December 31, 
        1995, File No. 0-22258, and incorporated herein by reference).

*10.51  Santana Block B 25% relinquishment dated October 2, 1995 
        (filed as exhibit 10.51 to the Company's annual report on 
        Form 10-K for the year ended December 31, 1995, File No. 
        0-22258, and incorporated herein by reference).

                                       65
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                                                                      Numbered
Number                      Description of Exhibit                       Page
------                      ----------------------                  ------------

 *10.52  Amendment to the La Fragua Association Contract dated 
         August 1, 1995 (filed as exhibit 10.52 to the Company's 
         annual report on Form 10-K for the year ended December 31, 
         1995, File No. 0-22258, and incorporated herein by 
         reference).

 *10.53  Operating Agreement for the Yuruyaco Area between Argosy 
         and Neo dated November 7, 1995 (filed as exhibit 10.53 to 
         the Company's annual report on Form 10-K for the year ended 
         December 31, 1995, File No. 0-22258, and incorporated 
         herein by reference).

 *10.54  Letter from ING Capital dated March 19, 1996, revising the 
         borrowing base and schedule of principal repayments and 
         Section 5.2 (m) of the Credit Agreement (filed as exhibit 
         10.54 to the Company's annual report on Form 10-K for the 
         year ended December 31, 1995, File No. 0-22258, and 
         incorporated herein by reference).

 *10.55  Amendment to the ING Capital Credit Agreement dated March 29, 
         1996 (filed as exhibit 10.1 to the Company's quarterly report 
         on Form 10-Q for the quarter ended March 31, 1996, File 
         No. 0-22258, and incorporated herein by reference).
 
 *10.56  Aviva Petroleum Inc. Severance Benefit Plan (filed as 
         exhibit 10.2 to the Company's quarterly report on Form 10-Q 
         for the quarter ended March 31, 1996, File No. 0-22258, and 
         incorporated herein by reference).
 
**10.57  Amendment to the ING Capital Credit Agreement dated November 
         22, 1996.
     
**10.58  Purchase and Sale Agreement dated November 22, 1996 between 
         BWAB Incorporated and Aviva America.

**10.59  Purchase and Sale Agreement dated December 6, 1996 between 
         Lomak Petroleum Inc. and Aviva America.
     
**10.60  Santana Crude Sale and Purchase Agreement dated February 10,
         1997.

 *21.1   List of subsidiaries of Aviva Petroleum Inc.


**27.1   Financial Data Schedule

-----------------------
* Previously Filed
**Filed Herewith

                                       66